Methods for Enhanced Oil Recovery E-Book

Baghir A. Suleimanov

• Herausgeber: Wiley-VCH
• Kategorie: Fachliteratur
• Sprache: Englisch

Seitenzahl: 639

Veröffentlichungsjahr: 2025

Beschreibung

An authoritative theoretical explanation of enhanced oil recovery combined with practical, “how-to” instructions on the real-world implementation of EOR

In Methods for Enhanced Oil Recovery: Fundamentals and Practice, a team of distinguished researchers delivers a comprehensive and in-depth exploration of the rapidly evolving field of enhanced oil recovery (EOR). The authors dive deep into the granular details of petroleum geology, hydrocarbon classification, and oil reserve assessment, while also explaining a variety of EOR techniques, like thermal, chemical, gas injection, and microbial approaches.

The book is heavily focused on advanced methods of EOR with accompanying analyses of contemporary techniques. It includes innovative new approaches to the discipline, presenting each method with a theoretical background and practical guidelines for implementation in the field. Readers will also find specific coverage of the criteria they should use to select appropriate EOR methods for specific reservoirs and the technological processes necessary to implement these methods in operational settings.

Inside the book:

• A thorough introduction to the laboratory evaluation of oil-bearing rock properties
• Contemporary case studies from oil fields in a variety of regions that illustrate the benefits and challenges of implementing EOR technologies
• Practical discussions of the economic implications of EOR methods
• Complete treatments of fundamental reservoir engineering concepts

Perfect for students of petroleum engineering, Methods for Enhanced Oil Recovery: Fundamentals and Practice will also benefit practicing petroleum engineers seeking a solid theoretical foundation into EOR combined with real-world, practical insights they can apply immediately.

Leseprobe

Table of Contents

Cover

Table of Contents

Title Page

Copyright

Preface

Introduction

Chapter 1: Basic Concepts in Reservoir Engineering

1.1 Rocks and Their Types

1.2 Forms of Occurrence of Sedimentary Rocks

1.3 Hydrocarbon Reservoirs

1.4 Oil and Gas Traps

1.5 Rock Porosity

1.6 Rock Permeability

1.7 Geological Heterogeneity of Rocks

1.8 Saturations

1.9 Resistivity

1.10 Capillary Pressure

1.11 Types of Reservoir Fluids

Bibliography

Chapter 2: Fluid Flow in Porous Media

2.1 Introduction

2.2 Applications of Darcy’s Law

2.3 Differential Equations for Fluid Flow

2.4 Steady-state Flow

2.5 Basic Solutions of the Constant Terminal Rate Case for Radial Models

2.6 The Constant Terminal Pressure Solution

2.7 Superposition

2.8 Ideal Gas Flow

Bibliography

Chapter 3: Classification of Hydrocarbons and Oil Reserves

3.1 Common Classification of Hydrocarbons

3.2 Classification of Oil Reserves

3.3 Oil Recovery Factor

3.4 SPE/WPC/AAPG Classification of Reserves

3.5 Russian Classification of Reserves

3.6 The United Nations Framework Classification for Resources

Bibliography

Chapter 4: Oil Recovery Methods

4.1 Introduction

4.2 Primary Recovery

4.3 Secondary Recovery

4.4 Tertiary Recovery

4.5 Sweep Efficiency

Bibliography

Chapter 5: Thermal Enhanced Oil Recovery (EOR)

5.1 Introduction

5.2 Steam Injection

5.3

In situ

Combustion

Bibliography

Chapter 6: Gas Flooding

6.1 Introduction

6.2 Injection of Hydrocarbon Gases

6.3 Nitrogen Injection

6.4 CO

2

Injection

6.5 Water–Gas Impact on the Formation

Bibliography

Chapter 7: Chemical Enhanced Oil Recovery (EOR)

7.1 Introduction

7.2 Polymer Flooding

7.3 Micellar-polymer Flooding

7.4 Alkaline Flooding

Bibliography

Chapter 8: Microbial EOR

8.1 Introduction

8.2 Introduction to Microorganisms in MEOR

8.3 Process Mechanism of MEOR

8.4 Applicability Criteria

8.5 Field Implementations

8.6 Implementation Technology

Bibliography

Chapter 9: Forefront EOR

9.1 Introduction

9.2 In Depth Fluid Diversion

9.3 Injection of Low-salinity Water

9.4 High Pressure Air Injection

9.5 Overview of Organic Oil Recovery Methods

Bibliography

Chapter 10: Practical Implementation of Enhanced Oil Recovery (EOR)

10.1 Screening Assessment

10.2 Phase Behavior of Formation Fluids and Core Analysis

10.3 EOR Simulation

10.4 Implementation of EOR

10.5 Technology Readiness Level

Bibliography

Chapter 11: Laboratory Evaluation of Oil-bearing Rock Properties

11.1 Introduction

11.2 Granulometric Composition of Rock

11.3 Determining the Density of Rocks

11.4 Determining the Carbonate Content of Rocks

11.5 Collector Properties

11.6 Porosity Measurements

11.7 Wettability and Wettability Tests

11.8 Interfacial Tension

11.9 Steady-State Permeability Measurements

11.10 Unsteady-state Permeability Measurements

11.11 Steady-State Liquid (Absolute) Permeability Measurements

Bibliography

Chapter 12: Economic Assessment of Enhanced Oil Recovery (EOR)

12.1 Introduction

12.2 Determining the Optimal Time to Start EOR

12.3 Technological Efficiency of EOR

12.4 Economic Efficiency of EOR

Bibliography

Index

End User License Agreement

List of Illustrations

Introduction

Figure 1 Distribution by year of the ratio of oil production due to EOR (%) in the USA ...

Figure 2 Share of each country in world oil production using EOR (%).

Figure 3 Distribution of additionally produced oil by enhanced oil recovery methods (%).

Figure 4 Distribution of additionally produced oil by general methods of enhanced oil r...

Figure 5 Forecast of the market value of EOR in the USA until 2025.

Chapter 1

Figure 1.1 Schematics of the rock cycle.

Figure 1.2 Internal structure of Earth (a) and main source of internal heat/ene...

Figure 1.3 Schematics of the hydrological cycle.

Figure 1.4 Mode of rocks occurrence.

Figure 1.5 Oil field schematic.

Figure 1.6 Anticline (fold) trap.

Figure 1.7 Fault trap.

Figure 1.8 (a) Pinch-out trap; (b) a trap confined to a reef massif.

Figure 1.9 Stratigraphic traps.

Figure 1.10 Connected/nonconnected pores.

Figure 1.11 Diagenesis.

Figure 1.12 (a) Cubic or wide packed; (b) rhombohedral or close-packed; (c) –4 b...

Figure 1.13 Interparticle porosity.

Figure 1.14 Intraparticle porosity.

Figure 1.15 Fracture porosity.

Figure 1.16 (a) Moldic; (b) vugs.

Figure 1.17 Schematic representation of the Darcy equation parameters.

Figure 1.18 Cross section of reservoir showing vertical segregation of fluids.

Figure 1.19 Normal initial fluid distribution in a reservoir of uniform permeabi...

Figure 1.20 Microscopic cross section of OWC and transition zone.

Figure 1.21 Example of saturation changes occurring in the core from

in situ

to ...

Figure 1.22 Definition of water resistivity.

Figure 1.23 Definition of a 100% water-saturated sand.

Figure 1.24 Relationship between and water conductivity.

Figure 1.25 Resistance in a hydrocarbon-bearing formation.

Figure 1.26 Capillary tubes in wetting and nonwetting fluids.

Figure 1.27 Capillary pressure in reservoirs.

Figure 1.28 Conventional capillary pressure curve.

Figure 1.29 Imbibition and drainage capillary pressure curves illustrating hyste...

Figure 1.30 Effect of permeability on capillary pressure.

Figure 1.31 Relationship between capillary pressure and relative permeability.

Figure 1.32 Relationship between capillary pressure and relative permeability.

Figure 1.33 Spatial variation of and curves for a reservoir.

Figure 1.34 Phase diagram of black oil.

Figure 1.35 Phase diagram of volatile oil.

Figure 1.36 Phase diagram of gas condensate.

Figure 1.37 Phase diagram of wet gas.

Figure 1.38 Phase diagram of dry gas.

Chapter 2

Figure 2.1 Radial fluid flow model toward the wellbore.

Figure 2.2 Linear flow model for parallel bed combinations.

Figure 2.3 Linear flow model for beds in series combination.

Figure 2.4 Radial flow model for beds in series combination.

Figure 2.5 Impact of high-velocity flow on the Darcy equation.

Figure 2.6 Representative model for fracture permeability.

Figure 2.7 Influence of geometric shape on the permeability-porosity relationship.

Figure 2.8 Cartesian coordinate system volume element.

Figure 2.9 Diagram illustrating boundary conditions for radial flow with consta...

Figure 2.10 Schematic of flow through a horizontal core.

Figure 2.11 Pressure profile around a well.

Figure 2.12 Wellbore pressure response to a change in flow rate.

Figure 2.13 Model illustrating the pressure response of a reservoir to a flowing...

Figure 2.14 Variation of the permeability around the wellbore changes the local p...

Figure 2.15 Pressure profile in a reservoir under semi-steady state flow conditio...

Figure 2.16 Superposition of pressure variations from multiple wells.

Figure 2.17 Effect of flow rate variations on wellbore pressure.

Figure 2.18 Wellbore pressure response to multiple flow rates.

Figure 2.19 Equivalence of flow rate variations in a reservoir.

Figure 2.20 The pressure impact of a barrier in a real reservoir represented by ...

Figure 2.21 Representation of a boundary using a real well and an image well.

Figure 2.22 Representation of a well at the intersection of two boundaries.

Figure 2.23 Representation of an actual well between two barriers.

Figure 2.24 Representation of a well surrounded by boundaries.

Figure 2.25 Flow net for a simple flow system.

Figure 2.26 Schematic representation of a closed boundary.

Figure 2.27 Schematic representation of an open boundary.

Chapter 3

Figure 3.1 Classification and nomenclature of hydrocarbon fluids.

Figure 3.2 Classification of oil reserves.

Figure 3.3 Adapted McKelvey box demonstrating terminology for recoverable resources.

Figure 3.4 Graphical representation of resources and reserves.

Figure 3.5 Uncertainty in resource estimation.

Figure 3.6 Russian classification of reserves.

Figure 3.7 Principles of Russian classification of reserves and resources.

Figure 3.8 UNFC classification criteria.

Chapter 4

Figure 4.1 Primary oil recovery.

Figure 4.2 Secondary hydrocarbon recovery.

Figure 4.3 Schemes for areal waterflooding.

Figure 4.4 Well location for contour flooding.

Figure 4.5 Waterflooding applicability criteria.

Figure 4.6 Oil recovery stages and applied extraction technologies.

Figure 4.7 EOR processes.

Figure 4.8 Methods for EOR.

Figure 4.9 Additional oil recovery factors (ORF) and final ORF figures for the ...

Figure 4.10 Representation of microscopic and macroscopic sweep efficiencies.

Chapter 5

Figure 5.1 The mechanism of the steam injection process into the reservoir.

Figure 5.2 Steam injection applicability criteria.

Figure 5.3 Technology of steam injection from the wellhead.

Figure 5.4 Steam generator.

Figure 5.5 Steam injection technology using a downhole steam generator.

Figure 5.6 Cyclic steam injection stages.

Figure 5.7 Well arrangement and schematic of oil extraction process during SAGD.

Figure 5.8

In situ

combustion process.

Figure 5.9 Zoning for dry forward burning.

Figure 5.10 Zoning for wet forward burning.

Figure 5.11 Zoning for reverse combustion.

Figure 5.12 Screening parameters for

in situ

combustion.

Figure 5.13 Deep gas-air heater.

Figure 5.14 Ignition well arrangement for ignition by the downhole electrical ig...

Figure 5.15 Ignition well arrangement for ignition by the submerged fired heater.

Chapter 6

Figure 6.1 Number of thermal and gas EOR projects implemented in the USA.

Figure 6.2 EOR production of thermal recovery and gas flooding in the USA.

Figure 6.3 Oil displacement scheme for immiscible hydrocarbon gas injection.

Figure 6.4 Oil displacement scheme for miscible hydrocarbon gas injection.

Figure 6.5 Ternary diagram ( – boundary phase curve, – curve of the begin...

Figure 6.6 Ternary diagram with different injection pressure.

Figure 6.7 Ternary diagram for immiscible injected gas–oil combination.

Figure 6.8 Ternary diagram.

Figure 6.9 Ternary diagram.

Figure 6.10 Oil displacement scheme for the liquid propane-supported flooding.

Figure 6.11 Ternary diagram.

Figure 6.12 Applicability criteria for hydrocarbon gas injection.

Figure 6.13 Hydrocarbon flooding EOR projects operating in the USA between 1980 ...

Figure 6.14 Implementation of the hydrocarbon gas injection method around the wo...

Figure 6.15 Gas injection well design.

Figure 6.16 Ternary diagram.

Figure 6.17 Vaporizing and condensing gas drive.

Figure 6.18 Ternary diagram for nitrogen.

Figure 6.19 Applicability criteria for nitrogen and flue gas injection.

Figure 6.20 Nitrogen injection projects completed in the USA between 1980 and 2014.

Figure 6.21 Flue gas and other gas injection projects implemented in the USA bet...

Figure 6.22 Nitrogen injection projects.

Figure 6.23 Nitrogen injection at the Akal field.

Figure 6.24 Injecting nitrogen into the gas cap.

Figure 6.25 Miscible displacement by nitrogen injection.

Figure 6.26 Nitrogen/water miscible displacement.

Figure 6.27 Gravity drainage with nitrogen injection.

Figure 6.28 Maintaining reservoir pressure in a gas condensate field by injectin...

Figure 6.29 Phase diagram of carbon dioxide (I – gas, II – liquid, III – solid).

Figure 6.30 Minimal miscible pressure determination.

Figure 6.31 CO

2

injection applicability criteria.

Figure 6.32 CO

2

injection projects implemented in the USA between 1972 and 2014.

Figure 6.33 Oil production in the USA, obtained from the implementation of CO

2

i...

Figure 6.34 Number of projects and annual production in 2014 from the implementa...

Figure 6.35 Carbon dioxide injection projects implemented in different countries.

Figure 6.36 Oil production obtained from the implementation of CO

2

injection pro...

Figure 6.37 Carbon dioxide injection projects implemented in the former USSR.

Figure 6.38 Number of immiscible displacement carbon dioxide injection projects.

Figure 6.39 Distribution of the number of carbon dioxide injection projects with...

Figure 6.40 Increasing oil production by implementing the immiscible displacemen...

Figure 6.41 Carbonated water injection.

Figure 6.42 Injection of CO

2

slug.

Figure 6.43 Artificial zoning and processes during CO

2

/water slug injections.

Figure 6.44 Alternating injection of carbon dioxide and water.

Figure 6.45 WAG process.

Figure 6.46 Sequential injection of gas and water.

Figure 6.47 Hybrid WAG.

Figure 6.48 Simultaneous WAG.

Figure 6.49 Selective simultaneous WAG.

Figure 6.50 Foam-assisted WAG.

Figure 6.51 Comparison of main processes during simple gas flooding and various ...

Figure 6.52 Effects of gas/oil miscibility properties during WAG implementation.

Figure 6.53 Criteria for the applicability of WAG.

Figure 6.54 Implemented gas injection projects and WAG technologies.

Figure 6.55 Hydrocarbon gas WAG projects with various methods of agent delivery.

Figure 6.56 Carbon dioxide WAG projects with miscible and immiscible displacements.

Figure 6.57 WAG surface injection arrangements with predominantly free (a) and a...

Figure 6.58 WAG hydrocarbons implementation with a separate gas/water injection.

Figure 6.59 Foam WAG hydrocarbons implementation with a separate gas/foam injection.

Chapter 7

Figure 7.1 Shear-thinning polymer solution ( is the viscosity of the solution, ...

Figure 7.2 Rheology of dilatant and pseudoplastic fluids ( - shear stress).

Figure 7.3 Rheology of a polymer solution in a heterogeneous porous medium.

Figure 7.4 Criteria for the applicability of polymer flooding.

Figure 7.5 Polymer flooding projects in 24 countries.

Figure 7.6 Results of polymer flooding projects.

Figure 7.7 Polymer flooding.

Figure 7.8 Micellar-polymer flooding.

Figure 7.9 Water saturation during the micellar-polymer flooding process.

Figure 7.10 Ternary diagram.

Figure 7.11 Types of micellar solutions.

Figure 7.12 Triple diagram.

Figure 7.13 Volume concentration of micellar solution components.

Figure 7.14 Applicability criteria for micellar-polymer flooding.

Figure 7.15 Implementation results of micellar-polymer flooding projects.

Figure 7.16 Implementation results of micellar-polymer flooding projects.

Figure 7.17 Implementation results of micellar-polymer flooding at the Shengli f...

Figure 7.18 Impact of oil activity on interfacial tension.

Figure 7.19 Impact of clay type on alkaline adsorption.

Figure 7.20 Applicability criteria for alkaline flooding.

Figure 7.21 Results of implementation of alkaline projects waterfloods.

Figure 7.22 Results of alkaline flooding projects.

Figure 7.23 Alkaline flooding.

Figure 7.24 Polymer-alkali flooding.

Figure 7.25 Alkaline flooding with precipitate-forming solution.

Chapter 8

Figure 8.1 Scheme of oil displacement from a reservoir during microbiological e...

Figure 8.2 Mechanisms of microbiological EOR.

Figure 8.3 Criteria for the applicability of microbiological methods of exposure.

Chapter 9

Figure 9.1 Difference between cross-linked and colloidal dispersed gels.

Figure 9.2 Change in the injectivity profile of the LAS-58 well after injection...

Figure 9.3 Dynamics of changes in oil production for 10 responding production wells.

Figure 9.4 Dynamics of changes in water cut of produced fluids for 10 reacting ...

Figure 9.5 Scheme of piping of ground-based equipment when pumping CDG.

Figure 9.6 Piping diagram for ground-based equipment at low water injection pre...

Figure 9.7 Piping diagram for ground-based equipment at high water injection pr...

Figure 9.8 Strapping scheme used when using PPG.

Figure 9.9 Technological scheme for obtaining the required composition of Desig...

Figure 9.10 Dependence of oxygen content on temperature in the formation.

Figure 9.11 Dynamics of implemented HPAI projects in the USA.

Figure 9.12 Schematic illustration of the enhanced organic oil recovery process ...

Chapter 10

Figure 10.1 Scoring procedure.

Figure 10.2 Seismic profile of the field.

Figure 10.3 Log Correlation.

Figure 10.4 Structural-stratigraphic framework of the horizon.

Figure 10.5 Reservoir facies model.

Figure 10.6 Petrophysical modeling.

Figure 10.7 Distribution of formation flow-capacity properties of a reservoir ov...

Figure 10.8 Saturation distribution in the hydrodynamic model.

Figure 10.9 Field development map with a highlighted pilot area.

Figure 10.10 Injection well injectivity profile before and after events.

Figure 10.11 Distribution of streamlines: (a) before the start of impact on the f...

Figure 10.12 Dynamics of oil flow rate and water cut of products.

Figure 10.13 Determination of additional oil production.

Figure 10.14 EOR implementation form.

Chapter 11

Figure 11.1 Weighing a saturated sample in a liquid: 1—scale; 2—wire; 3—sample; ...

Figure 11.2 Porosimeter: 1—chamber; 2—scale; 3—fitted lid; and 4—glass.

Figure 11.3 Determination of the density of the solid phase of the rock using a ...

Figure 11.4 Vacuum system for saturating rock samples with liquid.

Figure 11.5 Clark apparatus AK-4.

Figure 11.6 Soxhlet apparatus.

Figure 11.7 Helium grain volume instrument schematic (matrix cup empty).

Figure 11.8 Helium grain volume instrument schematic (matrix cup filled with plug).

Figure 11.9 Helium pore volume porosimeter schematic.

Figure 11.10 Typical mercury pycnometer schematic.

Figure 11.11 Typical mercury immersion system schematic.

Figure 11.12 Archimedes brine immersion system: (a) saturated weight (pore volume...

Figure 11.13 Grain density errors in density porosity calculations.

Figure 11.14 Sessile drop method.

Figure 11.15 Modified sessile drop method.

Figure 11.16 Goniometer experimental setup.

Figure 11.17 Surface roughness effects on measured contact angle (Popiel, 1978 / ...

Figure 11.18 Schematic of Amott test.

Figure 11.19 Amott cell schematic for spontaneous imbibition of water and oil.

Figure 11.20 Spontaneous imbibition schematic for unconsolidated material (using ...

Figure 11.21 USBM example—water wet sample.

Figure 11.22 USBM example—oil wet sample.

Figure 11.23 USBM example—neutral wet sample.

Figure 11.24 Combined Amott-USBM curve example.

Figure 11.25 SFW-mineral oil IFT versus salt concentration.

Figure 11.26 Illustration of pendant drop method.

Figure 11.27 Schematic of Du Noüy ring method.

Figure 11.28 Illustration of Wilhelmy plate method.

Figure 11.29 Gas permeameter schematic.

Figure 11.30 Hypothetical Klinkenberg plot showing non-Darcy flow behavior.

Figure 11.31 Hypothetical slippage—corrected Darcy plot showing non-Darcy flow be...

Figure 11.32 Hypothetical inertial flow and slippage-corrected Forchheimer plot.

Figure 11.33 Example of unsteady state pressure drawdown permeameter.

Figure 11.34 Example pulse decay apparatus.

Figure 11.35 Example pressure decay curve.

Figure 11.36 Example of Darcy plot for liquid flow.

Chapter 12

Figure 12.1 Typical chart of the changes in the oil production and net profit of...

Figure 12.2 The structure of the dependence of technological and economic (...

Figure 12.3 Dynamics of for the implementation of EOR.

Figure 12.4 Sensitivity of to changes in calculated parameters.

List of Tables

Chapter 1

Table 1.1 Typical interfacial tension and contact angle constants.

Table 1.2 Permeability effects.

Chapter 2

Table 2.1 Dimensionless pressure values at various dimensionless times for dif...

Table 2.2 Dimensionless pressure vs. dimensionless time – infinite r...

Table 2.3 Dimensionless pressure vs. dimensionless time – finite rad...

Table 2.4 Drainage area shape factors for different single-well configurations.

Chapter 3

Table 3.1 Resource uncertainty categories.

Table 3.2 Classification according to project status/maturity.

Table 3.3 Comparison of different classifications.

Chapter 4

Table 4.1 EOR mechanism for the most commonly used EOR methods.

Chapter 9

Table 9.1 Characteristics of reservoir rock and oil of the LomaAltasur field (...

Table 9.2 Composition of formation, produced, sea, and injected water at the t...

Table 9.3 Results of assessing the induction period of the autoxidation reacti...

Table 9.4 Results of HPAI implementation at light oil fields.

Table 9.5 Results of implementation of HPAI projects in fields with carbonate ...

Chapter 10

Table 10.1 Summary of screening criteria for EOR methods.

Table 10.2 Technology readiness level (TRL) for various enhanced oil recovery t...

Chapter 11

Table 11.1 Physical and dimensional properties of rock samples for density dete...

Table 11.2 Measurement data for determining rock sample density using a pycnometer.

Table 11.3 Classification by CaCO

3

content.

Table 11.4 Conversion table for CO

2

volume (cm

3

) to mass (mg) at various temper...

Table 11.5 Initial experimental data and calculations for determining CaCO

3

con...

Table 11.6 Helium pore volume—advantages and drawbacks.

Table 11.7 Mercury bulk volume: advantages and drawbacks.

Table 11.8 Re-saturation porosity: advantages and drawbacks.

Table 11.9 Contact angle wettability classification.

Table 11.10 Summary of contact angle measurements.

Table 11.11 Overview of Amott wettability methods.

Table 11.12 Amott wetting indices.

Table 11.13 Amott—Harvey summary.

Table 11.14 Overview of the USBM wettability method.

Table 11.15 USBM wetting indices.

Table 11.16 Summary of USBM method.

Table 11.17 Overview of the combined Amott–USBM Method.

Table 11.18 Combined Amott–USBM summary.

Table 11.19 Summary of IFT measurement methods.

Table 11.20 Unsteady-state gas permeability summary.

Table 11.21 Steady-state absolute liquid permeability summary.

Chapter 12

Table 12.1 Input data for calculation of economic efficiency.

Table 12.2 Calculation results for economic efficiency of the EOR implementation.

Table 12.3 Results of second stage calculations assessing effectiveness of EOR ...

Table 12.4 Summary of calculation results for different indicator variations.

Guide

Cover

Table of Contents

Title Page

Copyright

Preface

Introduction

Begin Reading

Index

End User License Agreement

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Methods for Enhanced Oil Recovery

Fundamentals and Practice

Baghir A. Suleimanov

Elchin F. Veliyev

Authors

Prof. Baghir A. Suleimanov

Deputy Director

Oil Gas Scientific Research Project Institute, SOCAR

Baku, Azerbaijan

Dr. Elchin F. Veliyev

Manager of Analytical Researches Laboratory

Oil Gas Scientific Research Project Institute, SOCAR

Baku, Azerbaijan

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Cover Image: © Han maomin/Shutterstock

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Preface

The science and practice of Enhanced Oil Recovery (EOR) have evolved significantly in recent decades, becoming an essential component in extending the productive life of oil fields and maximizing hydrocarbon extraction. This book, Methods for Enhanced Oil Recovery—Fundamentals and Practice, provides a comprehensive exploration of both theoretical and practical aspects of modern EOR techniques, making it a valuable resource for students, researchers, and engineers in the petroleum industry.

The early chapters cover fundamental reservoir engineering concepts, including the geology of oil fields, the classification of hydrocarbons and reserves, and the principles behind primary and secondary recovery methods. These foundational topics are essential for understanding the dynamics of oil reservoirs and their behavior under different recovery techniques.

A substantial portion of this book is dedicated to advanced methods of enhancing oil recovery, with in-depth analyses of various modern techniques. Readers will find detailed explanations of thermal, gas, chemical, and microbial EOR methods, as well as emerging innovations. Each method is presented not only with a theoretical background but also with practical guidelines for field implementation. Special attention is given to the criteria for selecting an appropriate EOR method for specific reservoirs and the technological processes necessary to implement these methods in operational settings.

A dedicated chapter focuses on the laboratory evaluation of oil-bearing rock properties. This section covers essential testing methods, such as porosity and permeability measurements, wettability tests, and interfacial tension evaluations. The detailed procedures for laboratory analysis provide readers with the tools to better understand the behavior of reservoir rocks, enabling more accurate predictions of EOR efficiency and outcomes.

Real-world applications play a prominent role throughout the book, with case studies from oil fields in various regions illustrating both the successes and challenges faced in implementing EOR technologies. Furthermore, the book explores innovative EOR techniques that are currently under development or in pilot testing, highlighting the industry’s future direction.

In addition to the technical aspects, the book also addresses the economic evaluation of EOR methods, emphasizing the importance of balancing technological efficiency with economic feasibility to guide decision-making in practical scenarios.

Whether you are a student looking to deepen your understanding of EOR or an engineer seeking practical guidance for field applications, this book provides both a solid theoretical foundation and practical insights. We hope it will inspire innovation and contribute to the successful deployment of EOR techniques in oil fields worldwide.

Introduction

The average oil recovery across the world is about 30%. At the same time, proven geological oil reserves in the world, as of the end of 2019, amount to 1.73 trillion barrels (237 billion tons). It is obvious that the current efficiency of oil field development, including enhanced oil recovery (EOR) methods, is insufficient. In connection with this, the relevance of research in the field of EOR increases.

The book brought to your attention is devoted to a detailed study of existing methods for increasing oil recovery, as well as the prospects for increasing their efficiency. EOR methods are part of improved oil recovery (IOR) methods, which include, in addition to EOR, new technologies for drilling and completing wells, control and regulation of development, modern monitoring methods, as well as primary and secondary field development methods.

The current contribution of EOR to total oil production is of great importance for analyzing the prospects for increasing their efficiency. Figure 1 shows the distribution by year of the share of oil production due to EOR in relation to the total production of the USA and China, which are the largest oil producers using EOR.

Figure 1 Distribution by year of the ratio of oil production due to EOR (%) in the USA and China.

As can be seen from Figure 1, oil produced as a result of EOR in China significantly exceeds the same figure in the USA, while the indicated figure for China continues to grow (from 14.88 in 2010 to 18.32 in 2016), and for the USA—decrease (from 8.67 in 2010 to 5.83 in 2016). The share of oil produced through EOR in China is approaching 20%. This is the best indicator for countries in the world (the world average is 3.3%, according to 2014 data). It is clear that there is significant potential for improving the efficiency of EOR.

Figure 2 shows the share of each country using EOR in the total oil production from EOR by country of the world, according to data from 2010 to 2014.

Figure 2 Share of each country in world oil production using EOR (%).

As can be seen from Figure 2, four countries—the USA, China, Venezuela and Canada—produce almost 80% of the additional oil obtained using EOR. The distribution of oil according to the applied methods of EOR is also of interest. The specified distribution is shown in Figure 3.

Figure 3 Distribution of additionally produced oil by enhanced oil recovery methods (%).

As can be seen from Figure 3, a number of EOR methods give up to 98% additional oil. These are steam injection, chemical methods, carbon dioxide, and hydrocarbon gas injection. World indicators for generalized methods of EOR (Figure 4) allow us to conclude that thermal methods are the main method of increasing oil recovery, although their share is decreasing from 58.2% in 2010 to 48.2% in 2014. At the same time, the share of chemical methods with 14.7% in 2010 to 26.2% in 2014. The share of gas EOR methods remains virtually unchanged.

Figure 4 Distribution of additionally produced oil by general methods of enhanced oil recovery (%).

Three generalized EOR methods—thermal, chemical, and gas—continue to dominate. The forecast for the market value of EOR in the USA until 2025 (Figure 5) shows that a similar trend will continue in coming years.

Figure 5 Forecast of the market value of EOR in the USA until 2025.

Let us now consider the basic principles of creating new technologies for enhancing oil recovery. When creating a new method for increasing oil recovery, it should be taken into account that it will be effective only when the technical contradiction inherent in the technological process is overcome. For example, a technical contradiction when flooding an oil field is that maintaining reservoir pressure requires injecting large volumes of water, along with Moreover, injection of a large volume of water leads to disruption of the stability of the displacement front and early breakthrough of water to production wells. Overcoming this contradiction is possible by using non-Newtonian systems that ensure both the maintenance of reservoir pressure and the stability of the displacement front.

One of the main requirements for the technological process of influencing the bottomhole zone is selectivity. Therefore, targeted delivery of the working fluid to the least permeable or contaminated zones of the formation is necessary. At the same time, the working fluid, if necessary, should be easily washed out of the well so as not to interfere with subsequent oil production. It is known that high-impact coverage is achieved when using high-viscosity fluids, while low-viscosity fluids are removed from the formation more quickly. Thus, mutually exclusive requirements for the working fluid determine a technical contradiction when influencing the bottomhole zone of wells.

The technical contradiction in oil production is that, with on the one hand, it is necessary to maintain high oil extraction rates, and with on the other hand, high oil production leads to early watering of wells and a sharp decrease in phase permeability for oil. This technical contradiction can be overcome by effective isolation of water inflows, which will ensure the maintenance of a sufficiently high oil recovery and will help reduce field development time. Obviously, the main requirement for an effective method of isolating water inflows is the selectivity of the effect, in which the phase permeability to water decreases (technical success), and the permeability to oil increases (economic success) or remains at the same level.

This approach to solving technical problems was developed by Genrich Saulovich Altshuller and called it «The Theory of Inventive Problem Solving» (TRIZ). It is easy to see that Altshuller’s approach is based on Hegelian dialectics. The (Hegelian) triad “thesis – antithesis – synthesis” allows solving many technical problems. The technical contradiction, born of the confrontation between thesis and antithesis, gives birth to new knowledge—synthesis.

In the book we will try to consider the technical contradictions of technological processes that lead to the creation of new, more promising methods for increasing oil recovery.

The book consists of 12 chapters and provides a comprehensive overview of enhanced oil recovery (EOR) methods. It begins with core concepts in reservoir engineering and fluid flow in porous media, followed by the classification of hydrocarbons, oil reserves, and recovery factors.

Chapters 4 through 8 cover major EOR techniques, including thermal, gas, chemical, and microbial methods. Chapter 9 discusses recent advances in EOR technologies.

Chapter 10 focuses on the practical steps of EOR implementation, while Chapter 11 addresses presents laboratory methods for evaluating the properties of oil-bearing rocks. The final chapter discusses the economic assessment of EOR projects.

Together, these chapters offer a balanced mix of theory, practical application, and current industry practices.

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Chapter 1Basic Concepts in Reservoir Engineering

1.1 Rocks and Their Types

A rock is a consolidated mixture of minerals. By “consolidated,” we mean hard and strong; real rocks don’t fall apart in your hands! A mixture of minerals implies the presence of more than one mineral grain, but not necessarily more than one type of mineral. For example, a rock can be composed of only one type of mineral, such as limestone, which is commonly made up of only calcite. However, most rocks are composed of several different minerals. Rocks can also include nonminerals, such as fossils or organic matter within a coal bed or in some types of mudstone.

A critical point to remember is the difference between a mineral and a rock. A mineral is a naturally occurring, inorganic solid with a specific chemical composition and a crystalline structure. Minerals are the building blocks of rocks and are defined by their unique physical and chemical properties. Examples of minerals include feldspar, quartz, mica, halite, calcite, and amphibole. These minerals vary in hardness, color, luster, and crystal form, and they are often used to identify and classify different types of rocks.

On the other hand, a rock is typically a mixture of several different minerals. For instance, granite is a common rock composed of quartz, feldspar, and mica. The proportions and types of minerals present in a rock determine its characteristics and classification. Rocks are categorized into three main types based on their formation processes: igneous, sedimentary, and metamorphic.

Igneous rocks

: These rocks form from the cooling and crystallization of magma, which is molten rock beneath the Earth’s surface. When magma cools slowly beneath the Earth’s crust, it forms intrusive igneous rocks such as granite, which have large, visible crystals. Conversely, when magma erupts onto the surface and cools quickly, it forms extrusive igneous rocks such as basalt, which have smaller crystals.

Sedimentary rocks

: These rocks are formed from the accumulation and lithification of sediment. The sediments produced by weathering and erosion are eventually deposited in various environments, such as rivers, lakes, deserts, and oceans. Over time, these sediments accumulate in layers and undergo lithification—a process of compaction and cementation—to form sedimentary rocks. Sediments can be fragments of other rocks, mineral grains, or biological materials. Sedimentary rocks are often layered and can contain fossils. Common types include sandstone, formed from compacted sand grains, and limestone, formed primarily from the remains of marine organisms. Sedimentary rocks provide valuable information about Earth’s history and past environments.

More than 70% of the area of all continents is covered with sedimentary rocks, and most of the mineral deposits are directly associated with them.

Depending on the forming processes, sedimentary rocks are divided into the following three groups:

clastic (crushed stone, sand, pebbles, gravel, clay);

chemical (various salts, silica); and

organogenic (limestones, fossil fuels).

Common sedimentary rocks include:

Sandstone: Formed from compacted sand grains.

Shale: Formed from compacted clay particles.

Limestone: Formed primarily from the remains of marine organisms.

Metamorphic Rocks

: These rocks form when preexisting igneous or sedimentary rocks are subjected to high temperatures, pressures, or chemically active fluids, causing them to undergo physical and chemical changes, leading to metamorphism. Metamorphic processes can result in the formation of new minerals and the reorganization of mineral grains into a more compact, crystalline structure. Examples of metamorphic rocks include schist, which has a foliated texture, and marble, which forms from limestone.

1.1.1 The Rock Cycle

The rock cycle is a fundamental concept in geology that describes the dynamic transformations of rocks within the Earth’s crust. The rock cycle is a continuous process, and rocks can be recycled through the cycle many times from one type to another through various geological processes (Figure 1.1). For example:

Igneous to Sedimentary: Igneous rocks exposed at the surface are weathered and eroded into sediments, which are then compacted and cemented to form sedimentary rocks.

Sedimentary to Metamorphic: Sedimentary rocks buried deep within the crust are subjected to heat and pressure, transforming them into metamorphic rocks.

Metamorphic to Magma: Metamorphic rocks can melt under extreme conditions to become magma, restarting the cycle.

Figure 1.1 Schematics of the rock cycle.

The rock cycle is a vital part of the Earth’s system. It helps to recycle the Earth’s materials, and it also plays a role in the formation of mineral deposits. The rock cycle is a complex process, but it is essential for understanding the Earth’s geology.

This cycle is driven by two primary forces:

Earth’s internal heat engine

: The immense heat from the Earth’s interior causes convection currents in the mantle, leading to the movement of tectonic plates. This movement drives processes, such as volcanic activity, mountain building, and the formation of igneous and metamorphic rocks. For example, when tectonic plates collide, they can push rocks deep into the Earth’s crust, where they are subjected to high temperatures and pressures, forming metamorphic rocks (

Figure 1.2

).

Figure 1.2 Internal structure of Earth (a) and main source of internal heat/energy (b).

The hydrological cycle

: Powered by solar energy, the hydrological cycle involves the continuous movement of water on, above, and below the surface of the Earth. This cycle includes processes, such as weathering, erosion, transportation, deposition, and precipitation (

Figure 1.3

). For instance, rainwater can cause the weathering of rocks, breaking them down into smaller particles that are transported by rivers and deposited as sediment in lakes or oceans, eventually forming sedimentary rocks.

Figure 1.3 Schematics of the hydrological cycle.

To understand the rock cycle, it’s convenient to start with magma, which is molten rock beneath the Earth’s surface. Magma has temperatures ranging from about 800 to 1,300°C, depending on its composition and the pressure. When magma cools and solidifies, it forms igneous rocks. The location where this cooling occurs determines the type of igneous rock formed:

Intrusive igneous rocks

: These form when magma cools slowly beneath the Earth’s surface, allowing large crystals to develop. Granite is a common example of intrusive igneous rock.

Extrusive igneous rocks

: These form when magma erupts onto the surface (as lava) and cools quickly, resulting in smaller crystals. Basalt is an example of extrusive igneous rock.

Weathering and erosion are critical processes in the rock cycle that break down rocks into smaller particles, which can then be transported and deposited to form sedimentary rocks. Types of weathering:

Physical (mechanical) weathering

: This type of weathering breaks rocks into smaller pieces without changing their chemical composition. It includes:

Frost wedging: Water seeps into cracks in rocks, freezes, and expands, causing the rock to break apart.

Thermal expansion: Repeated heating and cooling cause rocks to expand and contract, leading to fragmentation.

Biological activity: Plant roots grow into cracks in rocks, and animals burrow into the ground, contributing to the mechanical breakdown of rocks.

Chemical weathering

: This involves the chemical alteration of minerals within the rocks, leading to their breakdown. Key processes include:

Hydrolysis: Water reacts with minerals to form new minerals and soluble ions. For example, feldspar transforms into clay minerals.

Oxidation: Oxygen reacts with minerals, especially those containing iron, to form oxides. This process is responsible for the rusting of iron-rich rocks.

Dissolution: Soluble minerals, such as halite and calcite, dissolve in water, especially in acidic conditions.

Biological weathering

: This type of weathering involves the contribution of living organisms. For instance, lichen and moss can produce acids that chemically weather rocks, while tree roots and burrowing animals physically break down rock.

1.1.2 Erosion

Erosion involves the transportation of weathered materials by natural agents. The primary agents of erosion include:

Water: Rivers and streams carry sediments downstream, where they are deposited in floodplains, deltas, and oceans.

Wind: In arid regions, wind can transport fine particles over long distances, creating features like sand dunes.

Glaciers: Moving glaciers pick up and transport large quantities of rock debris, depositing them as glacial till when the ice melts.

Gravity: Gravity causes rocks and sediments to move downhill through processes like landslides and rockfalls.

Understanding the rock cycle is essential for geologists as it provides insights into Earth’s geological history, the formation and distribution of natural resources, and the processes that shape the planet’s surface. For example:

Natural resources: Many natural resources, such as minerals and fossil fuels, are found in specific rock types formed through the rock cycle. For instance, coal forms from buried plant material in sedimentary rock layers, while valuable minerals can be concentrated in igneous and metamorphic rocks.

Geological hazards: Knowledge of the rock cycle helps in predicting and mitigating geological hazards, such as volcanic eruptions, earthquakes, and landslides.

The rock cycle is not unique to Earth; it can also occur on other planetary bodies, although with significant differences. For instance:

The moon: The Moon lacks an atmosphere and liquid water, and its tectonic activity is minimal, resulting in a virtually inactive rock cycle.

Mars: Mars shows evidence of past volcanic activity and ancient river valleys, indicating a once-active rock cycle. However, its current rock cycle is much less active than Earth’s due to the absence of liquid water and significant tectonic activity.

Studying these differences helps scientists understand the unique geological histories of other planets and the factors that influence their evolution.

1.2 Forms of Occurrence of Sedimentary Rocks

Sedimentary rocks are composed mainly of almost parallel layers (strata), differing in physical and chemical properties (Figure 1.4).

Figure 1.4 Mode of rocks occurrence.

The surfaces separating the layers from each other are called the base if it is located below the layer in question and the roof if it is located on top. The line descending perpendicularly from the roof to the sole is called the thickness of the layer (or thickness of the layer); it is also the shortest distance between the roof and the base.

A layer composed of impermeable rocks is called a seal, and one formed from permeable rocks is called a reservoir. In nature, ideally, horizontal occurrence of layers is rarely found; as a rule, they have a wavy (folded) occurrence. This occurrence is due to the fact that the earth’s crust is not static, and various oscillatory, tectonic processes constantly occur in it.

The folds formed during these processes are called anticlines and synclines.

Anticline—an anticline is a convex bend in the Earth’s crust with a core in the center, with the core composed of older rocks and the outer layers composed of younger rocks.

Syncline—a syncline is the mirror opposite of an anticline, i.e., a concave curve in the Earth’s crust with ancient rocks in the outer part and young rocks in the central part. The structural elements of the anticline and syncline are shown in Figure 1.4.

Most of the oil and gas fields are confined to anticlines. Anticlines have an average length of up to 10 km and width up to 3 km. The largest oil field, Ghawar (Saudi Arabia), is located in an anticline 225 km long and 25 km wide.

1.3 Hydrocarbon Reservoirs

For a petroleum engineer, the property of rocks known as permeability is of particular interest, which will be discussed in detail below. For now, let’s dwell on the fact that, depending on the permeability of rocks, they are divided into reservoirs and seals. Seals are practically impermeable rocks that act as a dividing surface between reservoir layers.

Reservoirs are rocks that have the ability to contain and release fluids. Mostly reservoir rocks are of sedimentary origin.

The following types of reservoirs are distinguished by pore void structure:

Porous reservoirs

: They consist of voids formed by grain-like debris. For example: sands, sandstones, etc. This type has the best reservoir properties compared to others.

Cavernous reservoirs

: They are mainly associated with carbonate strata and are composed of voids (caverns) formed as a result of leaching or dissolution of salts that make up the rock.

Cracked reservoirs

: This type of reservoir is formed from impermeable rocks; however, numerous fractures of varying sizes allow them to accommodate hydrocarbons. For example, limestones.

Mixed reservoirs

: They are quite common and are a combination of the above types of reservoirs, with the first word in the name indicating the type of predominant rock. For example, cavernous—porous reservoir.

The best reservoir properties. Other types of collectors may also have good abilities to contain and release liquids and gases, as well as pass them through themselves.

It should be noted that there is also a classification of reservoirs by lithological composition:

terrigenous (silts, sands, etc.),

carbonate (dolomite, chalk),

siliceous rocks,

volcanogenic-sedimentary.

Hydrocarbon deposits are most often found in terrigenous and carbonate reservoirs.

1.4 Oil and Gas Traps

A trap is a part of a reservoir, the conditions of which provide for the accumulation of hydrocarbon reserves. A trap, in essence, is a permeable rock bounded by impermeable layers (seals) in which fluids are in static conditions and distributed according to the law of gravity. This distribution forms the classic structure of an oil field (Figure 1.5).

Figure 1.5 Oil field schematic.

The fluid interface is named according to the fluids bordering it:

GWC—gas-water contact,

WOC—water-oil contact,

GOC—gas-oil contact.

There are two main types of traps:

structural,

nonstructural.

Nonstructural traps, in turn, are divided into two types:

stratigraphic,

lithological.

1.4.1 Structural Traps

This type of trap, formed due to the migration of hydrocarbons into the fold of the anticline, is called Anticline (fold) traps (Figure 1.6). Hydrocarbon migration occurs either along the limbs of anticlines or along tectonic faults.

Figure 1.6 Anticline (fold) trap.

During tectonic movements of the earth’s crust, disturbances in the form of rock formations are often formed. If such a disturbance results in an overlap of the reservoir layer with an impermeable screen (seal), such a trap is called a fault trap (Figure 1.7).

Figure 1.7 Fault trap.

The types of structural traps described above generally have the greatest industrial significance in terms of the availability of potential hydrocarbon reserves.

1.4.2 Lithological Traps

This type of traps is formed due to the lithological dynamics of reservoir rocks, that is, the replacement of permeable rocks with impermeable. The reasons for this process are different, but among the most common of them are the following: pinchout, fracturing and changes in the permeability of reservoir rocks (Figure 1.8). Such traps are formed in the form of sand lenses in clayey deposits (Figure 1.8a) or in reef bodies (limestones) covered by poorly permeable rocks (Figure 1.8b).

Figure 1.8 (a) Pinch-out trap; (b) a trap confined to a reef massif.

1.4.3 Stratigraphic Traps

This type of trap is formed by the unconformable overlapping of reservoir rocks with fluid seals (poorly permeable layers). Sometimes a hydrodynamic seal created by formation waters (associated with high-pressure horizons) during filtration along tectonic disturbances can serve as a similar overlapping seal (Figure 1.9).

Figure 1.9 Stratigraphic traps.

Quite often, the formation of traps is influenced by several factors, and combined structural and lithological traps are formed.

1.5 Rock Porosity

Porosity is a critical property of reservoir rocks, defined as the ratio of the void space (pores) volume to the bulk volume of the rock, usually expressed as a percentage. This property is fundamental in determining the storage capacity of reservoir rocks for fluids, such as oil, gas, and water. Porosity indicates how much fluid a rock can hold and influences the movement of these fluids through the rock.

1.5.1 Primary and Secondary Porosity

Primary porosity develops during the initial deposition of the rock material. As sediment is deposited and buried, the spaces between the grains form the primary porosity. Over time, processes like compaction (where grains are pressed closer together under the weight of overlying materials) and cementation (where minerals precipitate from groundwater and fill the spaces between grains) reduce this primary porosity.

Secondary or induced porosity develops after the rock has formed. This type of porosity results from various geological processes, such as fracturing, dissolution, or recrystallization. For example, fractures in shales and limestones or solution cavities known as karsts are forms of secondary porosity. These secondary features can significantly enhance the ability of rocks to store and transmit fluids.

1.5.2 Effective and Total Porosity

From a reservoir engineering perspective, it is essential to distinguish between connected porosity and nonconnected pores (Figure 1.10). Effective porosity refers to the ratio of interconnected void spaces to the bulk volume of the rock, which is crucial for fluid flow within the reservoir. In contrast, total porosity is the sum of both connected and nonconnected porosities. Typically, in sandstones, the total porosity equals the effective porosity, as most pores are interconnected. However, in carbonates such as dolomites and limestones, nonconnected vuggy porosity may occur, where some pores do not contribute to fluid flow.

Figure 1.10 Connected/nonconnected pores.

1.5.3 Diagenesis and Its Impact

Diagenesis refers to the physical and chemical changes that occur in sediment after its deposition, transforming it into sedimentary rock. This process can significantly affect both porosity and permeability. Diagenesis includes various processes, such as mechanical compaction (which reduces pore space by pressing grains closer together), mineralogical changes (altering the mineral composition of the rock), cement precipitation (filling pores with new mineral growth), and mineral dissolution (enlarging pores by dissolving existing minerals) (Figure 1.11). These processes can either enhance or reduce the porosity and permeability of the rock.

Figure 1.11 Diagenesis.

The porosity of a rock can be influenced by the arrangement of its grains (Figure 1.12). For instance, in a cubic packing arrangement, where grains are arranged in a simple cubic pattern, the porosity can be calculated by considering a cube filled with eight spheres of radius . The volume of the cube is: while the total volume of the eight spheres is . The porosity for cubic packing, which is the least compact arrangement, is 47.6%.

Figure 1.12 (a) Cubic or wide packed; (b) rhombohedral or close-packed; (c) –4 by 4 pack.

Pores space volume is:

Porosity:

where , bulk volume and , volume of grains.

In contrast, rhombohedral packing represents the most compact arrangement of grains (Figure 1.12c). In this configuration, the spheres are packed as closely as possible, resulting in a lower porosity compared to cubic packing. The porosity of rhombohedral packing is significantly reduced (25.96%) due to the more efficient use of space.

1.5.4 Types of Porosity in Reservoir Rocks

Interparticle (intergranular) porosity

: Interparticle porosity, also known as intergranular porosity, is the predominant type found in sucrosic (sugar-like) rocks (

Figure 1.13

). In these rocks, pore sizes are typically of the same order of magnitude as, but usually less than, the particle sizes. For uniform spherical grains, interparticle porosity ranges from 47.6% in cubic stacking to 25.9% in close packing. However, in the field, these ideal figures are often reduced by variations in grain size and the presence of shale. Permeability in these rocks is influenced not only by porosity but also by sorting, stacking, and grain size. This can range from high permeability in large-grain sandstones (measured in darcies) to impervious conditions in chalks and siltstones.

Figure 1.13 Interparticle porosity.

Intraparticle porosity

: Intraparticle porosity is the network of pore spaces within individual grains (

Figure 1.14

). This type of porosity is often revealed by scanning electron microscope (SEM) images. Although intraparticle porosity can contain connate water (water trapped in the rock since its formation), it is usually nearly impervious to fluid flow due to the small size and isolated nature of these pores.

Figure 1.14 Intraparticle porosity.

Fracture porosity

: Fracture porosity is found in reservoirs that have been fractured, typically in carbonate rocks, such as limestones and dolomites (

Figure 1.15

). In these reservoirs, the rock is defined as a double porosity medium, consisting of both the matrix (the rock’s solid framework) and the fractures. Fractures can significantly enhance permeability by providing additional pathways for fluid flow. Fractured reservoirs are often encountered in crystalline and amorphous rocks, which lack grain size and therefore have minimal interparticle porosity.

Figure 1.15 Fracture porosity.

Vugs and molds

: Vugs and molds, though different in appearance and characteristics, are often classified together (

Figure 1.16

). Both are formed by the selective dissolution of sedimentary rock by percolating waters. Vugs can vary from the size of a fingernail to large caves and tend to be relatively well connected, allowing for better fluid flow. Molds are typically smaller, often resulting from the dissolution of oolites (small calcite spheres precipitated in seawater). These are known as oolmolds or oolicasts and can exhibit very high porosity, though their connectivity may be poor compared to vugs.

Figure 1.16 (a) Moldic; (b) vugs.

Depending on the diameter, pore channels are divided into three groups:

supercapillary (more than 0.5 mm), characterized by free filtration of fluids;

capillary (from 0.5 to 0.0002 mm ), filtration of fluids largely depends on capillary forces; and

subcapillary (less than 0.0002 mm ), filtration of fluids due to large capillary forces is practically impossible, regardless of the porosity value. The most typical examples of such rocks are clays and limestones.

1.6 Rock Permeability

The term “permeability” refers to a crucial property of porous rocks, specifically their ability to conduct fluids. This property plays a significant role in various fields, such as hydrogeology, petroleum engineering, and soil science. Permeability is a key factor in determining how easily fluids, such as water, oil, or gas, can move through subsurface rock formations.

When discussing permeability, it is important to distinguish between different types. If there is only one fluid present within the pore spaces of the rock, this property is termed specific or absolute permeability. Absolute permeability is a fundamental characteristic of the rock, unaffected by the type or properties of the fluid. However, in many practical scenarios, multiple immiscible fluids, such as oil and water, coexist within the pore spaces. In such cases, we refer to the effective permeability of each fluid, which varies depending on the presence and interaction of other fluids in the pores.