Mandurah Straight-fwd answer is whatever oil-pay sits beneath...

Mandurah

Straight-fwd answer is whatever oil-pay sits beneath the gascap is easy to spot on their 3D & confirm via appraisal wells. SNE#1 & 2 r in the guts, so check the contour slide by FAR (slide-11 from 26 Oct Conf).

http://www.far.com.au/research-reports/

3 wells ie SNE-1, 2 & a contingent well located three kms in a radial pattern in the guts of the dome should suffice to calibrate the Albian sands sweet-spot in my view. They can step-out & explore the fringes of the field to look for more, ie SNE3 & B1. Right now they r drilling in an almost N-S trend.


re: at what point would this test be conducted

Usually done after drilling Ops r completed.

It is easy to do onshore, but offshore post-completions (after DST etc) an Operator has to secure the well first & avoid any oil spills etc etc. Then set up pressure gauges on specially mounted well-heads & do the readouts remotely from Dakar Hilton or preferably aboard a supply boat.

They should have cut the casing off at SNE-1 after setting multiple plugs thro' out the bore as is the Std abandonment practice in the sector, so am not sure if they'd want to re-enter & drill out the plugs, perforate the 9" casing etc, so better off drilling a new well as its almost 13 months since they cased it off.
Rather let COP strategize on these sort of things.

Slide-13 from CNE's Oct presentation sums it all for SNE. Any extra toppings could come from B#1 or those mystical thin sands, hence the current 2C. It will change for sure as new data is gathered.

http://cairnenergy.com/index.asp?pageid=26

U r right though numbers get revised all the time as more & more sub-surf data is collated from appraisal, development & production wells.

Will have to wait till the core results come back from the lab then the model will have the 'insitu' poro/perm, grain density etc to input in the model & above all the pressure results frm the Flowtests & connectivity testing.

For now geophysical logs (LSA files), VSP data shot in each well, MDT pressure readings, 3Dseis should suffice for their inhouse static models. These r compulsory for an Operator to collate, analyse b4 booking numbers.

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B4b,

5-6 wells with straight fwd pressure data from flowtest results etc should suffice initially in my view. We dont know what their latest 3Dswath over SNE looks like, ie whether the geology is simple or complex.

As an example, at Chinguetti Woodside did a DoC after 4 wells & booked 2P, then embarked on Phase-1 Development drilling of 11 wells (included 6 injectors). Two appraisal wells were tested. First one clogged up with sands & flowed 150 bopd whilst another did a steady 11500 bopd on 72/64" choke. On production the field went into rapid decline. Field still does ~5400 bopd today & the FPSO contract was extended by its current Operator. Went from discv to prod in ~60 months.

Jubilee was done in 42 months just when oil prices were in the 90-110/bbl. 2015 has been hard, averaging US57/bbl for 27 mmbbls produced so far, with Production costs+DDA of 13+19/bbl. Margin is US25/bbl. This time last year it was US74/bbl.

Another way of looking at it is how soon can a JV complete an FID once reserves r booked.