A knowledge of formation pressure (or pore pressure ) is essential in drilling engineering, since, it affects casing design, mud weights, penetration rates, problems with stuck pipe, and well control. Of critical importance is the prediction and detection of high pressure zones where there is risk of blow out. Such zones are usually associated with thick shale sequences, which have trapped the connate water normally released during deposition.
A simplified model consisting of a vessel containing a fluid spring (representing the rock matrix) can describe the compaction process. A piston being forced down on the vessel can simulate the overburden stress. The Overburden (S) is supported by the stress in the spring (s) and the fluid pore pressure (r). Thus:
S = s + r
If the overburden is increased (e.g., die to more sediments being laid down) the extra load must be borne by the matrix and the pore fluid. In a formation where the fluids are free to move, the increased load must be taken by the matrix., while the fluid remains as hydrostatic. Under such circumstances, the pore pressure can be described as Normal, and is proportional to the depth and fluid density. If, however, the formation is somehow sealed so that the fluids cannot escape, the fluid pressure must increase above the hydrostatic value. Such a formation can be described as Overpressurized (i.e., part of the overburden stress being transferred from the matrix to the fluid in the pore space.). The grain to grain contact area cannot be increased due to presence of incompressible water, so the extra load must be taken by the fluid, thus increasing the pore pressure.
ORIGIN OF NORMAL PORE PRESSURES
Consider a layer of sediments deposited on the ocean floor in a fluid environment. As further sediments are laid on top, the grains are packed close together, thus expelling the water from the pore spaces. If this process is not interrupted, and the subsurface water is still continuos with the sea above via. the interconnected pores, the pressure will be hydrostatic. The hydrostatic gradient (psi/ft) varies according to the fluid density. Most oil field brines have a dissolved mineral content, which may vary from [o to over 200,000 ppm].
Correspondingly, the hydrostatic gradient ranges from 0.433 psi/ft (pure water) to about 0.50 psi/ft. In most geographical areas, the hydrostatic gradient is taken as 0.465 psi/ft (assuming 80,000 ppm of salt content). This gradient defines a normally pressurerized formation. Any formation pressure above or below this gradient may be called abnormal.
The bulk density of the rock must include the matrix, and the water in the pore space.
where,
Since lithology and fluid content are not constant, the bulk density will vary with depth.
The overburden gradient is derived from the pressure exerted by the rock above the depth of interest. This can be calculated from the specific gravity which vary from 2.1 (sandstone) to 2.4 (limestone). Using an average of 2.3 and converting to a gradient;
2.3 x 0.433 = 0.9959 psi/ft
For most calculations this is rounded up to 1 psi/ft. It is sometimes called geostatic gradient. It is unlikely that formation pressure could exceed the overburden gradient. however, it should be remembered that the overburden gradient may vary with depth due to compaction and change lithology and so cannot be assumed to be constant.
