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But 4.32 million billion new UKOG shares would make my current UKOG shareholding worthless
Mirasol - you've missed the point.
It's UKOG doing a reverse takeover of BP, where SS will become new `CEO on salary of $50 million per year.
It will be transformational for BP under his leadership and current share price of 360p will plummet to 3.6p by this time next year. Get out of BP now before the train leaves the station!
Wako
Ensign gas field
https://www.researchgate.net/publication/288472033_The_Ensign_enigma_Improving_well_deliverability_in_a_tight_gas_reservoir
Wako
Selene was ‘discovered’ by Centrica by drilling 48/8b-2 which found gas in Rotliegendes Sandstone. But reservoir quality was poor possibly because the well was drilled very close, or maybe even into, the large fault zone that bounds the Selene structure. There was also evidence of late stage dolomite pore occlusion. Subsequently, several operators tried offshore hydraulic stimulation - fracking - with spectacular improvements in productivity. The nearby Ensign gas field is a good example of a sub-commercial discovery becoming highly profitable from fracking. The other problem with 48/8b-2 was depth conversion of the seismic and it now looks like the well was drilled right on the edge of the Selene structure close to the gas-water contact - effectively an ‘appraisal well’ meaning the next well will be the ‘discovery well’ - hence high chance of success. It’s also right next to Shell’s Barque gas field and the pipeline system to the Bacton terminal - that’s why Deltic licenced the block.
TBH I believe Selene is a much better prospect than Pensacola which could spring a few surprises in the Zechstein reservoir as Murphy’s Law comes into play.
Harry
Cluff - now Deltic used analogues and operational techniques developed by Shell in the Netherlands to assess their Zechstein play. This was all done before Shell’s farm-in. It’s all covered in the 2015 CPR - see pages 145 - 150 for relevant figures.
https://www.cluffnaturalresources.com/wp-content/uploads/2016/01/5-Axis-CPR-on-Southern-North-Sea-Assets-02-December-2015_Optzd.pdf
I heard Deltic took a look at WN when it was on the market as a farm-out, but Deltic decided it wasn’t for them - a wise decision in hindsight. On other hand, RBD’s recent experience at WN has subdued unwarranted enthusiasm over the chance of success in Deltic’s Zechstein projects.
Also, Deltic is now in the clear financially, with Shell and Cairn running the show. The main risk now is a UK government clampdown on E&P similar to Denmark and the green trend developing in Norway. It’s probably a good time to invest in vacant pore space in depleted fields where captured carbon can be stored!
Harry - they also use coiled tubing rigs -
https://www.searchanddiscovery.com/abstracts/pdf/2003/intl/extend/ndx_83739.pdf
Harry
No need to consult NAM (Shell) - their work has been published for many years in professional press, including reservoir engineering, drilling technology, petroleum geology etc - all in equivalent Z2 Zechstein gas reservoirs.
Penguins
You’re right - total waste of money.
The 2016 227 mmbbl ‘independent consultant report’ was cleverly named so as not to be a ‘Competent Persons Report’. It was misleading because it never referred to the fairly comprehensive data, cores and flow tests conducted at Arreton-1. How this, and the subsequent Arreton-2 well can be described as a ‘discovery’ misrepresents the facts.
British Gas drilled Arreton-2 next to Arreton-1 to drill deeper and establish the eastern limit of the Sherwood Sandstone - the main reservoir at Wytch Farm, which turned out to be absent at Arreton-2.
SS must know the background, yet the most recent CPR assesses the commercial chance of success at 75% - which is bonkers.
BP Arreton 1 completion report link.
https://ukogl.org.uk/map/php/pdf.php?subfolder=well_reports&filename=01+-+Exploration+Wells%2FARRETON+1%2FARRETON+1_Well+Completion+Report.pdf
Page 2 -3
".. Only very slight traces of Oil were encountered ..."
Page 10
"... At 2560 feet a 4 inch band of brown compact limestone was strongly impregnated with oil - the strongest show noted in the well ..."
Do what NAM does in the Netherlands.
Drill wells under balanced and keep mud filtrate out of the reservoir near the well bore. Don’t acidise
https://www.countypress.co.uk/news/19642728.petition-isle-wight-oil-drilling-reaches-county-hall/
Cardinal 3
The Arreton-3 result RNS could be written before the well is drilled, saving PI’s a lot of money, based on previous drilling.
BP Arreton 1 completion report link.
https://ukogl.org.uk/map/php/pdf.php?subfolder=well_reports&filename=01+-+Exploration+Wells%2FARRETON+1%2FARRETON+1_Well+Completion+Report.pdf
Page 2 -3
".. Only very slight traces of Oil were encountered ..."
Page 10
"... At 2560 feet a 4 inch band of brown compact limestone was strongly impregnated with oil - the strongest show noted in the well ..."
https://iow.moderngov.co.uk/documents/s5106/Arreton%20Report.pdf
Actually Penguins - the area of the ‘deposit’ correlates quite well with the Lower Cretaceous surface outcrop from Chiddingfold eastwards. Reflection seismology 101.
GP - there’s always one dog which won’t stop barking at the passing car.
It’s usually because it wants attention. The more its ignored the louder it barks!
Good points Mirasol,
Almost all the 1979 - 1985 Vibroseis in the Weald was operated by two companies, Conoco and Carless, using CCG for acquisition and SSL for processing. Subsequent licences benefitted from all this legacy data. There were two distinct approaches. Conoco supervised their acquisition and processing using Company specialists flown in from Ponca City, Oklahoma, whereas `Carless used what you might call a 'hand-crafted' approach taking into account the small details of the surface geology, especially statics.
By modern standards the survey equipment was quite primitive. 48 channel recording with 50m shot interval and 50m receiver interval. So the split spread maximum offset was 2400m which was more than enough for velocity analysis/NMO correction since maximum TWT needed was 3 seconds - the target horizons are between 700 and 1400 milliseconds. That configuration yielded a 25m CDP interval with 24 fold multiplicity. But it worked, and the same seismic crew worked continuously for about 4 years acquiring about 100km per month at a cost of £1000/km.
Apart from all the above nerdy seismic stuff, precision was crucial - a +/- 10 millisecond static error to the seismic datum could create a +/- 40 ft depth error in mapping - as Conoco found to their cost at Godley Bridge 1 and 2. I just hope UKOG has taken this into account when selecting the Loxley location.
Penguins
Interesting relinquishment report which highlights how 'wrong' seismic mapping can be if static corrections are not calibrated with upholes and LVL/weathered layer surveys - especially where the outcrop is Lower Cretaceous.
The report notes Conoco conducted only 9 upholes complimented using a refraction crew over their area. The UK Onshore Geophysical Library used to have all upholes catalogued. Over the Humbly Grove licence area there were 80 upholes, such was the requirement for accurate statics and depth maps.
When, and if, Loxley is ever drilled I'd be surprised if formation tops are close to prognosis and, if gas is present, the statics issues will make volumetric calculations subject to a wide range of uncertainty.
Grey Panther,
Don't fret about others' comments.
In Turkey and further east there is a common, old expression - 'Let the dogs bark, the caravan moves on'.
If you've ever driven through a small village in Turkey, Syria, Iraq, Iran, India, ****stan etc the moment the car arrives, packs of dogs appear from nowhere and start barking but do no harm. It upsets their canine world. And the car driver always says 'Let the dogs bark, the car moves on'
Same on many bulletin boards - it's normal.
GP - let's remember Raithlin has been in business in UK for many years, starting with their exploration campaign in the Raithlin Basin in Northern Ireland which was stymied by local planners fearing fracking of the tight reservoir. In my experience, Calgary-based petroleum geologists would have written off the Kirkham Abbey Formation early on. Connaught's investors would like to see a return on their investment at some point, although the Calgary oil and gas scene is quite different to AIM in terms of raising money.
But that's no reason for a gloomy outlook because the gas is there and Raithlin/Reabold is pioneering the approach to commercial production which has defeated oil companies for 9 decades.
This 'breakthrough' opportunity is the attraction of this share - not the repetition of '118 metres of gross pay' we hear all the time.
Oil and gas is a highly technical industry - Reabold's key selling point is a solution to commercial production in tight magnesian limestone. So let's have an answer from their experts as cloves suggests rather than S&S blathering about it.
That's why I'm invested.
Snaffleman
I’d like to know precisely the nature of the ‘formation damage’ at WN-B because surely it is a clue to the technology needed to produce gas from the Kirkham Abbey Formation. Anyone who can make this work will have the run on the existing discoveries in this part of UK land, and perhaps others offshore.
As Grey Panther noted, the moment gas and condensate separate there are two fluids in the reservoir pores and capillary forces come into play. In very tight dolomitic carbonates like WN the pore throats connecting the pore spaces are very small and flow is much easier if a single phase fluid is present. But the moment a liquid and a gas phase are present, flow is dominated by capillary pressures. The condensate becomes the ‘wet’ phase and ‘wetting’ describes the molecular bonding of the condensate liquid to the rock matrix. Wetting, and the surface forces that control wetting, are absolutely fundamental to reservoir engineering, mainly due to capillary effects. This is why a tight rock ‘wet’ with condensate can become a barrier to the passage of gas.
Conversely, in an oil reservoir saturated with dissolved gas, if gas is allowed to ‘bubble’ in the pores, when pressure is reduced by too much drawdown, the gas bubbles create a barrier to oil flow.
In the case of WN-B it could be that the spent acid - essentially water - became the (un-intended) wet phase deep into the near well-bore zone, which effectively became a barrier to both condensate and gas inflow from the reservoir itself. In Sachin’s words ‘formation damage’.
Overall, it appears the Kirkham Abbey Formation at WN is no more friendly to the reservoir engineer than the many similar, but non-commercial discoveries in the area. Acidisation hasn’t worked.
So, question for Raithlin/Reabold specialist advisors - What is the plan for WN-A?
Harryshang
Thanks. GP's post got me thinking about how WN might progress. It just seems the Raithin/RBD had put the cart before the horse by presenting a scoping plan for development to the local authority.
For example, without knowing basic fluid parameters such as the dew point and flowing well head pressures, how could they describe the type and size of the gathering plant? These types of fields are often developed with flow lines operating at well head pressure and what is known as 'multiphase flow' where gas and fluids, including water, are sent to the processing plant for separation rather than at the field itself.
A good example is the Central Area Transmission System which sends fluids from North Sea to Seal Sands near Middlesborough and feeds the big chemical plants there. So 'wet' gas fields like Breagh use multiphase pipelines because it is more cost effective to separate fluids onshore than to build the kit offshore and needing separate gas and liquid pipelines.
Maybe S&S will enlighten us in the next RNS?