Formation Pore Pressure In Oil & Gas Wells

Formation pore pressure is the pressure exerted by the formation fluids on the walls of the rock pores. The pore pressure supports part of the weight of the overburden stress, while the rock grains take the other part [Rabia, 1985]. Formations are classified based on the magnitude of their pore pressure gradients.

In general, two types of formation pressure are known:

Normal formation pore pressure (hydro-pressure): This is when the formation pore pressure equals the hydrostatic pressure of an entire column of formation water. Normal pore pressure is usually of the order of 0.465 psi/ft.
Abnormal formation pore pressure (geo-pressure): This exists in regions with no direct fluid flow to the adjacent regions. The boundaries of such regions are impermeable, preventing the fluid from flowing and trapping it so that it takes a large proportion of the overburden stress. Abnormal formation pore pressure usually ranges between 0.8 and 1 psi/ft.

Pore Pressure Profiles

We can conventionally classify formations as normally pressured, under-pressured, or over-pressured.

Any pore pressure of the liquid or gas phase in the formation, as measured by logging tools, may be plotted on a graph similar to the one shown in Figure 1. As indicated on that graph, the position in which it is plotted will indicate into which pressure regime it falls.

Figure 1

These pressure regimes do not have strictly quantitative definitions based on what drilling fluid gradient is required to balance the pore pressure. Because of this, the boundaries between them are less well defined than shown in the graph and may vary according to the context and to local customs.

Normal Formation Pressure

Looking at Figure 1, we can see two cases of the hydrostatic gradient; these correspond to water with zero salinity and water with a highish (but not extreme) salinity. In general, if a plotted pressure falls between these two lines, the formation is normally pressured at that depth, and a normal unweighted drilling fluid can be used while drilling through it.

A normally pressured formation usually has a hydraulic connection to the water table level. However, this does not have to be vertical, i.e., the connection could happen some distance away via connections with other formations, non-sealing faults, etc. In this case, the water table will generally be at approximately the same elevation as the drilling location.

In a region known to have unusually high formation water salinities, and thus densities, the formation pressure would still be called “normal” or “hydrostatic” even though the plotted pressure is in the overpressure region of the chart (as long as it is consistent with the known pore fluid densities).

Notes:

Most of the fluids found in the pore space of
Sedimentary formations contain a proportion of salts (brines).
Dissolved salts may vary between 0 to over 200,000 ppm.
Pore Pressure gradient:
- Pure water = 0.433 psi/ft
- Saltwater = 0.442-0.478 psi/ft
- Most geographical area = 0.465 psi/ft (assumes 80,000 ppm salt content) – normal pressure gradient/hydrostatic pressure.

	P Gradient – PSI/FT	P Gradient – KG/M³
West Texas	0.433	1
Gulf Of Mexico Coastline	0.465	1.074
North Sea	0.452	1.044
Malaysia	0.422	1.021
Mackenzie Delta	0.422	1.021
West Africa	0.422	1.021
Anadarko Basin	0.433	1
Rockey Mountains	0.436	1.007
California	0.439	1.014

Normal Formation Pore Pressure Gradients For Several Areas Of Active Drilling

Subnormal Pore Pressure Regime

Formations with pore pressures that plot below the hydrostatic region shown in 1 (or below the locally accepted normal pressure region) are said to have a Sub-Normal or Sub-Hydrostatic pressure regime. If a formation in the region mentioned above has a pore pressure equivalent to a gradient of 10.2 kPa/m (0.45 psi/ft) it would probably be considered under-pressured, depending on local custom, even though it would be a normal pressure elsewhere.

Sub-normal pressures can be caused by the following situations:

Low water table or high drilling location elevation
Reservoir depletion
Tectonic extension after compression
Thermal Expansion
Formation Foreshortening

Low water table or High Elevation

In mountainous or arid areas, it is possible for the water table to be deep below the surface at the drilling location. The top hole is then drilled through dry rock. Here the pore pressure is zero, and the matrix stress alone defines the overburden down to the water table. Below the water table, p_o then plays a part. This situation is illustrated in Figure 2.3.3.

low water table effect — **Figure 2.3.3 :** The effect of a low water table or high location elevation

For example, if the water table is at 1000 m (3,281 ft) bdf and the formation fluid gradient is 10 kPa/m (0·442 psi/ft) then the pressure P at a depth D will be given by:

P = 10 kPa/m x (D – 1,000) m P = 0·442 psi/ft x (D – 3,281) ft

From the surface, it is said that the formation pressure is under pressure by 1,000 m x 10 kPa/m = 10,000 kPa or 3,281 ft x 0·442 psi/ft = 1,450 psi.

Depleted Reservoirs

It has been stated that a normally pressured reservoir usually has a hydraulic connection to the local water table level. This connection can be tenuous and of low permeability and can sometimes even have been lost as a result of sealing faults, salt intrusions etc. This situation is often described by saying that a reservoir has little or no natural water drive. Consequently, if such a reservoir is produced, the pressure in the reservoir will drop by the expansion process to less than that calculated from the normal gradient (unless it is artificially maintained by gas or water injection).

Some pressure gradients in Texas aquifers have been as low as 0.36 psi/ft.

Tectonic extension after compression

If a reservoir rock with permeability and porosity becomes sealed after deposition and is extended or expanded due to tectonic stresses acting on it, the effect can be to expand the fluid in the pore spaces and reduce the pressure. The effect will be to reduce the pore pressure to less than that generated by the local hydrostatic pressure gradient.

Formation Foreshortening

During a compression process, there is some bending of the strata. The upper beds bend upward, and the lower bed bend downwards. The intermediate beds must expand to fill the void and create a subnormal pressure zone. – This thought applies to some subnormal zones in Indonesia and the U.S. – Notice that this may also cause overpressures in the top and bottom beds.

Thermal Expansion

As sediments and pore fluids are buried, the temperature rises. If the fluid is expanded, the density will decrease, thus reducing the pressure.

Abnormal Formation Pressure Regime

Formations with pore pressures that plot above the hydrostatic region shown in Figure 2.3.1 (or above the locally accepted normal pressure region) are said to have an Abnormal or Over-Pressured pressure regime.

Over-pressures may be the result of:

High water table or low elevation
Hydrocarbon bearing formations
Abnormal sedimentary burial circumstances
Osmotic action

Whilst sub-normal or sub-hydrostatic formations can cause drilling problems such as mud losses or stuck pipe due to the pressure difference between the well bore and the formation pores (assuming that the well is full with water as a minimum!), over-pressures can cause more significant problems such as borehole instability, well kicks, and blow-outs. Consequently, it is essential to understand how over-pressures can occur and how we can predict and identify them early. You can read more in the causes of abnormal pore pressure article.

Prediction Of Formation Pore Pressure

Due to the drilling problems that both abnormally and sub-normally pressured formations can cause, it is important to be able to predict them. Depending on the nature of the drilling operation, this may be during the planning stages of a well or whilst actually drilling the well.

Prediction while planning
Warning signs while drilling

The pore pressure prediction article will discuss the above items in detail.

Pore Pressure Equation & Calculation

Conventional pore pressure analysis is based on Terzaghi’s effective stress principle, which states that vertical stress (S_v) is equal to the sum of the effective vertical stress (σ_e) and the formation pore pressure (P_f) as follows:

S_v = σ_e + P_f

The basic steps in performing a conventional 1-D pore pressure analysis are:

Calculate total vertical stress (S_v) from rock density
Estimate effective vertical stress (σ_e) from log measurements or seismic (LWD-WL, Vel)
Pore pressure P_f = S_v – σ_e
Then we can calibrate the analysis to credible information as it becomes available: – MDT/RFT – SIDPP – SPLINTERED CAVINGS – EXCEPTIONAL CONNECTION GAS – HOLE FILL – EXCESS DRILL STRING DRAG