Whence the pressure in oil wells?

Factual Questions
1

The troublesome oil well in the Gulf of Mexico is reported to have a static pressure differential, at the sea-floor wellhead, of somewhere around 9,000 psi. My dad recently asked if this is for real or if people are just making up numbers, so I did a simple hydrostatic analysis, and came up with this:

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In the worst case, the static pressure at the sea-floor wellhead could be as high as 10,000 psi. If a pipe is connected from the sea-floor wellhead to the rig on the surface of the ocean, the static pressure at sea level could be as high as 8,500 psi.

Assumptions:

-Ocean depth, 5000 feet. Well depth, 18,000 feet below sea surface level.

-The earth between the sea floor and the oil formation is composed of granite, with a specific gravity of 2.7. Actual specific gravity could be higher or lower, depending on the composition (granite, basalt, clay/silt, organic mud, etc.).

-The oil in the formation is light crude, with a specific gravity of 0.85. Heavy crude has a specific gravity of around 0.95, and would result in a correspondingly lower absolute pressure at the sea-floor wellhead.

-At the length scales involved, the mechanical properties of the rock may be disregarded, and the rock treated as a fluid (i.e. pressure at the bottom is proportional to height and density). If the surrounding rock is somehow bearing a significant bending/shearing load imposed by the surrounding crust, this could result in different pressure in the formation.

-No effects due to dissolution of methane during ascent from the formation. If a significant amount of methane comes out of solution in the well pipe, the density of the fluid column in the pipe decreases, and greater pressure will be communicated from the formation to the sea-floor wellhead, up to a maximum of 17,500 psi.
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OK, so my 10,000 psi matches pretty closely with the 8-9000 psi being reported on the evening news. But…did I just get lucky? What is the actual mechanism that produces pressure in subterranean oil formations? Note that eventually - after they’ve removed enough oil from the formation - the pressure tends to drop, and they have to resort to things like water injection to get the well to continue producing. So maybe the hydrostatic pressure from the overburden is not the cause of the formation’s pressure?

Is it the dissolved methane trying to come out of solution that’s causing such high pressures?

Petroleum engineers, help me understand…

2

I am completely non-expert in this area, but I suspect just using the weight of the granite isn’t directly relevant; if the granite has structure it may tend to support itself. If you’re in a cave you obviously don’t feel the weigth of the earth/rocks above you.

3

I think the OP analysis is correct, depending on exactly how much structural support the rock above the deposit gives. I think that oil deposits can cover larger areas than caves do, because the oil is supporting what is above.

4

The rock is actually self-supporting for the most part. The typical way to calculate reservoir pressure in a normal pressure reservoir is based off of the fluid column. In the Gulf of Mexico the native fluid typically has a specific gravity of about 1.08 which works out to about 0.468 psi/ft so for the given reservoir we would be at 10764 psi. This would be considered a normally pressured reservoir.

The basics of how reservoirs are created in a sedimentary basin is that alternating layers of sand and silt flow into the basin from a river and based on the current water level fall out in different spots. As water level changes this causes layering of sand and silt. As more layers are deposited these layers are buried under more and more dirt the pressure from which turns the dirt into rock. The silt turns into shale which has a very low permeability but also contains organics that over millions of year get turned into oil and gas. Which migrates until it come to surface or finds a trap.

The most common trap are anticlines of sandstone covered by a cap of shale which is basically a buoyancy trap since the oil can’t move through the shale and can’t slip under the cap since it float on top of the water. The bottom water is where the normal pressure comes from since it has ways around the shale cap to transmit pressure to surface.

If you take this sandstone reservoir and cut it off from its continuous water column through faulting it can then be moved up or down in the stratigraphic column and create over or under-pressured reservoirs.

In a waterdrive reservoir, as I described above, as the lighter fluids are removed from the reservoir they are replaced with the heavier water this naturally causes the pressure at the top of the reservoir to decrease. To illustrate; if the pressure at the bottom of the reservoir is a fixed 10,000 psi with a 100’ column of light crude with a sg of .85 the pressure at the top of the reservoir would be 9963 psi if the entire reservoir was drained and replaced with native Gulf water at 1.08 then the new pressure at the top of the reservoir would be 9953 psi.

There are other drive mechanisms that can cause a greater pressure drop in the reservoir but the math is much easier here. I’m not overly familiar with the gulf since I’ve never worked there but I can elaborate if anything is unclear.