Member Info for Jimmy23

TTT,
Excellent question.
We will need to drill to find out.
There are a number of possible outcomes.
Let’s start with what we know.
1. The lower sands in mou 1 are over pressurised and have high porosity and permeability. These sands are interpreted to be the end of fan deposition, so it should be thicker nearer its source of deposition.
2. The 2 d seismic shows that the reservoirs are connected between mou 1 and mou 2 ( previously named mou4).
3. The 2 d seismic shows that the mou 2 well is to drilled into a four way dip anticline, but outside of this four way anticline and above the mou 2 top seal there is evidence of a seismic gas cloud, which may indicate top seal failure at some point in the past. ( note there is a small fault to west of mou 2 location and it maybe less risky to drill on west of that fault, is this the reason for not declaring the final mou 2 well location).
4. The seismic Avo analysis indicates that there is an almost continuous gas indication from mou 1 to mou 2. In the past this has been a reliable gas indicator in the rharb basin.
5. We know the based was subject to uplift on at least two occasions.
6. We know that top seals at anchois 1 and 2 can be very thin and very effective.
7. As far as we know there is not a sealing fault between mou 1 and 2 and hence there is a good chance mou 2 is also overpressurised if the reservoirs at mou 1 connect to mou 2.

So what’s the outcome going to be , three principal possibilities
A. Mou 2 is drilled into the four way dip anticline and finds and flows gas, if the reservoir pressures can be correlated to mou 1 then it’s improves the likelihood that the gas reservoirs are connected.
B. If the gas pressures cannot be correlated between the wells then there may be two separate gas accumulations with different gas water contacts and probably a sealing fault between the reservoirs. If a gas water contact is established in mou 2 then that allows the gas in place calculations to be performed .
C. Mou 2 is drilled into the four way dip anticline and establishes a gas water contact in the structural spill point which indicates that the stratigraphic trap between mou 1 and 2 is not full of gas but two separate accumulations and that there then must be a fault or reservoir pinch out of gas between mou 1 and 2.
D. Mou 2 drills and finds gas but does not find the gas water contact and the reservoir pressures can be correlated to mou1, then upside case is still on.

I based my investment decision on mou 2 being drilled into the four way dip anticline and finding gas only in that structure with no upside. Enough to generate a sizeable cng net revenue quickly.

Jimmy

Hi vegas,
We do now that the lower sand at mou 1 had excellent porosity and permeability and the reservoir pressure was overpressurized which resulted in the well not being flow tested at the time it was drilled. So it’s likely to substantially exceed the average flow rate per meter in rharb basin. My calculations have not taken these enhanced features into account,so it’s upside . We should have enough gas to generate substantial cng revenues.
Jimmy

Vegas,
There are calculations that can be done to determine flow rate from well data, the key factor which investors do not have is the reservoir pressure for each horizon, so in the absence of such information it’s better to use a comparison to flow rates from similar geology as an interim assessment.
Jimmy

I am invested here because I believe there is a reasonably high chance that predator will achieve a combined flow rate of 20 to 26 mmmcf per day from mou 1 and 2.
So let’s start with what we know.
1. 22 meters of audited net gas pay at mou 1.
2. The average flow rate in the rharb basin from 17 wells works out at 6 mmcf per 10 meters, which gives an implied flow rate for mou 1 of 13 mmcf per day.
3. The average success rate in the rharb basin , which is a continuation of predators acreage, is 85%
4. The independent competent persons report attributed 393 bcf of contingent resources to the mou fan prospect.
5. Predator are forecast 168 meters of gross pay reservoir at mou2 . It is understood they are expecting circa 100 meters of net pay, similar to the anchois 2 net to gross ratio. However let’s assume they just get a repeat of mou1 at 22 metrers of net pay.
6. The implied flow rate is 26 mmcf per day, with upside if more gas reservoir is proven in mou2.
7. Predator reported in its September presentation that 26 mmcf per day for cng production would yield approx $86 million per year net to predator.
8. Predator report that gas sales and production equipment leasing contracts are ready for signing subject to a successful flow rate.

Predator are funded for the drilling which is to commence by mid December.

It all comes down to the flow rates and just got to wait and see.
Jimmy

I too am a little confused by the next well location.
However, will it drill into the four way dip anticline and also test the deep fan reservoir to confirm connectivity with mou 1 and determine where the gas water contact is.?
J

Another milestone.
https://www.rolls-royce.com/media/press-releases/2022/28-11-2022-rr-and-easyjet-set-new-aviation-world-first-with-successful-hydrogen-engine-run.aspx
Jimmy

Thanks billy,
Yes I could not see the decimal point after 12. Mmcf per day.
So the base case for mou 1 and 2 is circa 25 mmcf per day, which is clearly economical for cng, with the possibility of extra flow rates if additional net pay is proven.
Jimmy

Billy ray,
Thank you for posting the analysis of flow rates per meter in the rharb basin at.
https://www.reddit.com/r/PredatorOilandGasPRD/comments/t8ssg0/mou1_the_rharb_basin_net_pay_vs_well_flow_rate/

I was truly trying to work out how predator management were suggesting flow rates 150 to 250 mmcf per day from mou 1 and 2.
The analysis includes a regression analysis of 17 wells in the rharb basin that correlates flow rates to net pay reservoir.
The regression analysis graph shows that a 20 meter of net pay would produce an average of 120 mmcf per day. So for two wells x2 = 240 mmcf per day.
Obviously got to drill to confirm and flow test, but that’s the logic.
Jimmy

Hi Larry,
I am assuming the capex has increased to $500 million, for one extra well, two drilled previously, water depth 400 m, distance to shore 40km , planned production 105 mmcf per day so still a bit smaller than casiopea.
Jimmy

I am invested in predator because I believe it will achieve the minimum gas volumes for cng production.
My caution relates to the lack of 3D seismic which creates a higher risk when choosing a well location based on 2D seismic.
This is journey we are on.
Jimmy

Ps the price of gas in Egypt is currently about $2.50 mcf so very different economics than if you can export via a nearby pipeline to Europe at $20 mcf.
Jimmy

https://newatlas.com/energy/light-catalyst-ammonia-rice/
Jimmy

Eng mick,
The fields you referenced were all going to be developed for Lng production whereas chariot Morocco anchois field is being developed to tie into a nearby pipeline.
We don’t know the gas sales prices at this time, but if 50% is exported and 50% is for the local market resulting in an average price of $14 mcf then I would expect payback to be in 2 or 3 years for a field that will have a life of 17 years.
That’s my assessment. I would like to understand your estimate of $1 billlion capex.
Jimmy

Engmech
Can’t see where you are getting your numbers , have you read the chariot presentation.
J

Foot and mouth,
I believe your formulation does not include gas trap as a consideration and top seal integrity to keep the gas in place. This basin has been inverted twice so this is really important.
Now we know from anchois 2 that thin top seals can act as a good top seal , which if confirmed at mou2 will help support the upside case. The basin inversion could have caused the gas in place to expand during basin inversion and escape out at the spill points, so the gas is still in place, an alternative explanation is that the top seal failed to the east of the proposed mou 2 well and the gas escaped from the stratigraphic trap between mou 1 and 2 .
Got to drill to find out, or do you have other information that would explain the gas cloud in the seismic.
Jimmy

Hi wizzard.
Good article from the Ft.
From a chariot perspective, it’s gas price competitor is lng and the article concludes that as soon as China economy restarts after covid 19 lockdowns that it will import a lot more, keeping lng prices higher for longer and hence gas prices for longer.
Morocco is currently buying gas from lng in Spain at $32 mcf and chariot gas will replace such imports. So a good price can be negotiated, particularly good opportunity as chariots average price for npv valuations was only $10 mcf, which at 100 mmcf per day generates $1.2 million gross revenue for the field per day.
Jimmy

Hi mite,
I too get tired of some the drivel and infighting on this board.
Chariot usually give an update before year end and I expect substantial progress to be reported by that date.
If the leaked notes of a meeting in Morocco are to be believed then the principal terms of the gas sales agreement will be agreed by then, everything else flows from that.
Looking good.
Jimmy

Surfit,
The recent interview by Ap included a comment that Soc Gen have made great progress on the debt financing and the consortia will be both local moroccon and international banks. It’s all good, and subject to the gas sales agreements.
Jimmy

MEM,
The I tcf target is the best case outcome , it’s not probable as des ribbed by the cpr.
It will require a gas filled reservoir between mou 1 and 2 and we do not have that evidence to prove it, yet.
I agree that mou 3 could be a production well and possibly go deeper to prove the deeper gas between mou 1 and mou2
Jimmy

According to the Oort energy website they have proprietary Ip for low cost high efficiency electroylsers and have demonstrated this on a small scale basis. They are now building a large scale pilot plant to demonstrate efficiencies and lower cost at scale. In addition they have just hired a chief commercial officer.
So it’s well worth chariot collaborating with them to get access to new transformative technology when it’s available.
Jimmy