THE EFFECTS OF FOAM AND WATER ALTERNATING GAS INJECTION ON PERFORMANCE OF THIN OIL RIM RESERVOIRS

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