sedimentary sequences from outcrops or cores. This
information is critical for the prediction of reservoir
quality at greater depth.
Prediction of mechanical compaction of sediments
must be based on experimental compaction of
sediments with different mineralogical and textural
composition. Grain size, shape and sorting both in
sandstones and mudstones play an important role in
determining the mechanical compaction prior to
chemical compaction. Interpretations of provenance
and depositional environment should be used as
input for prediction of mechanical compaction based
on experimental compaction curves, thus linking diagenesis to more general basin analysis.
At shallow depth sediments may change their bulk
composition due to meteoric water flushing causing
leaching (dissolution) or evaporation (precipitation).
Below the reach of significant meteoric water flow the
porewater flow is very restricted with respect to transport of solids in solution.
Prediction of changes in rock properties due to
chemical compaction is based on thermodynamics
and kinetics and the initial mineral composition is
then critical. Fluid flow and transport of solids in
sedimentary basins can be constrained by modelling
sediment compaction and also by observations of
compositional stratification of the porewater. Burial
diagenetic reactions are nearly isochemical, and mineral reactions can therefore be written as balanced
equations. The burial diagenetic reactions are then
functions of the primary sediment composition which
can then be related to depositional environments and
provenance.
Significant increased porosity (secondary porosity)
is dependent on the dissolution and removal of solids
in solution which may occur during freshwater
flushing. Below the reach of freshwater the porewater flow is limited and a geochemically closed system cannot produce net increases in secondary
porosity.
Prediction of rock properties such as porosity and
velocity at a certain depth in a sedimentary basin must
be based on the burial history (effective stress and
temperature), but the primary mineralogical and textural composition of the sediments is equally important. Sedimentological studies of depositional
environments and provenance should therefore be
integrated with diagenesis and be a part of basin
analysis which is used for basin modelling (Bjørlykke
2014).
4.20 How Much Oil Can Be Produced
from Sandstone Reservoirs?
Petroleum exploration requires predictions about the
reservoir properties ahead of drilling to justify the
investment that a well represents. The reservoir
properties determine the percentage of recoverable
petroleum in each volume of rock. Even after drilling
several exploration wells and also production wells in
the development of an oil or gas field, the porosities
and permeabilities are only known from the cores.
Data from cores, cuttings and well logs must be
extrapolated to produce a 3D model of the large
volumes of rock between the wells. This must be
based on predictions from facies distribution, distribution of faults and fault properties. Changes in reservoir
properties as a function of depth require diagenetic
models which can predict changes in porosity as a
function of effective stress and temperature/time.
To calculate the producible oil in a prospect the
total rock volume (Gross – G) in the structure must be
estimated as well as the percentage of sandstone which
can be produced (Net Sand – N).
The oil in place (V p ) is:
V r Á N=G Á φ O sat
Here V r is the volume of oil between the oil/water
contact (OWC) and the reservoir cap rock or the gas/
oil contact. N/G (net/gross) is the ratio between the
fraction of the reservoir rock that can be produced and
the total volume of the reservoir rock. φ is the average
porosity of the producible part of the reservoir (net
volume). O sat is the average saturation of oil; typically
about 80–85% of the pores in sandstone are filled with
oil. The remaining portion is water, which in
siliciclastic rocks occupies the mineral surfaces and
the smallest pores where the capillary entry pressure is
too high for oil.
If the porosity is low the permeability will in most
cases also be very low so that the flow of oil from the
rock formation to the well becomes too slow to be
economical. About 10% porosity may be the minimum
porosity for defining the producible (net) part of the
4 Sandstones and Sandstone Reservoirs
145
information is critical for the prediction of reservoir
quality at greater depth.
Prediction of mechanical compaction of sediments
must be based on experimental compaction of
sediments with different mineralogical and textural
composition. Grain size, shape and sorting both in
sandstones and mudstones play an important role in
determining the mechanical compaction prior to
chemical compaction. Interpretations of provenance
and depositional environment should be used as
input for prediction of mechanical compaction based
on experimental compaction curves, thus linking diagenesis to more general basin analysis.
At shallow depth sediments may change their bulk
composition due to meteoric water flushing causing
leaching (dissolution) or evaporation (precipitation).
Below the reach of significant meteoric water flow the
porewater flow is very restricted with respect to transport of solids in solution.
Prediction of changes in rock properties due to
chemical compaction is based on thermodynamics
and kinetics and the initial mineral composition is
then critical. Fluid flow and transport of solids in
sedimentary basins can be constrained by modelling
sediment compaction and also by observations of
compositional stratification of the porewater. Burial
diagenetic reactions are nearly isochemical, and mineral reactions can therefore be written as balanced
equations. The burial diagenetic reactions are then
functions of the primary sediment composition which
can then be related to depositional environments and
provenance.
Significant increased porosity (secondary porosity)
is dependent on the dissolution and removal of solids
in solution which may occur during freshwater
flushing. Below the reach of freshwater the porewater flow is limited and a geochemically closed system cannot produce net increases in secondary
porosity.
Prediction of rock properties such as porosity and
velocity at a certain depth in a sedimentary basin must
be based on the burial history (effective stress and
temperature), but the primary mineralogical and textural composition of the sediments is equally important. Sedimentological studies of depositional
environments and provenance should therefore be
integrated with diagenesis and be a part of basin
analysis which is used for basin modelling (Bjørlykke
2014).
4.20 How Much Oil Can Be Produced
from Sandstone Reservoirs?
Petroleum exploration requires predictions about the
reservoir properties ahead of drilling to justify the
investment that a well represents. The reservoir
properties determine the percentage of recoverable
petroleum in each volume of rock. Even after drilling
several exploration wells and also production wells in
the development of an oil or gas field, the porosities
and permeabilities are only known from the cores.
Data from cores, cuttings and well logs must be
extrapolated to produce a 3D model of the large
volumes of rock between the wells. This must be
based on predictions from facies distribution, distribution of faults and fault properties. Changes in reservoir
properties as a function of depth require diagenetic
models which can predict changes in porosity as a
function of effective stress and temperature/time.
To calculate the producible oil in a prospect the
total rock volume (Gross – G) in the structure must be
estimated as well as the percentage of sandstone which
can be produced (Net Sand – N).
The oil in place (V p ) is:
V r Á N=G Á φ O sat
Here V r is the volume of oil between the oil/water
contact (OWC) and the reservoir cap rock or the gas/
oil contact. N/G (net/gross) is the ratio between the
fraction of the reservoir rock that can be produced and
the total volume of the reservoir rock. φ is the average
porosity of the producible part of the reservoir (net
volume). O sat is the average saturation of oil; typically
about 80–85% of the pores in sandstone are filled with
oil. The remaining portion is water, which in
siliciclastic rocks occupies the mineral surfaces and
the smallest pores where the capillary entry pressure is
too high for oil.
If the porosity is low the permeability will in most
cases also be very low so that the flow of oil from the
rock formation to the well becomes too slow to be
economical. About 10% porosity may be the minimum
porosity for defining the producible (net) part of the
4 Sandstones and Sandstone Reservoirs
145