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CO2 ENHANCED OIL & GAS RECOVERY THEORETICAL AND EXPERIMENTAL CONSIDERATIONS
BY EDMOND SHTEPANI, Ph.D.
6th Annual CO2 Conference
CASPER 2012
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OUTLINE
Rock Mineralogy and Pore Structure
Fluid Properties
Fluid-Fluid Interaction
Fluid-Rock Interaction
Energy
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Contents
PVT and Phase Behavior
Thermodynamics of Miscible Gas Injection
Compositional Simulation
Core Flood Experiments
Introduction
Summary
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Oil & Gas Recovery Mechanisms
Rock Mineralogy and Pore Structure
Fluid Properties
Fluid-Fluid Interaction
Fluid-Rock Interaction
Energy
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Porous Medium and REV
What is a representative size of porous medium?
REV << Flow Domain
REV >> Single Pore
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Dynamic Porosity
Dynamic porosity is the class of interconnected pores which
contribute to the flow (excluding dead-end pores or stagnant
pockets)
Velocity
Absolute Porosity
Effective Porosity
Dynamic Porosity
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Pore Size Distribution and Hysteresis
Mercury Saturation
Ca
pil
lary
Pre
ssu
re
0 1.0
Drainage Imbibition
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Pore-Size Distribution and Saturation Profile
1
2
3
4
5
Pd
100% Sw Swc
WOC
Pc
FWL
1 3
4
5
2
3
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Water Saturation Profile
Transition Zone
Oil Pay Zone
100% Water Saturation
Water-Oil Contact
100 % Swc
FWL (Free Water Level)
0 % Water Saturation
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Transition Zone with Permeability
Pd o
r h
Water Saturation , %
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Transition Zone and Fluid Density
Pd o
r h
SW , %
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2
1
3
4
5
6
7
High K
High K
High K
High K
Low K
Low K
Low K Well
High K Low K
Fluid Distribution in Heterogenous Reservoir
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Phase Trapping and Mobilization
Trapping and mobilization are related to the above factors in a
complex way which can be described by complex interactions
between viscous, gravity and capillary forces.
Trapping and mobilization of fluids in a porous medium is not
completely understood and cannot be rigorously described
mathematically
The trapping mechanism however is known to depend on:
Pore structure
Fluid/Rock interaction (related to wettability)
Fluid/Fluid interaction (reflected in IFT and mobility)
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Phase Trapping and Mobilization
Capillary Number, defined as the ratio of viscous forces to capillary forces, and
uN c
Interfacial Tension
Viscosity
Velocity
kgNb
Bond Number, defined as the ratio of gravity forces to capillary forces
Interfacial Tension
Density Difference
Gravity
Permeability
The basic expressions of the relative importance of these forces are provided by:
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Phase Trapping - Jamin Effect
BAowAB
rrpp
11cos2
BAow
ABr
pp
coscos2
A B Oil Water Water
A B Oil Water Water
BgoAgwAB coscos
rpp
2
өA
өB
Variation in Radius
Variation in Contact Angle
Variation in Interfacial Tension
A B Gas Water өA өB
Oil
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Oil Recovery
Primary Secondary Tertiary or EOR
Oil Recovery Operations
The initial production
from existing energy
in a reservoir.
• Natural Flow
• Artificial Lift
After primary production
declined.
• Water Flood,
• Immiscible Gas Injection
• Pressure Maintenance
The three major EOR
methods are:
• Miscible Gas
• Chemical Flood
• Thermal
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Displacement Efficiency
The overall displacement efficiency on any oil recovery displacement process can be considered as the product of microscopic and macroscopic displacement efficiencies
VDEEE E = Overall displacement
efficiency
(oil recovered by process/oil in place at start of process)
ED = Microscopic displacement efficiency
(displacement or mobilization of oil at pore scale)
EV = Macroscopic displacement efficiency
(effectiveness of the displacing fluid(s) in contacting the reservoir in a volumetric sense)
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Enhanced Oil Recovery by Miscible Gas
Hydrocarbon Gases : Lean Gas and/or Rich Gas
Non hydrocarbon Gases : N2, CO2, H2S and flue gas
Among the miscible gases used in EOR
Displacing oil with a gas that is miscible with the oil (i.e., forms a
single phase when mixed at all proportions with the oil) at the
conditions existing at the interface between the injected gas and
the oil bank being displaced.
Primary objective in a miscible process
CO2 Injection EOR
Pure CO2 (w and w/o miscibility enhancer, LPG)
CO2 with a certain degree of contamination
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Enhanced Oil Recovery by CO2 Injection
First contact miscibility (FCM) process
The injected CO2 is directly miscible with the reservoir oil at the
conditions of pressure and temperature existing in the reservoir.
There are two major variations in this process
Multiple contact miscibility (MCM) process
First contact miscibility may not be achieved because of limits on
reservoir pressure, especially, in shallow oil reservoirs. Multiple
contact miscibility can still be achieved in lower-pressure oil reservoirs
if the CO2 gas is enriched with components miscible with the oil.
In order to design a successful miscible CO2 injection project, one
must understand the mechanisms by which the injected CO2
displaces oil in the porous medium.
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Enhanced Oil Recovery by CO2 Injection
An important concept associated with the description of CO2 gas injection processes is the minimum miscibility pressure (or MMP). At this pressure, the injected gas and the initial oil in place become multi-contact miscible, and the displacement process becomes very efficient.
A closely related concept is the minimum miscibility enrichment (MME). It is the enrichment level of a particular component or group of components in CO2 gas for a given displacement pressure that still the displacement remains multi-contact miscible.
Conceptually the MMP and MME are the same; they describe the same physical mechanism, one from the point of view of varying pressure to achieve miscibility, the other from the point of view of varying injection gas composition.
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Immiscible Displacement @ Pressure below MMP
CO2 Injection EOR
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Multiple-Contact Miscible Displacement @ MMP
CO2 Injection EOR
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First-Contact Miscibility @ Pressure above MMP
CO2 Injection EOR
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First Contact Miscibility Pressure
Determine the minimum pressure required to have a certain amount of injection gas dissolved in the original oil in place.
Sa
tura
tion
Pre
ssu
re
Mole % Gas Addition
Reservoir Pressure
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Swelling Factor
Swelling of the oil phase causes:
Breakdown of the original capillary equilibrium,
Pore-scale redistribution of the phases.
Sw
elli
ng F
act
or
Mole % Gas Addition
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1.2 Gas injected, in PV
0 0.3 0.6 0.9
Oil
Reco
very
, %
25
50
75
100
VariableP
Variabley inj
i
or ,
Determination of dynamic MMP or MME
1
Oil
Reco
very
aft
er
1.2
PV,
%
Pressure or yi, (-)
1.1 1.2 1.3 1.4
70
80
90
100
MMP or MME
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Multiple Contact Experiment
Forward Contacting
Multi-contact Experiment determines the miscibility mechanism and the level of IFT at operating pressure.
1st Contact
2nd Contact 3rd Contact
2nd Contact 3rd Contact
Reverse Contacting
LOW IFT
HIGH IFT
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Pseudo-Ternary Diagram
Pseudo-ternary diagrams have traditionally been used to explain
the behavior of gas drive processes.
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1 . 1 . 2 . 3 . 4 . 5 . 6 . 7 . 8 . 9 0
0 1
C1
C2-C6 C7+
CP
M1
G1
Tie-line
Critical Tie-line
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Pseudo-Ternary Diagram Two-Phase Region with Pressure @ T=Const.
Continue
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1 . 1 . 2 . 3 . 4 . 5 . 6 . 7 . 8 . 9 0
0 1
C1
C2-C6 C7+
Pre
ss
ure
Continue
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Pseudo-Ternary Diagram
Two-Phase Region with Temperature @ P=Const.
Continue
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1 . 1 . 2 . 3 . 4 . 5 . 6 . 7 . 8 . 9 0
0 1
C1
C2-C6 C7+
Tem
pera
ture
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Enhanced Oil Recovery by Miscible Gas
The effectiveness of the EOR projects depends on pressure, i.e. the deeper reservoirs are more preferred because minimum miscibility pressure is more likely to be reached.
However, the reservoir temperature increases with depth, resulting in a higher minimum miscibility pressure.
Main parameter is the composition of target reservoir oil
Typically, CO2 can extract heavier components and has a lower MMP than natural gas, nitrogen or flue gas.
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0
1
M1
M2
G1
G2
G3
G4
G5
Oil
M3
M4
CO2 Injection Gas
Fixed Pressure
& Temperature
Vaporizing Gas Drive Mechanism
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0 1
M1
O1 O2
Oil
M3
M4 Injection Gas
Fixed Pressure
& Temperature
Condensing Gas Drive Mechanism
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Dynamic Miscibility Development
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1 . 1 . 2 . 3 . 4 . 5 . 6 . 7 . 8 . 9 0
0 1
C1
C7+ C2-C6
Oil 2 Oil 1
Injection Gas 2
Injection Gas 1
For the reservoir oil with a composition lying on, or to the right of, the critical tie line, and the natural gas with a composition lying to the left of the critical tie line dynamic miscibility can be achieved by VGD
Vaporizing Gas Drive
For the reservoir oil with a composition lying to the left of the critical tie line, and the natural gas with a composition lying on, or to the right of the critical tie line, dynamic miscibility can be achieved by CGD
Condensing Gas Drive
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CO2 Injection Special Coreflood Tests
Special Core flood displacement experiments at reservoir condition
on samples representing the principal reservoir rock types to:
Determine effect of IFT in fluid redistribution
Determine the effect of mobility, pore size distribution, and
wettability
Determine the relative flow represented by relative permeabilities
on equilibrium two phase flow: Krow(Sw), krog(Sg,σgo)
Generate residual oil saturation profile as function of IFT Sor(σgo)
Evaluate the longitudinal dispersion by compositional profile
In-situ monitoring of lab scale displacement
Evaluate the secondary and/or tertiary recovery processes.
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Wettability and PSD in Recovery Performance
A)Rock exhibits a wide pore size distribution and a large fraction of
the oil in place is trapped and contained in a relatively small pore
space with small pore throat radii.
Case A. Typical Pore Size Distributions
0 5 10 15 20 25
Pore Size
Pro
ba
bil
ity
Dis
trib
uti
on
O il WaterGas
Oil wet situation
Very Low IFT required to obtain high recovery
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Wettability and PSD in Recovery Performance
B) A large portion of the micro-porosity is saturated with water rather
than oil.
Case B. Typical Pore Size Distributions
0 5 10 15 20 25
Pore Size
Pro
ba
bil
ity
Dis
trib
uti
on O ilWater Gas
Water-wet situation
Higher IFT condition can obtain comparable recovery to A)
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Wettability and PSD in Recovery Performance
C) A skewed PSD is present and a large portion of the recoverable oil is
contained in macropores with very little micro-porosity
Higher IFT condition can obtain high recovery
* Adverse mobility ratio, gravity segregation result in low E
Case C. Typical Pore Size Distributions
0 5 10 15 20 25
Pore Size
Pro
ba
bil
ity
Dis
trib
uti
on
O ilWater
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Longitudinal Dispersion Coefficient
Defining the width of dispersion zone as the distance between the
locations at which the CO2 concentration is 0.1 and 0.9 mole fraction,
the width of dispersion zone can be calculated from
The dispersion width is ~ square root of time traveled or for constant
injection rates, from x = vt, the width of dispersion zone is ~ square root
of the mean distance traveled.
tK.xx l.. 62539010
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CO2 Coreflood Study- Vertical Down
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CO2 Coreflood Study- Horizontal
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CO2 Coreflood Study- Vertical Up
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CO2 Injection in Depleted Gas-Condensate
Reservoirs
Surface forces often render the condensate immobile and the only
means to recover efficiently these hydrocarbons is through vaporization
into a mobile phase.
Pressure diffusivity is typically three-five orders of magnitude larger than
molecular diffusivity, making repressurization occur much faster than
mixing by molecular diffusion
The maximum rate of vaporization in gas/condensate reservoirs will
occur at the maximum liquid drop out as the contact area between the
CO2 and liquid phase is maximized
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CO2 Injection in Depleted Gas-Condensate
Reservoirs
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CO2 Injection Compositional Simulation
Current Compositional Simulation
Recommended Compositional Simulation
Simulation and Interpretation of flow experiments using
compositional coreflood simulation methods is a final step to
complete the laboratory data required for a successful design
of a full scale compositional reservoir simulation.
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Current Compositional Reservoir Simulation
Continue
This assumption might hold true for homogeneous media and ideal miscibility conditions only. Wettability and pore size distribution may significantly impact recovery performance.
0
1
1 Saturation
Rela
tive P
erm
eabili
ty
Current simulation practices model the reservoir
using one set of relative permeability data per rock
region. Once rock regions are assigned they are
usually fixed over the life of the simulation.
In case of miscibility displacement an ideal relative permeability curve to correspond to total miscibility and scaling these curves for given conditions is used.
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High and Low IFT Relative Permeability
Case 1 represents the results of an experimental program where
interfacial tension effects dominate and are significant in increasing the
recovery of oil.
0.00
0.20
0.40
0.60
0.80
1.00
0 0.2 0.4 0.6 0.8 1
Gas Saturation
Krg
an
d K
ro
g
Case 1
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High and Low IFT Relative Permeability
Case 2 provides an illustration of a reservoir scenario where the
mobility, PSD, and core wettability effects appear to completely
dominate.
0.00
0.20
0.40
0.60
0.80
1.00
0 0.2 0.4 0.6 0.8 1
Gas Saturation
Krg
an
d K
ro
g
Case 2
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Recommended Compositional Simulation
Two sets of capillary pressures
Two sets of relative permeability curves measured from multi-contacted
fluid pairs if incorporated in the compositional simulator will substantially.
Longitudinal Dispersion Coefficient
History Matching using pressure differential, volumetric and compositional
experimental data
EOR process-variable sensitivity studies
To improve the predicting capabilities
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CO2 Injection Compositional Simulation
The representative values of capillary pressure and relative permeability
curves at given pressure and composition can be determined from IFT using
the following relationships:
minmax
** 1
SorSorSor
minmax
** 1
krgkrgkrg
minmax
** 1
krogkrogkrog
minmax
** 1
PcPcPc
minmax
min*
where
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Advanced PVT Experiments, and EOS characterization and
modeling of fluid phase behavior in the entire (P –V – T-μ – zi – Ki
– go) envelope
Reservoir Fluid PVT Study
Constant Composition Expansion
Differential Liberation
Constant Volume Depletion
CO2 Injection Laboratory Protocol
Miscibility Study
RBA
Swelling (P-x) Test
Multiple-Contact Experiment
Slimtube Test
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Special Core flood displacement experiments at reservoir conditions:
Generate Sor(σgo), Pc(σgo), Krow(Sw), krog(Sg,σgo)
Evaluate the secondary and/or tertiary recovery processes.
CO2 Injection Laboratory Protocol
Routine and Static Special Core Analysis
P &P, Mercury Injection Capillary Pressure
Wetability Restoration and Wetability Index
Capillary Pressure
Dynamic Special Core Analysis
USS relative permeability study at reservoirs conditions with
equilibrium fluids from SCE or MCE for each RRT
Secondary/Tertiary CO2 Injection Coreflood at Swi, TZ, ROZ with
ISSM and Compositional Measurements
WAG (or SWAG) CO2 Injection Coreflood at Swi
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THANK YOU FOR YOUR
ATTENTION
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Questions?