Member Info for Exploration

Well spotted - see link, with pictures. Russians on the left.

http://www.onhym.com/en/component/content/article/43-en/new-feed/533-december-17-2019-signature-of-a-memorandum-of-understanding-between-onhym-and-the-russian-state-company-transneft-related-to-cooperation-on-hydrocarbons.html

Levelup,

Yes - but Sound is demonstrably incompetent.

Ericnat17

Couple of points;

Sound Energy East needs to clear its liabilities before entering the JV with ‘mystery buyer’ as a Condition Precedent. These liabilities might include;

1) re-instatement of TE-8, 9 and 10 locations (Wacky Races in reverse)
2) demobilising both Saipem rotary rig and Italian coiled Tubing rigs to a Mediterranean coastal port + transport back to Italy
3) paying acreage fees to date of closure
4) legal and accounting fees for transaction
5) incidental costs for approval by Onhym/Minister

The trouble is that Sound cannot commit to new contracts for their own account without having sufficient cash in the bank. Otherwise, Directors are guilty of ‘Wrongful Trading’ - illegal according to UK company law - punishable by fines, disqualification etc. Hence to ‘top up’.

Maldini

Good points. I tend to take the long view.

OGIF has never paid a penny for participation in this, so they really haven’t lost out.

OGIF principals have been involved in Tendrara for years and Parsnips and Spaghetti outsmarted them with their personal, get rich quick approach.

The prospect of a ‘Johnny Foreigner’ making off with the goodies was too much for Rabat to tolerate.

FD

Early next year for 32nd Round

Couple of things;

First, 42/4-1 has opened a new play fairway in UKCS. A once in a decade event. Look at the positioning by others such a Simwell and Shell leading the charge.

Second, although the 42/4 discovery is a big news event, industry is sitting on news with 32nd Round coming up. Either way good news all round.

Maldini

OGIF don’t need to ‘buy’ the company - they just need to control it in stages with their own management. That gets round the 29% rule.

Stage 1; wait for parsnips to pi55 away private investors’ money on 3 hopeless wells to fulfil Tendrara licence commitments and secure licence for 8 years. (achieved after TE-10)

Stage2; take control of management and finance functions - exit Parsnips and Traynor. (I.e. fired). Replace with Segheri and Moroccan CFO. (Achieved)

Stage 3; create JV vehicle to satisfy Sound PIs with royalty of some kind - to be negotiated/in progress.

Stage 4; introduce new investor (the mystery company) and get on with TE-5 development, pipeline etc.

Pontcanna

Ask our CEO.

Level up

Ask Mohammed Seghiri - our CEO. OGIF has effectively grabbed the steering wheel and will clear up the mess made by his predecessor at Sound.

He was a managing partner at OGIF since it was created + worked for Advisory Finance Group who arranged the pipeline deal, the GSA and so on. OGIF/Maghreb has held Tendrara for about 20 years in some way or another and thought they were onto a winner with Sound and all their hype.

Fairdealer20 - a couple of weeks ago Hague and London announced results of their exploration well on 43/12 - see below. If you recall, this is right next to CLNR’s relinquished block 43/11 (formerly P2248) which they said they would re-apply for in 32nd Round. More recently, Spirit announced they will operate the 42/4 discovery/appraisal project and no doubt will do same for Andromeda. Then they can incorporate a development into the Cygnus system where Spirit has ~60% interest - although Cygnus is operated by Neptune.

OPERATIONAL UPDATE - Hague and London; December 2nd

Hague and London Oil PLC, the oil and gas company with a diverse portfolio of production, development, appraisal, exploration and infrastructure assets primarily focused on the Southern North Sea, is pleased to announce an operational update regarding the Andromeda North Well (“Andromeda North” or “The Well”) as well as an update regarding the awarding of the F5 Block, in the Dutch sector of the North Sea and HALO’s involvement in the pending United Kingdom ("UK") Offshore Licensing Round. The Group also notes that the previously announced proposed acquisition of several assets (the "Assets") in the Dutch & UK sectors of the North Sea from ONE-Dyas BV ("OND") is progressing with the Company expecting completion in early 2020.
Operations on the Andromeda North exploratory well (Andromeda or the Well) have been completed and the rig moved off location recently having proved a natural gas discovery in the targeted Carboniferous sandstones. Andromeda North is located in the block immediately to the west of the Greater Pegasus Area that has been successfully drilled and tested while currently under review for development concepts.
The Well found a significant gas column and reservoir section within the Westphalian A target section on the north side of Pegasus West bounding fault. The well encountered gas in good quality,
porous and permeable, sandstone, as was found in a similar reservoir section in Pegasus West.
The gas water contact was shallower than in Pegasus West indicating that Andromeda North is not in communication with Pegasus West. The well was drilled down-dip from the crest of the structure.
Pressure data demonstrates recoverable gas and there remains an, as yet, unquantified volume up- dip of the Andromeda North well. Consequently, the well met the minimum targets and was plugged and abandoned while the data is being studied for future activity.
The commitments have been met for the current phase of the 43/12 Block and the partners will evaluate the Andromeda North results for future planning, inclusive of a possible up-dip location as a potential appraisal well, alongside the ongoing development work within the Greater Pegasus Area.

Mike007

ONE have kept this quiet until after deadline for 32nd Round applications. Good news for P2252/Shell deal and backs up CLNR’s geology and strategy.

Dutch firm One-Dyas has confirmed an oil discovery with its Ossian-Darach well in the southern North Sea.

The area is better known for its gas reserves, but One-Dyas said it had struck oil.

One-Dyas would not provide a figure for discovered volumes.
The well was drilled using the Valaris 121 rig.

Drilling started in May. The well was sidetracked in July and completed at the end of August.

One-Dyas then asked the Oil and Gas Authority for permission to conduct and extended well test.

David Moseley, senior analyst at Westwood Global Energy Group, said in October that it could be assumed that hydrocarbons had been discovered.

An One-Dyas spokesperson said today: “One-Dyas and its partners are pleased with the encouraging results of the Ossian-Darach exploration well and can confirm that oil has been encountered.
“Further evaluations are ongoing to assess the commercial potential of the area.”

One-Dyas’ partners are Spirit Energy (35%) and Neptune (30%).

Thanks D0berman and sorry for my error.

Oranje Nassau/Neptune are maintaining confidentiality on Darach drilling results and its not clear their discovery is in the Zechstein or the underlying Carboniferous. But if it is ‘wet’ gas similar to the Breagh Field it fits with evidence of a deeper Carboniferous source rock, as opposed to shallower Westphalian-age source which is the source of gas further south.

If you look at pages 147 - 151 of CLNR’s CPR you can see they had based their application for P2252 on Zechstein reservoir models of analogue gas fields developed by Shell in Netherlands some years ago.

https://www.rns-pdf.londonstockexchange.com/rns/7920H_-2015-12-2.pdf

I wouldn’t be surprised to see a joint application from CLNR/Shell in the next licensing round based on finding more gas to maintain existing infrastructure in CLNR’s core area.

P2252

News is slowly leaking out that gas AND liquids have been discovered by Oranje Nassau in well 42/4/1.

https://www.upstreamonline.com/exploration/darach-find-said-to-hold-surprise-liquid-bounty/2-1-695654

CNRL reported this in the most recent update.

“The Zechstein Reef Play on Pensacola has seen significant activity and successful drilling over the last six months with Rathlin Energy announcing a significant discovery at West Newton, in East Yorkshire, where a 65m hydrocarbon column was confirmed in the West Newton A-2 well.  Offshore, ONE Dyas are reported to have recently discovered hydrocarbons in the Darach Central-1 well which was testing both a Zechstein Reef and a deep Carboniferous target.”

We know the Zechstein carbonates hold gas in P2252 from previous drilling and other blocks on the same trend which may have potential of 5 or 10 tcf potential for the whole play. So it looks like CNRL hunch to licence the P2252 area has some merit since the prospective trend will be much sought after in the forthcoming licence round. After Shell has reviewed the latest 3D seismic drilling an exploration well on P2252 this time next year looks more likely.

I should have added;

From our perspective the JV should be under jurisdiction of English Law.

The agreement should comply with GAAP standards.

I expect both Sound and Purchaser will want this anyway.

PNE79

Malcy is taking in general terms. The detail of this deal will be in the ‘JV Agreement’ mentioned in the RNS which defines how revenue is divided between the Contractor Parties (i.e. Sound and Purchaser). Malcy uses the term ‘royalty’ loosely without knowing what it will be.

In Oil & Gas Jv’s Sound’s interest could be a Net Profits Interest, a Production Payment Interest, an Over-riding Royalty Interest and a range of other definitions. These agreements are largely determined by accountants because somebody has to untangle the production and cash flows to ensure everyone is paid. I doubt anyone in Sound or Purchaser has the knowledge and experience to write such an agreement; it will likely be outsourced to the likes of Ernst and Young, supervised by Rothschilds.

A JV which favours one side or the other is to be avoided. If its not a balanced deal it will be unsustainable since both parties are joined at the hip for a decade or more.

Lyndondavies

Regarding new people, one could argue it’s just the same people without Parsons and Traynor. The accountant and chief counsel were there already and we know Mitchener and Argent from before. Mohammed Seghiri was Sound’s leader in Rabat.

So it’ll likely be more of the same but without Parsnips and Worzel Gummage.

I’m as intrigued as the rest of us about the buyer.

I thought for a while it might be a Moroccan entity associated with OGIF. But we’ve been assured it’s not a related party in any way.

Fred Lacuha (General Counsel) told us at the FSC.

“There is no link between the proposed purchaser and any existing or former employee or any associates of any of them obviously as far as the Company is aware.”

So that rules out any of the JP, Marco outfits and AFG. I dare say our new consultant is detailing with now. Whoever they are they are set up to double their money.

Overall, what is needed is a technical/operational project team led by a tough project manager to get TE5 into production as soon as the GSA is finalised - may that will get our money back. Forget exploration for now.

Thanks lyndondavies

All I can add is not to fall for the 11tcf claims on Sidi Moktar - yes there is gas, but in much smaller quantities which can be commercialized using on-site micro LNG to deliver it to buyers.

Hopefully, the new owner will engage Moroccan geoscientists who know the Petroleum systems.

Thanks Aussieridge

I reckon ddboy and I could do a better job for £10/hour (each!)

JOHN

I agree - the best prospects are all relatively close to TE-5 and could have increased the size of the developed area as a ‘cluster’ of smaller fields. However, Sound’s decision to ‘go for broke’ trying to discover more, bigger gas fields was never going to succeed. It wasn’t ‘bad luck’ or to be expected in the petroleum business’.

No - the root cause of Sound’s failures is second-rate subsurface analysis and failure to study and understand extensive previous work on reservoir effectiveness. TE-8 showed that features where the Tagi was deposited in a playa lake or alluvial fan facies. Without going into the details, the distribution of sedimentary facies is very variable and unpredictable, even over short distances (tens to hundreds of meters).

The available data from the wells suggest that the basin probably does not contain significant amounts of well-sorted (I.e. porous and permeable) sediments. Within the Tendrara area it appears that the alluvial fans developed as a consequence of initial rifting with main deposition occurring only locally. The morphology was levelled with progressing time and an extensive playa system covered the area forming the upper TAGI mudstones. Thus, an effective drainage area promoting braided streams and better sorting did not develop in the Tendrara area. Whether such a drainage system developed in general is very questionable since no indications of any clean fluvial sandstones have been encountered in wells to date I.e. nothing similar to time-equivalent Rotliegendes sandstone of North Sea or Sherwood Sandstone at Wytch Farm in UK.

The major faults will control the facies and thickness of the TAGI reservoirs. This model is based on poor seismic data, especially in the 2D seismic areas, and will only be improved with the widespread acquisition of high quality 3D seismic across the whole basin area. One wouldn’t do 3D all in one go - but rather extend it from known areas such as TE5 - eventually over a period of years the surveys can be ‘merged’ into a single survey.

In fact, the halite cement found in the Tagi in Sound’s dry wells probably formed before gas migrated from source rocks and therefore the reservoir was never charged in the first place.

Unfortunately similar processes in the Tagi took place in Sidi Moktar. Published work on the Meskala Gasfield in the Sidi Moktar area demonstrates this. 6 out of the 10 development wells on Meskala failed to flow due to halite pore occlusion. So while the proposed new seismic might define prospects the reservoir effectiveness risk still dominates the chance of success - just as it has in Tendrara.

Sounding Off

The Fasnet CPR states following range for prospective resources at SBK in bcf

Min 62 - most likely 205 - max 982

The wide range of resource estimates is driven by the range of bulk rock volume calculated from existing seismic.

Let’s remember the TE-6 and TE-7 well locations and trajectories were determined using 3D seismic. The older 2D seismic over SBK is inadequate to precisely locate new high angle wells similar to TE6 and TE7.

3D seismic is needed

The SBK-1 well was drilled in 2000 on a structure covering 50 km2 defined on a 2D seismic grid of 1974/75 and 1981/82 lines and on an SRM (Sedimentary Residual Magnetics) survey. The well produced gas from sub-salt Triassic TAGI sand reservoirs. The well bottomed in Palaeozoic clastics.

After acidisation, the well produced at a rate of 5.5 MMscfd of gas declining to 2.5 MMscfd
The production tests in both SBK-1 and TE-5 wells show that the TAGI reservoir is capable of producing gas unassisted. The reservoirs in both wells are overpressured by some 70% above hydrostatic.

The Seismic re-interpretation in 2010 confirms the SBK structure and suggests the well was drilled in a small graben close to a fault. This fault appears to be theproduction barrier indicated during the well testing. It is therefore probable that better production could be achieved from a well on a more crestal location. Also based on the recent work at Tendrara it should be possible to use attribute analysis to predict areas of better porosity in the TAGI.

The SBK-1 test results indicated that the overpressured reservoir (about 2000 psi, a reservoir pressure of 7175 psi against an hydrostatic pressure of some 4918 psi (0.44 psi/ft, 1.44 psi/m), equivalent mud weight some 1.4 gr/cm3) quickly depleted (decline of 25% after production of 3.9 MMscf) and that the interconnected volumes at best could be estimated at some 0.025 Bcf.

Clear boundary effects could be deduced from the static pressure surveys. A boundary was seen at 22 m from the well bore and radius of the total drained area varied between 44 m and 70 m (average porosity 5 % and 2 % respectively). Interpretation of the side-track TSP Gamma revealed a dense system of limited throw faults, spaced between 10 m and 100 m, suggestive of a fracture system. Faulting near the well track (100-150 m) was also confirmed from the line HX-06 which was converted to acoustic impedance. The test results in both the vertical hole and the sidetracked hole showed different pressure regimes suggesting that the fractures/faults are sealed.

This fracture system might be related to a fault system. The seismic, which dates from the early eighties, does not allow consistent detailed mapping of the interval between the base salt and the Hercynian unconformity or the fault system. The deepest horizon which can be mapped with reasonable confidence is the top of the intra-salt basalts. 3D seismic could de-risk this prospect