Member Info for Exploration

FD

Has anyone noticed OGA’s U-turn from ‘maximising economic recovery’ to ‘net zero by 2050’?

https://www.ogauthority.co.uk/the-move-to-net-zero/overview/

It’s going through an industry consultation process at the moment. One item in it suggests operators who can demonstrate no hope of a commercial return on exploration projects - especially with current price outlooks - must inform OGA immediately.

Also, does this mean future Offshore licence rounds will be deferred? It’s already happened Onshore with no rounds for six years, just as it has in France. Starve industry of new licences and it will rapidly fizzle out and move elsewhere.

Since oil and gas projects in UKCS have a lifespan of 10 to 20 years, Deltic and partners need to get a move on before its too late.

gregory

Sorry you’ve missed my posts. As a very long term investor, even from the Fastnet days. In natural resource companies the quality and quantity of the resource itself defines the expected outcome - but provided the management are competent. The rocks will not change and the gas is still there, so the project should eventually provide a return.

I almost sold out from Sound because I couldn’t stand the misrepresentation of the geological reality spouted on video and RNS announcements.

Remember TE-8? And the TE-9 fiasco? The CPR which never was? The palaeozoic play that isn’t there?

I concluded that this was a case of ‘innocent misrepresentation’ - a representation that was neither fraudulent nor negligent. The management failed to understand the consequences of their statements - especially those recorded on video. Innocent misrepresentation is almost impossible to prove. The promoter only has to show he had reasonable grounds to believe a statement was true - and can kick any complaints into the long grass.

With innocent misrepresentation, someone makes a reckless statement without any grounds for knowing whether what they are saying is true or false. But in petroleum geology there is the truth, the half-truth and nothing like the truth!

No wonder all the videos vanished without trace and we never saw the full CPR because any complainant has to show evidence - written or oral - that a material fact was misrepresented in such a way that the complainant agreed to buy shares he didn't intend to buy.

Then, thankfully, the final management massacre came - and we will never know what caused it.

GP

Thanks for the clarification - the names keep changing.

The 41/24-3 shown in Arenite’s illustration was sub-horizontal and penetrated the Z3 Platten dolomite (Brotherton Formation equivalent) flowed at rates, exceeding 30 mmscfd, via fractures and. In the deeper Z2 Haup dolomite (literally ‘main’ dolomite in German, or Kirkham Abbey Formation)

Industry only drilled one horizontal well (41/24a-2z, to intersect fractures in the Haupdolomite. In fact, 41/5-1 - right in the middle of Deltic’s Pensacola prospect almost blew out in 2004 when over 2000 bbls of mud vanished into fractures in the Haupdolomite andit took several days to bring under control. The best recorded flow rates in this era were from 41/24a-1 and 41/25a-1 which tested gas from the Plattendolomite. Conoco's 41/24a-2z was the only horizontal well and is believed to have tested gas at circa 100 mmscfd.

At the time - around 2000 - operators were exploring offshore for gas in the Rotliengendes and Carboniferous, but soon realised the ‘drilling hazard’ which caused gas kicks in the Zechstein seal was, in fact, a play in itself, despite it producing gas onshore for many years. In these pre-internet days, the operators’ geologists had simply overlooked it.

Building on experience from the Netherlands, Deltic’s early conceptual development plans for its Zechstein play involved horizontal wells into fractured Haupdolomite zones. For the same lithology, fractures are more closely spaced in thinner beds than thicker beds, but the effective fracture permeability is related roughly to the square of the bed thickness. i.e. double the bed thickness and get four times greater flow. Arenite had also figured this out, but never got round to drilling a horizontal well. See Cluff’s CPR - page 150.

https://www.cluffnaturalresources.com/wp-content/uploads/2016/01/5-Axis-CPR-on-Southern-North-Sea-Assets-02-December-2015_Optzd.pdf

Here’s a link to Arenite’s project immediately south of the Egdon blocks

https://www.spe-aberdeen.org/wp-content/uploads/2017/06/DEVEX-2017-Arenite-Cleveland-Basin-Gasfields.pdf

Mirasol

I sense the market has had enough of the legacy left to us by Captain Ramptastic who created value that was never there in the first place, took his reward and left us with the remains. So here we are with a mediocre portfolio almost impossible to explore or develop in a reasonable time frame due to ‘above ground’ conditions and planning bureaucracy.

If anyone has been watching the consultation process run by OGA concerning the government’s new ‘net zero by 2050’ strategy it might well lead to a situation where no new onshore licences are issued and onshore operators are simply left to produce what they can until wells fizzle out.

One issue which is under discussion is that OGA also proposes a requirement that licensees must inform the OGA as soon as they become aware that they consider they will be unable to make a satisfactory expected commercial return on the investment or activity.

This is effectively a ‘get out of jail free’ card to enable licencees to make the case that commitment exploration wells need not be drilled and marginal fields can be abandoned because it would simply be a waste of shareholders’ money to progress the projects.

Given that UKOG currently produces only 0.02% of UK’s daily oil consumption I can’t see the government would bother to intervene or support future planning applications for new wells. Sorry to paint such a dismal picture of the future onshore UK, but it really does reveal the promise offered by ventures in Turkey, which might be why interest has perked up. Better to abandon Loxley and Arreton when Turkey is ratified, say goodbye to Onshore UK and use the money in Turkey instead of asking investors for more.

Oil riches - yes, relative to UK it's a good move. The licensing regime is dynamic with contours turnover of acreage. The service sector is relatively efficient and low cost. It's now 6 years since the last UK Onshore Round and this seems to be the way UK's government is planning to snuff out small independent companies.

more than $100 million, the well found only oil shows in a poor reservoir. Later, Shell and Exxon conducted extensive seismic surveys in the Black Sea, but did not drill.

Let’s also remember 2 or 3 million barrels of oil transits Turkey every day via the Turkish Straits (from Russia) and the big export terminal at Ceyhan (from Iraq and Azerbaijan). Add to that the Blue Stream and Turkish Stream gas pipelines from Russia and the Southern Gas Corridor system from Azerbaijan to Italy/Europe and you’ll see Turkey has plenty of petroleum crossing its territory.

Turkey (at least inside its current borders) has been thoroughly explored and remains full of geological surprises.

For example, in recent years Valeura Energy has defined a huge basin-centred gas play in the Thrace Basin. https://www.valeuraenergy.com .In eastern Anatolia Shell demonstrated the Silurian Dadas Shale play would respond to fracking. https://seekingalpha.com/article/1172631-turkeys-dadas-shale-one-of-the-worlds-top-unconventional-shale-oil-plays

The Anglo-Persian Oil Company involvement in Turkey came in 1912 with the registration of the ‘Lion and Sun’ and ‘Palm Tree’ trade marks for use by the Anglo-Persian Oil Company (the original ‘BP’). It was one of many marketing initiatives following the discovery of oil in Iran in 1908. Finding oil at the time was easy, but selling it to markets, mainly with no cars, was a challenge.

Before the formation of Anglo-Persian in 1909 geologists had been in talks with the Turkish Sultan in Istanbul over the much sought-after concessions in Mesopotamia – at the time part of the Turkish Ottoman empire but which later became Iraq. As a result, Anglo-Persian became a part of the Turkish Petroleum Company and gained a 23.75% interest in the Kirkuk Concession in 1925. The Turkish Petroleum Company was renamed Iraq Petroleum Company. Oil was discovered at Kirkuk in 1927.

WW1 and its aftermath led to the The Treaty of Lausanne in 1923 defined the borders of the modern Turkish Republic. In the treaty, Turkey gave up all claims to the remainder of the Ottoman Empire and in return the Allies recognised Turkish sovereignty within its new borders. By then, other majors had arrived in Iraq and formed a consortium known as the Iraq Petroleum Company to continue work on the Kirkuk fields.

In an attempt to expand new oil markets representatives of Anglo-Iranian Oil Company visited Turkey and signed a supply contract in December 1946. BP entered the Turkish downstream market in 1949 and the country is dotted with BP petrol stations. The Mersin refinery, with a design capacity of 3.2 million tons per annum was commissioned in June 1962 and was jointly owned by BP (17%), Shell (27%) and Mobil (56%). BP’s share was vested in BP Overseas Refining Company. The integration of Mobil’s European downstream assets in the mid-1990’s propelled BP into its current strong position with an annual turnover of about $2.5bn. At the same timeShell/Mobil explored SE Turkey and NE Syria with great success.

In the 1980’s several majors conducted an exploration review of the whole country in association with the Turkish State Oil Company, TPAO. The main conclusion was that the best prospects of discovery of new oil or gas reserves lay in the deepwater Black Sea. A Reconnaissance Permit was awarded to BP and TPAO in 1991. A new seismic survey started in early May 2002 with drilling taking place in 2009 using the Glomar Explorer drill ship in the extreme south east of the Black Sea near the town of Hopa. Costing more

GP

Just looking at the history of the Cadeby Formation, it seems to feature in only one gas discovery at the Caythorpe gas field where a thin Rotliegendes sandstone - immediately below the Cadeby Formation contained gas. It was discovered 33 years ago and production started in 1992, initially into the NTS but later into a 9 MW power plant which implies about 2 mmscfd. The well became uneconomic in 2002, but was recompleted in the Cadeby Formation and fracked by the operator, Warwick Energy. Eventually Warwick converted it into a gas storage reservoir and sold it to Centrica. GIIP is recorded at 13.6 bcf, with 2.6 bcf produced i.e. ~ 10% Rf.

So the history in the area doesn’t bode well for a productive Cadeby reservoir - sure, there may be gas present, but will it flow?

Meanwhile, like you, gas seems guaranteed in the new well in the Kirkham Abbey Formation and let's hope Raithlin's cunning plan to manage the acquifer sees the EWT succeed.

GP

Yes - it’s quite technical, but I’m sure Rathlin are up to the job. And besides, all we really want to know is how much gas is present and how much of it can be produced.

Hewett is a bit of a red herring since its 2.5 tcf of gas was produced from Triassic Bunter Sanstones. Deeper drilling did prove a small accumulation of gas in the Zechstein sequence.

Grey Panther

The litho-stratigraphic nomenclature for the Magnesian Limestones in Yorkshire leads to no end of confusion. I prefer to use the established system of Zechstein deposition all cycles to understand it.

The Cadeby Formation, or Lower Magnesian Limestone belongs to the Zechstein Z1 cycle which is well known from North Sea, Netherlands, Germany and Poland. This link to an article which includes UJO’s seismic. The depositional environment seems to be more like a carbonate shelf, rather than a ‘reef’, at Z1 times.

https://expronews.com/wells/ukcs-west-newton-a-2-confirms-onshore-discovery/

Here’s a review of the diagenetic history of the Cadeby Formation. You can see diagenesis has been in progress since the moment the sediments were deposited and probably continued until emplacement of gas.

http://citeseerx.ist.psu.edu/viewdoc/download?doi=10.1.1.910.9520&rep=rep1&type=pdf

Anyway, I wouldn’t want to be the mud-logger on the new well because all the Permian cuttings will look pretty much the same.

Either way, PI’s should realise the inner-workings of the West Newton geological ‘Black box’ are far from simple.

bornagain

100 years? .Well, the rocks haven’t changed during that period for a start

I think you’ve finally worked out UKOG’s brilliant new exploration strategy for Isle of Wight.

Previous wells drilled at same location.

First try - Arreton 1, BP 1952 - result? Dry hole
Second try - Arreton 2, British Gas 1974 - Result? Dry hole
Third try - Arreton 3, UKOG, 2021 - Result?

Shows UKOG Board Directors’ belief that the third time something is attempted is more likely to succeed than the previous two attempts.

Mike007

I'm hoping the next UKCS Round sees Deltic recover the previous P2248 area - i'e. 43/11 etc. It's mature enough to warrant a firm well bid which is currently beyond Deltic's financial capability & capacity - so hopefully they've teamed up with someone with more money. Then perhaps we'll see that Pegasus/Andromeda trend fully appraised and developed?

Mirasol,

Glad you reminded us about Wytch Farm. The geology of the accumulation clearly demonstrates why ‘young’, Tertiary-age structures in the Weald and Wessex Basins are dry because they formed AFTER oil was generated in the source kitchens. In contrast, structural traps present BEFORE oil was generated, like Wytch Farm, tend to be full of oil.

Anglo-Persion figured this out in Iran/Iraq before moving on to licence the whole of Albania to discover `Europe’s biggest (1 bnbbl) onshore oilfield, Patos-Marinza, in 1938. At roughly the same time they looked at UK and drilled Ashdown-1 on the crest of the enormous Weald anticline, only to realise it had formed after peak oil generation. Known as BP by then, two other dry holes followed, Portsdown-1 and Arreton-1 - both failures, but with weak shows. The only success was Broadbench-1 - which became known as Kimmeridge-1, still producing today.

BP’s chief geologist at the time reviewed Arreton-1 (1952) and concluded ‘only very slight traces of oil were encountered and the lack of success is ascribedto early early migration of oil towards the edges of the basin before formation of the Arreton structure’.

They had mapped the structure on surface geology and tested 2 Purbeck intervals, and the basal Purbeck - all with no flow nor reservoir pressure. Same for one test in Inferior Oolite.

Later, Gas Council drilled Arreton-2 (1974) at exactly same place, but were actually looking for the eastern extent of the Bridport and Sherwood Sandstones - but they are absent at Arreton.

Strangely, trap timing is barely mentioned in UKOG’s CPR despite it being the single most important fact for discovery.

The American philosopher Santayana once said “those wearing red trousers who do not learn from the past are doomed to repeat it”.

FD

I’ve served on a couple of remuneration committees and the starting point is usually to look at a market survey to ensure salaries are competitive for a given sector. Unfortunately for PIs the E&P sector tends toward higher remuneration for a whole variety of reasons. The idea is to retain good executives who conduct their fiduciary duties properly and don’t misrepresent the assets of their company. No one can accuse GS of hype and he seems to be one of the most level-headed CEOs on AIM. A safe pair of hands.

Then there is the performance contract and LTIP on which to judge bonuses, which is measurable and not just a ‘finger in the air’ judgement. All this goes into the company’s records, usually for review by annual auditors.

Here’s a longer-term view - see link.

https://www.morningstar.com/stocks/xlon/delt/executive

Compare this with an outfit like Reabold - see link below. One outcome of a successful bid by RBD could have been to hike new directors salaries to over £1 million each + massive bonuses, but now its failed they’ll have to struggle along on £50,000 a month!
https://www.morningstar.com/stocks/xlon/rbd/executive

FD - before Algy Cluff retired he selected Mark Lappin to become Chairman. Mark knows Deltic's home patch of the North Sea like the back of his hand after a career at Conoco and Centrica. In fact, Mark has more technical/commercial oil/gas experience than Mssrs Swindells and Nunn put together.

The Chairman's job is to promote the highest standards of integrity, probity and corporate governance throughout the Company and particularly at Board level. It seems inconceivable to me that he hasn't noticed the discomfort amongst shareholders about excessive salaries. He and the other non-exec director form the remuneration committee, so it's within Lappin's power to decide on awards. He is paid £32k/year as Chairman.

Thanks Blackhopper - all I asked was a question to RBD about H2S. Obviously it would be great news if they confirm there is none, and therefore the WN project is more valuable.

But it provoked an emotional reaction from other posters - sorry about that. I'll shut up until the EWT results are announced.

I rather like ADX and their approach, but they're up against a real challenge in the tight gas zone of the Panonnian Basin, so good luck there.

You didn't mention California. Maybe I should call Dero Parker who seems to be operator?

BlackHopper

So I suppose you'd recommend doing away with the H2S scrubber in the forthcoming test. Get real, look at UK, Netherlands, German and Polish analogues for H2S inZechstein gas. It's nothing to be concerned about and is easy to process.

In my experience City types don't do geochemistry or geological research of any kind. Maybe that's why we've drilled 2 dry wells with Corallian, can't flow a well in Romania and ?is that gas well in California @<2/mcf?

Rubey,

It’s not casting doubt - it’s a petroleum engineering question about gas processing. Engineers can solve almost any problem, but it costs money.

Costain is Uk’s leader in treating sour gas - but they don’t work for free and anyone on this bulletin board who thinks raw West Newton gas can go straight into the NTS at NPB prices had better do some homework.

https://www.costain.com/solutions/case-studies/sse-knapton-power-project/

GP

I thought at the time the advice to ‘open the windows’ was strange. I’ve been trained to put on a respirator and run away as far as possible (upwind) from the well! The Tengiz sulphur mountain from de-sulphurising the oil and gas is quite a sight with 23% H2S!

https://www.researchgate.net/figure/Sulfur-storage-at-the-TengizChevroil_fig1_255209881

Meanwhile, here’s the official story showing how the human nose is ultra-sensitive down to 0.02 ppm.

https://oem.bmj.com/content/60/4/308

Air Concentration: Physiological Response
1,000-2,000 ppm: Loss of consciousness and possible death
100-1,000 ppm: Serious respiratory, central nervous, and cardiovascular system effects
150-200 ppm: Olfactory fatigue (sense of smell is significantly impaired)
100 ppm: Immediately Dangerous to Life and Health (IDLH concentration)
5-30 ppm: Moderate irritation of the eyes
5-10 ppm: Relatively minor metabolic changes in exercising individuals during short-term exposures
Less than 5 ppm: Metabolic changes observed in exercising individuals, but not clinically significant
5 ppm: Increase in anxiety symptoms (single exposure)
5 ppm: Start of the dose-response curve (short-term exposure)
0.032-0.02 ppm: Olfactory threshold (begin to smell)