Recovery from thin oil rims are generally affected by the depletion strategies, reservoir
architecture, operational and reservoir uncertainties. Irrespective of the oil rim thickness,
size of the gas cap and aquifer, recoveries are generally low because of pressure depletion
rates. Oil recoveries during gas and water injections are also often low due to ineffective
study of uncertainties in reservoir parameters. Previous studies on Water Alternating Gas
(WAG) injection were based on less profitable depletion strategies and did not consider
reservoir architecture. Foam injection in oil rims have not been documented but its
effectiveness in controlling mobility of injected gas can increase oil recovery. A PlacketBurman (PB) design of experiment (DOE) was used to create oil rim models from extensive
parameters highlighted in literature. The architectural structure of synthetic reservoir
models were designed based on various dip angles, gas-cap and aquifer sizes, and oil-rim
thickness. The synthetic models were initialized with reservoir rock and fluid properties to
investigate the best depletion strategy for primary recovery using a reservoir simulator
(Eclipse 100). Concurrent development was considered in generating the response surface
model for gas and oil recoveries. Pareto chart was used to distinguish significant parameters.
Low oil recovery at an average of 10.53% from all the models necessitated water and gas
injection, then foam and WAG injection schemes. Based on 3 established parameters (dip,
aquifer and gas cap sizes), the models were subjected to various development strategies
using Water, Gas, Foam and Water Alternating gas injections. An incremental oil recovery
of 4.4% and 6.5% was recorded for Reservoir models 4 and 10 under water up dip and water
down dip injection respectively. Increasing injection rates led to an incremental recovery of
15.4% for model 10 under simultaneous water up dip and down dip injection. WAG up dip
injection at 2 cycles recorded an incremental oil recovery of 30.2% for reservoir model-4
while foam up dip injection recorded a 54.4% increase in oil recovery. A case study of oil
rim reservoir from the Niger Delta recorded an incremental recovery of 5.9 % after history
matching, 8.53% for WAG up dip injection, 7.94% for WAG down dip injection, 8.57% for
foam up dip injection and 8.56% for foam down dip injection. During injection, oil recovery
generally increased in the order of WAG down dip < WAG up dip < Foam down dip < Foam
up dip injection. It is recommended that oil rim reservoirs be properly delineated and
optimal location of injectors be ascertained before initiating fluid injection schemes.
TABLE OF CONTENTS
CONTENT Page COVER PAGE i TITLE PAGE ii ACCEPTANCE iii DECLARATION iv CERTIFICATION v DEDICATION vi ACKNOWLEDGEMENT vii TABLE OF CONTENTS ix LIST OF TABLES xiv LIST OF FIGURES xvi ABBREVIATIONS xix NOMENCLATURE xx ABSTRACT xxi
CHAPTER ONE: INTRODUCTION 1 1.0. Introduction 1 1.1. Primary Production History Of A Thin Oil Column Reservoir 4 1.2. Categories of Oil Rim Reservoirs. 5 1.3. Challenges Facing Effective Production 7 1.3.1. Technical Challenges 7 1.3.2. Business Challenges 7 1.4. Reservoir Simulation 8 1.5. Recovery Mechanism 9 1.5.1. Water Flooding 10 1.5.2. Gas Injection 10 1.5.3. Foam Injection 11 1.5.4. Water Alternating Gas (WAG) 13 1.6. Statement of Problem 13 1.7. Aim And Objectives 16 1.7.1. Aim 16 1.7.2. Objectives 16 1.8. Scope and Limitations 16
x 1.9. Research Expectations and Significance 17
CHAPTER TWO: LITERATURE REVIEW 18 2.0. Literature Review 18 2.1. Reservoir Drive Mechanism 18 2.2. Thin Oil Rim Reservoir Studies 20 2.3. Design Of Experiment 27 2.4. Pareto Chart 39 2.4.1. When to use Pareto chart 39 2.5. Thin Oil Rim Uncertainties 40 2.6. Secondary Injection And Enhanced Oil Recovery Schemes 41 2.6.1. Introduction 41 2.6.2. Water and Gas Injection 42 2.6.3. Water Alternating Gas 44 2.6.4. Foam Injection 48 2.7. Reservoir Simulation 50 2.8. Development Of Mathematical Model For Reservoir Simulation 52 2.8.1. Modelling Philosophy 53 2.8.2. Fluid Description 53 2.8.3. Reservoir Type 53 2.8.4. Model Scope 53 2.9. The Reservoir Tank Model 54 2.10. The Black Oil Numerical Model 56 2.11. Model Dimensionality 59 2.12. Differential Equations 59 2.12.1. One Dimensional (1D) Flow 59 2.12.2. Two Dimensional (2) Flow 63 2.12.3. Three Dimensional (3D) Flow 64 2.13. Auxiliary Equations 64 2.14. Boundary Equations 66 2.15. Initial Conditions 66 2.16. Spatial Discretization 68 2.17. Grid Systems 71 2.18. Time Discretization 73
xi 2.19. Basic Infinite Difference Equation 73 2.20. Rearranged Finite Difference Equation 74 2.21. Well Injection And Production Rates 76 2.22. Final Form Of Difference Equation 77 2.23. Description Of Solution Technique 77 2.23.1. Mobility Weighing 77 2.23.2. Complete Explicit Formulation 78 2.23.3. Explicit Solution for Single Phase Pressure 79 2.23.4. Implicit Solution for Single Phase Pressure 80 2.24. Flow Equations For Horizontal Wells 82 2.24.1. Borisov’s Method 82 2.24.2. Renard and Dupuy’s Method 83 2.24.3. Giger et al.’s Method 83 2.25. Eclipse Black Oil Simulator Overview 83 2.25.1. GridSim 84 2.25.2. PVTi 85 2.25.3. Scal 85 2.25.4. Schedule 86 2.25.5. Eclipse Office 86 2.25.6. Case Manager 87 2.25.7. Data Manager 87 2.25.8. Run Manager 87 2.25.9. Result Viewer 87 2.25.10. Report Generator 87
CHAPTER THREE: METHODOLOGY 88 3.0. INTRODUCTION 88 3.1. Niger Delta Case Study 89 3.2. AR 2 Reservoir Simulation 92 3.2.1. Geology 92 3.2.2. AR2 Well Performance Review 92 3.3. AR 2 Study Work Flow 93
xii 3.4. AR2 Reservoir Fluid Modelling 95 3.4.1. AR2 Model Grid Description 95 3.4.2. AR2 Formation Core Analysis 96 3.4.3. Aquifer Modeling 98 3.4.4. PVT Modeling 98 3.4.5. Reservoir Initialization 98 3.5. Observed Production Data And Well Events Schedule 98 3.6. Simulation Run 99 3.7. History Matching 99 3.8. AR2 Material Balance Analysis 100 3.9. Synthetic Reservoirs 104 3.9.1. Simulation Grid Design 104 3.9.2. Steps to Grid Model Design 106 3.10. Fluid (PVT) Modelling 109 3.11. Oil Rim Property Uncertainty Analysis 111 3.12. Design Of Experiment And Response Surface Model 113 3.13. Development Strategies For Thin Oil Rim Reservoirs 117 3.13.1. Gas Cap Blow Down 117 3.13.2. Sequential Production 117 3.13.3. Concurrent Development 118 3.13.4. Swing Production 118 3.14. Initial Conditions 122 3.15. Response Surface Model (RSM) And Pareto Analysis 124 3.16. Oil Rim Optimization 136 3.16.1. Secondary Injection 138 3.16.2. Enhanced Oil Recovery 138 3.16.2.1. Water Alternating Gas (WAG) 138 3.16.2.2. Foam Injection 139 3.16.2.2.1. Foam Model Activation 139 3.16.2.2.2. Foam Adsorption 139 3.16.2.2.3. Foam Decay 140 3.16.2.2.4. Gas Mobility Reduction 140
xiii 3.17. Enhanced Oil Recovery Scheme 144 3.17.1. Prediction 144
4.0. CHAPTER FOUR: RESULTS AND DISCUSSION 147 4.1. Secondary Injection Schemes 147 4.1.1. Oil Recovery from Up Dip Injections (Case 1) 147 4.1.2. Oil Recovery from Down Dip Injections (Case 2) 151 4.1.3. Oil Recovery from Gas Up Dip/ Down Dip and Water Up Dip/ Down 155 Dip Injections (Case 3) 4.1.4. Oil Recovery from Gas Up Dip And Water Down Dip Injection, Gas 159 Down Dip and Water Up Dip Injection (Case 4) 4.1.5. Oil Recovery from Gas Up Dip And Water Down Dip Injection, Gas down dip and Water Up Dip Injection (Improved Injection Rates) Case 5 163 4.2. Enhanced Oil Recovery Scheme 167 4.2.1. Oil Recovery from Water Alternating Gas (Cycle 1) 167 4.2.1. Oil Recovery from WAG Injection (Cycle 2). 171 4.2.2. Oil Recovery from WAG Injection (Cycle 3) 175 4.2.3. Foam Injection 184 4.3. Analysis of Enhanced Oil Recovery Scheme For AR2 Reservoir 189 4.3.1. Producer Wells (With no injection) 189 4.3.2. Oil Recovery from Down Dip WAG Injection 192 4.3.3. Oil Recovery from WAG Up Dip Injection 194 4.3.4. Oil Recovery from Foam Up Dip Injection 196 4.3.5. Oil Recovery from Foam Down Dip Injection 198 5.0.
CHAPTER FIVE: CONCLUSION AND RECOMMENDATION 202 5.1 CONCLUSIONS 202 5.2 RECOMMENDATIONS. 203 5.3 CONTRIBUTIONS TO KNOWLEDGE 204 REFERENCES 206 APPENDIX 213 CONFERENCES AND PUBLICATIONS 218
Olabode, O. & oluwasanmi, O (2019). THE EFFECTS OF FOAM AND WATER ALTERNATING GAS INJECTION ON PERFORMANCE OF THIN OIL RIM RESERVOIRS. Afribary. Retrieved from https://afribary.com/works/final-olabode-oluwasanmi-project
Olabode, Oluwasanmi, and Olabode Oluwasanmi "THE EFFECTS OF FOAM AND WATER ALTERNATING GAS INJECTION ON PERFORMANCE OF THIN OIL RIM RESERVOIRS" Afribary. Afribary, 15 Oct. 2019, https://afribary.com/works/final-olabode-oluwasanmi-project. Accessed 05 Nov. 2024.
Olabode, Oluwasanmi, and Olabode Oluwasanmi . "THE EFFECTS OF FOAM AND WATER ALTERNATING GAS INJECTION ON PERFORMANCE OF THIN OIL RIM RESERVOIRS". Afribary, Afribary, 15 Oct. 2019. Web. 05 Nov. 2024. < https://afribary.com/works/final-olabode-oluwasanmi-project >.
Olabode, Oluwasanmi and Oluwasanmi, Olabode . "THE EFFECTS OF FOAM AND WATER ALTERNATING GAS INJECTION ON PERFORMANCE OF THIN OIL RIM RESERVOIRS" Afribary (2019). Accessed November 05, 2024. https://afribary.com/works/final-olabode-oluwasanmi-project