since the Pleistocene (the past∼15,000 years) due to locally rapid erosion caused by post-glacial uplift (Riis 1992; Dore and Jensen 1996).
It is relatively straightforward to understand the conditions under which compaction disequilibrium will result in overpressure development. The characteristic time,τ, for linear diffusion is given by
τ = l2
κ = (φβf+βr)ηl2
k (2.2)
where l is a characteristic length-scale of the process,κ≈k/(φβf+βr) is the hydraulic diffusivity,βfandβrare the fluid and rock compressibilities, respectively,φis the rock porosity, k is the permeability in m2(10−12m2=1 Darcy), andηis the fluid viscosity.
For relatively compliant sedimentary rocks, equation (2.2) gives
logτ =2log l−log k−16 (2.3)
whereτand l are in years and kilometers, respectively. In low-permeability sands with a permeability of about 10−15 m2 (∼1 md), the characteristic time for fluid transport over length-scales of 0.1 km is of the order of years, a relatively short amount of time in geological terms. However, in low-permeability shales where k∼10−20m2 (∼10 nd) (Kwon, Kronenberg et al. 2001), the diffusion time for a distance of 0.1 km is∼105 years, which is clearly sufficient time for increases in compressive stresses due to sediment loading, or tectonic compression, to enable compaction-driven pressure to build up faster than it can diffuse away.
Tectonic compression is a mechanism for pore pressure generation that is analogous to compaction disequilibrium if large-scale tectonic stress changes occur over geolog- ically short periods of time. Reservoirs located in areas under tectonic compression are the most likely places for this process to be important, such as the coast ranges of California (Berry 1973), or the Cooper basin in central Australia although changes in intraplate stress due to plate tectonic processes can also lead to pore pressure changes (Van Balen and Cloetingh 1993). In the northern North Sea offshore Norway, as well as along the mid-Norwegian margin, Grollimund and Zoback (2001) have shown that compressive stresses associated with lithospheric flexure resulting deglaciation between 15,000 and 10,000 years ago appear capable of explaining some of the pore pressure variations in Figure 2.3, with higher pore pressures in areas of induced compression and lower pore pressures in the areas of induced extension. Thus, along the Norwegian margin there appear to be three mechanisms for generating excess pore pressure, two mechanisms related to deglaciation – changes in the vertical stress due to recently rapid sedimentation and increases in horizontal compression due to lithospheric flexure – and hydrocarbon generation (discussed below). Interestingly, the two mechanisms asso- ciated with deglaciation have resulted in spatially variable pore pressure changes over the past few thousand years.
40 42 44 46 48 50 52 54 2600
2800
3000
3200
3400
3600
Pore pressure (MPa) H Y D R O S TAT I C
P O R E P R E S S U R E G R A D I E N T
Depth (m)
Figure 2.11. Pore pressure measurements from an oil and gas field in the northern North Sea. Note the distinct, low gradient, hydrocarbon legs associated with reservoirs encountered in a number of wells.
Hydrocarbon column heights can result in substantial overpressure at the top of reser- voir compartments, especially when appreciable amounts of buoyant gas are present.
This was seen for the FB-A and FB-B OI sands in South Eugene Island in Figure 2.8a (Finkbeiner, Zoback et al. 2001) and as mentioned above can ultimately limit the size of hydrocarbon columns in some reservoirs. Figure 2.11 shows excess pore pressure at the top of hydrocarbon columns from a field in the North Sea.
Centroid effects refer to the fact that relatively high pore pressure occurs at the top of a tilted sand body encased in shale. As shown in Figure 2.12, the pore pressure at the top of
Centroid
Bottom
Depth
Shale Pres. (Ppsh) Sand Pres. (Ppss) Top
Pressure/Stress
OVERBURDE
N HYDROST
ATIC S H A L E
SAND
C O M P L E T E LY S E A L E D
Figure 2.12. Illustration of the centroid effect where the tilting of a sand body encased in a low permeability shale results in a higher pore pressure at the top of the sand than in the shale body at the equivalent depth (from Finkbeiner, Zoback et al.2001). AAPGC 2001 reprinted by permission of the AAPG whose permission is required for futher use.
the sand body is higher than that in the adjacent shale at the same elevation. Pressure in very weak shales is presumed to increase with a lithostatic gradient (as below 11,000 ft in Figure 2.2). The depth at which pore pressure is the same in the two bodies is referred to as the centroid. This concept was first described by Dickinson (1953), and expanded upon by England, MacKenzie et al. (1987) and Traugott and Heppard (1994). It is clear that drilling into the top of a sand body with pore pressure significantly higher than the adjacent shale poses an appreciable drilling hazard. Finkbeiner, Zoback et al.
(2001) discussed centroid effects in the context of pressure-limited column heights in some reservoirs (in contrast with column heights controlled by structural closure or sand-to-sand contacts). We revisit this topic in Chapter 11.
Aquathermal pressurization refers to a mechanism of overpressure generation stem- ming from the fact that as sediments are buried, they are heated. Temperature increases with depth in the earth due to heat produced by radioactive decay of crystalline base- ment rocks and heat flowing upward through the crust from the mantle. Because heating causes expansion of pore fluid at depth, in a confined and relatively incompressible rock matrix, expanding pore fluid pore would lead in theory to pressure increases. The reason aquathermal pressure increases are not, in general, thought to be a viable mechanism of overpressure generation in most places is that the time-scale for appreciable heating is far longer than the time-scales at which overpressures develop in active sedimentary systems (Daines 1992; Luo and Vasseur 1992) such that a near-perfect seal would be required for long periods of geologic time.
Dehydration reactions associated with mineral diagenesis have been proposed as another mechanism that could lead to overpressure development. Smectite dehydration
is a complex process (Hall 1993) but can lead to overall volume increases of both the rock matrix and the pore water system. One component of this process is the phase transition from montmorillonite to illite, which involves the expulsion of water from the crystal lattice of montmorillonite. The transition occurs at a temperature of about 100◦C in the Gulf of Mexico, which is often correlative with the depth at which overpressures are observed to develop (Bruce 1984). The transition of anhydrite to gypsum is another dehydration reaction that can lead to overpressure development, but only at relatively shallow depths as the temperature at which this dehydration occurs is only about half that of the smectite–illite transition.
The exact manner in which dehydration reactions may generate overpressure is quite complicated. For example, in the case of the smectite–illite transition, the overall volume change associated with the transition is poorly known and the phase transition may work in conjunction with compaction disequilibrium (due to increased compressibil- ity) and silica deposition (which lowers permeability). Nonetheless, a number of authors (e.g. Alnes and Lilburn 1998) argue that dehydration reactions are an important mech- anism for generating overpressure in some sedimentary basins around the world.
Hydrocarbon generation from the thermal maturation of kerogen in hydrocarbon source rocks is associated with marked increases in the volume of pore fluid and thus can also lead to overpressure generation. This is true of the generation of both oil and gas from kerogen, although the latter process is obviously more important in terms of changes in the volume of pore fluids. As discussed in detail by Swarbrick and Osborne (1998), this mechanism appears to operate in some sedimentary basins where there is an apparent correlation between the occurrence of overpressure and maturation. In the North Sea, for example, the Kimmeridge clay is deeply buried and presently at appropriate temperatures for the generation of oil or gas (Cayley 1987). However, some younger formations (at depths well above the maturation temperatures) are also overpressured (Gaarenstroom, Tromp et al. 1993), so other pore pressure mechanisms are also operative in the area.