Member Info for Sailplane

10:54
Take a listen to Michael Duncan at 4mins in:
https://www.youtube.com/watch?v=1sUjszlKUL0&t=240s

So, they had ~153,000 acres and have added ~40,000 more.
That’s now ~193k acres which works out, it would appear, at ~301.5 sq miles
And that is equivalent to a square of land some 17.36 x 17.36 miles!!
Though, I do find visualization of a strip 1 mile wide and 301.5miles long easier on the brain cells.
That’s because, I guess that would be like a 1 mile wide strip, almost all the way from London to Edinburgh!!
[London – Edinburgh is about 332miles, as the crow flies]

https://dog.dnr.alaska.gov/Services/BIFAndLeaseSale
select: Current Leased Sales> North Slope Areawide Sale 2022W > Received Bids
This downloads a spreadsheet with the details
Then select: Current Leased Sales > North Slope Areawide Sale 2022W > Results Map
to view the location of the blocks.

Bidding results available to the public online at
https://dog.dnr.alaska.gov
– Wednesday, November 9, 2022, at 9:00 a.m.
Alaska appears to be some 9 hours behind the UK – so that puts results at 18:00hrs UK time.

Those blocks look to be in 3 places around Alkaid.
Wouldn't have thought likely, at those locations, to make commercial sense to be anyone but Pantheon picking them up.
And if it is Pantheon, what does that say about Pantheon's confidence in the Alkaid area.

Posted on Reddit
https://www.reddit.com/r/PantheonResourcesPANR/comments/yo8b1f/what_are_the_most_effective_hydraulic_fracturing/
Of particular interest, I thought, was the bringing together of the FMI tool logs from Alkaid#1 and the vertical fractures seen there and then how we ended up with a large amount of propant returned from Alkaid#2 - maybe coming back from such vertical fractures - and what this might mean for the reservoir's overall permiability - and hence the flow rate - of the Alkaid#2 well.
The interesting section (on Reddit it's with associated slide):
In the Alkaid #1, Vertical Open Fractures are indicated by the dark lines as logged by the FMI (Formation Micro Imaging) tool. The interval shown was tested in the Alkaid #1 and represents the interval completed in the Alkaid #2. Such fractures offer 100% porosity and Darcie's of permeability, and seldom retain sand sized frac propant.

... several tons per sq inch and sizes used range from 0.1mm to over 2mm diameter....
Interesting article:
https://geology.com/articles/frac-sand/

...have the majority of the fracking water back out of the well in a 2 to 3 week period.
Listen from 4mins 19secs in.
https://www.youtube.com/watch?v=1sUjszlKUL0#t=4m19s
And CEO: Jay, talking about the coil tubing unit, which is expected very soon, to clean out the Flowback sand.
Listen from 4mins 45secs.
https://www.youtube.com/watch?v=1sUjszlKUL0#t=4m45s
So, shouldn't be long before we find out what this 'sweet spot' in the Alkaid reservoir can deliver at Alkaid#2.
And as Jay says, Alkaid#2 results showed better porosity and permiability and thickness:
Listen from 1min 37secs.
https://www.youtube.com/watch?v=CRpoZ_7Y1zY&t=97s

said Bob, earlier in the year.
And that he thought the optimum Farm-in time would really be when they start getting the production test results – and that would be some time in the fall.
Listen at 10m 15s in:
https://www.youtube.com/watch?v=vLJbrJU7F3E#t=10m15s

On Reddit, telemachus has posted his thoughts on the RNS:
https://www.reddit.com/r/PantheonResourcesPANR/comments/ycy4nz/excellent_rns_from_pantheon/

09:52 “If sand is being forced back, presumably it is not fulfilling its intended function of keeping the fracks open for flow - is this detrimental in the long term?”
I think the hi sand return is indicative of them using proppant sand grains in the frack fluid mix that are too small ie. they were expecting the rock fissures produced by the frack to be tighter, in which case the size of sand grains used would have become trapped. Obviously, if the fracks open fissures wider than the diameter of the sand used, they will just flow back with the frack water during Flowback clean up.
This does rather suggest higher permeabilities than expected. Good Flowback rate of the frack fluid rather supports this.
And thousands of barrels (of mostly, at this stage, frack fluid) to me means multiple thousands ie. more than 2,000 barrels a day – which bodes very well, I would think, for when we move to the oil cut being closer to 100%.
As always DYOR.

07:16
When the compressed gas, sent down the well’s casing anulus, enters the production tubing through the gas lift valve, the energy of the expanding gas entering the oil in the production tubing rises up the vertical tubing, helping lift the oil to the surface as it does so.
But, hopefully as you can see, this injection doesn’t constantly get rid of excess gas – the lift gas recirculates around and around and so any additional gas coming from the reservoir therefor has to either be used on site for electrical generation or is flared off.
Hence the need for permission to flare.

Alaric: “but i think they will aim for more clean up here to maximise the oil cut.”
Yes, I agree. Because the market would, no doubt, not give them the ‘benefit of the doubt’ if they put out an early RNS, while only, let’s say ~50% oil cut had been reached and the BOPD might, at first glance, appear on the disappointing side.
Better, I think, to wait a bit longer, until the Flowback clean-up has reached a decent oil cut %age and we, hopefully, have a more pleasing BOPD figure to look at.

investopedia.com offers ideas as to the times taken for the various aspects of a horizontal well.
They say that after fracking, the adding of production tubing can take a week.
And then that can be followed by 2 to 3 weeks of Flowback, in which a mix of the fracking water and oil and gas are produced.
Well, PANR's 26oct RNS said the Work-over Rig was due in a week to 10 day - and 10 days from then put it about 6th Oct. If we then add another week for the production tubing to go in, we're up to about 13thOct - it was about this time we got the satellite flare images being seen - which would fit nicely with them starting to get some Flowback containing some gas. So if Flowback then typically takes 2 to 3 weeks to get the well producing a high % oil cut, we could be looking at maybe 27th Oct - if they decide to wait for that degree of clean up before advising us.
But I recall, with Alkaid#1 they did let us know the oil flow rate when they had only cleaned up to about 40% oil cut - so, still room, I guess, for the RNS to be sooner.

See under Hydraulic Fracturing section.
https://www.investopedia.com/ask/answers/061115/how-long-does-it-take-oil-and-gas-producer-go-drilling-production.asp

"Global Oil And Gas Exploration Dives Nearly 60% In 2022"
https://oilprice.com/Energy/Energy-General/Global-Oil-And-Gas-Exploration-Dives-Nearly-60-In-2022.html

https://www.youtube.com/watch?v=Gn5kpnT9rqM&t=447s
Jay informs us.
play from time: 7m:27s

18:45 cbaron “Do we have any evidence of the typically expected levels in sands at the tighter end of the porosity spectrum?”
Well, what we do know, is that the porosity and permeability are better at Alkaid#2 than at Alkaid#1, where the flow rate when only cleaned up to ~40% oil cut was ~100bopd for just a single 6 foot fracked section of well.
So, if they had had the time to test Alkaid#1 longer, would the continued clean up have resulted in proportionately more BOPD when the fracking fluid had all been recovered and the oil cut was closer to 100%?
Then something I don’t think we know, is how many perforating shots per foot were in that Alkaid#1 6 foot frack and how many are there in each of the 30 fracks we now have in the Alkaid#2 horizontal?
Having now read that perforating guns can deliver between 4 and 12 perforations per foot, I don’t think we can simply assume each of the 30 fracks will produce along the lines of the single Alkaid#1 6foot frack – the 6foot fracked section at Alkaid#1 may have had anything from 4 to 12 perforations per foot, and having viewed several YouTubes on horizontal fracking, I would have doubted each of the 30 Fracks on Alkaid#2 were likely to be carbon copies of that - but I just don’t know – I’ve not seen PANR mention this sort of info anywhere.
A bit of an interesting overview on perforating guns:
https://www.epa.gov/sites/default/files/documents/casingperforatedoverview.pdf

A short, interesting explanation of the expected differences - due to the nature of the rock - in fracking tight sand v shale reservoirs:
"... if the formation does initially produce at an acceptable rate, it is more likely that the well will continue to flow with a lower, but steadier flow, than the shale well, and for a considerably longer time."
https://oilprice.com/Energy/Natural-Gas/The-Differences-In-Fracking-Tight-Sand-And-Shales.html
Explanation starts about 6th paragraph in. And though the article is primarily angled at tight gas production, it's the information about how the different rock types react to the fracking process that's interesting.

"A workover rig is estimated to arrive to location over the next week to ten days to install production tubing prior to commencing flow testing operations. "
from 26th Sept 22 RNS.
Not long now.

Footnote:
(1) Total Revenues are defined as the total amount of invoiced sales during the period. This number is seen by management as more accurately reflecting the underlying cash generation capacity of the business as opposed to Revenue recognised in the Condensed Consolidated Statement of Comprehensive Income.

And the Revenue comment:
As previously highlighted, it is important to note the impact of take-or-pay accounting rules under IFRS 15 on our Income Statement as regards to revenue recognition for our gas sales agreements. The Revenue shown in the Condensed Consolidated Statement of Comprehensive Income includes only the gas, oil and condensate that has been delivered. The Total Revenues(1) of US$128.7 million (H1 2021: US$116.5m) includes the volume of gas that customers are committed to pay for under the take-or-pay terms of the gas sales agreements, which includes gas that has been delivered plus gas invoiced but yet to be delivered, plus oil and condensate revenues.

So, the actual Take-or-Pay revenues at $128.7m are some $42.9m higher than the $85.8m revenues used in the consolidated accounts statement. So to my mind that lifts the Total comprehensive loss of $20.545m to a profit of [$42.9m-$20.545m]
= a profit for 2022H1 of $22.355m.
But where then has that $42.9m gone as it's not shown in the consolidated income statement.
Well the Debt amount has reduced by - you guessed it: $42.9m
Yes, they say: Net debt $327.1m at 30june22 and was $370.0m at 31dec2021.
Am I right?