82
The Chemistry and Technology of Petroleum
parameters influences the displacement profiles and disperses the flood front. It is more than likely
that wettability of the reservoir rock by heavy oil (particularly adsorption of the polar constituents)
can have major effects on heavy oil recovery.
Briefly, wettability of reservoirs rocks is the tendency of one fluid to spread on or adhere to a
solid surface in the presence of other immiscible fluids and is determined by complex interface
boundary conditions acting within the pore space of sedimentary rocks. In general, at least one
of the two immiscible fluids in a porous medium will be the wetting phase. When the system is in
equilibrium, the wetting fluid will completely occupy the smallest pores and be in contact with the
majority of the rock surface. The nonwetting fluid will occupy the center of the large pores and form
globules that extend over several pores. When the rock is water wet, there is a tendency for water to
occupy the small pores and to contact the majority of the rock surface. The term oil wet is referred to
the rock, which is preferentially in contact with the oil, and oil will occupy the small pores and contact the majority of the rock surface. The minerals present in reservoir rocks are generally known
as being intrinsically hydrophilic, that is, preferentially water-wet.
Wettability is generally considered to be one of the most important parameters influencing saturation, distribution, and flow of fluids in porous media. Knowledge of the wettability of reservoir
rock is important to petroleum engineers and geologists. For example, a waterflood on a strongly
oil-wet rock is much less efficient than one in water-wet rock (Anderson, 1986).
4.3 CLASSES OF FLUIDS
In order to produce a wellhead product from a reservoir there has to be flow of the fluids to the
wellbores through the heterogeneous porous media of the reservoir. Fluid movements within the
reservoir are governed by the local fluid potential gradients and reservoir effective permeability,
the injection and production points and the fluid viscosities. However, fluid flow is also governed
by the character of the fluids in the reservoir.
In the current context, reservoirs usually contain three main fluids: (1) natural gas, (2) oil, and
(3) water with minor constituents being acid gases (carbon dioxide and hydrogen sulfide). These
components will vary greatly in combination and proportion within each reservoir and in the case
of heavy oil, the amount of gas will be substantially less than would be found in a conventional oil
reservoir.
Reservoir fluids vary greatly in composition and chemical properties. The term fluid can mean
gaseous state or in the liquid state, and the fluids exist either as solid, liquid, or gas. Gas and liquids
coexist in a given reservoir.
The distribution of the fluids in a reservoir rock depends on the densities of the fluids as well as
on the properties of the rock. If the pores are of uniform size and evenly distributed, there is (1) an
upper zone where the pores are filled mainly by gas (the gas cap), (2) a middle zone in which the
pores are occupied principally by oil with gas in solution, and (3) a lower zone with its pores filled
by water. A certain amount of water (approximately 10%–30%) occurs along with the oil in the
middle zone. There is a transition zone from the pores occupied entirely by water to pores occupied
mainly by oil in the reservoir rock, and the thickness of this zone depends on the densities and interfacial tension of the oil and water as well as on the sizes of the pores. Similarly, there is some water
in the pores in the upper gas zone that has at its base a transition zone from pores occupied largely
by gas to pores filled mainly by oil.
The water found in the oil and gas zones is known generally as interstitial water and usually
occurs as collars around grain contacts, as a filling of pores with unusually small throats connecting with adjacent pores, or, to a much smaller extent, as wetting films on the surface of the mineral
grains when the rock is preferentially wet by water. The water may occur as wetting films, or collars,
around the sand grains as well as in some completely filled pores. The three-dimensional network
allows continuity to exist for the hydrocarbons by means of connections on every side of the sand
grains. The so-called gas–oil and oil–water contacts are generally horizontal but have been known
The Chemistry and Technology of Petroleum
parameters influences the displacement profiles and disperses the flood front. It is more than likely
that wettability of the reservoir rock by heavy oil (particularly adsorption of the polar constituents)
can have major effects on heavy oil recovery.
Briefly, wettability of reservoirs rocks is the tendency of one fluid to spread on or adhere to a
solid surface in the presence of other immiscible fluids and is determined by complex interface
boundary conditions acting within the pore space of sedimentary rocks. In general, at least one
of the two immiscible fluids in a porous medium will be the wetting phase. When the system is in
equilibrium, the wetting fluid will completely occupy the smallest pores and be in contact with the
majority of the rock surface. The nonwetting fluid will occupy the center of the large pores and form
globules that extend over several pores. When the rock is water wet, there is a tendency for water to
occupy the small pores and to contact the majority of the rock surface. The term oil wet is referred to
the rock, which is preferentially in contact with the oil, and oil will occupy the small pores and contact the majority of the rock surface. The minerals present in reservoir rocks are generally known
as being intrinsically hydrophilic, that is, preferentially water-wet.
Wettability is generally considered to be one of the most important parameters influencing saturation, distribution, and flow of fluids in porous media. Knowledge of the wettability of reservoir
rock is important to petroleum engineers and geologists. For example, a waterflood on a strongly
oil-wet rock is much less efficient than one in water-wet rock (Anderson, 1986).
4.3 CLASSES OF FLUIDS
In order to produce a wellhead product from a reservoir there has to be flow of the fluids to the
wellbores through the heterogeneous porous media of the reservoir. Fluid movements within the
reservoir are governed by the local fluid potential gradients and reservoir effective permeability,
the injection and production points and the fluid viscosities. However, fluid flow is also governed
by the character of the fluids in the reservoir.
In the current context, reservoirs usually contain three main fluids: (1) natural gas, (2) oil, and
(3) water with minor constituents being acid gases (carbon dioxide and hydrogen sulfide). These
components will vary greatly in combination and proportion within each reservoir and in the case
of heavy oil, the amount of gas will be substantially less than would be found in a conventional oil
reservoir.
Reservoir fluids vary greatly in composition and chemical properties. The term fluid can mean
gaseous state or in the liquid state, and the fluids exist either as solid, liquid, or gas. Gas and liquids
coexist in a given reservoir.
The distribution of the fluids in a reservoir rock depends on the densities of the fluids as well as
on the properties of the rock. If the pores are of uniform size and evenly distributed, there is (1) an
upper zone where the pores are filled mainly by gas (the gas cap), (2) a middle zone in which the
pores are occupied principally by oil with gas in solution, and (3) a lower zone with its pores filled
by water. A certain amount of water (approximately 10%–30%) occurs along with the oil in the
middle zone. There is a transition zone from the pores occupied entirely by water to pores occupied
mainly by oil in the reservoir rock, and the thickness of this zone depends on the densities and interfacial tension of the oil and water as well as on the sizes of the pores. Similarly, there is some water
in the pores in the upper gas zone that has at its base a transition zone from pores occupied largely
by gas to pores filled mainly by oil.
The water found in the oil and gas zones is known generally as interstitial water and usually
occurs as collars around grain contacts, as a filling of pores with unusually small throats connecting with adjacent pores, or, to a much smaller extent, as wetting films on the surface of the mineral
grains when the rock is preferentially wet by water. The water may occur as wetting films, or collars,
around the sand grains as well as in some completely filled pores. The three-dimensional network
allows continuity to exist for the hydrocarbons by means of connections on every side of the sand
grains. The so-called gas–oil and oil–water contacts are generally horizontal but have been known