Most well sorted sandstones have a porosity which lies
between these two values, typically around 40–42%.
Poorly sorted sand may have lower primary porosity
and will also compact more at moderate burial depths.
Clay-rich sediments have a much greater porosity
immediately after deposition, typically 60–80%. This
means that immediately following deposition a sand
bed is denser than a bed of clay or silt. However, clay
and silt lose their porosity more rapidly with burial.
Porosity may be classified into different types
depending on its origin.
Pore space between the primary sediment grains is
often referred to as primary porosity. Intergranular
porosity simply means porosity between the grains
whereas intragranular porosity means porosity inside
the sediment grains. The latter may be cavities in
fossils, e.g. foraminifera, gastropods, molluscs, but
also partly dissolved feldspar and rock fragments.
Pore space formed by dissolution or fracturing of
grains is called secondary porosity.
Cavities formed by selective solution of sediment
grains or fossils are classified as mouldic porosity. A
typical example is when dissolution of aragonite
fossils like gastropods leaves open pore spaces
(moulds).
Particularly in carbonates we may also have porosity on a large scale i.e. as caverns (karst) and in reefs.
Pore space produced by fracturing is called fracture
porosity.
Permeability is an expression of the ease with
which fluids flow through a rock. It will depend on
the size of the pore spaces in the rocks, and in particular the connections between the pore spaces. Even thin
cracks will contribute greatly to increasing the
permeability.
Permeability can be measured by letting a liquid or
gas flow through a cylindrical rock sample under pressure. The pressure difference P 1 À P 2 between the two
ends of a horizontal cylinder is ΔP, the cylinder length
L, and the flow rate of water (or another fluid) through
the cylinder, is Q (cm
3 /s). A is the cross-section and μ
the viscosity of the fluid
Q ¼
k Á A Á ΔP
L Á μ
where k is the permeability.
The volume of water which flows through each
surface unit in the cross-section A is thus equal to the
flux F ¼ Q=A. F can be measured in cm
3 /cm
2 /s or in
m
3 /m
2 /s. This is equal to the Darcy velocity which is
cm/s.
Well-sorted sandstones may have permeabilities
exceeding 1 Darcy and values between 100 and
1,000 mD are considered to be extremely good.
Permeabilities of 10–100 mD are also considered to
be good values for reservoir rocks. Permeabilities of
1–10 mD are typical of relatively dense sandstones
and limestones, so-called tight reservoirs. There are
also examples of rocks with even lower permeabilities
being exploited commercially for oil production, for
example in the Ekofisk Field where the generally low
permeability of a chalk matrix is enhanced by
fractures which increase the overall permeability.
In the great majority of rocks, the permeability
differs according to flow direction. In sedimentary
rocks the permeability is much higher parallel to the
bedding compared with normal to the bedding. Channel sandstones can also have a marked directional
impact on the permeability.
In well-cemented sandstones and limestones, and
also in certain shales, the matrix permeability is
extremely low and the effective permeability may be
mostly controlled by fractures if they are present.
Claystones and shales have very low permeability
and can be almost completely tight. In the laboratory
shale permeabilities as low as 0.01 nanodarcy have
been measured. Samples from cores or outcrops can
contain minute fissures formed in response to
unloading during retrieval to the surface and these
must be closed to replicate the in situ permeability
prior to unloading.
Most rocks are far from homogeneous. We may
measure the porosity and permeability of a hand specimen or core plug, but it is not certain that these are
representative of a larger volume. Fractures occur at
varying intervals, and range in size from large, open
joints down to microscopic cracks which can barely be
seen in a microscope.
Rocks with low porosity and permeability may
fracture and sufficiently increase their porosity, and
particularly permeability, to form large oil reservoirs.
This means that reservoirs may be good producers
despite relatively low porosity.
Occasionally we find petroleum in fractured metamorphic and igneous rocks but reservoirs normally
consist of sedimentary rocks. Sandstones make up
about 50–60% of the reservoirs in the world while
1 Introduction to Petroleum Geology
19
between these two values, typically around 40–42%.
Poorly sorted sand may have lower primary porosity
and will also compact more at moderate burial depths.
Clay-rich sediments have a much greater porosity
immediately after deposition, typically 60–80%. This
means that immediately following deposition a sand
bed is denser than a bed of clay or silt. However, clay
and silt lose their porosity more rapidly with burial.
Porosity may be classified into different types
depending on its origin.
Pore space between the primary sediment grains is
often referred to as primary porosity. Intergranular
porosity simply means porosity between the grains
whereas intragranular porosity means porosity inside
the sediment grains. The latter may be cavities in
fossils, e.g. foraminifera, gastropods, molluscs, but
also partly dissolved feldspar and rock fragments.
Pore space formed by dissolution or fracturing of
grains is called secondary porosity.
Cavities formed by selective solution of sediment
grains or fossils are classified as mouldic porosity. A
typical example is when dissolution of aragonite
fossils like gastropods leaves open pore spaces
(moulds).
Particularly in carbonates we may also have porosity on a large scale i.e. as caverns (karst) and in reefs.
Pore space produced by fracturing is called fracture
porosity.
Permeability is an expression of the ease with
which fluids flow through a rock. It will depend on
the size of the pore spaces in the rocks, and in particular the connections between the pore spaces. Even thin
cracks will contribute greatly to increasing the
permeability.
Permeability can be measured by letting a liquid or
gas flow through a cylindrical rock sample under pressure. The pressure difference P 1 À P 2 between the two
ends of a horizontal cylinder is ΔP, the cylinder length
L, and the flow rate of water (or another fluid) through
the cylinder, is Q (cm
3 /s). A is the cross-section and μ
the viscosity of the fluid
Q ¼
k Á A Á ΔP
L Á μ
where k is the permeability.
The volume of water which flows through each
surface unit in the cross-section A is thus equal to the
flux F ¼ Q=A. F can be measured in cm
3 /cm
2 /s or in
m
3 /m
2 /s. This is equal to the Darcy velocity which is
cm/s.
Well-sorted sandstones may have permeabilities
exceeding 1 Darcy and values between 100 and
1,000 mD are considered to be extremely good.
Permeabilities of 10–100 mD are also considered to
be good values for reservoir rocks. Permeabilities of
1–10 mD are typical of relatively dense sandstones
and limestones, so-called tight reservoirs. There are
also examples of rocks with even lower permeabilities
being exploited commercially for oil production, for
example in the Ekofisk Field where the generally low
permeability of a chalk matrix is enhanced by
fractures which increase the overall permeability.
In the great majority of rocks, the permeability
differs according to flow direction. In sedimentary
rocks the permeability is much higher parallel to the
bedding compared with normal to the bedding. Channel sandstones can also have a marked directional
impact on the permeability.
In well-cemented sandstones and limestones, and
also in certain shales, the matrix permeability is
extremely low and the effective permeability may be
mostly controlled by fractures if they are present.
Claystones and shales have very low permeability
and can be almost completely tight. In the laboratory
shale permeabilities as low as 0.01 nanodarcy have
been measured. Samples from cores or outcrops can
contain minute fissures formed in response to
unloading during retrieval to the surface and these
must be closed to replicate the in situ permeability
prior to unloading.
Most rocks are far from homogeneous. We may
measure the porosity and permeability of a hand specimen or core plug, but it is not certain that these are
representative of a larger volume. Fractures occur at
varying intervals, and range in size from large, open
joints down to microscopic cracks which can barely be
seen in a microscope.
Rocks with low porosity and permeability may
fracture and sufficiently increase their porosity, and
particularly permeability, to form large oil reservoirs.
This means that reservoirs may be good producers
despite relatively low porosity.
Occasionally we find petroleum in fractured metamorphic and igneous rocks but reservoirs normally
consist of sedimentary rocks. Sandstones make up
about 50–60% of the reservoirs in the world while
1 Introduction to Petroleum Geology
19