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Hi Welsh. its not always possible to define whether you have entered a water zone, particularly before electric logs have been run.
Lowish permeability formations often have extensive transition zones, where both the oil and the water are mobile. SS probably could not be sure whether the drill bit was in oil or water at the toe, when drilling was terminated. otherwise, as you imply, the toe could have been squeezed prior to completion. IMHO
Water ingress at the toe can be eliminated easily. I would expect a cement squeeze, since we are dealing with a slotted liner. A simple mechanical plug in the tubing string would not isolate anything. Its much easier to squeeze the toe than to shut off water from the middle of the section, since, in that case you would want to re`establish production from the zones beyond the new plug. A simple cement squeeze at the toeshould be possible in the near term,
Just one word of warning. Although 'bleeding oil' at least confirms the presence of oil, in my experience, it can also be an indication of relatively low permeability. In theory, if the rocks are of good permeability, the oil is flushed from the core during drilling operations. On the other hand, if oil is bleeding from the core, when its brought to surface its an indication that the low permeability rocks are holding the oil in place, rather than allowing it to be flushed out. And low permeability means lower flow rates. So, be careful!
GLALTH
In order to put HH-1 and HH-2z on to long term production by the end of the year, don’t HHDL need approval of an FDP from OGA?
This is likely to be difficult in the case of HH-1, as we are given the impression that much more data and analysis is required on the Kimmeridge before an FDP can be formulated.
Presumably, HHDL will be talking to OGA about a Portland FDP, on the basis of their own reserve estimates, since the CPR is unlikely to be available until well into the new year. IMHO
IMHO the last thing we need is more borrowing from Riverfort/YA, and a still greater share overhang. Seems to me that PIs would be far better off if the BOD pursued a more conventional equity issue - rights or placing.
Furthermore, there is no need whatever to acquire the Alba stake in HH. The difference in profitability would be marginal, but a continued share overhang would be bad for current holders and for company reputation. A gift for trolls. GLA
There seems to be a lot of uncertainty regarding future drilling. I can see the rationale for continuing to produce HH-1. Why reduce the revenue generation when we have slots and approval for new wells?
Alternatively, it would not make sense to drill several wells - depleting cash resources - without putting each one on (test) production as soon as possible.
Since the reservoir pressure depletion is less than expected, this supports the notion of a bigger STOIIP initiated by the discussion of the 4th core. This suggests that further drilling in the Portland should be a priority - for production presumably, since there's no produced water to be re-injected. Its to be hoped that SS is reviewing these options, so that we can retain the rig. We have a busy potential drilling programme ahead.
One option which I hope we can now put to bed is the use of the convertible funding vehicles. Surely, a placing or rights issue would have left shareholders - and management? - in a much better and less uncertain position than we are now in. There seems to be substantial support for the company and its plans, despite the continued absence of IIs, since the acquisition of Magellan was proposed. IMHO we would have been in a far better position by now with a more conventional equity raise. GLA
One of the factors affecting the short term flow rate from a well is the length of rock contributing to flow ('h') and the rock permeability ('k'). There are other factors as well, particularly the degree to which the operator 'sucks' from the well - the drawdown (reduction) of pressure at the bottom of the hole.
Since the HH-2z well is in contact with a lot more (70x) 'h' than the vertical well, K times h will be a lot more. However, as you say, 70 times the flow rate is not possible. Instead, it is likely that a certain flow rate, such as 1000 bopd, will require a much lower pressure drawdown than the same rate for a vertical well.
GLA
I agree CT40. I would go a bit further and say that even lowish vertical permeabilise can be very effective when they occur consistently over a wide area. Perfect communication over the whole area is unlikely to be necessary; small areas of decent vertical permeability can provide all the pressure support required for sustained flow rates.
Regarding the potential effects of small scale faulting, not everyone will recognise the benefits of horizontal boreholes in being able to drain small isolated fault blocks, which otherwise may remain undrained by conventional vertical or inclined wells. GLALTHs
Penguins,
I have not looked at the HH -1 core analyses, but I believe that permeabilities of 3md upwards would give good flow rates from a 3,200 ft interval.
In addition, the supposition from SS that the pressure depletion seems to be less than expected indicates to me that the amount of oil 'seen' by HH-2z is likely to be greater than expected from previous data, ie the STOIIP may be calculated to be greater than the volumes indicated in previous analyses. I am sure that you realise this, even if it is inconvenient for your preferred position.
GLA
Apologies. A rate of 3500 bopd would generate $77 mm of GROSS revenue, not net.
So the $4.5 mm accruing to Alba's interest from just 50% of the target rate (ie 1750 bond) would be gross inflow, or $3mm net. IMHO
With the oil price at $60, and costs of c.$20/bbl, net revenue is about two thirds of gross revenue.I'm not sure that HH can average 3500 bond next year, but if it did total field net revenues would be c.$77 mm, of which Alba's share would be $9 mm (unless reduced by penalties for not contributing to cash calls). Even if average 2020 production was only one half of the 3500 target, a cash inflow of c.$4.5 mm would be welcomed IMHO
Mirasol,
On the OWC-STOIIP issue, the RNS stated "Results of analyses that directly impact the field's possible increased oil in place and recoverable oil volumes will be reported in due course".
So, the work is underway, and results are not yet available.
Changes in STOIIP due to changes in the OWC will probably take a bit of time to quantify, and important enough to need close checking before disclosure. GLA