Member Info for Jimmy23

Game changer for storage of hydrogen at.

https://www.nature.com/articles/s41557-024-01443-x

Jimmy

Hi thebold,

I understand that chariot have identified a secondary target in the forthcoming well, which I am assuming is the deeper 300 meter reservoir found in lnb1 well.

I believe the main target is an anchois aged reservoir which was reported previously by SDX to be at 10.5 meters thick and to be widespread in the onshore Loukas 3D seismic area .

My understanding is that this reservoir has the same seismic attributes as anchois and is updip from a well which found gas, same concept as when anchois 2 was drilled.

We need an update from chariot if they are to target the deeper 300 meter reservoir , which may in turn, if successful de risk the offshore rissana licence where the prospect sizes are huge.

Jimmy

The key to the high drilling success rate at anchois is a combination of drilling up dip from proven gas reservoirs that have been logged and processing the seismic to identify where the proven gas can be identified on the seismic and then mapped as to where it’s located away from the well, by way of AVO analysis.

In the basin this has a success rate of about 80 to 85%.

Got to drill to prove, but this approach works very well in this geology.

Jimmy

Nigel,

If prd find a substantial resource, it’s likely to be a phased development, first to generate early cashflow by cng, followed by gas to power via the nearby pipeline.

It took chariot about 18 months to complete its environmental impact study for both offshore and onshore, so I think prd could do it in 12 months, followed by construction of cng, facilities in about 6 months and a further 6 months for gas processing facilities for pipeline gas.

If pressure communication between wells can be demonstrated then an exploitation licence can be applied for, in not then either more drilling or seismic or both.

Jimmy

Hi the old..

My understanding of the difference between the whole sale price is a daily market price and the retail price includes profit mark up and the cost of hedging when prices were considerably higher.

J

One possible explanation for the drop in share price has been the fallin the forward price of gas in Spain, from where morroco currently imports its gas. The forward price for 2025 is approximately $9 mcf, down from about $12.

However, the drop in gas price can more than adequately be compensated for by an increase in production volumes, from 105 mmcf per day to circa 200 mmcf per day.

The most recent presentation from chariot stated it was intended to have three producer wells, and that the last anchois 2 well has been calculated to produce from 100 to 200 mmcf per day, so producing 200 mmcf per day from three wells, excluding the new O sand reservoirs is very doable.

Chariot just need to get on with announcing progress on these projects.

Jimmy

Hob.

My optimistic calculation for the jurrasic prospect is slightly over 1 tcf gross.

The itr notes that seismic coverage is not high density and hence there is uncertainty as to what areas of the jurrasic will have high porosity. The itr has an overall optimistic area of 177 km2 of which 55 km2 is forecast to have high porosity by both leaching and fracture porosity, the area outside this is expected to have lower porosity. It’s a combination of reservoir thickness and porosity which have high impact on recoverable reserves.

.

My calculations are as follows.

1. Area 55km2, reservoir thickness optimistic case 50. Meters, porosity 15% , recovery factor optimistic 65% gas charge70% , gas expansion factor 116, due to shallow depth= 768 bcf.

2. Area 122km2. Reservoir thickness optimistic 50 meters, porosity 10% , recovery 40% , gas expansion 116 = 349 bcf.

If the reservoir thickness drops to 20 meters then total recoverable gas drops to 446 bcf.

A long way from 7tcf, but still great fr shareholders.

Jimmy

In the wacky calculation of jurrasic ne potential. I don’t see the the gas saturation , the recovery factor or the formation volume calculation.

In addition the 50 meters is not likely to be the average reservoir thickness through out the 177 km area.

The ITR shows a two areas, one of high porosity and the other lower porosity .

Perhaps it’s more reliable to just look at the ITR P10 volumes.

Jimmy

Brv,

I like the jurrasic prospect for the following reasons,

1, mou 4 well found 2 meters of high porosity and high gas saturation carbonate reservoirs.

2. The mou 4 well was at the bottom of a large, up to 177km prospect making it likely there is gas up dip.

3. The jurrasic carbonates are at a particularly shallow horizon which increases the likelihood of leeching porosity.

4. The basin has undergone two periods of inversion and compression since the jurrasic reservoir was deposited, and since the prospect is mostly in a anticline against a fault , there is likely to be fracture porosity in the carbonates.

All very good and worthwhile drilling.

However,

The reservoir that’s proven to date is 2 meters and the ITR suggests it will thicken updip to 18 to 20 meters, on which the prospective resources are based. In addition, the area does not have 3D so it make require a lot of infill drilling to prove lateral continuity of high porosity and permeability zones.

The ITR does not indicate reservoir thickness of hundreds of meters which would be required to achieve the high tcf volumes suggested by some here. Perhaps I am missing some information in that regard and would appreciate if others could post the relevant information to support the very thick reservoirhypothesis.

Jimmy

The ITR is a very usefull update and I identify something interesting each time I read it.

The great success of the recent drilling has been the confirmation of 50.5 meters of mou fan reservoir in mou 3 which are gas bearing.

To the east of mou 3 is a long elongated and curving fault as shown in figure 19 of the ITR. NOTE , how the contours , like a an ordnance survey map, cross the fault without displacement which indicates that the same reservoir is juxtaposed against the equivalent reservoir on the other side of the fault, this is known as a slip fault, and over geological time will allow gas to migrate across that fault.

Mou fan in mou 2 is mapped in figure 19 as updip of mou3 so it’s highly likely to be gas bearing.

The question arises then as to how much mou fan reservoir will be encountered in mou 2 when it’s completed. Fortunately, figure 20 shows an isopach map , which is the gross thickness of the mou fan which shows that the mou fan in mou 3 had a gross thickness of 105 meters and we know from the mou 3 rns that 50.5 meters of mou fan was identified in that block, which is a 48% net to gross reservoir thickness. The figure 20 isopac for mou 2 shows a gross mou fan thickness of 130 meters which if it has the same net to gross ratio would be expecting 62 meters of net reservoir.

Since the drilling mud problem has now been resolved, it would take 2 or 3 days to complete the well which would prove up a substantial area of gas. They should consider doing that as part of the mou 5 drilling campaign as it’s very low risk and cost.

Jimmy

Keith, thanks again for your comments, which I have been considering.

So if the shallow 50 meters of reservoir in mou 4 are in fact the newly designated A sand also found in mou 3, then why not test them in mou 4 before redrilling mou 3 follow on wells.

Puzzled.

J

Thanks Keith.

It’s certainly confusing when the rns announced 50 meters of shallow gas in mou 4, which is now not detailed in the Itr and is now classified as higher risk. Perhaps it did not pass the nuetech test.

Jimmy

Ok, I found it in the rns described as mou 4 shallow sands, but did not see it referenced in the ITR.

Jimmy

The rns announcing the results of mou 4 stated.

519 to 713 metres TVD MD, including the M1 sands.

50 metres of likely gas sands.

I don’t see such reservoir as being tested in the forthcoming flow test program. Can any one explain , Keith perhaps.

Thanks

Jimmy

James,

In calculating market cap you need to consider that prd have 75% of what’s found so to get to a $15 b market cap you need 20tcf of proven gas .

I just cannot see that.

1 to 3tcf would still be beyond most analysts expectations in a most optimistic scenario.

Still a 1 tcf reserve is a possibility , but it starts with flow testing shortly

Jimmy

Predator published npv values for cng and gas to power are reported at $4.89 per bcf and $1.99 million per bcf for gas to power.

See. Page 6 at

https://wp-predatoroilandgas-2020.s3.eu-west-2.amazonaws.com/media/2023/05/Proactive-Presentation-18-May-2023-FINAL.pdf

Obviously all dependant on flow rates and then I would discount by a further50% for execution risk.

Jimmy

My,

The onshore acreage adjacent to offshore licence became available with the same geology and a 3 d seismic data set that’s identified gas prospects up dip from proven gas and with seismic signature of gas, Avo, same as offshore area which was demonstrated in anchois 2 well.

The success rate onshore is 80 to 85% and it’s close to end user markets and a pipeline, so pathway to early cashflow.

The onshore 3 d seismic has identified a 10.5 meter reservoir, which if proven will produce circa 21 mmcf per day, which will fund chariot opex till anchois goes into production offshore.

I am invested in both chariot and predator.

Jimmy

H bob.

My answer is consistant with GRH comments on common pressure gradient between stated wells.

Developing the point further and in line with the Itr depth map it effectively derisks mou 2 area .

Jimmy

Regarding GRH comments about pressure communication between mou 1 and grf 1 wells in the mou fan, it’s also illustrated in figure 19 of the ITR which shows the fault between mou 1 and grf 1 as being a slip fault so there is sand to sand communication. However, the upside around grf 1 is limited by a stratagraphic pinch out of the reservoir a short distance from grf1.

However, the same map is wort noting the slip fault to the east of mou 3 which shows reservoir to reservoir communication across the fault to mou 2 well location which derisks that area.

Further more, the wells illustrated in the Itr show that both mou 3 and mou 4 drillled through the slump above the mou fan , where mou 2 stopped drilling. So it looks like they solved that drilling problem and could complete mou 2 without the problem.

Jimmy

Lancy,

The taf 1 well had very poor porosity.

Much that I would like a very thick jurrasic reservoir, the facts remain that mou 4 found only 2 meters of reservoir and that the independent technical report indicated 18 to 20 meters of jurrasic reservoir .

Jimmy