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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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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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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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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?