Q921 re1 lec4 v1

Reservoir Engineering 1 Course (2nd Ed.)

1. Crude Oil Properties:
A.
B.
C.
D.
E.
F.
G.
H.

Density (gamma)
Solution gas (Rs)
Bubble-point pressure (Pb)
Formation volume factor (Bo)
Isothermal compressibility coefficient (Co)
Total formation volume factor (Bt)
Viscosity (mu)
Surface Tension (sigma)

2. Water Properties

1. Laboratory Analysis
2. Laboratory Experiments
3. Rock Properties:
A.
B.
C.
D.
E.

Porosity
Saturation
Wettability
Capillary Pressure
Transition Zone

Laboratory Analysis of Reservoir Fluids
Accurate laboratory studies of PVT and phaseequilibria behavior of reservoir fluids are necessary
for characterizing these fluids and evaluating their
volumetric performance at various pressure levels.
There are many laboratory analyses that can be
made on a reservoir fluid sample.
The amount of data desired determines the number of
tests performed in the laboratory.

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Reservoir Engineering 1 Course: Laboratory Experiments & Rock Properties

5

Types of Laboratory Tests
In general, there are three types of laboratory tests
used to measure hydrocarbon reservoir samples:
1. Primary tests (simple, routine field (on-site) tests)
The measurements of the specific gravity and
The gas-oil ratio of the produced hydrocarbon fluids.

2. Routine laboratory tests
3. Special laboratory PVT tests

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Routine Laboratory Tests
2. Routine laboratory tests (laboratory tests that
are routinely conducted to characterize the
reservoir hydrocarbon fluid)
Compositional analysis of the system
Constant-composition expansion
Differential liberation
Separator tests
Constant-volume depletion

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Special Laboratory Tests
3. Special laboratory PVT tests (performed for very
specific applications. If a reservoir is to be depleted
under miscible gas injection or a gas cycling
scheme)
Slim-tube test
Swelling test

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Composition of the Reservoir Fluid
It is desirable to obtain a fluid sample as early in
the life of a field as possible so that the sample will
closely approximate the original reservoir fluid.
Collection of a fluid sample early in the life of a field
reduces the chances of free gas existing in the oil zone of
the reservoir.
Most of the parameters measured in a reservoir fluid
study can be calculated with some degree of accuracy
from the composition.
It is the most complete description of reservoir fluid that
can be made.

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Heavy Components
In the past, reservoir fluid compositions were usually
measured to include separation of the component
methane through hexane, with the heptanes and
heavier components grouped as a single component
reported with the average molecular weight and
density.
With the development of more sophisticated
equations-of-state to calculate fluid properties, it was
learned that a more complete description of the heavy
components was necessary.
It is recommended that compositional analyses of the
reservoir fluid should include a separation of components
through C10 as a minimum.
The more sophisticated research laboratories now use
equations-of-state that require compositions through C30 or
higher.

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Constant-Composition Expansion Tests
Constant-composition expansion experiments are
performed on gas condensates or crude oil to
simulate the pressure-volume relations of these
hydrocarbon systems. The test is conducted for the
purposes of determining:
Saturation pressure (bubble-point or dew-point
pressure)
Isothermal compressibility coefficients of the singlephase fluid in excess of saturation pressure
Compressibility factors of the gas phase
Total hydrocarbon volume as a function of pressure
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Differential Liberation (Vaporization)
Test
In the differential liberation process, the solution gas
that is liberated from an oil sample during a decline in
pressure is continuously removed from contact with the
oil, and before establishing equilibrium with the liquid
phase.
This type of liberation is characterized by a varying
composition of the total hydrocarbon system. The
experimental data obtained from the test include:
Amount of gas in solution as a function of pressure
The shrinkage in the oil volume as a function of pressure
Properties of the evolved gas including the composition of the
liberated gas, the gas compressibility factor, and the gas
specific gravity
Density of the remaining oil as a function of pressure

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Separator Tests
Separator tests are conducted to determine the
changes in the volumetric behavior of the reservoir
fluid as the fluid passes through the separator (or
separators) and then into the stock tank.
The resulting volumetric behavior is influenced to a large
extent by the operating conditions, i.e., pressures and
temperatures, of the surface separation facilities.

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Objectives of Separator Tests
The primary objective of conducting separator
tests, therefore, is to provide the essential
laboratory information necessary for determining
the optimum surface separation conditions, which
in turn will maximize the stock-tank oil production.
In addition, the results of the test, when
appropriately combined with the differential
liberation test data, provide a means of obtaining
the PVT parameters (Bo, Rs, and Bt) required for
petroleum engineering calculations. These
separator tests are performed only on the original
oil at the bubble point.
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Extrapolation of Reservoir Fluid Data
In partially depleted reservoirs or in fields that
originally existed at the bubble-point pressure, it is
difficult to obtain a fluid sample, which usually
represents the original oil in the reservoir at the time of
discovery.
Also, in collecting fluid samples from oil wells, the
possibility exists of obtaining samples with a saturation
pressure that might be lower than or higher than the
actual saturation pressure of the reservoir.
In these cases, it is necessary to correct or adjust the
laboratory PVT measured data to reflect the actual
saturation pressure.
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Laboratory Analysis of
Gas Condensate Systems
In the laboratory, a standard analysis of a gascondensate sample consists of:
Recombination and analysis of separator samples
Measuring the pressure-volume relationship, i.e.,
constant-composition expansion test
Constant-volume depletion test (CVD)

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Constant-Volume Depletion
Experiment
Constant-volume depletion (CVD) experiments are
performed on
Gas condensates and
Volatile oils

To simulate reservoir depletion performance and
compositional variation.

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Rock Physical Properties
The material of which a petroleum reservoir rock
may be composed can range from very loose and
unconsolidated sand to a very hard and dense
sandstone, limestone, or dolomite.
Knowledge of the physical properties of the rock
and the existing interaction between the
hydrocarbon system and the formation is essential
in understanding and evaluating the performance
of a given reservoir.

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Rock Properties Determination
Rock properties are determined by performing
laboratory analyses on cores from the reservoir to
be evaluated.
There are basically two main categories of core
analysis tests that are performed on core samples
regarding physical properties of reservoir rocks.
The rock property data are essential for reservoir
engineering calculations as they directly affect both
the quantity and the distribution of hydrocarbons
and, when combined with fluid properties, control
the flow of the existing phases (i.e., gas, oil, and
water) within the reservoir.
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Core Analysis Tests
These are:
Routine core analysis tests:
Porosity, Permeability, Saturation

Special tests:
Overburden pressure, Capillary pressure, Relative permeability,
Wettability, Surface and interfacial tension

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Porosity Definition
The porosity of a rock is a measure of the storage
capacity (pore volume) that is capable of holding
fluids.
As the sediments were deposited and the rocks
were being formed during past geological times,
some void spaces that developed became isolated
from the other void spaces by excessive
cementation. This leads to two distinct types of
porosity, namely:
Absolute porosity, Effective porosity
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Absolute Porosity
The absolute porosity is defined as the ratio of the
total pore space in the rock to that of the bulk
volume. A rock may have considerable absolute
porosity and yet have no conductivity to fluid for
lack of pore interconnection.
Determination method?

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Effective Porosity
The effective porosity is the percentage of
interconnected pore space with respect to the bulk
volume, or
Where φ = effective porosity

The effective porosity is the value that is used in all
reservoir-engineering calculations because it
represents the interconnected pore space that
contains the recoverable hydrocarbon fluids.
Determination method?
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Application of the Effective Porosity
One important application of the effective porosity
is its use in determining the original hydrocarbon
volume in place.
Consider a reservoir with an areal extent of A acres
and an average thickness of h feet.

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Saturation Definition
Saturation is defined as that fraction, or percent, of
the pore volume occupied by a particular fluid (oil,
gas, or water).

Also for Sg and Sw
All saturation values are based on pore volume and not
on the gross reservoir volume. The saturation of each
individual phase ranges between zero to 100%. By
definition, the sum of the saturations is 100%, therefore

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Connate (Interstitial) Water Saturation
Swc
The fluids in most reservoirs are believed to have
reached a state of equilibrium and, therefore, will
have become separated according to their density,
i.e., oil overlain by gas and underlain by water.
In addition to the bottom (or edge) water, there
will be connate water distributed throughout the oil
and gas zones. The water in these zones will have
been reduced to some irreducible minimum.
The forces retaining the water in the oil and gas zones
are referred to as capillary forces because they are
important only in pore spaces of capillary size.
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Critical Gas and Water Saturation
Critical gas saturation, Sgc
As the reservoir pressure declines below the bubblepoint pressure, gas evolves from the oil phase and
consequently the saturation of the gas increases as the
reservoir pressure declines. The gas phase remains
immobile until its saturation exceeds a certain
saturation, called critical gas saturation, above which gas
begins to move.

Critical water saturation, Swc
The critical water saturation, connate water saturation,
and irreducible water saturation are extensively used
interchangeably to define the maximum water
saturation at which the water phase will remain
immobile.
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Critical and Movable Oil Saturation
Critical oil saturation, Soc
For the oil phase to flow, the saturation of the oil must
exceed a certain value, which is termed critical oil
saturation.

Movable oil saturation, Som
Movable oil saturation Som is defined as the fraction of
pore volume occupied by movable oil as expressed by
the following equation:
Som = 1 − Swc – Soc

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Residual Oil Saturation, Sor
During the displacing process of the crude oil
system from the porous media by water or gas
injection (or encroachment), there will be some
remaining oil left that is quantitatively characterized
by a saturation value that is larger than the critical
oil saturation. This saturation value is called the
residual oil saturation, Sor.
The term residual saturation is usually associated with
the nonwetting phase when it is being displaced by a
wetting phase.

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Average Saturation
Proper averaging of saturation data requires that
the saturation values be weighted by both the
interval thickness hi and interval porosity φ.

Also for Sw and Sg
Where the subscript i refers to any individual
measurement and hi represents the depth interval to
which φi, Soi, Sgi, and Swi apply.
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Illustration of Wettability
Wettability is defined as the tendency of one fluid
to spread on or adhere to a solid surface in the
presence of other immiscible fluids.

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Contact Angle
The tendency of a liquid to spread over the surface
of a solid is an indication of the wetting
characteristics of the liquid for the solid.
This spreading tendency can be expressed more
conveniently by measuring the angle of contact at the
liquid-solid surface.
This angle, which is always measured through the liquid
to the solid, is called the contact angle θ.
The contact angle θ has achieved significance as a
measure of wettability.
Complete wettability: 0°, complete nonwetting: 180° and
intermediate wettability contact angles of 60° to 90°
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Illustration of Surface Tension

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Pressure Relations in Capillary Tubes
If a glass capillary tube is
placed in a large open vessel
containing water, the
combination of surface
tension and wettability of
tube to water will cause water
to rise in the tube above the
water level in the container
outside the tube as shown in
Figure.
The water will rise in the tube
until the total force acting to
pull the liquid upward is
balanced by the weight of the
column of liquid being
supported in the tube.

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Surface Tension Calculation
Assuming the radius of the capillary tube is r, the
total upward force Fup, which holds the liquid up, is
equal to the force per unit length of surface times
the total length of surface, or (Fup = (2πr) (σgw)
(cos θ))
The upward force is counteracted by the weight of
the water, which is equivalent to a downward force
of mass times acceleration, or (Fdown = πr2 h (ρw −
ρair) g, neglecting ρair yields Fdown = π r2 ρwg) so

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Capillary Forces
The capillary forces in a petroleum reservoir are the
result of the combined effect of the surface and
interfacial tensions of the rock and fluids, the pore
size and geometry, and the wetting characteristics
of the system.
When two immiscible fluids are in contact, a
discontinuity in pressure exists between the two
fluids, which depends upon the curvature of the
interface separating the fluids. We call this pressure
difference the capillary pressure and it is referred to
by pc.
pc = pnw − pw
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Capillary Pressure Equipment

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Capillary Pressure Curve

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Variation of Capillary Pressure
with Permeability

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Capillary Hysteresis
Drainage process:
The process of displacing the wetting phase, i.e., water,
with the nonwetting phase (such as with gas or oil).

Imbibition process:
Reversing the drainage process by displacing the
nonwetting phase (such as with oil) with the wetting
phase, (e.g., water).

Capillary hysteresis:
The process of saturating and desaturating a core with
the nonwetting phase

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Capillary Pressure Hysteresis
This difference in the
saturating and
desaturating of the
capillary-pressure
curves is closely related
to the fact that the
advancing and receding
contact angles of fluid
interfaces on solids are
different.

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Wettability of Reservoir Rock
Frequently, in natural crude oil-brine systems, the
contact angle or wettability may change with time.
Thus, if a rock sample that has been thoroughly cleaned
with volatile solvents is exposed to crude oil for a period
of time, it will behave as though it were oil wet.
But if it is exposed to brine after cleaning, it will appear
water wet.

At the present time, one of the greatest unsolved
problems in the petroleum industry is that of
wettability of reservoir rock.

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Initial Saturation Distribution
in a Reservoir
An important application of the concept of capillary
pressures pertains to the fluid distribution in a
reservoir prior to its exploitation.
The capillary pressure-saturation data can be converted
into height-saturation data by:

(h= the height above the freewater level, Δρ = density
difference between the wetting and nonwetting phase)

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Water Saturation Profile
Figure shows a plot of
the water saturation
distribution as a
function of distance
from the free-water
level in an oil-water
system.

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Important Levels in Reservoirs
Transition zone:
the vertical thickness over which the water saturation
ranges from 100% saturation to Swc (effects of capillary
forces)

Water-oil contact (WOC):
uppermost depth in the reservoir where a 100% water
saturation exists

Gas-oil contact (GOC):
minimum depth at which a 100% liquid, i.e., oil + water,
saturation exists in the reservoir

Free water level (FWL)
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An Idealized Gas, Oil, and Water
Distribution in a Reservoir
Initial
saturation
profile in a
combinationdrive reservoir

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Saturation Profile vs.
Pore-Size Distribution
Section A shows a
schematic illustration of a
core that is represented
by five different pore
sizes and completely
saturated with water, i.e.,
wetting phase.
We subject the core to oil
(the nonwetting phase)
with increasing pressure
until some water is
displaced from the core,
i.e., displacement
pressure Pd.
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Free Water Level
There is a difference between the free water level
(FWL) and the depth at which 100% water
saturation exists.
From a reservoir-engineering standpoint, the free water
level is defined by zero capillary pressure.
Obviously, if the largest pore is so large that there is no
capillary rise in this size pore, then the free water level
and 100% water saturation level, i.e., WOC, will be the
same.

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Variation of Transition Zone
with Fluid Gravity (API for Oil)
The thickness of the
transition zone may
range from few feet to
several hundred feet in
some reservoirs. Height
above FWL:

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Variation of Transition Zone
with Permeability

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1. Ahmed, T. (2010). Reservoir engineering
handbook (Gulf Professional Publishing).
Chapter 3 and 4

1.
2.
3.
4.
5.
6.
7.
8.
9.

Darcy Law: Linear Flow Model
Permeability Measurements
Darcy Law: Radial Flow Model
Permeability-Averaging Techniques
Effective Permeabilities
Rock Compressibility
Homogeneous and Heterogeneous Reservoirs
Two-Phase Permeability
Reservoir Characteristics

Q921 re1 lec4 v1

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