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My understanding is that HUR need to drill a vertical Commitment well to determine the actual oil water contact depth and so be able to more accurately determine the field size - a field determination is apparently required before they can proceed with development ie. hooking up Li Crestal to the FPSO - what they have now got from the OGA is more time in order to get all this sorted .

"Talitha's two other zones, (i) The "Slope Fan System" (Brookian), and (ii) the Kuparuk Formation also offer significant potential to Pantheon. The analysis is not yet complete on these two zones and will be announced to the market once that work has concluded. "
Anyone know approx timescale for this analysis?

Yes, they achieved close to 15kbopd from just the 6 well for about a 2 month test period - and of course they could then decide to add in a little more 'top up' from the 7z well - it isn't that the 7z has gone away, we still have that as a good well (a little wetter than the 6) but still on its own the 7z has managed about 15kbopd - remember, we do still have 2 good producers, its just that the reservoir matrix of fractures between the wells is so good, there are instability interactions between the wells when both are producing together at high rates. And I think we have to remember just how good these flow rates are compared to those of many conventional reservoir wells.

https://www.bnamericas.com/en/news/peru-pressing-hydrocarbons-restart-as-royalties-slide

From:
15 September 2014 Post-Well Analysis: Lancaster Appraisal Well 205/21a-6
-- Data from this well indicates that under production conditions and a moderate 120 psi drawdown the basement reservoir could deliver 20,000 STB/d from a single well.

" the only thing green about Green Energy is the money it makes...."
https://www.youtube.com/watch?v=c4NvDaMQs6g

https://www.youtube.com/watch?v=Zk11vI-7czE&t=2643s

https://www.vanguardngr.com/2020/05/state-of-nigerias-power-sector-worsens/

It looks to me that the Lincoln Field Determination, required by the OGA, is required because of the Lincoln field possibly venturing into a neighboring block (if you look closely at maps of the field) - the neighbor I think is PMO. So, I assume that the commitment well has been requested to get an accurate oil water contact depth and so enable this data to be married to the seismic to give an accurate lateral extent to the field.

https://energy-analytics-institute.org/2020/05/11/argentina-to-restore-artificially-high-oil-price/

(unless the appraisal well could double up as producer?)
Didn't they say, regarding the Lancaster horizontal wells, that the production was at present only coming from the 1st 40 meters or so of the horizontal sections - so it would appear one could reasonably get a suitably long section of a vertical commitment well to double up as a producer on Lincoln - isolating the lower reaches of the well down to the aquifer after the well has proved up the oil water contact depth.

The OGA document: https://www.ogauthority.co.uk/exploration-production/development/field-determinations/
says:
"The final determination will be made following all relevant discussion, and must be in place prior to first production."
So if the OGA will not be flexible enough on this P&A issue, why can't HUR get underway with coupling up the Lincoln crestal well to the FPSO , so preventing it being an unused well that needs to be P&A'd . Then HUR complete the required OGA Determination with the Lincoln field commitment well - and thereafter getting the OGA consent to produce from the now connected up and ready to go Lincoln Crestal. So avoiding the waste and cost of having to P&A the Crestal and then drill another Lincoln producer.

7th May 2020:
North American Pipeline operator commenting on shut-in well restarts:
Targa Resources Corp. was asked Thursday if the wells its system serves would ever ramp up to previous volumes.

“I think for the most part, we’d expect the shut-in volumes to come back and perform well,” Targa CEO Matt Meloy said. “Could there be some older, really low-rate vertical wells … which they shut-in and just don’t bring back?
I think there could be some amount of those.”
https://business.financialpost.com/pmn/business-pmn/shale-sector-faces-great-unknown-when-time-comes-to-reopen-wells

Anyone come across why this pipeline is considered a covid19 risk?
- why are we not seeing pipelines around the world being similarly shut down?

In the CMD RNS, regarding the Lancaster production wells, it says:
"the potential productivity upside of these wells has yet to be tested"
Has it been said in any RNS, or in the Q&A session, if and when this potential productivity upside might be tested?

The government of President Martín Vizcarra had previously said it would restart key activities in four phases starting this month....
https://www.nasdaq.com/articles/copper-giant-peru-to-gradually-ease-restrictions-on-mining-sector-in-may-2020-05-03

In 2020, the planet's oil wells will produce nearly 12.7 billion gallons a day of, surprisingly, water.
...an average of three to five barrels of water is produced with one barrel of oil. That means water is the number one fluid produced by the oil industry.
Never knew they could be that wet ! Makes our wells look positively parched !
https://www.cnbc.com/advertorial/2017/11/13/five-barrels-of-water-for-one-barrel-of-oil.html
and never mind the oil in Texas - look at all that water:
https://mercercapital.com/energyvaluationinsights/an-overview-of-salt-water-disposal/

Does the Q&A cover why there appears to be an OGA approval problem with Lincoln Crestal tie-back to the FPSO.
Why the talk about a possible Lincoln shallow well to tie back if Lincoln Crestal has to be P&A.
What would be the difference from an approvals point of view?

Just had another look at CMD slide 15 – “Testing the reservoir thro’ stepped production increase.”
Period 1 (May 2019) shows the initial flows – one well at a time - of the 6 well at 17kbopd and then the 7z well at 17.5kbopd which sounds reasonable.
But then the period 7 ie. April2020 I read it as showing both wells flowing together at a peak of 21kbopd for the 6 well and a pretty simultaneous peak of 27kbopd for the 7z well. That’s briefly 48kbopd !!
That can’t be right, can it?
For a start how would that be accommodated by the FPSO – for which I have a max crude production shown as 30kbopd.
I thought they might be water plus oil rates, but the diagram key shows them separately as oil rates in green and water rates in blue.
I must be somehow reading it wrong. Can someone else have a look at that slide 15 and see if they read it differently.

Looking at the RNS for the 7 vertical pilot well on 9sept2016 - it saying:-
"DST testing of the basement reservoir yielded a maximum, natural flow rate of 6,600 bopd and a maximum flow rate of 11,000 bopd (artificial lift with an electrical submersible pump) of good quality 38 API oil with no formation water produced."
If from a vert well one can get such good flow rates near the FPSO, why would you not 'kill 2 birds with 1 stone' and drill the commitment well, to please the OGA and find the measured depth of the oil water contact, as they require - but drill it close to the FPSO so it can then be hooked up as a producer. If there is the gas flare problem for production amounts above 20k bopd then at least HUR would have a 3rd well option to select and could use it rather than the 7Z well with its current water cut - that's assuming the new well had a lesser water cut, of course. Whatever, it would give the security of having a 3rd well in hand should, at any time, the need arise. They after all do say that testing has shown that the oil is coming from the first few meters of the horizontal wells so why drill a 1 km horizontal .
So, what's the snag, I've not spotted, with this idea?

But even nicer, Prose, your link shows the last 4 days (19th-22nd) at an average of 14,909bopd.