part+1+Fundamebtals+of+reservior+engineering-+Abbas+Radhi+2020-converted.pptx

Part : 1
Reservoir Engineering
Fundamentals of petroleum Engineering
By
Petroleum Engineer
Abbas Radhi Abbas
Iraq / Missan / 2020
1

6.Determined hydrocarbon in place
5.Reservoir Classifications
Contents
1.Reservoir Engineering Functions
2. Introduction to Reservoir Engineering
3.Type of Hydrocarbon Reservoir Traps
4.Basic Rock and Fluid Properties
7.Enhanced Oil Recovery (EOR)
8.Reservoir Surveillance
9.Tracer Techniques
10. Reservoir management
2
Contents
Reservoir
Engineering
Fundamentals

(1) Reservoir Engineering Functions
3

Determined hydrocarbon in place
(1) Reservoir Engineering Functions
Determine Reserves Determine rates
1. Analogy Method
2. Volumetric method
3. Material Balance
4. Decline curve analysis
5. Reservoir simulation
4
 Primary recovery phase
1. Expansion
2. Solution gas drive
3. Gas Cup drive
4. Water drive
5. Gravity drainage
6. Combination
 Supplemental recovery phase
 Secondary recovery
1. Water injection
2. Gas injection
 EOR
1. Miscible injection
2. Thermal recovery
3. Chemical injection
 Number of wells
 Well potential
1. Completion
2. Reservoir permeability and thickness
3. Reservoir homogeneity

2-Introduction to Reservoir Engineering
5

The reservoir engineer in the multi-disciplinary perspective of modern oil and
gas
field management is located at the heart of many of the activities acting as a central
co-ordinating role in relation to receiving information processing it and passing it on
to others.
6

The activities of reservoir engineering fall into the following three general
categories: Activities
of
Reservoir
Engineering
(A) Reserves Estimation
(B) Development Planning
(C) Production Operations Optimization
7

The Society of Petroleum Engineers SPE and World Petroleum Congress
WPO1987
agreed classification of reserves3 provides a valuable standard by which to define
reserves, the section below is based on this classification document. :
8

9
Reserves :
are those quantities of petroleum which are anticipated to be commercially
recovered from known accumulations from a given date forward.
(A) Proven Reserves
Proven reserves are those quantities of petroleum which, by analysis of
geological
and engineering data, can be estimated with reasonable certainty to be
commercially
recoverable, from a given date forward, from known reservoirs and under current
economic conditions, operating methods, and government regulations.
There should be at least a 90 percent probability (P90) that the quantities actually
recovered will equal or exceed the estimate.

10
(B) Unproved Reserves
Unproved reserves are based on geologic and/or engineering data similar to that
used in estimates of proved reserves; but technical, contractual, economic, or
regulatory uncertainties preclude such reserves being classified as proved.
Unproved reserves may be further classified as probable reserves and possible
reserves.
1-Probable Reserves
•Those additional reserves that analysis of geoscience and engineering data
indicate are less likely to be recovered than proved reserves but more certain to be
recovered than possible reserves.
•There should be at least a 50 percent probability (P50) that the quantities actually
recovered will equal or exceed the estimate...
2-Possible Reserves
•Those additional reserves that analysis of geoscience and engineering data suggest
are less likely to be recoverable than probable reserves.
•There should be at least a 10 percent probability (P10) that the quantities actually
recovered will equal or exceed the estimate.

Relationships between parameters related with OOIP , RF and Reserve
RESERVES : Reserves are simply the oil or gas in place times the RF.
for an oil reservoir:
for a gas reservoir:
Recovery Factor ( RF)
11

Relationships between parameters related with OOIP , RF and Reserve
OOIP
RF
12
Reserves = OOIP X RF
OOIP : Original Oil in place
RF : Recovery factor

13
Variations of reserves During filed life

(B) Development Planning
1. Static model
2. Dynamic Model
3. Techno-economics
4. Uncertainty
The following list summarises some of the principal uncertainties
associated with the performance of the overall reservoir model.The
type of data can for example be subdivided into two aspects “static”
and “dynamic” data .
Static Properties
• Reservoir structure
• Reservoir properties
• Reservoir sand connectivity
• Impact of faults
• “thief” sands
Dynamic Properties
• Relative permeability etc
• Fluid properties
• Aquifer behavior
• Well productivity (fractures, well-type, condensate drop outetc.)
14

1-History Matching
The purpose of history matching is to calibrate the numerical simulation model
so that it can be used to reasonably predict the future performance of the
reservoir(s) under various development and operating scenarios
15

16
2-Phases of Development
During the development there are a number of phases. Not all of these phases
may be part of the plan. There is the initial production build up to the capacity
of the facility
There is the plateau phase where the reservoir is produced at a capacity
limited by the associated production and processing facilities. Different
companies work with different lengths of the plateau phase and each project
will have its own duration. There comes a point when the reservoir is no longer
able to deliver fluids at this capacity and the reservoir goes into the decline
phase. The
decline phase can be delayed by assisting the reservoir to produce the fluids
by the use of for example ‘lifting’ techniques such as down-hole pumps and
gas lift. The decline phase is often a difficult period to model and yet it can
represent a significant amount of the reserves

Phases of Production
17

Primary , secondary & Tertiary recovery
18

(3) Type of Hydrocarbon Reservoir Traps
19

(3) Type of Hydrocarbon Reservoir Traps
20

Structural Traps
Structural Traps
Structural traps are created by the deformation of rock strata within the earth’s crust. This
deformation can be caused by horizontal compression or tension, vertical movement and
differential compaction, which results in the folding, tilting and faulting within sedimentary
rock formations
Fault Trap
The faulting of
stratified rock occurs as a result of
vertical and horizontal stress. At
some point the rock layers break,
resulting in the rock faces alongthe
fracture moving or slipping past
each other into an offsetposition.
A fault trap is formed when the
faulted formations are tiltedtoward
the vertical. When a non-porous
rock face is moved into a position
above and opposite a porous rock
face, it seals off the natural flow of
the hydrocarbons allowing them to
accumulate.
21

Structural Traps
Fold (Anticlinal) and Dome Trap
The rock layers
in an anticlinal trapwere
originally laid down
horizontally then folded
upward into an arch or
dome. Later,
hydrocarbons migrate
into the porous and
permeable reservoir
rock. A cap or seal
(impermeable layer of
rock) is required to
permit the accumulation
of the hydrocarbon
22

Stratigraphic Traps
23
Stratigraphic traps
are formed as a
result of differences or variations
between or within stratified rock
layers, creating a change or lossof
permeability from one area to
another. These traps do not occur
as
a result of movement of the strata.

Combination Traps
Salt Dome or Salt Plug Trap
A trap created by piercement or
intrusion of stratified rock layers from
below by ductile nonporous salt. The
intrusion causes the lower formations
nearest the intrusion to be upliftedand
truncated along the sides of the
intrusion, while layers above are
uplifted creating a dome or anticlinal
folding. Hydrocarbons migrate into
the porous and permeable beds onthe
sides of the column of salt.
Hydrocarbons accumulate in the traps
around the outside of the salt plug if a
seal or cap rock is present.
24

(4) Basic Rock and Fluid Properties
26

(4) Basic Rock and Fluid Properties
27
There are four fundamental types of properties of a hydrocarbon reservoir
that control its initial contents, behavior, production potential, and hence
its reserves.
1. The rock properties of porosity, permeability, and compressibility, which
are all dependent on solid grain/particle arrangements and packing.
2.The wettability properties, capillary pressure, phase saturation, and relative
permeability, which are dependent on interfacial forces between the
solid and the water and hydrocarbon phases.
3.The initial ingress of hydrocarbons into the reservoir trap and the
thermodynamics of the resulting reservoir mixture composition.
4. Reservoir fluid properties, phase compositions, behavior of the phases
with pressure, phase density, and viscosity.

Basic Rock Properties
28
Rock Properties
1. Porosity
2. Permeability
3. Wettability
4. Saturation
5. Capillary Pressure

Generally can estimate rock properties from core Analysis , logs , see the
SCAL and RCAL
Routine Core Analysis Special CoreAnalysis
29

1-Porosity:
is defined as the ratio of pore volume to total rock volume:
Where :
Vp = pore space volume
Vb = bulk volume
Porosity Measurements :Porosity is measured in two ways :
1. from wire line logs
2. Laboratory measurement on core
1-Porosity from wire line logging :
Porosity can be estimated from interpretation of wire line logs, in particular
Acoustic ( sonic) , neutron, Density & NMR logs.
30

2-Porosity Laboratory measurement on core:
Porosity is calculated using the following equation:
Where :
Vp : pore space volume
Vm : matrix (solid rock) volume
Vb : bulk volume (Vp + Vm)
Bulk volume (Vb) can be determined directly from core dimensions
if we have a fluid-saturated regularly shaped core (normally cylindrical),
or by fluid displacement methods by weight where the density of the
solid matrix and the displacing fluid is known, or directly by volume
displacement.
Matrix volume (Vm) can be calculated from the mass of a dry sample
divided by the matrix density. It is also possible to crush the dry solid and
measure its volume by displacement, but this will give total porosity rather
than effective (interconnected) porosity.
31

Boyle’s law : used to calculate the
matrix volume present in the
second
cell using Boyle’s law .This method
can be very accurate, especially
for low-porosity rock.
Boyle’s law: P1V1 = P2V2
(assuming gas deviation factor Z
can be
ignored at relatively low pressures)
can now be used.
Pore space volume (Vp) can also
be determined using gas
expansion
methods.
32

2-Permeability :
Permeability: Is the property a rock has to transmit fluids. It is related to
porosity but is not always dependent upon it. Permeability is controlled by the
size of the connecting passages (pore throats or capillaries) between pores. It
is measured in darcies or milli-darcies
absolute permeability : the ability of a rock to transmit a single fluid when it is
100% saturated with that fluid
Effective permeability : refers to the presence of two fluids in a rock, and is the
ability of the rock to transmit a fluid in the presence of another fluid when the
two fluids are immiscible
Relative permeability : is the ratio between effective permeability of fluid at
partial saturation, and the permeability at 100% saturation (absolute
permeability).
33

relative permeability
To account for the effect of multiple fluids,
relative permeability's are defined as follows:
Water oil relative permeability
Typical relative permeability curves for oil
and water are shown in Figure Oil
permeability decreases monotically from its
maximum at the irreducible water saturation,
krowe, to zero at the residual oil saturation to
water. Water permeability increases
monotonically from zero at the irreducible
water saturation to a maximum at the
residual oil saturation, krwe.
Typical water- oil relative permeability curves.
34

relative permeability
Gas-oil relative permeability
Gas-oil permeabilities are usually
measured in samples presaturated
with water so that irreducible water
is present in the sample as it would
be in the reservoir. The relative
permeabilities of oil and gas are
plotted against either liquid (oil plus
water)
Typical Gas- oil relative permeability curves.
35

Measurement of Relative Permeability
There are two ways of measuring relative permeabilities in the laboratory.
1. Steady-state methods.
2. Unsteady-state methods.
Steady-state methods involve the simultaneous injection of two or more
phases into a core of porous material. The flow ratio is fixed, and the test
proceeds until an equilibrium is reached such that the pressure drop across
the core has stabilized. The data obtained are used with Darcy’s law to
calculate the relative permeabilities of each phase. The flow ratio is changed
to give relative permeabilities over the full range of saturations.
The advantage of steady-state methods is that it is simple to interpret
resulting data. It is, however, time-consuming since a steady state can take
many hours to achieve.
Unsteady-state methods are an indirect technique in which the relative
permeabilities are determined from the results of a simple displacement test.
Flow-rate data for each phase are obtained from the point at which the
injected phase breaks through and we have two-phase flow
36

Measurement of Permeability :
1. From Core (Laboratory Determination of Permeability)
2. Well test
3. Darcy’s Law in Field Units
4. Formation tester
5. From log and NMR log
37
Vertical and Horizontal Permeability :
It is normally (but not always) assumed that horizontal permeability is the
same in each direction; but vertical permeability is often, and particularly in
clastics, significantly smaller than horizontal permeability when sediments
are frequently poorly sorted, angular, and irregular. Vertical/horizontal
(kv/kh) values are typically in the range 0.01- 0.1.

1. From Core (Laboratory Determination of Permeability)
Laboratory Determination of Permeability Single-phase absolute permeability is
measured on core in a steel cylinder where pressures P1 and P2 are measured
for a given gas flow rate Q.
For a gas: from Darcy’s law for
horizontal flow,
For an incompressible liquid: for
horizontal flow
Where : Q : volumetric flow rate (cm3/s); A : area (cm2); m : viscosity of
the gas or liquid; P : pressure (atmospheres); x : length of core (cm). This
gives the value for permeability k in Darcy’s equation.
38

For a constant production flow rate Q,
permeability can be estimated from
average formation thickness h, fluid
viscosity m, bottom hole pressure Pw,
initial reservoir pressure Pe at an
assumed undisturbed (still at initial
conditions) distance re from the well
and wellbore radius rw using the
equations.
2-Permeability From Well-Test
Analysis
39

Where :
k is in milli-Darcies (mD);
u is in RB/day/ft2;
dx dp is in psi/ft;
m is in centipoise (cP);
Y is specific gravity (dimensionless)
3- from Darcy’s Law in Field Units
In field units the Darcy equation will be
40

interfacial energy between oil and solid (dyne/cm)
interfacial energy between water and solid (dyne/cm)
interfacial energy, or IFT, between oil and water (dyne/cm)
contact angle at oil–water–solid interface measured through the water phase(degrees)
3-Wettability
Wettability is the ability of a fluid phase to wet a solid surface preferentially in the
presence of a second immiscible phase. The wetting, or wettability, condition in a
rock–fluid system depends on IFT. Changing the type of rock or fluid can change
IFT and hence the wettability of the system. Adding a chemical such as
surfactant,
polymer, corrosion inhibitor, or scale inhibitor can alter wettability.
Wettability is measured by contact angle, which is always measured through the
denser phase and is related to interfacial energies by
41

Wettability
Contact angles for oil-wet and water-wet examples are illustrated in Figure
(A)
Wettability is usually measured in the laboratory. Table (--) presents
examples
of contact angles for different wetting conditions. Several factors can affect
laboratory measurements of wettability. Wettability can be changed by
contact of the core during coring with drilling fluids or fluids on the rig floor,
and by contact of the core during core handling with oxygen or water from the
atmosphere. Laboratory fluids should also be at reservoir conditions to obtain
the most reliable measurements of wettability.
Figure (A)
Table ( --)
42

Special Core Analysis
 Core measurements include
imbibition and centrifuge
 capillary pressure measurements
 An Amott imbibition test
compares the spontaneous
imbibition of oil and water to the
total saturation change obtained
by flooding. We will also see later
pressure and
permeability
give an idea of
that capillary
relative
measurements
rock wettability
Measuring Wettability
Several methods are available to
measure a reservoir’s wetting
preference.
43

Where:
Sw : water saturation
So : oil saturation
Sg : gas saturation
4-Saturation
Saturation is the proportion of
interconnected pore space
occupied by a given phase. For
a gas –oil-water system
Routine Core Analysis
44

Where :
Pc : capillary pressure (psi)
Pnw : pressure in non-wetting phase (psi)
Pw : pressure in wetting phase (psi)
5-Capillary Pressure
Capillary pressure is the pressure difference across the curved interface
formed by two immiscible fluids in a small capillary tube. The pressure
difference is
45

Where :
Po :pressure in the oil phase (psia)
Pw : pressure in the water phase (psia)
Capillary pressure increases with height above the oil–water contact (OWC)
as
water saturation decreases.
Oil–Water Capillary Pressure
Oil is the non-wetting phase in a water-wet oil–water reservoir. Capillary
pressure
for an oil–water system is
46

Where :
Pg : pressure in the gas phase (psia)
Po : pressure in the oil phase (psia)
Capillary pressure increases with height above the gas–oil contact (GOC) as
the
wetting phase saturation decreases.
Gas–Oil Capillary Pressure
In gas–oil systems, gas usually behaves as the non-wetting phase, and oil is
the
wetting phase. Capillary pressure between oil and gas in such a system is
47

Capillary Pressure measurement
Can estimate the Capillary
pressure from special core
analysis ,
Capillary pressure is usually
determined in the laboratory by
centrifuge experiments
that provide a relationship
between capillary pressure Pc
and water saturation Sw. A typical
Pc versus Sw curve has the
following features
48

 Reservoir Fluid Properties can Estimated from PVT sample
• Oil Compressibility
• Saturation Pressure
• Live Oil Viscosity
• Live Oil Density
• Oil Formation Volume Factor
• Gas-Oil Ratio
• Liberated Gas Formation Volume factor
• Incremental Liberated Gas-Gravity
• Cumulative liberated Gas-Gravity
49
Basic Fluid Properties

 • Types of fluid Sampling
(1)Sub-surface sampling (Down-hole sampling)
1-DST strings
2 Wireline sample ( MDT – in open hole )
3 Slickline ( cased hole )
(2)Surface sampling
1-Wellhead samples
2-Separator samples
Sub-surface sampling for Oil Reservoirs Subsurface
samples are generally taken with the well shut-in.
The sample should be taken under single-phase
conditions, Pres > Pb The well should be fully
cleaned up A static pressure gradient survey should
be performed either prior to or during sampling to
check for the presence of water at the bottom of the
well
50

Surface sampling for Oil/gas Reservoirs Sampling at the wellhead Valid
fluid samples are only likely to be obtained if the fluid is single-phase at
the wellhead Poses safety hazards (high-pressure fluid...) Sampling at
the separator Easier, safer, cheaper Only reliable surface method if fluid
is two-phase at the wellhead
Wellhead sampling Sample point should be as near wellhead as possible
Separator sampling The most important factor in separator sampling is
stability of conditions Stabilized gas and oil flow rates (and therefore
GOR) Stabilized temperature Stabilized wellhead pressure Gas and
liquid samples should be taken simultaneously, as they are a matched
pair Oil and gas rates must be measured carefully Sample points must
be as close to the separator as possible
51

Separator sampling
52

The following terms are defined for the black oil model:
Bo :oil formation volume factor (rb/stb or m3/scm)
= the ratio of oil volume at reservoir conditions to the oil volumeat
surface conditions
Rs : solution gas-oil ratio ratio (SCF=stb or scm=scm)
= the ratio of the standard volume of solution gas dissolved inthe
oil at a given pressure to the oil volume at surfaceconditions
Bg : gas formation volume factor (rb=SCF or m3/scm)
= the ratio of gas volume at a reservoir conditions to thegas
volume at surface conditions
Bw : water formation volume factor (rb=stb or m3/scm)
= the ratio of water volume at reservoir conditions to thewater
volume at surface conditions
53

Bubble point pressure (pb)
Bubble point pressure (pb) is the Pressure at which first bubble of gas is released from
reservoir oils
Gas oil ratio (GOR)
Gas oil ratio (GOR)=total associated gas (SCF) / total crude production (STB) @ 60 f, 14.7
psi
Shrinkage factor (SF)
Shrinkage factor (SF) = Stock tank barrel (STB) / reservoir fluid barrel
Fluid Viscosity (µo,g,w)
Is a measure of a fluid's internal resistance to flow
Fluid viscosity depends on pressure, temperature, and fluid composition.
Typical values:
Oil: 0.2 to 30 cp
Gas: 0.01 to 0.05 cp
Water: 0.5 to 1.05 cp
54

Example of Black oil properties
56

(5) Reservoir Classifications
57

(5) Reservoir Classifications
1. Clastic Reservoir
2. Carbonate Reservoir
According to fluid properties
According to Rock type
According to phase behavior
According to drive mechanism
1. Black oil
2. Volatile Oil
3. Retrograde condensate gas
4. Wet gas
5. Dry gas
1. Single phase gas
2. Gas condensate
3. Under saturated oil
4. saturated oil
2. Gas Cup drive
3. Water drive
4. Gravity drainage drive
5. Combination drive
58

•The Five Reservoir Fluids
1-According to fluid properties
According to fluid properties
1. Black oil
2. Volatile Oil
3. Retrograde condensate gas
4. Wet gas
5. Dry gas
59

Black Oil Reservoirs:
•GOR < 1,000 SCF/STB
•Density less than 45° API
•Reservoir temperatures < 250°F
•Oil FVF < 2.00 (low shrinkage
oils)
•Dark green to black in color
•C7+ composition > 30%
60
Black Oil Reservoirs:

Volatile Oil Reservoirs:
•1,000 < GOR < 8,000 SCF/STB
•Density between 45-60° API
•Oil FVF > 2.00 (high shrinkage
oils)
•Light brown to green in color
•C7+ composition > 12.5%
Volatile Oil Reservoirs:
61

Gas Condensate Reservoirs:
•70,000 < GOR < 100,000
SCF/STB
•Density greater than 60° API
•Light in colour
•C7+ composition < 12.5%
Gas Condensate Reservoirs:
62

Wet Gas Reservoirs:
•GOR > 100,000 SCF/STB
•No liquid is formed in the reservoir.
•Separator conditions lie within
phase envelope and liquid is
produced at surface.
Wet Gas Reservoirs:
63

Dry Gas Reservoirs:
•GOR > 100,000 SCF/STB
•No liquid produced at surface
Dry Gas Reservoirs:
64

Range of Reservoir fluid properties
65

2-According to Rock type
66
 Reservoir must be ( porous , permeable & Trapped )
 Any reservoir and formation should know the petro-physical
properties :
1. Porosity
2. Permeability
3. Wettability
4. Saturation
5. Capillary Pressure
 petro-physical properties can calculated from :
1. Well logging
2. Core
3. Well test

1. Clastic Reservoir
2. Carbonate Reservoir
According to Rock type
2-According to Rock type
67
1-Clastic Reservoir
• Consist primarily of Silicate Mineral ( Quartz SiO2)
• Sandstone porosity ( 10-30 )%
2-Carbonate Reservoir
• Mean limestone and dolomite
• Limestone is better than dolomite for ( porosity and permeability )

According to phase behavior
1. Single phase gas
2. Gas condensate
3. Under saturatedoil
4. saturated oil
3-According to phase behavior
69

Pressure-temperature phase diagram
for
multicomponent hydrocarbon reservoir
fluid mixture. For
isothermal production in the reservoir:
position Aindicates
reservoir fluid found as an under
saturated oil;
position B
indicates reservoir fluid found as a gas
condensate;
position C indicates reservoir fluid
found as a dry gas
70
Pressure-temperature phase diagram

4-According to drive mechanism
According to drive mechanism
2. Gas Cup drive
3. Water drive
4. Gravity drainage drive
5. Combination drive
Drive Mechanism
The natural energy of the reservoir used to transport hydrocarbons towards and out of the
production wells
.
There are five important drive mechanisms (or combinations).
1. Solution Gas Drive.
2. Gas Cap Drive.
3. Water Drive.
4. Gravity Drainage.
5. Combination or Mixed Drive
A combination or mixed drive occurs when any of the first three drives operate together
or when any of the first three drives operate with the aid of gravity drainage.
71

1- Solution Gas Drive
Solution Gas Drive:
Gas breaks out of solution and
expanding gas maintains pressure
in reservoir somewhat over time
72
Characteristics Trend
Reservoir Pressure Declines rapidly and continuously
Gas/Oil Ratio First low then rises to a maximum and then drops
Production Rate continues to decline First high, then decreases rapidlyand
Water Production None
Well Behavior Requires artificial lift at early stages
Expected Oil Recovery 5-30% of original oil-in-place

Gas Cap Drive:
Gas in gas cap is expanding as pressure
depletes, maintaining pressure somewhat
overtime (later stages of solution gas drive)
73
2.Gas cap Drive.
Reservoir Pressure Falls slowly and continuously
Gas/Oil Ratio Rises continuously
Production Rate First high, then declines gradually
Water Production Absent or negligible
Well Behavior Cap Long flowing life depending on size of gas cap
Expected Oil
Recovery
20 to 40% of original oil-in-place

.
Water Drive
Large aquifer volume expands
providing pressure for relatively
small oil volume. Can be
supplemented with water injection
Over time:
3.Water Drive.
Reservoir Pressure Remains high
Gas/Oil Ratio Remains steady
Water Production tarts early and increases to appreciable amounts
Well Behavior Cap Flow until water production gets excessive
Expected Oil
Recovery
up to 60% original oil-in-place.
74

Gravity Drainage Drive
Usually for heavy oils with very little or no
gas.
Oil literally is produced as the density of the
oil drops and oil moves under force of
gravity.
Normally accompanied by artificial lift.
Can also be supplemented with water
injection.
Over Time:
Reservoir pressure remains low.
GORvery low if at all.
75
4.Gravity Drainage.

5.Combination or Mixed Drive
76
5.Combination or Mixed Drive
combination drives : we have a gas cap
with the oil accumulation underlain
by water providing potential water drive
.So both free gas and water are in
contact with the oil.
In such a reservoir some of the energy
will come from the expansion of the gas
and some from the energy within the
massive supporting aquifer and it is
associated compressibility.

Reservoir Drive Indexes from the Material Balance Equation (MBE)
A general Material Balance Equation that can be applied to all reservoir types was
first developed in 1936. Although it is a tank model equation, it can provide great
insight for the practicing reservoir engineer.
Reservoir Drive Indexes from the Material Balance Equation (MBE)
77

(6) Determined hydrocarbon in place
78

79
Five methods to Determined hydrocarbon in place :
1. Analogy Method
2. Volumetric method
3. Material Balance Method
4. Decline curve analysis Method
5. Reservoir simulation Method

1 Analogy method
The analogy method is applied by comparing factors for the analogous and
current fields or wells. A close-to-abandonment analogous field is taken as
an approximate to the current field. This method is most useful when running
the economics on the current field; which is supposed to be an exploratory
field.
2 Volumetric method
The volumetric method, on the other hand, entails determining the areal
extent
of the reservoir, the rock pore volume, and the fluid content within the pore
volume. This provides an estimate of the amount of hydrocarbons-in-place.
The
ultimate recovery, then, can be estimated by using an appropriate recovery
factor.
 Each of the factors used in the calculation above have inherent
uncertainties that, when combined, cause significant uncertainties in the
reserves estimate. 80

Volume of Oil Initially In Place (OIIP)
To estimate oil initially volume in place, the following formula is a
volumetric calculation for oil.
Where;
STOIIP = stock tank oil in place, stb
A= area, acre
h = reservoir thickness, ft
ɸ
= rock porosity, %
Swc =connate water saturation, %
Boi = oil formation volume factor, rb/stb
Note: the stock tank condition is a standard surface condition of oil and
gas at 60F and 14.7 psia.
81

Volume of Gas Initially In Place (GIIP)
The formula to determine gas in place is listed below;
Where;
G = gas oil in place at standard condition, scf
A= area, acre
h = reservoir thickness, ft
ɸ
= rock porosity, %
Swc =connate water saturation, %
Bgi = gas formation volume factor, rcf/scf
Note: This is the same formula as the oil in place but only constant is
different because of volume of gas is reported in cu-ft.
82

3-Material balance calculation
is an excellent tool for estimating
gas reserves. If a reservoir
comprises a closed system and
contains single-phase gas, the
pressure in the reservoir will
decline proportionately to the
amount of gas produced.
Unfortunately, sometimes bottom
water drive in gas reservoirs
contributes to the depletion
mechanism, altering the
performance of the non-ideal gas
law in the reservoir. Under these
conditions, optimistic reserves
estimates can result.
83

84
4-decline analysis and material balance
As production and pressure data from a field become available, decline analysis
and material balance calculations, become the predominant methods of calculating
reserves. These methods greatly reduce the uncertainty in reserves estimates.
Decline curve relationships are empirical, and rely on uniform, lengthy production
periods. It is more suited to oil wells, which are usually produced against fixed bottom-
hole pressures. In gas wells, however, wellhead back-pressures usually fluctuate,
causing varying production trends and therefore, not as reliable .
The most common decline curve relationship is the constant percentage decline
(exponential). With more and more low productivity wells coming on stream, there
is currently a swing toward decline rates proportional to production rates
(hyperbolic and harmonic). Although some wells exhibit these trends, hyperbolic or
harmonic decline extrapolations should only be used for these specific cases. Overe-
xuberance in the use of hyperbolic or harmonic relationships can result in
excessive reserves estimates
.

(7) Enhanced Oil Recovery (EOR)
85

(7) Enhanced Oil Recovery (EOR)
EOR / IOR definition
86

EOR methods : used to improve reservoir recovery efficiency, and explain
their differences For each method, state whether it can improve
displacement, vertical or areal sweep efficiency and explain how it works.
1 Primary recovery
Primary recovery, using ( the natural energy of reservoirs and artificial lift ) ,
typically recovers up to 50% of OOIP (average 19%).
2 Secondary recovery
Secondary recovery involves adding energy to the natural system by
injecting water to maintain pressure and displace oil (also known as water
flood). Typical recoveries are 30-50% of OIP after primary recovery (average
32%).
3 Tertiary recovery
Tertiary recovery includes all other methods used to increase the amount of
oil recovered ( thermal , gas injection , chemical injection , others ) . Typical
recoveries are more than 50% of OIP .
87
What is the (EOR) ?

 The goal of any enhanced oil recovery process is to mobilize "remaining" oil.
 This is achieved by enhancing oil displacement and volumetric sweep
efficiencies.
 Oil displacement efficiency is improved by reducing oil viscosity (e.g.,
thermal floods) or by reducing capillary forces or interfacial tension (e.g.,
miscible floods).
 Volumetric sweep efficiency is improved by developing a more favorable
mobility ratio between the injection and the remaining oil-in-place (e.g.,
polymer floods, water alternating- gas processes).
 It is important to identify remaining oil and the mechanisms that are
necessary to improve recovery prior to implementing an EOR process.
88
Objective of EOR

 Water-flooding : use water
 Thermal methods: steam stimulation, steam-flooding, hot water drive, and
in- situ combustion
 Chemical methods: polymer, surfactant, caustic, and micellar/polymer
flooding
 Miscible methods: hydrocarbon gas, CO2, and nitrogen (flue gas and
partial miscible/immiscible gas injection may also be considered)
EOR methods
89

 Description
Water-flooding consists of injecting water into the reservoir. Most widely used
post-primary recovery method. Water is injected in patterns or along the
periphery of the reservoir.
Mechanisms that Improve Recovery Efficiency
• Water drive
• Increased pressure
Limitations
• High oil viscosities result in higher mobility ratios.
• Some heterogeneity is acceptable but avoid extensive fractures.
Challenges
• Poor compatibility between the injected water and reservoir may cause
formation damage
Water-flooding
90

Water-flooding
Different well pattern :
91

To increase ultimate oil production beyond that achievable with primary and
secondary methods, there are a few steps to undertake.
1. First, an improvement of the sweep efficiency must ensue.
2. This is then followed by a reduction of the amount of residual oil in the
swept zone.
3. Thirdly, there must be an increase in the displacement efficiency.
4. And finally, there must be a reduction in the viscosity of thick oils.
Here will explain :
1. Surfactant / Polymer Flooding
2. Polymer Flooding
92
Chemical oil recovery methods

Surfactant / Polymer Flooding
93
 Description
Surfactant / polymer flooding consists of injecting slug that contains water,
surfactant, electrolyte (salt), usually a co-solvent (alcohol), followed by
polymer-thickened water.
• Interfacial tension reduction (improves displacement sweep efficiency).
• Mobility control (improves volumetric sweep efficiency).
Limitations
• An areal sweep of more than 50% for water-flood is desired.
• Relatively homogeneous formation.
• High amounts of anhydrite, gypsum, or clays are undesirable.

Challenges
• Complex and expensive system.
• Possibility of chromatographic
separation of chemicals.
• High adsorption of surfactant.
• Interactions between surfactant
and polymer.
• Degradation of chemicals at high
temperature.
Surfactant / Polymer Flooding
94

Polymer Flooding
95
 Description
Polymer augmented waterflooding consists of adding water soluble polymers
to the water before it is injected into the reservoir.
• Mobility control (improves volumetric sweep efficiency).
Limitations
• High oil viscosities require a higher polymer concentration.
• Results are normally better if the polymer flood is started before the water-
oil ratio becomes excessively high.
• Clays increase polymer adsorption.
• Some heterogeneity is acceptable, but avoid extensive fractures.

Challenges
• Lower injectivity than with water
can adversely affect oil
production rates in the early
stages of the polymer flood.
• Xanthan gum polymers cost
more, are subject to microbial
degradation, and have a greater
potential for wellbore plugging.
Polymer Flooding
96

Miscible Gas Flooding ( CO2 injection )
97
 Description
CO2 flooding consists of injecting large quantities of CO2 (15% or more
hydrocarbon pore volumes) in the reservoir to form a miscible flood.
• Components from the oil, and, if the pressure is high enough, develops
miscibility to displace oil from the reservoir.
• Viscosity reduction / oil swelling.
Limitations
• Very low viscosity of CO2 results in poor mobility control.
• Availability of CO2
• Surface facilities

Challenges
• Early breakthrough of CO2
causes problems.
• Corrosion in the producing wells.
• The necessity of separating CO2
from saleable hydrocarbons.
Repressuring of CO2 for
recycling.
• A large requirement of CO2 per
incremental barrel produced.
Miscible Gas Flooding ( CO2 injection )
98

Miscible Gas Flooding (Hydrocarbon Injection)
99
 Description
Hydrocarbon gas flooding consists of injecting light hydrocarbons through the
reservoir to form a miscible flood.
• Viscosity reduction / oil swelling / condensing or vaporizing gas drive.
Limitations
• Minimum depth is set by the pressure needed to maintain the generated
miscibility. The required pressure ranges from about 1,200-5000 psi for the
high pressure Gas Drive, depending on the oil.
• A steeply dipping formation is very desirable- permits gravity stabilization of
the displacement that normally has an unfavorable mobility ratio.

Challenges
• Viscous fingering results in poor
vertical and horizontal sweep
efficiency.
• Large quantities of expensive
products are required.
• Solvent may be trapped and not
recovered
Miscible Gas Flooding (Hydrocarbon Injection)
100

Nitrogen / Flue Gas Flooding
101
 Description
Nitrogen or flue gas injection consists of injecting large quantities of gas that
may be miscible or immiscible depending on the pressure and oil composition.
Large volumes may be injected, because of the low cost.
Nitrogen or flue gas are also considered use as chase gases in the
hydrocarbon-miscible and CO2 floods.
• Vaporizes the lighter components of the crude oil and generates miscibility
if the pressure is high enough.
• Provides a gas drive where a significant portion of the reservoir volume is
filled with low-cost gases.
Limitations
• Miscibility can only be achieved with light oils at high pressures; therefore,
deep reservoirs are needed.
• A steeply dipping reservoir is desired to permit gravity stabilization of the
displacement, which has a very unfavorable mobility ratio.

Challenges
• Viscous fingering results in poor
vertical and horizontal sweep
efficiency.
• Flue gas injection can cause
corrosion.
• Non hydrocarbon gases must be
separated from saleable gas
Nitrogen / Flue Gas Flooding
102

Thermal (Steam-flooding)
103
 Description
Steam-flooding consists of injecting about 80% quality steam to displace oil.
Normal practice is to precede and accompany the steam drive by a cyclic
steam simulation of the producing wells (called Huff and Puff).
• Viscosity reduction / steam distillation.
• Thermal expansion.
• Supplies pressure to drive oil to the producing well.
Limitations
• Application to viscous oil in massive, high permeability sandstones or
unconsolidated sands.
• Oil saturations must be high, and pay zones should be > 20 feet thick to
minimize heat losses to adjacent formations.
• Steam-flooded reservoirs should be as shallow as possible, because of
excessive wellbore heat losses.

Thermal (Steam-flooding)
More Limitations
• Steam-flooding is not normally done in
carbonate reservoirs.
• Since about 1/3 of the additional oil
recovered is consumed to generate the
required steam, the cost per
incremental barrel of oil is high.
• A low percentage of water-sensitive
clays is desired for good injectivity
Challenges
Adverse mobility ratio and channeling of
steam.
104

Thermal (In SITU COMBUSTION) or "Fire-flooding")
 Description
This method is sometimes applied to reservoirs containing oil too viscous or
"heavy" to be produced by conventional means. Burning some of the oil in situ
(in place), creates a combustion zone that moves through the formation toward
production wells, providing a steam drive and an intense gas drive for the
recovery of oil.
105

EOR process maturity curve-with time
106

(8) Reservoir Surveillance
107

108
 A definition of surveillance
A definition of surveillance that is more suitable for managing hydrocarbon
assets is the : ( continuous process of generating opportunities for improving
reservoir performance )
 History of Reservoir Surveillance
Surveillance techniques were first discussed in the SPE literature in the early
1960s . Since then, reference to surveillance has been made, but mostly in the
context of episodic data gathering to monitor performance, primarily in flooding
situations
The four stages of value creation using measurements, in order of increasing
benefits, are
1. Data
2. Information
3. Knowledge
4. Intelligence

these stages along with the
characteristics pertaining to each
stage. Significant increase in
effort is required for large gains in
value as the information is
converted to knowledge and then
into intelligence. Intelligence is
gained when we possess the
ability to predict the future for a
parameter, property, or system.
The rapidity with which
companies gain system
intelligence differentiates and
distinguishes them from their
competitors
109

Engineering functions and tasks leading to decisions
110

Relating measurements to interpretation and uncertainty reduction
111

Example 1 : plan to identify thief zones and remediate:
112
 Example 1 : plan to identify thief zones and remediate:
Steps :
1. Develop areal distribution maps of movable oil in place.
2. Based on production/injection data, prepare well connectivity maps.
3. Run injection and production profile surveys.
4. Use petrophysical data, injection surveys, and connectivity maps to identify
correlatable thief zones.
5. Plan appropriate data gathering.
6. Evaluate alternatives for shutoff including production curtailment,
debottlenecking, pattern realignment, and facilities upgrade.

Uncertainty management plans (UMP)
the uncertainty about the reservoir, its performance, our ability to forecast, and
new opportunities to improve recovery that makes surveillance so challenging.
During early phases of field development, there are significant uncertainties that
lead to project risks.This Fig. show how uncertainty-management plan sresult in
the definition of technology and surveillance plans for an asset.
Uncertainty management plans (UMP) drive surveillance and technologyplans
113

Performance expectations
114
Performance expectations must be established for all major components of
an asset. This includes wells, reservoirs, fields, equipment, and facility
installations. Defining performance goals and expectations for the assets
provides a valuable basis for future comparison and analysis. Minimum
expectations for asset management include compilation and active
management of the following data streams:
1. Geological maps for the fields including structure maps, isopach maps,
and well-record maps.
2. Mechanical well sketch for each of the wells including tubing and casing
detail as well as wellhead data and other tubing equipment (packers,
liners, nipples, plug back total depth, subsurface safety valves, gas-lift
valve depths, pump depths, etc.).
3. A petrophysical summary for each well that includes formation tops, pay
intervals, net feet of pay, and sand-identification information.

Performance expectations
4. An evaluated open-hole log over the entire logged interval.
5. Raw and allocated production data and allocation factors.
6. Rock property data, core data and core-study data, and rock failure data.
7.Fluid properties and pressure-volume-temperature analyses for the wells
and reservoirs.
8. Pressure data—static and buildup from all surveys taken in the field.
9. Authority for expenditure (containing detailed justifications) for each well.
10. Well summary sheet with well histories.
11.Copy of field studies, petrophysical studies, reservoir and geological
studies.
12. Reserve report data.
115
13. Facility, plant, process flow diagram (PFD), flowline data and drawings.

data types, roles, and primary responsibilities
shows an example of a table that may be used to assign data ownership and
responsibility for different sources of information. Such tables are valuable in
the dynamic personnel situation in most companies.
116

parameter for Static and Dynamic Reservoir Information
simple matrix chart that allows one to identify which measurements provide
information for a given parameter for Static Reservoir Information and Dynamic
Reservoir Information
117

This table shows how the
state of knowledge for a
given parameter will
change as a result of using
a particular measurement
technique . This tells us
which method will reduce
the uncertainty in a given
parameter the most
118

This table is constructed with
categorical variables (low,
medium, high). However,
numerical values can
be assigned and then
vertically summed by
columns to establish the
highest value in terms of
uncertainty resolution by a specific tool. Although the table looks relatively
innocuous, a number of considerations are required to populate the low, mid,
high nature of a particular measurement . The consideration should include
• Resolution
•Accuracy
•Repeatability
•Interpretability
•Environment variables that impact tool fidelity 119

Objectives based tools selection for measurements
1
2
3
4
120

5
6
7
121

8
9
10
11
122

12
13
14
15
123

16
17
18
19
124

20
21
22
125

Problem based Diagnostic and tools selection
1
2
3
126

4
5
127

6
128

7
129

8
9
10
130

11
12
131

Problem based job planning tree
Start
End
132

(9) Tracer Techniques used for Reservoir surveillance.
134
The technologies have existed for over 50 years.
Tracers provide a powerful surveillance technique for understanding reservoir
connectivity and determining remaining oil saturation. Success of secondary and
tertiary oil recovery projects targeting remaining oil in mature or partially
depleted reservoirs strongly depends on appropriate description of reservoir
heterogeneity and remaining oil distribution. Tracers have been used in
groundwater hydrology and chemical industry for a very long time. Applications
in the oil industry have been mixed.
Two types of tracer tests are generally conducted:
1. Single-well tracer tests
2. Inter-well tracer tests

1-Single-well tracer tests
Use of single-well tracer tests is widespread. Tracers can be used for estimation
of oil saturation in the vicinity of the wells, determining injection profiles of fluids,
tagged tracer for cement and proppants can be run in a well to determine the
effectiveness of fracture proppant placement or cement quality behind pipe. With
increased use of single-trip, multistage fracturing operations both in
unconventional reservoirs and thick deep water reservoirs, tagged tracers are
being used more often for understanding the quality of completion, proppant
placement, and cement isolation. A more recent development is the use of tracer
cartridges that can be placed in between flowing intervals in production wells.
The tracers are soluble only in water phase and can help determine which
intervals are producing water without the introduction of wireline tools to run
PLTs.
135

2-Inter-well tracer tests
Inter-well tracer tests, if designed and conducted well, can be a powerful tool for
describing a reservoir, investigating unexpected anomalies in flow, verifying
suspected flow barriers, and determining reservoir heterogeneity including
layering. Tracers are also used for determining connectivity between wells,
determining remaining oil saturation and estimating performance of a water-
flood, solvent injection, or steam injection
Common Use of tracers in reservoir managements
1. Determine remaining/residual oil saturation
2. Define well-to-well connectivities
3. Determine the presence of flow barriers
4. Characterize reservoir heterogeneity and layering
5. Compute swept pore volume
6. Assess cement integrity in wellbores
7. Evaluate completion quality and proppant placement
8. Calculate phase dispersivities
136

Tracer Characteristics
A perfect tracer for subsurface reservoir application should have the following
characteristics:
1. Soluble and move at the same speed as the tracer carrier
2. Stable except for radioactive tracer that decay according to their half lives
3. Not absorbed significantly or broken down by chemicals in target formation
4. Should be at negligible or low concentrations in the reservoir (background)
5. Detectable and measurable at low concentrations
6. Cost efficient
7. Safe to inject, produce, and handle
8. Repeatable and standardized analytical equipment for measurement
137

For radioactive tracers, operational safety is the most critical component of
running a tracer program and appropriate attention needs to be paid. From an
operational perspective, overall cost and detectability are important. The
success of a tracer test and its quantitative use is determined by maintaining
material balance in the reservoir. To achieve this, measures should be taken
during tracer selection to make appropriate trade-offs in terms of chemical types,
their dynamic characteristics, and interactions with rocks and fluids.
Tracer Types
138

Commonly Used Tracers in the oilfields
139

Design Considerations.
The generic questions that should be answered are:
1. What are the objectives of the test (reservoir characterization, proppant
placement determination, injection distribution in a well, residual oil saturation
determination, barrier confirmation, sweep efficiency characterization,
breakthrough characteristics, etc.)?
2. Is it a single or a mult-iwell tracer test?
3. What is the impacted reservoir volume (pattern-size, single-well
drainage/injection volume)?
4. What are the feasible tracer types and volumes based on objectives?
5. What are the detectability limits of the selected tracer?
6. What is the maximum permissible tracer concentration?
7. Is the test being designed to answer qualitative connectivity questions or is
quantitative evaluation needed?
8. What is the volume of tracer injection?
140

Design Considerations.
9 What are the analytical techniques used to estimate tracer eluent concentration?
10 What would be the sampling frequency and resulting cost?
11Is in-line sampling and analysis practical? What is the trade-off between in-line
sampling installation cost vs. lab measurement?
12Do lab tests need to be conducted to confirm compatibility with reservoir rock,
fluids, and water?
13Do we understand the adsorption behavior of the tracer in question and the link
to design concentration for detectability?
14 What are the measurement methods and stability of partitioning tracers?
15 Is the partition coefficient constant or do we know the partition coefficient
function for
the tracer?
16What would be the soak and backflow time for single-well partitioning tracer
tests?
17 What are the field equipment requirements for mixing, injection, and sampling
procedures as well as field procedures for handling?
141

Reservoir Management
144
Definition of Reservoir Management:
Reservoir Management relies on the use of human, technological and financial
resources to capitalize on profits from a reservoir by optimizing the hydrocarbon
recovery while minimizing both the capital investments and the operating costs.
Main objectives of the reservoir management :
1. Decreasing of the risk
2. Increasing of the oil and gas production
3. Increasing of the oil and gas reserves
4. Minimization of the capital expenditures
5. Minimization of the operating costs
6. Maximizing of the final hydrocarbon recovery

146
The reservoir management process must be designed and implemented to
individual fields on the basis of:
1. Logistics and size of the field/reservoirs
2. Geological complexity of the field/reservoirs
3. Reservoir rock and fluid properties
4. Depletion state
5. Regulatory controls
The modelling process is based on the following main steps:
1-reconstruction of a reservoir geological model
(geological characterization and fluid properties definition)
2-selection of a reservoir mathematical model
(up-scaling and initialization)
3 calibration of the reservoir geological model
(past history matching)
4 prediction of the reservoir future performance
( production forecasts)

Reservoir Management Process
147

Developments plan work-flow
148

Data Acquisition and Characterization
1-Data acquisition :
Data acquisition, involving the gathering of raw data from various sources, i.e.
1. Seismic surveys
2. Well logs
3. Conventional and special core analyses
4. Fluid analyses
5. Static and flowing pressure measurements
6. Pressure-transient tests
7. Periodic well production tests
8. Records of the monthly produced volumes of fluids (oil, gas, and water)
9. Records of the monthly injected volumes of IOR/EOR fluids (water, gas,
CO2, steam, chemicals,…).
149

150
2-Data processing:
Data processing based upon:
1. Seismic time maps
2. Seismic conversion of time-to-depth maps
3. Seismic attribute maps
4. Log analyses
5. Structural maps
6. Cross sections
7. Geologic models
8. Reservoir fluids modeling
9. Simulation models

3-Data integration and Reservoir Characterization
The characterization of a reservoir aims at producing the best detailed
geological reconstruction both of its geometry and of its internal
structure. The overall process is, therefore, the first basic step in the
development of a reservoir model, and it must consider all the available
data, processed and interpreted with the best technologies always
caring to be consistent with the observed historical reservoir
performance.
Geophysical, geological, and engineering characterization provides
also information on the initial distribution of the fluids, as well as on the
hydraulic connectivity between different zones of the reservoir rocks.
151

The following activities are
normally performed for the
acquisition of the data required by
the reservoir characterization.
1. Seismic
2. Well Logging
3. Core Analysis
4. Fluid Properties
5. Well Testing
152

1-Seismic
Seismic allows reconstructing the
reservoir geological setting through
different level observations:
1. On large scale: reservoir geometry,
identification of main structural
features (e.g. faults), , etc
2. On small scale: detailed structural
and stratigraphycal features, fluid
contacts, etc.
Seismic response of a reservoir
depends on petro-acoustic properties of
the volume of rock investigated; such
properties can be obtained by the
interpretation of specific field data.
153

Generally can estimate rock properties from core Analysis
Routine Core Analysis Special CoreAnalysis
155
3- Core analysis

 Reservoir Fluid Properties can Estimated from PVT sample
• Oil Compressibility
• Saturation Pressure
• Live Oil Viscosity
• Live Oil Density
• Oil Formation Volume Factor
• Gas-Oil Ratio
• Liberated Gas Formation Volume factor
• Incremental Liberated Gas-Gravity
• Cumulative liberated Gas-Gravity
156
4- Fluid Properties

 Type of well test :
1. Static pressure test
2. Drawdown test
3. Build-up test
4. Injection test / fall-off test
5. Interference test and pulse test
6. Gas well test
7. Flow after flow test,
8. Isochronal test,
9. Modified isochronal test
10. DST
157
5- well test

Workflows for integrated reservoir modeling
Integrated Reservoir Modeling
158

reservoir modeling
Integrated Reservoir Modeling
Static Model
1. Structural modeling
2. Stratigraphic modeling
3. Lithological modeling
4. Petrophysical modeling
159
Dynamic model
1. Up-scaling
2. simulation
3. History matching

Static Model
1. Structural modeling
Reconstruction of the geometrical and
structural properties of the reservoir, by
defining a map of its structural top and
the set of faults running through it. This
stage of the work is carried out by
integrating interpretations of the
geophysical surveys with the available
well data.
(I) Static Model
160

Static Model
2. Stratigraphic modeling
Definition of a stratigraphic scheme
using well data, which form the basis
for well to well correlations. The data
consist of electrical, acoustic and
radioactive wireline logs, and of results
of core analysis, integrated where
possible with information from
specialist studies and production data.
(I) Static Model
161

Static Model
3. Lithological modeling
Definition of the lithological types
(basic facies ), which are characterized
on the basis of lithology,
sedimentology, and petrophysics. This
classification into facies is a
convenient way of representing the
geological characteristics of a
reservoir, especially for the purposes of
subsequent three-dimensional
modeling.
(I) Static Model
162

Static Model
4. Petrophysical modeling
A quantitative interpretation of well logs
to determine some of the main
petrophysical characteristics of the
reservoir rock, (porosity, water
saturation, and permeability). Core
data represent the essential basis for
the calibration of interpretative
processes.
(I) Static Model
163

Build a Petrel project of the field assembling all the data available :
1-Seismic Interpretation & Inversion
– Horizons and Fault Interpretation
2-Core Description:
– Conceptual depositional model
3- Petrophysical Interpretation
– Data review and QC
– Cementation factor (m), and Saturation exponent (n)
– Permeability-Porosity Transform
– Rock Typing (MICP, RCA, Log Data, Lithofacies)
– Free Water Level and Saturation Height Function
164
(I) Static Model

Continue Build a Petrel project of the field assembling all the data
available :
4-Structural modeling
– Fault model, Pillar gridding, Horizon model, Zonation and Layering
5 Facies Modeling
–Population of lithofacies and depositional facies in the 3D Grid
6 Petrophysical Property Modeling
–Realistic property model reflecting the reservoir geological and production
characteristics.
– Stochastic porosity and permeability modeling
– Water saturation modeling
7-Volumetrics Estimation
165
(I) Static Model

Uncertainty Analysis Workflow
167

Uncertainty Analysis Workflow
168

(II) Dynamic Model
Fully Integrated Petrel Framework
1-Entire model will be based on Petrel
– PVT, SCAL, VFP,Aquifers, Development
Strategies
2Petrel workflows and macros will be used to
ensure a portable and maintainable history
matched model.
3Grid block-independent multipliers will be used:
Zones, Segments, polygones, …This enables a
smooth transition from one grid size to another in
thehistory matching process
170

1-Upscaling
(II) Dynamic Model
171

1-Upscaling
1-Honoring reservoirs heterogeneity
– Retain as much geological details as possible
2-Two Upscaled models:
– High Resolution: Targeted studies (infill drilling, EOR, …)
– Low Resolution: Multi-scenario production forecasts.
– History Matching will take place on the low resolution model first
– Results will then feed into the HM of the high resolution model
3 Understand the continuity of the reservoir properties both areally and vertically
(facies)
4 Preserve vertical barriers
5HCPV maps per zone and porosity cross-sections were made. The final
proposed layering scheme is selected giving priority to zones with high HCPV
and
high vertical contrast of porosity.
(II) Dynamic Model
172

Up scaling – QC
1. Check Volumetrics (see separate slide)
2. For all wells compare synthetic porosity, permeability and saturation logs
(fine scale and upscaled models).
3. Perform visual checks on the upscaled porosity and permeability by
comparing 2D map views, 2D cross-sections for the upscaled model and
the static model for all relevant zones.
4. Compare histograms and k-phi cross-plots before and after upscaling for
all the relevant horizons and facies
5. Compare dynamic behavior on a sector model between fine scale and
upscaled models
173
(II) Dynamic Model

2-Reservoir simulation
Reservoir simulation is a branch of petroleum engineering developed for
predicting reservoir performance using computer programs that through
sophisticated algorithms numerically solve the equations governing the complex
physical processes occurring during the production of an oil/gas reservoir.
Basically, a reservoir simulation study involves five steps:
1. Setting objectives
2. Selecting the model and approach
3. Gathering, collecting and preparing the input data
4. Planning the computer runs, in terms of history matching and/or performance
prediction
5. Analyzing, interpreting and reporting the results.
174
(II) Dynamic Model

3-History Matching
1. Uncertainty Analysis: Identify the set of reservoirs parameters with high
uncertainty and their corresponding
2. ranges of uncertainty.
3. Run a sensitivity analysis to investigate the impact of different parameters on
the flow performance (rates, water breakthrough, WCT, GOR, pressure).
4. Narrow down the set of uncertainty parameters to be carried on to be used in
the history matching process.
5. Field, Group & Well level.
6. Production data analysis helps on setting the HM criteria.
7. Calibrate model to well test data.
8. Check quality of the HM using the RST/PNL Data.
9. Potential usage of assisted history matching as applicable (Petrel HM &
Optimization or MEPO).
10. History match the Low Resolution model followed my HM of the High
Resolution model.
(II) Dynamic Model
175

 Breaks Down Barriers between Disciplines.
 Bring the Engineering Models Closer to the Operational World.
 Feasibility Validation of Field Development Plans.
 Evaluation of any Possible Production System Bottleneck.
 Optimizing CAPEX and OPEX
(III) Integrated Asset Model – Surface/Subsurface
176

Network Modeling including :
 Well/Network Modeling
 Well Design and Analysis
 Nodal Analysis
 Network Debottlenecking
 Pipeline & Equipment Sizing
 Gas Lift / ESP Optimization
 Flow Assurance
 Erosion & Corrosion Modeling
 Slug flow prediction / Slug
catcher sizing
 Field Network Development
Planning
(V) Network Modeling
177

Reference
178
1. Reservoir Engineering Handbook, (Tarek Ahmed, 5thedition)
2. integrated Reservoir Asset Management. Principles and Best Practices(John R. Fanchi)
3. Basic of reservoir engineering (ReneCosse)
4. Fundamentals of Applied Reservoir Engineering-Appraisal, Economics-and Optimization
(RICHARD WHEATON)
5. Fundamentals of Reservoir Engineering (L.P. Dake)
6. Reservoir Engineering (Heriot-Watt University)
7. Reservoir Surveillance-(Jitendra Kikani)
8. Reservoir Engineering- the fundamental -simulation and management (Abdus Satter & GhulamM.
Iqbal)
9. Basic Petroleum Geology and Log Analysis – (Hallibuton)
10. Basic Rock and Fluid Properties
11. Larry W . Lake -Petroleum engineering handbook - reservoir engineering andpetro-physics
volume V
12. Reservoir Engineering (Kaiser A. Jasim 2019)
13. method OOIP calculation( paper)
14. Reservoir Management (Dr. Jawad R. RustumAl-Assal)
15. static and dynamic model – work-folw (Kassem Ghorayeb) fromSLB

Name: Abbas RadhiAbbas
Position: Chief Engineer / petroleum Engineer
Nationality: Iraq- Missan
Date of Birth: 1978
Gender: Male
Education Background:
Period Education description
1996-2001 University of Bagdad – college of Engineering – petroleum engineering department- (BSc)
Certificates of Appreciation
15 Certificates of Appreciation from difrent international companies such as (Schlumberger- waetherford , CNOOC , COSL ,
BHDC )
Work Experience : in Missan Oil Company ( MOC)
Period Work description
(2004-2006) reservoir engineer
(2006-2010 ) water injection engineer
during (2011) drilling and workover engineer
(2011 to 2020 ) petrophysics manager in Reservoir department
Language:
Mother language:
Arabic
Second
language/level: English/Fluent oral and written in English.
179
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