@Kit67Hey Kit, as of October 2023, which I believe is the last...

@Kit67
Hey Kit, as of October 2023, which I believe is the last known full update on "The Plan" they will be licking a few swollen testicles over what appears to be "a slight technical issue" as Houston would typically call it...

Noting the claim that all 3 reservoirs flowed oil to surface in Alameda-1, so it was there then, but that a "New Type" play would be introduced to Alameda-3. The result of which was evident for all to see at 11.30 on the morning of the discovery..... Doh!





Alameda-1 & then Alameda-2 proved up the prospect of the upper sheet and hence development planning for that is still underway, or at least one would think it should be, all other scenarios considered. Alameda-3 failed to achieve its full objective however we were told of successful core sampling being taken and will be able to draw some conclusions from the extrapolation of the contaminated oil sample data results, but overall it didn't achieve the full objective which was to commercially prove the previous discovery & hence will need to do so before anything changes there. Whether that is a rectification works program on the existing well or a new targeted campaign, time will tell. ?



Forward plans focus mainly on the upper sheet & are not on Alameda 3 data and henceforth field development plans aiming at 5k barrels per day are very much still in focus.


What they didn't achieve was fully proving up the potential commerciality of the 179mmbl resource. That doesn't mean it's a duster, but it does mean MacD's aren't going to budge any time soon on an upgrade so lets forget about it for now & focus on the upper sheet play. Interestingly it does say that they "optimized" the drilling program to enable "the valuable information" about both reservoirs.. Having been around the traps as have others no doubt, the term optimization is either in reference to money or reliability and generally one is at the cost of the other so I wonder if they've got a little cute and tried to do too much with 1 well? Gut seems to say considering the hikes in mud weight, lost bit, side track & slow drilling that it may well be the case, but again time will tell. gltah h8tey




p.s. I'm no expert and don't claim to be with downhole engineering concepts but considering the outcome I'd be willing to hypothesize that the bean counters have won the battle which then lost the war? It may be a case of asking too much from a single well, especially when considering what happened in Alameda-1, along with the claim of oil flowing previously?

Meta AI
In a highly fractured folded carbonate reservoir, the pressure gradient would likely be complex and variable, reflecting the heterogeneous nature of the rock properties and fluid distribution. Here's a hypothetical scenario:

High pressure gradient: Near the surface, the pressure gradient might be relatively high (~0.5-1.0 psi/ft) due to the weight of the overlying rock and the presence of fractures and faults.

Decreasing pressure gradient: As you drill deeper into the reservoir, the pressure gradient might decrease (~0.2-0.5 psi/ft) as the fractures and faults become more extensive, allowing for greater fluid mobility and pressure dissipation.

Pressure anomalies: Localized pressure anomalies might occur due to the presence of high-permeability fractures, caves, or vugs, which could lead to pressure drops or increases over short intervals.

Variable pressure gradients: The pressure gradient might vary significantly over short distances, reflecting changes in rock properties, fracture density, and fluid saturation.

Abnormal pressure zones: Isolated zones with significantly higher or lower pressure gradients might be encountered, indicating compartmentalization or fluid segregation within the reservoir.

Keep in mind that this is a simplified representation, and the actual pressure gradient would depend on various factors, including the specific geology, fluid properties, and drilling conditions.

Stacked reservoirs add another layer of complexity! With stacked reservoirs, the pressure gradient becomes even more dynamic and challenging to predict. Here's an updated appreciation:
Multiple pressure regimes: Each reservoir may have its own distinct pressure regime, potentially with different pressure gradients, reflecting varying rock properties, fluid saturations, and connectivity.

Pressure communication: The stacked reservoirs may be in pressure communication, allowing fluids to move between them, which can impact the pressure gradient across the entire system.

Pressure gradient variations: The pressure gradient may vary significantly between reservoirs, and even within each reservoir, due to differences in rock properties, fracture density, and fluid saturation.

Depth-dependent pressure gradients: At greater depths, like 3916m MD (corresponding to 980 on the top scale axis), the pressure gradient may be more pronounced due to the increased weight of overlying rock and potentially higher fluid densities.

Non-linear pressure profiles: The pressure profile may become non-linear, with abrupt changes in pressure gradient at the interfaces between reservoirs or within individual reservoirs, due to variations in rock properties and fluid saturation.

Increased uncertainty: The stacked reservoir scenario introduces additional uncertainty, making it more challenging to predict pressure gradients and fluid behavior, especially at depth.

By considering these factors, you can better appreciate the complex pressure gradient behavior in stacked reservoirs, like the one you described.



As for how long would it take to pot holes in the upper sheet? All depends on suitable rig availability and that has been a consideration so multiple drilling fronts are possible.