Q922+rfp+l02 v1

Reservoir Fluid Properties Course (3rd Ed.)

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About This Course
Syllabus
Resources
Training Outline (Beta)

1. Reservoir Fluid Behaviors
2. Petroleum Reservoirs
A. Oil
B. Gas

3. Introduction to Physical Properties
A. heavy fractions

Multiphase Behavior
Naturally occurring hydrocarbon systems found in
petroleum reservoirs are mixtures of organic
compounds that exhibit multiphase behavior over
wide ranges of pressures and temperatures.
These hydrocarbon accumulations may occur in the
gaseous state, the liquid state, the solid state, or in
various combinations of gas, liquid, and solid.

Spring14 H. AlamiNia


5

Petroleum Engineers Task
These differences in phase behavior, coupled with
the physical properties of reservoir rock that
determine the relative ease with which gas and
liquid are transmitted or retained, result in many
diverse types of hydrocarbon reservoirs with
complex behaviors.
Frequently, petroleum engineers have the task to
study the behavior and characteristics of a
petroleum reservoir and to determine the course of
future development and production that would
maximize the profit.


6

Classification of Reservoirs and
Reservoir Fluids
Petroleum reservoirs are broadly classified as oil or gas
reservoirs. These broad classifications are further
subdivided depending on:
The composition of the reservoir hydrocarbon mixture
Initial reservoir pressure and temperature
Pressure and temperature of the surface production

The conditions under which these phases exist are a
matter of considerable practical importance.
The experimental or the mathematical determinations
of these conditions are conveniently expressed in
different types of diagrams commonly called phase
diagrams. One such diagram is called the pressuretemperature diagram.


7

Pressure-Temperature Diagram
Although a different hydrocarbon system would
have a different phase diagram, the general
configuration is similar.
These multicomponent pressure-temperature
diagrams are essentially used to:
Classify reservoirs
Classify the naturally occurring hydrocarbon systems
Describe the phase behavior of the reservoir fluid



8

Typical P-T Diagram
for a Multicomponent System

Binary Component



9

key points on P-T diagrams
To fully understand the
significance of the pressuretemperature diagrams,
it is necessary to identify and
define the following key
points on these diagrams:
 Cricondentherm (Tct)
 The Cricondentherm is defined
as the maximum temperature
above which liquid cannot be
formed regardless of pressure.
The corresponding pressure is
termed the Cricondentherm
pressure pct.

 Cricondenbar (pcb)

which no gas can be formed
regardless of temperature. The
corresponding temperature is
called the Cricondenbar
temperature Tcb.

 Critical point
 The critical point for a
multicomponent mixture is
referred to as the state of
pressure and temperature at
which all intensive properties
of the gas and liquid phases
are equal. At the critical point,
the corresponding pressure
and temperature are called the
critical pressure pc and critical
temperature Tc of the mixture.

 The Cricondenbar is the
maximum pressure above



10

key points on P-T diagrams (Cont.)
Phase envelope
(two-phase region)
The region enclosed by
the bubble- point curve
and the dew-point curve,
wherein gas and liquid
coexist in equilibrium, is
identified as the phase
envelope of the
hydrocarbon system.

Quality lines
The dashed lines within
the phase diagram are
called quality lines. They
describe the pressure and
temperature conditions

for equal volumes of
liquids. Note that the
quality lines converge at
the critical point.

Bubble-point curve
The bubble-point curve is
defined as the line
separating the liquidphase region from the
two-phase region.

Dew-point curve
The dew-point curve is
defined as the line
separating the vaporphase region from the
two-phase region.


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Oil vs. Gas Reservoirs
In general, reservoirs are conveniently classified on
the basis of the location of the point representing
the initial reservoir pressure pi and temperature T
with respect to the pressure-temperature diagram
of the reservoir fluid. Accordingly, reservoirs can be
classified into basically two types. These are:
Oil reservoirs
If the Tr is less than the Tc of the reservoir fluid

Gas reservoirs
If the Tr is greater than the Tc of the hydrocarbon fluid


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Oil Reservoirs
Depending upon initial reservoir pressure pi, oil
reservoirs can be subclassified into the following
categories:
Undersaturated oil reservoir.
If the initial reservoir pressure pi, is greater than the bubblepoint pressure Pb of the reservoir fluid

Saturated oil reservoir.
When pi is equal to the bubble-point pressure of the reservoir
fluid

Gas-cap reservoir or two-phase reservoir.
If pi is below the bubble point pressure of the reservoir fluid
The appropriate quality line gives the ratio of the gas-cap
volume to reservoir oil volume.



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Crude Oils
Crude oils cover a wide range in physical properties and
chemical compositions, and it is often important to be
able to group them into broad categories of related oils.
In general, crude oils are commonly classified into the
following types:
Ordinary black oil
Low-shrinkage crude oil
High-shrinkage (volatile) crude oil
Near-critical crude oil

The above classifications are essentially based upon the
properties exhibited by the crude oil, including physical
properties, composition, gas-oil ratio, appearance, and
pressure-temperature phase diagrams.


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Ordinary black oil
quality lines, which are approximately equally spaced,
characterize this black oil phase diagram.
Following the pressure reduction path as indicated by
the vertical line EF on next figure, the liquid shrinkage
curve, is prepared by plotting the liquid volume percent
as a function of pressure.
The liquid shrinkage curve approximates a straight line except
at very low pressures.

When produced, ordinary black oils usually yield gas-oil
ratios between 200 and 700 scf/STB and
oil gravities of 15° to 40° API
The stock tank oil is usually brown to dark green


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Ordinary Black Oil

A typical p-T diagram for an ordinary black
Liquid-shrinkage curve for black oil
oil
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Low-shrinkage oil
The diagram is characterized by quality lines that
are closely spaced near the dew-point curve.
The other associated properties of this type of
crude oil are:
Oil formation volume factor less than 1.2 bbl/STB
Gas-oil ratio less than 200 scf/STB
Oil gravity less than 35° API
Black or deeply colored
Substantial liquid recovery at separator conditions as
indicated by point G on the 85% quality line of next slide



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Low-Shrinkage Oil

A typical phase diagram for a low-shrinkage
Oil-shrinkage curve for low-shrinkage oil
oil
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Volatile (high-shrinkage) crude oil
Note that the quality lines are close together near the
bubble-point and are more widely spaced at lower
pressures.
This type of crude oil is commonly characterized by a
high liquid shrinkage immediately below the bubblepoint as shown in next Figure.
The other characteristic properties of this oil include:

Oil formation volume factor less than 2 bbl/STB
Gas-oil ratios between 2,000 and 3,200 scf/STB
Oil gravities between 45° and 55° API
Lower liquid recovery of separator conditions (10% next slide)
Greenish to orange in color
the API gravity of the stock-tank liquid will increase in the
later life of the reservoirs



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Volatile Crude Oil

A typical p-T diagram for a volatile crude oil


A typical liquid-shrinkage curve for a volatile
crude oil
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Near-critical crude oil
If the Tr is near the Tc of the hydrocarbon system, the
hydrocarbon mixture is identified as a near-critical
crude oil.
Because all the quality lines converge at the critical
point,

an isothermal pressure drop may shrink the crude oil from
100% of the hydrocarbon pore volume at the bubble-point to
55% or less at a pressure 10 to 50 psi below the bubble point.

a high GOR in excess of 3,000 scf/STB
an oil formation volume factor of 2.0 bbl/STB or higher
The compositions of near-critical oils are usually
characterized by 12.5 to 20 mol% heptanes-plus, 35% or
more of ethane through hexanes, and the remainder
methane.


22

Near-Critical Crude Oil

A schematic phase diagram for the nearA typical liquid-shrinkage curve for the nearcritical crude Reservoir Fluid Properties Course (3rdcrude oil
critical Ed.)
Spring14 H. AlamiNia oil
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Liquid Shrinkage for Crude Oil Systems



24

Gas Reservoirs
In general, if the reservoir temperature is above the
critical temperature of the hydrocarbon system, the
reservoir is classified as a natural gas reservoir.
On the basis of their phase diagrams and the
prevailing reservoir conditions, natural gases can be
classified into four categories:
Retrograde gas-condensate
Near-critical gas-condensate
Wet gas
Dry gas



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Retrograde gas-condensate reservoir
If the Tr lies between the Tc and Tct of the reservoir
fluid, the reservoir is classified as a retrograde gas
condensate reservoir.
This category of gas reservoir is a unique type of
hydrocarbon accumulation in that the special
thermodynamic behavior of the reservoir fluid is the
controlling factor in the development and the depletion
process of the reservoir.

When the pressure is decreased on these mixtures,
instead of expanding (if a gas) or vaporizing (if a
liquid) as might be expected, they vaporize instead
of condensing.


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Retrograde Gas-Condensate

A typical phase
diagram of a
retrograde
system


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Retrograde Gas-Condensate reservoirs
In most gas-condensate
reservoirs, the condensed liquid
volume seldom exceeds more
than 15% to 19% of the pore
volume.
This liquid saturation is not large
enough to allow any liquid flow.
It should be recognized, however,
that around the wellbore where
the pressure drop is high, enough
A typical liquid dropout curve
liquid dropout might accumulate
(liquid shrinkage volume curve to give two-phase flow of gas and
for a condensate system)
retrograde liquid.


30

Retrograde Gas-Condensate
The associated physical characteristics of this category
are:
Gas-oil ratios between 8,000 and 70,000 scf/STB.
Generally, the GOR for a condensate system increases with time
due to the liquid dropout and the loss of heavy components in the
liquid.

Condensate gravity above 50° API
• Stock-tank liquid is usually water-white or slightly colored

There is a fairly sharp dividing line between oils and
condensates from a compositional standpoint.
Reservoir fluids that contain heptanes and are heavier
in concentrations of more than 12.5 mol% are almost
always in the liquid phase in the reservoir.


31

Near-critical gas-condensate reservoir
If the Tr is near the Tc, the hydrocarbon mixture is
classified as a near-critical gas-condensate.
Because all the quality lines converge at the critical
point, a rapid liquid buildup will immediately occur
below the dew point.
This behavior can be justified by the fact that several
quality lines are crossed very rapidly by the isothermal
reduction in pressure.
At the point where the liquid ceases to build up and
begins to shrink again, the reservoir goes from the
retrograde region to a normal vaporization region.


32

Near-Critical Gas-Condensate

A typical phase diagram for a near-critical
Liquid-shrinkage curve for a near-critical gascondensate system
Spring14 gas AlamiNia reservoir
H. condensate Reservoir Fluid Properties Course (3rd Ed.)
33

Wet-gas reservoir
In a wet gas reservoir temperature is above the
cricondentherm of the hydrocarbon mixture.

Because the reservoir temperature exceeds the
cricondentherm of the hydrocarbon system, the reservoir
fluid will always remain in the vapor phase region as the
reservoir is depleted isothermally, along the vertical line A-B.

As the produced gas flows to the surface, however, the
pressure and temperature of the gas will decline.

If the gas enters the two-phase region, a liquid phase will
condense out of the gas and be produced from the surface
separators.
This is caused by a sufficient decrease in the kinetic energy of
heavy molecules with temperature drop and their subsequent
change to liquid through the attractive forces between
molecules.



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Wet-gas reservoirs characterization
Wet-gas reservoirs are characterized by the
following properties:
Gas oil ratios between 60,000 and 100,000 scf/STB
Stock-tank oil gravity above 60° API
Liquid is water-white in color
Separator conditions, i.e., separator pressure and
temperature, lie within the two-phase region



35

Wet Gas

Phase diagram
for a wet gas


36

Dry-gas reservoir
The hydrocarbon mixture exists as a gas both in the
reservoir and in the surface facilities.
The only liquid associated with the gas from a drygas reservoir is water.
Usually a system having a gas-oil ratio greater than
100,000 scf/STB is considered to be a dry gas.
Kinetic energy of the mixture is so high and
attraction between molecules so small that none of
them coalesces to a liquid at stock-tank conditions
of temperature and pressure.


37

Dry Gas

Phase diagram
for a dry gas


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Other hydrocarbon classifications
The classification of hydrocarbon fluids might also
be characterized by the initial composition of the
system.
McCain (1994) suggested that the heavy components in
the hydrocarbon mixtures have the strongest effect on
fluid characteristics.
The ternary diagram, with equilateral triangles can be
conveniently used to roughly define the compositional
boundaries that separate different types of hydrocarbon
systems.



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Compositions of
Various Reservoir Fluid Types



41

Qualitative concepts vs. quantitative
analyses
it can be observed that hydrocarbon mixtures may
exist in either the gaseous or liquid state,
depending on the reservoir and
operating conditions to which they are subjected.

The qualitative concepts presented may be of aid in
developing quantitative analyses.
Empirical equations of state are commonly used as
a quantitative tool in describing and classifying the
hydrocarbon system.



42

Empirical equations of state
Equations of state require:
Detailed compositional analyses of the hydrocarbon
system
Complete descriptions of the physical and critical
properties of the mixture individual components
Many characteristic properties of these individual components
(in other words, pure substances) have been measured and
compiled over the years.



43

Characteristic properties
Characteristic properties provide vital information for
calculating the thermodynamic properties of pure
components, as well as their mixtures.
The most important of these properties are:
Critical pressure, pc
Critical temperature, Tc
Critical volume, Vc
Critical compressibility factor, zc
Acentric factor, T
Molecular weight, M

Next slide documents some of the above-listed
properties for a number of hydrocarbon and
nonhydrocarbon components.


44

Physical Properties for Pure
Components



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Undefined Petroleum Fractions
Nearly all naturally occurring hydrocarbon systems
contain a quantity of heavy fractions that are not
well defined and are not mixtures of discretely
identified components.
These heavy fractions are often lumped together and
identified as the plus fraction, e.g., C7+ fraction.

A proper description of the physical properties of
the plus fractions and other undefined petroleum
fractions in hydrocarbon mixtures is essential in
performing reliable phase behavior calculations and
compositional modeling studies.


47

Undefined Petroleum Fractions
Analysis
Frequently, a distillation analysis or a
chromatographic analysis is available for this
undefined fraction.
Other physical properties, such as
molecular weight and specific gravity,
may also be measured
for the entire fraction or
for various cuts of it.



48

Using the thermodynamic propertyprediction models
To use any of
the thermodynamic property-prediction models,
e.g., equation of state,
to predict the phase and volumetric behavior
of complex hydrocarbon mixtures,
one must be able to provide
the acentric factor, along with
the critical temperature and critical pressure,
for both the defined and
undefined (heavy) fractions in the mixture.



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physical property prediction
Riazi and Daubert (1987) developed a simple twoparameter equation for predicting the physical
properties of pure compounds and undefined
hydrocarbon mixtures.
θ = a (M)^b γ^c EXP [d (M) + e γ + f (M) γ]

based on the use of the M and γ of the undefined petroleum
fraction as the correlating parameters.

Where

θ = any physical property
•
•
•
•

Tc = critical temperature, °R
Pc = critical pressure, psia
Tb = boiling point temperature, °R
Vc = critical volume, ft3/lb

a–f = constants for each property
γ = specific gravity of the fraction
M = molecular weight


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1. Ahmed, T. (2010). Reservoir engineering
handbook (Gulf Professional Publishing).
Chapter 1

1. Gas Behavior
2. Gas Properties:
A. Z Factor:
a. Calculation for pure components
b. Calculation for mixture components
I. Mixing rules for calculating pseudocritical properties
II. Correlations for calculating pseudocritical properties

c. Nonhydrocarbon adjustment
d. High molecular weight gases adjustment

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