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Reservoir Fluid Properties Course (1st Ed.)

1. Petroleum Engineering & Its Importance
2. Petroleum Formation
3. Petroleum Extraction
A. Drilling
B. Production

4. Consumption of Oil

2013 H. AlamiNia

Reservoir Fluid Properties Course: Petroleum Reservoir Fluids

2

1.
2.
3.
4.

Reservoir Fluids
Phase Behavior of Hydrocarbons
Phase Envelopes
HC Classifications

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Reservoir Fluid Constituents
Petroleum reservoir fluids are multicomponent
mixtures consisting primarily of hydrocarbons.
 Methane (CH4) is the simplest of all hydrocarbons, and
also the most common component in petroleum
reservoir fluids. Because methane contains one carbon
atom, it is often referred to as C1.
Hydrocarbons with seven and more carbon atoms are
called C7+ components, and the entity of all C7+
components is called the C7+ fraction.
Petroleum reservoir fluids may contain hydrocarbons as
heavy as C 200.

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C7+ Components
 A particular C7+ component will belong to one of the
following component classes:
 Paraffins: A paraffinic compound consists of hydrocarbon segments
of the type C, CH, CH 2, or CH 3. The carbon atoms are connected by
single bonds. Paraffins are also sometimes referred to as alkanes.
 Naphthenes: These compounds are similar to paraffins in the sense
that they are built of the same types of hydrocarbon segments, but
they differ from paraffins by containing one or more cyclic
structures. Naphthenes are also called cycloalkanes.
 Aromatics: Similar to naphthenes, aromatics contain one or more
cyclic structures, but the carbon atoms in an aromatic compound
are connected by aromatic double bonds.

 The percentage contents of paraffinic (P), naphthenic (N),
and aromatic (A) components in a reservoir fluid is often
referred to as the PNA distribution.
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Molecular Structures

Molecular Structures of Some
Petroleum Reservoir Fluid
Constituents

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Non HC Components
Petroleum reservoir fluids may also contain
inorganic compounds, of which
Nitrogen (N 2),
Carbon dioxide (CO 2),
And hydrogen sulfide (H 2 S)

Are the most common.
Water (H 2 O) is another important reservoir fluid
constituent. As water has limited miscibility with
hydrocarbons, most of the water in a reservoir is
usually found in a separate water zone located
beneath the gas and oil zones.
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Phase Behavior Definition
A "phase" is defined as any homogeneous part of a
system that is physically distinct and separated from
other parts of the system by definite boundaries.
For example, ice, liquid water, and water vapor
constitute three separate phases of the pure substance
H20.
Whether a substance exists in a solid, liquid, or gas
phase is determined by the temperature and pressure
acting on the substance.
It is known that ice (solid phase) can be changed to
water (liquid phase) by increasing its temperature and,
by further increasing temperature, water changes to
steam (vapor phase). This change in phases is termed
Phase Behavior.
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Properties of
Reservoir Fluid Constituents
The pure component vapor pressures and the pure
component critical points are essential in
calculations of component and mixture properties.
 The pure component vapor pressures are
experimentally determined by measuring
corresponding values of temperature (T) and
pressure (P) at which the substance undergoes a
transition from liquid to gas.

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Single-Component Systems
The simplest type of hydrocarbon system to
consider is that containing one component. The
word ''component'' refers to the number of
molecular or atomic species present in the
substance. A single-component system is composed
entirely of one kind of atom or molecule. We often
use the word "pure'' to describe a singlecomponent system.

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Qualitative Understanding
The qualitative understanding of the relationship
between temperature T, pressure p, and volume V
of pure components can provide an excellent basis
for understanding the phase behavior of complex
petroleum mixtures.
The foregoing relationship is conveniently
introduced in terms of experimental measurements
conducted on a pure component as the component
is subjected to changes in pressure and volume at
constant temperature.
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P-V Diagram for
a Single Component System

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Isothermal Paths
Suppose a fixed quantity of a pure component is
placed in a cylinder fitted with a frictionless piston
at a fixed temperature T 1. Consider the initial p
exerted on the system to be low enough that the
entire system is in the vapor state (E).
Step 1. The pressure is increased isothermally (F).
On the diagram, where the liquid begins to condense.
The corresponding pressure is known as the dew-point
pressure Pd, and is defined as the pressure at which the
first droplet of liquid is formed.

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Isothermal Paths (Cont.)
Step 2. The piston is moved further into the cylinder as more
liquid condenses. This condensation process is characterized
by a constant pressure and represented by the horizontal
line FG.
At point G, traces of gas remain and the corresponding
pressure is called the bubble-point pressure Pb, and defined
as the pressure at which the first sign of gas formation is
detected.
A characteristic of a single-component system is that at a
given temperature, the dew-point pressure and the bubblepoint pressure are equal.
Step 3. As the piston is forced slightly into the cylinder, a
sharp increase in the pressure (point H) is noted without an
appreciable decrease in the liquid volume. That behavior
evidently reflects the low compressibility of the liquid phase.
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Isothermal Paths (Cont.)
By repeating the above steps at progressively
increasing temperatures, a family of curves of equal
temperatures (isotherms) is constructed.
The dashed curve connecting the dew points is called
the dew-point curve (line FC) and represents the states
of the ''saturated gas."
The dashed curve connecting the bubble points is called
the bubble-point curve (line GC) and similarly represents
the "saturated liquid."
These two curves meet at point C which is known as the
critical point. The corresponding pressure and volume
are called the critical pressure Pc and critical volume V,
respectively.
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P-T Diagram for
a Pure Component System.

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Binary Systems
(Two-Component Systems)
Methane and benzene, both common constituents
of oil and gas mixtures.
 The vapor pressure curve ends in the critical point
(CP), above which no liquid- to gas-phase transition
can take place.
Vapor pressure curves of methane and benzene
(full-drawn line). Phase envelope (dashed line) of a
mixture of 25 mol% methane and 75 mol% benzene
calculated using the Soave–Redlich–Kwong
equation of state.
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Vapor Pressure Curves of
Methane and Benzene

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The Phase Behavior of
a Pure Component
At a given temperature, T 1, may be studied by placing
a fixed amount of this component in a cell kept at the
temperature T 1. The cell volume may be varied by
moving the piston up and down.
At position A, the cell content is in a gaseous state. If the
piston is moved downwards, the volume will decrease and the
pressure increase.
At position B a liquid phase starts to form.
 By moving the piston further downwards, the volume will
further decrease, but the pressure will remain constant until
all gas is converted into liquid. This happens at position C.
 A further decrease in the cell volume will result in a rapidly
increasing pressure.
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Pure Component Phase Behavior
in PT and PV Diagrams

Related to previous and next slides.

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The Phase Behavior of
a Pure Component (Cont.)
The left-hand-side curve illustrates the phase changes
when crossing a vapor pressure curve. A pure
component can only exist in the form of two phases in
equilibrium right at the vapor pressure curve.
When the vapor pressure curve is reached, a
conversion from either gas to liquid or liquid to gas will
start. This phase transition is associated with volumetric
changes at constant T and P.
 At the point B the component is said to be at its dew point or
in the form of a saturated gas.
 At position C the component is at its bubble point or in the
form of a saturated liquid.
At position A the state is undersaturated gas, and at D it is
undersaturated liquid.

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Phase Envelopes
Petroleum reservoir fluids are multicomponent
mixtures, and it is therefore of much interest to look for
the mixture equivalent of the pure component vapor
pressure curve.
With two or more components present, the two-phase
region is not restricted to a single line in a PT diagram.
 As is illustrated for a mixture of 25 mol% methane and
75 mol% benzene, the two-phase region of a mixture
forms a closed area in P and T.
The line surrounding this area is called the phase
envelope.
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Composition of Natural Gas Mixture

The phase envelope has been
calculated using the Soave–Redlich–
Kwong equation of state

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Phase Envelopes (Cont.)
Next slide shows the phase envelope of a natural gas
mixture of the composition given in previous slide.
 The phase envelope consists of a dew point branch and
a bubble point branch meeting in the mixture critical
point.
At the dew point branch the mixture is in gaseous form
in equilibrium with an incipient amount of liquid. At
these conditions the gas (or vapor) is said to be
saturated.
 At higher temperatures at the same pressure, there is
no liquid present.
On the contrary, the gas may take up liquid
components without liquid precipitation taking place.
The gas is therefore said to be undersaturated.
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Phase Envelope of Natural Gas

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At the bubble point branch the mixture is in liquid form
in equilibrium with an incipient amount of gas, and the
liquid is said to be saturated.
At lower temperatures, at the same pressure the liquid
(or oil) is undersaturated.
Right at the critical point, two identical phases are in
equilibrium, both having a composition equal to the
overall composition.
 At temperatures close to the critical one and pressures
above the critical pressure there is only one phase
present, but it can be difficult to tell whether it is a gas
or a liquid. This term super-critical fluid is often used
the super-critical region.
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 The highest pressure at which two phases can exist is
called the cricondenbar and the highest temperature
with two phases present is called the cricondentherm.
 The phenomenon called retrograde condensation is as
a dashed vertical line at T = -30°C. At this temperature,
the mixture is in gaseous form at pressures above the
upper dew point pressure, i.e., at pressures above
approximately 75 bar.
At lower pressure, the mixture will split into two
phases, a gas and a liquid. Liquid formation taking place
as the result of a falling pressure is called retrograde
condensation. If the pressure at a constant temperature
is decreased to below the lower dew point pressure of
approximately 15 bar, the liquid phase will disappear,
and all the mixture will be in gaseous form again.
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Classification of Reservoirs
Reservoirs can be classified into essentially two
types.
Oil reservoirs: If the reservoir temperature T is less than
the critical temperature Tc of the reservoir fluid, the
reservoir is classified as an oil reservoir.
Gas reservoirs: If the reservoir temperature is greater
than the critical temperature of the hydrocarbon fluid,
the reservoir is considered a gas reservoir.

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Oil Reservoirs
Depending upon initial reservoir pressure pi, oil
reservoirs can be sub classified into the following
categories:
Undersaturated Oil Reservoir: If the initial reservoir
pressure Pi, is greater than the bubble-point pressure Pb
of the reservoir fluid
Saturated Oil Reservoir: When the initial reservoir
pressure is equal to the bubble-point pressure of the
reservoir fluid
Gas-cap Reservoir: If the initial reservoir pressure is
below the bubble point pressure of the reservoir fluid.
The ratio of the gas-cap volume to reservoir oil volume is
given by the appropriate quality line.
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Typical P-T Diagram

Typical P-T Diagram for a MultiComponent System (Oil Reservoir)

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Gas Reservoirs
Natural gases can be categorized on the basis of
their phase diagram and the prevailing reservoir
condition into four categories:
Retrograde gas-condensate
Near-critical gas-condensate
Wet gas
Dry gas

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P-T Diagram for a Wet Gas Reservoir

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A Typical P-T Diagram

A Typical P-T Diagram
for Dry Gas Reservoir

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Classification of
Petroleum Reservoir Fluids
Petroleum reservoir fluids may be divided into:
Natural gas mixtures
(Dry and wet gas)

Gas condensate mixtures
Near-critical mixtures or volatile oils
(Low-shrinkage, High-shrinkage (volatile) and Near-critical
crude oil)

(Ordinary) Black oils

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Classification Base
The various fluid types are distinguished by the
location of the mixture-critical temperature relative
to the reservoir temperature. The above
classification is essentially based upon the
properties exhibited by the crude oil, including:
Physical properties
Composition
Gas-oil ratio
Appearance
Pressure-temperature phase diagram
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Exercise
Determine mentioned properties for each type of
oil and gas reservoirs.

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Phase Envelope of
Various Types of Reservoir Fluids

The phase envelopes have been
constructed using the Peng–
Robinson equation of state

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Tracking P & T during
Production in Gas Reservoirs
During production from a reservoir, the temperature
remains approximately constant at the initial reservoir
temperature, Tres, whereas the pressure decreases as a
result of material being removed from the reservoir.
For a natural gas, this pressure decrease will have no
impact on the number of phases. The gas will remain a
single phase at all pressures.
 For a gas condensate, a decreasing pressure will at
some stage lead to the formation of a second phase.
This happens when the pressure reaches the dew point
branch at the temperature Tres. The second phase
forming will be a liquid phase, a phase of a higher
density than the original phase.
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Composition of
Gas Condensate Mixture

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Production in Near-Critical Mixture
 With a near-critical mixture, a pressure decrease will
also at some stage lead to the formation of a second
phase. If the reservoir temperature is Tres, the second
phase will be a gas phase, because the point at which
the phase envelope is reached is on the bubble point
branch. Such a mixture will be classified as a volatile oil.
 Had the reservoir temperature been slightly higher as
indicated by T'res, the entry into the two-phase region
would take place at the dew point branch, and the
mixture would be classified as a gas condensate
mixture.
Near-critical reservoir fluids are mixtures with critical
temperatures close to the reservoir temperature. Right
inside the phase envelope the gas- and liquid-phase
compositions and properties are similar.
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Composition of Near-Critical Mixture

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Close-Up of the Near-Critical Region
Next slide shows a close-up of the near-critical
region of a Chinese reservoir fluid (Yang et al.,
1997).
It illustrates the fact that the relative volumetric
amounts of gas and liquid change rapidly with
pressure and temperature in the vicinity of the CP.
For example, at a temperature of 100°C only a
marginal change in pressure is needed to change
the liquid-phase amount from 50 to 100 vol%.

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Near-Critical Part of Phase Envelope

The values stated are liquid volume
percentages. CP stands for critical
point.

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Production in Oil Reservoirs
Finally with black oils, entry into the two-phase
region at the reservoir temperature will always take
place at the bubble point side and, accordingly, the
new phase forming is a gas.

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Composition of Oil Mixture

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1.
2.
3.
4.

Samples
Sample Analysis
Samples Quality Control
K-Factor as A QC

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1. Pedersen, K.S., Christensen, P.L., and Azeem,
S.J. (2006). Phase behavior of petroleum
reservoir fluids (CRC Press). Ch1.
2. Tarek, A. (1989). Hydrocarbon Phase Behavior
(Gulf Publishing Company, Houston). Ch1.

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Q913 rfp w1 lec 2

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