Advanced

Reservoir Engineering
Course Instructor: Marzhan Karimova
Introductory Words
• Karimova Marzhan Kazhmuratovna

• Schedule:
Monday Tuesday Wednesday Thursday Friday Saturday Sunday
10 am –
1pm
6 - 9 pm 6 - 9pm

• If you have any questions: m.karimova@kbtu.kz

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Course Structure
Module 1. Introduction Review: primary, secondary, tertiary oil recovery, basic concepts of
permeability, porosity, capillary pressure, wettability, drainage, imbibition

Module 2. Methods of Deterministic and probabilistic approaches, analogy, volumetric,

estimating reserves performance based (MBE, DCA, simulation)
Module 3. Material General Equation of MB, MBE for saturated oil reservoir, undersaturated oil
Balance reservoir, MBE for dry gas reservoir, gas condensate. Drive indices.
Module 4. DCA Fundamentals of Decline Curve analysis, Types of DCA: harmonic,
hyperbolic, exponential, Decline type-curve analysis
Module 5. Water Influx Aquifer types, Steady state, Unsteady state, pseudo steady state methods.
Module 6. Immiscible Fractional Flow Equation, Buckley Leverett Equation, areal and vertical
Displacement displacement, Fundamentals of waterflooding, waterflooding design

3
Exams/Quizzes/ Assignment
• Assignment – 2 (20 %): Deadlines – 3.05 and 5.05
• Quizzes – 2 (10%): 09.04 and 30.04
• Midterm Exam – (30 %): 23.04
• Final Exam – (40 %): 7.05

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Reference Books
• Ahmed, T. H. (2019). Reservoir Engineering Handbook. Gulf
Professional Publishing.
• Blunt, M. J. (2017). The Imperial College Lectures in Petroleum
Engineering: Reservoir Engineering. World Scientific.
• Craft, B. C., 1917-, H. M. F., & Terry, R. E. (1991). Applied
Petroleum Reservoir Engineering. Prentice Hall.
• Craig, F. F. (1993). The reservoir engineering aspects of
waterflooding. Henry L. Doherty.
• Dake, L. P. (2001). Fundamentals of Reservoir Engineering.
Elsevier.
5
Advanced Reservoir
Engineering
Module 1. Introduction

6
Module Outline
• 1.1 Fundamental concepts of reservoir engineering
• 1.2 Reservoir definition and description
• 1.3 Review of reservoir rock and fluid properties
• 1.4 Drainage and Imbibition Process
• 1.5 Primary, secondary, and tertiary oil recovery
• 1.6 Primary reservoir drive mechanisms

7
1.1 Fundamental concepts of
reservoir engineering

8
Definition of Reservoir Engineering
Application of scientific principles to the drainage problems arising during
development and production of oil and gas reservoirs (Craft and Hawkins,
1991).

The art of developing and producing oil and gas fluids in such a manner as
to obtain a high economic recovery (T.V. Moore, 1955).

Accoriding to Dake (1978), the main functions of Reservoir Engineer:

Estimation of hydrocarbons in-place
Calculation of recovery factor
Forecast of production

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Questions needs to be answered by
Reservoir Engineer:
1. How much oil and gas is originally in place?
2. What are the drive mechanisms for the reservoir?
3. What are the trapping mechanisms for the reservoir?
4. What will the recovery factor be for the reservoir by primary
depletion?
5. What will future production rates from the reservoir be?
6. How can the recovery be increased economically?
7. What data are needed to answer these questions?

10
Reservoir Engineering technique to
answer these questions
• The material-balance equation and various drive indices can be
calculated to give an indication of the relative strengths of
different drive mechanisms
• The displacement theory of Buckley and Leverett can be used
to forecast future recovery and production rates
• Decline-curve models also help to forecast future production
rates and ultimate recoveries

11
Reservoir Engineering technique to
answer these questions
• To increase recovery from a reservoir, some sort of flooding
usually is involved.
• The most common of these is waterflooding, but gasflooding,
steamflooding, miscible-gas flooding, fire flooding, polymer
flooding, and surfactant flooding are also used
• Determining the economics of various enhanced-oil-recovery
schemes depends on determining a good model of the reservoir

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What are the methods used in Reservoir
Engineering?
3 main approaches are used to find OIIP (Oil Initially In Place):

1. Analogy

2. Volumetric estimation

3. Performance based estimation

(DCA, MBE, Simulation)

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What are the methods used in Reservoir
Engineering?

• Analogy and volumetric

methods are used at the early
stages of reservoir
development.
• DCA, MBE, Reservoir
Simulation are used during or
after Production Phase.

Senturk, Y. (2011). Essence of the SPE petroleum resources management system - definitions and
guiding principles for classification, categorization and assessment process. All Days.
https://doi.org/10.2118/149078-ms

14
Data Sources Required
To use volumetrics, the data needed are
• porosity,
• reservoir thickness,
• fluid saturation,
• formation volume factors (FVF's).

The first three properties can be determined at each well only by use of well logs and
cores.
FVF is determined by taking a bottomhole or recombined sample of the reservoir
fluid and measuring pressure/volume relationships in the laboratory at the reservoir
temperature.

15
Data Sources Required

To use the material-balance equation, the data needed

are
1) the pressure/volume relationships of the reservoir
fluids;
2) the production volumes of oil, water, and gas as
functions of reservoir pressure.

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Data Sources Required

• To apply the Buckley-Leverett displacement theory,

the relative permeability data are required.
• These data are determined with cores in a process
called special core analysis.
• Reservoir permeabilities and well geometries are
needed to calculate rates from individual wells.

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1.2 Reservoir definition
and description

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Definition: Petroleum Reservoir
(Conventional) A critical components of the petroleum system:
• A subsurface porous and 1. Seal or cap rock
2. Reservoir
permeable rock having 3. Source Rock

commercial quantities of
oil/gas.
• Typically, a sedimentary rock
• A single hydraulically
connected system

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Classification of petroleum reservoir
Petroleum reservoirs are classified based on
• the fluids they contain
• the primary drive mechanism
• conventional or unconventional

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Petroleum reservoir classification based
on the fluids they contain
Gas reservoirs
• Dry gas: hydrocarbons will always be in the vapor phase from reservoir to
surface
• Wet gas: hydrocarbons will be in the vapor phase at reservoir, some liquids
condense out at surface
• Retrograde-condensate: Some liquids condense out at reservoir, reducing
amount of liquids at surface

Oil reservoirs
• Undersaturated-oil: No free gas present at reservoir
• Saturated-oil: Can have a free gas cap at reservoir

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Phase
Behavior
Diagram

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Reservoir classification based on the
primary drive mechanism
• Solution gas drive
Expansion of oil and originally dissolved gas
• Gas cap drive
Expansion of free gas
• Natural water drive
Expansion of aquifer water with influx into reservoir displacing hydrocarbon fluids
• Compaction drive
Pore volume contraction, reduces porosity, forcing fluids out of pore space
• Gravity drainage
Oil drains downdip from gas cap, gas migrate updip from oil column
• Combinations drive

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Reservoir classification based on
conventionals or unconventionals
A conventional petroleum reservoir is defined as subsurface porous and
permeable rock having commercial quantities of oil/gas. Typically, a
sedimentary rock, which is a single hydraulically connected system, and a
critical component of the petroleum system

An unconventional petroleum reservoir are hydrocarbon accumulations

widespread throughout a large area. This reservoirs are not affected by
hydrodynamic influences in terms of buoyant forces and influence of water
column surrounding the hydrocarbon accumulation. The fluids in these
reservoir present a low mobility either because of its high viscosity or the
rock low permeability. These reservoirs do not produce economic volumes
without assistance from massive stimulation treatments or special recovery
processes and technologies.
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 1.3 Review of reservoir
rock and fluid properties

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Basic Oil Properties: Review
• Specific gravity
• API gravity
• Oil formation volume factor
• Bubble point pressure
• Solution gas/oil ratio and gas solubility
• Total (two-phase) formation volume factor
• Coefficient of isothermal compressibility
• Viscosity
• Density
• Thermal expansion coefficient

Please refer to the book: McCain, W. D.: The Properties of Petroleum Fluids, Second Edition,
PennWell Books, 1990

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Basic Water Properties: Review
• Chemical composition
• Salinity
• Density of brine at standard conditions
• Bubble point pressure
• Solution gas-water ratio
• Gas solubility
• Water formation volume factor
• Density
• Coefficient of isothermal compressibility
• Viscosity
• Water vapor content of Natural Gas
• Solubility of Water in Liquid Hydrocarbons
• Solubility of Liquid Hydrocarbons in Water

Please refer to the book: McCain, W. D.: The Properties of Petroleum Fluids, Second Edition,
PennWell Books, 1990

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Properties of reservoir rock
• Porosity
• Permeability
• Fluid Saturation
• Wettability
• Capillary Pressure

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Porosity
The porosity is the fraction
of the volume of the porous
medium occupied by void
space. This means that the
porosity is the volume of
void space in a rock divided
by the total volume of the
rock (including void spaces).

29
Permeability
p1 p2
Dp
Permeability is the ability of
a porous rock to transmit q q
fluids flowing through its
pore space. A
L

Permeability is an empirical Darcy’s Law:

property derived from
experimental observations
(In 1856, Henry Darcy).

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Types of permeability

Absolute permeability (ka): when porous media is 100%

saturated by one phase.

Effective permeability (ke): conductance of one fluid when

medium is saturated with more than one fluid.

Relative permeability (kr): ratio of effective permeability of one

phase to the absolute permeability
ke
k r=
ka
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Relative Permeability Curve

Relative permeability is a function of saturation:

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Wettability
• Interaction between the surface of the reservoir rock and the fluid
phases confined in the pore space influences fluid distribution in
rocks as well as flow properties
• When two immiscible phases are placed in contact with a solid
surface, one of the phases is usually attracted to the surface more
strongly than the other phase
• This phase is identified as the wetting phase while the other phase is
the non-wetting phase
• Wettability is explained quantitatively by examining the force
balances between two immiscible fluids at the contact line between
the two fluids (water and oil) and the solid
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Wettability
• The water phase spreads out over the surface in preference
to oil. The forces that are present at the contact line are
• , the IFT between solid and oil phase
• , the IFT between solid and water phase
• the IFT between oil and water phases
• The contact angle, , is measured through the water phase to
the tangent to the interface at the contact line
• At equilibrium, the sum of the forces acting along the
contact line must be zero
• The Young equation, represents the force balance in the
direction parallel to the rock surface:

34
Fluid distribution in the porous media is a
function of wettability
• Wetting phase occupies smaller pores
• Non-wetting phase occupies the more open channels

35
Wettability: Qualitative Imbibition Method
• The basis of most wettability measuring techniques is in
determining which fluid is most strongly imbibed into the rock,
displacing the other fluid
• A simple experiment performed to demonstrate wettability is to
place a drop of water on a sample of dry rock, and check:
• If the water drop is imbibed quickly into the pores of the rock, the
rock is considered to be strongly water wet
• If the drop imbibes slowly, the rock is slightly water wet
• If the water drop remains on the surface of the rock and is not
imbibed into the pores, the rock is considered to be oil wet
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Wettability: Spontaneous imbibition method
• If the amount of water displaced by
spontaneous imbibition of oil is larger
than the amount of oil displaced by
spontaneous imbibition of water, the
rock is oil‐wet
• If the amount of water displaced by
spontaneous imbibition of oil is equal
to the amount of oil displaced by
spontaneous imbibition of water, the
rock is neutral wet.

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Wettability
• Simple instrument and convenient
operation
• This method can reflect actual
situation of reservoir
• This method can only qualitatively
determine wettability

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Wettability: Quantitative evaluation of
wettability
• Wettability is determined quantitatively with two types of methods:
• Wettability contact angle measurement using uncontaminated
reservoir oil. Need very smooth surface of pure minerals of rock.
• Wettability displacement method using core sample that are obtained
with original wettability intact, example Amott, USBM method.

There are number of different indices in common usage:

• Amott method‐ Amott wettability index
• Amott method‐ Amott‐ Harvey wettability index
• USBM method‐ USBM wettability index
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Wettability: Amott Wettability Technique
• Fresh core plug sample is oil
flooded to irreducible water
saturation
• Sample is immersed in
simulated formation brine for
spontaneous water imbibition
• Sample, after stabilization,
water flooded to residual oil
saturation (dynamic
displacement)

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Wettability: Amott Wettability Technique
• Sample is then immersed in oil
for spontaneous oil imbibition
• Sample, after stabilization, oil
flooded to irreducible water
saturation (dynamic
displacement)

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Wettability
• Iw is the displacement by water ratio:
• It is defined as the oil volume replaced by spontaneous water
imbibition, relative to the total oil volume displaced by total
water imbibition

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Wettability
• Io is the displacement by oil ratio:
• It is defined as the water volume replaced by spontaneous oil
imbibition, relative to the total water volume displaced by total
oil imbibition

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Wettability
• If the material is completely water‐wet:
• Then Io=0 and Iw=1
• If the material is completely oil‐wet:
• Then Io=1 and Iw=0
• With connected pathways of both oil and water:
• Then both indices can be greater than zero

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Wettability
• Amott‐Harvey Wettability index

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Wettability
• USBM method
• This index is based on the ratio of the two areas representing forced imbibition

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Wettability
• A1 and A2 are the areas under the oil and brine drive curves
respectively
1. If W>0 indicate water‐wet
2. W<0 indicate oil‐wet
3. W=0 indicate neutrally‐wet
• The larger the absolute value of W, the greater the wetting
preference
• Typical values of USBM wettability index are in the range ‐1.5 to
+1.0

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Surface tension and interfacial tension
(IFT)
• Whenever immiscible phases coexist in a porous
medium, surface energy related to the fluid interfaces
influences the saturations, distributions, and
displacement of the phases
• Water coexists with oil in a reservoir even when the
reservoir has not been waterflooded or flooded by a
natural waterdrive
• Even though the water may be immobile in this case,
interfacial forces can still influence performance of
subsequent flow processes
• If a reservoir has been waterflooded or there is a
natural waterdrive, then water saturations will be high
and the water phase will be mobile
• Interfacial forces must then be examined to determine
their significance for oil recovery

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Surface tension and interfacial tension
(IFT)
• The term surface tension is reserved for the surface between a
liquid and a vapor phase
• The term interfacial tension is used for the surface between two
different liquids, or between a liquid and a solid
• The surface tension of water in contact with its vapor at room
temperature is approximately 73 dynes/cm
• IFTs between water and pure hydrocarbons are approximately
30 to 50 dynes/cm at room temperature
• Mixtures of hydrocarbons such as crude oils will have lower IFTs
that depend on the nature and complexity of the liquids
49
Surface tension and interfacial tension
(IFT)
• The simplest way to measure surface tension of a liquid is to
use a capillary tube
• When a capillary tube of radius r is placed in a beaker of water,
the water will rise in the capillary tube to a certain height, h
• At static conditions, the force owing to surface tension will
balance with the fore of gravity acting on the column of liquid

• Solving for 𝜎,

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Surface tension and interfacial tension
(IFT)

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Surface tension and interfacial tension
(IFT)
• Measuring the contact angle, 𝜃, and the height of the liquid
column, then the surface tension can be determined
• Example: Calculate the surface tension of water at 77 oF if 𝜃 =
8o, the capillary radius is 100 mm, and the height of the water
column is 12 cm

52
Capillary Pressure
In reservoir rocks bearing oil and water phases, the pressure in
the oil phase is different from the pressure in the water phase.
The pressure difference between the fluid phases is due to
• Immiscibility between the fluids
• Curvature of the surface between the fluids
• Surface/interfacial tension between fluids
• Surface tensions between porous rock surface and fluids
• Wettability preference

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Capillary Pressure
More specifically, capillary pressure is controlled by
• Pore size and pore size distribution
• Pore throat size and its distribution
• Connectivity of pores
• Wettability preference
• Contact angle

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Capillary Pressure
The minimum pressure required to overcome the capillary
pressure in the largest tube (pore) is known as the capillary
threshold pressure
The capillary threshold pressure is also known as
• minimum displacement pressure
• minimum entry pressure

where R – radius of the largest

pore

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Capillary Pressure
For porous rock, the capillary pressure is defined as the
difference between the non-wetting and wetting immiscible fluids
occupying the pore space of the rock sample

𝑃 𝑐 = 𝑃 𝑛𝑤 − 𝑃 𝑤

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 1.4 Drainage and
Imbibition Process

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Drainage
In a drainage process, the saturation of the non-wetting phase
increases and the saturation of the wetting phase decreases; Sw
goes down.

Examples of drainage process?

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Imbibition
On the contrary, in an imbibition process, the saturation of the
wetting phase rises, and the saturation of the non-wetting phase
is suppressed; Sw goes up

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Capillary Pressure Curve
For porous rock, the capillary
pressure is defined as the
difference between the non-
wetting and wetting immiscible
fluids occupying the pore space
of the rock sample

60
Capillary Pressure Curve

61
1.5 Primary, secondary,
and tertiary oil recovery

62
 Primary Recovery

Rock and liquid expansion Depletion Drive

Water Drive Gas Cap Drive
Combination drive Gravity Drainage drive

Secondary Recovery

Waterflooding Immiscible gas injection

Tertiary Recovery

CO2 immiscible
Chemical Miscible Injection Thermal Microbial
Injection

Polymer flood Miscible Solvent Steam Injection

Surfactant Flood Enriched gas drive In situ
Alkaline Flood CO2 injection combustion
63
1.6 Primary reservoir
drive mechanisms

64
Primary Drive Mechanisms
• Solution gas drive
Expansion of oil and originally dissolved gas
• Gas cap drive
Expansion of free gas
• Natural water drive
Expansion of aquifer water with influx into reservoir displacing hydrocarbon fluids
• Compaction drive
Pore volume contraction, reduces porosity, forcing fluids out of pore space
• Gravity drainage
Oil drains downdip from gas cap, gas migrate updip from oil column
• Combinations drive

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Solution gas drive: expansion of oil and
dissolved gas
• Rapid and continuous pressure
decline
• Low initial production GOR
• Oil production rate constantly
declining
• Little or no water production
• Low oil recovery: 5 – 30% OOIP
• Gas reservoirs: high recovery,
70 – 90% OGIP

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Gas cap drive: expansion of free gas
• Slow decline of reservoir pressure
• GOR rises continuously
• Oil production rate declines slowly
and continuously
• Negligible water production
• Moderate oil recovery: 20 – 40%
OOIP

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Natural Water Drive: water influx
from aquifer displacing oil/gas
• Pressure decline is relatively
small
• Little change in production GOR
• Early water production may occur
• High oil recovery: 35 – 75% OOIP
• Gas reservoirs: gas trapped
(residual saturation) behind water
front.
• Gas recovery: 50 – 70% OGIP

68
Compaction drive: Pore volume
contraction, reduces porosity, forcing
fluids out of pore space
• Rapid pressure decline
• High rock compressibility
Normal values: 3 to 8 × 10-6 1/psi
• High values: > 50 × 10-6 1/psi
• Can lead to subsidence at surface
• Least efficient driving mechanism

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Gravity drainage: Oil drains
downdip from gas cap, gas
migrate updip from oil column
• Variable rate of pressure
decline
• Low GOR for structurally low
wells, increasing GOR for high
wells
• Little or no water production
• Oil recovery vary widely: up to
80% OOIP

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Combinations drive: water and
free gas are available to displace
oil, with solution gas drive
• Relatively rapid pressure
decline
• GOR continuously increase
• Slowly increasing water
production for structurally low
wells
• Oil recovery: greater than
solution gas drive, less than
water or gas cap drive
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Summary of drive mechanisms

72
References
1. Senturk, Y. (2011). Essence of the SPE petroleum resources
management system - definitions and guiding principles for
classification, categorization and assessment process. All
Days. https://doi.org/10.2118/149078-ms
2. McCain, W. D.: The Properties of Petroleum Fluids, Second
Edition, PennWell Books, 1990

73