Reservoir Fluid Properties Course: Key Concepts

Reservoir Fluid Properties Course (1st Ed.)

1.
2.
3.
4.

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

2013 H. AlamiNia

Reservoir Fluid Properties Course: Reservoir Hydrocarbons (Natural gas & Crude Oil)

2

1.
2.
3.
4.

Reservoir Fluid Course
HC Alteration
Properties of Natural Gases
Properties of Crude Oils
A. density
B. Gas Solubility

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Reservoir
To optimize the production from an oil or a gas
field, it is essential to have extensive knowledge of
The volumetric and
Phase changes

The reservoir fluid is likely to undergo on its way
from petroleum reservoir to oil refinery.
Reservoir pressures typically range from 100 to
1500 bar (~1450-21000 psi!), and reservoir
temperatures from 50 to 200 ° C (~120-390 °F).
The well connecting the reservoir to the topside
facilities can have a length of more than 2 km.
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Well and Flowlines
The pressure and temperature will gradually
decrease in production well. It will further decrease
in flowlines connecting the well to the process plant
and in the process plant itself.
Figure illustrates schematically the production path
of a reservoir fluid.

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Course Followed By Reservoir Fluid

Course Followed By Reservoir Fluid
from Reservoir to Ambient
Conditions

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Reservoir Fluid Alteration
The conditions in the reservoir itself will also
change as a result of production.
A reservoir fluid, which in the exploration phase
was either single-phase gas or single-phase oil, may
sometime after production split into two phases.
This phase split is the result of material being removed
from the reservoir.

With more space available for the remaining
reservoir fluid, the pressure will decrease and may
after some time reach the saturation pressure, at
which a second phase (gas or oil) starts to form.
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PVT Properties
 PVT properties is the general term used to express
the volumetric behavior of a reservoir fluid as a
function of pressure and temperature.
An essential PVT property is
The saturation pressure

At reservoir temperature.

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Fluid Composition Alteration
 From the time the reservoir pressure reaches the
saturation pressure and a second phase starts to
form, the composition of the produced well stream
will most likely change
Because the production primarily comes from either the
gas or the liquid zone.

It is customary to use the volumes of oil and gas at
atmospheric pressure and 15 ° C (60°F) as reference
values.
Atmospheric pressure (1 atm or 1.01325 bar) (14.5
psi) and 15 ° C are referred to as standard
conditions.
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Natural Gas Expression
Conventionally, natural gas compositions are
expressed in terms of mole fraction, weight
fraction, and volume percent. These are derived as
follows:
Mole Fraction: the number of moles of the component
divided by the total number of moles of all the
components in the mixture. (yi=ni/n)
Weight Fraction: is defined as the weight of that
component divided by the total weight. (wi=mi/m)
Volume Fraction: is defined as the volume of that
compound divided by the total volume of the mixture.
(vi=Vi/V)
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Mixture Apparent Molecular Weight
If yi represents the mole fraction of the ith
component in a gas mixture,
the apparent molecular weight is defined
mathematically by the following equation:
𝑴𝑾 𝒂 =

𝒚 𝒊 ∙ 𝑴𝑾 𝒊
𝒊=1

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Ideal Gas Mixture Density and
Specific Gravity
The density of an ideal gas mixture is calculated by:
𝝆𝒈=

𝒑𝑴𝑾 𝒂
𝑹𝑻

The specific gravity is defined as the ratio of the gas
density to that of the air. Both densities must be
taken at the same temperature and pressure, or:
𝜸𝒈=

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𝝆𝒈
𝝆 𝒂𝒊𝒓

=

𝑴𝑾 𝒂
𝑴𝑾 𝒂
=
𝑴𝑾 𝒂𝒊𝒓 28.96


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Compressibility of Natural Gases
A knowledge of the variability of fluid
compressibility with pressure and temperature is
essential in performing many reservoir engineering
calculations.
For a liquid phase, the compressibility is small and
usually assumed to be constant.
For a gas phase, the compressibility is neither small
nor constant.

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Gas Compressibility Definition
By definition, the isothermal gas compressibility is
the change in volume per unit volume for a unit
change in pressure, or, in equation form:
1
𝒑𝒔𝒊

𝑪𝒈=−

1
𝑽

𝜕𝑽
𝜕𝒑

=
𝑻

1 1
−
𝒑
𝒁

𝜕𝒁
𝜕𝒑

𝑻

For an ideal gas, Z = 1 and (∂Z/∂p) T = 0, therefore
Cg=1/p

For calculating isothermal pseudo-reduced
compressibility (Cr) in terms of the pseudo-reduced
pressure and temperature by simply replacing p.
with (Ppc Ppr) we have Cr=CgPpc
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Gas Formation Volume Factor
Definition
The gas formation volume factor is used to relate
the volume of gas, as measured at reservoir
conditions, to the volume of the gas as measured at
standard conditions, i.e., 60°F and 14. 7 psia.
This gas property is then defined as the actual
volume occupied by a certain amount of gas at a
specified pressure and temperature, divided by the
volume occupied by the same amount of gas at
standard conditions.

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Bg Expression
In an equation form, the relationship is expressed
as
𝑩𝒈=

𝑽 𝒑,𝑻
𝑽 𝒔𝒄

Where Bg = gas formation volume factor, ft3/scf
Vp, T = volume of gas at pressure p and temperature T,
ft3.
And V sc = volume of gas at standard conditions, scf

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Bg Expression for Real Gases
Applying the real gas EoS to the above relationship
gives
𝒁𝒏𝑹𝑻
𝒑
𝑩𝒈=
𝒁 𝒔𝒄 = 1)𝒏𝑹𝑻 𝒔𝒄
𝒑 𝒔𝒄
𝒑 𝒔𝒄 = 14.7
=
𝑻 𝒔𝒄 = 60 + 460 = 520
𝒁𝑻 𝒇𝒕3
= 0.02827
,
𝒑 𝒔𝒄𝒇
𝒁𝑻 𝒃𝒃𝒍
= 0.005035
,
𝒑 𝒔𝒄𝒇

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𝒁𝑻
𝒑


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Gas Expansion Factor
The reciprocal of the gas formation volume factor is
called the Gas Expansion Factor and designated by
the symbol Eg, or
𝑬𝒈
𝒑
= 35.37
,
𝒁𝑻
𝒑
= 198.6
,
𝒁𝑻

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𝒔𝒄𝒇
𝒇𝒕3
𝒔𝒄𝒇
𝒃𝒃𝒍


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Physical and Chemical Properties of
Crude Oils
Petroleum (an equivalent term is “crude oil") is a
complex mixture consisting predominantly of
hydrocarbons, and containing sulfur, nitrogen,
oxygen, and helium as minor constituents.
The physical and chemical properties of crude oils
vary considerably and are dependent on the
concentration of the various types of hydrocarbons
and minor constituents present.

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Physical Properties of Petroleum
Physical properties of primary interest in petroleum
engineering studies include:
Fluid densities
Isothermal compressibility
Solution gas-oil ratios
Oil formation volume factor
Fluid viscosities
Bubble-point pressure
Surface tension

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Determination of Physical Properties
Data on most of these fluid properties is usually
determined by laboratory experiments performed
on samples of actual reservoir fluids.
In the absence of experimentally measured
properties of crude oils, it· is necessary for the
petroleum engineer to determine the properties
from empirically derived correlations.

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Crude Oil Density
Density:
The crude oil density is defined as the mass of a unit
volume of the crude at a specified pressure and
temperature. It is usually expressed in pounds per cubic
foot.

Specific gravity:
The specific gravity of a crude oil is defined as the
ratio of the density of the oil to that of water. Both
densities are measured at 60°F and atmospheric
pressure.
𝜸𝒐 =
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𝝆𝒐
𝝆𝒘


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Crude Oil Density Determination
As the density of water at 60°F is close to 1 g/cm3,
the 60°F/60°F specific gravity of an oil sample will
take approximately the same value as the density of
the oil sample in g/cm3.
During the last forty years, numerous methods of
calculating the density of crude oils have been
proposed. There are two approaches available in
the literature to calculate liquid density:
The equation-of-state approach
The liquid density-correlation approach.

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Standing's Method
Standing (1981) proposed an empirical correlation
for estimating the oil formation volume factor as a
function of the gas solubility Rs, the specific gravity
of stock tank oil γo, the specific gravity of solution
gas γg and the system temperature T.
𝝆𝒐 =

62.4𝜸 𝒐 + 0.0136𝑹 𝒔 𝜸 𝒈
0.972 + 0.000147

𝑹𝒔

𝜸𝒈
𝜸𝒐

1.175

0.5

+ 1.25 𝑻 − 460

Where T =system temperature, °R & γo = specific gravity
of stock-tank oil
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API
Although the density and specific gravity are used
extensively in the petroleum industry, the API gravity is
the preferred gravity scale.
This gravity scale is precisely related to the specific
gravity by the following expression:
𝑨𝑷𝑰 =

141.5
− 131.5
𝑺𝑮 = 𝜸 𝒐

The density of an oil from a flash to standard conditions
has traditionally been expressed as API gravity.
The API gravities of crude oils usually range from 47°
API for the lighter crude oils to 10° API for the heavier
asphaltic crude oils.
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Gas Solubility
The gas solubility Rs is defined as the number of
standard cubic feet of gas which will dissolve in one
stock-tank barrel of crude oil at certain pressure
and temperature.
The solubility of a natural gas in a crude oil is a
strong function of the pressure, the temperature,
the API gravity, and the gas gravity.
To determine Rs, beside experimental analysis
there are many correlations (including: Beal's
Correlation, Standing's Correlation, Lasater's
Correlation, Vasquez-Beggs' Correlation, Glaso's
Correlation, Marhoun's Correlation)
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Rs vs. P and Rs vs. T Relationships

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Rs Relationships

API Gravity-Rs Relationship
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Gas Gravity vs. Gas Solubility Relationship


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Rs vs. P
For a particular gas and crude oil to exist at a
constant temperature, the solubility increases with
pressure until the saturation pressure is reached.
At the saturation pressure (bubble-point pressure)
all the available gases are dissolved in the oil and
the gas solubility reaches its maximum value.

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An Idealized Rs-P Diagram for
an Undersaturated Oil

A typical gas solubility curve, as a
function of pressure for an
undersaturated crude oil

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Rs vs. P in Reality
Rather than measuring the amount of gas that will
dissolve in a given stock-tank crude oil as the pressure
is increased, it is customary to determine the amount of
gas that will come out of a sample of reservoir crude oil
as pressure decreases.
As the pressure is reduced from the initial reservoir
pressure pi, to the bubble-point pressure Pb, no gas
evolves from the oil and consequently the gas solubility
remains constant at its maximum value of Rsb·
Below the bubble-point pressure, the solution gas is
liberated and the value of Rs decreases with pressure.
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1. Tarek, A. (1989). Hydrocarbon Phase Behavior
(Gulf Publishing Company, Houston). Ch2 &
Ch3 & Ch4.

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1. Formation Volume Factor
A. Oil
B. Total (two phase)

2. Property Constants

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Reservoir Fluid Properties Course: Key Concepts

Reservoir Fluid Properties Course: Key Concepts

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