Member Info for Exploration

Try this - with following wind, might even see a well drilled before Deltic!

https://www.energyvoice.com/oilandgas/africa/ep-africa/371208/algy-cluff-zimbabwe-invictus/

https://hotcopper.com.au/threads/ann-farm-in-option-agreement-for-a-2-well-campaign.6476405/

Penguins

It seems to me that UKOG is far behind competitors in Turkey in use of modern technology - let alone maps or well prognoses.

Here is a 10-year old presentation by Transatlantic on the general area of the Molla oilfield in South East Turkey. It shows how they used a combination of 3D seismic and professional petroleum geology to target and drill horizontal wells into to Karababa limestone reservoir within the Mardin Group. Karababa means ‘blackbird’ in Turkish. Oil occurrence in this area correlates strongly with the underlying Dadas Shale (Devonian/Silurian) source rocks. The key to risk mitigation in this area is high quality seismic.

https://www.sec.gov/Archives/edgar/data/1092289/000119312512424040/d424600dex991.htm

Why don’t we ever see similar subsurface petroleum geology or application of seismic/drilling technology from UKOG? Answers on a (small) postcard please.

Mirasol

It’s clear from some posts that some contributors have no idea what is involved in a modern Vibroseis survey in this part of Turkey.

Firstly, permitting - this is the all-important liaison with the local Gendarmerie General Command which is the national Gendarmerie force of Turkey. It is a service branch of the Turkish Ministry of Interior responsible for the public order in areas that fall outside the jurisdiction of the local police - generally in rural areas. This requires liaison with MENR, GDPA and perhaps Environment Ministry in Ankara. All very time consuming and requires precise paperwork. Since the local mufti has a lot of influence, for operations in SE Turkey some operators even keep the Department of Religious Affairs informed. Equipment left out overnight is liable to be stolen and it’s not uncommon to find all vibrators without batteries in the morning. Guards - well, they might work, but often they will turn a blind eye.

Secondly, the seismic lines have to be surveyed for elevation (for static corrections) and flags planted for each geophone group and vibration point. Each receiver group might include 20 individual geo phones over a 100m group length to eliminate the effects of ground roll. For maximum efficiency the survey the surveying crew needs to keep at least 10km ahead of the vibrators.

Thirdly, with wireless technology a ‘rear crew’ is needed to pick up geo phones and send them to the ‘front crew’ to be re-laid. Obviously frozen ground and snow make this work miserable, if not impossible. Then there will be 6 vibrator drivers (3 x two shifts), 2 observers, a six person LVL crew, 2 ‘computers’ (people) to calculate the statics corrections, 6 pickup trucks with drivers to ‘move up’ the equipment from rear to front.

Fourthly, all these people need food and drink, shelter and so on and there’s a shortage of appropriate accommodation. So, overall, everything has to well organised and managed continuously by the party chief and his assistants.

Then there will be downtime, due to equipment failure, weather etc. Assuming all of above work perfectly, the production rate is principally determined by sweep length, sweeps per vibration point, listening time and move-up time between vibration points. So the time interval between one VP and the next can be 5 to 10 minutes. Assuming 50m VP interval and geophone interval with 96 channels that means 20 VPs/km I.e. 100 minutes to 200 minutes per km. With an 8 hour day (480 minutes) at this latitude for safe operations that’s between 4.8 km/day and 2.4 km/day.

Obviously, 100m group and receiver interval translates - on paper - to between 9.6 and 4.8 km/day, but at the expense of spacial resolution I.e. 50m CDP interval. But, without information from UKOG about the survey parameters, it’s all speculation!

Penguins

You are right with 'a fe km/day' for the seismic acquisition. Assuming 50m VP interval and 5 seconds listening time that's 20 vp's per km with 10 minutes per vp including move-up time that work out at 3 hours/km. At this time of year with daylight of ~12 hours that means ~ 2.5 km/day. When it snows in this part of Anantolia its impossible to plant and recover geo phones and wireless equipment, so you can count on ~ 1.25 km/day, with vibrators sliding around on compacted snow. 80 days for 100km and survey acquisition complete by March 2022. But why would anyone waste time and money fighting daylight and weather when they could wait until spring?

Penguins,

Viking Geophysical Services was once the technical/operations division of Transatlantic Petroleum.

Transatlantic started out in Morocco and then Turkey some years ago. In Turkey, they simply outclassed the local operators by introducing 3D seismic - using Viking Geophysical, and their own drilling rigs for horizontal wells, in the Thrace Basin gas play and then, the Selmo oilfield in SE Turkey.

Having demonstrated how modern seismic, drilling and petroleum geoscience can revolutionise success in a country like Turkey, Transatlantic moved on to positions in Romania and then Albania to redevelop oil and gas fields.

http://www.transatlanticpetroleum.com/

Transatlantic sold Viking to its current owners some years ago. In fact, Transatlantic is a good example of how to create value via a series of deals, rather than the organic growth path adopted by UKOG. While AME does have ‘60 years of experience’ in Turkey, it is more like one year repeated 60 times over.

Frankly, UKOG is the ultimate green company. They can't find any oil or gas, let alone produce much. Keep it up SS and cause global temperatures to fall into the next ice age.

Penguins

I agree with your comments on Turkey. I wonder if the Basur well was started in the nick of time to extend the licence rather than a serious attempt to reach the reservoir.

In UK, one has to ask if OGA is playing an effective role in ensuring onshore petroleum operations are aligned with OGA’s technical, commercial and governance expectations, or are they simply collecting the licence fees to support OGA’s own costs?

Mutually beneficial relationships between regulators and industry players develop over time in many business sectors as each relies on the other. Occasionally, there is a breakdown such as Ofgem’s disastrous mis-judgement over the financial capacity and capability of small gas/electricity traders in UK. We all end up paying for their mistakes.

Seems to me that OGA allows some small UK onshore companies to operate non-commercial, sometimes technically flawed E&P ventures, which are not aligned with OGA’s expectations. And it’s investors who pick up the bill.

https://www.ogauthority.co.uk/exploration-production/overview/

Corallian seeks bidders
The pre-production North Sea independent has put itself up for sale

UK continental shelf (UKCS) licence holder Corallian Energy has engaged financial adviser Hannam & Partners to conduct a strategic review of its business, which will include approaching third parties potentially interested in making an offer for up to 100pc of its share capital. Privately held Corallian, in which AIM-listed Reabold Resources holds a 49.9pc stake, owns seven UKCS production licences, all but one of which with 100pc stakes.

FD - now Deltic has surrendered control/operations to Cairn and Shell their main function is to trot out news stories from partners. There is no more UKCS licencing, so building the business in the conventional manner is over. Investors can only sit and wait for drilling.

On other hand, as CCS from BP’s NE Cluster gather’s pace licencees of depleted gas fields will compete with one another to offer the best carbon sinks - just in same way they competed to licence the gas fields in the exploration phase. You can be sure all serious SNS operators have already assessed and ranked depleted fields with existing pipelines/platforms which are best for CO2 storage.

Here’s link to a recent BBC radio programme featuring CCS.
https://www.bbc.co.uk/programmes/m0010qb7

FD - I always wonder what Deltic do all day, apart from showing up to the odd meeting with Cairn or Shell.

But they do have the old Forbes and Esmond depleted gas fields in Deltic acreage. And these are Bunter sandstone - about the best reservoir in the area. But they've done the deal with Cairn and must work together.

The rules for nominating CCS areas as carbon sinks are that nominees must have a deal with a carbon source matching the CO2 emission volumes with sink capacity. Just as in production, really good reservoirs in sinks mean the commercial outcome is better than in pore reservoirs.

Also, the 'Crown' doesn't own the 'pore space' in the reservoir - so, in theory, its all tax free.

Naturally, Aberdeen-based OGA pen pushers smell job security and willnmake sure CCS is the new big thing since there will be no more licence rounds.

Apart from that, if only Deltic could think of ways to increase the value of the company, I'd be much happier.

J1osf

There is no shortage of jack-ups in the North Sea - Maersk have 5 And Valaris a few more.

But there is a feeding frenzy for depleted gas fields as carbon sinks for CCS projects. All the V fields were nominated last week and if Deltic had their wits about them, Forbes and Esmond are good candidates. With CO2 prices in UK hovering around $70 the Southern North Sea will soon see another business cycle boom with plenty of injection wells and a pause on decommissioning of platforms.

Mirasol

The morons in this saga are those who made the planning application.

Firstly, the morons believed there was an oil and gas discovery to be appraised when two previous wells proved there is nothing.

Secondly, the morons completely failed to understand how strongly public opinion is opposed to onshore UK petroleum exploration, especially after Loxley.

Thirdly, the morons failed to make a credible case that oil production at Arreton was in the national interest and would be cheaper that imported oil.

I would not be surprised if IoW Council sent SS an invoice for wasted planning officers time.

Cynderlad

The planning system for petroleum exploration and production today is the same now as it was 40 years ago. In the 1970/1980’s, Conoco, BG, BP and others peppered the Weald Basin, the Wessex Basin and Isle of Wight with exploration wells, discovered numerous commercial oil fields and brought them into production without the drama seen recently at Arreton and Loxley. Everything worked smoothly, permissions were granted in weeks and a typical 5000ft well took 30 days to drill and test.

What has changed since the 1980s is that the onshore petroleum industry in UK has lost the case in the ‘Court of Public Opinion’. Governments of both colours have recognised this, halted onshore licencing 7 years ago and even paused offshore licencing for the forseeable future.

With public opinion shifting so far, county councillors had a duty to listen to, and represent their constituents’ interests - not just their own. In the case of Arreton, UKOG’s assertion that their proposed well was appraising an existing ‘oil AND gas discovery’ - according the latest RNS - stretched credibility.

UKOG investors should breathe a sigh of relief that IoW County Council has saved them £6 million for a non-productive exercise.

Actually Tony - Red Jet and Wightlink out of service tonight, Are you swimming home?

Good ramping by planning officer - probably a shareholder?

Penguins

Good points. All technical reviews/CPRs specifically ignore Arreton-1 which found minor oil shows and flow tested every horizon in the Arreton-3 prognosis. According to the planning officer’s report UKOG told him that ‘old technology’ was to blame and, presumably, it follows UKOG’s drilling and fantastic geological expertise is going to find oil where there is none.

There is even a core in Arreton-1 of UKOG’s main objective which provided a laboratory measured porosity of 3% - also ignored in the Xodus report whereas Xodus suggest that objective will produce oil from fractures with a commercial CoS of 75%!

GP

Good points. When RBD say ‘gas and liquids recovered to surface’ I expect it could be either reverse circulated to the production tubing or, more likely, recovered to the surface via a wireline formation tester (a few cu.cm.) at reservoir pressure and temperature for PVT analysis. PVT samples are collected in a pressurised container at the reservoir level and analysed to determine how fluid phases in the well are ‘liberated’ as pressure and temperature decline.

The reservoir engineering aspects of fractures are highly dependent on bed thickness. As a rule, thin beds have lots of closely spaced small fractures, whereas thick beds - like the Kirkham Abbey - have fewer, widely spaced large fractures. The maths of fluid flow in fractures reveals effective permeability is a function of the cube of bed sickness i.e. double the bed thickness and you get eight times the permeability. This suggests that finding the big natural fracture zones by horizontal drilling in a tight carbonate is fundamental to establishing commercial flow rates.

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!