IVZ - General Discussion, page-1470

## Re-posted below for easier reading due to funky formatting in last post - too many words, too many images. You can reference figures in last post.

Hey Butcher – this is a good post playing devil’sadvocate – asking the right questions. This is the type of discussion we need -breaking things down and not continually perpetuating confirmation bias.However, I think many are being affected by recency bias atm – that is theshare price has been smashed recently and a lot of holders are seeing this ashow things will remain and that it means the stock is fundamentally flawed. Itis not.

I’ll hit on your main points first and then hit upyour sub-points. (Apologies if this is rough, I’m just going to machine guntype this. You folks not in subsurface might have to google some terms I usehere, I’ll try to add detail where I remember. This might also need to bespread across multiple posts).

1. Poor reservoir quality and low permeability inUpper and Lower Angwa at Mukuyu

Ok – let me start with Mobilstudy and circle back. They had rock samples from the Upper Angwa where itoutcrops at surface in the basin. They did porosity and permeability (‘poroperm’)testing on these. Now I’m assuming the samples were tested at ambientconditions, not an assumed overburden pressure (basically the rocks were testedat surface pressures so the poro and perm measurements will be higher than atsubsurface pressures – with a km of rock lying on top of them). So the resultswould be optimistic but still indicative* (I’ve asterixed this because I’llhave further detail for anyone who can be f**ked reading at base of post).

The poroperm values got up to~20% and permeabilites up to 1.2 darcies (1200md) [see figures 1 & 2 below].

I’m definitely not saying they’llbe these values at Mukuyu reservoir depth, but given the porosities encounteredin M-2 (of which Scott has clearly mentioned the UA quality at the Mukuyu-2location was poorer than M-1, and whose to say M-1 is the best example in thefield – that may not have even been in a channel proper – 3D seismic is the wayforward on that one), in my experience I’d say a permeability average of 20mdto 200md would be fair to assume. Lets go more conservative and say the perm wehave for M-2 averages between 20md and 100md. I’ve seen plenty of gas fieldsget good flows for these sort of permeability levels, and I’ll throw someexamples out when I answer your point 3.

The other point to note is theMobil work interpreted the UA system as having some braided systems present (aswell as meandering). If this is accurate, and holds to the Mukuyu location,braided systems are generally more laterally extensive, thicker and higher NTG thanmeandering systems (google braided vs meandering, or ask ChatGPT, maybe she canspit out something decent). It may be the case that in M-1 & M-2 we’ve hitmeander prone areas (and overbank equivalent to the braided stratigraphiclevels), and missed the better sands. Translation: we may have hit the poorerstuff with our wells relative to what’s present elsewhere in structure. You’veput 2 pinpricks in a 200km2 structure (4 including ST but they hardly countspatially), it’s not statistically plausible to think we’ve hit the best stuff anduntil we get 3D seismic, we’re not going to know better. But I still think whatwe’ve already hit is producible, and again I’ll go into more detail on dot point3.

Figure 1:

Fig. 2:

I’ll just also note here – we don’thave porosity info for the overpressured lower angwa sands (no quad combocoverage hence no porosity interp). When SM says these are looking betterquality (I’m assuming they had LWD GR & Resistivity cover them so that willgive an indication of quality), I definitely believe that. I’m going to soundlike a broken record but overpressure is fantastic for maintaining higherporosity than normally-pressured reservoir as the rocks are buried.

I’m not going to bother goingfurther into all the ways that what is currently called non-net may shift intonet pay in the future for Mukuyu-2. It just wouldn’t surprise me if we get somedecent surprise flow contributions in the flow test, especially if they try toisolate multiple zones, including those currently classed as non-net to seewhat they can get out of them.

To circle back around, let’s carryforward an assumption 20 to 100md permeability for Mukuyu-2. For gas thisworks, I wouldn’t be sh*tting the bed over this, but we’ll come back to it.

2. Significant downgrade to prospectiverecoverable resources in the Mukuyu structure due to net pay well belowpre-drill estimates

I think I’ve already partiallyaddressed this in the above. Porosity cut-offs in basins I’ve worked FOR CONVENTIONALS (at a supermajor) have been as low as 4% porosity. I don’t think they’ve gone this low of a cut-off here. Nonetheless, there could be a heap of rock currently sitting under the porosity cut-off by 1% maybe 0.5%. You either have evidence to support lowering your porosity cut-off (if you prove a given section can flow at this porosity), or your core calibration tells you your petrophysics/log-based porosity is too conservative and you adjust your porosity interp up, you suddenly potentially have a sh*tload of non-net suddenly become net.

And that’s not to mention thatwhen you deepen this well with the 6” into the overpressured lower angwa that’syour low-hanging fruit for adding more net to this well.

As for the section above the UA(Pebbly, Dande, etc.), yeah you only have residual hc at the M-2 location, butI’ve seen it a bunch of times before – you don’t have hydrocarbons at onelocation in a given unit, and then you do somewhere else in the field – easily doneif there’s valid structural or stratigraphic controlled. It is positive therewere residual hc’s in the Pebbly (& high gas chromotograph readings in theshallower units), it means hydrocarbons have migrated through those units, andif there are any suitable trapping locations you’ll have hydrocarbons present. The3D will definitely help with this – in a)identifying valid structural trap thatcan’t be broken out on 2D, and amplitudes will help with identifying poss. Strattraps or DHI constraint/ extent (watch out for fizz gas though). Also, if thesupra-UA doesn’t have hydrocarbons, based on what I believe are conservativenet pay figures released, you already have multi-Tcf in that alone (from my back-of-the-envelopecalcs).

3. Low flow rates in the upcoming flow test atMK-2

Define low flow rates? For gas? 10MMscf/d?20MMscf/d? 5MMScf/d? (rhetorical question)

If you need more deliverability,you just drill another well. You are onshore, this is relatively cheapdrilling. Especially when the basin gets going. Personally I think 10MMScf/dmay be fine, but I think we’ll get more.

So, let’s quickly look at fewrelatively low perm fields and their flows.

Let’s use Perth Basin seeing asthat’s been referred to a lot. Specific flow test: Waitsia-4. This well had anestimated average perm of 55md for the tested section. It flowed 89MMScf/d.I think that’s probably enough for us. A disclaimer here is that it had aslightly larger net interval (so theoretically a greater kh), but I’d arguethat we’re going to have more contributing than the stated net pay numbers forM-2 (LA not covered by quad combo, UA under current net pay cut-off but thatwill contribute, possibility of barefoot flow of 6” section). If we could get aportion of 89MMscf/d I’d be happy. It just goes to show what you can do with relativelylow perm reservoir. Flow test screengrabs below (Fig 3 & 4), most of theWaitsia wells are open file so you can grab the completion reports, flow testreports if you want.

Fig 3

Fig 4:

Another PNG field, Hides,currently producing averages about 40 to 60md perm and flows very well (can’tprovide flow rates that are publicly available – but they are very competitive).Hides is a significant producer for the PNG LNG project.

Where I see reductions in flowrate compared to what Mukuyu could otherwise get – is if it has high CGR and issubject to retrograde condensation / dropout. Dropout can negatively affectflow rates. But you will still flow, and you still get liquids to sell. If thisis the case, there are ways to manage keeping reservoir above the dewpoint andIVZ can explore strategies to maximise recovery. You never 100% pull out allhydrocarbons from a reservoir in any case – that’s why we have recoveryfactors.

Again, even if it is subject todrop out, the well will still flow. So either, you have high CGR (a lot of condensate),and so you will have liquids to sell, but you may have a lower flow rate; oryou have low CGR (little condensate), and you will maximise your gas flow rate. There’s pro’s and cons to everything.

4. Low CGR and minimal liquids content

See above. But Scott has already said they think this is a wet gasdiscovery. They had a lot of heavier ends on the gas chromo readings. They hadheavy C’s on fluid analyser. If in the unlikely case it’s a low CGR, then you’reprobably going to get better flow rates. So again, pros and cons to everything (‘itdepends’ is often the best answer in subsurface).