Member Info for Exploration

Mike 007

I found the recent interview featuring our leader discussing the 3D survey over the Pensacola area uninspiring and rather like a workshop manual on ‘How to polish a brick’ - which, in the exploration business means pointless, expensive, time-consuming activity unlikely to add any value to a project.

Also, co-operation between partners in the petroleum sector has moved 99.9% into a virtual world and will likely stay that way in the post-pandemic era. So not a good excuse for delays.

Looking at the state of the UKCS today I’d say Shell is moving into ‘harvest’ mode rather than exploring non-material (for Shell) new play fairways such as drilling Pensacola.

The 'revelation' about the chalk inlier is hardly new - after all its been known about from previous 3D seismic work for years. And the pre-Deltic squad planned wells and even a conceptual development scheme 6 years ago - see the 2015 CPR. See link below.

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

Desmond45

Well said

Just about all AIM oil/gas companies quote hydrocarbons originally in place now-a-days which is fine if you like big numbers, but it often verges on a form of misrepresentation.

211 bcf gas in place at West Newton. Historic recovery factor in KAF discoveries in Yorkshire is 12%. That’s ~25 bcf recoverable at West Newton, which is quite impressive in its own right - but only if it can be produced.

https://sp.lyellcollection.org/content/465/1/119

Mirasol

If we wait 110 million years - approx age of Gault Clay - and let source mature some more + expel more oil - there should be ~ 1000 bbl/day from HH1 Kimmeridge declining rapidly to a trickle.

Genghis15

If you look at the ADX news you’ll see they have their own problems resulting from the recent unexpected withdrawal of their co-venturer Tamaska. Although this doesn’t directly affect the mica-1 area where Reabold paid 100% for the recent work, it does mean ADX will be short of money for their other ventures in the Panonnian Basin.

https://adx-energy.com/documents/parta-exploration-farmin-update.pdf

Also, mica-1 was a typical Panonnian Basin challenge of forecasting pore pressure, with sudden changes in lithology and fluid pressure resulting from rapid burial of sediments. Maybe Manwell can provide some guidance on how to tackle this.

https://adx-energy.com/documents/iecea-mica-1-well---increase-in-pressure-control-incident.pdf

https://adx-energy.com/documents/im-1-drilling-update-no.-5---ready-to-drill-to-well-depth.pdf

Doing a Looney. UK’s biggest PR blunder?

Let’s say BP’s market cap is around £40 billion today. So for a combination of reasons around £60 billion has evaporated in the last year. I really have to wonder how much BP’s own leadership team has contributed to this decline by launching a vague, aspirational strategy without a carefully calibrated implementation plan with measurable objectives.

Up to 2010 BP had a gold-plated reputation in the John Browne era for communications. Leader in BP’s communications was Roddy Kennedy - famous for saying ‘Think before you say anything’. All downhill after that with the Bumbling Andrew Gowers after Kennedy, overwhelmed by Macondo and ably assisted by Tony Hayward prone to have both feet in his mouth before speaking.

Today, to many investors, replacing petrol pumps with EV charging units and promoting retail sales of Mars Bars hardly seems to be the way to a new future. Also, electricity can’t be sold as a branded product - like natural gas, it’s the same stuff, everywhere, even in my living room. BP can’t say its electricity is better than a competitor’s and will make your appliance work better, unless theirs is much cheaper.

There are some damaging forms of publicity and statements that can be easily misinterpreted with catastrophic consequences. When a few words are taken out of context such as Looney’s sudden transition plan, or there is a full blown PR blunder, businesses can experience extensive brand and reputation damage, which is sadly more important than product/service quality, especially in the power market where price is king.

These things are often referred to as “doing a Ratner.” The saying was made famous by Gerald Ratner the former chief executive of the major British jewellery company Ratners Group, whose off-hand comments about his products at a private conference caused the company’s near collapse.

Shell and Exxon shares have suffered for sure, but to them its drama-free, business as usual behind the scenes to cope with the energy transition, rather than BP’s Ratner style approach, by rubbishing petroleum that consumers cherish to heat their homes and get around - an approach which arguably has cost shareholders £60bn due to pathetic corporate communications.

Here’s a link to a video description of Ossian/Darach including seismic etc.

https://youtu.be/oWZP9Z6BOBw

Looks like the main reservoir may be Z3 Haupdolomite, but main point is that the circular fringing reef and atoll in the centre grew on a Carboniferous palaeo-high. Same for Crosgan discovery and Pensecola feature in Deltic’s area.

GP

A useful discussion. As you say this part of UK is the western feather edge of the Zechstein Basin and is really a ‘carbonate ramp’, similar to today’s trucial coast of the Arabian Gulf but with occasional reefs.

What distinguishes Yorkshire/Southern North Sea is the relict Carboniferous topography/eroded unconformity surface. Where subtle Carboniferous paleo-highs existed in the Zechstein Sea, atolls and fringing reefs tended to form around them with lagoons of oolite behind the reefs - similar to the Bahamas. There are several large, well-defined atoll reefs offshore including the huge Ossian/Darach feature in 42/4 where ONE recently discovered gas and condensate.

There is a sample of the 3D seismic across West Newton and a geological interpretation model in this article from expronews,

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

The seismic is described as a ‘density section’, which I assume means it has been processed to invert the acoustic properties to density. Bearing in mind salt/anhydrite is low density and is coloured blue, and the underlying Carboniferous is higher density and is represented in strong pink seismic event at the base Permian Unconformity you can see how the stratigraphy has been interpreted.

I’m guessing the horizontal black lines are two-way time 100 msec apart - which, with an interval velocity of, say 2500 m/sec means 100 msec TWT = 125 metres. So, by regional Zechstein standards, that’s a significant basin-edge fringing reef formed on a topographic high.

But reefal limestone developments, by their very nature, do not generally show a great deal of lateral continuity, with individual beds thickening and thinning very rapidly - over tens of mores - which is seen to the east of West Newton at outcrop in quarries. Studies of these outcrops confirm the Cadeby Formation was deposited in a supratidal zone meaning early diagenisis reduced its primary porosity and permeability.

Because the Cadeby Formation is an important aquifer, a lot is known about its properties from numerous boreholes. It has a low primary intergranular permeability of 0.01 m/d to 0.1 m/d but potentially high secondary permeability due to the presence of fissures and fractures. In other words, without fractures, neither oil nor gas will not flow in commercial quantities.

BadA

The uncertainty around Shell is actually partly driven by Exxon’s ongoing sale of its UKCS assets.

Shell operates a 50/50 Shell/Exxon JV in North Sea and Netherlands. This dates back to the early 1960s when the ‘seven sisters’ carved up the world and formed similar JVs. This is why Exxon operates onshore Germany in a similar JV with Shell. Or maybe Shell will buy Exxon’s share. Who knows?

So presumably there could be a new owner of Exxon’s 50% in coming months and the arrangement will take time to stabilise.

Exxon’s departure is all part of the re-structuring of today’s petroleum industry.

GP

I agree & also doubt drilling under-balanced would be used on a vertical appraisal or exploration well at WN - too risky. I expect the operator will aim to match mud weight to just above formation pressure and collect more data on the reservoir and fluids. Given input from our Canadian partners perhaps it will happen in future development wells. To best of my knowledge UBD has never been used in N Yorkshire.

UBD comes into its own with horizontal development wells where the aim is to intersect vertical fractures in the reservoir.

UBD was developed over 40 years ago in western Canada and L48 using closed loop mud systems, sometimes with nitrogen-based foam circulating fluids and a ‘gas-buster’ at the surface to remove methane and send it to a flare. In simple terms the ‘gas-buster’ is basically a cylindrical container where gas-saturated, returning mud enters at the bottom, is agitated by a paddle to release the gas which rises to the top while de-gassed mud exits at annulus pressure, since the mud system is a closed loop.

The gas is burned at a flare and the de-gassed mud passes to the shakers/cyclones before re-entering the mud system as drilling continues. As you know, all BOP’s have annulus diverter systems to cope with unforeseen gas kicks to a flare.

Harryshang

You may have a point regarding ADX and the Pannonian Basin reservoirs, especially in relation to formation damage. I’d be surprised if no-one has tried UBD after decades of experience in the basin.

During UBD operations, a low density drilling fluid is used in order to maintain a wellbore pressure profile that is lower than the pore pressure of the formation at all locations along the borehole. One major advantage of UBD over conventional drilling is that formation damage is reduced because a filter-cake is not allowed to form near the wellbore. Experience shows wells completed with UBD have been shown to perform three to four times better than their conventional counterparts in the same formation.

In addition, lost circulation can often occur during conventional drilling when a large fracture is either created or encountered. Massive mud losses into the fracture can cause a complete loss of drilling fluid circulation resulting in extremely long and uneconomic nonproductive times. UBD techniques can often
help to avoid these costly lost circulation situations. Another benefit of UBD is enhanced the ROP, especially in tight-hard-rock reservoirs such as magnesian limestones in WN.

Hello GP

NAM has been drilling under-balanced wells which flow to a flare during drilling in Netherlands for many years. See link;

https://www.rigzone.com/news/oil_gas/a/10343/bj_completes_3rd_ubd_operation_using_duct_technology_for_nam/

The Zechstein Z2 and Z3 Netherlands produce from fractures and are generally lithologically equivalent to the Kirkham Abbey magnesian limestone.

Underbalanced drilling has been developed by all service companies into a product known as ‘managed pressure drilling’ or ‘mud weight on-demand’.

https://www.slb.com/drilling/rigs-and-equipment/managed-pressure-drilling-services

The main use is in fractured reservoirs to avoid flooding the fracture systems with drilling mud which often wrecks the effective permeability. It’s often used with coiled tubing which eliminates the need for connections, but also works with a conventional rig equipped with a rotating head BOP.

MajorThomas

I think we all agree on the potential value of Deltic’s assets which you summarise, most of which were licensed 6 years ago when the CLNR was under previous management.

This bulletin board discussion in recent days, following IOG’s approach, is more about the business acumen of Deltic’s current management team, their capacity to understand how to cope in the mayhem of today’s petroleum industry and, most importantly, to act in all shareholders’ best interests.

IOG, on the other hand, are not trying to 'steal' `Deltic, but rather proposing to stimulate activity to help realise the value in Deltic's licences by teaming up and bringing in-depth business expertise.

Also, unlike Deltic's management IOG's team has been working without salaries, with compensation linked via options based on future success of their projects.

Major Thomas

Key success factor for small independents is never to spend your own money on drilling.

Since Deltic can neither afford to drill or are even capable of operational drilling, it follows their licences are virtually worthless to them alone. Right now, the company has value because the Shell is priced in. Sure, you can calculate RENAV from the bottom up, but without exploration wells (i.e. money) it’s zero.

For a couple of years, the market has not considered Deltic’s value with no prospect of drilling at all, or even a back-up plan.

Since Deltic’s investment case is to reward shareholders solely by capital appreciation, the CEO has elected to gamble everything on a strategic decision by Shell in the Hague - something over which he has no control.

So is there a Plan B?

Mike 007

I have to agree with you. I normal times Deltic’s team seemed to muddle along in generally the right direction.

Over recent weeks there has been a ‘revolution’ in the upstream petroleum industry. Experience shows significant change usually occurs rapidly, usually driven by exogenous events. Examples which spring to mind include the Yom Kippur war in 1973, perceived oil shortages of the 1990’s, fracking in the USA and so on.

This tends to happen in all natural systems - you can watch waves gently lap onto a tropical beach for days on end, but now and again a hurricane hits and the whole beach vanishes overnight!

There is little doubt that we are experiencing a revolutionary phase of the energy industry’s evolution. While winning companies are reacting to this watershed moment, losing companies are reacting as ‘rabbits in the headlights’ with inevitable consequences.

As someone once said, “there are decades where nothing happens and there are weeks where decades happen” - and Deltic’s short-sighted decision to stop talking to IOG suggests they are incapable of adapting as the North Sea rapidly re-structures.

Hi 0ilriches

Blocks 41/5 and 41/10 (P2252) have ‘drill or drop’ terms in the current licence. In other words, if the licensees decide not to drill, for any reason, the acreage is relinquished with no penalty since the 3D seismic was the work programme agreed with OGA.

The point I was trying to make is that major companies sometimes make big decisions for strategic reasons (i.e. stop all exploration in UKCS) rather than on a prospect-by-prospect basis.

Also, since 1968, Shell has operated a 50/50 JV in the North Sea with Exxon and I assume needs their support on exploration drilling decisions. A number of companies are expected to present offers for Exxon’s UKCS assets in the next couple of months and it will take a few months for the new JV to stabilise. All this simply adds uncertainty to Deltic’s forward programme.

Against this background, while the majors sort out their long term strategic plans, the discussion with IOG might have led to a better outcome for Deltic shareholders. However, it seems Deltic executive directors prefer to sit on their hands and collect huge salaries + bonuses.

Finding and producing oil and gas in UKCS is relatively easy, but finding the money to do is hard. Without Shell, the value of Deltic’s portfolio isn’t far off what IOG’s estimate in the current environment. CEO and COO should consider their positions.

Mike 007

I’m afraid shareholders will regret the selfish decision by our Board not to find a way to progress a merger with IOG which, longer term, would have been in the best interests of all shareholders. The survival and prosperity of Deltic now depends almost entirely on Shell. Time will tell, but IMO it is a strategic blunder to reject IOG, possibly with existential consequences.

The failure to continue discussions with IOG has been presented to shareholders purely value-based analysis as of today, but fails to recognise the transformation of the industry business environment and cessation of UKCS licensing rounds.

In case no-one has noticed, Shell initiated the sale of its Norwegian North Sea assets earlier this year. And let’s not forget Shell’s UKCS projects are a 50/50 JV with Exxon, who are selling their UK assets.

This is diametrically opposite to the startegy being implemented by IOG, CalEnergy and Berkshire Hathaway Energy.

Since Shell joined the Deltic venture, there has been a big strategic shift from ‘business as usual’ directed from Shell’s HQ with exploration bearing the brunt of reduced drilling.

There is now a very real prospect that Shell may decide to decline to commit to firm wells with Deltic - not for technical reasons, but rather because the business environment has changed since they farmed in.

If that happens, where does that leave Deltic’s shareholders? Open to lower offers than IOG’s I expect, especially as Deltic has no experience of drilling or offshore operations let alone the financial resources needed.

Looney’s team; can they do it?

When working for a big multi-national oil company like BP, technical rigour in earth sciences and engineering becomes a way of life - its a technical industry and people are paid for what they know, rather than being paid for what they do.

And 30 years after John Browne revitalised BP based on a simple strategy in 1989 of only exploring and developing large, simple oil and gas fields, investors have reaped the rewards - until now. Browne’s strategy entranced the financial community because progress could be monitored against measurable technical and financial objectives. It worked and instilled confidence in investors and BP staff alike. Finding costs, development costs and so on could be compared with competitors to demonstrate relative performance against objectives. Simultaneously, there was a quiet revolution in earth sciences and drilling/production technology which led to discovery of vast petroleum resources.

Today, in the post-pandemic aftermath, BP seems to have no published competitive benchmarks for what the company is trying to achieve as an ‘energy company’. So, 1) how can staff or investors assess performance and 2) precisely who are BP’s new competitors? Furthermore, where are the experienced technical specialists in the top management team who understand power grids, solar and wind power generation and speak in megawatts rather than barrels?

Instead, its the same group who’s only experience is running an oil and gas company. Sure, the ‘net zero’ aspiration is understandable, but how will it be achieved, what financial returns will it generate and what are the intermediate objectives?

Lack of clear strategy is what has depressed the share price.

Production cost;

https://www.bp.com/content/dam/bp/business-sites/en/global/corporate/pdfs/investors/bp-annual-report-and-form-20f-2019.pdf

See page 33

Upstream unit production costs $/boe

2019 - production cost per boe = $6.84 - down from $10.4 in 2015

Darientaylor

$6.61 per boe in 1Q 2020.

FD

In case of change of control, AN and GS will probably have 2 year notice periods. Normally, directors do their own NPV calculation and it makes commercial sense to go. I doubt IOG has enough chairs for them to continue to do nothing every day, except perhaps negotiate termination of their current office lease, clear out the stationary cupboard and flog their laptops.