Formation pressure, also called pore pressure, is the pressure of the fluids inside the pores of a rock. Knowing it is essential in drilling engineering because it affects casing design, mud weights, penetration rates, stuck-pipe problems and well control. This article explains where normal pore pressure comes from, how overpressure forms, and how the overburden gradient is calculated.
Predicting and detecting high-pressure zones is critically important, because they carry a risk of blowout. Such zones are usually associated with thick shale sequences that have trapped the connate water normally released during deposition. See key pressure definitions for the basic terms.
Overburden, Matrix and Pore Pressure
A simple model of compaction is a vessel containing fluid and a spring that represents the rock matrix. A piston pressed down on the vessel represents the overburden stress. The overburden (S) is supported by the stress in the spring (σ) and the fluid pore pressure (p):
S = σ + p
If the overburden increases, for example because more sediment is deposited, the extra load must be carried by the matrix and the pore fluid.
| Condition | What happens | Pore pressure |
|---|---|---|
| Fluids free to escape | The matrix takes the extra load; the fluid stays hydrostatic | Normal |
| Formation sealed, fluids cannot escape | The fluid takes part of the load, because water is almost incompressible and the grain contact area cannot increase | Above hydrostatic: overpressured |
In a normal case the pore pressure is proportional to depth and fluid density. In an overpressured formation, part of the overburden stress is transferred from the matrix to the fluid in the pore space.
Origin of Normal Pore Pressures
Consider a layer of sediment deposited on the ocean floor. As more sediment is laid on top, the grains pack closer together and water is expelled from the pore spaces. If this process is not interrupted and the water in the pores stays connected to the sea above through the interconnected pores, the pressure is hydrostatic.
The hydrostatic gradient (psi/ft) depends on the fluid density. Most oil field brines contain dissolved minerals, from almost none 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 areas it is taken as 0.465 psi/ft, assuming 80,000 ppm of salt. This gradient defines a normally pressured formation. Any formation pressure above or below it is called abnormal.
Example: at 10,000 ft, normal pore pressure = 0.465 × 10,000 = 4,650 psi.
Bulk Density and the Overburden Gradient
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 varies with depth.
The overburden gradient comes from the pressure exerted by the rock above the depth of interest. It can be calculated from the specific gravity of the rock, which varies from about 2.1 (sandstone) to 2.4 (limestone). Using an average of 2.3 and converting to a gradient:
2.3 × 0.433 = 0.9959 psi/ft
For most calculations this is rounded up to 1 psi/ft, sometimes called the geostatic gradient. At 10,000 ft the overburden pressure would be about 10,000 psi. It is unlikely that formation pressure can exceed the overburden gradient. But the overburden gradient may vary with depth because of compaction and changes in lithology, so it cannot be assumed to be constant.
| Gradient | Typical value (psi/ft) |
|---|---|
| Fresh water | 0.433 |
| Normal formation water (80,000 ppm salt) | 0.465 |
| Overburden (geostatic) | about 1.0 |
How Formation Pressure Is Checked
- Downhole measurements, such as a bottom hole pressure survey, confirm the predictions.
- A leak-off test at the casing shoe helps establish the safe mud weight limit.
Frequently Asked Questions
What is normal formation pressure?
The pressure equal to a column of formation water from the surface to the depth of interest, about 0.465 psi/ft in most areas.
What causes overpressure?
A sealed formation in which fluids cannot escape during compaction, so the pore fluid takes part of the overburden load.
Why does formation pressure matter in drilling?
If it exceeds the mud hydrostatic pressure, the well can kick. If mud weight is too high, the formation can fracture and mud can be lost.
Key Takeaways
- Overburden = matrix stress + pore pressure (S = σ + p).
- Normal gradient is about 0.465 psi/ft; overburden is about 1 psi/ft.
- Sealed formations become overpressured and carry a blowout risk.
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