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1.3 million m/c
Someone is extracting the Michael!
15-Apr-24 12:47:10 0.042 78 Sell* 0.04 0.05 0.03 O
15-Apr-24 12:47:03 0.043 1,898 Sell* 0.04 0.05 0.81 O
15-Apr-24 12:18:03 0.044 227 Sell* 0.04 0.05 0.10
52 Week Low 0.045
52 Week Low Date 15-Apr-2024
PBoo,
So can you point out exactly where BP is wrong in his posts on Balcombe, why you think so and what the correct interpretation should be?
Sorry to burst you š«§ but you have not got a clue what your talking about, as per usual.
How many years in the oil industry š¤
They get their money from shareholders not sales, so trying to pump the SP is UKOG's top priority.
Expect some ridiculous announcement about Portland and it's Ā£1b risk free opportunity prior to a major fund raise. They will then spent the money on directors salaries before announcing that they aren't in a position to bid for this year's hydrogen storage round, but they will aim to bid in the next round and then not even do that as no-one is interested in the project.
P&A costs now greater than cash balance. Do the math, the councils are gonna be peeved.
"All Investor share transactions are subject to:
Ā· an orderly market provision that provides that the maximum number of shares which can be traded by the Investors or any of their affiliates in any calendar month shall be such number of shares which is equal to twenty (20) per cent of the number of shares of the Company that have traded during the previous calendar month (as confirmed by the reports available by Bloomberg or their equivalent);
Ā· neither the Investors nor any of their affiliates shall hold any net short position with respect to the equity of UKOG during the Loan term; and
Ā· Investors will exercise any share voting rights in support of any resolutions proposed by the Company."
I'm not sure they will pay off the first Ā£2m given the low trades other than the ones made by YA before the AGM when they will have to go cap in hand to shareholders for the right to issue more.
The only question is will they do a placing to pay for HH-2Z and funds to keep the lights on before the AGM.
Sorry Pete - you may be correct, but are you honestly expecting anyone to take that verification seriously when you reference Adrian? Come on
I put Pboo on filter a couple of years ago. He is madly in love with UKOG, as is Adrian. Both are as bad as each other, short as two thick planks to boot.
Well I will leave the world to evaluate your high quality post Peeeeeeeee Boooooo,,, as clueless as ever, give Adrian my regards in the den !!
The problem Bubblepoint is no oil, other than a Tesco bottle mixed oil and water was ever seen.
No and I repeat no oil tankers ever left the site. The site was being monitored 24/7 by the locals camped outside on the grass verge. Adrian and the other eyes were also there on a regular basis. No Oil tankers were seen going in or out
Penguins,
There will ALWAYS be potential for pockets of migrated/trapped hydrocarbons with such a vast source throughout the basin, finding them is the real skill, and then the big question, commercial or puddle ?
Either way, they already demonstrated there are mobile hydrocarbons at Balcombe, I think my write up was pretty clear on most fronts, but it will at least be interesting to see how this one comes out...
BP,
Let's see what happens when they test the well properly, which is the plan. The testing as reported seems a shambles - though AIM oiler reporting of testing leads much to be desired.
I don't remember seeing what volume of oil was produced during the tests rather than flow rates which can be deceptive. Did Angus ever publish the volumes of oil produced?
Ignoring the specific water issue that appears to be answered by statements from Angus about salinity there is nevertheless the lack of any other Kimmeridge well being put into production - all supposedly technical successes and much vaunted when drilled - Brockham, Lidsey, Broadford Bridge, even Horse Hill.
True to form :
No revenue is expected from UKOGās interests in the Pinarova-1 well, which the company previously described as āirresistibleā and had hoped for ārapid monetisationā of reserves. Testing revealed an absence of commercial rates of hydrocarbons and has been halted.
https://drillordrop.com/2024/04/13/horse-hill-production-fall-hits-ukog-revenue/#more-104973
In view of the money they threw into the sidetrack, the number and quality of the consultants they (and Angusās predecessors) used, and the time it took, there would, surely, have been good reasons for each of the decisions they took, at each stage. Wingas could have done the work far more cheaply but didn't think it would be worth the investment. So much so, that they paid Paul Forrest to take it off their hands. Itās a heavily depleted field with a complex structure. Even with all their new seismic and expert interpretation, it appears to come down to a matter of hit or miss. Lord Lucanās shortcoming throughout his tenure lay in his reluctance to level with shareholders - and of course in failing to avail Angus of the much cheaper bank finance that he said he was offered nine months or so before the shocking revelation of the Ā£12mm loan requirement, and the eight months after that that it took to conclude the equally shocking terms for the loan. One should also remember that if theyād got the field going again nine months earlier (and they had Covid and related supply issues to deal with) Angus would have enjoyed the big spike in gas prices and would have avoided the huge losses on the first two months of their hedge contracts. It would be a very different picture in such a case. As the poet John Greenleaf Whittier put it:
āOf all sad words of tongue or pen, the saddest are these: āit might have beenāā. Innit?
Ocelot,
Yeah, but either way, Vonk, GL, etc they are just as bad as each other, same as the leader of this too. terrible. BUT hopefully RH is a little more on point, though much damage to repair.
Bubblepoint,
Appreciate your posts of this morning.
In fairness to George Lucan, the testing of Balcombe pre-dates his time at Angus, going back to Paul Vonk.
Hi ZYX,
Yeah pretty disappointing in that regard, as you say, cheap & cheerful to use and clearly demonstrates what is what.
That said, Angus were imo "sloppy" much of the time in their past, and their past leader Lucan, left a lot to be desired in his approach and corner cutting. I do believe the new leadership is a "little" more switched on, and prepared to "try" and stay on the straight & narrow, which "may" at least ensure they do this properly the next time round, ultimately resulting in a definitive proven or fail, not some carp that is full of grey, foggy sheite and unanswered questions.
BP,
Pretty much what I was thinking when I read their RNS's at the time.
The one thing that did surprise me was that they apparently didn't use a tracer in either the drilling fluid or the kill brine.
Maybe because I've spent most of my time doing Exploration Wells, but I've always insisted on using a tracer - preferably an Iodide tracer.
Easy to use, cheap and with an Iodide tracer, (unlike others) there is zero chance of any confusion as to what is formation fluid and what is fluid that you've used during drilling / testing.
Penguins, below is my take on Balcombe, using ALL info and my 30+ years industry experience & Knowledge, may prove right or wrong, but from my side I deem it VERY strong potential. I wrote this post about a year ago for the Angus board, but since you are discussing it then I thought I would put it here too.
My take on Balcombe:
Primarily Balcombe was a successful discovery, they discovered light oil and produced from it under testing conditions.
The well had to be lifted prior to testing, meaning they had to run coiled tubing to enable pumping of Nitrogen which lifts the column of kill fluids, residual drilling fluids etc that are sitting in the wellbore and preventing the reservoir from producing any hydrocarbons.
They achieved natural flow to surface for both tests, the first test produced notable water along with hydrocarbons, roughly 850bbls of oil with approx. 200bbls of water.
The second test flowed naturally to surface at almost double the flow rate of test 1, approx. 1600bbls of hydrocarbons and a much reduced volume of water, approx. 105bbls water.
The Company also noted they initially recorded flow at around 3000bbl/day with the well slugging.
What do I take from all the general information available and apply my take on that ?
OK, I donāt take much notice of the stupidly announced initial slugged 3000bbl/day, why ? because often what companies do is they might get say 125bbls of oil slug to surface in the first hour only. What do they likely mean by āsluggingā, well this is most likely referring to the coil tubing that is pumping down nitrogen to start lifting fluids out of the well, the nitrogen is a light pocket/bubble of gas pumped under the column of fluid in the well, the gas wants to rise to surface and while doing so the pockets of nitrogen lift/drive out the fluids above them. The slug is referring to the pocket of liquids being lifted by the pocket of gas to surface.
So what a company can do is say Heyyy ok there was still a chunk of nitrogen left in the horizontal when we opened the well for the first flow test and that nitrogen came out from the horizontal and then slugged up some notable slugs of oil to surface, equating to 125bbls in the first hour, 24 x 125 = potentially 3000bbl/day.
It isnāt a good idea to spout slugged numbers, they are very unreliable and likely without the residual nitrogen escaping back out the well. It would never naturally produce such a high constant 24/7 rate.
Move on to the āactualā rates, the 1st flow test had a 22% water cut, which they were not expecting, and with this amount of water entering into the wellbore will seriously inhibit production and flow stability, water is heavier (denser) than oil so any water rising up the wellbore will weigh on any lighter oil trying to come to surface, this means your wellhead pressure is going to be less and may even stall out to zero if enough water % is entering into the wellbore column to surface.
Move on to test No 2, they flowed at double, approx 1600bbl/day, and MOST importantly only produced around 105bbl/day of water. You ask HOW so ? surely double the oil rate should = double the water rate.
For me it was very significant, it was demonstrating that whatever water was remaining in the wellbore and near wellbore reservoir was depleting, it was depleting because this water was pumped into the wellbore likely as a ākill fluidā and because water is more dense than oil, it will try to go all the way down, and possibly push into the near wellbore reservoir, where it will sit until the day someone lightens the fluid column back to surface again, and then what happens is the oil sitting behind the suppressed water then drives the water outwards and upwards to surface.
What they eventually discovered was that the water was of high salinity, similar to Brines used for well kill purposes etc, and the salinity did not correlate to anything within the region.
Therefore I strongly expect that a much longer test period would see water production eventually decline to zero.
Importantly, what needs to be considered is that the Balcombe target reservoir was only 2700ft from surface, which means that the pressure at reservoir is very likely not that high. Example, if the pressure at reservoir is say 1000psi, and say light crude oil has a gradient of 0.2 psi/ft then that means the column of oil to surface (2700ft) weighs 540psi, meaning you only have an underbalance at reservoir of 460 psi trying to push the oil out at surface. (simplified in layman terms), if you have saline water in the wellbore too, saline water could be 0.5 psi/ft, so if you have 1/3rd of your wellbore with saline water in it and 2/3rds filled with oil to surface, then the surface pressure will be zero, the column weighs greater than 1000psi at reservoir and you well will not flow until you remove more water.
My take on the actual flow rates achieved: The Company stated it was a 7 day test, but did not state how long each test was physically run for, it could be hours, it could be days, only they know. But the important fact here is they did demonstrate highly mobile light crude that did produce naturally and dramatically improved by the 2nd test, that tells me the reservoir pressure isnāt huge at that depth, because the significant increase in oil to surface was because the saline water was also significantly less, meaning less weight of water in the column to surface holding back the oil wanting to get out.
Is Balcombe commercial ? In my opinion it is highly likely it is commercial, but it is highly likely that long term sustainable production would be by installation of completion with pump to eliminate the issue of wellhead pressure/reservoir pressure decline.
What rates are possible long term? I do not think they would look to produce big numbers, I think they would go for much lower steady & continuous production, maybe 300=500bbl/d. I think that for 2 main reasons, firstly to best manage the reservoir and allow optimum drainage to be achieved, and secondly it is highly likely Balcombe would require onsite facilities to process and store, before being road tankered away.
A typical tanker can hold around 200bbl, and I do not think they would push locals and local routes with more than 2 possibly 3 tankers back and forth each day, even that could cause local irritation and issues, and likely onsite storage would need to be limited, maybe 2000bbls processing and storage to limit local focus.
That is my take on I ;-))))))))))))
2/10/18
'The water produced was not expected, the Company's testing team believes a small high-pressure water zone was intersected in the horizontal section of the well which will require isolation in the future.'
Not sure that is as encouraging as just cleaning out the kill fluids a d everything will be fine. UKOG initially just thought they needed to isolate, in the Portland, a fracture zone in the toe of HH-2z - and that was after UKOG had run logs to identify where the water was coming from.
The Kimmeridge is expected to be fractured, the reason it can flow reasonably if only whilst 'unloading' from the fractures, and in 2018 production from the Kimmeridge at Horse Hill was still planned so was used as an example by Angus of the Kimmeridge performing well vs what happened at Broadford Bridge.
Even if water influx isn't an issue long term production from the Kimmeridge at 'strong rates' is yet to be proved anywhere, I'd certainly be cautious about initial flow rates being indicative of anything much except an opportunity for a P&D.
I hope Balcombe proves the Kimmeridge can be put in to long term production, but it certainly isn't a done deal.
Cyan,
You are far from correct regarding Balcombe, it has been clearly demonstrated that they simply failed to clean out the kill fluids etc from the drilling processes during that initial test that was performed, the plan going forward is to re test it and ensure it is cleaned up fully, for which I strongly believe will prove strong hydrocarbon rates.
Brockham IS a total waste of time, but likely Angus simply want to play with it and squeeze a few more worthless barrels out of it rather than P&A and have to run the "return" to field restoration cost.