Member Info for xxnjr

Yes but I then mentioned "yes but the operator says the new wells will be drilled in locations supported by existing water injection wells" which elicited an extremely detailed and complicated response that I wont post here as it will only do our heads in with different scenarios. Anyway google gemini AI - it's free seems well informed. Will have another go in a few days with some targeting questioning.

I went on to ask the possible reason for the current program being heavily weighted to producers (5:1 in my Q)

The Implication of the 5:1 Producer-to-Injector Ratio. The new 6-well campaign is "heavily weighted" towards 5 producersand only1 water injector. This imbalance, after the struggles of the previous campaign, is highly telling and suggests a difficult choice was made:Strategy implication in a Mature FieldHigh Producer Ratio5:1 Focus on Immediate Cash Flow: The operator needs immediate volume and revenue to fund the campaign and manage debt. They are prioritizing near-term oil extraction over long-term pressure support.Low Injector Ratio 1:5 Pressure Management Risk: This is the highest technical risk. One injector cannot adequately support five new producers, especially in compartmentalized turbidites. The lack of robust pressure support will: 1. Accelerate the decline rate of the new producers. 2. Accelerate water/gas breakthrough in the new producers.This strategy is often a short-term fix that extracts valuable oil quickly but inevitably sets the field up for an even steeper decline later, as the water injection system will be under-pressured and the reservoir's energy quickly depleted.🌊 Why the Previous Decline Rate is IncreasingThe dramatic failure to sustain the gain is compounded by the permanent damage caused by the $\text{19-day}$ March/April shutdown:Pressure Depletion: The shutdown caused a permanent pressure drop (as discussed before), increasing the capillary forces that hold oil in the tiny rock pores. This means less oil will flow to any well (old or new), making the base decline rate even higher.Water Migration: The fluid rearrangement during the shutdown means the existing wells are now producing a higher Water Cut, accelerating their decline and requiring a higher gross volume to be produced just to get the same $\text{60K bopd}$ net oil.In short, the operator is in a difficult position: they must drill continually just to run in place, as the reservoir is resisting production due to its maturity, complexity, and recent operational setbacks.

Anton - if you will allow me to I'd like to address the concern you raised earlier today:-

The Impact of the March/April 2025 FPSO Shutdown

The drop from 75K bopd pre-shutdown to 61K bopd post-shutdown (a loss of approx 18.7%) is a significant and worrying symptom in a mature field.

1. Permanent Pressure Loss (The Biggest Risk)The Mechanism: When the FPSO (FPSO Kwame Nkrumah) shuts down for maintenance, production stops, and critically, water injection often has to stop or be severely restricted (xx comment w/inj was shut down).The Consequence: Stopping water injection for 19 days in a mature, deepwater reservoir is highly risky. The reservoir pressure in the producing zones can irreversibly drop due to the natural flow of fluids. Restarting the injectors doesn't always fully restore the pressure or the original fluid balance. This pressure loss leads to a permanent reduction in the field's production capability.

2. Reservoir Fluid SegregationDuring the extended static period of a shutdown, fluids within the complex turbidite channels can re-distribute.Water Migration: Water, being denser, can more easily slump or migrate into the lower-lying parts of the wellbore near the perforations, making the wells water-out faster once they are restarted. This is known as water coning or water encroachment during the static period.Gas Migration: Similarly, reservoir gas caps can expand or migrate, potentially causing early gas breakthrough when the wells are brought back online, which also chokes off oil production.

3. Wellbore and Equipment IssuesSand and Scale: Production stops allow solid particles, like sand or scale (mineral deposits), to settle out in the wellbore, flowlines, and manifolds. When the field is restarted, these blockages can restrict flow, permanently reducing the achievable rate until costly and time-consuming well interventions (like coiled tubing cleanouts) are performed.In summary, the drilling campaign confirmed the transient nature of the oil pockets in Jubilee's turbidite channels, and the major shutdown exposed the reservoir's extreme sensitivity to pressure management—a failure that is difficult, if not impossible, to fully reverse.

Well the above according to google gemini which I have to say seems very knowledgeable. If you are paying a sub for chatGPT I suggest you cancel it and use gemini as it's free (for now).

No need for that, as........ Nobody Cares!

End of discussion.

If you say so!

Having said that I agree with you that now is not the time for being conservative.

jmax - this would be a better bb if you refrained from constantly ******** (apols for language!) about other posters averages, name calling and mentions of 39p etc etc as...... nobody cares!

sometimes you make decent points and recite historical tlw facts that are useful. the other "stuff" is really just a waste of our and (maybe?) your time.

The 26FY guidance has a higher range (8K) than usual. Top end is 35K Oil. At this juncture suggests they are not exactly sure which way it will go. I don't necessarily believe Kosmos's UBER optimistic take but let's hope TLW are being conservative.

Based on Petrocom data looks like 2025FY OIL production will be kind of Jubilee 61.2K (23,856 net) TEN 16.1K (8,829 net). Throw in 700 bopd net for CDI gives total company FY OIL 33, 385 bopd. Slightly below bottom end of FY guidance.

That is a very good Q Anton. The gas processing capacity of the FPSO (250 mmscfd) is not the limiting factor at the moment as we can see total associated gas production is below that number. Having said that GOR went up after the shutdown meaning overall the wells started getting gassier for some reason (maybe declining reservoir pressure?) noting the increased GOR was already evident before they introduced gas lift on some wells. The simplistic, non-expert answer, is the current well stock capacity is insufficient to deliver more than say 62K bopd. They have mentioned increased water cut in some wells. They have mentioned JSE wells and eastern wells under performing and having to utilise gas lift. It's concerning the additional 10K has already been neutered by decline elsewhere and/or in the new well. The field has been in production for about 15 yrs now. This sort of stuff is normal in mature fields as reservoir pressure declines. I still feel (with a bit of luck) there's at least a possibility things may start turning around after the 3rd comes on but based on evidence of first well looks like it could be an up hill battle to mitigate decline.

OK Anton - It was nagging me - the webcast actually said BOPD!

Not point emailing KOS IR as in my experience they don't reply.

If I have time later this evening I may revisit KOS webcast.

Anton,

Ah! thanks for that. It's not exactly clear now as further on in the same report you've linked to, KOS say "..... The first producer well of the 2025/26 Jubilee drilling campaign came online in July and initial production levels have been encouraging, averaging ~10,000 boepd through the first three months."

So there's a typo in there somewhere.

Ah! Hadn't noticed that Jmax. The KOS 10K was indeed boepd. Over the entire field oil is 62% of boepd. 10K boepd becomes 6,200 bopd. But you'd anticipate a new well would have lower GOR than field average. Would have been helpful if KOS had told us the oil number.

You are not wrong Tman75.

Rhd3 - Thanks for mentioning new Petrocom Data published....."The gas figure looks quite high though." It's not too bad. At least they have managed to contain the GOR at slightly higher levels than June. We started the yr at 2,672 scf/bbl with GOR rising strongly month by month to elevated levels in June (3,594 scf/bbl). New well came on end of July (3,768 scf/bbl ) with Aug/Sept/Oct scf/bbl 3,693/3,766/3,733 so GOR has been contained. Using the formula FPSO = Gas[mmscfd] /GOR[scf/bbl]

the maximum FPSO output at latest Oct GOR would be 250,000/3,700 = 67,568, or 65,500 bopd with 97% uptime. To get above 65K bopd the GOR would need to start coming down. If GOR got back to 3,500 scf/bbl production could theoretically increase to 71,500, or 69,355 bopd 97% uptime assuming the well stock could deliver at those rates. So maybe we need a couple more wells to see if they can reverse GOR and get production up to say 69K bopd by end of 1Q?

MavD is a day, or short term trader. Nothing wrong in that. All credit to anyone who can succeed in that way.

He's only been there 3 yrs. https://www.tullowoil.com/application/files/8916/8501/7419/Tullow_Oil_plc_-_Result_of_2023_AGM.pdf

And his support has steadily declined each yr! https://www.tullowoil.com/application/files/8817/1587/0092/240516_-_RESULT_OF_AGM_announcement_-_Final.pdf

So we have (i) the least supported director in the AGM vote (ii) but the only director to put his hand in his pocket in a significant way..... gaining more power. So what lead to this decision? Support in him as measured by AGM voting results? or his buying of shares? Will be interesting to see what the eventual end game here is!

Interesting move to put more power to influence in the hands of RG given he appears to be Tullow's least trusted director as measured by the last AGM voting results!

https://www.tullowoil.com/application/files/3717/4792/0330/250522_Result_of_AGM_announcement.pdf

In Tullow's case the money evaporated into a series of black holes that failed to find any oil. Whether or not an extinction event ensues remains to be seen.