Member Info for Foresight22

The issue is that below Structural Closure - the fracture density seems to decrease significantly (see Lincoln well in ppts). Mobile oil is present from the crest down to the oil water contact in the host rock. So there is mobile oil, hundreds of feet below SC which will be drained via producers in SC. The problem seems to be HE wanting to drill to appraise these oil volumes rather than modelling based on ongoing production data. As long as there is commercial productivity in SC - the development plan is fully robust - certain reserves. Hence need for LC & WC to be flowed successfully - thereby enabling production in future from SC and below SC in both Lincoln & Warwick. Hence SP drop from 58p post WD well results - CMD not convincing either that GWA was robust..

...not sure market drop just Brexit & weak Pound (where there is time to still get exit with 2 years transition and a 10 year NI backstop); also Trump vs China, August Holiday Blues, HUR BoD not willing to support SP with RNSs... LC is FB soon.

..supply boat next to rig, is this the casing being delivered? => at built section of well?

Why would a geophysicist be able to answer this question?

..if you asked a reservoir engineer he/she would say it’s irrelevant now after three months production - wells being produced by pressure drawdown constraints - which limited DD on aquifer - hence no premature water production. A better question would be how far out now have we ‘seen’ the barrier between Lancaster and Halifax yet? If not what is the chance of these two FB reservoirs being actually the same field?

HE will only know which fractures are flowing by running a PLT log which is impossible now the wells are subsea completed. Ie no rig over producers. This would not help as the fracture meshwork is to complex to identify. Once HE start to understand the extent of Lancaster’s oil connected to these two producers - they can then decide whether to increase the DD => increasing the flow.

..do Tullow issue Exploration RNSs when oil discovered or after well completed, rig moving on? If former - not looking too good if no SP movement in next week.

..come on you rock lovers - all the geologists on here, one must be still working(!) - any ‘bleeding oil’ in 204/30-1 core report. Surprised HE don’t put pictures of rocks in their ppts to keep non oilers audience awake at their CMDs. Maybe they do not own ‘cameras’.

204/30-1 was drilled by Monsanto in 1975. It was drilled into Warwick Basement - penetrating some 40 feet and was cored recovering 100%. So yes if that core found oil (information I don’t have) WC will be appraisal! ..Net Rock may have been proved already... who has access to this well’s core report - end of well report?

Edison Report Claimed 64% CCoS for GWA:

'We increase the risking we apply for GWA to reflect the non-commercial flow seen at Warwick Deep. We have decreased the commercial chance of success from 72% to 64%. We do not believe the result of Warwick Deep should have a material impact on the GWA tieback risking, since a discovery in Lincoln has been confirmed and the tieback is only targeting c 20mmbl of the previously estimated 500mmbbl for the GWA.'

WD obviously not analog for LC well target, so CCoS should not effected! [geological, petrophysical and engineering properties not similar) : (1) LC build section out of FD so will have good access to weathered FB (if drilled to plan unlike WD which was drilled deeper) & Fracture System & Host Rock; (2) WD drilled outside Structural Closure, LC drilled inside; (3) LC is appraisal well => commercial producer so should be drilled to full horizontal length.

..must be near (1) FB top. SP shows signs of life at HUR.

'mapping of porosity using seismic methods is not possible -- mapping of seismic scale faults and attributing Fault Zone widths as statistical ranges'

This might help - cut & pasted from FB references:
'In the case of the Rona play, porosity is almost entirely associated with fissure fills, joints and microfractures that are present within and without zones associated with larger faults identified from seismic interpretation (Belaidi et al., 2016). This distribution is split into two facies: Fault Zones (Fracture System) and Fractured Basement (Host Rocks). As an example, the average porosity for the Lancaster Field is 4% with average Fault Zone (FS) porosity 4.8% and Fractured Basement (HR) porosity 3.2%. Despite the improved porosity associated with Fault Zones, mapping of porosity using seismic methods is not possible and areas of potential high porosity are quantified through the mapping of seismic scale faults and attributing Fault Zone widths as statistical ranges. Fault Zone widths are estimated from the ranges of Fault Zones established through drilling and wireline data (Belaidi et al., 2016). Porosity generation is attributed to a pre existing fracture network that has been enhanced by a combination of fissuring (tensile failure), partial mineralization due to influx of hydrothermal fluids and deep penetration of surface weathering processes down fissures (Trice et al., 2018; Holdsworth et al. 2019).'

So static reservoir modelling biased heavily by statistical methods - know from logs eg Lincoln - that fracture density within structural closure (crestal) >> deeper below structural closure. Problem with seismic is it is shot in time not depth - so hard to pin-point exact position in depth of seismic scale faulting (can easily be >100ft out in depth) - as well as oriented sub-vertical or sub-horizontal from seismic image 'cube'. Also Lancaster & WD seem to have perched water too - not modelled pre-WD. Perched water seems to increase with depth too, while fracture density decrease. But HE has proved connected oil (ie oil column) is present below structural closure.

In WD if they had drilled an exploration slanted hole (more costly) they would have encountered fractures which they could (1) checked if statistics in model ok, & (2) drilled the horizontal well as an appraisal well to hit best encountered in slanted pilot hole - appraising rather than exploring at WD with horizontal. Actual horizontal was drilled deeper than planned so - statistics would be worse still.

So models not 100% accurate as based on interpretation of seismic (+ depth to time issues) & statistics of expected fracture density with depth... Drilling deep in Lancaster below the structural closure could result in same result! HE know the approximate OWCs - so in the future 'hopefully' will not drill this region again while we are investors and instead evaluate this region based on volumes connected to producers through dynamic production modelling.

'extolling the benefits of basements'

Unfortunately Dr Rocks thinks FB WoS has no true-direct producing analogs when compared to other FBs, so under US & Canadian Reserves booking rules - would not help. For instance perched water production not obviously seen in other FB reservoirs. All very vuggy!

Post WD & CDM negative impact (Kerogen & Centrica) + possibility GWA may not be commercial to justify 'bigger boat' (HE/Spirit still appraising through LC & WC) one postulation is that new buyers are simply waiting for LC critical info to start leaking before HUR SP jump, forcing new buyers to commit again. As Dr Rocks highlighted (based on 'WD flow oil' failure) - need (1) losses while drilling in top FB section; if get this (2) HE will be very positive before run casing; before (3) drilling horizontal with increased losses while drilling; if get this (4) HE stop drilling at planned TD; to (5) run planned DST; which delivers (6) expected commercial rates. With such critical well LC - HUR need Spirit to remain optimistic for enlarged GWA development, therefore 1 => 6 will deliver > 58p SP. Depending on degree of 1 => 6, lots of leaking info 'points' => risk-less-future investment based on strength of 1-> 5 "messages". Hopefully this is the last period such low SP will be so prevalent... HUR need enlarged GWA development which helps GLA further drilling certainty - opportunities (eg Halifax). With just Lancaster EPS production, Dr Rocks may just simply blow profits on deep Lancaster & Halifax drilling + other hydrocarbon appraisal - one postulation why current SP < preFOIL ropey period.

Looking forward to SP firming based on (1), … (2),... increasing based on (3),… (4)… (5)… jumping on (6).

Right — companies need investment (raise Capital) which bring in new shareholders. So oil company X gets some acreage - raises bank loan/White Knight for seismic - brings in big fish - raises Capital to drill - sidetracks to discovery - raises shed load as new investors think this is amazing based on pre-drilled guesstimates (some 200 small uncommercial discoveries just in UK) - drills appraisal to discover no further oil - still got loads blows on another ‘project’. Where do profits for shareholders come under this scenario of AIM company X. Shareholder profit is down to Certainty of The Plan which raises The Investment & Risks of execution (degree of experimentation - knowns & unknowns).

..how can ECO share price increase by 4% and Tullow decrease by 4% in same day. Was there something in the HY results that caused this ? Certainly running complex smart completions are not that smart! Cost more and so have less wells but end up with similar production, only service industry benefits. Great to see Tullow get back to grown-up Exploration again - looking for 80% increase in SP if all three are commercial discoveries!

..reason why companies join AIM is to raise capital! ..not to benefit investors - that is a function of certainty of plans & risks of execution.

'Xcite Bentley' 2013
1P, 2P and 3P oil reserves for the Bentley Field of 198, 250 and 312 MMstb respectively over a 35-year production period
BUT
..Finally, an updated Field Development Plan will be submitted to DECC in the coming months

Without FDP approved by DECC - companies have no bookable Reserves! Bentley was still in Appraise without long-term EPS, not the EWT carried out which just proved there were 'some' Contingent Resources .

...not sure JOG is good example of why AIM not good marketplace for companies looking for capital. Buchan Area very difficult so will be very surprised if JOG add more than 10-25 million BO Resources. How's Verbier going? H2S measurements? Probably something not that interesting for most on here. Xcite - did you really believe the CPR Resources?

'bullied'

..no bullying goes on this BB - everyone has free voice to contribute! On any subject -- as it seems.. 'HUR' domain is clearly commercial matters & practices (BoD) -- so RNSs clearly are under 'HUR' domain. HE (Hurricane Energy) is clearly for technical matters & practices covering HE issues & concerns related to technical production, appraisal & exploration activities - most so specialist the HUR BoD would defer from anyhow! ...leaving Dr Rocks to answer. DarkEnergy, I can see you like clarity which clearly is not the main goal of certain BBers. Clarity (53%) vs Fog (47%) - who knows.

What is certain is that HUR has missed another great opportunity - promoting instead ambiguity, uncertainty & risk. HE material in CMD ppts have lots of ambiguity such as 1:27 "1 billion Gross Reserves - probably do us" referring to a plot with 'Net 2P Reserves' - which would be lost if just referring to ppt only - not listening to actual commentary. Q&A session of CMD likewise was insightful by questions unanswered.

One issue under HE is why are they not drilling 4 km horizontal producers! .. maybe that's another opportunity, which is why no material in CMD 'pack' appendix. What a hot Summer!

..cannot see that current market ‘prices’ in future discoveries. Lower SP since Ghana ‘over complex well completion’ hick obviously became news. Tullow got three drills in Guyana - based on industry global average only one would be expected discovery, maybe less for massive commercial discovery. But oilers know this is GUYANA! ..not long now - been long 3 year wait.

...so no RNS on second lifting. HUR bunker mentality now on, all technical focus on LC. Could have all gone on holiday? Or just melted in heat? ...