Member Info for Exploration

No1plasterer

Onshore fracking in UK is waste of time and money because the geology is 'wrong' for shale gas.

But hydraulic stimulation in tight conventional reservoirs has rejuvenated North Sea Rotleigendes play in prospects like Selene. I expect Shell will drill a 5000 or longer horizontal well into the reservoir where gas was discovered 20+ years ago and then conduct a multi-stage fracking job, including a few hundred tons of propant, to stimulate commercial flow rates.

Shell did similar at Clipper South which was effectively become non-commercial, followed by same treatment in other fields and prospects in the area.

So fracking is central to Deltic's success at Selene.

86EE - if drilling starts early November that implies any results announcements will be late January 2023. I expect Shell/Deltic will keep news to themselves in the meantime with 33rd Licence Round applications due mid-January since Pensacola will shed light on the Zechstein play in surrounding open blocks. As you say, patience is needed.

66EE - I think the rig is working on an almost depleted gas field in L13 in Netherlands. There are some minor partners but its really NAM , which is 505/50 Shell Exxon and also EBN (Energie Beheer Nederland which is owned 100 per cent by the Dutch state.

L13 is a mono-tower which feeds raw well bore fluids to a nearby processing platform. L13 is forecast to reach its economic limit in 2023 so could be that operations are aimed at plugging wells prior to decommissioning - but that’s just speculation. Looks to me like drilling at Pensacola unlikely until November, but even Deltic can't be sure so expect no announcement until the official mobilisation defined by the contract.

If you’ve looked at jack-up videos you’ll have seen various examples of catastrophic leg failures involving weak sea beds and often leading to capsize and sinking of the barge. So the whole pre-load procedure must comply with UK regulations.

66EE - if you mean how long does it take from the moment the rig arrives at the exact location to the start of drilling - for a jack up in North Sea it is several days. It usually needs three towing vessels to manoeuvre the barge to the precise well location.

Then the legs are lowered to the sea bed and the barge is jacked up to three or four feet of air gap, sea-water ballast is then taken aboard to ‘pre-load’ the spud cans on the bottom of the legs.

This operation is to check the stability of the pre-laid rock foundations/sea bed and ensure the spud cans have penetrated the expected amount. This operation may take a day or two and even longer if there are unforeseen events such as spud cans sinking further than expected or even punching through.

Assuming the barge itself is stable after pre-load, the water ballast is pumped overboard and it is jacked to operating height with an air gap determined by the maximum wave heights expected at the location.

The precise definition of ‘mobilisation’ will be defined in the drilling contract because a lot of money is involved. A day-rate compensation structure can present ambiguity if not properly drafted.

Drilling contracts may include all or some of the following day-rates:

Mobilization and demobilization rates payable when the rig is traveling to and from drilling location.

Standby rates, payable when the rig is on contract but not used, due to weather conditions for example.

Operational rates payable during drilling activity.

Force majeure rates payable during the period of a force majeure event.

Repair rates payable when the rig is not operating and permitted maintenance or acceptable repairs are underway. Such as slipping the drilling line when it reaches the limit of its specified ton-miles.

Zero rate payable when the rig is not operating due to fault of the drilling company or under other specified circumstances. 

ibug

politicians/government in UK can safely promote fracking as a solution to the energy crisis because they know it will never happen.

Operators will take years to get planning permission but the real barrier is that UK's geology is such that fracking may have worked 280 million years ago - but not today. Sure, hydraulic stimulation does enhance well productivity in conventional low-permeability reservoirs and has rejuvenated Rotleigendes reservoirs offshore UKCS, but in no way is this comparable with the 'shale gas' plays onshore USA. See link below to excellent paper describing the issue.

https://www.ed.ac.uk/impact/opinion/uk-is-280-million-years-late-for-fracking-boom

Thanks Uggy

I noted that one of the twins was ‘pleased’ to see a CPR showing WN is currently worthless!

Also, I expect Simwell is thinking twice about a shares deal worth 15% less than they originally hoped.

Smythery

The value of gas in the ground at West Newton as defined in the CPR is currently zero. Yes, the volume may be there but there is a catch hidden in the CPR.

RPS has classified the gas as ‘contingent resources’. PRMS defines ‘contingent resources as those volumes that are potentially recoverable from discovered accumulations by the application of development projects’.

Note the weasel word is ‘potentially’. Contingent resources may include those without a market or, at West Newton, resources waiting for a technical advancement by Raithlin to demonstrate the gas will flow from the reservoir, which hasn’t happened so far. That’s why a horizontal well + oil-based mud etc is needed.

If and when commercial flow rates have been demonstrated, Resources turn into Reserves which do have value.

So, beware the monetary values mentioned in the CPR - the production figures are analogues from Canada and unrelated to West Newton.

Fairdealer

It’s hard to say what NewMed’s plans will be, although probably much better than Tullow which has a poor record of technical/commercial discipline in exploration/development in the past.

Capricorn was operator in eight licences offshore Israel with a modest seismic processing commitment ahead of a drilling decision but they relinquished the licences. That’s probably how they met NewMed.

Capricorn investors will end up with 10% of the combined company with Simon Thompson as non-exec chairman. So the NewMed guys will be calling the shots and making the decisions on Deltic’s properties I suppose.

https://www.energyvoice.com/oilandgas/447991/capricorn-newmed-energy-merger-tullow-oil/

Grey Panther

There are good parts of the CPR;

‘oil’ is now ‘condensate’ - but no mention it is retrograde condensate.

Exploration prospects - geological COS <50% due to trap definition.

But otherwise, the CPR is not very convincing;

1) RPS says “The ultimate recovery factor expected from each of the projects is highly speculative, and as such has a considerable risk associated with it. RPS has used a range of recovery factors based on publicly available information from analogous plays in Western Canada”. They claim lack of data in Europe and numerous other discoveries in Yorkshire is ‘not available’ - RPS should search Polish, German, Dutch and UK publications - there is a lot of data.

2) RPS says “Well performance is ‘notional” - i.e. each well starts at 10 mmscfd and declines 60% in couple of years. But there is no evidence from WN or any other `Yorkshire field. ‘Notional’ - ‘guesswork?

3) RPS does not mention water breakthrough and how it will be addressed. No mention of fractures which is obviously key to commercial production.

4) Porosity in resource calculations. 5% to 7%, permeability 0.5 md. With such poor permeability commercial flow rates - without fractures - very unlikely.

5) Recovery/well is guesstimated at ~10bcf or thereabouts at economic limit. Is there any well is N Yorkshire Zechstein Kirkham Abbey which has produced even 1 or 2 bcf?

Although Reabold has bought the whole Simwell company, Block 41/9 is next to Deltic's Blocks 41/5 and 41/10 (P2252) where the Pensacola prospect is located.

Shell earned a 70% interest in 41/9 by extending the 3D survey originally planned for 41/10 and 41/5. The 3D doesn't cover the whole of Simwell's 41/9 - just a narrow strip along the eastern edge of 41/9.

So Reabold now has a 30% interest in 41/9 if the deal completes.

But looks like Shell/`Deltic decided not to follow up with a commitment to drill in 41/9 and preferred to wait until Pensacola outcome is known. There are three dry holes in P2252 drilled >40 years ago. One found gas in very tight Haupdolomite - more or less equivalent to the Kirkham Abbey Formation at West Newton.

Hence the 50% chance of geological success at Pensacola - but will gas flow?

Wed, 28th Sep 2022 07:00

RNS Number : 9036A
Reabold Resources PLC
28 September 2022

28 September 2022



Reabold Resources plc



("Reabold" or the "Company")





Conditional Acquisition of Simwell Resources Limited ("Transaction")



Reabold, the AIM quoted investing company with a portfolio of upstream oil and gas projects, is pleased to announce the execution of a Sale and Purchase Agreement ("SPA") for the conditional acquisition of Simwell Resources Limited ("Simwell").



Key Highlights:

· Reabold is to acquire Simwell at a low acquisition cost with a total initial consideration, plus the repayment of all outstanding creditors/liabilities, of £1 million

· The transaction substantially increases Reabold's footprint in the emerging Zechstein trend, complementing its onshore position in PEDL183, including the West Newton project

· The licences have a number of prospects covered with high quality 3D seismic data

· Licence P2332 has prospects to be derisked by success at the Pensacola well



Transaction Details:

The SPA between the shareholders of Simwell ("Sellers") and Reabold provides for the conditional sale of the entire issued share capital of Simwell to Reabold. Concurrently, Reabold will settle the outstanding creditors/liabilities of Simwell. Reabold has agreed to pay the following amounts for the Transaction:



· An initial consideration of £361,840.93 to the Sellers to be satisfied by the issue of 134,105,159 new ordinary shares ("Ordinary Shares") in the capital of the Company ("Initial Consideration Shares") at a price of 0.27 pence per share, being the closing price on the last practicable trading day prior to signing of the SPA (the "Issue Price").

· The sum of £305,157.71 payable to certain Simwell creditors which shall be satisfied by the issue of 113,021,374 new Ordinary Shares at the Issue Price ("Creditor Shares").

· The sum of £333,001.36 payable to certain Simwell creditors to be satisfied in cash from the Company's existing cash resources.

· A contingent deferred consideration of £150,000 ("Deferred Consideration Amount") payable to the Sellers to be satisfied by the issue of new Ordinary Shares ("Deferred Consideration Shares"):

o The contingent deferred consideration will be payable to the Sellers if, inter alia, the operator of licence P2332 undertakes to the NSTA that the licensees will commit to drill a well pursuant to a defined work programme and within the applicable timescales.

o The number of Deferred Consideration Shares to be issued to the Sellers will be calculated by dividing the Deferred Consideration Amount by the prevailing share price based on the ten-day volume weighted average price of an Ordinary Share, as reported by Bloomberg, immediately preceding the date on which all of the applicable conditions are satisfied.

Simwell currently holds interests in four UK licences in the Southern North Sea ("SNS") outlined in the t

FD

Shell will have submitted an operational plan which complies with NSTA guidelines. I would guess that it covers several possible outcomes.

1) No shows = plug and abandon with cement plugs placed at intervals determined by the geology. Casing remains in the hole, but is cut at or below seabed. Actually, casing is relatively cheap item of operational costs despite rising cost of steel.

2) Hydrocarbon shows with cores and logs = several options including downhole formation tester to recover fluids at reservoir temperature and pressure to evaluate deliverability. Known in the trade as ‘PVT sampling’. Then plug/abandon.

3) Drill stem test = much more complex operation requiring all sorts of approvals just for a few hours - and still expensive with rig on location. Then plug and abandon.

4) Extended well test = 30 days flow test which poster ‘Geochem’ noted requires a lot of permits and money. Not sure if Deltic is carried by Shell for EWT.

Likely outcome will be gas, and maybe condensate, shows - as in previous three wells on licence in Zechstein carbonates. Followed by the usual RNS saying ‘further analysis is underway to assess commerciality of the discovery’.

Allenby were promoting the recent Ossian/Darach discovery in Block 42/4 as a Pensacola look-alike. Sure it flowed gas and liquids and got everyone excited - until the water broke through. Neptune didn’t appraise it and relinquished the licence earlier this year. Let's hope its not a Pensacola look-alike!

All

You don’t just park the jack-up rig on the spot and start drilling..

Depending on the sea bed, rock foundations are placed to prevent excessive sea bed scouring around the spud cans or avoid punch through. This is not just a matter of dumping rock overboard, but rather a precision operation requiring a DP vessel.

Se link

https://www.hse.gov.uk/research/rrpdf/rr289.pdf

33nd Licensing Round
UK public policy regarding North Sea oil and gas development has changed radically in recent months. This is clearly a consequence of the surge in oil and particularly gas prices since the third quarter of 2021 and growing concerns over the security of supply, given the tight market backdrop and the potential for a cessation of shipments from Russia.
The government has now clearly acknowledged that gas is an important energy transition fuel given relatively low carbon emissions vis-à-vis coal and oil. Furthermore, energy supply security is now being prioritised to a greater extent than previously. Both factors suggest encouraging indigenous oil and gas development. A key manifestation of the new policy was the announcement in the British Energy Security Strategy paper of 6 April 2022 that the 33rd offshore licensing round would take place in the autumn of 2022.
Deltic has indicated that it has been working on identifying and maturing a number of potential opportunities in the Southern and Central North Sea. The intention is to make multiple licence applications on both a 100% basis and in partnership with other established oil and gas companies. It should be noted that licence applications are a low- cost way of sourcing exploration and development opportunities and have been key to Deltic’s success to date.

Looking ahead 100 years -

Horse Hill in 2222

https://www.youtube.com/watch?v=evmuD06nlT0

????? hot ticket

wako

Why are you using Bank of Israel Street, Jerusalem calculator? Does it generate bigger numbers?

GP

Only last year, ONE Dyas completed wells 42/04-1 and 42/04-1Z on the Ossian (Zechstein) and Darrach (Carboniferous) prospects. The 42/04-1 well proved oil in 145 ft gross Zechstein limestone, with the Carboniferous targets believed to be water-wet. The sidetrack proved oil in 12 ft gross Zechstein reservoir. The well flowed maximum 3,500 bpd with a 79% water cut. 62 tonnes of oil and 15,000 Sm3 gas were recovered during clean-up but the test was abandoned without completing planned EWT. Operatorship of the licence has since been transferred to Spirit Energy.

In addition, oil and gas were found in the Kirkham Abbey Formation (Hauptdolomit) in the West Newton onshore well in 2019, drilled by Rathlin Energy. The company is now actively working on further appraising the discovery and handed in plans to drill two more wells.

Block now relinquished without appraisal or development.

GP

Ossian/Darach

https://youtu.be/oWZP9Z6BOBw