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Part : 1
Reservoir Engineering
Fundamentals of petroleum Engineering
By
Petroleum Engineer
Abbas Radhi Abbas
Iraq / Missan / 2020
1
2.Introduction to Reservoir Engineering
3.Type of Hydrocarbon Reservoir Traps
4.Basic Rock and Fluid Properties
6.Determined hydrocarbon in place
7.Enhanced Oil Recovery (EOR)
5.Reservoir Classifications
8.Reservoir Surveillance
Contents
1.Reservoir Engineering Functions
9.Tracer Techniques
10. Reservoir management
Contents
Reservoir
Engineering
Fundamentals
2
(1) Reservoir Engineering Functions
3
Reservoir engineers often specialize in two areas:
(1) Reservoir Surveillance
(2) Simulation modeling
Surveillance Engineer
1. monitoring of existing
fields and optimization of
production and injection
rates.
2. Surveillance engineers
typically use production
data , well test , cased
hole logging … etc to
control the production and
injection then diagnose
production problems
3. Use software such as (
Pipsim , OFM , prosper ,
kappa … etc )
Simulation modeling
Engineer :
1. conduct of reservoir
simulation studies to
determine optimal
development plans
for oil and gas
reservoirs.
2. Use software such as
Petrel-RE , Eclipse ,
CMG ….etc
 Detailed understanding of the reservoir, including rock and fluid flow
characteristics, and the mechanisms by which a reservoir is produced;
unconventional reservoirs pose new challenges .
Reservoir engineering functions
 Reservoir Fluid Properties can
Estimated from PVT sample
• Oil Compressibility
• Oil Viscosity
• Oil Density
• Oil Formation Volume Factor
• Gas Formation Volume factor
• Gas-Oil Ratio
• Bubble point pressure
 Rock Properties can estimate
from ( core – log – well test )
1. Porosity
2. Permeability
3. Wettability
4. Saturation
5. Capillary Pressure
Rock and Fluid Properties
 Integration of reservoir engineering data with geophysical, geological,
petrophysical, and production information, among others, to develop a
conceptual model of the reservoir .
 Estimation of oil and gas in place , reserves , Recovery factor
Reservoir engineering functions
Determined hydrocarbon in place
OOIP
Determine Reserves Determine Recovery factor
1. Analogy Method
2. Volumetric method
3. Material Balance
4. Reservoir simulation
1. Decline curve analysis RF = Reserve / OOIP
 Design, placement, and completion of producers and injectors in order to
optimize production
 Plan, design, execution, and monitoring of water flood and enhanced oil
recovery operations
 Implementation of a strategy for incremental oil recovery from matured fields
 Meeting challenges posed by declining well productivity, premature
breakthrough of water and gas, unexpected reservoir heterogeneities,
operational issues, economic aspects, environmental concerns, statutory
regulations, and others
 Development and simulation of computer-based models that predict reservoir
performance
Reservoir engineering functions
 Reservoir surveillance that enhances the knowledge of the reservoir and
charts future courses of action
 Working closely with a multidisciplinary team of engineers and earth
scientists in order to manage the reservoir effectively
Reservoir engineering functions
2-Introduction to Reservoir Engineering
9
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.
2-Introduction to Reservoir Engineering
10
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
2-Introduction to Reservoir Engineering
11
(A) Reserves Estimation
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. :
12
(A) Reserves Estimation
(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.
Reserves :
are those quantities of petroleum which are anticipated to be commercially
recovered from known accumulations from a given date forward.
13
(A) Reserves Estimation
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.
(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.
14
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)
15
Relationships between parameters related with OOIP , RF and Reserve
16
OOIP
RF
Reserves = OOIP X RF
OOIP : Original Oil in place
RF : Recovery factor
(A) Reserves Estimation
Variations of reserves During filed life
17
(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 out etc.)
18
(C) Production Operations Optimization
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
19
(C) Production Operations Optimization
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
20
(C) Production Operations Optimization
Phases of Production
21
(C) Production Operations Optimization
Primary , secondary & Tertiary recovery
22
(3) Type of Hydrocarbon Reservoir Traps
23
(3) Type of Hydrocarbon Reservoir Traps
24
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 along the
fracture moving or slipping past
each other into an offset position.
A fault trap is formed when the
faulted formations are tilted toward
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.
25
Structural Traps
Fold (Anticlinal) and Dome Trap
The rock layers
in an anticlinal trap were
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
26
Stratigraphic Traps
Stratigraphic traps
are formed as a
result of differences or variations
between or within stratified rock
layers, creating a change or loss of
permeability from one area to
another. These traps do not occur
as
a result of movement of the strata.
27
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 uplifted and
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 on the
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.
28
Unconventional Traps
29
(4) Basic Rock and Fluid Properties
30
(4) Basic Rock and Fluid Properties
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.
31
Basic Rock Properties
Rock Properties
1. Porosity
2. Permeability
3. Wettability
4. Saturation
5. Capillary Pressure
32
Generally can estimate rock properties from core Analysis , logs , see the
SCAL and RCAL
Routine Core Analysis Special Core Analysis
Basic Rock Properties
33
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.
Basic Rock Properties
34
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.
Basic Rock Properties
35
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.
Basic Rock Properties
36
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).
Basic Rock Properties
37
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.
Basic Rock Properties
38
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.
Basic Rock Properties
39
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
Basic Rock Properties
40
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
Measurement of Permeability :
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.
Basic Rock Properties
41
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.
Measurement of Permeability :
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.
Basic Rock Properties
42
2-Permeability From Well-Test
Analysis
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.
Measurement of Permeability :
Basic Rock Properties
43
3- from Darcy’s Law in Field Units
In field units the Darcy equation will be
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)
Measurement of Permeability :
Basic Rock Properties
44
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
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
Basic Rock Properties
45
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.
Wettability
Basic Rock Properties
Figure (A)
Table ( --)
46
Special Core Analysis
Several methods are available to
measure a reservoir’s wetting
preference.
 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
that capillary pressure and
relative permeability
measurements give an idea of
rock wettability
Measuring Wettability
Basic Rock Properties
47
Saturation is the proportion of
interconnected pore space
occupied by a given phase. For
a gas –oil-water system
Where:
Sw : water saturation
So : oil saturation
Sg : gas saturation
4-Saturation
Routine Core Analysis
Basic Rock Properties
48
Capillary pressure is the pressure difference across the curved interface
formed by two immiscible fluids in a small capillary tube. The pressure
difference is
Where :
Pc : capillary pressure (psi)
Pnw : pressure in non-wetting phase (psi)
Pw : pressure in wetting phase (psi)
5-Capillary Pressure
Basic Rock Properties
49
Oil is the non-wetting phase in a water-wet oil–water reservoir. Capillary
pressure
for an oil–water system is
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
Basic Rock Properties
50
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
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
Basic Rock Properties
51
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
Capillary Pressure measurement
Basic Rock Properties
52
 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
• Bubble point pressure
• Liberated Gas Formation Volume factor
• Incremental Liberated Gas-Gravity
• Cumulative liberated Gas-Gravity
Basic Fluid Properties
53
 • 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
Basic Fluid Properties
54
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
Basic Fluid Properties
55
Separator sampling
Basic Fluid Properties
56
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 volume at
surface conditions
Rs : solution gas-oil ratio ratio (SCF=stb or scm=scm)
= the ratio of the standard volume of solution gas dissolved in the
oil at a given pressure to the oil volume at surface conditions
Bg : gas formation volume factor (rb=SCF or m3/scm)
= the ratio of gas volume at a reservoir conditions to the gas
volume at surface conditions
Bw : water formation volume factor (rb=stb or m3/scm)
= the ratio of water volume at reservoir conditions to the water
volume at surface conditions
Basic Fluid Properties
57
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
Basic Fluid Properties
58
Basic Fluid Properties
59
Basic Fluid Properties
Example of Black oil properties
60
(5) Reservoir Classifications
61
(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
1. Solution gas drive
2. Gas Cup drive
3. Water drive
4. Gravity drainage drive
5. Combination drive
62
•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
63
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%
Black Oil Reservoirs:
64
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:
65
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:
66
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:
67
Dry Gas Reservoirs:
•GOR > 100,000 SCF/STB
•No liquid produced at surface
Dry Gas Reservoirs:
68
Range of Reservoir fluid properties
69
 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
2-According to Rock type
 Reservoir must be ( porous , permeable & Trapped )
70
1. Clastic Reservoir
2. Carbonate Reservoir
According to Rock type
2-According to Rock type
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 )
71
2-According to Rock type
72
According to phase behavior
1. Single phase gas
2. Gas condensate
3. Under saturated oil
4. saturated oil
3-According to phase behavior
73
Pressure-temperature phase diagram
for
multicomponent hydrocarbon reservoir
fluid mixture. For
isothermal production in the reservoir:
position A indicates
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
Pressure-temperature phase diagram
74
4-According to drive mechanism
According to drive mechanism
1. Solution gas drive
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.
75
1- Solution Gas Drive
Solution Gas Drive:
Gas breaks out of solution and
expanding gas maintains pressure
in reservoir somewhat over time
Trend
Characteristics
Declines rapidly and continuously
Reservoir Pressure
then drops
First low then rises to a maximum and
Gas/Oil Ratio
continues to decline First high, then decreases rapidly and
Production Rate
None
Water Production
Requires artificial lift at early stages
Well Behavior
5-30% of original oil-in-place
Expected Oil Recovery
76
Gas Cap Drive:
Gas in gas cap is expanding as pressure
depletes, maintaining pressure somewhat
overtime (later stages of solution gas drive)
2.Gas cap Drive.
Trend
Characteristics
Falls slowly and continuously
Reservoir Pressure
Rises continuously
Gas/Oil Ratio
First high, then declines gradually
Production Rate
Absent or negligible
Water Production
Long flowing life depending on size of gas cap
Well Behavior Cap
20 to 40% of original oil-in-place
Expected Oil
Recovery
77
Water Drive
Large aquifer volume expands
providing pressure for relatively
small oil volume. Can be
supplemented with water injection.
Over time:
3.Water Drive.
Trend
Characteristics
Remains high
Reservoir Pressure
Remains steady
Gas/Oil Ratio
tarts early and increases to appreciable amounts
Water Production
Flow until water production gets excessive
Well Behavior Cap
up to 60% original oil-in-place.
Expected Oil
Recovery
78
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.

GOR very low if at all.
4.Gravity Drainage.
79
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.
5.Combination or Mixed Drive
5.Combination or Mixed Drive
80
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)
81
(6) Determined hydrocarbon in place
82
(6) Determined hydrocarbon in place
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
83
(6) Determined hydrocarbon in place
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. 84
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.
(6) Determined hydrocarbon in place
85
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.
(6) Determined hydrocarbon in place
86
(6) Determined hydrocarbon in place
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.
87
(6) Determined hydrocarbon in place
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
.
88
(7) Enhanced Oil Recovery (EOR)
89
(7) Enhanced Oil Recovery (EOR)
EOR / IOR definition
90
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 .
What is the (EOR) ?
91
 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.
Objective of EOR
92
 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
93
 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
94
Water-flooding
Different well pattern :
95
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
Chemical oil recovery methods
96
Surfactant / Polymer Flooding
 Description
Surfactant / polymer flooding consists of injecting slug that contains water,
surfactant, electrolyte (salt), usually a co-solvent (alcohol), followed by
polymer-thickened water.
Mechanisms that Improve Recovery Efficiency
• 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.
97
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
98
Polymer Flooding
 Description
Polymer augmented waterflooding consists of adding water soluble polymers
to the water before it is injected into the reservoir.
Mechanisms that Improve Recovery Efficiency
• 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.
99
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
100
Miscible Gas Flooding ( CO2 injection )
 Description
CO2 flooding consists of injecting large quantities of CO2 (15% or more
hydrocarbon pore volumes) in the reservoir to form a miscible flood.
Mechanisms that Improve Recovery Efficiency
• 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
101
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 )
102
Miscible Gas Flooding (Hydrocarbon Injection)
 Description
Hydrocarbon gas flooding consists of injecting light hydrocarbons through the
reservoir to form a miscible flood.
Mechanisms that Improve Recovery Efficiency
• 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.
103
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)
104
Nitrogen / Flue Gas Flooding
 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.
Mechanisms that Improve Recovery Efficiency
• 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.
105
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
106
Thermal (Steam-flooding)
 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).
Mechanisms that Improve Recovery Efficiency
• 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.
107
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.
108
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.
109
EOR process maturity curve-with time
110
(8) Reservoir Surveillance
111
(8) Reservoir Surveillance
 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
112
(8) Reservoir Surveillance
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
113
Engineering functions and tasks leading to decisions
114
Relating measurements to interpretation and uncertainty reduction
115
Example 1 : plan to identify thief zones and remediate:
 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.
116
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 technology plans
117
Performance expectations
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.
118
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.
13. Facility, plant, process flow diagram (PFD), flowline data and drawings.
119
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.
120
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
121
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
122
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 123
Objectives based tools selection for measurements
1
2
3
4
124
Objectives based tools selection for measurements
5
6
7
125
Objectives based tools selection for measurements
8
9
10
11
126
Objectives based tools selection for measurements
12
13
14
15
127
Objectives based tools selection for measurements
16
17
18
19
128
Objectives based tools selection for measurements
20
21
22
129
Problem based Diagnostic and tools selection
1
2
3
130
Problem based Diagnostic and tools selection
4
5
131
Problem based Diagnostic and tools selection
6
132
Problem based Diagnostic and tools selection
7
133
Problem based Diagnostic and tools selection
8
9
10
134
Problem based Diagnostic and tools selection
11
12
135
Problem based job planning tree
Start
End
136
(9) Tracer Techniques
137
(9) Tracer Techniques used for Reservoir surveillance.
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
138
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.
(9) Tracer Techniques used for Reservoir surveillance.
139
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
(9) Tracer Techniques used for Reservoir surveillance.
140
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
(9) Tracer Techniques used for Reservoir surveillance.
141
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
(9) Tracer Techniques used for Reservoir surveillance.
142
Commonly Used Tracers in the oilfields
(9) Tracer Techniques used for Reservoir surveillance.
143
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?
(9) Tracer Techniques used for Reservoir surveillance.
144
Design Considerations.
9-What are the analytical techniques used to estimate tracer eluent concentration?
10-What would be the sampling frequency and resulting cost?
11-Is in-line sampling and analysis practical? What is the trade-off between in-line
sampling installation cost vs. lab measurement?
12-Do lab tests need to be conducted to confirm compatibility with reservoir rock,
fluids, and water?
13-Do 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?
16-What 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?
(9) Tracer Techniques used for Reservoir surveillance.
145
(10) Reservoir Management
146
Reservoir Life Process
147
Reservoir Management
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
148
Reservoir Management Team
149
Reservoir Management
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)
150
Reservoir Management
Reservoir Management Process
151
Developments plan work-flow
152
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,…).
153
Data Acquisition and Characterization
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
154
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.
Data Acquisition and Characterization
155
Data Acquisition and Characterization
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
156
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.
157
158
Generally can estimate rock properties from core Analysis
Routine Core Analysis Special Core Analysis
3- Core analysis
159
 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
4- Fluid Properties
160
 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
5- well test
161
Workflows for integrated reservoir modeling
Integrated Reservoir Modeling
162
reservoir modeling
Integrated Reservoir Modeling
Static Model Dynamic model
1. Structural modeling
2. Stratigraphic modeling
3. Lithological modeling
4. Petrophysical modeling
1. Up-scaling
2. simulation
3. History matching
163
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
164
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
165
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
166
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
167
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
(I) Static Model
168
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
(I) Static Model
169
Static Model workflow
170
Uncertainty Analysis Workflow
171
Uncertainty Analysis Workflow
172
Fracture Model workflow
173
(II) Dynamic Model
Fully Integrated Petrel Framework
1-Entire model will be based on Petrel
– PVT, SCAL, VFP, Aquifers, Development
Strategies
2-Petrel workflows and macros will be used to
ensure a portable and maintainable history
matched model.
3-Grid block-independent multipliers will be used:
Zones, Segments, polygones, …This enables a
smooth transition from one grid size to another in
thehistory matching process
174
1-Upscaling
(II) Dynamic Model
175
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
5- HCPV 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
176
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
(II) Dynamic Model
177
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.
(II) Dynamic Model
178
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
179
 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
180
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
181
Reference
1. Reservoir Engineering Handbook, (Tarek Ahmed, 5th edition)
2. integrated Reservoir Asset Management. Principles and Best Practices (John R. Fanchi)
3. Basic of reservoir engineering (Rene Cosse)
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 & Ghulam M.
Iqbal)
9. Basic Petroleum Geology and Log Analysis – (Hallibuton)
10. Basic Rock and Fluid Properties
11. Larry W . Lake -Petroleum engineering handbook - reservoir engineering and petro-physics
volume V
12. Reservoir Engineering (Kaiser A. Jasim 2019)- presentation
13. method OOIP calculation( paper )
14. Reservoir Management (Dr. Jawad R. Rustum Al-Assal)
15. static and dynamic model – work-folw (Kassem Ghorayeb) from SLB
182
183
Name: Abbas Radhi Abbas
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.
About Authorized
Thank You!
184

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Fundamentals Of Reservoir.pdf

  • 1. Part : 1 Reservoir Engineering Fundamentals of petroleum Engineering By Petroleum Engineer Abbas Radhi Abbas Iraq / Missan / 2020 1
  • 2. 2.Introduction to Reservoir Engineering 3.Type of Hydrocarbon Reservoir Traps 4.Basic Rock and Fluid Properties 6.Determined hydrocarbon in place 7.Enhanced Oil Recovery (EOR) 5.Reservoir Classifications 8.Reservoir Surveillance Contents 1.Reservoir Engineering Functions 9.Tracer Techniques 10. Reservoir management Contents Reservoir Engineering Fundamentals 2
  • 4. Reservoir engineers often specialize in two areas: (1) Reservoir Surveillance (2) Simulation modeling Surveillance Engineer 1. monitoring of existing fields and optimization of production and injection rates. 2. Surveillance engineers typically use production data , well test , cased hole logging … etc to control the production and injection then diagnose production problems 3. Use software such as ( Pipsim , OFM , prosper , kappa … etc ) Simulation modeling Engineer : 1. conduct of reservoir simulation studies to determine optimal development plans for oil and gas reservoirs. 2. Use software such as Petrel-RE , Eclipse , CMG ….etc
  • 5.  Detailed understanding of the reservoir, including rock and fluid flow characteristics, and the mechanisms by which a reservoir is produced; unconventional reservoirs pose new challenges . Reservoir engineering functions  Reservoir Fluid Properties can Estimated from PVT sample • Oil Compressibility • Oil Viscosity • Oil Density • Oil Formation Volume Factor • Gas Formation Volume factor • Gas-Oil Ratio • Bubble point pressure  Rock Properties can estimate from ( core – log – well test ) 1. Porosity 2. Permeability 3. Wettability 4. Saturation 5. Capillary Pressure Rock and Fluid Properties
  • 6.  Integration of reservoir engineering data with geophysical, geological, petrophysical, and production information, among others, to develop a conceptual model of the reservoir .  Estimation of oil and gas in place , reserves , Recovery factor Reservoir engineering functions Determined hydrocarbon in place OOIP Determine Reserves Determine Recovery factor 1. Analogy Method 2. Volumetric method 3. Material Balance 4. Reservoir simulation 1. Decline curve analysis RF = Reserve / OOIP
  • 7.  Design, placement, and completion of producers and injectors in order to optimize production  Plan, design, execution, and monitoring of water flood and enhanced oil recovery operations  Implementation of a strategy for incremental oil recovery from matured fields  Meeting challenges posed by declining well productivity, premature breakthrough of water and gas, unexpected reservoir heterogeneities, operational issues, economic aspects, environmental concerns, statutory regulations, and others  Development and simulation of computer-based models that predict reservoir performance Reservoir engineering functions
  • 8.  Reservoir surveillance that enhances the knowledge of the reservoir and charts future courses of action  Working closely with a multidisciplinary team of engineers and earth scientists in order to manage the reservoir effectively Reservoir engineering functions
  • 10. 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. 2-Introduction to Reservoir Engineering 10
  • 11. 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 2-Introduction to Reservoir Engineering 11
  • 12. (A) Reserves Estimation 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. : 12
  • 13. (A) Reserves Estimation (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. Reserves : are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. 13
  • 14. (A) Reserves Estimation 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. (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. 14
  • 15. 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) 15
  • 16. Relationships between parameters related with OOIP , RF and Reserve 16 OOIP RF Reserves = OOIP X RF OOIP : Original Oil in place RF : Recovery factor
  • 17. (A) Reserves Estimation Variations of reserves During filed life 17
  • 18. (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 out etc.) 18
  • 19. (C) Production Operations Optimization 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 19
  • 20. (C) Production Operations Optimization 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 20
  • 21. (C) Production Operations Optimization Phases of Production 21
  • 22. (C) Production Operations Optimization Primary , secondary & Tertiary recovery 22
  • 23. (3) Type of Hydrocarbon Reservoir Traps 23
  • 24. (3) Type of Hydrocarbon Reservoir Traps 24
  • 25. 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 along the fracture moving or slipping past each other into an offset position. A fault trap is formed when the faulted formations are tilted toward 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. 25
  • 26. Structural Traps Fold (Anticlinal) and Dome Trap The rock layers in an anticlinal trap were 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 26
  • 27. Stratigraphic Traps Stratigraphic traps are formed as a result of differences or variations between or within stratified rock layers, creating a change or loss of permeability from one area to another. These traps do not occur as a result of movement of the strata. 27
  • 28. 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 uplifted and 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 on the 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. 28
  • 30. (4) Basic Rock and Fluid Properties 30
  • 31. (4) Basic Rock and Fluid Properties 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. 31
  • 32. Basic Rock Properties Rock Properties 1. Porosity 2. Permeability 3. Wettability 4. Saturation 5. Capillary Pressure 32
  • 33. Generally can estimate rock properties from core Analysis , logs , see the SCAL and RCAL Routine Core Analysis Special Core Analysis Basic Rock Properties 33
  • 34. 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. Basic Rock Properties 34
  • 35. 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. Basic Rock Properties 35
  • 36. 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. Basic Rock Properties 36
  • 37. 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). Basic Rock Properties 37
  • 38. 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. Basic Rock Properties 38
  • 39. 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. Basic Rock Properties 39
  • 40. 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 Basic Rock Properties 40
  • 41. 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 Measurement of Permeability : 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. Basic Rock Properties 41
  • 42. 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. Measurement of Permeability : 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. Basic Rock Properties 42
  • 43. 2-Permeability From Well-Test Analysis 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. Measurement of Permeability : Basic Rock Properties 43
  • 44. 3- from Darcy’s Law in Field Units In field units the Darcy equation will be 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) Measurement of Permeability : Basic Rock Properties 44
  • 45. 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 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 Basic Rock Properties 45
  • 46. 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. Wettability Basic Rock Properties Figure (A) Table ( --) 46
  • 47. Special Core Analysis Several methods are available to measure a reservoir’s wetting preference.  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 that capillary pressure and relative permeability measurements give an idea of rock wettability Measuring Wettability Basic Rock Properties 47
  • 48. Saturation is the proportion of interconnected pore space occupied by a given phase. For a gas –oil-water system Where: Sw : water saturation So : oil saturation Sg : gas saturation 4-Saturation Routine Core Analysis Basic Rock Properties 48
  • 49. Capillary pressure is the pressure difference across the curved interface formed by two immiscible fluids in a small capillary tube. The pressure difference is Where : Pc : capillary pressure (psi) Pnw : pressure in non-wetting phase (psi) Pw : pressure in wetting phase (psi) 5-Capillary Pressure Basic Rock Properties 49
  • 50. Oil is the non-wetting phase in a water-wet oil–water reservoir. Capillary pressure for an oil–water system is 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 Basic Rock Properties 50
  • 51. 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 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 Basic Rock Properties 51
  • 52. 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 Capillary Pressure measurement Basic Rock Properties 52
  • 53.  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 • Bubble point pressure • Liberated Gas Formation Volume factor • Incremental Liberated Gas-Gravity • Cumulative liberated Gas-Gravity Basic Fluid Properties 53
  • 54.  • 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 Basic Fluid Properties 54
  • 55. 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 Basic Fluid Properties 55
  • 57. 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 volume at surface conditions Rs : solution gas-oil ratio ratio (SCF=stb or scm=scm) = the ratio of the standard volume of solution gas dissolved in the oil at a given pressure to the oil volume at surface conditions Bg : gas formation volume factor (rb=SCF or m3/scm) = the ratio of gas volume at a reservoir conditions to the gas volume at surface conditions Bw : water formation volume factor (rb=stb or m3/scm) = the ratio of water volume at reservoir conditions to the water volume at surface conditions Basic Fluid Properties 57
  • 58. 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 Basic Fluid Properties 58
  • 60. Basic Fluid Properties Example of Black oil properties 60
  • 62. (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 1. Solution gas drive 2. Gas Cup drive 3. Water drive 4. Gravity drainage drive 5. Combination drive 62
  • 63. •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 63
  • 64. 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% Black Oil Reservoirs: 64
  • 65. 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: 65
  • 66. 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: 66
  • 67. 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: 67
  • 68. Dry Gas Reservoirs: •GOR > 100,000 SCF/STB •No liquid produced at surface Dry Gas Reservoirs: 68
  • 69. Range of Reservoir fluid properties 69
  • 70.  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 2-According to Rock type  Reservoir must be ( porous , permeable & Trapped ) 70
  • 71. 1. Clastic Reservoir 2. Carbonate Reservoir According to Rock type 2-According to Rock type 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 ) 71
  • 73. According to phase behavior 1. Single phase gas 2. Gas condensate 3. Under saturated oil 4. saturated oil 3-According to phase behavior 73
  • 74. Pressure-temperature phase diagram for multicomponent hydrocarbon reservoir fluid mixture. For isothermal production in the reservoir: position A indicates 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 Pressure-temperature phase diagram 74
  • 75. 4-According to drive mechanism According to drive mechanism 1. Solution gas drive 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. 75
  • 76. 1- Solution Gas Drive Solution Gas Drive: Gas breaks out of solution and expanding gas maintains pressure in reservoir somewhat over time Trend Characteristics Declines rapidly and continuously Reservoir Pressure then drops First low then rises to a maximum and Gas/Oil Ratio continues to decline First high, then decreases rapidly and Production Rate None Water Production Requires artificial lift at early stages Well Behavior 5-30% of original oil-in-place Expected Oil Recovery 76
  • 77. Gas Cap Drive: Gas in gas cap is expanding as pressure depletes, maintaining pressure somewhat overtime (later stages of solution gas drive) 2.Gas cap Drive. Trend Characteristics Falls slowly and continuously Reservoir Pressure Rises continuously Gas/Oil Ratio First high, then declines gradually Production Rate Absent or negligible Water Production Long flowing life depending on size of gas cap Well Behavior Cap 20 to 40% of original oil-in-place Expected Oil Recovery 77
  • 78. Water Drive Large aquifer volume expands providing pressure for relatively small oil volume. Can be supplemented with water injection. Over time: 3.Water Drive. Trend Characteristics Remains high Reservoir Pressure Remains steady Gas/Oil Ratio tarts early and increases to appreciable amounts Water Production Flow until water production gets excessive Well Behavior Cap up to 60% original oil-in-place. Expected Oil Recovery 78
  • 79. 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.  GOR very low if at all. 4.Gravity Drainage. 79
  • 80. 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. 5.Combination or Mixed Drive 5.Combination or Mixed Drive 80
  • 81. 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) 81
  • 83. (6) Determined hydrocarbon in place 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 83
  • 84. (6) Determined hydrocarbon in place 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. 84
  • 85. 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. (6) Determined hydrocarbon in place 85
  • 86. 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. (6) Determined hydrocarbon in place 86
  • 87. (6) Determined hydrocarbon in place 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. 87
  • 88. (6) Determined hydrocarbon in place 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 . 88
  • 89. (7) Enhanced Oil Recovery (EOR) 89
  • 90. (7) Enhanced Oil Recovery (EOR) EOR / IOR definition 90
  • 91. 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 . What is the (EOR) ? 91
  • 92.  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. Objective of EOR 92
  • 93.  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 93
  • 94.  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 94
  • 96. 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 Chemical oil recovery methods 96
  • 97. Surfactant / Polymer Flooding  Description Surfactant / polymer flooding consists of injecting slug that contains water, surfactant, electrolyte (salt), usually a co-solvent (alcohol), followed by polymer-thickened water. Mechanisms that Improve Recovery Efficiency • 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. 97
  • 98. 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 98
  • 99. Polymer Flooding  Description Polymer augmented waterflooding consists of adding water soluble polymers to the water before it is injected into the reservoir. Mechanisms that Improve Recovery Efficiency • 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. 99
  • 100. 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 100
  • 101. Miscible Gas Flooding ( CO2 injection )  Description CO2 flooding consists of injecting large quantities of CO2 (15% or more hydrocarbon pore volumes) in the reservoir to form a miscible flood. Mechanisms that Improve Recovery Efficiency • 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 101
  • 102. 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 ) 102
  • 103. Miscible Gas Flooding (Hydrocarbon Injection)  Description Hydrocarbon gas flooding consists of injecting light hydrocarbons through the reservoir to form a miscible flood. Mechanisms that Improve Recovery Efficiency • 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. 103
  • 104. 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) 104
  • 105. Nitrogen / Flue Gas Flooding  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. Mechanisms that Improve Recovery Efficiency • 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. 105
  • 106. 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 106
  • 107. Thermal (Steam-flooding)  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). Mechanisms that Improve Recovery Efficiency • 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. 107
  • 108. 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. 108
  • 109. 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. 109
  • 110. EOR process maturity curve-with time 110
  • 112. (8) Reservoir Surveillance  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 112
  • 113. (8) Reservoir Surveillance 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 113
  • 114. Engineering functions and tasks leading to decisions 114
  • 115. Relating measurements to interpretation and uncertainty reduction 115
  • 116. Example 1 : plan to identify thief zones and remediate:  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. 116
  • 117. 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 technology plans 117
  • 118. Performance expectations 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. 118
  • 119. 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. 13. Facility, plant, process flow diagram (PFD), flowline data and drawings. 119
  • 120. 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. 120
  • 121. 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 121
  • 122. 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 122
  • 123. 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 123
  • 124. Objectives based tools selection for measurements 1 2 3 4 124
  • 125. Objectives based tools selection for measurements 5 6 7 125
  • 126. Objectives based tools selection for measurements 8 9 10 11 126
  • 127. Objectives based tools selection for measurements 12 13 14 15 127
  • 128. Objectives based tools selection for measurements 16 17 18 19 128
  • 129. Objectives based tools selection for measurements 20 21 22 129
  • 130. Problem based Diagnostic and tools selection 1 2 3 130
  • 131. Problem based Diagnostic and tools selection 4 5 131
  • 132. Problem based Diagnostic and tools selection 6 132
  • 133. Problem based Diagnostic and tools selection 7 133
  • 134. Problem based Diagnostic and tools selection 8 9 10 134
  • 135. Problem based Diagnostic and tools selection 11 12 135
  • 136. Problem based job planning tree Start End 136
  • 138. (9) Tracer Techniques used for Reservoir surveillance. 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 138
  • 139. 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. (9) Tracer Techniques used for Reservoir surveillance. 139
  • 140. 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 (9) Tracer Techniques used for Reservoir surveillance. 140
  • 141. 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 (9) Tracer Techniques used for Reservoir surveillance. 141
  • 142. 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 (9) Tracer Techniques used for Reservoir surveillance. 142
  • 143. Commonly Used Tracers in the oilfields (9) Tracer Techniques used for Reservoir surveillance. 143
  • 144. 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? (9) Tracer Techniques used for Reservoir surveillance. 144
  • 145. Design Considerations. 9-What are the analytical techniques used to estimate tracer eluent concentration? 10-What would be the sampling frequency and resulting cost? 11-Is in-line sampling and analysis practical? What is the trade-off between in-line sampling installation cost vs. lab measurement? 12-Do lab tests need to be conducted to confirm compatibility with reservoir rock, fluids, and water? 13-Do 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? 16-What 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? (9) Tracer Techniques used for Reservoir surveillance. 145
  • 148. Reservoir Management 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 148
  • 150. Reservoir Management 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) 150
  • 153. 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,…). 153
  • 154. Data Acquisition and Characterization 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 154
  • 155. 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. Data Acquisition and Characterization 155
  • 156. Data Acquisition and Characterization 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 156
  • 157. 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. 157
  • 158. 158
  • 159. Generally can estimate rock properties from core Analysis Routine Core Analysis Special Core Analysis 3- Core analysis 159
  • 160.  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 4- Fluid Properties 160
  • 161.  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 5- well test 161
  • 162. Workflows for integrated reservoir modeling Integrated Reservoir Modeling 162
  • 163. reservoir modeling Integrated Reservoir Modeling Static Model Dynamic model 1. Structural modeling 2. Stratigraphic modeling 3. Lithological modeling 4. Petrophysical modeling 1. Up-scaling 2. simulation 3. History matching 163
  • 164. 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 164
  • 165. 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 165
  • 166. 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 166
  • 167. 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 167
  • 168. 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 (I) Static Model 168
  • 169. 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 (I) Static Model 169
  • 174. (II) Dynamic Model Fully Integrated Petrel Framework 1-Entire model will be based on Petrel – PVT, SCAL, VFP, Aquifers, Development Strategies 2-Petrel workflows and macros will be used to ensure a portable and maintainable history matched model. 3-Grid block-independent multipliers will be used: Zones, Segments, polygones, …This enables a smooth transition from one grid size to another in thehistory matching process 174
  • 176. 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 5- HCPV 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 176
  • 177. 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 (II) Dynamic Model 177
  • 178. 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. (II) Dynamic Model 178
  • 179. 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 179
  • 180.  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 180
  • 181. 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 181
  • 182. Reference 1. Reservoir Engineering Handbook, (Tarek Ahmed, 5th edition) 2. integrated Reservoir Asset Management. Principles and Best Practices (John R. Fanchi) 3. Basic of reservoir engineering (Rene Cosse) 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 & Ghulam M. Iqbal) 9. Basic Petroleum Geology and Log Analysis – (Hallibuton) 10. Basic Rock and Fluid Properties 11. Larry W . Lake -Petroleum engineering handbook - reservoir engineering and petro-physics volume V 12. Reservoir Engineering (Kaiser A. Jasim 2019)- presentation 13. method OOIP calculation( paper ) 14. Reservoir Management (Dr. Jawad R. Rustum Al-Assal) 15. static and dynamic model – work-folw (Kassem Ghorayeb) from SLB 182
  • 183. 183 Name: Abbas Radhi Abbas 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. About Authorized