Member Info for Penguins

PITW,

they've just hired Apex who according to UKOG :-

'advise our clients on horizontal well placement, stage lengths, optimal reservoir stimulation and completion fluids all specifically tailored to the rock-type being treated.'

So if these guys are going to determine well placements etc, then it would be a bit premature drilling HH-2 'soon', the Portland horizontal which according to the gantt chart will be the first well drilled, before they've done their work.

I just looked in here and at FOTH twitter and saw this:-

'Towards the end of yesterday`s interview, SS stated that "in 2 years time the company will be worth many multiples of were it is now.'

I haven't listened to it but I also saw in FOTH''s feed a tweet from eyes on the prize that he also said a company was valued on its reserves.

Current reserves are under 100,000 barrels (2P 85,000 in Xodus CPR).

I'm sure someone will say multiples meant 100 times.........

Argus,

Tellurian do not have to participate in the development. The JOA summary in the readmission document has provision for sole risking - ie HHDL decide to go ahead with the development but Tellurian can elect to not participate.

I'm not sure if HH-1z and or HH-2 are commitment wells (the development is not a licence work programme commitment) - if they are Tellurian (or anyone they sold to) will have to contribute their share and will be entitled to their share of oil.

Phil,

Just because I think the average daily production will be lower in 2021 why does it 'infer' I think the rate at the end of 2020 will be 'above 2,000 bopd'.

It has nothing to do with the 2000 bopd figure - it means I think the average for 2021 will be lower than 2020 - which was in response to this bit of your post:-

'The peak production planned for late 2020, from Horse Hill alone, according to the plans is 16 tankers = 3840 bopd. 1.4m barrels in 2021.' - which inferred the production in 2021 would be 3840 bopd (as 365*3840 = 1,401,600bbls) the same or more than 2020 (as the 3840 you are saying is peak production at the end of 2020).

Andy,

do you really think SS is worried what anybody posts on this BB?

I've said why I think the statement was in the RNS and it wasn't because he was being conservative.

Phil,

I don't know why you're asking me:- 'Where does it say "over 2000 bopd" at the end of 2020? Are you mixing stats to suit yourself?'

I think making things up to suit yourself may be your problem as I never said anything about "over 2,000 bopd' being at year end."

Rodders,

Why not just say you hope it will be more save a lot of angst, the RNS statement is:-

'Subsequent horizontal wells in 2020 are designed to boost gross production to over 2,000 bopd'

It doesn't say that the 'over 2,000 bopd' will be in 2020 but is the boost resulting from the horizontal wells drilled in 2020 (which is all of them).

But I would still expect the 2021 figure to be less - my opinion.

Phil,

why in the RNS is such a low number used 'over 2,000 bopd', why not 'over 3,000 bopd' then.

I suppose this isn't a planning application and it's clear from the RNS that Xodus have been working on both Kimmeridge and Portland data to be able to 'agree' 720 to 1000 bopd initial production figures for both Kimmerdige and Portland horizontals (although there are a few caveats).

But Xodus could be more cautious in a CPR than UKOG / HHDL might be in a planning application and if that information has been passed on to UKOG then they would have to take it into account in such predictions of production in an RNS.

As for 2021 when all the HH production wells have had their initial flows I would expect a decline in average production across the year.

But all opinion until the CPRs are released.

Tony,

the cores should be at the BGS (core store), as should any other cores or samples from UK wells (except they didn't core the Kimmeridge in Southampton -1 which is the geothermal well). The Kimmeridge is 445ft (136m) thick; in HH-1 about 1514ft true vertical thickness.

If you are really interested as it was a BGS well the Completion Report is available here:-

http://nora.nerc.ac.uk/id/eprint/514817/1/WAKB82003.pdf

Appendix F of the BGS Weald Study has 6 correlations of Weald wells and the fourth correlation (page 5 of the pdf) goes through Southampton-1.

https://www.ogauthority.co.uk/media/2771/bgs_decc_jurassicwealdshale_study_2014_appendix_f.pdf

This illustrates one problem - the 2 main limestones have been eroded at the edges of the basin (the 2 pale green stripes in the Kimmeridge in the Crockerhill well to the east at about 900metres, not in Southampton-1).

The same correlation has Lidsey-1 (not the recent well although that was drilled beside it) which has a condensed / eroded / faulted section - the limestones too thin to mark on the correlation.

Depending on where you live one of the correlations may include a well near your house - Hedge End -1 is near the Hampshire Cricket Ground - but not in a correlation.

The issue of maturity is always problematic as determining how deep the Kimmeridge has been buried in the Weald depends on a certain amount of guessing as to how much of the overburden has been eroded. This is addressed in the main body of the report.

Obviously I have too much time on my hands tonight...……...

SlowRoll,

Xodus stated this in the 2018 CPR (page

'However subsequent analysis and testing demonstrated that over the main zones of interest the well’s cement did not require any remedial treatment.'

Doesn't seem to match Alan's analysis.

Correction HH-1 will be sidetracked into the Kimmeridge.

PITW,

Erm,

don't understand your question - you're the one that suggested they also produce from the Portland to get to 650 bopd.

To do that they would need to install a new completion - production pipes down the well, packers, pumps etc to separately produce from the Portland and Kimmeridge and thus seperately monitor production.

But it would incur unnecessary costs and risk.

HH-1 is eventually going to be sidetracked horizontally and will only produce from the Portland in the future

PITW,

that assumes it's worth stopping production from the KL3/4, killing the well, removing the completion, installing a new completion that separately covers the 2/3 zones (and any associated risks) and then start up production again.

PITW,

To be clear the sole risk drilling and testing of HH-1 is covered by provisions in the farm out agreement and won't therefore be covered by the JOA sole risk provisions mentioned for further drilling and development.

The problem is that the sole riskdrilling and testing was agreed in the original farm in to the licence which was between Magellan and Angus and subsequently taken on by HHDL.

The farm in agreement has been mentioned although I cannot remember any mention being made regarding the revenues from oil produced during the drilling and testing oF HH-1.

However it would be counter intuitive if in bearing 100% of costs that HHDL wasn't entitled to 100% of the revenue.

A summary of the JOA in the recent change from investment to operating company document (about page 173) does indicate that Tellurian has 3 options regarding the HH development.

Not participate by selling their licence interest.

Participate in the development and upcoming wells, I would assume the farm in agreement would mean they do not have to pay back costs of the ewt.

Not participate in non obligation work programme but remain in the licence. If at a future date they wanted to back in to the development they would have to pay a 10 times uplift on an initial investment in the development (whatever that means). This provision also applies to drilling wells outside of the development. It's possible that HH1-2 is an obligation well but tbh I cba to look it up.

Argus,

interesting concept ' choked back minimum sustainable output.'

As surely a lower rate would be even more sustainable?

More likely to be a maximum or near maximum - testing the frontiers of flow rates as suggested in the OGA testing document:-

'Can KL3 and KL4 be commingled as one zone? If so, what is a sustainable flow rate?'

Tony,

they did include the shales - have a look at the Nutech and Schlumberger calculations.

Here's Schlumberger's (June 4, 2015) for OIP in mmbbls per sq km:-

U. Kimmeridge 21.1 (Shale)
Kimmeridgian Micrite1 4.4 (KL4)
M Kimmeridge 1 26.4 (Shale)
Kimmeridgian Micrite2 9.3 (KL3)
M. Kimmeridge 2 3.2 (Shale)
Kimmeridgian Micrite3 1.1 (KL2?)
L. Kimmeridge Clay 60.3 (Shale)

Whilst the OIP figure may be interesting what matters is the contacted oil and the fact that it seems that only oil in the fractures is currently being produced. What percentage of the OIP is in the fractures and therefore will contribute to the contacted oil is the number that will be taxing Xoduge.

As there has never been a figure for contacted oil in the Kimmeridge there have only ever been analogues quoted for recovery and they've been applied to the total OIP in various layers (or all of them).

Bladehater.

The Portland reservoir isn't a limestone and I don't remember there being a shale layer 'between' them.

Tony,

as there were no reserves previously reported for the Kimmeridge then they can't be increased. There were as you say guesses one of which was that each Kimmeridge well could recover 1mmbbls, but I don't believe that's in the planning application which inferred flow rates from the tanker movements.

Where are you getting this information from, I'd be careful repeating insider information or claiming unverifiable rumour as fact on this board.

Rodders,

This started because I said that nowhere in the RNS did they state the rates were steady state, nor the rates were constrained by pump or anything else.

I can stand by that statement because it is true.

As regards the pump it is clear that it can flow at least the initial 525 bopd in the configuration used in the 303 bopd sustained average rate and 351 hourly rate, with tweets regularly show it running at what appears to be the maximum rate of about 6 strokes per minute.

You have quoted a document that says steady state rates will be used for volumetric calculations, and that is a primary objective but presumably not the only objective, another in that document is:-

'Can KL3 and KL4 be commingled as one zone? If so, what is a sustainable flow rate?'

We might argue over the definition of sustainable but to me that's a rate that could be maintained for a while but not a significant time without decline, and it's used for the 303 bopd average rate achieved before the dewaxing. The 351 bopd rate post dewaxing is only described as an hourly rate - which is different again.

This constant chopping and changing of description in the flow rates in this RNS does not help.

Maybe we are posting at cross purposes. To me sustained means that the flow is controlled at a rate that isn't a maximum and is to all intents and purposes a production rate., ie it is not severely restricted to the extent you are envisaging, ie the rate isn't being constrained (meaning: severely restricted in scope, extent, or activity).

We also disagree on free flow to the extent that you say it will definitely happen and will be much higher than the pumped rates and I said are you sure, which is just pointing out that it may not happen and certainly hasn't been mentioned as happening.

As far as pumping and free flow is concerned In the 10 September RNS this was stated:-

'During these sustained flow periods, intermittent natural flow was evident, with metered rates at the separator exceeding the nominal pumped volume by up to 50 bopd'

That doesn't seem to have happened during the KL3/4 flows.

You will also see in that RNS they specifically state that rates were being restricted for a steady state flow test.