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Reservoirs and Reservoir Fluids
to exist as a very gentle incline. On occasion, part of an accumulation of the oil or gas has its lower
boundary marked, not by the water-bearing zone of the reservoir rock but by an adjacent sealing
rock that has characteristics similar to those of the cap rock. When the pressure and temperature
conditions are suitable in relation to the proportions and the nature of the gas and oil, there may be
no gas cap but only oil, with dissolved gas overlying the water.
Typically, heavy oil has an API gravity between 10° and 20° (Chapter 1), is more viscous than
conventional petroleum, and has the commonality of being, or ability to be, in the liquid state and,
therefore, has mobility in the reservoir. It can be recovered from a reservoir by the use of conventional (including enhanced) oil recovery techniques (Speight, 2009).
The water (brine) produced with oil has been trapped with the oil and is brought to the surface
along with oil. Because the water has been in contact with the oil, it contains some of the chemical characteristics of the formation and the oil itself. Oil and gas wells produce more water than
oil (7 bbl/1 bbl oil in some fields). The composition (salt content) of coproduced water determines
the need for anti-scaling additives. There are strict regulations to limit disposal and beneficial use
options as well as environmental impacts that pertain to oil field waters.
Reservoirs contain complex fluid mixtures whose behavior is strongly dependent on chemical
makeup. Heavy oil is a fluid that is also a multicomponent mixture composed of nonhydrocarbons
and a variety of hydrocarbons—especially of the alkane series. Typical hydrocarbons encountered
in heavy oil are the higher boiling hydrocarbons—the amount depending on the original source
materials and the maturation pathways; volatile hydrocarbons boiling lower than C 12 are not present
in a ready abundance.
Reservoir temperatures may vary up to 90°C or more, while surface conditions are around 20°C.
Pressure can vary from its atmospheric value (or lower in the case of vacuum distillation) to a number in the hundred million pascals (Pa). Within such an ample range of conditions, hydrocarbon
fluids undergo severe transformations and exist as a single phase (gas, liquid, or solid) or coexist in
several forms (liquid plus gas, solid plus liquid, vapor plus solid, or even in liquid plus liquid combinations). Understanding how hydrocarbon fluids interact with and react to their thermodynamic
surroundings is essential to adequately analyze systems of interest, and one of the most useful phase
behavior visualizations is the pressure–temperature (p–T) diagram or p–T envelope. Each envelope
represents a thermodynamic boundary separating the two-phase conditions (inside the envelope)
from the single-phase region (outside).
The correct identification of the type of hydrocarbon fluid is critical for the proper design and
development of the correct production strategy for the field under consideration. This identification
is critical for proper hydrocarbon reservoir modeling as well. When a fluid is assumed to behave as
heavy oil, it is assumed that its behavior is complex and selecting an appropriate model for behavior
becomes a limiting factor.
Reservoir fluids are brought to the surface as a mixture of oil, gas, and water, which is sent to
a surface production facility before they can be disposed or sold to an industrial costumer (e.g., a
refinery). A surface production facility is the system in charge of the separation of the well stream
fluids into its three single-phase components—oil, gas, and water—and of their transport and
processing into marketable products and/or their disposal in an environmentally acceptable manner. Once separated, the oil, natural gas, and water follow different paths. Water is typically reinjected for reservoir pressure maintenance operations. The oil usually goes through a process of
dehydration, which removes basic sediments and hydrocarbon fluids are assumed to comprise two
components—stock tank oil and surface gas.
4.4 EVALUATION OF RESERVOIR FLUIDS
Reservoir-fluid pressure–volume–temperature (PVT) properties are critical for efficient reservoir
management throughout the life of the reservoir, from discovery to abandonment (Honarpour et al.,
2006; Nagarajan et al., 2007). In fact, reliable data related to the properties of in situ fluids are essential
Reservoirs and Reservoir Fluids
to exist as a very gentle incline. On occasion, part of an accumulation of the oil or gas has its lower
boundary marked, not by the water-bearing zone of the reservoir rock but by an adjacent sealing
rock that has characteristics similar to those of the cap rock. When the pressure and temperature
conditions are suitable in relation to the proportions and the nature of the gas and oil, there may be
no gas cap but only oil, with dissolved gas overlying the water.
Typically, heavy oil has an API gravity between 10° and 20° (Chapter 1), is more viscous than
conventional petroleum, and has the commonality of being, or ability to be, in the liquid state and,
therefore, has mobility in the reservoir. It can be recovered from a reservoir by the use of conventional (including enhanced) oil recovery techniques (Speight, 2009).
The water (brine) produced with oil has been trapped with the oil and is brought to the surface
along with oil. Because the water has been in contact with the oil, it contains some of the chemical characteristics of the formation and the oil itself. Oil and gas wells produce more water than
oil (7 bbl/1 bbl oil in some fields). The composition (salt content) of coproduced water determines
the need for anti-scaling additives. There are strict regulations to limit disposal and beneficial use
options as well as environmental impacts that pertain to oil field waters.
Reservoirs contain complex fluid mixtures whose behavior is strongly dependent on chemical
makeup. Heavy oil is a fluid that is also a multicomponent mixture composed of nonhydrocarbons
and a variety of hydrocarbons—especially of the alkane series. Typical hydrocarbons encountered
in heavy oil are the higher boiling hydrocarbons—the amount depending on the original source
materials and the maturation pathways; volatile hydrocarbons boiling lower than C 12 are not present
in a ready abundance.
Reservoir temperatures may vary up to 90°C or more, while surface conditions are around 20°C.
Pressure can vary from its atmospheric value (or lower in the case of vacuum distillation) to a number in the hundred million pascals (Pa). Within such an ample range of conditions, hydrocarbon
fluids undergo severe transformations and exist as a single phase (gas, liquid, or solid) or coexist in
several forms (liquid plus gas, solid plus liquid, vapor plus solid, or even in liquid plus liquid combinations). Understanding how hydrocarbon fluids interact with and react to their thermodynamic
surroundings is essential to adequately analyze systems of interest, and one of the most useful phase
behavior visualizations is the pressure–temperature (p–T) diagram or p–T envelope. Each envelope
represents a thermodynamic boundary separating the two-phase conditions (inside the envelope)
from the single-phase region (outside).
The correct identification of the type of hydrocarbon fluid is critical for the proper design and
development of the correct production strategy for the field under consideration. This identification
is critical for proper hydrocarbon reservoir modeling as well. When a fluid is assumed to behave as
heavy oil, it is assumed that its behavior is complex and selecting an appropriate model for behavior
becomes a limiting factor.
Reservoir fluids are brought to the surface as a mixture of oil, gas, and water, which is sent to
a surface production facility before they can be disposed or sold to an industrial costumer (e.g., a
refinery). A surface production facility is the system in charge of the separation of the well stream
fluids into its three single-phase components—oil, gas, and water—and of their transport and
processing into marketable products and/or their disposal in an environmentally acceptable manner. Once separated, the oil, natural gas, and water follow different paths. Water is typically reinjected for reservoir pressure maintenance operations. The oil usually goes through a process of
dehydration, which removes basic sediments and hydrocarbon fluids are assumed to comprise two
components—stock tank oil and surface gas.
4.4 EVALUATION OF RESERVOIR FLUIDS
Reservoir-fluid pressure–volume–temperature (PVT) properties are critical for efficient reservoir
management throughout the life of the reservoir, from discovery to abandonment (Honarpour et al.,
2006; Nagarajan et al., 2007). In fact, reliable data related to the properties of in situ fluids are essential