Hydrostatic pressure is both (a) the pressure exerted (per unit area) in a column of fluid by the density of fluid (i.e., liquid plus solids) and (b) the normal predicted pressure for a given depth exerted by a static column of water due to the density of the liquid (and dissolved solids) plus any pressure acting on the surface of the liquid. Case (a) uses a straightforward approach that we will adopt when describing a bore hole filled with drilling fluid, whereas (b) is more geologically oriented. However, in both cases the size and shape of the fluid column (Figure 100) has no effect on the magnitude of the pressure at any depth, it is liquid density and vertical distance that fundamentally control hydrostatic pressure (Fertle et al., 1976).
However, differences in fluid density and the
presence of temperature gradients do affect hydrostatic pressure and hydrostatic pressure gradients. For example, an increase in the concentration of TDS will lead to an increase in the hydrostatic pressure gradient, whereas the presence of gas will decrease the gradient. Similarly, an increase in temperature will lead to a decrease in density and also lower the gradient. Hydrostatic pressure (Phy) at a given depth can be approximated using the average fluid density, multiplied by depth and a gravity constant. However, for oil field purposes hydrostatic pressure is often calculated using the following (or derivative):
Phy = 0.0519 * W * D (imperial units) or (6)
Phy = 0.0098 * W * D (metric units) where: Phy = hydrostatic pressure (psi or kPa)
W = fluid density, expressed as a weight (lb/gal or kg/m3) D = the vertical height of the column (feet, SI, or meters) and
0.0519 and 0.0098 are oilfield conversion constants (imperial and metric units respectively) All oil field measurements are related to the rotary kelly bushing (RKB).
Figure 100. Hydrostatic pressure (Phy), showing that shape is irrelevant.
In all cases the vertical height is 3,000 m (9,842 ft), the mud weight density is 1,437 kg m3 (12 lb gal or 0.623 psi ft); in all cases (a to e) the Phy is 21,470 kPa or 3114 psi at the base of each column.
Chapter 5—Water, Pressure, and Temperature
Overburden pressure
Overburden pressure ( Po) is the sum of rock (i.e., mineral) density, fluid density, and vertical height (Fertle et al., 1976). Since this pressure is due to the combined weight of the rock/sediment matrix and pore fluids, overburden pressure generally increases with depth and has been expressed as:
where: Po = overburden pressure
D = vertical height of the geological column (feet or meters) = porosity (as a fraction)
pma = rock matrix density in lb/ft3 or kg/dm3 and pf l = fluid density in lb/ft3 or kg/dm3.
The force exerted due to the combined weight of the rock/sediment matrix and pore fluids creates an overburden pressure gradient, expressed in psi/ft or kg cm-1 m-1. In contrast the pressure gradients exerted by rock matrix (i.e., lithostatic) or pore fluid (i.e., hydrostatic) alone will be less than the overburden pressure (Figure 101). Overburden pressure gradients vary from basin to basin and even within a basin.
Formation pressure
Formation pressure ( Pf) is the pressure acting upon formation fluids (gas, oil, water) held within the pore space of rock/sediment. If hydraulic continuity exists between the surface and the subsurface, the pressure will equal the hydrostatic head (hydrostatic pressure, Figure 101).
However, as already discussed, hydrostatic pressure is dependent upon the density of the pore fluid. For example, within the Rocky Mountains (U.S.A.) where meteoric water predominates, the normal pressure gradient is 9.8 kPa/m or 0.434 psi/ft; in contrast, within the Gulf of Mexico formation water is dense and saline (i.e., connate water), and associated with a normal pressure gradient of 11.3 to 12.4 kPa/m or 0.5 to 0.55 psi/ft (Chillingar et al., 2002).
Normal and abnormal formation pressures
It is often assumed that for normally compacted formations in which pressure is transmitted through a continuous column of water from surface down to a given depth, the pressure gradient will increase uniformly (linearly) with depth (Figure 102A). However, many basins of the world exhibit markedly nonuniform or nonlinear pressure gradients, where there is a lack of hydraulic continuity between the surface and a formation of interest, perhaps due to the presence of a sealing surface. If the pressure below the seal is greater than the normal (i.e., hydrostatic) pressure gradient, the pressure is termed overpressure (Figure 102B), if the pressure below the seal is less, then the pressure is termed underpressure or subpressure (Fertle et al., 1976).
Figure 102. (a) Normal pressure gradient in which all successively deeper reservoirs [A, B, and C] are in hydraulic continuity with the surface; (b) an abnormal pressure gradient in which a sealing surface isolates reservoir [C] resulting in overpressure [C1] or underpressure [C].
(7)
Figure 101. Subsurface pressure concepts (after Fertle et. al., 1976; Chillingar et al., 2002;Swarbrick et al., 2002; and others).
Figure 102. (a) Normal pressure gradient in which all successively deeper reservoirs [A, B, and C] are in hydraulic continuity with the surface;
(b) an abnormal pressure gradient in which a sealing surface isolates reservoir [C] resulting in overpressure [C1] or underpressure [C].
Chapter 5—Water, Pressure, and Temperature
76
Therefore, a normal pressure gradient can be visualized as a hydraulic 憃pen system? in which hydrostatic conditions exist (Figure 102A). In contrast, abnormal pressure gradients are essentially 慶losed systems,? in which fluid communication is restricted or prevented (Fertle et al., 1976). In a normally pressured basin, the rock matrix (i.e., mineral grains) supports the overburden load by grain-to-grain contact. If the pressure gradient is high (i.e., overpressured) then the overburden pressure is, in part, supported by formation fluid within the pore space Figure 103).
Overburden pressure gradients vary from basin to basin (Figure 104) and there are many causes of abnormal pressure gradients. For example, variations in fluid and rock density, compaction rates, the permeability evolution of sediment, transformation of kerogen to petroleum and the diagenesis of minerals can all influence the pressure regime of a basin (Fertle et al., 1976; Swarbrick et al., 2002).
Examples of subnormal pressured gradients exist and include, for example, the Permian, Pennsylvanian, Mississippian, and Devonian age formations in parts of the Anadarko Basin, Oklahoma, U.S.A., areas of the Texas Panhandle, U.S.A., with gradients ranging from 0.083 kg cm-2 (0.36 psi/ft) to 0.09 kg cm-2 (0.39 psi/ft), oil and gas reservoirs of Tertiary age and Middle Miocene age in Russia, and the Viking Formation, Alberta, Canada (Fertle et al., 1976). Possible causes for underpressure or subnormal pressured gradients include the presence of abnormally low water tables (e.g., Middle East) or the lowering of the water table by excessive subsurface fluid withdrawal (Swarbrick et al., 2002).
Some factors responsible for overpressure
There are a number of possible reasons for overpressure and only some are presented here. For a contemporary review see Swarbrick et al., (2002) and Chillingar et al., (2002).
Disequilibrium compaction
During sediment burial, an increase in vertical stress, coupled with a marked reduction in permeability, may lead to incomplete sediment dewatering (Figure 103) and fluid retention. The depth at which this
Fluid expansion can occur due to aquathermal expansion of pore fluids, smectite dehydration, and kerogen transformation/petroleum generation.
The aquathermal expansion of pore fluids has been cited as a possible mechanism responsible for abnormal formation pressures (Chillingar et al., 2002). For example, an increase of 40oC will generate a volumetric expansion of pore fluid of 1.65% (Swarbrick et al., 2002). Although this degree of expansion can lead to an increase in pore pressure, aquathermal expansion is not considered capable of generating the high-magnitude overpressures associated with some basins (e.g., Northwest Shelf, Australia).
Smectite dehydration involves three stages of dewatering, with an estimated increase in volume of 4%; whereas the transformation of smectite to illite can generate either a volumetric increase of 4.1% or a decrease of 8.4%, although estimates using a higher geothermal gradient (40 篊 km) yield an estimated increase in overpressure of 0.8 MPa (112 psi) (Swarbrick et al., 2002).
When kerogen is thermally transformed into petroleum there is a volumetric increase, depending upon kerogen Type and the molecular weight and density of the petroleum products. Volumetric increases of 25 vol% are considered
Figure 103. Overpressure. When sediment burial is rapid and permeability poor, pore fluid cannot escape and supports the ever-increasing overburden stress (left). Permeable lithologies undergo 慸ewatering? (right). Povb = overburden pressure (psi); Ppore = pore pressure (psi) (image
? 2007 Schlumberger, Ltd. Used with permission).
Figure 104. Generalized example overburden pressure gradients (after Rehm, 1972;
Lepine and White, 1973; Fertle et al., 1976;
Eaton, 1999; and others).
Chapter 5—Water, Pressure, and Temperature
possible during the generation of oil from a Type II kerogen (Meissner, 1978) with estimates ranging from 75 to 140 vol% during the generation of gas at high levels of thermal maturity. The generation of gas can create potential overpressures of 0.5 to 41 MPa (70 to 6000 psi) (Swarbrick et al., 2002).
Overpressure: The concern
There are many reasons abnormal pressure is a concern, especially during the drilling of a well, which include the following (Figure 105):
The ingress of formation fluid into the wellbore, known as a
慿
ick? (Figure 105:1). An uncontrolled kick that either flows to the surface or invades another formation is termed a慴
lowout.?Increasing the drilling fluid density to counter a kick (Figure 105:2) can cause the loss of drilling fluid, known as
憀
ost circulation,? into a porous underpressured or normally pressured formation (Figure 105:4). Large scale losses will lower the hydrostatic head of the drilling fluid, creating other problems.The differential sticking of drill pipe to the wall of the borehole, known as
憇
tuck pipe? (Figure 105:3).A high pore pressure in low permeability rocks (e.g., mudrocks) can cause those rocks to
慶
ave? (swell and slough) into the borehole, creating a drilling hazard or complicating the geological interpretation of drilled lithologies.For these and many other reasons, drillers and engineers alike are constantly seeking and refining means of predicting abnormal pressure regimes ahead of the drill bit. Various approaches have proven useful throughout the last 40 years, especially in clastic-dominated basins, and include the observation of shale cuttings density and shape, the use of d-exponents, wireline data and more recently measurement-while-drilling devices (MWD).
For a succinct overview of pressure detection methods see Pilkington (1999) and Fertle et al., (2002)