What's It All Mean??

What to take out of the recent ann? {Thanks for that interim update Ron}.

I think the biggest disappointment is that no additional flow rates were announced for at least
the boo recovered, even whilst clean up is still proceeding. On closer inspection though, one
does not have a need for this figure yet. The period from 21/7 to 4/8 was hindered due to
frac tree replacement and other work-overs on the well. The current 3 week period we see a
potential partial blockage of the well bore from the proppant, resulting in a loss of pressure
and hence recovery of HC's and fracc fluids. Even though I argued for these rates to be
disclosed at the time, it would have been meaningless really. 55% of frac fluids had been
recovered at this juncture with loss of pressure already an issue I would venture.

What we do have however are the flow rates over the first week. 77H produced 790 bopd
over about a 7-8 day period with 40% fracc fluids recovered. Recovering 5% fracc fluids per day
and 100 bopd. No gas flows given. The current ann states that the cumulative total of boo that
they have recovered is 120 boo per 1mmscfg. That is 300% higher than anticipated. So for
100bopd we get 833mscfgd.

That's how we get a gas flow rate, for the first 7 days at least, with only 40% of frac fluids recovered.
I would venture to say that during this period no significant loss of pressure would have been
present as is now.

Now, for 77H to be commercial, they would want about 3.5 -4 mmscfgd. Over the 1st 7 days we
had 100bopd AND 833scfgd or a TOTAL of 2mmscfg. To convert I use 1boe=12mscfg. A ratio
of 1;12 instead of 1;6. More acurate in $ terms {$100 boo v $8 mscfg} and more conservative.
On my reckoning we were already
about 60% of the way there with ONLY 40% fracc fluids recovered and the POSSIBILITY that
we had light CRUDE oil, not condensate. What is critical here, in my view, is that they just
stated in the recent ann that the liquids to gas ratio was 300% higher than anticipated as
PART OF THE WELL DESIGN. Their fracture treatment is now confirmed to have been
heavily weighted in favour of a dryer well. Wet wells require a higher volume of proppant
at lower frac fluid volumes & pump rates. This would affect pressure & hence flow rates
AS WELL AS the current partial blockage in the well bore. Now, if the oil recovered is
in fact crude rather than condensate, this too would have a bearing on how it in fact
travels through the fractured rock into the reservoir. Harder to flow particularly in shale that has
average porosity.

Condensate is still ok if it were not crude and that would cancel out the theory above of crude
oil adding to the loss of pressure, in part due to a frac treatment design that was geared more
towards a gas/condensate well. So, what is it?? Interesting to see those sample bottles of oil
from other wells drilled in the field. Well 60 is marked condensate and it is light brown. Well
73 is marked condensate yet it is black. The yet to be analysed and tested RECENT samples
from 77H are marked OIL and it is black. Mmmmm. Remember those INITIAL samples that
went to the lab 3 weeks ago? Why mark it oil???

" The light crude oil is consistently measured in the range of API 45 – 50 degrees and therefore may be considered a condensate. However as seen in the accompanying photograph, Cambay-77H liquid hydrocarbon has the appearance of other Cambay crudes. It is of high quality and the laboratory results will provide more information"
Well, we know that pure light crude has more value than the condensate. They are strongly hinting in my
opinion that it is in fact crude and not condensate, they've even marked the bottle as OIL. That would be
my punt. That would also explain loss of pressure as the proppant was not in sufficient quantity to enable
a bigger fracture to let the CRUDE flow. No bother, artificial pumps can add substantially to flow rates and
light crude is the preferred product.

This is a "CONCEPT" well only, 8 fracture stages with 350m lateral. Even I keep forgetting that.

In summary ;

1. If my calculations are correct then in the first 7 days of flowing we were already producing
the equivalent of 2mmscfgd. 4mmscfgd would be commercial.

2.We were half way there already with 60% of frac fluids to still be recovered. I will assume no loss
of pressure at this stage. If pressure was starting to fall off in the last few of the 1st 7 days, then all
the better.

3. I will assume that the initial fracture treatment design was heavily weighted towards a gas/
condensate well rather than a crude oil well. I will also assume that the samples recovered are
in fact crude oil rather than condensate. A much higher % of proppant at lower frac fluid volumes
and pump rates could be used in follow up wells if in fact the area is predominately crude to
further enhance flow rates.

4. Longer laterals and more fracture stages would obviously enhance flow rates if 77H proves
even marginally commercial or just under it.

5. Larger well bore casings as Joatman alluded to would also increase flow.

6. If 1&2 above are correct then it would not be too much to extrapolate, once the
partial blockage of the well bore is sorted out and we recover the remaining 60%
of frac fluids, that the flow could be double that of the first 7 days to 4mmscfgd.
That would make it commercial {albeit on a 24 hr flow test}.

7. 4mmscfd with the above improvements NOT YET factored into the remaining test wells.

8.In the short term the flushing of the well bore seems to be no problem. If loss of pressure
is also attributable to crude oil and a less than optimum fracture treatment then artificial
means can be employed to increase flow rates.

9. " No formation water at 77H has been encountered NOR at any other of the 39 well
penetrations of the Y zone within the Cambay field " Very important for flow rates and
the resulting economics.

I think that's enough for me even at this stage, to assume the glass is half full and change
my sentiment from Hold to Buy.

GLTAH