Kaolinite has very low solubility in water, and strong
acid (HF) is required to dissolve it. Kaolinite is therefore
chemically stable and its ion exchange capacity is lower
than that of other clay minerals. Chlorite, on the other
hand, is soluble in acids such as HCL. If acid is used to
dissolve minerals like chlorides in order to increase the
permeability around the well, it is important to avoid iron
being precipitated as iron hydroxide (Fe(OH) 3 ). This
could reduce the porosity very severely because it
forms pore-filling cement. To avoid this, one can add
chemicals which form complexes with iron (e.g. citrate).
Illite and smectite are not very soluble in HCL, and
hydrofluoric acid (HF) must be added to dissolve these
minerals. They are sensitive to variations in salinity
and in particular to the K
+ content. K
+ and other alkali
ions will be held in the interlayer position in smectite
so that water is expelled and the mineral contracts in
volume. On the other hand, injection of fresh or
slightly saline water into a reservoir may lead to
uptake of water and expansion of smectite and mixed
layer minerals, which may greatly reduce the porosity.
Sodium smectites can swell to 5–10 times their original volume. Swelling can be reduced by injecting
dilute acid (HCl) or water with a high salinity (e.g.
KCl). Water is also often injected to maintain reservoir
pressure. Offshore drilling platforms in particular
depend on using seawater. However, seawater may
have adverse effects on the reservoir. The high
sulphate concentration in seawater may cause precipitation of baryte (BaSO 4 ) which is the least soluble of
the common sulphate minerals. Seawater also contains
sulphate-reducing bacteria which will start to reduce
SO
2À
4 to H 2 S in the reservoir. This is most undesirable
since H 2 S is a very poisonous gas which also has a
highly corrosive effect on steel during production.
To avoid unforeseen chemical damage to the reservoir rock, it is necessary to carry out very thorough
mineralogical analyses so as to be able to predict the
effect of various types of chemical stimulation.
Physical damage to the reservoir, as previously mentioned, is due to mineral grains being loosened and
carried by oil and water, eventually clogging the flow
paths. If the reservoir is water-wet, fine-grained
minerals will tend to remain suspended in the aqueous
phase, and will not come into the oil phase very easily
because of surface tension. When considerable
quantities of water are produced together with oil,
therefore, the aqueous phase is particularly likely to
carry clay minerals and other small mineral particles,
for example of quartz and felspar, which may block the
pore throats. This effect can be reduced by lowering the
production rate. In the laboratory this type of mechanical formation damage can be tested in an experimental
flow rig. If the measured permeability increases temporarily when the flow direction is reversed, formation
damage has been caused by “a moving clay and silt
fraction”. Sandstones with a high percentage of secondary porosity will have relatively large pores with small
pore throats. The ratio between the pore diameter and
the pore throat is often referred to as the aspect ratio.
Pores with high aspect ratios will be particularly vulnerable to mechanical formation damage. Pore geometry is also important with respect to two-phase flow (oil
and water) because of the capillary forces that have to
be overcome in the pore throats. This is even more the
case with condensate reservoirs, where we may have
three phases (oil, gas, water).
The planning of production from a reservoir
involves a detailed production strategy and optimal
positioning of production and injection wells. The
trend production will take with time is simulated on
extremely powerful computers which are fed with a
very large number of parameters relating to the reservoir. Simulations depend very heavily on the geometry
of the reservoir and internal communication, e.g.
between sandstone bodies, the exact position of the
sealing fault, etc. The internal properties of the reservoir can be measured on cores from the wells, but a
three-dimensional representation of the distribution of
porosity and permeability and the pore geometry must
be constructed, using models for the detailed depositional environment and diagenetic alteration.
It may now be possible to follow fluid flow within
the reservoir compartments during production using
4D time-lapse seismic data (Lynn et al. 2014).
21.12 Carbonate Reservoirs and
Fractured Reservoirs
Many of the same principles apply to carbonate
reservoirs as apply to sandstones. There is a tendency
for carbonate reservoirs to be less water-wet than sandstone reservoirs, but this depends on the composition of
the oil and on the temperature and pressure. Pores often
have a high aspect ratio, particularly in limestones
where we often have intragranular porosity inside
fossils or vuggy mouldic porosity after selective dissolution of organic fossils. The reservoir properties of
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K. Bjørlykke
acid (HF) is required to dissolve it. Kaolinite is therefore
chemically stable and its ion exchange capacity is lower
than that of other clay minerals. Chlorite, on the other
hand, is soluble in acids such as HCL. If acid is used to
dissolve minerals like chlorides in order to increase the
permeability around the well, it is important to avoid iron
being precipitated as iron hydroxide (Fe(OH) 3 ). This
could reduce the porosity very severely because it
forms pore-filling cement. To avoid this, one can add
chemicals which form complexes with iron (e.g. citrate).
Illite and smectite are not very soluble in HCL, and
hydrofluoric acid (HF) must be added to dissolve these
minerals. They are sensitive to variations in salinity
and in particular to the K
+ content. K
+ and other alkali
ions will be held in the interlayer position in smectite
so that water is expelled and the mineral contracts in
volume. On the other hand, injection of fresh or
slightly saline water into a reservoir may lead to
uptake of water and expansion of smectite and mixed
layer minerals, which may greatly reduce the porosity.
Sodium smectites can swell to 5–10 times their original volume. Swelling can be reduced by injecting
dilute acid (HCl) or water with a high salinity (e.g.
KCl). Water is also often injected to maintain reservoir
pressure. Offshore drilling platforms in particular
depend on using seawater. However, seawater may
have adverse effects on the reservoir. The high
sulphate concentration in seawater may cause precipitation of baryte (BaSO 4 ) which is the least soluble of
the common sulphate minerals. Seawater also contains
sulphate-reducing bacteria which will start to reduce
SO
2À
4 to H 2 S in the reservoir. This is most undesirable
since H 2 S is a very poisonous gas which also has a
highly corrosive effect on steel during production.
To avoid unforeseen chemical damage to the reservoir rock, it is necessary to carry out very thorough
mineralogical analyses so as to be able to predict the
effect of various types of chemical stimulation.
Physical damage to the reservoir, as previously mentioned, is due to mineral grains being loosened and
carried by oil and water, eventually clogging the flow
paths. If the reservoir is water-wet, fine-grained
minerals will tend to remain suspended in the aqueous
phase, and will not come into the oil phase very easily
because of surface tension. When considerable
quantities of water are produced together with oil,
therefore, the aqueous phase is particularly likely to
carry clay minerals and other small mineral particles,
for example of quartz and felspar, which may block the
pore throats. This effect can be reduced by lowering the
production rate. In the laboratory this type of mechanical formation damage can be tested in an experimental
flow rig. If the measured permeability increases temporarily when the flow direction is reversed, formation
damage has been caused by “a moving clay and silt
fraction”. Sandstones with a high percentage of secondary porosity will have relatively large pores with small
pore throats. The ratio between the pore diameter and
the pore throat is often referred to as the aspect ratio.
Pores with high aspect ratios will be particularly vulnerable to mechanical formation damage. Pore geometry is also important with respect to two-phase flow (oil
and water) because of the capillary forces that have to
be overcome in the pore throats. This is even more the
case with condensate reservoirs, where we may have
three phases (oil, gas, water).
The planning of production from a reservoir
involves a detailed production strategy and optimal
positioning of production and injection wells. The
trend production will take with time is simulated on
extremely powerful computers which are fed with a
very large number of parameters relating to the reservoir. Simulations depend very heavily on the geometry
of the reservoir and internal communication, e.g.
between sandstone bodies, the exact position of the
sealing fault, etc. The internal properties of the reservoir can be measured on cores from the wells, but a
three-dimensional representation of the distribution of
porosity and permeability and the pore geometry must
be constructed, using models for the detailed depositional environment and diagenetic alteration.
It may now be possible to follow fluid flow within
the reservoir compartments during production using
4D time-lapse seismic data (Lynn et al. 2014).
21.12 Carbonate Reservoirs and
Fractured Reservoirs
Many of the same principles apply to carbonate
reservoirs as apply to sandstones. There is a tendency
for carbonate reservoirs to be less water-wet than sandstone reservoirs, but this depends on the composition of
the oil and on the temperature and pressure. Pores often
have a high aspect ratio, particularly in limestones
where we often have intragranular porosity inside
fossils or vuggy mouldic porosity after selective dissolution of organic fossils. The reservoir properties of
556
K. Bjørlykke