Member Info for Exploration

250SWB

TE-6 and TE-7 were 'staged fracs' in deviated wells designed to improve production. It worked spectacularly well as we all know. The TE-5 Horst project also calls for 12 wells, each with multi-staged frac completions.

Examples/analogues include the Tagi-equivalent age Rotliegendes Formation which extends across Germany, Netherlands and North Sea where hydraulic stimulation is 'the norm' for many completions. Luckily for us Schlumberger is providing the insight, experience and operational capability needed in Morocco.

Sound need to be careful with communications so as not to wake up the anti-fracking mob in Morocco who don't like 'shale gas'.

https://www.equaltimes.org/divisions-over-shale-gas-in?lang=en#.XGxFUy-cbOQ

petroleumeng

You are absolutely right - I agree with you that there is a lot more to the perforation strategy than just ‘heavy duty’ perforating guns 'to flow more gas' as the RNS said!

As I understand it, the plan for TE-10 is 1) to test intervals in the well firstly by ‘natural completion’ to determine whether they flow under their own pressure and 2) use hydraulic fracturing to stimulate the reservoir to determine the reservoir response.

If that is the case, the success of hydraulic stimulation depends largely on how well the perforations allow delivery of treatment fluids and frac pressures into the reservoir. So, paradoxically, it’s not so much making big perforations to let gas into the well-bore, but rather to ensure plenty of fracturing fluid and proppant get into the formation!

Because the frac fluids and pressure- induced fractures are intended to move beyond the perforation, shot ‘phasing’ (0, 180 or 120 degrees), density (shots-per-foot) and hole diameter are of higher priority than depth of penetration.

The depth of perforations is largely determined by the size/design of the shaped charge capsules inserted into the gun carrier and the weight os explosive which is typically 20 gm per capsule. Depth of penetration is important because the deeper the perforation, the greater the effective wellbore radius.

Schlumberger’s shaped charge factory is in Houston – hence the delivery from USA. Schlumberger has a patented method of containing the charge capsules for transportation by commercial air-freight which is approved by the FAA etc. The gun carrier itself is not a hazardous cargo. The charge capsules themselves are only useful for perforating wells – it’s the shaped charge design which does the damage. Also, the capsules are detonated using explosive cord in the gun carrier and only connected to an electric detonator when the carrier is in the well bore for additional safety.

Sound’s TE-10 plan is ambitious, time consuming and probably expensive. It isn’t slowing things down, but rather a much lower risk, sensible use of funds than to continue inconclusive exploration drilling. Good call, Mr Parsons.

Big guns

https://www.slb.com/~/media/Files/perforating/product_sheets/gun_systems/carrier/312fracgun.pdf

Scoobydoo5

Thanks. My post should have stated it was prompted by dickupham's last contribution.

Sorry about that.

I accept that you view your oil/gas portfolio through a CFO lens but it seems that the Shell farm-in to P2252 depends on the search for a subtle petroleum trap with huge potential gas volume, partly proven by wells drilled >30 years ago. The CPR and economic evaluations provide insight into the quality of CNRL's endeavours in the UKCS.

This can only have been achieved by CNRL deploying very experienced technical and commercial support behind the scenes although you only see Mssrs Swindells and Nunn working from a small office in Westminster, a location convenient for the Chairman to walk to the office. Wisely, CNRL has distanced itself from operations at sea which, today, is a regulatory labyrinth and requires cast of thousands. Actually running an independent company in the UKCS is very easy by following the long-established systems and reporting procedures. It goes wrong when corporate governance is extended beyond its 'elastic limit'.

When it comes to the detail of negotiating/closing a transaction I noticed Gneiss were involved in completing the Shell deal. They provide exactly the right commercial and legal horsepower needed to make these transactions bullet-proof. CNRL can ill-afford to pay an in-house team of this calibre on standby. Completing the JOA will be a piece of cake.

https://www.gneissenergy.com/gneiss-energy-acts-as-commercial-adviser-to-cluff-on-their-farm-out-to-shell/

So I think our money is in safe hands - and certainly much safer than many other AIM natural resource companies!

dickupham

One rule for house-sellers is to assume 'buyers are liars' and same applies to oil & gas deals. When forced to declare their real financial capacity/capability buyers cannot produce the goods for various reasons. I expect that may have happened with the 'preferred bidder'.

A range of options on 2248. Let’s remember the most cost effective approach, in a perfect world, would be to let adjacent licencees 1) drill/develop Pegasus in 43/13, 2) drill the Andomeda prospect in 43/12, and then, 3) CNRL drills one or more of its Bunter prospects in 43/11. Why? Well, there is no point drilling 43/11 now and then having to wait years for a development scheme/pipeline to reach it. I expect CNRL has been talking to its neighbouring operators and knows their positions.

Spirit Energy/Neptune Energy hold most of the cards and if I were in their shoes I’d wait for the 2248 blocks to be nominated in the next round and bid one or more wells to secure a conventional Production Licence. A well commitment is worth 50 points when scores are allocated to competing bids.

CNRL doesn’t have enough money in the bank to bid a well against an applicant who can. On the other hand, assuming 2248 is relinquished, CNRL could form a joint bidding partnership with an investor who could pay for a well. The advantage in this case is that a bid would score more points allocated on the technical case which has been built. At the moment, if CNRL could find the money, they could still apply for a conventional Production Licence on a ‘drill or drop’ basis (which requires financial backing) to buy time.

It might seem unfair, but these are the rules under which everyone operates in UKCS. OGA is keen to see exploration wells – there are only 3 exploration/appraisal wells operating in the whole UKCS today.

As always, finding oil and gas is relatively easy – but finding the money to drill is much harder!

Longlad,

Spot on. up to 2014 CNRL had spent four years fighting an uphill political battle to try UCG technology and needed to change course to conventional exploration. Despite holding several UCG licences it became apparent it was a very long term venture.

With a clean sheet and the availability of ‘promote’ licences of the UKCS 28th Round CNRL prioritised an area which had plenty of legacy well and seismic data, existing infrastructure, shallow (<80m) of water and was under-explored for gas. At the time anyone could apply for a promote licence and OGA simply needed an application fee payable by credit card. According to OGA’s website the work programme for each of their promote licences was to reprocess 10 km of seismic data (yes 10km)

And yes, a stable, transparent fiscal regime – but above all the most ‘liquid’ gas market in Europe. i.e. any gas producer can sell into the NBP hub as long as their gas meets National Grid specifications and they abide by the ‘network code’ which is the NBP book of rules.

The other thing about what CNRL calls their ‘core area’ is that it is located at the western margin of the Western Europe Permian basin, a vast hydrocarbon province including UK, Poland, Germany, Netherlands with thousands of wells and geological insights developed over 9 decades. Leading companies – Shell and Exxon. So the scope for technology transfer to CNRL is another, latent benefit with the current deal on licence 2252.

You have to hand it to CNRL. They took a counter-cyclic view, run the company on a shoe-string and put shareholder value first. I’m staying invested for long term.

Fair enough, dickupham. Yes - a lot of finance stuff is way above my head (& quite boring!). That's why I'm pleased to see the CEO with finance background while the COO gets on with the science. It's teamwork.

Couple of points;

1) If the results of the 3D seismic justify drilling a well the technical case, with Shell operating, for a new play test will attract a lot of attention and the money will come to CNRL. They will have to demonstrate financial capacity and capability to commit to a 'drill or drop' licence conversion with OGA.

In comparison to some of the total dross being promoted in UKCS right now the 2252 area is outstanding - which is why Shell have signed up, but perhaps as part of a bigger plan.

2) Both Mssrs Swindell and Nunn are loyal to the Cluff 'brand'. Low overheads, financial discipline, technical/commercial realism/excellence and aversion to dilution/debt - quite unlike many AIM oil cos!

If I were AC I would hang a portrait of myself in the Board Room just to remind successors about how to run a business!

Dickupham

I’ve been wondering why a company the size of Shell would want to explore relatively small prospects in P2252 unless, of course, it fitted into a much bigger picture which could be revealed by broadband 3D seismic.

For 80 years geologists have been trying to develop gas in Zechstein reef carbonates – mainly around the Cleveland Anticline and its offshore extension in Q41, The reef trend crosses P2252 where 41/10-1 found fractured Zechstein with gas and almost blew out. The trend continues across the northern edge of Q42 with the Ossian and associated reef prospects. It is effectively a new play fairway neglected by North Sea explorers until now.

Exploration in North Yorkshire started in 1937, targeting Triassic and Permian reservoirs – same as P2252. D’Arcy (BP) drilled Eskdale-2, the first gas discovery in the Zechstein carbonates in the UK. Since then ~ 100exploration/appraisal wells have been drilled in the basin with exploration success relatively high. Out of the 25 pure exploration wells in the region, 13 have found hydrocarbon accumulations (flowed gas) and eight of the discoveries have been developed to date with some e.g. Lockton still producing,. The primary reservoir is the Permian-aged Zechstein carbonate sequence and, more specifically, the Z2 cycle, which is a tight carbonate reservoir overprinted by a high permeability fracture system. Despite considerable investment and effort over the years, the historical development story of these fields has been very much one of technical and investment failure. Amoco did try a near-horizontal well offshore Cleveland which flowed >20 mmscfd but gave up..

Meanwhile, onshore Netherlands, NAM (Shell) has developed several gas fields in the Coevorden area in Netherlands, which are more or less same Zechstein play, by using underbalanced horizontal drilling. So it seems a combination of broadband 3D seismic and horizontal drilling might open a new, multi-tcf play fairway. This is all described in CNRL’s 2016 CPR. I’d be interested to know is CNRL and Shell have also agreed to co-operate in forthcoming licencing rounds or farm ins to chase this play.

Now that would be really exciting if CNRL were involved in a huge new gas play 50 years after the first UKCS discoveries.

The 800th anniversary of diplomatic contacts between the United Kingdom and Morocco

King John got it going

This is a creative deal. It’s really just a ‘seismic option’ which, on the face of it might not seem that exciting. But there are three aspects which distinguish it from ‘run of the mill’ farm-outs.

First, it’s Shell, well known for the appliance of science. If you look at page 145 of CNRL’s CPR for P2252;

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

one play is a fractured Zechstein reef which has been largely overlooked as ‘too difficult’ in the UKCS. However, NAM (Shell) has developed several gas fields in the Coevorden area in Netherlands which are more or less same play. In 2252, 41/10-1 discovered gas in the Zechstein years ago, so the play is proven in 2252, and extends to the south, even to onshore, and to the west. So it could be much bigger overall.

Second, although there is existing 3D over P2252, the Shell deal involves ‘broadband’ 3D which is largely responsible for the wave of Carboniferous discoveries further east including Breagh, Cygnus etc. With gas shows in the Namurian Carboniferous shown by early wells, the gas must be sourced from a deeper lower Carboniferous source, as opposed to the younger, Westphalian coals. So maybe Broadband 3D will reveal what is really going on in the pre-Permian rocks, especially now offshore fracking in UKCS has become the norm.

Third, if I have read the RNS correctly, 70% of a drilling commitment will be carried by Shell which can obviously demonstrate its financial muscle to OGA. That leaves CNRL to find 30% of a well cost. If the seismic results are that encouraging, then the case for raising money may be easier.

Here is SDX show today;

http://www.sdxenergy.com/~/media/Files/S/Seadragon-Corp/presentations/2019/SDX%20Energy%20-%20Morocco%20Conf%20Presentation%20Feb%206_7%202019.pdf

I've attended 3 of these conferences since 2008. Attendance and interest peaked in 2014 towards the end of the last Moroccan offshore boom. The 2014 conference included Cairn, Chevron, Genel, Gulfsands, Caithness (SDX), Fastnet, Kosmos, San Leon, Repsol, Anadarko, Shell, BP, GDF and Pura Vida. CGG, Halliburton and Schlumberger were there too. This was the period when BP farmed in to Kosmos's Essaouira acreage. Shortly after, pure Vida drilled the super-deep MZ-1 well offshore which completely failed to find either reservoir or source. This + a couple of wells by Cairn and Genel killed off the offshore leaving Chariot to carry on looking for slightly different plays. BP even paid Kosmos $16 million penalty to get out rather than drill and subsequently canned their (BP) $1 billion work offshore Nova Scotia which is the conjugate margin to Morocco and paid an exit penalty there too.

Not surprising attendance is a bit thin in comparison with previous years.

Shed

Sure - you can assert your views. But all sensible corporate finance people use decision trees - except Sound.

https://www.slb.com/~/media/Files/resources/oilfield_review/ors00/win00/p2_9.pdf

Gozo

Yes I concur with your post.

I'm afraid Shaungreen and his fan club are struggling to pass their 11+ and multiple probability theory will reach them when they start wearing long trousers.

But if you visualise a decision tree and take into account the unpredictability of Tagi reservoir effectiveness its tough to generate a positive EMV for a 2 well appraisal programme on TE-10 unless CoS for each well CoS is in region of 50%.

The main point is that investors money is exposed not just to Exploration risk, but also in 'Tagi world' Appraisal risk, unless BM and his team can create a reliable predictive model. o getting to a Commercial Field worthy of a Concession is very risky.

With drilling commitments met, even if a TE-11 location is confirmed, I expect it may be hard to convince Schlumberger to spend more on exploration drilling. Management Committee decisions on money must be unanimous.

Level Up

Spot on. In terms of adding value a TE-10 appraisal programme with a couple of wells is the best commercial answer.

But - let's be generous and assume TE-10 is a discovery which flows gas. Then, knowing what we do assume 2 appraisal wells each with 20% CoS are drilled. The combined CoS is therefore ).2 x 0.2 - which is 4% to demonstrate a commercial accumulation - or !a in 25 gamble - slightly better than roulette.

The sooner Sound demonstrates some commercial sense, the better for PI investors.

Dickupham,

The EMV thing is very much a guide to objective, logical decision making, taking into account the multiple risks in taking a blank area of the UKCS through to a commercial outcome. So to use the dice/coin toss example, the EMV would take you to a decision to gamble your £60 on coin tossing. In the CNRL scheme, even if you’d farmed in for 1% interest, you’d still get a positive, but 100th of the size, EMV.

But because oil and gas projects are very long term projects the wise negotiators will search for a balanced, sustainable commercial agreement where all participants share the returns more or less equally. Experience shows un-balanced agreements lead to mis-alignment and furious arguments about strategy/investments.

And then there are a host of other influences on decision-makers. For example Oranje-Nassau Energie has a 30% interest in the Breagh gas field in Block 42/12 and will soon need more gas to replace ullage in the Breagh-Teeside pipeline and Seal Sands Terminal. So they’ll be up against Neptune who need more gas to keep the Cygnus system to Bacton running full tilt at maximum price – especially this week with the cold weather.

Oranje-Nassau also picked up Sterling Resources exploration assets, including the monster Zechstein reef in blocks 36/30, 42/2a, 42/3a, 42/4 & 42/5, immediately north of CNRL’s core area and a proven gas play in the Netherlands. CNRL’s Pensacola prospect in P2252 is same play – ignored for years in North Sea, but its possible gas right on the Breagh pipeline.

Then, back in the commercial department, a key measure in capital allocation is Internal Rate of Return. You can see in CNRL’s analysis that the Bunter Sandstone prospects show an IRR of ~24%. This is one reason why CNRL proposes to explore these first this year. So the farming in partner will ask themselves ‘How much can I afford to spend and still meet my own corporate IRR targets?’. The buy side is then able to negotiate within clear commercial guidelines. I suspect you are familiar with how this works.

Dickupham

EMV is a mind-bending concept for a Sunday morning. It is appropriate to use it when multiple outcomes on a decision tree are available to help an investor understand the chain of risks. In AIM oil and gas a simple positive EMV is enough encouragement to go ahead.

Expected monetary value (EMV) is an indication of how much money an investor in CNRL’s projects can reasonably expect to make. Imagine it as an average of the best- and worst-case scenarios. It accounts not only for the value figure assigned to each outcome of a decision tree but also for the chance of that outcome occurring.

But first You need a decision tree like the one shown in CNRL’s report To calculate EMV. It’s quite simple; you just multiply the value of each possible outcome by each outcome’s chance of occurring; then add all the the results to reveal the EMV.

For example, if you bet £60 that I’ll roll a dice and it’ll come up on the number 4, the EMV is –$40, because you have a 1 in 6 chance of winning £60 (=`£10) and a 5 in 6 chance of losing $60 (-£50). Result; £10 - £50 = -£40.

On other hand, if the gamble of £60 was based on the toss of a coin and you bet £60 the result is heads the EMV is £0 because the chance is 50/50. The EMV equation is (£60 x 0.5) – (£60 x 0.5) = £0.

Note that many AIM oil company CEOs (mentioning no names!) just don’t ‘get it’ because they simply multiply the single well NPV of a prospect by the CoS and (correctly) claim a risked value. But that doesn’t take into account appraisal and development risks. If they did it would reveal the actual, intolerably high, risks to which investor’s funds are exposed.

In CNRL’s analysis the results of each well will define how the EMV of the venture develops. Assuming each branch of the decision tree eliminates its risked outcome, in the success case the route through the tree will reveal a single value which, strangely enough, is the NPV!

dickupham

CNRL's `economic feasibility study of P2248 explains how risked value is calculated.

It is quite uncommon for an AIM company to be so transparent and confident in the quality of their work.

I imagine same has been done for P2252.

The main point is that CNRL has a convincing 'base case' from which to start farm-in negotiations.

https://www.cluffnaturalresources.com/wp-content/uploads/2017/04/P2248-Economic-Feasibility.pdf

I suspect we are seeing 'organisational drag' on the buyer's side, waiting for a board meeting or similar capital allocation procedure. Nothing CNRL can do to speed it up.

Ducati2

20 years ago BP started a CT drilling campaign in Alaska to pick off undrained parts of the Sadlerochit reservoir in Prudhoe Bay. The Sadlerochit is a fluvial sandstone reservoir which was initially difficult to develop without a detailed geological model. Similar and time-equivalent to the Tagi. Fortunately BP had cored most of the production wells, built a predictive model for reservoir effectiveness which enabled the CT operation to probe remaining oil in the reservoir.

Later, BP did same in the Sherwood Sandstone at Wytch Farm in terms of creating a predictive reservoir model, although they opted for a conventional rig to drill the 10km horizontal wells under Poole Bay. The Sherwood Sandstone is also a fluvial sandstone and time equivalent to the Tagi in Morocco.

Anyway, CT may eventually be the way to develop the Tagi in Tendrara, but only when Sound has a convincing depositional model.

See link below for the Alaska CT story - and this is 20 years ago. CT drilling has advanced a lot since then.

https://www.slb.com/~/media/Files/resources/oilfield_review/ors98/sum98/pgs_20_35.pdf

summary of upstream activity in morocco

https://www.leconomiste.com/article/1039980-exploration-gaz-petrole-la-liste-des-projets