This is partly because the porewater is not heated
very much during basin subsidence since it is moving
upwards as the basin and the sediments are sinking.
When solids (e.g. kerogen) are transformed into
fluids like oil and gas, a volume expansion may
occur. Cracking of oil and the formation of gas also
involves a phase change, which will cause increased
pressure because of the expansion of gas.
Generation of oil from kerogen gives an increase in
volume but calculations suggest that it is not very large
because this leaves some solid material (coke)
remaining. Generation of gas will cause a higher volume increase, especially at relatively shallow depths.
Even if the total increase in volume is moderate the
convertion of solid kerogen to fluid petroleum is a
very efficient mechanism for increasing the pore pressure. This is because the fluid/solid ratio is changed
and this may cause source rocks to hydrofracture so
that the petroleum is expelled. An illustration of such
a phase change can be observed in the spring when
lenses of ice frozen in the ground melt. The conversion from solid ice to water represents a reduction in
overall volume but may generate overpressure
because the fluid/solid ratio has been very much
increased.
When considering larger compartments in sedimentary basins, however, the pressure is mainly controlled by the water phase which is much more
abundant.
Development of overpressure depends on the fluid
flux in relation to the permeability of the rocks. The
permeability of shales which may serve as seals for
overpressure compartments varies greatly and is difficult to predict. A change from 1.0 nD (10
À9 D) to 0.1
nD will increase the pressure gradient 10 times. We
must also remember that for vertical flow perpendicular to bedding the effective permeability is the harmonic average of the permeabilities in the different
layers. Thin layers with very low permeability may
therefore control the flow rate and the build-up of
overpressure. It is therefore very difficult to model
and predict overpressure. High overpressures will
reduce the effective stress and make the sediments
less consolidated. There will then be very little mechanical compaction and compaction-driven fluid flow to
build up an overpressure. Fluid transfer from greater
depth may cause higher overpressure at shallower
levels, though. The onset of chemical compaction,
and in particular quartz cementation at temperatures
higher than 80–100
C, will reduce the porosity and
permeability not only in the sandstones but also in the
shales. High sedimentation and subsidence rates
will increase the compaction-driven flux but the rate
of permeability reduction in the shales (seals) due
to chemical compaction will be slower so the permeability of the sealing shales will be higher. This
could compensate for the higher fluid flux. Many
shales are almost impermeable.
Extremely low permeabilites are required to maintain overpressures in basins that are uplifted and no
longer undergo compaction. Overpressured reservoirs
in onshore basins in North America have, for the most
part, not subsided since the early Tertiary and it is
remarkable that the overpressures have been retained
without more recent compaction. In the Anadarko
Basin the Missisippian and Pennsylvanian sequence
is overpressured close to fracture pressure, while the
underlying Ordovician rocks are normally pressured.
In the Powder River Basin, Cretaceous shales are
highly overpressured but not to fracture pressure.
Widely distributed free gas (Surdam et al. 1994) may
also reduce the permeability for water in the shales. It
is not clear if these pressures are maintained by active
gas generation at depth. Reservoirs flanking mountain
chains like the Rocky Mountains may also be
overpressured, here due to meteoric water flow from
the mountains.
In sedimentary basins the permeabilities are very
much higher parallel to bedding than perpendicular to
bedding, and overpressure usually depends more on
the lateral drainage than on variations in the vertical
permeabilities. Modelling 1 D vertical flow is therefore not very realistic. Faulting that offsets permeable
sandstones against tight shales may contribute to the
development of overpressure. Synsedimentary growth
faulting in particular is very common in basins with
high sedimentation rates like the Gulf Coast basins.
This is one of the reasons for the widespread
overpressuring in such basins.
Models for the prediction of overpressure are often
based on changes in fluid flux with less emphasis on
the permeability which is more difficult to constrain.
This is because the vertical flux depends on the harmonic average of the permeabilities in all the layers
also within shales. If the permeability is kept constant,
it is possible to model overpressure as a function
of other variables such as rates of compaction, hydrocarbon generation and thermal expansion of the
298
K. Bjørlykke
very much during basin subsidence since it is moving
upwards as the basin and the sediments are sinking.
When solids (e.g. kerogen) are transformed into
fluids like oil and gas, a volume expansion may
occur. Cracking of oil and the formation of gas also
involves a phase change, which will cause increased
pressure because of the expansion of gas.
Generation of oil from kerogen gives an increase in
volume but calculations suggest that it is not very large
because this leaves some solid material (coke)
remaining. Generation of gas will cause a higher volume increase, especially at relatively shallow depths.
Even if the total increase in volume is moderate the
convertion of solid kerogen to fluid petroleum is a
very efficient mechanism for increasing the pore pressure. This is because the fluid/solid ratio is changed
and this may cause source rocks to hydrofracture so
that the petroleum is expelled. An illustration of such
a phase change can be observed in the spring when
lenses of ice frozen in the ground melt. The conversion from solid ice to water represents a reduction in
overall volume but may generate overpressure
because the fluid/solid ratio has been very much
increased.
When considering larger compartments in sedimentary basins, however, the pressure is mainly controlled by the water phase which is much more
abundant.
Development of overpressure depends on the fluid
flux in relation to the permeability of the rocks. The
permeability of shales which may serve as seals for
overpressure compartments varies greatly and is difficult to predict. A change from 1.0 nD (10
À9 D) to 0.1
nD will increase the pressure gradient 10 times. We
must also remember that for vertical flow perpendicular to bedding the effective permeability is the harmonic average of the permeabilities in the different
layers. Thin layers with very low permeability may
therefore control the flow rate and the build-up of
overpressure. It is therefore very difficult to model
and predict overpressure. High overpressures will
reduce the effective stress and make the sediments
less consolidated. There will then be very little mechanical compaction and compaction-driven fluid flow to
build up an overpressure. Fluid transfer from greater
depth may cause higher overpressure at shallower
levels, though. The onset of chemical compaction,
and in particular quartz cementation at temperatures
higher than 80–100
C, will reduce the porosity and
permeability not only in the sandstones but also in the
shales. High sedimentation and subsidence rates
will increase the compaction-driven flux but the rate
of permeability reduction in the shales (seals) due
to chemical compaction will be slower so the permeability of the sealing shales will be higher. This
could compensate for the higher fluid flux. Many
shales are almost impermeable.
Extremely low permeabilites are required to maintain overpressures in basins that are uplifted and no
longer undergo compaction. Overpressured reservoirs
in onshore basins in North America have, for the most
part, not subsided since the early Tertiary and it is
remarkable that the overpressures have been retained
without more recent compaction. In the Anadarko
Basin the Missisippian and Pennsylvanian sequence
is overpressured close to fracture pressure, while the
underlying Ordovician rocks are normally pressured.
In the Powder River Basin, Cretaceous shales are
highly overpressured but not to fracture pressure.
Widely distributed free gas (Surdam et al. 1994) may
also reduce the permeability for water in the shales. It
is not clear if these pressures are maintained by active
gas generation at depth. Reservoirs flanking mountain
chains like the Rocky Mountains may also be
overpressured, here due to meteoric water flow from
the mountains.
In sedimentary basins the permeabilities are very
much higher parallel to bedding than perpendicular to
bedding, and overpressure usually depends more on
the lateral drainage than on variations in the vertical
permeabilities. Modelling 1 D vertical flow is therefore not very realistic. Faulting that offsets permeable
sandstones against tight shales may contribute to the
development of overpressure. Synsedimentary growth
faulting in particular is very common in basins with
high sedimentation rates like the Gulf Coast basins.
This is one of the reasons for the widespread
overpressuring in such basins.
Models for the prediction of overpressure are often
based on changes in fluid flux with less emphasis on
the permeability which is more difficult to constrain.
This is because the vertical flux depends on the harmonic average of the permeabilities in all the layers
also within shales. If the permeability is kept constant,
it is possible to model overpressure as a function
of other variables such as rates of compaction, hydrocarbon generation and thermal expansion of the
298
K. Bjørlykke