BAKER HUGHES - Drilling Fluids Reference Manual

Formation Mechanics
Reservoir Pressure
The fluid in the pores of reservoir rock is under a certain degree of pressure, generally called reservoir
(or formation) pressure. A normal reservoir pressure at the oil-water contact approximates very
closely the hydrostatic pressure of a column of salt water to the depth. The hydrostatic pressure
gradient varies somewhat, depending on the amount of dissolved salts in the average water for a given
area. For fresh water, it is 0.433 psi/ft of depth. For water containing 80,000 ppm of dissolved salts
(U.S. Gulf Coast), the pressure is approximately 0.465 psi/ft. However, normal marine water is about
35,000 dissolved salts, approximately 0.446 psi/ft. Reservoirs can contain fluids under abnormal
pressure up to as high as 1.00 psi/ft of depth.
Abnormal pressure may develop in isolated reservoirs as a result of compaction of the surrounding
shales by the weight of the overburden. During this process, water is expelled from the shale into any
zone of lower pressure. This may be into a wholly confined sandstone which does not compact as
much as the shale. Consequently, its contained water is under a lower pressure than that in the shale.
Ultimately, a state of equilibrium can be reached when no further water can be expelled into the
sandstone, and its fluid pressure will approximate that of the shale.
Since compaction of sandstones is related to the pressure of the pore fluid as well as to the pressure
exerted by the overburden, it follows that abnormally pressured sandstones are partially supported by
the fluid pressure and partially by grain-to-grain contact. Consequently, when the abnormal pressure
is reduced by production, compaction of the reservoir begins to occur. Subsurface compaction can
cause serious problems, not only in collapse of the well casing, but also because of the subsidence
reflected at the surface. Such occurrences result in very expensive landfill and well repair costs.
It has been demonstrated that there can be a direct relationship between subsidence and the amount of
liquid withdrawn. Studies of the Wilmington Field in California indicated that re-pressuring by water
injection would increase oil recovery and stop compaction. Subsidence was stopped by such a
program, and, in places, the surface regained some of the elevation that was lost. However, work on
sediments has shown that this compaction is not entirely reversible. Some permanent reduction of
porosity and permeability results from permitting abnormal reservoir pressure to decline, and this may
adversely affect the rate of production and possibly, the ultimate recovery.
Formation Damage
Permeability
It is imperative that rocks containing hydrocarbons not be inhibited in their ability to produce oil or
gas during drilling. Rocks allow the flow of a liquid or gas when their pore spaces are connected to
form channels. This ability to flow is called permeability, and the standard unit of measure is termed
the Darcy, named for Henry Darcy who developed a mathematical equation called Darcy's Law that
can be used to calculate permeability. Using this equation, the permeability of a material can be
measured if the following values are known:
• Length and cross-sectional area of the material
• Viscosity of the fluid flowing through it
• Amount of pressure needed to cause the flow
• Flow rate (i.e., the volume of fluid that flows through the material in a given amount of time)
A piece of material one centimeter long and one square centimeter in area that will flow water at a rate
of one cubic centimeter per second at a driving pressure of one atmosphere (14.7 psi) has a
permeability of one Darcy. Most rocks have much less than one (1) Darcy permeability, so the most
Reference Manual
Baker Hughes Drilling Fluids
2-14 Revised 2006