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The Schwarzbach-2 well spudded on 19 June when we were told that it would take 25 days to drill, plus another 12 days for testing if warranted. We are now on day 56. We haven't yet seen a "plug and abandon" RNS so I assume we still have a chance of success, but they're really taking their time. However, it's quite a deviated well, so we don't know what's going on right now.

Hi itsawrap. I've analysed the NSTA's monthly figures and got the following for this year: Jan: 832 bopd & GOR: 589, Feb: 771 bopd & GOR: 640; March: 770 bopd & GOR: 716; April: 770 bop &: GOR: 695 and May: 779 bopd & GOR: 687. So to my mind, there doesn't seem to be a close relationship between the gas and the oil being produced. It will therefore be really interesting to see the NSTA's figures for gas, oil and water for July, presumably published in early September.

Hi Serif. It's not easy to predict whether the recent water cut will significantly affect Egdon's drilling plans. Because of the better than expected reservoir behaviour up until now I'd been anticipating that they might try to penetrate the Ashover reservoir a bit deeper than in Wressle-1 in an attempt to prove up a lower oil / water contact. Depending on how the water cut increases they may, if it's only slow, still do this, but not if there's a sudden rush of water. I think we can draw some comfort from Europa's nearby Crosby Warren well. This is an Ashover producer too, and it's been on stream since RTZ discovered it more than 30 years ago. The water cut there is still only around 60%, so it's only increased by about 2% per year, albeit on a much lower flow rate. So we can still hope for something similar here, maybe. GP

In my experience CPRs are usually carried out atall the JV Partners' expense, rather than just on Egdon's behalf as the operator. So, when the Wressle CPR finally emerges, I'd expect it to be announced and - most likely - published in full if it's any good by all the partners. It may also take a quite while longer than originally expected as ERCE will no doubt be keeping an eye on the water cut over some weeks, not just the first month's rates, and they will presumably also be looking very carefully at its continued effect on the oil rate.

Hi Copper3. You're right about Wressle starting production Jan 2021, but it was at only about 80 bopd initially. It didn't reach 550 bopd (and better) until the proppant squeeze, which took place in August 2021. Since then we've had about 2 years at rates of up to 1,000 bopd, but averaging about 750 to 780 bopd, I believe. All the best.

Regarding TD: It's usually the total depth, which we don't yet know. The well may end up more (or remotely possible, less) deviated than was planned, so the MD (the measured depth) along the borehole will be greater than the planned TVD (true vertical depth). That's probably enough abbreviations for now!

I was told some time ago that there are five 500 barrel storage tanks on the Wressle site and that four are for oil and one is for any oily / reservoir water coming from the separator. So there could only be a couple of water disposal tanker runs per month, depending on the size of the tankers,

Hi itsawrap. You are completely correct. Let's assume 780bopd x 3.72% water cut x 31 days in July, which is about 900 barrels of water. So 4.5 x 200 bbl takers of water per month.

Hi Pboo. It's probably not a tanker load of formation water yet, but Egdon must presumably be storing it one site or getting rid of it somewhere. So, If EOG wanted to put permit in place, they could presumably apply to the EA or NSTA for it, since it would provide some additional revenue for them, but I'm not sure where to find such an application , if there is one.

Here's a small but potentially positive element for Europa regarding the water break through at Wressle. Europa owns the nearby Crosby Warren field where the water cut is about 90% after (I think) 30+ years of production. They are presumably using an abandoned CW well to dispose of what must be about 200 barrels of water per day. I estimate that Wressle is only producing 780 bopd x 3.72% of water, say 30 barrels per day. So EOG could make alittle money from the other Wressle partners by disposing of a small amount of extra water. Does anyone know what the cost per barrel of disposed water might be?

Hi Hms687. I believe the NPV (net present value) of a barrel of crude in most producing fields is less than £10 / barrel, and probably closer to $US 10 / bbl. Your £200 million for 3.85 million bbl of 2P reserves of represents £51.95 / bbl which isn't a lot less than today's $84 Brent oil price. However, IMO NPV is much more likely to indicate the real value in today's terms as the oil would be produced over many years of field life, so you wouldn't get all the value today. I hope this makes sense. GP

Hi highlandmatt. A possible comparison for Beacon as a small oil producer might be with one of the partners in the UK Onshore Wressle oil field, which has a low operating cost of just under $10 / barrel. Union Jack Oil Oil, for example, owns 40% of Wressle's ca. 750 bopd of production, say 300 bopd net to UJO. It currently has a market cap of £27 million. So, at a very rough guess, 500 bopd net could indicate a £45 million mkt cap. This ignores the relative sizes of each field's reserves, of course.

You may well be correct Ezhik. However, it's not completely clear from the RNS at which point the bottom hole assembly and the drill string parted company. It could have been occurred before, and therefore necessitated, the fishing job, or might have been a part of it. One thing, though, that I hope we can agree on is that yesterdays' share price blip was a good buying opportunity. I too picked up more shares.

Hi persimmon. I don't think I've ever ramped Reabold, but I was once rather more optimistic. I last posted here on 13 July '23 when I commented:

"I'd quite like Malcy (or anybody) to ask what can they (S&S) or LNenerg tell us about the discovery from a technical POV, and how much technical due diligence did Reabold do before signing up".

Hi Ezhik. Do you really think they "managed to drop a couple hundred thousand dollars worth of BHA and DD equipment down the hole"? We've been told that they were dealing with was stuck pipe, and it happens quite frequently in highly deviated wells

I’m not surprised there have been drilling issues with the well, but I’m pretty confident they will be overcome. If you bear in mind the difference between the originally proposed Total Depth, which was 2,255 metres (as the measured depth) and compare it with the 1,709 metres True Vertical Depth to TD, this tells us that the well's deviation was expected to be around 41 degrees. This angle combined with the 1,709 metres TVD allows us to estimate the well’s horizontal displacement relative to its surface location. It’s about 1,470 metres, which is quite a long step out, and may explain why the well has had drilling problems. But I can’t say that I’m particularly worried, which is why I’ve topped up this morning.

Europa's website has some useful info about Cloughton. The porosity and the

permeability are obviously going to be an issue as it says that porosities within the Carboniferous are 2-9% with permeabilities of between 0.1 and 1mD, which is very "tight" IMO. The full website entry says:

"PEDL 343 contains two adjacent blocks, TA09 and SE99a and covers 110 square kilometres. Block TA09 is located north of Scarborough running up the east coast and Block SE99a is located to its west. The Cloughton-1 discovery well was drilled by Bow Valley in 1986 and encountered gas throughout the Carboniferous section. Four zones were tested, three of which were in the Carboniferous, the other within the Permian dolomitic limestone. The Cloughton-1 well test achieved rates of between 2-40,000 scf/day on natural flow, however with the right completion and production optimisation techniques it is believed a well could flow at 6 mmscft/day. The gas is sweet good quality gas with >98% methane and ethane. Log and core data indicates that porosities within the Carboniferous section are 2-9% with permeabilities of between 0.1 and 1mD. The well was drilled crestally on the Cloughton anticline which is a NNW/SSE trending anticline with significant dip closure in all directions. Around 60m of Carboniferous net sandstone was realised with high gas saturations. Given the large column height (over 1000m), large areal closure and net sand present within the well there is a large volume of gas is in place. Europa regards Cloughton as a gas appraisal opportunity with the critical challenge being to obtain commercial flowrates from future production testing operations. A location for an appraisal well pad has been identified and following successful testing operations the field would be monetised by connecting to the nearby gas grid."

Hi Serif. I agree with youthat we need to look into Cloughton in much more detail. The Cloughton reservoirs, while also Carboniferous in age, aren't at all comparable to Angus's Saltfleetby reservoirs. Cloughton seems to me to contain older and much less permeable than Saltfleetby, and has only flowed gas at about 40,000 cubic feet per day, unlike the several million cu. feet at Saltfleetby, which has produced gas from rahter younger Westphalian and Namurian reservoirs. I suspect Cloughton might need fracking, or at least a series of "proppant squeezes", as at Wressle, to produce a commercial amount of gas on a daily basis. So I'm not getting too excited just yet. All the best, GP

Sorry for my mis-type below. I should have said that that the deviation is 1,709 / 2,255 (= 0.7579) expressed as a cosine of the well's AVERAGE deviation angle - which is still is 40 degrees, 43 minutes. Will do better next time, I hope!

Hi Blubay. I've some experience with deviated oil and gas wells so I'd like to say that the difference between the proposed Drill Depth TD of 2,255m and the True Vertical Depth (TVD) TD of 1,709m (or 546 metres) isn't the lateral deviation of the well. The two figures actually tell us that the deviation is 1,709 / 2,255 (or 0.8606) expressed as a cosine of the well's AVERAGE deviation angle. This is about 40 degrees, 43 minutes, so it's a highly deviated well but not (IMO) one with a horizontal section. The 40 degrees, 43 minutes angle combined with a TVD TD of 1,709 metres allow us to estimate the horizontal displacement relative to the surface location, which is about 1,470 metres. So it's quite a long step out. This may explain why the well had a fairly minor, but apparently now resolved, drilling problem. All the best, GP