PAB4034 FIELD DEVELOPMENT PROJECT (FDP) GELAMA …

i

PAB4034 FIELD DEVELOPMENT PROJECT (FDP)

GELAMA MERAH , OFFSHORE SABAH

PREPARED BY: GROUP 6

Arthur Goh Jin Wang 8890

Abd Hafriz Bin Abd Wahid 8967

Mahamad Alfouti Ben Ali 7205

Ahmad Aqbal Bin Azman Shah 9495

Siti Sarah Salehuddin 9223

Siti Nur Mahirah Mohd Zain 9212

Mohd Zahidi Amin Bin Hamzah 9480

Hazwan Bin Jasman 9243

Final Report submitted in partial fulfilment of

the requirements for the

Bachelor of Engineering (Hons)

Petroleum Engineering

JULY 2010

Universiti Teknologi PETRONAS

Bandar Seri Iskandar

31750 Tronoh

Perak Darul Ridzuan

i

CERTIFICATION OF APPROVAL

GELAMA MERAH , OFFSHORE SABAH

PREPARED BY: GROUP 6

Arthur Goh Jin Wang 8890

Abd Hafriz Bin Abd Wahid 8967

Mahamad Alfouti Ben Ali 7205

Ahmad Aqbal Bin Azman Shah 9495

Siti Sarah Salehuddin 9223

Siti Nur Mahirah Mohd Zain 9212

Mohd Zahidi Amin Bin Hamzah 9480

Hazwan Bin Jasman 9243

A project dissertation submitted to the

Universiti Teknologi PETRONAS

in partial fulfilment of the requirement for the

Bachelor of Engineering (Hons)

Petroleum Engineering

Approved by,

UNIVERSITI TEKNOLOGI PETRONAS

TRONOH, PERAK

JULY 2010

_____________________

(AP DR ZUHAR ZAHIR)

FDP Supervisor

_____________________

(SALEEM TUNIO)

FDP Supervisor

_____________________

(ELIAS ABLLAH)

FDP Supervisor

ii

CERTIFICATION OF ORIGINALITY

This is to certify that we are responsible for the work submitted in this project, that

the original work is our own except as specified in the references and

acknowledgements, and that the original work contained herein have not been

undertaken or done by unspecified sources or persons.

_______________________________

ARTHUR GOH JIN WANG

_______________________________

ABD HAFRIZ BIN ABD WAHID

_______________________________

MAHAMAD ALFOUTI BEN ALI

________________________________

AHMAD AQBAL BIN AZMAN SHAH

________________________________

SITI SARAH SALEHUDDIN

_________________________________

SITI NUR MAHIRAH MOHD ZAIN

_________________________________

MOHD ZAHIDI AMIN BIN HAMZAH

__________________________________

HAZWAN BIN JASMAN

iii

EXECUTIVE SUMMARY

Gelama Merah field is located in Offshore Sabah Basin at approximately 43km from

Labuan and 130km from Kota Kinabalu, Malaysia owned by PETRONAS. The objective of

the Gelama Merah FDP project is to carry out a technical and economics study of the

proposed development utilizing the latest technology available. This FDP group namely

PETROBEN intended to provide a comprehensive description development plan includes

geological interpretation, petrophysics, geological and reservoir modeling, facilities

engineering design, drilling program, well completion and project economics for the Gelama

Merah field. Gelama Merah field is divided to 9 layers which are U3.2, U4.0, U5.0, U6.0,

U7.0, U8.0, U9.0, U9.1 and U9.2 respectively. The main lithologhy identified are dominant

claystone interbedded with minor sand stone. From the results of MBAL simulation, it is

identified that Gelama Merah has dominant gas cap expansion drive mechanism while the

aquifer support is found to be weak. The total oil in place (STOIIP) from the top U3.2 to

U9.3 is 76.83MMStb, while the gas in place (GIIP) has the amount of 67.76MMMScf. Based

on the static reservoir model, it is found that only 3 zones (U9.0, U9.1 and U9.2) which have

contained the possible amount of oil to be recovered (40.41MMbbl). After various plans of

optimizations, it was decided that 5 production wells and 1 water injection well are needed to

recover the amount of 19.5MMbbl of oil with 47.8% recovery factor recorded with 20 years

of production. Based on the required facilities and environmental condition, a long term and

fixed on site platform which is jacket platform is preferably to be installed at Gelama Merah

field. It is decided to tie in the platform to Samarang-B CPP to process the crude oil as it

reduces the cost for processing on GMJT-A itself and reduces the cost for leasing a FPSO

vessel for the whole 20 years cycle. The total cost of Capital Expenditure (CAPEX) is about

88.492 Mil USD while the cost for Operating Expenditure (OPEX) is estimated about 5.135

Mil USD/year. The calculated Net Present Value (NPV) at 10% is 62.9 MM USD. With IRR

at 36%, the breakeven is estimated in 3.52 years.

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ACKNOWLEDGEMENT

First of all, we would like to convey our greatest praise and gratitude to Allah

the Almighty for His Mercy for giving us the strength and capability to complete this

report of Field Development Project throughout this final semester. Special thanks to

our FDP supervisor firstly, AP Dr Zuhar, Mr Saleem Tuinio and Mr Elias Abllah and

FDP Coordinator Pn Mazlin Idress, from Universiti Teknologi PETRONAS (UTP)

for the constant guidance towards the completion of this report.

We also would like to take this opportunity to thank all parties involved for

the respective professionalism and contribution to the project particularly to En

Adzlan Mohaideen, Drilling Engineer and Mohd Zafuan Che Zulkifli, Facilities

Engineer from PETRONAS Carigali, KLCC for their contribution and also to our

friends and colleagues for their continuous support. Not to forget also to Mr Armi

Faizal, Field Engineer from PCSB Sabah Operation, for his information on the Sabah

Offshore operation. Greatest gratitude also to Haji Aminuddin B Mohd Yussoff,

Former Drilling & Completion Supervisor, PCSB for a thorough guide into drilling

plans during his teaching course in UTP.

Besides that, we would like to express the deepest appreciation to Ms. Nor

Baizurah Bt Ahmad Tajuddin and Mr. Azmir Bakhtiar Bin Bahari, Reservoir

Engineers in PETRONAS CarigaliSd. Bhd. whose encouragement, guidance and

support from the initial to the final stage of Reservoir Engineering phase in this

project has enabled to develop a good understanding in solving problems encountered

in reservoir simulation studies.

Thank you once again from PETROBEN and without their guidance and persistent

help, this project would not have been possible.

v

TABLE OF CONTENTS

CERTIFICATION OF APPROVAL …………………………………………… i

CERTIFICATION OF ORIGINALITY ……………………………………….. ii

EXECUTIVE SUMMARY …………………………………………………….. iii

ACKNOWLEDGEMENT ……………………………………………………… iv

LIST OF FIGURES …………………………………………………………….. xi

LIST OF TABLES ……………………………………………………………… xiv

LIST OF APPENDICES ………………………………………………………... xvii

PHASE 1 OVERVIEW …………………………………………………….. 1

1.1 Introduction ....................................................................................... 1

1.2 Problem Statement ………………………………………………… 1

1.3 Objectives …………………………………………………………. 2

1.4 Methodology ………………………………………………………. 2

1.4.1 Modeling Softwares

1.4.2 Flow Diagram 1 : Geology and Petrophysics

1.4.3 Flow Diagram 2 : Reservoir Engineering

1.4.4. Flow Diagram 3 : Production Technology

1.4.5 Flow Diagram 4 : Drilling & Completion Plan

1.5 Project Team ……………………………………………………… 7

PHASE 2 GEOLOGY……………………………………………………….. 8

2.1 2-Dimensional Cross Imaging ……………………………………… 8

2.2 Stratigraphy and Reservoir Geology …………………..................... 11

2.3 Regional Setting …………………………………………………… 12

2.4 Exploration Opportunities …………………………………………. 13

2.5 Petroleum System ………………………………………………….. 14

2.6 Depositional Environment …………………………….................... 14

2.7 3-Dimensional Static Model ………………………………………. 15

2.7.1 General Description (PETREL)

2.7.2 Model Parameters

2.7.3 Top Structure Development

2.7.4 Creating New Wells

2.7.5 Stratigraphic Modeling

2.7.6 Structural Modeling

2.7.7 Properties Modeling

2.8 Hydrocarbon Volumetric Assessment (PETREL) ………………… 21

2.9 Risk Analysis and Uncertainties…… ……………………………… 23

vi

PHASE 3 PETROPHYSICS EVALUATION …………………………….. 24

3.1 Formation’s Lithologic Evaluation ………………………………… 24

3.1.1 Well Gelama Merah-1

3.1.2 Well Gelama Merah-ST1

3.1.3 Lithology Cross Plot Identifications

3.2 Fluid Types Identification…………………………………………. 29

3.3 Properties Calculation …………………………………………….. 30

3.3.1 Objectives

3.3.2 Petrophysical Evaluation Methodology

3.3.3 Porosity Calculation

3.3.4 Water Saturation Calculation

3.3.5 Water Saturation of Flushed Zone

3.3.6 Hydrocarbon Moveability Index

3.3.7 Calculation of Bulk Volume Water

3.3.8 Averaging Method

3.3.9 Average Porosity

3.3.10 Average Water Saturation

3.3.11 Concept of Cutoffs

3.4 Volumetric Calculations ………………………………………….. 38

3.4.1 Volumetric Estimation Approach

3.4.2 Deterministic STOIIP & GIIP by Properties

3.4.3 Deterministic STOIIP & GIIP by IP Software

3.4.4 Comparison of Volumetric Calculations

3.5 Discussions & Recommendations……….…………….................... 43

3.5.1 Discussions

3.5.2 Recommendations

PHASE 4 RESERVOIR ENGINEERING …….…………………………... 47

4.1 Introduction……………………….................................................... 47

4.2 Reservoir Characteristics…………………………………………… 48

4.3 Reservoir Data……………………………………………………….. 49

4.3.1 Porosity Permeability Relationship

4.3.2 Vertical and Horizontal Permeability Transform

4.3.3 Relative Permeability

4.3.4 Oil Water System

4.3.5 Gas Oil System

4.3.6 Denormalization of Oil Water System

4.3.7 Denormalization of Gas Oil System

4.3.8 Leverett J function and the Capillary Pressure

4.4 Well Test Data……………………………………………………… 59

4.4.1 Production tests

4.4.2 Pressure Transient Analysis

4.5 Reservoir Fluid Study (PVT Analysis)..……………………………. 61

4.5.1 Preliminary Quality Check (QC) Test

4.5.2 Compositional Analysis

vii

4.5.3 Constant Compositional Expansion

4.5.4 Differential Vaporization (DV) Test

4.5.5 Viscosity Test

4.5.6 Separator Test

4.6 Reserves Estimation……….………………………………………… 75

4.7 Material Balance ……………………………………………………. 75

4.7.1 Energy Plot

4.7.2 Recovery Factor

4.7.3 Production Profile Forecast

4.8 Reservoir Simulation Study ………………………………………… 78

4.8.1 Objective of Simulation Study

4.8.2 Reservoir Model Set Up

4.6.3 Well Placement

4.6.4 Base Case Model

4.6.5 Reservoir Development Strategies Option

4.9 Sensitivity Analysis ………………………………………………… 91

4.10 Production Profile ………………………………………………... 95

4.11 EOR Consideration ………………………………………………… 97

PHASE 5 PRODUCTION TECHNOLOGIST ……………………………101

5.1 Introduction ……………………………………..………………….. 101

5.2 Sand Control Strategies …………………………………………….. 101

5.2.1 Sand Condition Analysis

5.2.2 Bottomhole Completion Options

5.2.3 Sand Control Methods

5.2.4 Types of Slotted Liner Patterns

5.2.5 Sand Control Design Selections

5.3 Production Optimization …………………………………………… 108

5.3.1 Inflow Performance Prediction

5.3.2 Optimum tubing size selection

5.3.3 Gas Lift Justifications

5.3.4 Gas Lift Design

5.3.5 Tubing Performance with Increasing WC

5.3.6 Tubing Performance with Increasing GOR


5.3.8 Material Selection

5.4 Well Profile ……………………………………….……………….. 117

5.4.1 Orientation of Producing Wells

5.4.2 Horizontal Well Radius Profile

5.4.3 Wellbore Diagrams

5.5 Potential Production Chemistry Problem………..…………………. 119

5.5.1 Scale Formation

5.5.2 Wax Deposition

5.5.3 CO2 Content and Sweet Corrosion

5.5.4 H2S Content and Sour Corrosion

viii

5.5.5 Emulsion Formation

PHASE 6 DRILLING & COMPLETION IMPLEMENTATION……… 121

6.1 Drilling Development…..…………………………………………… 121

6.1.1 Platform Location

6.1.2 Rig Selection

6.1.3 Well Types

6.1.4 Well Trajectory using SES

6.2 Pressure Management………………………………………………. 125

6.3 Drilling Fluid Design ………………………………………………. 127

6.4 Casing Plans ………………………………………........................ 128

6.5 Cementing Plan …………………………………………………….. 131

6.6 Well Control ……………………………………………………….. 133

6.6.1 BOP Specification

6.6.2 Actuator / SSV

6.6.3 Wellhead/Casing Spool

6.7 Hydraulic Optimization ………………………………………… 134

6.8 Drilling Optimization ……………………………………………….. 136

6.8.1 Rotary Steerable System (RSS)

6.8.2 Cement Assessment Tool (CAT)

6.8.3 Directional Casing While Drilling (DCwD)

6.9 Potential Drilling Problems ………………………….................... 137

6.10 Bit Selection ……………………………………………………….. 138

6.11 Well Completion …………………………………………………… 139

6.11.1 Swell Technology™ Packer

6.11.2 Expandable Sand Screen (ESS) Control

6.11.3 Subsurface Safety (SCSSV) System

6.11.4 Tubing Installation

6.11.5 Sliding Side Door (SSD)

6.11.6 X-mas Tree Selection

6.11.7 Completion and Packer Fluid

6.11.8 Completion Design

6.12 Drilling Cost and Schedule Estimation …………………………….. 143

PHASE 7 FACILITIES ENGINEERING ……………………………….. 145

7.1 Introduction ………………………………………………………….. 145

7.3.1 Summary of completion

7.3.2 Types of development platform

7.2 Design Features & Basis ……………………………………………. 146

7.2.1 Design Concept

7.2.2 Substructure

7.2.3 Top structure

7.3 Operation Facilities Selection ……………………………………….. 148

ix

7.3.1 Production Flowline, Flow Control & Manifold

7.3.2 Wellhead

7.3.3 Gas Metering and Measurement

7.3.4 3-Phase Separator

7.3.5 Water Injection

7.3.6 Gas Handling

7.3.7 Gas Lift System

7.3.8 Electrical Power and Lighting

7.3.9 Drain System

7.3.10 Flare Boom/Vent System

7.3.11 Instrument Air System

7.4 Safety Facilities System …………………………………………… 151

7.4.1 Safety Shutdown System

7.4.2 Automatic Fire Detection and Alarm Systems

7.4.3 Live Saving Appliances

7.5 Production Pipeline ………………………………………………… 153

7.5.1 Pipeline Tie-ins

7.5.2 Optimum Pipeline Size using PIPESIM™

7.5.3 Wax Mitigation

7.5.4 Slug Surpression System (SSS)

7.6 Pipeline Corrosion Management …………………………………… 160

7.6.1 Corrosion Inhibitor Injection

7.6.2 Corrosion Allowance

7.6.3 Pigging

7.6.4 Corrosion Monitoring

7.7 Abandonment ………………………………………………………. 161

7.8 Facilities CAPEX, OPEX & Decommissioning Cost …………….. 162

7.8.1 Capital Expenditure (CAPEX)

7.8.2 Decommissioning Cost

7.8.3 Operational Cost (OPEX)

PHASE 8 ECONOMIC ANALYSIS………………………………….......... 165

8.1 Introduction ………………………………………………………… 165

8.2 Development Expenditures ………………………………………… 166

8.3 PSC Arrangment / Fiscal Terms…………………………………… 167

8.4 Evaluation Basis and Assumptions ………………………………. 168

8.5 Development Scenarios………………………………................. 170

8.5.1 1st Screening : Well Types

8.5.2 2nd

Screening : Pressure Maintenance Scheme

8.5.3 3rd

Screening : Injection Time

8.5.4 4th

Screening : Injection Rate

8.5.5 5th Screening : Production Control Mode

8.5.6 6th Screening : Production Life

8.6 Economic Results ………………………………………………… 172

8.6.1 1st Screening Results

8.6.2 2nd

Screening Results

x

8.6.3 3rd

Screening Results

8.6.4 4th Screening Results



8.7 Revenue Split ……………………………………………………… 175

8.8 Sensitivity Analysis ……………………………………………….. 176

8.8.1 Spider Plot

8.8.2 Tornado Chart

8.8.3 Delay/Acceleration of Production

8.9 Recommendations…………………………………………………. 179

PHASE 9 HSE & SUSTAINABLE DEVELOPMENT …………………… 180

9.1 General Health, Safety & Enviroment (HSE) ……………………… 180

9.2 HSE Management System (HSEMS) ……………………………… 180

9.3 Safety and Risk Management ……………………………………… 181

9.4 HSE Delineation of Responsibility ………………………………… 182

9.5 Quality Management ………………………………………………. 184

9.6 Occupational Health Management ………………………………… 185

9.7 Environmental Management ………………………………………. 185

9.7.1 Environmental Waste Management

9.7.2 Environmental Impact Assessment (EIA)

9.8 Sustainable Development …………………………………………. 187

9.8.1 Reservoir Management

9.8.2 Production Technology

9.8.3 Drilling & Completion Implementation Plan

9.8.4 Facilities Engineering & Operations

9.8.5 Abandonment Options

9.9 Quality Assurance ………………………………………………… 189

APPENDICES ………………………………………………………………….... 190

xi

LIST OF FIGURES

PHASE 1 : INTRODUCTION

Figure 1.1 PETROBEN (Group 6) Organization Chart 7

PHASE 2 : GEOLOGY

Figure 2.1: Surface map for Unit 3.2 8

Figure 2.2: Spreadsheet horizontal cross section for Gelama Merah 10

Figure 2.3: Top Structure for Unit 3.2 16

Figure 2.4: Well top correlations using Gamma Ray for GM-1 and GM-ST1 18

Figure 2.5: Cross sectional view of exploration well on 10 stacked structures 20

Figure 2.6: Correlating the layers with the facies from log 20

PHASE 3 : PETROPHYSICS

Figure 3.1: Pressure Plot for Gelama Merah Field 29

Figure 3.2: Area vs Height for U3.2 to U.9.2 38

PHASE 4 : RESERVOIR ENGINEERING

Figure 4.1 : Porosity Permeability Transforms 50

Figure 4.2 : Normalized Oil Water Relative Permeability 52

Figure 4.3 : Normalized Gas Oil Relative Permeability 53

Figure 4.4 : Swc And Porosity For Water Oil System 54

Figure 4.5 : Porosity And Krw Relationship For Oil Water System 55

Figure 4.6 : Porosity And Sor Relationship For Oil Water System 55

Figure 4.7 : Permeability And Sgr Relationship For Gas Oil System 56

Figure 4.8 : Permeability And Srg Relationship For Gas Oil System 57

Figure 4.9 : Leverett J Function 58

Figure 4.10 : GM-1 DST-1 well test interpretation 60

Figure 4.11: Relative volume at Deg F 65

Figure 4.12 : GM-1 Solution GOR at 155 Deg F 67

Figure 4.13 : GM-1 Oil FVF at 155 Deg F 68

Figure 4.14 : Oil Viscosity at 155 Deg F 69

xii

Figure 4.15 : Energy Plot 75

Figure 4.16 : Oil recovery Factor vs. time plot 76

Figure 4.17 : Oil rate (STB/ day) vs. time plot 77

Figure 4.18 : GLM Base Case model 80

Figure 4.19 : Development zone of GLM Base Case 81

Figure 4.20 : Average Oil Saturation (Res. 9.2) 82

Figure 4.21 : Average RQI (Res. 9.2) 83

Figure 4.22 : Average So*RQI (Res. 9.2) 83

Figure 4.23 : Individual Well Locations 84

Figure 4.24 : Cumulative Oil Production for Individual Well 84

Figure 4.25 : Creaming Curve 85

Figure 4.26 : Optimum Well Location for Reservoir 9.0 86



Figure 4.29: Base Case Result for 9.0 88

Figure 4.30 : Base Case Result for 9.1 88

Figure 4.31 : Base Case Result for 9.2 89

Figure 4.32 : Summary of the sensitivity analysis flow work to determine the best

development strategy 93

Figure 4.33 : Sensitivity Analyses 94

Figure 4.34 : Daily oil production rate for selected development strategy for GM-1 field 95

Figure 4.35 : Total cumulative oil production for selected development strategy for GM-1

field 95

PHASE 5 – PRODUCTION TECHNOLOGIST

Figure 5.1: Depth vs Sonic Transit Time for GM-1 102

Figure 5.2: Inflow Performance of test data points 108

Figure 5.3: Plot of Water Cut vs Production Rate for GMJT-01A 115

Figure 5.4: Plot of GOR vs Production Rate for GMJT-01A 115

Figure 5.5 Well Schematic for Well 01A-05C for GM using SES 118

PHASE 6 – DRILLING AND COMPLETION

Figure 6.1: Well profile for GMJT-01A 123

xiii

Figure 6.2: Well profile for GMJT-05C 124

Figure 6.3: Well Locations in Gelama Merah from horizontal plane 124

Figure 6.4: Pressure Profiles vs Depth for Gelama Merah 126

Figure 6.5: Casing setting depth selection method 128

Figure 6.6: CAT elastomer in long term zonal isolation 136

Figure 6.7: Swellable packer in horizontal wells 139

Figure 6.8: Gelama Merah Drilling and Completion Time vs Cost 144

PHASE 7 – FACILITIES ENGINEERING

Figure 7.1: Tie-in from GMJT-A to SMP-B diagram 153

PHASE 8 – ECONOMIC ANALYSIS

Figure 8.1: Revenue flow diagram for PSC between project, contractor & state 168

Figure 8.2: Spider Plot for NPV at 10% base case project 176

Figure 8.3: Tornado chart analysis for base case 177

PHASE 9 – HSE & SUSTAINABLE DEVELOPMENT

Figure 9.1: HSEMS Approach Sequence 180

Figure 9.2: HSE Risk Management Process 181

xiv

LIST OF TABLES

PHASE 1 : INTRODUCTION

Table 1.1: Modeling Softwares used for FDP 2

PHASE 2 : GEOLOGY

Table 2.1: List of horizon name, horizon type and input for making zones 19

Table 2.2: Types of horizontal truncations 19

Table 2.3: Distribution of gross volume and STOIIP/GIIP on zones 22

PHASE 3 : PETROPHYSICS

Table 3.1 : Lithology Identification comparison 28

Table 3.2: Comparison of WOC & GOC contact depths 29

Table 3.3: Properties Calculation for GM-1 for various reservoir zones 36

Table 3.4: Properties Calculation for GM-ST1 for various reservoir zones 37

Table 3.5: STOIIP and GIIP Estimation using manual log properties reading 39

Table 3.6: STOIIP and GIIP Estimation using Intellectual Petrophysics (IP) Software 40

Table 3.7 : Comparison of STOIIP for Petrel/Log Analysis/ IP 41

Table 3.8 : STOIIP and GIIP Estimated Values from Deterministic Approach 41

Table 3.9 Percentage distribution of STOIIP and GIIP by zones 46

PHASE 4 : RESERVOIR

Table 4.1: Reservoir Descriptions 48

Table 4.2 : Summary of well test results 59

Table 4.3 : Summary of Well Test Analysis on GM-1 DST-1 61

Table 4.4: Quality Check of GM-1 Separator Samples 62

Table 4.5: Compositional Analysis of GM-1 Separator Oil and Gas Samples and Calculated

Wellstream Composition 63

Table 4.6: Compositional Analysis of GM-1 Stock Tank Oil and Gas and Calculated

Wellstream Composition 64

Table 4.7: GM-1 Constant Composition Expansion (CCE) Test at 155°F 65

Table 4.8: GM-1 Differential Vaporisation (DV) Test at 155°F 66

Table 4.9: GM-1 Oil and Gas Viscosity at 155°F 68

Table 4.10: GM-1 Single-Stage Separator Flash Analysis Case 1 69

Table 4.11: Composition of the Liberated Gases Collected from GM-1 Single-Stage 70

Table 4.12: Comp of Residual Oil from GM-1 Single-Stage Separator Flash Test Case 70


xv

Table 4.14: Composition of the Liberated Gases Collected from GM-1 Single-Stage

Separator Flash Test Case 2 71

Table 4.15: Comp of Residual Oil from GM-1 Single-Stage Separator Flash Test Case 2 72


Table 4.17: Composition of the Liberated Gases Collected from GM-1 Single-Stage

Separator Flash Test Case 3 73

Table 4.18: Comp of Residual Oil from GM-1 Single-Stage Separator Flash Test Case 3 73

Table 4.19: GM-1 Reservoir Fluid Study Results Summary 74

Table 4.20: UR and Drive mechanism from MBal software 78

Table 4.21 : Optimization of Number of Wells per Reservoir 85

Table 4.22: Input Data for Base Case Model 87

Table 4.23 : Base Case Simulation Results 89

Table 4.24: Production profile for Gelama Merah 95

Table 4.25: Reservoir and Fluid properties for Gelama Merah. 97

Table 4.26: Technical Screening Guides for Immiscible Gas flooding 100

Table 4.27: Technical Screening Guides for Water Flooding 100

Table 4.28: Technical Screening Guides for Water Alternating Gas (WAG) 100

PHASE 5 : PRODUCTION TECHNOLOGIST

Table 5.1: Completion strings summary for Gelama Merah 101

Table 5.2: Comparison between Slotted Liner, WWS and Gravel Pack 104

Table 5.3 Production Data with various tubing sizes for base case from GM-1 109

Table 5.4: Gas lift valves optimum setting depths for 5 wells 112

Table 5.5: Oil production rate with increasing water cut 113

Table 5.6: Oil production rate with increasing GOR 114

PHASE 6: DRILLING & COMPLETION IMPLEMENTATION PLAN

Table 6.1: Depth and daily rates for offshore drilling rigs (taken on 27/09/10) 121

Table 6.2: Well Survey and Logging Tools 122

Table 6.3: Gelama Merah drilling profiles 123

Table 6.4: Pressure data against depth for GM 125

Table 6.5: Mud design additives for each casing design 127

Table 6.6: Mud weight and properties for depth 553-1587m 127

Table 6.7: Casing Setting Depth in MD for individual wells 129

Table 6.8: Details of casing design 129

Table 6.9: Design factor for casing stress check 130

xvi

Table 6.10: Casing specification and load (casing stress check) based on API grade 130

Table 6.11: Proposed cement design 131

Table 6.12: Consideration for hydraulic planning 133

Table 6.13: Factors affecting the hydraulics 133

Table 6.14: BOP Operating Pressure 134

Table 6.15: UH-1 Wellhead Configurations 135

Table 6.16: Comparison between unihead and conventional wellhead 135

Table 6.17: Completion Summary for Gelama Merah 142

Table 6.18: Cost Summary for Gelama Merah (Source: FDP Sumandak Main) 143

PHASE 7 – FACILITIES ENGINEERING

Table 7.1: Production forecast for Gelama Merah 146

Table 7.2: Reservoir fluid properties for Gelama Merah 147

Table 7.3: CAPEX for jacket facilities for Gelama Merah 162

Table 7.4: Comparison of Cost for different tie-in options 163

Table 7.5: Operating Cost for Gelama Merah platform 164

PHASE 8 – ECONOMIC ANALYSIS

Table 8.1: Summary of development costs 166

Table 8.2: Fiscal terms for PSC 85’ 167

Table 8.3: List of Initial Subsurface Scenarios 170

Table 8.4: List of second screening Subsurface Scenarios 170

Table 8.5: List of third screening Subsurface Scenarios 170

Table 8.6: List of Fourth screening Subsurface Scenarios 171

Table 8.7: List of fifth screening Subsurface Scenarios 171

Table 8.8: List of Fourth screening Subsurface Scenarios 171

Table 8.9: First Screening Results for Subsurface Scenarios 172

Table 8.10: Second Screening Results for Subsurface Scenarios 173

Table 8.11: Third Screening Results for Subsurface Scenarios 173

Table 8.12: Fourth Screening Results for Subsurface Scenarios 174

Table 8.13: Fifth Screening Results for Subsurface Scenarios 174

Table 8.14: Sixth Screening Results for Subsurface Scenarios 175

Table 8.15 : Revenue split for Gelama Merah project 175

Table 8.16: Sensitivities value for NPV at 10% 176

Table 8.17: Comparison of current/delay/acceleration of project economics 178

Table 8.18 Summary of Economic Analysis 179

xvii

LIST OF APPENDICES

APPENDIX A – Geology & Petrophysics

A.1 Vertical Cross Section for Exploration Wells

A.2 Lithologies for GM-1 and GM-ST1

A.3 Hingle Plot used for Calculation of Sw for GM-1 and GM-ST1

A.4 Non-corrected Neutron-Density Crossplot for Lihtology Identification

A.5 Corrected Neutron-Density Crossplot for Lihtology Identification

A.6 M-N Lithology Identification Data and Plot

A.7 Averaging Methods for Properties Calculation

A.8 Averaging Methods for Properties Calculation

A.9 Distribution of Hydrocarbon in Sumandak Tepi, offshore Sabah

A.10 STOIIP Calculation – Minimum, Most Likely and Maximum

APPENDIX B

B.1 Optimized Well Location and Well Type

B.2 Zone cross-sectional

B.3 Comparison Chart for sensitivity analysis on cumulative oil field production and daily

production rate

APPENDIX C– Production Technologist

C.1 4 Proposed Sand Screen Control Methods in the Production Technologist Phase

C.2.1 EPS WELLFLO 3.8.4 for Nodal Analysis : Tubing Size Selection with GM-1

Exploration Well Data

C.2.2 EPS WELLFLO 3.8.4 for Nodal Analysis : Water Production For GMJT-01A

C.2.3 EPS WELLFLO 3.8.4 for Nodal Analysis : Produced GOR for GMJT-01A

C.3 Gas Lift Design

APPENDIX D – Drilling & Completion Implementaion Plan

D.1 Well Trajectories

D.2 Well trajectory details using Stoner Engineering Software (SES)

D.3 Wellbore Diagram for GMJT-01A to 05C, and WI

APPENDIX E – Facilities Engineering

E.1 Surface Schematics

E.2 Production Options

APPENDIX F – Economic Evaluation

F.1 Contractor’s Cash Flow Calculation

F.2 PETRONAS Cash Flow Calculation

F.3 Government Cash Flow Calculation

1

PHASE 1 OVERVIEW

1.1 INTRODUCTION

The Gelama Merah field is located Offshore Sabah at approximately 43km

from Labuan and 130km from Kota Kinabalu, Malaysia in the Sabah Basin block

owned by PETRONAS. The operator for the field is PETRONAS CARIGALI SDN

BHD with Japan Drilling Company as the drilling contractor. Two exploration wells

had been drilled so far which is well GM-1 (vertical profile) and GM-ST1

(sidetracked) from a drilling floor height of 27.3m from the mean sea level (MSL). As

for current, the status of the exploration is plugged and side tracked.

The wells were successfully drill from seabed at 70.1m to 1636m (from RKB)

and hydrocarbon reservoir was encountered as predicted, with one suite of wireline

logs carried out in the 12-1/4” hole phase and drill stem test (DST) was carried out as

well, tested at interval of 1521 to 1530m TVD-RKB. In addition, on-line real-time

data monitoring and recording of pressure and drilling parameters were carried out

during whole course of drilling. Continous evaluation of pressure and drilling

progress provided an aid in optimizing drilling cost and ensuring maximum safety to

personnels.

1.2 PROBLEM STATEMENT

The Gelama Merah field was discovered in 2002, and since then, further study

has been conducted with gathering of information from the 2 exploration wells

discussed. Facing time constraint, limited data and large number of uncertainties, the

determination of the best development options has been considered as a tough

challenge.

The FDP report covers 6 main phases involved which are listed below:.

Geology and Formation Evaluation

Reservoir Development Plan

Production Technology

Drilling & Completion Implementation Plan

Economic Analysis

Health, Safety & Environment (HSE) and Sustainable Development

2

1.3 FDP OBJECTIVES

The objective of the Gelama Merah FDP project is to carry out a technical and

economics study of the proposed development utilizing the latest technology available.

The ultimate objective is to produce a reasonable and reliable FDP report that satisfies

the needs of high-level management in making decision of the proposed development

for Gelama Merah field. Objectives in formulating the best, possible FDP will include

the following:

Maximizing economic return

Maximizing recoverable hydrocarbons

Maximizing hydrocarbon production

Compliance with health, safety and environment issues

Providing recommendations in reducing risks and uncertainties

Providing sustainable development options

1.4 METHODOLOGY

1.4.1 Modeling Softwares

The softwares available and used for the FDP for Gelama Merah are listed below:

No Phases Softwares

1 Geology & Petrophysics ImageJ , PETREL 09, Microsoft Excel Spreadsheet,

LAS, Intellectual Properties (IP) 09

2 Reservoir Development PVTSim, MBal, PETREL 09, ECLIPSE 08,

Tempest, PRIze

3 Production Technology Stoner’s Engineering Software (SES), EPS WellFlo

v3.8.4

4 Drilling & Completion Stoner’s Engineering Software (SES), Cement

Planner (PCSB), Casing Stress Check (PCSB),

Que$tor v9.4

5 Facilities Engineering Que$tor v9.4 , PIPESim 05, Microsoft Excel

Spreadsheet

6 Economic Analysis Que$tor v9.4, Microsoft Excel Spreadsheet

Table 1.1 – Modeling Softwares used for FDP

3

1.4.2 Flow Diagram 1 : Geology And Petrophysics

GEOLOGY

PETROPHYSICS Quick Look

Identification on

available logs to

differentiate

impermeable and

possible

hydrocarbon

formation.

Identification of

gas, oil and water

bearing zones.

Pressure plot

to identify the

GOC & WOC

from the

formation

pressure plot

in Drill Stem

Test (DST)

Software: Microsoft

Spreadsheet Excel

Properties calculation for

effective φ, Rw, Sw, Bulk

volume water (BVW),

Hydrocarbon moveability

index, Net to Gross (NTG)

for every layer. Values for

each point in every layer

will be averaged based on

arithmetic (φ) , power (Sw),

and weighted average

(NTG)

2 Dimensional

Cross Imaging to

identify the

layering of each

zones based on

contour surface

maps provided.

Software: Microsoft

Spreadsheet Excel ,

ImageJ

Identification

of regional or

depositional

settings,

stratigraphy

and geological

structure for

offshore

Sabah

province/area

3 Dimensional

Static Model

developments with

appropriate data

from well test and

core analysis report

which includes

facies modeling,

properties modeling

and well insertions.

Software: PETREL

Schlumberger

Volumetric calculation

for STOIIP for oil

producing zones (to be

identified in the

previous section. 3

Methods of

deterministic

calculation are

compared and

discussed.

Softwares:

1. PETREL

2. Intellectual Properties

3. Microsoft Spreadsheet

Excel (manual)

Discussion, Risk

Analysis and

Recommendations

4

1.4.2 Flow Diagram 2 : Reservoir Engineering

RESERVOIR

ENGINEERING

Software: ECLIPSE

PVTi

Software: PETREL,

ECLIPSE 100

Definition of

Simulation Study

Define the

objectives of

simulation studies

and problems to be

solved.

Data preparation.

Data is obtained and

evaluated with a

focus on its quality

and the

identification of

relevant drive

mechanism. The

given reports on

Gelama Merah are

extensively utilized

to obtain the

required data.

Data Validation

By using PVTi used to

characterize a set of fluid

samples for use in

ECLIPSE simulators. It is

vital in creating a realistic

physical model.

Secondary Recovery Mechanism

Plan and Strategies

1. EOR Screening

By using PRIze Screening

Software and recheck by

manual screening.

2. Development Strategies Plan

3. EOR modeling in ECLIPSE

4. Future Performance Prediction

Reservoir Simulation

1. Reservoir input data

Preparing .DATA file to be run in

ECLIPSE

2. Model Initialization

Describes the basic reservoir

analysis includes the reservoir

model validation through the

calculation of original fluid in

place volumes, establishing the

initial fluid saturation and

pressure distribution within the

reservoir.

3. Development Strategies Plan

Defining the flow wells control,

set prediction controls, identify

uncertainties and control

parameters and rank development

strategies.

4. Define Simulation Case

Performance predictions based on

development strategies and then

analyze the uncertainties,

performing sensitivity analysis,

simulate, validate and iterate.

PVT Analysis

i. Constant-

Composition

Expansion Test

ii. Differential

Liberation Test

(Vaporization)

Well Testing

Includes the Reservoir Evaluation

(conductivity, pressure, effect,

forecast, boundaries), Reservoir

Management and Reservoir

Description

History Matching

History matching to be

done utilizing the manual

and automatic method

Software: PVTSim

Software: Pansystem

5

1.4.3 Flow Diagram 3 : Production Technologist

PRODUCTION

TECHNOLOGIST

An objective to be

identified whether

sand control is

required or not in

Gelama Merah field.

Sand control analysis

to be planned based

on the sand

production data rate

from the well test

sample and PVT

report. Among the

scope are selecting

open/cased hole, and

decision of types of

sand screens to be

used.

Production Optimization using nodal

analysis method by doing PVT and IPR

matching from the exploration wells.

Some of the parameters that will be

tested are:

i. Optimum tubing size

ii. Water cut percentage on production

iii. Gas Oil Ratio effect on production

A gas lift design will also be developed

to compare the results of the natural

drive method. An analysis of when to

optimize the well utilizing the gas lift

method will be proposed based on the

finding from the obtained results. This

includes the material selection for the

tubings and the packer in term of steel’s

grade and other related properties.

Research, Reference

books and notes

Well Design is to be

developed on the basis on

well orientation and well

profile (radius of curvature)

including justifications for

selection. A Wellbore

diagram is also planned for

the wells to be drilled in

Gelama Merah field which

includes components such

as SCSSV, Packers, Sand

screen, Zone of Interest,

Perforated Zones, Gas Lift

Valves and deviation angle

depths.

Software : EPS (Edinburgh Petroleum

Services) WellFlo 3.8.4 by

Weatherford

Software :

1.Microsoft Spreadsheet

Excel

2. Horizontal Drilling

Software

Production chemistry analysis

on produced components such

as H2S and CO2 %

6

1.4.4 Flow Diagram 4 : Drilling And Completion Plan

DRILLING PLAN Selection of

Platform Type

Well Trajectory

Well Types

Identification of Pore

Pressure, Fracture Gradient,

Mud Pressure and Trip/Kick

loss margin in a plot against

depth.

COMPLETION

PLAN

Selection of downhole/surface completion tools :

Packers, SCSSV, tubing sizes, sand control method,

completion/packer fluid, SSDs and X-mas tree

specification.

Types of Completion:

Single Completion

Dual Completion

Types of fluids produced

Casing Design

Casing Setting Depths

Casing Stress Check

(Collapse, Burst , Tension)

Cementing Plan (volume to be pumped, density)

Mud Plan (additives, density)

Hydraulics, Torque, Drag

Drilling Optimization (technology to be

implement)

Well Control (BOP, Casing Spool specification)

Drilling and Completion Schedule and

Cost Estimation

Softwares:

1. Cementing Calculation spreadsheet

2. Drilling Trajectory in 2Dimension

3. Casing Stress Check spreadsheet

4. Torque and Drag calculator sheet

5. Stoner Engineering Software

7

1.5 PROJECT TEAM

The Gelama Merah FDP is assigned to a dedicated and well-rounded

PETROBEN project team. The team is led by Arthur Goh with support from 7

members from petroleum engineering disciplines. A total of 13 weeks were allocated

for the 8 phases involved. The approach taken were to divide the job equally amongst

the members as this encourages constructive ideas and suggestions since all the

members are from similar disciplines and with the objective that every member

should be acknowledging the whole concept of the FDP as a whole.

The project was initiated in August 2010 and the team plans to complete the

FDP by November, 2010. The structure of the team is presented in Figure 1.1.

Figure 1.1: PETROBEN Project Team Organization Chart.

Project Manager

Arthur Goh

Geology Hafriz (Lead), Aqbal, Sarah,

Mahirah

Petrophysics Zahidi (Lead),

Arthur, Hazwan, Alfouti

Reservoir Eng Sarah (Lead),

Hafriz, Hazwan

Production Tech Mahirah (Lead), Alfouti, Arthur

Drilling & Completion

Aqbal (Lead), Zahidi, Arthur,

Mahirah, Alfouti

Facilities Eng Alfouti (Lead),

Mahirah, Arthur

Econonmics & HSE

Arthur (Lead), Zahidi, Aqbal

8

PHASE 2 GEOLOGY

2.1 2-DIMENSIONAL CROSS IMAGING

Surface map consist of contour line which indicate the depth of the area from

top view. Contour lines connect a series of points of equal elevation and are used to

illustrate relief on a map. For instance, numerous contour lines which are close to one

another show hilly or mountainous terrain while in apart, they indicate a gentler slope.

The depth range that plotted on the top map is within 1300-1800m. There are a total

of 10 layers of surface map which are U3.2, U4.0, U5.0, U6.0, U7.0, U8.0, U9.0,

U9.1, U9.2 and U10.0. The maps were scaled as 1:233m which is in A4 sizes. For

conventional cross section imaging, a identical scale of horizontal and vertical are

recommended (where the vertical exaggeration is 1) as shown below.

Vertical Exaggeration

(VE)

= 1:233m = 1

1:233m

Figure 2.1 – Surface map for Unit 3.2

= the value of one unit of measurement on

the Horizontal (Map ) Scale

the value of the same unit of measurement

on the Vertical z

9

From the surface map, the depth cross section was drawn to visualize the

contour line in two dimensional views. The horizontal and vertical cross sections were

both plotted using Microsoft Excel spreadsheet and point reader based on pixel,

Image_J. On the x-axis is given for the width (horizontal and vertical) while the y-

axis indicates the thickness of each zone.

Two methods of depth conversion of time maps were initially utilized, where

in the first, manual calculation from the graph and secondly moving to the result of

Image_J software. It was found out that, the manual calculation does not give accurate

result due to small scale of the maps (1:233), and since the actual reservoir layers are

only approximately 20-50m in thickness, which is represented in a minor 1mm in the

A4 paper can easily lead to stacking of layers. This error was later eroded by the use

of Image_J and Microsoft Excel spreadsheet higher accuracy. The results of the plots

are shown in Figure 2.2.

In Figure 2.2, the well trajectory is developed using the Measurement While

Drilling (MWD) data, where the angle, direction, true vertical depth (TVD), N/S

departure and E/W departure. The properties of each zone are also included in Figure

2.2 which are obtained from the later part in Phase 3 – Petrophysics. Besides that, the

boundary were also plotted. The Water Oil Contact (WOC) is found to be at 1509m

TVDSS while the Gas Oil Contact (GOC) is at 1470m TVDSS. The two points of

well given in the surface maps are constant in scale for every maps, indicating that the

points given are in TVD for both the wells.

The distance between both of the wells are calculated to be approximately

600m, calculated using simple Pythagoras rule where the hypotenuse of the curve

should be lesser than 1774.6m (as this is a curved, not a straight line as indicated in

Figure 2) and having the TVD value of 1580m. Therefore, the x and y axis scale both

indicates the coordinate of the location in term of meters. From the 3 plots, we can see

as well that there is no minor or major fault detected. The zones from U3.2 to U.9.2

can be see truncated as the top layer were slightly eroded. Zone U10.0 from the

figures is set to be the base reservoir which confines the boundary of the reservoir.

*Refer to Appendix A for vertical and horizontal cross section from Excel Spreadsheet

10

Figure 2.2 – Spreadsheet horizontal cross section for Gelama Merah 1 and ST-1

1200

1300

1400

1500

1600

1700

1800

1900

2000

272000.00 273000.00 274000.00 275000.00 276000.00 277000.00 278000.00 279000.00 280000.00 281000.00 282000.00

Dep

t

Length

Horizontal Cross Section GM-1 ST-1 & GM-1

U3.2

U4.0

U5.0

U6.0

U7.0

U8.0

U9.0

U9.1

U9.2

U10.0

GM-1

GM-1 ST-1

GOC

WOC

GOC = 1468m TVDss

WOC = 1508m TVDss

U3.2, φ= 0.195, NTG=0.749, Sw=0.180

U4.0, φ= 0.158, NTG=0.748, Sw=0.415

U6.0, φ= 0.134, NTG=0.629, Sw=0.711

U7.0, φ= 0.245, NTG=0.848, Sw=0.239

U8.0, φ= 0.222, NTG=0.822, Sw=0.207

U9.0, φ= 0.208, NTG=0.797, Sw=0.251

U9.1, φ= 0.219, NTG=0.736, Sw=0.393

U9.2, φ= 0.207, NTG=0.739, Sw=0.943

U5.0, φ= 0.214, NTG=0.752, Sw=0.263

11

1.5 STRATIGRAPHY AND RESERVOIR GEOLOGY

As shown in the multi-layered reservoir in Figure 2.2, it can be seen that there

the oil accumulation are distributed at a thick layer at zone U9.0 and U9.1. The thin

oil layers are identified above the GOC is at zone U3.2, U5.0 and U9.0 above the

GOC level. The existence of oil layers above the original GOC can be explained by

the unconformity and erosion theory. It was believed that, there are 3 different

depositional time frame. Firsty zone U9.0 until U10.0 was firstly deposited and

sedimented. Soon after, there was to be a new sedimentation of zone U5.0-U8.0. This

whole section was then uplifted and at the area where the zones pinched, there might

be a possible erosion causing an uncomformity layer when the new sedimentation of

U3.2 and U4.0 occurs. Then, tectonic might have caused another possible uplift that

gives the Gelama Merah the current anticlinal shape it has now. The erosional secion

may provide a path for the oil in the lower zone to escape to some thin upper zone

layers which is bounded by impermeable clay and shale layers.

Sedimentology and biostratigraphic analyses of side wall cores taken based on

Gelama Merah-1 and Gelama Merah-1 ST-1 show the presence of marine hiatal

events / surface wave, cross stratification and burrows. Studies from mudlog and side

wall cores described all sands packages as very fine to fine grained, poor consolidated

to unconsolidated sand with minor shale occurrences. From these observations tell

that the hydrocarbon bearing reservoirs are very friable. Therefore the formation is

susceptible to sand failure possibility during production.

Two lithofacies are interpreted from the combination of Gelama Merah-1 ST-

1 and Gelama Merah-1 cores logging. They are cross-bedded sandstones, planar

bedded sandstone, laminated sandstone, massive sandstone, fosiliferous sandstone,

claystone and dolomite (from the drilling report for rock lithologies).

Porosity and permeability were derived from well log data properties and

calculations using the Excel spreadsheet. Then the porosity and permeability are

grouped into facies in the static model (to be discussed in the later section) and was

used to establish relationships between facies and rock properties. The results from

the properties calculation show high reservoir quality with porosity up to 30%.

12

Lamination and cross bedding sand facies have variable permeability/porosity

relationship due to thin bed effects.

Lateral lithology changes can be seen in well log data properties and

horizontal cross section. Reservoirs are stratified, with extensive shale barriers acting

as both top and bottom seals. 2D cross section studies focuses more on stratigraphic

framework and hydrocarbon column instead of surface layers distribution due to the

multiple effects near the unconformity. Cored lithofacies were used to correlate with

log interpretations from petrophysicist as a process to determine the lithofacies in

uncored wells.

The hydrocarbon bearing reservoirs in Gelama Merah area are represented by

topset 2D cross section and also quick-look method from the logs proven by

Microsoft Excel Spreadsheet calculations. It is interpreted as a prograding event,

shallow marine sand and with continuous shale package. Oil with thick gas cap was

discovered in Unit 4.0, Unit 5.0, Unit 6.0, Unit 7.0, Unit 8.0, Unit 9.0, Unit 9.1, and

Unit 9.2. Gelama Merah-1 discovered a total of 158 m of net gas sand and 30 m of net

oil sand from Unit 4.0 to Unit 9.1. Gelama Merah-1 ST-1 discovered a total of 53 m

of net gas sand and 26 m of net oil sand in Unit 9.0 and Unit 9.2. (These values are

shown in the later section of Petrophysics chapter. Proven Gas Oil Contact (GOC)

was established at 1468 m TVDSS for the sand units.

2.3 REGIONAL SETTING

Gelama Merah area is located in the offshore Sabah basin. Based on research

on offshore Sabah Basin, it was believed that the field lies in the West Labuan-Paisley

Syncline and characterized by a major North-South growth Morris Fault which is the

major of tectonic importance. The regional wrench fault was interpreted by Rice-

Oxely (1991) and Tan and Lamy (1990) which has marks the transition from the

Inboard and Outboard Belts of the shelf region. It had also indicated a high structural

complexity, possibly confirming the interpreted wrench mechanisms along this fault.

Gelama Merah is believed to be deposited in the later part of Middle Miocene

sands and has the depositional environment of prograding delta and coastal complex.

13

Apart from that, there are 4 major prograding sand packages were recognized within

the targeted reservoir levels and they are characterized by interbedded sand shale,

coarsening upwards.

Throughout the cross section data, a small erosion occurrence can be clearly

seen and it is assumed to be the result of the movement of Morris Fault followed by

landslide near the up-thrown block. A thin continuous layer of shaly to silty sand was

then filled the eroded area. In the other part of Sabah’s Basin Geological studies, the

structure is understood to be exposed to the northwesterly striking channels,

dissecting delta top thus forming the unconformity. This is proven and supported by

the wells correlation of Gelama Merah field. The mentioned unconformity represents

a major movement of the Morris Fault and it is also found that the unconformity

pointed out a drastic change in the depositional environment, from deeper in the

underlying interval (coastal) to shallower coastal plain.

2.4 EXPLORATION OPPORTUNITIES

Past explorations activities in the western and northern Sabah have been

traditionally focused on the inboard areas of the continental shelf. The areas have

been explored for the past 100 years, where first oil seeps were reported from the

Kudat Peninsulas. The first ever offshore well developed in Sabah Basin was the

Hankin-1, which was drilled SHELL Sabah/Pecten in 1958. The oil and gas

production from Sabah account for approximately 15% and 5% dated in 2005, of the

total production in Malaysia, respectively. There are currently 7 producing fields in

the Sabah Basin (Ketam has already ceased production) and, except for Kinabalu, all

the fields were discovered before 1980.

The Gelama Merah field is specifically located in the sub-block 6S-18 of

Block SB 301. Recent exploration targets are clastic and carbonate reservoirs of

Miocene and Pliocene age. There are currently seven offshore blocks under

exploration PSC or have exploration commitments. Most of these blocks are located

in the west Sabah area and are available under the Revenue over Cost (R/C) PSC

terms.

14

2.5 THE PETROLEUM SYSTEM

Maturation and Migration

The Gelama Merah field is to be assumed as of the Miocene-Pliocene deltaic

accumulation at a convergent margin. Migration along the faults is probably a major

method of migration in unconformity layers due to erosion. Some migration through

sedimentary facies has presumably occurred, especially in an up dip direction. The

timing for the maturation is assumed to varies from Middle Miocene to present.

Source Rocks

The hydrocarbons estimated in Sabah Basin are essentially very similar in

composition and is predicted to have originated from source rock which are rich in

terrigenious organic matter No discrete rich source of rock layers are identified or

known, however the organics are probably concentrated in the marine compact

intervals.

Reservoir Rocks

Reservoir rocks for the Gelama Merah field consist of intebedded sandstone

with non-reservoir formation of thin shales.

Traps and Seals

For Gelama Merah, the formation are of anticlinal features, either from growth

faulting or aticlinal features associated with tectonics. Presumably there are also

stratigraphic traps unrelated to anticlinal features as the unconformity trapping

mechanism that traps the hydrocarbons in our units of interest.

2.6 DEPOSITIONAL ENVIRONMENT

Before the static model is generated, it is vital to identify the depositional

environment of the zone of interest. For Gelama Merah, the depositional is dominated

by the deltaic environment. Based on core data, a less considerable variation in grain

size and sorting was observed within the sand body contained in the units of interest.

15

From the Gelama-2 ST1 core data, it can be seen that the zone beyond the

unconformity is shale interlaminated scarcely with sand. Shale in the Gelama Merah

field reservoir is hard to fairly hard, well compacted, finely fissile, micromicaceious,

smoothly sloppy.

Besides, in the cores examined, they also exhibit cross bedded layers of sand

and conglomerate with shaly sand. The regional tilting of the basin north west wards

and the basin ward migration of the hinge lines that separate unconformities from

there correlative conformities can also be evident for the fluvial dominated deltaic

environment.

2.7 3-DIMENSIONAL STATIC MODEL (PETREL 08)

2.7.1 General Description

The static model implies the three-dimensional structure of the reservoir zones

based on the surface contoured from surface maps, lithologies correlated from log

readings and also facies based on depositional environment. The reservoir model was

developed using Schlumberger’s PETREL software. Ten surface maps were digitized

and stacked on the depths to produce a geocellular reservoir model. The well tops

function were first used to correlate both wells in Gelama Merah 1 and ST-1, which

will be used to determine the lithologies using facies modeling.

2.7.2 Model Parameters

The Gelama Merah areas are modeled using surface maps imported into

PETREL. They are defined for the same value of X-axis value from 273800 to

280000 meter East, and for Y-axis value from 613000 to 616700 meter North. This

approximates to a perimeter of investigation at 6200 meter from west to east and 3700

meter from north to south. Figure 2.3 illustrates the contours that have been used to

present one of the reservoir units, U3.2. The model created is not included with fault

as it is not detected from the 2 Dimensional cross image plotted using the Microsoft

Excel spreadsheet in Figure 2.2.

16

2.7.3 Top Structure Development

The BMP image file were first input into PETREL, and coordinates in the 3

dimension are set for X,Y,and Z axis.. The polygons of the 3D contour lines are

created as such by dotting the lines in the surface maps and then transferring the

contours to the desired depth. The depth of this boundary should be the lowest point

in the surface image map. The “Make/edit Surface” converts the digitized contour into

top structure map by choosing the polygon as the main input while boundary as the

boundary itself. The geometry of grid size and position is set to automatic, thus by

this it means, the structure (hills and slope) will be automatically defined. The top

structure map for U3.2 is shown in Figure 2.3. Ten top structure maps are then

stacked on top of each other for a complete view of the reservoir structure skeleton.

Figure 2.3 – Top Structure for Unit 3.2

2.7.4 Creating new wells

The identical wells for explorations were created by “Input new well” option

from the Input window. The well deviation data were previously compiled from

drilling reports and imported to PETREL for both the sidetrack and vertical well.

Both the wells were precisely placed at the coordinates based on the surface maps.

2.7.5 Stratigraphic Modeling

Stratigraphic modeling comprises of making well tops and also well

correlation. The logs from the well logging data are transferred into PETREL in LAS.

17

File. The new well section window is activated to view the available logs which are :

(RDEEP_1, RSHAL_1, RMICRO_1, DEN_1, CALI_1, NEUT_1, GR_1, SP_1,

DTCOMP_1, PEF_1, DTSH_1). Based on the lithology identification (under

Petrophysics in the next chapter), well correlations can be made to identify the well

tops from U3.2 to U9.3. By using the “Create well top” function, each zones can be

easily distinguished as the information can be converted into the three dimensional

model as well. Other log properties, such as effective porosity, permeability and water

saturation can b derived from the original log and will be discussed in the later section

of 3D Static modeling.

Under the global well logs (general log- if logs are added here, it will be

automatically be added in both of the wells), there are other few alternatives log

created which were DensityPoro (for density porosity), Facies (for facies), ND_Poro

(neutron-density porosity), Eff_Poro (effective porosity), Res_W (Resistivity of

water) and Sat_W (water saturation).

Defined Formulas are:

DensityPoro = (2.644-DENB_1)/(2.644-1)

Facies= If(GR_1>86,1,0)

Vshale (Linear)= (GRlog-GRmin)/(GRmax-GRmin)

ND_Poro= Sqrt((Pow(NEUT_1,2)+Pow(DensityPoro,2))/2)

Eff_Poro= ND_Poro*(1-Vshale)

Sat_W= Pow(Res_W/(RDEEP_1*Pow(Eff_Poro,1.8),(1/1.93)

The values input in the previously are formulas which will be used for manual

calculation in the petropyhsics chapter. After each properties are defined, quality

check or cross check will be done to ensure the formula are correct. For instance,

shale should have lower effective porosity compared to sandstone, and for water

resistivity, the resistivity shown by the sandstone (from zone U3.2 to U9.0) should

have lower values compared to shale due to the presence of hydrocarbon in the

formation.

18

Figure 2.4 – Well top correlations using Gamma Ray for GM-1 and GM-ST1

2.7.6 Structural Modeling

Under the structural modeling, in “Define model” option, the name of the field,

Gelama Merah (GM) is selected. Only truncated tops which are eroded were

identified from top of U3.2 to base of U8.0. Pillar gridding is a selection of boundary

for a tri-skeleton development to give the structural model its shape. A boundary that

covers the two exploration wells were selected. The I increment and J increment

values are set to be 50 unit. (Lower values will give a more detailed skeleton, while

50 would be deemed sufficient). The horizons were chosen based on the top structure

The U3.2 to U8.0 is

identified from well

GM-1 but not in

GM-ST1. This is

also shown in the

2D cross image

from Excel as the

zones are truncated.

Therefore the zones

are not correlated to

the neighbor well.

Both wells logs

show the existence

of U9.0 to U9.3. For

this case, the

Gamma Ray log is

used. However, if

we already obtained

the depth of each

zones from log

interpretation, any

log (even Calipher

or Resistivity) can

be used as a

correlation log. This

correlation will

appear in all logs.

19

that were available. Zone U3.2 to U8.0 were selected to be erosional horizon type,

while for the rest below were conformable. The tables for the horizons were set as:

Index Horizon

Name

Horizon

Type

Conform to

another

horizon

Well Tops Use

Horizontal

Fault lines

Input #1

(TS)

1 U3.2Top Erosion No U3.2 Top Yes U3.2






7 U9.0Top Conformable No U9.0 Top Yes U9.0



10 U10Top Conformable No Yes U10.0

Table 2.1 – List of horizon name, horizon type and input for making zones

Erosion The horizontals below will be truncated

Base Horizons above will be truncated

Discontinuous The horizon is both a base and an erosional. Horizons below and above

will be truncated.

Conformable Horizons will be truncated by erosional, base and discount. Lower

conformable horizons will be truncated by upper conformable horizons

in the make horizons process.

Table 2.2 – Types of horizontal truncations

Table 2.1 shows the list of horizon names and types of several range of

reservoir units in Gelama Merah field. For the well tops , there are 3 options, which

are well tops, the middle zones, and the lower base, and the well tops for each top

surface structure are selected which were developed previously in the correlation part.

While for the Input , the top structures are selected accordingly. The horizon types are

choosen based on the environment of deposition in offshore Sabah basin as well,

where the reservoir are mostly dominated by shallow marine deltaic sequence, where

it progrades to the north western direction. All zones (Zone 1-9) were to be set to

proportional. Proportional indicates that the division of the zones or layering are

going to have a proportional scale based on the thickness of each zones. In the final

20

step of structural modeling, the contact boundaries were defined. The water oil

contact (WOC) is input to be at 1508m TVDSS while for the gas oil contact (GOC)

set at 1468m TVDSS at the “Gas/Oil/Water Boundary” selection. (from formation

evaluation)

After the horizon setting, the zones and layer were produced by the “Make

Zones” and “Layering” options. For the layering, it was based on the facies and

lithologies of from the well intersection window of the log. For instance, for zone

below U9.0 Top – U9.0Base, the formation is only sand, thus a proportional value of

1 is input. Other options are “Fractions” or “Follow bottom”.

Figure 2.6 – Correlating the layers with the facies from log

The structural modeling was concluded with the setting of the GOC at 1468m

and WOC at 1508m based on the lithology identification and formation evaluation

later in Phase 3.

Figure 2.5

Cross sectional view of the GM-1

and GM-ST1 exploration well on the

10 top surface structures stacked.

21

2.7.7 Properties Modeling

Property Modeling is the final section towards the static model in PETREL.

The well logs were scaled up for the properties of neutron-density porosity, facies,

water saturation and effective porosity. The function of scaling up is to allow

PETREL to virtually categorize the values of each property in every 5mins for the

volumetric estimation in the next section. The facies modeling option were then

selected. The nugget of the variogram is set to be E-W direction based on the

depositional environment which was defined in the earlier section with the angle of

azimuth 90˚. The minor direction is set to 500, and major direction 1000, with the

vertical value of 4. This would change the nugget to be more curved indicating the

direction of the major axis which is the sandstone. The variogram type of exponential

is selected with the method for zone/facies of Sequential Indicator Simulation used

for more accuratre results during quality check using the historgram distribution. The

same setting was done for the Petrophysical properties for porosity, water saturation

and effective porosity. The final model that was produced from the property modeling

is the 3D-Static Model.

2.8 HYDROCARBON VOLUMETRIC ASSESSMENT SIMULATION

The PETREL Software discussed in the previous section was generated and

used to calculated the STOIIP and the GIIP, using the defined upscaled water

saturation, effective porosity, and the net to gross value above the water oil contact.

The GOC at 1468m TVDSS and OWC at 1508m TVDSS were derived from the

lithological study in the next chapter. There is a total of STOIIP at 76.83MMStb and

GIIP of 67.76MMMScf from the top U3.2 to U9.3 as Gelama Merah total proven

discovery resources as shown in Table 1 based on the 3D Static Model from PETREL.

HC intervals : includes oil interval only

Upper contact : Gas oil contact

Lower contact : Oil water contact

Porostiy : PHIE (effective) and Net to Gross

Recovery for STOIIP : 1.00 ; Bo (FVF): 1.169 [rm3/sm3]

22

Recovery for GIIP : 1.00; Bg = 0.01 cuft/scf , 0.001523476 stb/scf

PHIE = Total Porosity * (1-Vshale)

STOIIP in sm3: 12215 *10^3 sm3

Conversion Factor from sm3 to bbl, 1sm3 = 6.2934bbl

STOIIP in bbl : 76.83MMStb

GIIP in scf : 67.76 MMMScf

Case

Bulk volume

[*10^3 m3]

Net

volume[*10^3

m3]

GIIP [*10^3

sm3]

STOIIP (in

oil)[*10^3 sm3]

Group6 161475 109845 16404 12215

Zones

U3.2 17640 10806 110 11

U3.2 base 2633 1781 22

U4.0 1364 919 207 0

U4.0 base 228 148 33 0

U5.0 702 566 148 0

U5.0 base 1265 752 197 0

U6.0 1668 956 44 18

U6.0 base 924 658 30 4

U7.0 5412 3715 338 22

U7.0base 773 441 40 0

U8.0 4442 3004 4651 0

U8.0base 847 428 663 0

U9.0 19419 13538 9557 34

U9.0base 4039 2298 0 5412

U9.1 11376 7456 0 6503

U9.1base 6235 4317 0 232

U9.2 50843 36558 0 0

U9.3 25315 16672 0 1

U9.3base 6351 4833 0 0

Table 2.3 – Distribution of gross volume and STOIIP/GIIP on zones

*The comparison of STOIIP and GIIP for Volumetric Estimation will be

compared in the Phase 3 – PETROPHYSICS, to be compared using log analyses

and Intellectual Petrophysics (IP) software for deterministic and probabilistic

approaches.

23

2.9 RISK ANALYSIS AND UNCERTAINTIES

i. One of the potential risks is the sand structure. Gelama Merah sand is poor

consolidated to unconsolidated, with very fined to fine grained which

could give problem during productions. The unconsolidated sand might

intrude the wellbore and being produce to the wellhead. The sand

production can erode downhole equipment and the wellbore itself, and can

clog the wellhead and other equipment such as BOP and separator.

ii. The varieties of lithofacies of the Gelama Merah structure increase the

reservoir heterogeneity. These varieties may reduce the connectivity

between layers. Low connectivity between layers decreases the vertical

permeability of the reservoir. Thus, it restricted the movement of the

reservoir fluid to the wellbore. The presence of continuous shale between

sand layers also contributes to the low connectivity for the reservoir

iii. Core analysis did not provide sufficient information on the sand

distribution throughout the Gelama Merah area. There are still high

uncertainties regarding the heterogeneity of the sands and also the

complexities of the trap due to the unconformity

iv. As for the 3D static model, without information from the seismic data, it

lacks information to built a complete and accurate fault model. The fault

model is important as it act as an imaginary well to the production well.

Therefore, it might give inaccurate information on the determination of the

actual reservoir boundary for the volumetric estimation and also leading to

the dynamic model in reservoir simulation in the later stages.

v. Available logs are only from Gelama Merah field. Therefore, in the well

tops and horizons setting, the top layer U3.2 (facing towards the east) will

be slightly thicker as it is virtually being pulled by the welltops since there

are no correlations of wells available towards the east of well GM-1.

24

PHASE 3 PETROPHYSICS EVALUATION

3.1 FORMATION EVALUATION

The formation evaluation of Gelama Merah was divided by wells, first for

well GM-1 and then followed by well GM-ST1. Results of each zones were discussed

and rock types were also identified in the subsection. Methods such as using LAS

software, spreadsheet, and some interpreting charts from the module. Methods that

were used were evaluation on gamma ray log, resistivity log, neutron log, bulk

density log, photoelectric factor log, and also SP log.

3.1.1 Well Gelama Merah-1

i. Depth 500.00m-1320.00m

Gamma Ray reading gives relatively high reading; indicate high radioactive

formation, which is probably shale formation. Resistivity log give relatively low

reading indicates formation contains salty water (high conductivity); the overall

resistivity will be low indicating a highly probable non-hydrocarbon zone.

ii. Depth 1302.53 – 1324.84 m TVDss, Zone U3.2

Gamma Ray reading gives low reading; indicate low radioactive formation,

which is free shale formation, (Sandstone). Resistivity log give high reading indicates

formation contains hydrocarbon. This zone give high resistivity values may indicate a

hydrocarbon bearing formation. Neutron porosity log give low reading while density

porosity gives high reading may indicate it fills with gas; neutron porosity is low due

the lower concentration of H+ ion in gas than in oil/ water. Beside, gas has lower

density than oil/water.

In this zone, we can clearly see the Neutron and Density log curve crossover

each other, indicate gas effect/ butterfly effect. NEUT / DENT crossover (Øn > Ød)

of 6-8 units, indicating this zone is possible to be a sandstone interbedding with a thin

limestone.

25

iii. Depth 1332.00-1433.00m TVDSS , Zone U4.0 /U5.0/U6.0/U7.0/U8.0

Gamma Ray reading gives lower reading; indicate low radioactive formation,

which is free shale formation, (probably reservoir formation). Resistivity log give

relatively high reading indicates formation contains hydrocarbon. This zone give high

resistivity values may indicate a hydrocarbon bearing formation. Neutron porosity log

give low reading while density porosity gives high reading may indicate it fills with

gas; neutron porosity is low due the lower concentration of H+ ion in gas than in oil/

water. In these zone, we can clearly see the Neutron and Density log curve crossover

each other, indicate gas effect/ butterfly effect. NEUT / DENT crossover (Øn > Ød)

of 6-8 units, we can say that this zone is sandstone interbedding with a thin limestone.

For Zone U6.0 (1388m-1400m), At the upper part of this zone, we can clearly see the

Neutron and Density log curve crossover each other, indicate gas effect/ butterfly

effect. NEUT / DENT crossover (Øn > Ød) of 6-8 units, thus the upper part of this

zone is sandstone.

iv. Depth 1436.35 – 1484.58m TVDSS, Zone U9.0


which is free shale formation indicating probable reservoir formation. Resistivity log

give relatively high reading indicates formation contains hydrocarbon. This zone give

high resistivity values may indicate a hydrocarbon bearing formation.From depth

1436.35 to 1468m, the neutron porosity is observed to be much lower than the density

porosity, showing that there is a possible gas effect as neutron porosity detects the

hydrogen ion in the formation fluid, while density porosity calculates the real bulk

density of the formation. Gas formation usually has lower density due to high porosity

and because gas has lower density as compared to oil and water. Therefore zone

1436.35 to 1468m is believed to contain gas bearing formation.

From depth 1468 to 1484.58m, the resistivity gives a relatively high reading

indicating probable hydrocarbon zones. While the density and neutron log difference

is relatively small (less than 2-4 units) indicating that this is a probably oil bearing

zone. Thus, the GOC for well GM-1 is detected at depth of 1468m TVDSS. NEUT /

DENT crossover (Øn > Ød) of 6-8 units, thus the upper part of this zone is sandstone.

26

v. Depth 1493.05m-1505.51m, Zone U9.1


which is free shale formation, (Sandstone). The resistivity gives a relatively high

value indicating a probable reservoir formation. While the density and neutron log

difference is relatively small (less than 2-4 units) indicating that this is a probably oil

bearing zone. In this zone, we can clearly see the Neutron and Density log curve

separate each other, If NEUT/ DENT separate (Øn < Ød), thus this zone is dolomite.

vi. Depth 1545.00m-1600.00m, zone 9.2


which is free shale formation, (Sandstone). Resistivity log give very low reading

indicates formation contains water formation due to high conductivity. Most probably

this zone is at the water zone. The neutron and density log are shown intersecting

/stacking effect indicating that this is an aquifer zone from quick look method.

3.1.2 Gelama Merah – 1 ST1

i. Depth 1200.00-1406.74m TVDSS

Gamma ray shows high reading which a high radio active concentration.That

is indicate clearly shale formation with a very thin sand layers interbedding (from

1250m-1287m). Resistivity log gives relatively low reading which indicates water

bearing zone. Neutron- density log both give low reading and parallel line, which

prove that is a shale zone.

ii. Depth 1406.74 - 1414.08m TVDSS (Zone U9.0)

Gamma Ray reading is low; indicate low radioactive formation, which

is probable sandstone formation. Resistivity log give higher reading than the

minimum which is probably hydrocarbon zone. Neutron gives high reading, which

indicate high hydrogen concentration zone (liquid zone).Density reading is low,

probably gas zone.The two lines neutron density cross over that indicate clearly gas

zone in sandstone

27

iii. Depth 1416.73 – 1444.11m TVDSS (Zone U9.1)

Gamma Ray reading gives high reading; indicate low radioactive formation,

which is Sandstone. Resistivity log give more than the minimum reading

and formation may contains hydrocarbon. Neutron give low concentration reading of

H+, so probability of oil bearing formation is high in this zone. Density porosity

reading is high, that indicate the probability of oil is high in this zone. We can also see

both lines neutron density cross over, which indicate oil zone in a sandstone

formation interbedding with a thin limestone layers (sandy limestone).

iii. Depth 1446.07-1508.26m TVDSS (Zone U9.2)

Gamma Ray gives low reading; indicate low radioactive formation, which is

free shale formation, (Sandstone). Resistivity log give high reading,that

indicates formation may contains hydrocarbon bearing. Neutron gives medium

reading and low reading in the same zone at different distance. Medium reading when

neutron and density line cross and Low reading when both lines overlap. Density

reading give opposite reading of neutron. Less density reading when lines cross over

and high density reading when lines overlap. In the crossover location we can clearly

identify the presence of gas bearing formation. From the resistivity log we have high

reading that proves that in the overlapping location is oil.

iv. Depth 1510.06 – 1538.88m TVDSS ( Zone U9.3)

Gamma Ray gives low reading from (1510m-1520m) and high reading from

(1522m-1540m). Low reading indicates sandstone and high reading indicate high

radio active concentration which is shale formation. Resistivity log give minimum

value which indicate probability of water bearing formation. Neutron give high

reading, mean high hydrogen concentration zone. Density reading is medium. From

this we can say that the zone is interbedding of sandstone and dolomite and is water

zone.

*Refer to Appendix for the Lithology evaluation sketched on the log for GM-1

and GM-ST1 in the Appendix

28

3.1.3 Lithology Cross Plot Identification

Zones Drilling Report (Exploration

Data)

CNL “Compensated Neutron Log & Litho-

Density” M-N Lithology Plot

Uncorrected

Porosity

Corrected Porosity

3.2

Dominant Claystone

interbedded with minor sand

stone

(1300ft-1580ft)

Sandstone Shaly sandstone Shale interbedded sandstone

4 Sandstone Shaly sandstone Sand intebedded shale

5 Shaly sand stone Sandy claystone Shale interbedded sandstone

6 Dolomitic lime stone Sandy limestone Shale

7 Limey sandstone Limey sandstone Sandstone interbedded limestone

8 Limey claystone Sandy claystone Shale interbedded sandstone

9 Shaly sandstone Shaly sandstone Shale interbedded sandstone

9.1 Limestone Sandy limestone Sandstone interbedded limestone

9.2 Limey sandstone Sandstone Sandstone interbedded limestone Table 3.1 : Lithology Identification comparison

For the lithology identification, 3 method of comparisons are taken into consideration. The drilling report from exploration well for

GM-1 identify dominant claystone (shale) interbedded with minor sand from U3.2 to U9.2. The Neutron-Density cross plot supports the data

by showing majority of the layers found were in the region of shale and sandstone when corrected to the shale percentage. The M-N Plot was

also used to confirm this, and it was found that the results obtained were almost similar where percentage of limey sandstone or dolomitic

sandstone is very small.

*Refer to the Appendix A for the figure of plots for the Neutron-Density Crossplots and M-N Lithology Plot

29

3.2 FLUID TYPES IDENTIFICATION

Figure 3.1 Pressure Plot for Gelama Merah Field

The pressure plot from the drill stem test as shown is used to reconfirm the

depths of the WOC and the GOC. The table below shows the comparison of the

contacts from the quick-look method and also the pressure plot method. The depths

from the pressure plot (drill stem test) were taken from the RKB depth of 27.3m, thus

needs to be adjusted to subsea at MSL. The gas gradient is 0.045psi/ft, oil gradient

0.335psi/ft and water gradient of 0.43psi/ft which is the reciprocal of the slope.

Contacts Quick-Look Method Pressure Plot

GOC 1468 m TVDSS 1495m – 27.3m =1467.7m TVDSS

WOC 1506 m TVDSS 1533m – 27.3m = 1506.7m TVDSS

Table 3.2 Comparison of WOC & GOC contact depths

1300

1350

1400

1450

1500

1550

1600

2050 2100 2150 2200 2250

m T

VD

-RK

B (

RK

B=

27

.3m

) Formation Pressure (psia)

Gas Gradient

Oi Gradient

Water GradientGOC = 1468m TVDSS

WOC = 1506m TVDSS

y = 22.131x – 41946

Gradient : 0.045psi/ft

y = 2.985x – 1421

Gradient : 0.335psi/ft

y = 2.329x – 7.6579

Gradient : 0.43 psi/ft

2000 2050 2100 2150 1950

30

3.3 PROPERTIES CALCULATIONS

3.3.1 Objectives

The scope of study comprises of evaluation of all available formation data to

provide petrophysical parameters for resource assessment of Gelam Merah 1 and

Gelama Merah 1 ST-1 structure. The logging data comprises of : DEEP

RESISTIVITY, SHALLOW RESISTIVITY, MICRO RESISTIVITY, BULK

DENSITY, NEUTRON POROSITY, GAMMA RAY, SPONTANEOUS

POTENTIAL.

3.3.2 Petrophysical Evaluation Methodology

3.3.2.1 Shale volume calculation

Because shale is usually more radioactive than sand or carbonate, gamma ray

logs can be used to calculate volume of shale in porous reservoir. The volume of shale

expressed as a decimal fraction or percentage is called Vshale. The value is very useful

to be applied in the analysis of shaly sand. Calculation of gamma ray index start by

determine the volume of shale from a gamma ray log:

Where:

= gamma ray index

GRlog =gamma ray reading of formation

GRmin = minimum gamma ray (clean sand or carbonate)

GRmax = maximum gamma ray (shale)

For a first order estimation of shale volume, the linear response, where Vshale = IGR,

should be used.

Gamma ray logs are lithology log that measure the natural radioactivity of a

formation. Because radioactive is concentrated in shale, so shale has a high gamma

31

ray reading and shale free sandstone and carbonate, therefore usually have low

gamma ray readings.

3.3.3 Porosity calculation

There are 3 common type of porosity logs which are sonic, density and

neutron. But for this case the only available data from logging is density and neutron.

Although the advent of porosity logs provided a substantial improvement in log

interpretation, the significant change, from a geological viewpoint, was the

development of interpretive technique that combined the measurement from different

porosity tool. With combination of these 2 available data which are density and

neutron, lithology could be interpreted and better estimate of porosity produced.

Firstly the value of bulk density must be determine from the log data. The bulk

density is the density of the entire formation (solid and fluid part) as measured by

logging tool. It may be thought of as the density of a particular rock type that has no

porosity. Formation bulk density is a function of bulk density, porosity, and density of

the fluid in the pores. To determine density porosity by calculation, the matrix density

and type of fluid in the formation must be known. For this case the matrix density is

equal 2.644 g/cm3. The formula to calculate density porosity is:

Where:

= density porosity, = matrix density = formation bulk density (from log

reading) = fluid density

To combine the neutron-density log to get the porosity value is achieve by using the

formula:

√

Where:

= neutron-density porosity = density porosity = neutron density

32

Effective Porosity (PHIE) = PHIA*(1-VSHALE)

3.3.4 Water saturation calculation

3.3.4A. Method 1 : Apparent Water Resistivity, Rwa

The Rwa method relies on the comparison of calculated value of water

resistivity between interval in a well. This comparison can be made between different

zones or within the same zone if a water hydrocarbon contact is suspected in that zone.

Beside used for water saturation calculation, it is also help to identified zones. The

zone with the lowest value of Rwa is the most likely to be water bearing, and the value

of Rwa is closest to the actual value of Rw in the formation. But zone with values of

Rwa greater than the minimum observed are likely to have some hydrocarbon

saturation. Apparent water resistivity is define by using formula:

In practice, especially when calculated and displayed as a curve during a

logging job, the following values are used for simplicity: a=1.0 and m=2.0. After that,

an Archie water saturation can be calculated from the ratio of the Rwa values.

√

3.3.4B Method 2: Hingle's Plot using Archies Equation

The significant benefit of Hingle technique is that a value for water saturation

can be determine even if matrix properties of a reservoir are unknown. The Hingle

plot allows the interpreter to predict some of the parameter from the log rather than

estimating them by other method. Basically, the formation water resistivity can be

estimated by choosing the any point along the water-bearing line.

Firstly, create a Hingle Plot using available Water Bearing Zone data. (Density

RHOB and Matrix density). Then draw the best linear line trough the aquifer lines

33

which is 100% Water Saturated. From the log, the value of Pb is obtained, and

correlate to obtain the Ro in the y-axis. Then, calculate Rw and Sw using the

formulas:

(

)

( )

Where:

= resistivity of undisturbed water bearing zone = true formation resistivity.

3.3.5 Water saturation of the flushed zone

Water saturation of a formation flushed zone Sxo is also based on Archie

equation, but 2 variable are changed: mud filtrate resistivity Rmf in place of formation

water resistivity Rw and flushed zone resistivity Rxo in place of uninvaded zone

resistivity. Water saturation of the flushed zone can be used as indicator of

hydrocarbon moveability.

(

)

Where:

= water saturation of the flushed zone

= resistivity of the mud filtrate at formation temperature

= shallow resistivity

a = tortuosity factor (for this case a = 1)

m = cementation exponent (for this case m=2)

n = saturation exponent (n =2 )

3.3.6 Hydrocarbon moveability index.

Calculate by using formula:

34

If the ratio

is equal or greater than 1.0, then hydrocarbon were note move

during invansion. This is true regardless of whether or not a formation contain

hydrocarbon. For sandstone, whenever the ration is less than 0.7 moveable

hydrocarbons are indicated.

3.3.7. Calculation of bulk volume water

The product of a formation water saturation and its porosity is the bulk volume

of water. If values for bulk volume water, calculated at several depth in a formation,

are constant or very close to constant, they indicate that the zone is of a single rock

type and at irreducible water saturation. When a zone is at irreducible water saturation,

water in uninvaded zone does not move because it is held on grains by capillary

pressure. Therefore, hydrocarbon production from a zone at irreducible water

saturation should be water free.

3.3.8 Averaging method

Averaging method is use to make an average value of some parameters. For

this case, porosity and water saturation need to make an average value for some

values of these parameter at certain depth for each zones.

3.3.9 Average porosity.

Thickness weighted average method is used to calculate average porosity and the

formula

Where: i= porosity at certain depth , hi=height.

35

3.3.10 Average water saturation

Volume weight average method is used to calculate average saturation and the

formula:

Where:

Swi= Water saturation at certain depth i= porosity at certain depth , hi=height.

3.3.11 Concept of Cutoffs

3.3.11A Shale content, Vsh.

Eliminate the portion of the formation which contains large quantities of shale which

is about Vcutoffs

≈ 20 to 30 %.

3.3.11B Porosity

Eliminate the portion of the formation which is low porosity (and low permeability)

and therefore would be non-productive.

Sandstones, φcutoff

≈ 7% gas

φcutoff

≈ 8% oil

Carbonates, φcutoff

≈ 4%

3.3.11C Water saturation.

Eliminate the portion of the formation which contains large volumes of water in the

pore space.

Sandstones, Swcutoff

≈ 60%

Carbonates, Swcutoff

≈ 50%

36

Table 3.3 - Properties Calculation for GM-1 for various reservoir zones

37

Table 3.4- Properties Calculation for GM-ST1 for various reservoir zones

38

3.4 VOLUMETRIC CALCULATION

3.4.1 Volumetric Estimation Approach

The deterministic method was applied for the calculation of Stock Tank Oil

Initially in Place (STOIIP) and Gas Initially in Place (GIIP). The formula for both the

calculation are shown as below (conversion factor not required if GRV in m³)

STOIIP = 7758 × GRV × NTG × ø × (1 – Sw) × 1/Bo

GIIP = 43560 × GRV × NTG × ø × (1 – Sw) × 1/Bg

The GRV can be calculated from 2 methods, which is by using a planimeter to

calculate the structure map for the top and base layer, and manually counting squares

with know scales. For the method utilizing the planimeter, the values obtained for the

top and base are plotted for the area against thickness plot. The hydrocarbon bearing

zone is considered to be the zone sealed by the unconformity from top. From the GRV

estimation it can be seen that Unit 9.0 to U.9.1 have good hydrocarbon bearing unit in

terms of the gross volume rock in-capsulated by the top and base structure layer.

Figure 3.2 Area vs Height for U3.2 to U.9.2

1300

1350

1400

1450

1500

1550

1600

0 2000000 4000000 6000000 8000000 10000000 12000000

Hei

gh

t, m

TV

D

Gross Rock Volume, m3

Base Layer

Top Layer

GOC

WOC

U9.2

U9.1

U9.0

U8.0

U7.0

U6.0

U5.0

U3.2

39

3.4.1 Deterministic STOIIP & GIIP by log analysis

Table 3.5 STOIIP and GIIP Estimation using manual log properties reading

40

3.4.2 Deterministic STOIIP & GIIP by Intellectual Petrophysics (IP) Software

Table 3.6 STOIIP and GIIP Estimation using Intellectual Petrophysics (IP) Software

41

3.4.4 Comparison of Volumetric Estimations

Comparisons of three deterministic methods used are as follows in Table 3.7:

*SLB : Schlumberger

Methods PETREL (SLB) Log Analysis IP (SLB)

STOIIP (MMStb) 76.830 76.220 78.030

GIIP (BScf) 68.330 80.360 116.980

Table 3.7 Comparison between 3 deterministic methods

The values obtained from volumetric estimation from the properties calculation are

shown in Table 3.7. The STOIIP for each zones are determined individually because there

were shale layers as thick as 9m and would lead to suspected result if the zones are total up

together. For Log properties method, properties data are based on manual log readings which

may not be fully accurate as it is by manual method. The IP is a specialized software for

logging as the log data is input into it, and automatic identification of formation’s lithology

and properties was done. Table 3.8 shows the minimum, most likely and maximum

hydrocarbon recovery.

Units STOIIP ( MMSTB) GIIP (SCF)

Minimum Most Likely Maximum Minimum Most Likely Maximum

3.2 0.042 0.124 0.271 0.987 2.786 4.964

4.0 0.000 0.000 0.000 1.1012 2.175 3.656

5.0 0.000 0.000 0.000 1.1012 3.803 6.392

6.0 0.146 0.382 0.898 3.227 8.061 12.523

7.0 0.139 0.427 0.842 3.215 9.430 13.163

8.0 0.141 0.000 0.000 2.499 8.997 11.188

9.0 3.344 9.258 21.603 4.388 10.357 16.505

9.1 4.869 13.689 24.719 0.070 0.160 0.331

9.2 5.748 17.526 29.128 0.000 0.000 0.000

TOTAL 16.409 41.406 77.461 16.409 45.770 68.722

Table 3.8 STOIIP and GIIP Estimated Values from Deterministic Approach

42

However, the zones are slanted direction while the WOC and GOC are

horizontal. Therefore the result displayed by Log Properties and IP may not be as

theoretically accurate from static modeling using PETREL. However, these were

calculated on the basis of comparison. Based on the 2D plot generated by PETREL,

zone 9.0, 9.1 and 9.2 are slanted in between GOC and WOC, which defines that the

value should be used. For the Log Properties and IP, they can be concluded as not as

accurate because it is purely based on 2 point data from exploration well of GM-1 and

ST-1.

However as shown in Table 3.7 also, the difference margin between the

STOIIPs were small. For PETREL, calculations are self-defined for the properties,

where it is input using the calculator applications which reads from the global log data.

However the GIIP obtained for the 3 methods are significantly different in huge value.

The water saturation value for IP is concluded to be highly unreliable because it

fluctuates heavily in the gas layers (from 0.9 to 0.05 in 1 ft interval) thus reading of

average are taken.

For Table 3.8, three situations are being considered, minimum, most likely

and maximum STOIIP and GIIP based on the range of porosity, GRV, water

saturation and net to gross values from Petrel Simulation. The minimum indicates the

low case for the reservoir while the maximum shows an optimistic approach. The

most likely is the value of reserves that are most likely to be recovered. The objective

to determine the low case and high case is to identify which zones to produce in the

reservoir modeling. This will be further elaborated in the Recommendation in

Section 3.6 Thus, the STOIIP and GIIP will be used as a reference for the reservoir

engineering in dynamic modeling and also the ultimate recovery.

*For the complete calculation of Minimum, Most Likely and Maximum STOIIP,

refer to the Appendix A

43

3.5. DISCUSSION & RECOMMENDATIONS

3.5.1 Discussions

3.5.1.1 Gelama Merah 1

i. Gas effect zone. [Depth 1300 – 1465 TVDSS (3.2U,4U – 9U)]

First of all, to identify the gas effect zone, quick look method has been applied by

looking at the log curve pattern. Then, proceed by checking the value of Apparent water

resistivity, Rwa, Water saturation, Sw, to doubled check on the result from the quick look

method. The result for both ways are quite overlap on each other. The average Sw for

each zone (3.2U, 4U – 9U) show the low value which are from 18% to 41.4% regardless

the Sw in zone 6 which is 71%.Therefore, zone 6 has high possibility to be eliminated by

following the concept of cutoff for sandstone. So the average Sw for this zone (gas zone)

would be 22.7% and it is quite possible to be Hydrocarbon zone as expected from the log

pattern curve. By considering the Apparent water resistivity, Rwa value is greater than

the minimum observed are likely to have some hydrocarbon saturation and it is confirm

by the butterfly effect from log curve observation. At this zone, the density porosity show

a high value but the neutron log reading show a low value indicated probably of gas zone.

The average shale volume for gas effect zone is 22% regardless some thin top

shale at zone 7U and 8U. Refer to cutoff concept which is explained before, the portion

of the formation which contains large quantities of shale which is about Vcutoffs

≈ 20 to 30

% need to be eliminate. So up to point, all the zones should be keep first except zone

6.The average porosity for each zones which are calculated by using weighted average

method is from 21.1% to 29.7%. So, the average porosity for gas effect zone would be

around 26.3%. Based on the concept of cutoff, the portion of the formation which is low

porosity and would be non-productive need to be eliminate. Therefore, for this gas effect

zone, we just keep all zones (3.2U, 4U, 5U, and 7U-9U) for further analysis. As

conclusion the thickness for gas effect zone would be roughly around 165m including

zone 6 which is have possibility to be eliminated.

44

ii. Oil zone [ 1470m – 1506m TVDSS ( 9U and 9.1U)]

From the log interpretation, indicated that Hydrocarbon probably present at this

interval. The assumption getting stronger when neutron log reading and density porosity

show just a slightly different between the 2 values. Furthermore, supported by the value

of Rwa where it is greater than the minimum Rwa at this well indicated probably of

hydrocarbon bearing. The Sw at this interval also quite low which is around 25.1% until

39%. The average shale volume for oil zone is 22.1%. The average porosity for zones 9

and 9.1 are 26.1% and 29.7% which are calculated by using weighted average method.

So, the average porosity for these 2 zones would be around 27% which is quite good.

Based on the concept of cutoff, the portion of the formation which is low porosity which

is round 8% need to be eliminated. So, this interval fulfills the requirement. As a

conclusion, the thickness of oil zone interval would be roughly around 36m.

iii. Water bearing [1520m-1570m TVDSS (9.2U)]

From the calculation of average water saturation,Sw obviously indicated that this

interval is water bearing zone because the value for average Sw is 94.3%. Supported by

the low value of Rwa at this interval. The zone with the lowest value of Rwa is the most

likely to be water bearing. The average porosity and shale volume for this zone are 27.9%

and 26.1%.

3.5.1.2 Gelama Merah1-ST1

i. Gas effect zone. [Depth 1407 – 1465 TVDSS (9 – 9.2U)]

To identify the gas effect zone, quick look method has been applied by looking at

the log curve pattern. Then, proceed by checking the value of some parameter to doubled

check on the result from the quick look method. The result for both ways are quite

overlap on each other. The average Sw for each zone (9U – 9.2U) show the low value

which are from 26.9% to 48% . So the average Sw for this zone (oil zone) would be 32%

and it is quite possible to be Hydrocarbon zone as expected from the log pattern curve.

By considering the Apparent water resistivity, Rwa value is greater than the minimum

45

observed are likely to have some hydrocarbon saturation and it is confirm by the butterfly

effect from log curve observation.. In this zone, the neutron porosity is less than density

porosity indicated probably of gas zone.The average porosity for each zones which are

calculated by using weighted average method is from 21.4% to 26.1%. So, the average

porosity for gas effect zone would be around 23%. Based on the concept of cutoff, the

portion of the formation which is low porosity and would be non-productive need to be

eliminate. Therefore, for this gas effect zone, we just keep these zone (9U – 9.2U).The

average shale volume for gas effect zone is 47.5% which is quite high.Refer to cutoff

concept which is explained before, the portion of the formation which contains large

quantities of shale which is about Vcutoffs

≈ 20 to 30 % need to be eliminate.

ii. Oil zone [Depth 1470m – 1505m TVDSS ( 9.2U)]

From the log interpretation, indicated that Hydrocarbon probably present at this

interval. The assumption getting stronger when neutron log reading and density porosity

show just a slightly different between the 2 values which is indicated probably of oil

zone. Furthermore, the value of Rwa greater than the minimum observed are likely to

have hydrocarbon bearing. The average Sw at this interval also quite low which is

26.9%. The average shale volume for oil zone is 29%. The average porosity for zones

9.2 are is 26.1% which are calculated by using weighted average method. Based on the

concept of cutoff, the portion of the formation which is low porosity which is round 8%

need to be eliminated. So, this interval fulfills the requirement. As a conclusion, the

thickness of oil zone interval would be roughly around 35m.

ii. Water bearing [1520m-1570m TVDSS (9.2U)]

From the calculation of average water saturation,Sw obviously indicated that this

interval is water bearing zone because the value for average Sw is 92.1%. Supported by

the low value of Rwa at this interval. The zone with the lowest value of Rwa is the most

likely to be water bearing. The average porosity for water bearing 20.1% and the shale

volume show a quiet high value which is 51.7% and has high possibility to be eliminated.

46


Units STOIIP Percentage (%) GIIP Percentage (%)

Minimum

Most

Likely Maximum Minimum Most Likely Maximum

3.2 0.256 0.299 0.350 6.015 7.223 6.103

4.0 0.000 0.000 0.000 6.711 5.320 4.764

5.0 0.000 0.000 0.000 6.711 9.301 6.541

6.0 0.890 0.923 1.159 19.666 18.223 18.955

7.0 0.847 1.031 1.087 19.593 19.154 18.586

8.0 0.859 0.000 0.000 15.229 16.280 17.588

9.0 20.379 22.359 27.889 26.741 24.017 27.123

9.1 29.673 33.060 31.912 0.427 0.482 0.339

9.2 35.030 42.327 37.603 0.000 0.000 0.000

Table 3.9 Percentage distribution of STOIIP and GIIP by zones

It was identified that Unit 3.2 to 8.0 are potential gas bearing zones with high

GIIP and very low STOIIP (less than 0.5 MMSTB for Most Likely case). Three (3)

potential units are identified for oil development which are located in Zone 9, U9.0, U9.1

and U9.2. Zone 9 consist of approximately 75.45MMSTB which contributes to 97.4% of

the total cumulative STOIIP value. Zone U3.2 - 9.0 has higher GIIP storage as shown in

Table 3.9. However, the decision to produce gas will be based on Facilities Design and

Reservoir Development plan to identify the drive mechanisms for the field, as production

of gas from the mentioned units might in-turn, will affect the production of oil, which is

the main production plan.

The development strategy for the oil production will be analysed in term of

Reservoir Engineering prospect, and Economic Evaluation to determine the best

approach for production and development with highest net present value and recovery

factor. However for the Static Model’s STOIIP, the heterogeneity of the reservoir is

not taken into the manual calculation, thus the Dynamic Model in Reservoir

development might yield lower results of STOIIP for each units.

47

PHASE 4 RESERVOIR ENGINEERING

4.1 INTRODUCTION

In this chapter, the studies of reservoir engineering aspects are focused on

analyzing reservoir production performance, under current and future operating

conditions. Evaluation of present reservoir performance, followed by prediction of its

future performance is an essential aspect of the reservoir management process. Thus,

the given well test report, PVT and SCAL report is fully utilized in completing the

study.

The main output of this chapter is to come out with reservoir dynamic model with

the expected deliverables as follows;

a) Reservoir material balance for Oil In Place

b) Drive mechanisms

c) Well locations and number of wells

d) Production Profile

e) Recovery Profile

f) EOR Considerations

The completed reservoir model is an integration of static and dynamic

models which has the purpose of developing a reservoir characterization which can

reasonably represent the behavior of an inherently heterogeneous reservoir. It then

can be utilized with high reliability in predicting the reservoir performance in terms

of well rate, reservoir pressure and ultimate recovery. This process is highly

important as the economic viability of a petroleum recovery process is greatly

influenced by the production performance of a reservoir under current and future

operating conditions.

48

4.2 RESERVOIR CHARACTERISTIC

Gelama Merah has been subdivided into 10 zones namely U3.2, U4.0, U5.0, U6.0,

U7.0, U8.0, U9.0, U9.1, U9.2 and U10.0. Based on the static reservoir model, it is

found that only 3 zones (U9.0, U9.1 and U9.2) which have contained the possible

amount of oil to be recovered. Thus only the 3 zones are considered to be simulated

by Petrel and ECLIPSE in making dynamic models.

Table 4.1 :Reservoir Descriptions

49

All the salient points of reservoir characteristics are tabulated in table above.

These are the points which have been used as the key input in the reservoir simulator. It

should be noted that all the reservoirs are not communicating, slanted and reside side by

side of each other at depth ranging from 4470ft to 5220ft, and this conclude why all the 3

reservoirs has almost the same fluid properties as they are not differ much by depth and

rock quality.

4.3 RESERVOIR DATA

This section giving an overview about the important reservoir data required to construct

and run the reservoir model. These data include:

1) Rock properties from routine core analysis

2) SCAL data

3) Fluid data from PVT analysis

4) Production test data

4.3.1 Porosity Permeability Relationship

One of the methods used to assign the porosity values for the reservoir model is to

populate the porosity from the logging of well GM1 and ST1 in the reservoir model. The

permeability values have been assigned to the model from the porosity permeability

transform relationship figure 4.1 which was created from the routine core

analysis(RCAL) for (21) core plugs taken in the sand from sand 9.0 ,9.1 and 9.2. The

measured core permeabilities were in the range of <20md 20md<k<150md and >150md,

these measurements yielded this porosity permeability transforms:

For low quality rock: k= 0.005e 0.381Ø

For moderate quality rock: k= 21.09e 0.072Ø

And for good quality rock: k= 0.021e 0.287Ø

50

Then the permeabilities values were populated in the 3D grid by direct correspondence to

cell’s porosity value.

4.3.2 Vertical And Horizontal Permeability Transform

Vertical and horizontal permeability relationship has been created from the routine core

analysis. The ratio of core vertical to horizontal permeability is found to be 0.1.

Kv/Kh = 0.1

4.3.3 Relative Permeability

Three measurements/investigations were carried out in order to determine the relative

permeability data. These methods can be summarized as the following:

i. Steady state method under the gravity drainage conditions in an oil/gas system in

order to determine oil relative permeability

y = 0.021e 0.287x R² = 0.588

y = 21.09e 0.072x R² = 0.656

y = 0.005e 0.381x R² = 0.703

0.1

1

10

100

1000

10000

0 5 10 15 20 25 30 35 40

Porosity, Φ

Pe

rmea

bili

ty,

, k (m

D)

poor perm<50 md moderate perm 50<k>250 good perm k<250 Expon. (poor perm<50 md) Expon. (moderate perm 50<k>250) Expon. (good perm k<250)

Figure 4.1 : Porosity Permeability Transforms

51

ii. Steady state method was carried out in order to determine oil/water relative

permeability in the imbibition cycle

iii. Investigation of the effect of the oil/water viscosity ratio on residual oil saturation

Only four core plugs were taken from the reservoir sand. The steady state method was

run on all of the core plugs. Also steady state method was run on eight samples in order

to determine the relative permeability for the oil gas system.

Two methods were carried out to normalize the relative permeabilities curves:

Averaging method

Corey exponent method

The two methods almost showing the same result with average difference 0.002

4.3.4 Oil Water System

The steady state measurements showing oil end points relative permeabilities of 1.0 with

average also 1 (calculated using the averaging method). The water end point relative

permeabilities range from 0.269 to 0.368 with average value 0.319.

The Corey exponents were used are:

Oil phase: 3

Water phase: 2

The below figure 4.2 shows the normalization for oil water system

52

4.3.5 Gas-Oil System:

The steady state method measurements were carried out with connate water present.

These measurements showing oil end points relative permeabilities of 1.0 with average

value also 1.0. Corey exponent of 1.5 for gas and 1.9 for oil was assumed.

The figure below shows the normalization for gas oil system

Normalized USS Oil-water rel. perm curves

0

0.2

0.4

0.6

0.8

1

1.2

0 0.5 1 1.5

Water Sat, Sw

Rel

Pe

rm,

Kr

Kr

Krw* 2-017

Kro* 2-017

Krw* 3-005

Kro* 3-005

Krw* 3-015

Kro* 3-015

Krw* 2-015

Kro* 2-015

corey

Figure 4.2 : Normalized Oil Water Relative Permeability.

53

Then, the relative permeability (relperm) were denormalized according to the rock type

(porosity and permeability), and the 3 relperm table were created for 3 ranges of the

permeability (will be discuss later). Attempts have been made to make relationships to

create connate water saturation, residual oil saturation and the end points relative

permeabilities.

4.3.6 Denormalization Of Oil Water System:

Swc and porosity:

The connate water saturation was related to the porosity from the lab measurements as in

Figure 4.4 An attempt was made to create a relationship between connate water saturation

and the rock quality index (RQI) from the log, but no straight forward relationship was

found. The connate water saturation is related to the porosity using the following

relationship which is derived from the core data:

Normalized USS Gas-oil rel. perm curves

0

0.2

0.4

0.6

0.8

1

1.2

0 0.2 0.4 0.6 0.8 1 1.2 Water Sat, Sw

Rel

Perm

, K

r

Kr

Krg* 1-021 Kro* 1-021 Krg* 2-015 Kro* 2-015 Krg* 2-017 Kro* 2-017 Krg* 3-005 Kro* 3-005 Krg* 3-015 Kro* 3-015 Krg* 3-016 Kro* 3-016 Krg* 3-022 Kro* 3-022 Krg* 3-025 Kro* 3-025 cory corey oil

Figure 4.3 : Normalized Gas Oil Relative Permeability

54

Swc = -3.3994 phi + 1.3053

As shown in Figure 4.4

Porosity and krw relationship

A relationship between porosity and water relative permeability at residual oil saturation

was made from the lab data. The equation derived as the following:

krw (Sor) = 0.5181e-2.1229 phi


Connate Water Saturation versus Porosity

y = -3.3994x + 1.3053

R 2 = 0.9458

0.2

0.25

0.3

0.35

0.4

0.45

0.25 0.27 0.29 0.31 0.33 0.35

Porosity, Φ

Sw

c

c

Figure 4.4 : Swc And Porosity For Water Oil System

55

Porosity and Sor relationship

A relationship between porosity and residual oil saturation was made from the lab data.

The equation derived as the following:

Sor = 0.9278 phi - 0.0249


Sor versus porosity

y = 0.9278x - 0.0249 R 2 = 0.9705

0.2 0.21 0.22 0.23 0.24 0.25 0.26 0.27 0.28 0.29

0.25 0.26 0.27 0.28 0.29 0.3 0.31 0.32 0.33 0.34

Porosity, Φ

Resid

ua

l O

i, S

or

So

r

Krw at Sor versus porosity

y = 0.5181e -2.1229x

R 2 = 0.0488

0.1

1 0.25 0.27 0.29 0.31 0.33 0.35

Porosity, Φ

Krw

at

So

r

So

r

Figure 4.5 : Porosity And Krw Relationship For Oil Water System

Figure 4.6 : Porosity And Sor Relationship For Oil Water System

56

4.3.7 Denormalization Of Gas Oil System:

Permeability and Sgr

A relationship between permeability and residual gas saturation was made from the lab

data. The equation derived as the following:

Sgr = -0.0004k + 0.7196


Permeability and krg (Sgr )

A relationship between permeability and gas relative permeability at residual gas

saturation was made from the lab data. The equation derived as the following:

krg (Sgr ) = 0.0002k + 0.7187


Sgr versus k

y = -0.0004x + 0.7196 R 2 = 0.7976

0.4

0.45

0.5

0.55

0.6

0.65

0.7

0.75

0 200 400 600 800 1000 1200 1400

Permeability, k

Resid

ua

l G

as, S

gr

Sg

r

Figure 4.7 : Permeability And Sgr Relationship For Gas Oil System

57

4.3.8 Leverett J Function and the Capillary Pressure

Leverett J function method was used to correlate and interpolate capillary pressure data

from laboratory Measurements. J function has been calculated from the air mercury

injection data. The measurements made on core plugs taken from the reservoir sand and

MDT data, with permeability range of <20md 20 md<k<150 md and >150 md. J function

has been calculated using the following equation:

Where:

For lab system:

Pc: capillary pressure (Psi)

: Interfacial tension (for mercury system 480dyne/cm).

: Contact angle for (mercury system 140º).

: Permeability (MD).

0.2166( )

Pc KJ Sw

COS

K

Krg at Sgr versus k

y = 0.0002x + 0.7187 R 2 = 0.9683

0

0.2

0.4

0.6

0.8

1

1.2

0 500 1000 1500

Permeability, k

Krg

at

Sg

r

Sg

r

Figure 4.8 : Permeability And Sgr Relationship For Gas Oil System

58

: Porosity (fraction).

For the reservoir system:

: Interfacial tension (oil water system 25dyne/cm).

: Contact angle for (oil water system 30).

J (Sw): Leverett J function (dimensionless).

The below figure shows Leverett J function plot

Plotting of J (sw) versus Sw yielded the following equation which is used to calculate the

capillary pressure for the reservoir model.

J (sw) = 1041.4 Sw -1.8444

J function plot

y = 1041.4x -1.8444

R 2 = 0.8037

0

2

4

6

8

10

12

14

16

0 20 40 60 80 100 120

Sw (ppv)

J (

Sw

)

(Sw

)

Figure 4.9 : Leverett J Function

59

4.4 WELL TEST DATA

4.4.1 Production Tests

Production tests were carried out in well Gelama Merah-1 (DST-1) for unit 9

reservoir. The well test operation was carried out in three major flow event; Main

Flow Period, Main Build-Up and Maximum Flow Period. As one of the objectives in

conducting the production test, three sets of surface PVT samples were collected

during the stabilized Main Flow period. The sampling was taken during this period

because this is the best stage to characterize the reservoir fluid since the reservoir is

still virgin. Table 4.2 shows the summary of well test results.

Table 4.2: Summary of well test results

PERIOD Main

Flow Build Up Max Flow

Duration (hrs) 8 10 4

Choke ( /64”) 32 0 128

FBHP, psi @ 1496.1 m-MDRKB 1753 - 1479

FBHT, °F @ 1496.1 m-MDRKB 155 - 151

WHP, psi 390 - 156

WHT, °F 97 - 104

Separator P, psi 155 - 139

Separator T, °F 94 - 99

SIBHP, psi @ 1496.1 m-MDRKB - 2104 -

SIBHT, °F @ 1496.1 m-MDRKB - 154 -

Oil Rate, stb/d 1378 - 2745

Gas Rate, MMscf/d 0.16 - 0.73

Water Rate, stb/d 0 - 0

GOR, scf/stb 119 - 267

Gas Gravity, Air = 1 0.654 - 0.653

Oil Gravity, °API 23.7 - 23.6

H2S, ppm 0 - 0

CO2, % 0

0

BS&W, % 0

0

Note: Gas Rate measured during Main Flow period was incorrect. Estimated gas rate based on Nodal

Analysis is 0.37 MMscf/d.

60

4.3.2 Pressure Transient Analysis

Pressure transient analysis has been conducted based on the well test data

obtained during the well test operation. All pressure data was obtained from the

downhole pressure gauge. The interpretation was carried out using PIE-Well Test

Analysis software.

Figure 4.10 : GM-1 DST-1 well test interpretation

Figure above shows the log-log plot for the pressure transient analysis. The

log-log plot was then matched by using type curve analysis to get the best reservoir

model. After the model matched, the average permeability, kh product, wellbore

storage constant, and reservoir boundary is determined. From the plot, the best

pressure transient model represented is a homogeneous reservoir with wellbore

storage, skin an a constant pressure boundary.

Wellbore storage

regime

Transient regime

Pseudo steady-

state regime

61

In the derivative plot, the curve deviate downwards at the late time shows the

effect of constant pressure boundary. The constant pressure boudary is corresponds to

the OWC depth in 1508 mss. The radius of investigation for unit 8 Sand at the end of

the wellbore storage effect was estimated at 101 ft after 0.3 hour of shut in time. The

radius of investigation at the end of main build period or 9.6 hour of shut time was

about 669 ft.

Table 4.3 : Summary of Well Test Analysis on GM-1 DST-1

Properties Simulated Derivative

Wellbore storage, bbl/psi 0.00271

Permeability, mD 140

Kh, mD.ft 4130

Skin -2.1

Extrapolated Pressure, 2116

P*/Pi @ 1496.1 m-MDRKB, psi

Extrapolated Pressure,

2151 P*/Pi @ mid perf. , 1525.5 m-MDRKB, psi

(0.369 psi/ft pressure gradient)

+ x boundary, ft 236

From the pressure transient analysis in the given Well Test report, the well productivity

index was calculated by the software. The actual productiviy index is 3.4556258

STB/D/PSI and the ideal producitivity index is 2.4692214 STB/D/PSI. The calculated

skin pressure loss due to the skin effect is -159.30064 Psi. The flow efficiency is

1.3994800.

4.5 RESERVOIR FLUID STUDY (PVT ANALYSES)

Three sets of Gelama Merah field oil and gas separator samples were collected

during the stabilized Main Flow period of GM-1 DST #1 on 11th

January 2003. These

samples have been forwarded to PETRONAS Research & Scientific Services (PRSB)

Sdn. Bhd. for the Reservoir Fluid Study of GM-1 DST #1.

62

The routine PVT Analysis study for GM-1 DST #1 separator samples involves six

tests altogether. Those tests are:

Preliminary Quality Check (QC) Test

Compositional Analysis,

Constant Composition Expansion (CCE) Test

Differential Vaporisation (DV) Test

Viscosity Test

Separator Test.

4.5.1 Preliminary Quality Check (QC) Test

At the separator temperature, the opening pressures of the separator samples were

determined to check for the leakage. This is to ensure that only a representative samples

to be used in the analysis. The bubble point pressure of the separator oil samples was also

determined at the separator temperature.

Based on the opening pressure, the most representative set of samples was selected for

further analysis. Table 4.4 below summarizes the results of the Preliminary QC Test.

Table 4.4 : Quality Check of GM-1 Separator Samples

Type of sample Separator Oil Separator Gas

Cylinder no. 7990-

QA

7991-

QA

7989-

QA 4339 A 4553 A 4588 A

Opening pressure at

separator temperature, °F

Psig

105

@97.0

90

@97.2

100

@95.2

146

@97.0

150

@97.2

149

@95.2

Approximate sample volume

@ 1000 psig

Cc

553 593 536

20000

@ 146

psig

20000

@ 150

psig

20000

@ 149

psig

Bubble point pressure at

separator temperature, °F

Psig

120

@97.0

125

@97.2

140

@95.2 NA NA NA

Remarks

Pair

with

4339 A

Pair

with

4553 A

Pair

with

4588 A

Pair

with

7990-

QA

Pair

with

7991-

QA

Pair

with

7989-

QA

63

4.5.2 Compositional Analysis

A spike flash technique was used to carry out the compositional analysis whereby

the sample was flashed to atmospheric conditions to obtain stock tank gas and liquid at

equilibrium conditions. The evolved gas phase was circulated for sufficient period of

time for the oil and gas to achieve equilibrium. The gas oil ratio (GOR) was then

measured. Table 4.5 below summarizes the results for compositional analysis of the

separator oil and gas samples.

Table 4.5 : Compositional Analysis of GM-1 Separator Oil and Gas Samples and Calculated Wellstream

Composition

Component Mole % Molecular

weight

Density @

60°F Separator

Gas

Separator

Oil

Wellstream

N2

CO2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7

C8

C9

C10

C11+

3.16

2.78

87.79

5.75

0.41

0.05

0.05

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.05

0.27

3.52

0.88

0.21

0.44

0.40

0.16

0.24

0.48

3.45

4.74

5.48

9.89

69.79

0.57

0.69

17.54

1.69

0.25

0.37

0.34

0.14

0.20

0.40

2.88

3.95

4.57

8.25

58.24

195.39

0.821

TOTAL 100.00 100.00 100.00 Note: The wellstream composition was calculated based on GOR of 126 scf/stb.

The separator oil and gas were physically recombined to the gas oil ratio at

separator conditions to represent the reservoir fluid. From the separator oil and gas

composition, the composition of the recombination fluid was calculated by using the

separator GOR. The resulting fluid was then used for the remaining test program to

describe the fluid behavior in the reservoir.

64

The issue addressed is reservoir fluid (based on separator GOR of 126 scf/stb)

exhibited bubble point pressure of 1035 psia. This bubble point pressure was far below

from reported reservoir pressure of 2116 psia. Thus, by correlating with nearby saturated

reservoir, Sumandak Selatan-1, PRSS has adjusted the recombination ratio to the

specified bubble point pressure of 2028 psia. The obtained separator GOR is 256 scf/stb.

Table 4.6 above summarizes the results for compositional analysis of the reservoir fluid.

Table 4.6 : Compositional Analysis of GM-1 Stock Tank Oil and Gas and Calculated Wellstream Composition

(Adjusted Bubble Point Pressure to 2014 psig)


weight

Density @

60°F Stock

Tank

Gas

Stock

Tank

Oil

Wellstream

N2

CO2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7

C8

C9

C10

C11+

7.39

2.85

80.52

8.00

0.78

0.16

0.18

0.05

0.04

0.02

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.28

0.14

0.24

0.17

0.17

0.63

4.38

6.23

4.33

6.68

76.75

2.43

0.94

26.50

2.63

0.45

0.15

0.22

0.13

0.13

0.43

2.95

4.18

2.90

4.48

51.49

202.3

0.826

TOTAL 100.00 100.00 100.00 Note: The wellstream composition was calculated based on GOR of 326 scf/stb.

4.4.3 Constant Composition Expansion (CCE) Test

This test was performed to simulate the pressure-volume relation of the fluid.

CCE Test objectives are to determine the bubble point pressure, oil

compressibility and percentage of liquid volumes below bubble point. Table 4.6

below summarizes the CCE Test results.

65

Table 4.7 : GM-1 Constant Composition Expansion (CCE) Test at 155°F

Pressure

psig

Relative

Volume

V/Vsat

Single-Phase

Compressibility

V/V/psi

Y-Function Liquid

Volume

Percent

5000

4000

3500

3000

2700

2500

2300

2100

2014

2000

1800

1600

1400

1200

1000

800

0.976

0.983

0.987

0.990

0.993

0.994

0.995

0.997

1.000

1.002

1.034

1.074

1.127

1.197

1.297

1.446

-

7.096E-006

7.101E-006

7.127E-006

7.171E-006

7.192E-006

7.214E-006

7.226E-006

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

3.511

3.482

3.453

3.425

3.396

3.367

3.339

-

-

-

-

-

-

-

-

100.00

99.81

97.43

90.81

83.05

74.15

64.12

52.31

From the table shown above, the GM-1 reservoir temperature bubble point pressure is

determined as 2028 psia since it is the point where the value of relative volume is equal

to 1.000. From the Figure below, the physical trend shows the behavior of decreasing

relative volume over reduction of pressure. Thus, the data can be considerably good and

valid for analysis.

Figure 4.11: Relative volume at Deg F

0.9

1

1.1

1.2

1.3

1.4

1.5

0 1000 2000 3000 4000 5000 6000

Rela

tive V

olu

me, V

/Vsa

t

Pressure, Psig

Relative Volume vs Pressure

66

4.4.4 Differential Vaporization (DV) Test

In real cases, the gas liquid separation below bubble point in reservoir is a constant

changing system. In this differential vaporization test, the GM-1 sample was equilibrated

at bubble point pressure and reservoir temperature. The solution gas that is liberated from

an oil sample during a decline in pressure is continuously removed from contact with the

oil and before establishing equilibrium with the liquid phase.

From this test, the data that can be obtained include:

Amount of gas in solution as a function of pressure

The formation volume factor as a function of pressure

Properties of evolved gas including the composition of the liberated gas, the

gas compressibility factor, and the gas specific gravity

Density of the remaining oil as a function of pressure

Table below shows the summary of the Differential Vaporization test of Gelama Merah.

Table 4.8: GM-1 Differential Vaporisation (DV) Test at 155°F

Pressure

psig

Oil

Density

g/cc

Oil FVF

bbl/stb

Solution

GOR

Scf/stb

Gas FVF

cf/scf

Cumulativ

e Gas

Gravity

Z-

factor

5000

4000

3500

3000

2700

2500

2300

2100

2014

1600

1200

800

400

200

100

0

0.848

0.842

0.839

0.836

0.834

0.833

0.832

0.829

0.828

0.836

0.845

0.855

0.866

0.873

0.876

0.881

1.144

1.152

1.156

1.160

1.163

1.164

1.166

1.168

1.169

1.141

1.117

1.093

1.067

1.053

1.045

1.032

336

336

336

336

336

336

336

336

336

272

210

146

80

45

27

0

-

-

-

-

-

-

-

-

-

0.010

0.013

0.020

0.041

0.080

0.150

-

-

-

-

-

-

-

-

-

-

0.610

0.601

0.623

0.624

0.629

0.682

0.780

-

-

-

-

-

-

-

-

-

0.895

0.913

0.936

0.968

0.983

0.991

1.000 Note: 1. Density of residual oil @ 60°F = 0.909 g/cc.

2. API Gravity of residual oil @ 60°F = 24.16.

67

From Table 4.8, at above the bubble point pressure of 2014 psig, only one phase

exists in the reservoir which is liquid oil. This result indicates that reservoir is

undersaturated. Any gas dissolved in the oil above the bubble point of 2014 psia would

not increase the value GOR but remain constant at 336 scf/stb until the pressure drop

under bubble point). From Figure 4.12 below, as the pressure declines below bubble point

pressure, more and more gas is liberated from the saturated oil. Thus, solution GOR

continually decreases.

Figure 4.12 : GM-1 Solution GOR at 155 Deg F

Figure 4.13 below shows that oil formation volume factor (FVF) increases

slightly as the pressure is reduced from initial to the bubble point pressure. This effect is

simply due to liquid expansion. The expansion is relatively small since the single phase

compressibility of the reservoir is low. Below bubble point pressure, oil FVF steadily

declines with pressure as each reservoir volume of oil contains a smaller amount of

dissolved gas.

0

50

100

150

200

250

300

350

400

0 1000 2000 3000 4000 5000 6000

So

luti

on

GO

R, sc

f/st

b

Pressure, Psig

Solution GOR vs Pressure

68

Figure 4.13 : GM-1 Oil FVF at 155 Deg F

4.4.5 Viscosity Test

A viscosity measurement was performed on the oil at the reservoir temperature using the

Capillary Viscometer. At each pressure drop below the bubble point pressure, the

liberated gas was removed from the viscometer and its composition was analyzed using

the Gas Analyzer. The gas composition was then used to calculate the gas viscosity. The

Viscosity Test results are tabulated in Table 4.9 below.

Table 4.9 : GM-1 Oil and Gas Viscosity at 155°F

Pressure

Psig

Viscosity (cP) Oil/Gas

Viscosity Ratio Oil Gas

5000

4000

3000

2500

2014

1600

1200

800

400

200

100

1.7581

1.6066

1.4759

1.4020

1.3374

1.5105

1.6567

1.8453

2.0740

2.2157

2.3541

-

-

-

-

-

0.0152

0.0143

0.0136

0.0131

0.0128

0.0125

-

-

-

-

-

99

116

136

158

173

188

1.02

1.04

1.06

1.08

1.1

1.12

1.14

1.16

1.18

0 1000 2000 3000 4000 5000 6000

Oil

FV

F, b

bl/

stb

Pressure, Psig

Oil Formation Volume Factor vs Pressure

69

Figure 4.14 : Oil Viscosity at 155 Deg F

4.4.6 Separator Test

The test was conducted as three separate single stage separator test at specified separator

conditions:

Case 1 – at 890 psig and 87°F



The separator test objective is to determine the effect of separator pressure and

temperature on separator volume factor, GOR, oil and gas density and stock tank oil

gravity. Table 4.10 until Table 4.18 below summarizes the results of all the three cases of

GM-1 separator test accordingly.

Table 4.10 : GM-1 Single-Stage Separator Flash Analysis Case 1

Pressure

psia

Separator

Temperature

°F

GOR

scf/bbl

(1)

Separator

Volume

Factor

bbl/stb

(2)

Formation

Volume

Factor

bbl/stb

(3)

Stock

Tank

Oil

Gravity

°API

890 87 110 1.086 - -

to

0 60 193 1.000 1.119 23.32 Notes:

1. Cubic feet of gas at 14.73 psia, 60°F per barrel of oil at indicated pressure and temperature.

1

1.2

1.4

1.6

1.8

2

2.2

2.4

2.6

0 1000 2000 3000 4000 5000 6000

Vis

cosi

ty (

cP

)

Pressure, Psig

Oil Viscosity vs Pressure

70

2. Barrel of oil at indicated temperature and pressure per barrel of stock tank oil at 60°F.

3. Barrels of saturated oil at 2014 psig and 155°F per barrel of stock tank oil at 60°F.

Table 4.11 : Composition of the Liberated Gases Collected from GM-1 Single-Stage Separator Flash Test Case 1

Component Mole %

890 psig 0 psig

N2

CO2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7+

12.25

1.47

83.44

2.53

0.17

0.03

0.03

0.01

0.01

0.01

0.05

4.49

3.56

78.88

10.28

1.47

0.32

0.37

0.11

0.08

0.08

0.36

TOTAL 100.00 100.00

Molecular Weight 18.41 20.22

Specific Gravity 0.636 0.698

Calculated Gross

Heating Value

(BTU/scf of gas)

894.16 1045.26

Table 4.12 : Composition of Residual Oil from GM-1 Single-Stage Separator Flash Test Case 1


Weight

Density @

60°F

N2

CO2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7+

0.00

0.00

0.00

0.00

0.10

0.12

0.21

0.16

0.17

0.61

98.63

182.82

0.817

TOTAL 100.00

71

Table 4.13 : GM-1 Single-Stage Separator Flash Analysis Case 2

Pressure

psia

Separator

Temperatu

re

°F

GOR

scf/bbl

(1)

Separator Volume

Factor

bbl/stb

(2)

Formation

Volume Factor

bbl/stb

(3)

Stock Tank

Oil Gravity

°API

265 84 241 1.032 - -

to

0 60 60 1.000 1.116 23.41

Note:

1. Cubic feet of gas at 14.73 psia, 60°F per barrel of oil at indicated pressure and

temperature.




Component Mole %

265 psig 0 psig

N2

CO2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7+

8.73

2.21

84.04

4.48

0.34

0.05

0.05

0.01

0.01

0.01

0.06

2.61

4.99

71.49

17.03

2.36

0.42

0.46

0.12

0.09

0.09

0.36

TOTAL 100.00 100.00

Molecular Weight 18.55 21.68


Calculated Gross

Heating Value

(BTU/scf of gas)

940.76 1118.55

72



Weight

Density @ 60°F

N2

CO2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7+

0.00

0.00

0.00

0.00

0.12

0.16

0.26

0.17

0.18

0.62

98.48

183.10

0.818

TOTAL 100.00

Table 4.16: GM-1 Single-Stage Separator Flash Analysis Case 3

Pressure

psia

Separator

Temperature

°F

GOR

scf/bbl

(1)

Separator

Volume

Factor

bbl/stb

(2)

Formation

Volume

Factor

bbl/stb

(3)

Stock

Tank Oil

Gravity

°API

60 91 297 1.014 - -

to

0 60 9 1.000 1.117 23.36 Note:

1. Cubic feet of gas at 14.73 psia, 60°F per barrel of oil at indicated pressure and

temperature.



73


Component Mole %

60 psig 0 psig

N2

CO2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7+

7.65

2.69

81.34

6.81

0.81

0.16

0.18

0.05

0.04

0.05

0.23

2.82

4.58

74.52

14.70

1.95

0.37

0.41

0.11

0.08

0.08

0.36

TOTAL 100.00 100.00

Molecular

Weight

19.33 21.10


Calculated Gross

Heating Value

(BTU/scf of gas)

977.13 1094.73



Weight

Density

@ 60°F

N2

CO2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7+

0.00

0.00

0.00

0.00

0.26

0.14

0.24

0.25

0.37

0.83

97.91

184.16

0.823

TOTAL 100.00

74

Among the uncertainties involving GM-1 Reservoir Fluid Study are:

GM-1 PVT analysis laboratory experiments do not duplicate actual reservoir

process.

Liberation process in reservoir is considered approaching differential process.

Liberation process around GM-1 well is considered flash. Actual reservoir

process is neither flash nor differential.

Hence, a combination test may be assumed closest to the actual reservoir process based

on expected adjustments.

a) The data has been smoothed. The data taken are the best quality.

b) The bubble point has been adjusted to fit accordingly the reservoir conditions.

Table 4.19 summarizes the final results of GM-1 Reservoir Fluid Study.

Table 4.19 : GM-1 Reservoir Fluid Study Results Summary

Properties Value

Reservoir Pressure, psia 2116

Reservoir Temperature, °F 155

Bubble Point Pressure, psig 2014

Oil FVF, bbl/stb 1.169

Solution GOR, scf/stb 336

Oil Density, g/cc 0.828

75

4.6 RESERVES ESTIMATION

In estimating the hydrocarbon reserves, it involves a high degree of uncertainties

of which includes government regulations and unknown reservoir heterogeneity (Abdus

Satter, 2008). The accuracy of reserves estimation results is also dependent on the

amount of reliable geological, petrophysics and other engineering data available. Gelama

Merah’s geological model simulated in petrel has return a STOIIP value of 40.41 MMbbl

and has indicates a good agreement (within 1% difference) between the geological 3D

model (556,920 cells fine scale) and the upscaled dynamic model (21,700 cells). Ultimate

recovery is controlled by reservoir rock properties, fluid proper tries, heterogeneities and

more importantly reservoir natural energies. Gelama Merah’s ultimate recovery is

estimated around 19.5MMbbl with recovery factor of 47.8%. This value is satisfactory

after taking into account pressure maintenance scheme (1 water injection well) at the

early of production life and considering 5 deviated production wells.

4.7 MATERIAL BALANCE with MBAL

4.6.1 Energy Plot

Figure 4.15 : Energy Plot

76

It should be noted that the given result obtained by MBAL is a prediction. No

history matching was performed due to unavailability of any production data and the

reservoir simulation study was considering a green field development approach. Figure

4.15 shows the drive mechanism of the reservoir from 2008 until 2050. The energy plot

shows the relative contributions of the main source of energy in the reservoir and aquifer

systems along the history data time. The y-axis represents the percentage of the drive

mechanism while the x-axis represents time.

The red colored region represents the gas cap, while the blue colored represents

Fluid Expansion and the green colored represents PV Compressibility. From the energy

plot obtained, we can identify that the drive mechanism is dominated by fluid expansion

by the percentage of 70% out of the total mechanism assisted by water influx and gas gap

expansion.

4.6.2 Recovery Factor

Figure 4.16 : Oil recovery Factor vs. time plot

The blue plot represents the Oil recovery factor and the red plot represents the

Tank Pressure. From Figure 4.16, it shows that the maximum value of blue plot is

77

approximately 30%. Thus, this indicates the recovery factor of approximately 0.30.

Recovery factor (RF) is the estimate of recoverable oil/ reservoir oil in place (STOIIP)

and depends mainly on the reservoirs characteristics and the drive mechanism. Thus,

from recovery factor that we get, we are able calculate estimate of recoverable oil.

Recovery factor (RF) = estimate of recoverable oil/ reservoir oil in place (STOIIP).

Estimate of Recoverable Oil= Recovery Factor x reservoir oil in place (STOIIP).

= 0.30 x 76.83MMSTB (from Static Model)

= 23.05 MMSTB

Profit that we get is based on the Estimate of Recoverable Oil that we can gain

from the reservoir. Thus, the recovery factor is very crucial role to measure the profit we

acquired for the investment. Oil recovery factor varies from almost 0% to 80% and study

of International Energy Agency Oil reserves conference shows that Recovery factor

increases with oil-in-place: an average of 30% for the small fields (with a huge range

from 0% to more than 80%) and of 50% for the largest fields (range from 30% to 70%).

However, recovery factor can be improved due to new technology such as enhanced oil

recovery and also production optimization.

4.6.3 Production Profile Forecast

Figure 4.17 : Oil rate (STB/ day) vs. time plot

78

Figure 4.17 represents production profile forecast of Gelama Merah reservoir. The

blue plot represents oil rate and the red line represent Tank Pressure. From this graph, it

shows that the reservoir can give a highest flow, with a plateau rate of 2800bbl/day for

about nine years, 2008 until 2017. After that, the graft obtained shows the decline of

production rate over the time.

Table 4.20 : UR and Drive mechanism from MBal software

Estimate of Recoverable Oil 23.05 MMSTB

Drive Mechanism Fluid expansion (dominant) ,Gas cap

expansion and water influx

4.8 RESERVOIR SIMULATION STUDY

Reservoir simulation are widely used to study reservoir performance include the

analysis of different scenarios for estimating the applicability and recovery potential of

the most feasible recovery processes available for use within the property. Depending on

the level of detail required for a particular property evaluation, simulation studies can be

coupled with decision-risk and/or economic evaluation models. Reservoir simulators play

a very important role in modern reservoir management process and are used to develop a

reservoir management plan. This plan includes the ability to monitor and evaluate

reservoir performance during the life of the reservoir.

The simulation phase in this project is carried out mainly by using the ECLIPSE

100 and PETREL RE which are the oil and gas reservoir simulator originally developed

by Schlumberger. Reservoir simulators are classified in different approaches. But it is

commonly classified by the type of reservoir fluids being studied and the recovery

processes being modeled. The classification of the reservoir fluids include gas, black oil

and compositional simulators. ECLIPSE 100 has been specified for black oil reservoir. It

79

is used when the recovery process are not sensitive to compositional changes in the

reservoir fluids. In general, reservoir simulation process can be divided as follows;

1. Input Data Gathering: geological, reservoir, well completions, production,

injection, etc.

2. Data Validation: history matching, initialization, pressure match,

saturation match, etc.

3. Performance Prediction: existing operating and/or some alternative

development plan.

(Abdus Satter, 2008)

4.8.1 Objectives Of Simulation Study

Simulation study is planned to forecast the reservoir production performance and

to analyze the best development strategy which in turn will give the maximum recovery

of oil production of Gelama Merah. In order to complete the goals, following objectives

are expected to be achieved;

i. To determine the optimum number of wells and propose a suitable depletion

strategy

ii. To generate production profile and calculate reserves based on well potential.

iii. To develop a justifiable numerical simulation model to predict reservoir

performance.

The result of simulation study is highly important as it will be the main reference

or the main basis of other judgment for the next phase of this FDP.

4.8.2 Reservoir Model Set Up

The main simulators used for this field development project are Petrel and

Eclipse 100. The static model was develop by using Petrel and exported to Eclipse

100 for dynamic. All the data input required for simulation were defined in Petrel.

Most of the file that were exported to Eclipse 100 are in include file (.INC), which is

80

some value cannot be edited by Eclipse 100. In this model, all the reservoir properties

such as rock properties and fluid properties are first defined in the Main GLM model.

Figure 4.18 : GLM Base Case model

The main GLM model is like a tank model which contains all zones, (Zone

U3.0 until Zone U9.2) cover from gas zone to water zone. The model consists of 78

cells (west to east), 68 cells (north to south) and 105 cells thickness. This total grid

cells for this model is 556920 cells with total HCIIP of 76.83 MMSTB. After the

model redefined and took into consideration the interested zone (zone 9.0, zone 9.1

and zone 9.2) only, the model was divided into 3 development model, which namely

U9.0 Development Model, U9.1 Development Model and U9.2 Development Model.

81

Figure 4.19 : Development zone of GLM Base Case

All the properties for these models are summarized in Table 4.1 previously. The

reservoir simulation was run separately on these models, but the total production from

Gelama Merah field is the recombination from these entire models. All the well

engineering section required for the Eclipse 100 simulation, such as proposed well

path design and well completion were done in Petrel. The scheduling for development

strategy also done first done in Petrel before exported to Eclipse 100. The next

sections will discuss more on the development of the Gelama Merah field.

4.8.3 Well Placement

Suitable well target locations are determined by utilizing the completed dynamic

model. In ensuring the best strategic location is selected, few main reservoir criteria are

fulfilled as follows;

i. Area with high oil saturation

ii. Good rock quality in terms of permeability and porosity

iii. Clearance from OWC

iv. Away from fault

v. Representative of average reservoir properties

vi. Reservoir thickness

82

The well placement process is done according to the reservoir layer. Each reservoir

is carefully studied in order to choose the best well spots. Begin with reservoir 9.2, a 3D

view model which illustrates the oil saturation distribution is mapped by using PETREL.

The oil saturation properties is then summed up vertically within the grid cells (in k-

direction) and then averaged in order to determine the highest saturation point among the

grids cells. See Figure 4.20.

Figure 4.20 : Average Oil Saturation (Res. 9.2)

By only referring to the oil saturation to select the good well spots is not sufficient

as the ability of one reservoir to produce oil is also depending on reservoir rock quality.

This can be represented by Rock Quality Index (RQI) which is calculated by using

following equation;

(√ ⁄ )

Where ; Perm I = Permeability in x-direction

PHIE = Effective porosity of reservoir rocks

The equation above is plugged into PETREL, and RQI for each grid cells is then

calculated by the simulator program. The new reservoir property is then summed up

vertically and the average RQI value is mapped and illustrates by figure below.

83

Figure 4.21 : Average RQI (Res. 9.2)

As mentioned earlier, selection of well spots must take into account both RQI and

oil saturation. Thus in determining which area is good at both qualities, both averaged

RQI and oil saturation in each grid cells are multiplied with each other and mapped in the

reservoir model. And this is shows by figure below.

Figure 4.22 : Average So*RQI (Res. 9.2)

By using the Average So*RQI map in Figure 3, six initial wells namely P6, P7,

P8, P10, P11 and P12 are proposed at different reservoir locations in order to examine the

best drainage area. The wells are placed randomly within the area with high value of oil

saturation and RQI products which indicates good reservoir and fluid quality. Each of the

wells is then been run individually by using ECLIPSE 100 in order to analyze individual

84

performance of the well in response with well location. Figure below illustrates all the 6

well locations proposed initially.

Figure 4.23 : Individual Well Locations

Figure 4.24 : Cumulative Oil Production for Individual Well

85

Productive drainage area is indicated by ability of the well to produce the highest

oil recovery. By looking at the resulted graph shown in figure above, well P11 has shown

the highest recovery amongst all while P8 is the poorest. Drainage area at well P7 and

P12 has somehow shown the same production result and ranked as the second best area.

To determine the optimum number of wells per reservoir, creaming curve method

is applied. Creaming curve plots the total amount of oil discovery against the total

number of wildcat exploratory wells. In plotting the creaming curve, 6 simulation cases

namely Case A until Case F is run to get the total cumulative oil of each case of which

the number of wells is the variable of those cases. The list of cases, name of the wells

involved and oil cumulative production resulted from the simulation is tabulated in table

below.

Table 4.21 : Optimization of Number of Wells per Reservoir

Figure 4.25 : Creaming Curve

86

By using the oil production resulted from simulation run of each case, a creaming

curve is plotted against the number of wells involved in each case. Creaming curve in

figure above clearly shown that total oil production is increasing with the number of

wells and the trend is turned to plateau when number of wells has reached five. The

recovery is maximum when the reservoir has 5 and 6 wells. But lesser number of wells is

always preferred when the same amount of oil is contributed by both cases. Thus it can

be concluded that the optimum number of wells required in this particular reservoir (Res.

9.2) is five. The five well locations are also representing the best drainage area in the

reservoir. As for the other 2 reservoirs, 9.0 and 9.1, the same method is applied. And it

turned out that only 1 well is sufficient for each of the reservoirs.

Figure 4.26 : Optimum Well Location for Reservoir 9.0


87


4.8.4 Base Case Model

Base case model for all the three reservoirs is designed after the optimized well

numbers is known. The model is utilized within the entire project as the main reference

for the use of comparing with other simulation cases. Therefore, it must be properly

designed so that the outcome will be reliable. Table below summarized the input data

used in designing the base case model.

Table 4.22 : Input Data for Base Case Model

88

All the simulation base case has been run by ECLIPSE 100 to analyze the early

simulation results. By using the input data shown in the table, production profiles for

each reservoir are resulted as figure below.

Figure 4.29: Base Case Result for 9.0

Figure 4.30 : Base Case Result for 9.1

:

89

Figure 4.31 : Base Case Result for 9.2

Table 4.23 : Base Case Simulation Results

Table above summarized the base case results of the 3 layers. With the oil rate

control set as 600bbl/d, reservoir 9.2 has shown the largest oil cumulative production

which in total gives 2.6MMbbl recovery of oil with 14 years of producing life while the

plateau rate has recorded at 600bbl/d until the 11th

years. While reservoir 9.1 has

recorded the highest recovery factor (13.3%) and ironically gave the least amount of oil,

0.839 MMbbl. This is due to the least amount of OIIP it contained.

90

4.8.5 Reservoir Development Strategies Options

From the results from MBAL, it is identified that Gelama Merah has dominant

fluid expansion and gas cap drive mechanism while on the other hand, the aquifer support

is found to be weak. It should be noted that the gas cap layers above the reservoir are

assumed to be communicating with each other thus would form a bigger gas cap layer of

which gave large effects on reservoir drive mechanism. Type of drive mechanism

acquired plays very important roles in determining reservoir development strategies that

should be opt.

For a reservoir with big gas cap but small aquifer strength, it is preferably to

produce the oil column first without intruding the gas column. This is because the main

pressure support is coming from above (gas cap) and if the gas is determined to be

produced before oil, the reservoir might be losing its gas cap expansion pressure support.

As the gas being produced, reservoir pressure will be depleting and soon until it achieves

bubble point pressure, the oil column will be thinner and thinner due to gas which begins

to evolve out of solution. With continued production, the reservoir pressure would

decline further, producing appreciable quantities of gas that may eventually dominate the

multiphase flow of fluids in the reservoir. And this is not the condition that we would

want to happen. Losing the oil column to gas does not mean good in reservoir

development planning. Thus in order to maintain the pressure support by gas cap, it is

decided to produce the oil column first until it reaches the economical limits and just then

the gas cap will be considered to be produced.

Reservoir with big gas cap usually will results in 20-40% of oil recovery. But

looking at the base case results, the total production of the 3 reservoirs had resulted in

lower recovery factor which is 12.7%. With all the operating parameters have been

optimized, the low recovery factor is suspected due to insufficient pressure support. Thus,

initiation of an early pressure maintenance scheme may be necessary to maintain

reservoir pressure above the bubble point and circumvent gas evolution and its eventual

dominance in production. There are two types of pressure maintenance scheme being

91

considered, which either gas or water injection. These options are finalized after the

performance of both injection methods are analyzed in sensitivity analyses.

4.9 SENSITIVITY ANALYSES

Sensitivity analysis shows to what extent the viability of a project is influenced by

variations in major quantifiable. It is a technique used to investigate the impact of

changes in project variables on the base case. The purpose of doing sensitivity analysis is

to help to indentify the key variables which influence the project effectiveness.

It is also believed that the reservoir performance can be optimized by doing

sensitivity analyses based on the simulation base case result. Sensitivity analyses are also

performed to rank the importance of reservoir parameters which affecting production

performance. There are 6 parameters which have been sensitized in the simulation study,

which are pressure maintenance scheme, injection time, injection rate, and production

control mode as well as production life. By using the base case model, the parameters

mentioned is changed one by one in order to investigate which optimum values can

contribute to increase the recovery.

For the first sensitivity analysis, the RE team considered to use two type of well,

which are vertical and deviated well. For the base case, which is Case 1 was run by using

7 vertical wells, and Case 2 was run by using 5 deviated wells. The number of well for

Case 2 was reduced because deviated well can drain two determined target point from the

base case and it has more contact area with the reservoir. The result of this sensitivity

analysis shows that the Case 2 give better recovery and high cumulative production as

compare to base case. NPV analysis shows that Case 2 gives high net present value at

8.24 USD MM as compared to base case only 3.23 USD MM. Thus, for the rest of the

sensitivity analysis shall use the Case 2 for modification.

Second sensitivity analysis is on the pressure maintenance scheme. As the oil

production continues, the reservoir pressure will slowly deplete. The decrease in pressure

92

will affect the oil production. For the pressure maintenance scheme, two options to be

considered which Case 3 is for Gas Injection and Case 4 for Water Injection. Gas

injection is considered because of the availability of gas resource from the field

meanwhile water injection is the popular pressure maintenance scheme because it is

cheap and easy to handle. From the sensitivity analysis result, it shows that water

injection gives better oil recovery as compared to gas injection. Gas injection did not give

any improvement on the oil recovery. Thus, for NPV analysis, Case 4 shows an

improvement of 16.82 USB MM as compared to 8.24 USD MM for case 3.

After decide to use water injection as production maintenance scheme, the

injection can be done either Case 5; from the first day of production or Case 6; after the

production starts to deplete. This scenario is third sensitivity analysis. From the results,

injection from the first day shows better recovery as compare to after production

depleted. Injection from the first day can maintain the pressure longer; therefore the oil

recovery is higher. The NPV analysis also shows that case 6 gives high NPV value of

18.56 USD MM.

The next sensitivity analysis is on the injection rate. Injection rate is limited the

operation capacity of the injector well. Thus, optimum rate should be considered for the

injection to get optimum recovery within safety margin. Two cases to be considered,

Case 7 is 3780 bbl/d and Case 8 is 4716 bbl/d. the simulation result shows that the

increment of oil recovery from Case 8 is only 0.53%. From the NPV analysis, Case 8

gives high NPV value of 18.78 USD MM as compared to case 7, 18.56 USD MM, but

again, the increment is only about 0.22 USD MM. Therefore, case 7 were selected in this

analysis.

The fifth sensitivity analysis is on the production control mode. In this analysis,

only two control modes were considered, which Case 9 is for Oil rate Control Mode and

Case 10 for BHP Control Mode. From the result, control mode by using Oil rate gives

better recovery as compared to BHP control mode. For NPV analysis, case 9 gives high

NPV value of 18.56 USD MM as compared to case 10 which only gives 14.35 USD MM.

93

Last sensitivity analysis is on the production life. Case 11 was run for 14 years

and Case 12 was run 20 years. The result turn to be the Case 12 gives higher recovery

than Case 11. The NPV for case 12 is very much higher than case 11 which is 62.9 USD

MM over 16.82 USD MM for case 11. Therefore, the economic analysis will be done

base on the Case 12. This can be conclude that the Case 12 was run by using 5 deviated

wells, the reservoir pressure is maintain by using water injection which injected from first

day of production with injection rate of 3780 bbl/d and the production is control by oil

rate for 20 years.

Figure 4.32 : Summary of the sensitivity analysis flow work to determine the best development strategy.

0

10

20

30

40

50

60

Reco

very

Fa

cto

r, R

F (

%)

Comparison of Recovery Factor for all scenarios

94

Figure 4.33 : Sensitivity Analyses

95

4.9 PRODUCTION PROFILE

The following tables show the production forecast for Gelama Merah field. The

production forecast based on the best development strategy after several sensitivity

analyses has been carried out.

Table 4.24 : Production profile for Gelama Merah

Time Days Oil rate,

STB/D

Cumulative Oil

production, STB

Annual Oil

rate. STB/Y

1-Jan-11 365 7825 2856180 2621426

1-Jan-12 730 7825 5477606 2621426

1-Jan-13 1095 7697 8056404 2578797

1-Jan-14 1460 6606 10269659 2213255

1-Jan-15 1825 6095 12311659 2041999

1-Jan-16 2190 3791 13581731 1270071

1-Jan-17 2555 2761 14506995 925263

1-Jan-18 2920 2503 15345809 838814

1-Jan-19 3285 2422 16157277 811467

1-Jan-20 3650 2397 16960391 803113

1-Jan-21 4015 2384 17759060 798669

1-Jan-22 4380 1967 18418200 659140

1-Jan-23 4745 1003 18754430 336229

1-Jan-24 5110 676 18981077 226646

1-Jan-25 5475 578 19174885 193807

1-Jan-26 5840 395 19307355 132470

1-Jan-27 6205 308 19410831 103476

1-Jan-28 6570 272 19502063 91231

1-Jan-29 6935 225 19577700 75637

1-Jan-30 7300 167 19633935 56234

96

Figure 4.34 : Daily oil production rate for selected development strategy for GM-1 field

Figure 4.35 : Total cumulative oil production for selected development strategy for GM-1 field

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

1-J

an-1

1

1-J

an-1

2

1-J

an-1

3

1-J

an-1

4

1-J

an-1

5

1-J

an-1

6

1-J

an-1

7

1-J

an-1

8

1-J

an-1

9

1-J

an-2

0

1-J

an-2

1

1-J

an-2

2

1-J

an-2

3

1-J

an-2

4

1-J

an-2

5

1-J

an-2

6

1-J

an-2

7

1-J

an-2

8

1-J

an-2

9

1-J

an-3

0

FO

PR

, S

TB

/D

Date

Field Oil Production Rate for

selected development strategy

0

5000000

10000000

15000000

20000000

25000000

0 1000 2000 3000 4000 5000 6000 7000 8000

FO

PT

, S

TB

Days

Cumulative Oil Production for

selected development strategy

97

4.10 EOR CONSIDERATION

In a field development project, it is always wise to early consider the feasible

EOR plan that might be applied to one reservoir. This will anticipate the recovery

planning of unrecoverable oil during the natural depletion phase.EOR projects typically

require a large amount of capital investment and operating expense, besides having low

incremental production over a long period of time. In addition, uncertainties in technical

data could impact the EOR process assessment. It is imperative that a disciplined process

is used for EOR evaluation to ensure technical uncertainties and risks are appropriately

identified and managed to support investment decisions.

Gelama Merah was screened for potential EOR application. Among the key

reservoir and fluid properties for EOR process screening assessment are the crude oil

quality, reservoir temperature, and reservoir pressure. In general, Gelama Merah

reservoirs contain high-quality light oil with typical gravity of 23.7 API, and favorable

viscosity and waterflood mobility ratio. The basin reservoir temperature is about 155 F.

The reservoir pressure is about 2166 psia psia. A more complete list of reservoir and fluid

properties of the Gelama Merah Basin fields is shown in Table 4.25.

Table 4.25 : Reservoir and Fluid properties for Gelama Merah.

Property Value

Oil Gravity o API 23.7

Reservoir Temperature, o

F 155 F

Original Reservoir Pressure, psia 2116 psia

Oil viscosity, cp 1.337 CP

Solution Gas GOR, SCF/ STB 336 scf/stb

Porosity, fraction 0.27

Hotizontal Permeability, md 140 mD

Reservoir Depth, ft 1272.76 ft

Residual Oil Saturation 0.56

It should be noted that this work illustrates manual EOR assessment process,

starting with initial screening of appropriate EOR processes, followed by detailed

98

reservoir simulation evaluation of EOR process options supported by scoping cost

estimating of full-field facilities development.

Published and in-house screening guidelines were used to quickly identify

potential EOR processes for Gelama Merah reservoirs. The EOR processes that were

considered for screening are broadly categorized as follows:

1. Immiscible Gas flooding/injection methods (using readily available hydrocarbon

gas)

2. Water Flooding.

3. Water alternating Gas (WAG)

4. Improved water flooding methods using chemical (polymer and surfactant)

methods

The results of the manual screening work indicated that Water Flooding,

Immiscible Gas Flooding and Water-alternating-gas (WAG) are the promising EOR

processes, which are suitable and meet the criteria in order to be implemented at Gelama

Merah. Table 4.26, 4.27 and 4.28 show the technical screening guides for each method.

Paper reviews have been conducted to screen Gelama Merah’s reservoir fluid and

rock properties. Screening data covered from successful cases of Water Flooding,

Immiscible Gas Flooding and WAG mainly from world wide application. Gelama Merah

field has meet the criteria of having sandstone formation, net thickness less than 100ft

(29.5ft), good quality of sands (>27%porosity, 140md) and low oil viscosity (1.337cp). In

the criteria of reservoir fluid properties, initial reservoir pressure (2116psi. Besides, 23.7

API is reasonable value (higher than preferred value, >23), and it is pre-flooded with

water. In additional, Gelama Merah field has abundance of gas and availability of water

and gas injection facilities. This factor increase better cash flow for Water, immiscible

Gas flooding and WAG project in Gelama Merah field.

99

Finally, based on theory and literature review, result obtained show that Water

Alternating Gas (WAG) process using readily available hydrocarbon gas is the most

feasible EOR for Gelama Merah compare with only single EOR method such as Water or

Immiscible Gas Flooding. This method really suit and applicable with Malay Basin

environment, which is offshore base. In fact, WAG already pilot tested in several

reservoir in Malay basin such as in Dulang Field.

In addition, this WAG Injection is complete with all the EOR principles include:

i. Overcome the disadvantages of Water Flooding and Gas injection, as they are in

the single EOR method. One of the disadvantages of Gas Injection is it has poor

macroscopic sweep efficiency due to the fingering effects. By applying water

flooding after the gas injection alternately through WAG process, it can reduce

the potential of fingering effects from occurs by lowering the gas mobility ratio.

This is also can improve the sweep efficiency.

ii. Improve the Mobility Ratio, because the combined mobility ratio between gas and

water is less than the mobility ratio if the gas is injected alone.

iii. Reduces the instability of the gas-oil displacement process due to the relative

permeability effects, thus improving overall sweep efficiency.

iv. WAG can control the fluid profile. The higher microscopic displacement

efficiency of gas combined with the better macroscopic sweep efficiency of water

significantly increases the incremental oil production over the plain water flood.

v. Water flooding is relatively cheap, thus it can reduce the cost by minimizing the

volume of gas to be injected through WAG, since the gas will not be injected for

the whole time, but water will also be injected alternately.

Unlike Thermal and Chemical EOR, WAG is far cheaper and economical. Reported,

total cost of WAG Injection is around $25-$30 cost produce per barrel. At the current oil

price, which is $73 per barrel, this would still offer a reasonable profitable. Thus, this

method is the ultimate EOR in Gelama Merah and should be implemented during

depletion year. However, due to the lack of data, result obtained by reservoir simulation

only for Water Flooding and Immiscible Gas Flooding. The result show below:

100

Table 4.26 : Technical Screening Guides for Immiscible Gas flooding

IMMISCIBLE GAS FLOODING - RECOMMENDED

Gravity o API >12

Viscosity, cp < 600

Composition not critical

Oil Saturation, % PV >0.35 to 0.70

Type of formation Sandstone or carbonate, with few fractures and high

permeability streaks

Average Permeability Not critical

Depth, ft Depth must great enough to allow injection pressure

greater than MMP, >1800

Temperature, F Not critical

Table 4.27 : Technical Screening Guides for Water Flooding

WATER FLOODING - RECOMMENDED

Gravity o API <20

Viscosity, cp Low viscous

Composition High percentage of light hydrocarbon

Oil Saturation, % PV >40




Depth, ft Not critical


Table 4.28 : Technical Screening Guides for Water Alternating Gas (WAG)

WATER ALTERNATING GAS (WAG) - RECOMMENDED

Gravity o API >15

Viscosity, cp <0.4

Composition High percentage of light hydrocarbon

Oil Saturation, % PV >40




Depth, ft Depth must great enough to allow injection pressure

greater than MMP


101

PHASE 5 PRODUCTION TECHNOLOGY

5.1 INTRODUCTION

Five (5) drainage points have been identified to achieve a plateau production rate

of 5000 bbl/day based on the results of reservoir simulation model. The MDT survey of

the Gelama Merah shows that all sand units are in the same pressure system in a

homogeneous character. The producers and injectors will be completed as single string

and unit, 9.0, 9.1 & 9.2 will be produced separately. Different sand exclusion techniques

are considered and is modeled with the slotted liner selection chosen as per discussed in

this section.. It has been identified that there will be no immediate need of artificial lift

from the initial production at the field but the wells ceases to flow at early water cut

therefore, considerations for future artificial lifting will be included to facilitate future

need when reservoir pressure has declined with increasing water cut.

Well Name Well Type Perforated Sand Remarks

GMJT-01A Deviated Unit 9.2 Single oil producer



GMJT-04B Horizontal Unit 9.1 Single oil producer

GMJT-05C Deviated Unit 9.0 Single oil producer

GMJT-WI Vertical Unit 9.3 Single water injector

Table 5.1 Completion strings summary for Gelama Merah

5.2 SAND CONTROL STRATEGIES

5.2.1 Sand Condition Analysis

Predicting that a reservoir will produce at some point in a well’s life is possible by

analyzing core samples in laboratory to obtain the detail on the composition of the rock.

The core analysis for the core samples from Gelama Merah-1 indicates that the Gelama

Merah area formations are un-uniformed and has high percentage of fine particles.

Besides it can also be concluded that the formation grains in the area are poorly sorted.

102

Referring to the well test result from Gelama Merah-1 as well, no sand production

were observed from the reading and sample taken. The water rate from the main flow and

max flow are both showing 0 stb/d with BS&W of 0%. Although the well test result gives

a contradicting information on the sand production, there might be some explanation to it.

The fine particles of sand might not be produced because the water was not produced,

thus no drag force to cause near wellbore sand grain migration. Therefore, this means that,

sand production will occur at higher drawdown pressure. Having a production rate of

approximately 800-1000 bbl/d for each well, lowering the drawdown or production rate

to reduce the sand production would not be a preferable option to be taken.

Based on analogy to PCSB’s field development strategy, sand exclusion is

required where sonic transit time is above 100 μs/ft. The sonic transit time vs Depth for

Gelama Merah is shown in Figure 5.1 and is between 110-125 μs/ft, which is higher than

threshold value of 100 μs/ft. Hence, sand exclusion is proposed for all completions.

Sonic Transit Time Vs Depth

4300

4400

4500

4600

4700

4800

4900

5000

5100

405060708090100110120130140

DTCOMP (US/FT)

Dep

th (

FT

)

Sonic Transit Vs Depth

Unit-6

Unit-7.0

Unit-8.0

Unit-9.0

Unit-9.1

Linear (Unit-6)

Linear (Unit-7.0)

Linear (Unit-8.0)

Linear (Unit-9.0)

Linear (Unit-9.1)

Figure 5.1

Depth vs Sonic Transit Time for

Gelama Merah-1

103

5.2.2 Bottomhole Completion Options

From the well test data and core analysis report, it is known that the formation is

unconsolidated and potential to produce sand when water production begins as per

discussed in the previous section. Having cased hole completion would provide

additional CAPEX towards total development due to material and time consideration.

The proposed well (discussed below) is deviated wells, thus it may reduce the skin

contributed by the higher velocity of sand particles entering towards the sand screen from

the casing, which has possibility of causing erosion and plugging towards the screen or

gravel packs. However, due to moderate flow rate (1000-1500 bbl/d) this would not post

a severe issue, unless the well is big oil producer such as in the Middle East where

production ranges 5000-10000 bbl/d. Slotted liner completion with partial isolation can

provide guard against hole collapse and also convenient path to insert various tools such

as coiled tubing in the future stages.

5.2.3 Sand Control Methods

There are three options to control the sand production downhole which are gravel

pack, stand alone sand screen and slotted liner. Some justifications of selecting the slotted

liner over stand alone sand screen and gravel pack are as follows.

(as shown in Table 5.2):

i. Gravel packing requires relatively large wellbore diameter to achieve required

throughbore which significantly requires larger size casing in upper section.

ii. Gravel packing is operationally more difficult, time consuming and expensive in

horizontal or deviated wells which increases cost of installation phase.

iii. Ineffective pre-packing in high inclinations due to gravity effect leads to poor

production performance and high completion skin due to rapid clogging and

plugging of internal gravel packing due to un-uniform compaction gravel media.

iv. The liner and sandscreen are able to give good sand retention performance in

open hole unconsolidated formation. (small or no-annulus between screen and

formation) . Small annulus behind the sand screen can naturally form a higher

104

permeable layer and allow more uniform velocities of fluid entering the

wellbore to reduce the erosion factor.

v. In terms of borehole stability, the liner and sand screen installation which

consists of slotted pipe will give stability and control to the well bore. It can

hold the hole section stability and prevent it from collapse. In the open hole

section, it is difficult for elastomer in the external gravel pack system to swell

towards the shale hence resulting to imperfect sealing. This will lead to high

possibility of well collapse to take place.

ITEM

SLOTTED

LINER

(Mild Steel)

WIRE WRAPPED

SCREEN

(Stainless Steel)

PRE-PACKED

SCREEN

Resin Coated Sand

Description Rectilinear slots/

machined in pipe

Wire welded to longitudinal

rods

Gravel sandwiched

between two wire

wrapped screens

Concept

Wellbore

reinforcement,

sand bridges

around slots

Formation sand exclusion

or gravel retention

Gravel provide sand

exclusion

Material Mild steel Stainless steel on mild steel

base pipe

Stainless steel on mild

steel base pipe

Sand

Exclusion

Poor: 0.012” slot

width minimum

Better than slotted liner

since slot width 0.006” –

0.040”

Excellent: as with

gravel pack

Works with

gravel pack Yes Yes

Yes, but should not be

necessary

Flow

restriction High

Low, = 10 times flow area

of slotted liner

High, as for wire

wrapped screen

Mechanical

resistance Good

Poor to collapse/tension if

base pipe omitted. Also

susceptible to erosion

Fair: base pipe

reinforces structure

Plugging

tendency

Low (Too wide

to retain to

formation sand)

Moderate

High: Fine + mud

cake. Also impairment

while RIH

Cost Cheapest 2 -3 x slotted liner

2 – 3 x wire wrapped

screen, but often less

than gravel pack

Application

Borehole

reinforcement

coarse grained

formation

High productivity wells

medium grained formation.

Allows fines production

Retains sand grains of

all sizes

Table 5.21 Comparison between Slotted Liner, WWS and Gravel Pack

105

5.2.4 Types of Slotted Liner Patterns

A slotted liner completion simply employs some type of screen or liner positioned

inside a productive interval. From the core analysis result, the Gelama Merah field has a

concern on producing high percentage of fine particles. The optimum screening opening

size should be approximately 120-150 microns range based on the particle size from 42

cores tested. The 4 sand screen options proposed for this field are:

1. Spiral Welded Liner (SWL)

2. Compound Grading Sand Control Screen (CGS) on Liner

3. Continuous Wire Wrapped Sand Control (CWWS)

4. Expandable Slotted Liner (ESL) with Partial Completion

5.2.4.1 Spiral Welded Liner

The spiral welded stainless steel filter tube acts as an anti-sand filter blocks, with

straight seam welded stainless steel filter tubes. The perforated seam is welded in straight

line, with unique spiral distribution formed by spiral welding and greater filter strength.

The advantage of this screen is with the external pressure from the wellbore, the forced

part will have a reduced or closed gap in the pipe to ensure reliability of sand

retention.For wells containing H2S, CO2, high-Cl that has special requirements, the

center tube can be corrosion-resistant casing or tubing. Screen is acid and alkali resistant

and salt corrosion resistant.

5.2.4.2 Compound Grading Sand Control Screen (CGS) on Liner

Compound Grading Sand Control Screen has adopted unique grade sand control

with the surface filter and deep filter combined together to form a double precision.

During transport, the protection cover can protect the grade sand control filter layer,

protect the sand control filter layer from punctured or damaged during the procedure of

entering the well. In the oil and gas wells production, using of it can effectively prevent

106

the direct erosion and damage of the fluid to the grade sand control filter layer and it can

extend the service life of screen.

5.2.4.3 Continuous Wire Wrapped Sand Control (CWWS)

Continuous slot screen is manufactured by wrapping a shaped wire around an

internal array of longitudinal rods. The wire and rod, made from carbon or stainless steel

are joined by resistance welding. Continuous slot screens are very effective in relatively

shallow, thin aquifer that was prolific in term of water productions. Wells of this type are

reliable since they can be manufactured with very small slot size and yet maintain the

necessary open area to minimize the friction head loss. Most continuous wire wrap screen

is manufactured from stainless steel rather than carbon steel in order to avoid problems

which often lead to accelerated corrosion.

5.2.4.3 Expandable Slotted Liner (ESL) with Partial Isolation

For wells with multizone injectors, the completion type must offer sand control

and injectivity capability of an openhole completion coupled with the selectivity of a

cased hole completion. The liners are perforated where holes are drilled in the liner, also

known as prepacked liner. To reduce the susceptibility to plugging, the diameter of the

screen should provide minium area for the annular section. For partial isolation, the

external casing packers (ECPS) have been installed outside the slotted liner to divide long

horizontal wellbore into smaller sections for future simulation and production control.

5.2.5 Sand Control Design Selections

Main priority in sand control design selection is to apply the sand retention

system that will not reduce or impact the producing well’s productivity. This will

basically allow the improved production rate given the similar pressure drop across the

sandface. Gravel packing can also be successful in stronger zones, but it becomes more

expensive and more technically difficult in longer horizontal wellbores.

107

Four options were proposed in the previous section. Slotted liners are the least

expensive and with large diameter prepacked screens may be the best filters, depending

on the design.. Wire wrapped screens are normally best for gravel packing when wire

spacing is sized to stop gravel; and premium screens, with their micron-size openings, are

designed as downhole filters to stop all of the formation sand. All the sand screens are

able to give good sand retention performance in the Gelama Merah unconsolidated

formation.

All four liner patterns (SWP, CWWS, ESS and CGS) are able to provide good

retention of sand in open hole in Gelama Merah’s unconsolidated formations.

For the ESL, elimination of the annulus will provide better isolation sections or to

squeeze treatment fluids into formation in future optimization works.

The ESL also enhances the production log reading because flow from the reservoir

will enter directly through the screen and into the wellbore rather than along the

annulus compared to CWWS, SWL and CGS.

If an ESL could be expanded to sit on the wellbore face, there would be a dramatic

reduction the ability of sand particles to move around under producing conditions.

Tight fittings of the ESLwill provide stabilization characteristics of a well-packed

gravel pack at a lower cost and faster installation.

The recommended selection of ESL with partial isolation with blank pipe and

swellable packers set up would be a preferable option due to its economic and borehole

stability advantages for openhole completion selection compared to a production casing

installation and stand alone sandscreen on oil well producers for the Gelama Merah

development plan. For future production optimization on additional perforation, the in-

tubing stratacoil can also be used to be fitted inside the 3-1/2” single string tubings.

108

5.3 PRODUCTION OPTIMIZATION

5.3.1 Inflow Performance Prediction

For the test point data from Gelama Merah-1 well test report, the main flow data

were used which are 1753.0psia and 1378.0STB/day. The layer pressure for the zone of

interested is taken for the average (middle depth) of the GOC and WOC which is at

2133.5psia and bottomhole temperature of 155˚F. The mid-perft depth is set to be 5150 ft

MDRKB where the RKB is 89.57ft (27.3m) above the mean sea level (MSL). The

effective permeability used is 140mD with total Darcy skin of 0 even thought the skin is

-2.1 from well test. The negative skin may be contributed from successful underbalanced

perforation jobs (debris were flowed out instead of plugging the perforated holes due to

lower hydrostatic pressure).

The IPR model used is Vogel for two phase flow correlation. This generates the

productivity index (J) of 3.8267 Stb/day/psi and absolute open flow (AOF) of 4631.3

Stb/day for matching with the development plans. For the circular drainage area, the

Dietz shape factor of 31.620, this is because the wellbore is assumed to be circular and

tubing in the centered. The option of psedo-radial flow is selected with the given

wellbore radius of 4.344”. The Vasquez-Beggs correlation is used for the gas solution,

bubble point pressure and formation volume factor, while Beggs et al and Carr et al has

been chosen to represent the vertical flow correlation for Gelama Merah field.

Figure 5.2 Inflow Performance of test data points

109

5.3.2 Optimum Tubing Size Selection

*Refer to Appendix for Flow Capacity screenshots

Tubing ID

(inches)

Operating

Pressure (psia)

Oil Rate

(STB/Day)

Water

Rate

(STB/day)

Gas Rate

(MMSCF/day)

4.500 1732.671 1444.847 0 0.386

3.500 1725.604 1467.954 0 0.392

2.875 1735.951 1434.123 0 0.383

2.375 1764.683 1338.728 0 0.357

For the single string completions, the tubing size options available are 4.5”, 3.5”,

2.875”, and 2.375”, depending on the wellbore configuration and inflow-outflow

requirements. From Table 5.3, Wellflo modeling and historical experience has shown

that tubing sizes are larger than 3.5”. are not required or justified for conventional

completion. Typically, 3.5” tubing is optimum for the range of production rates expected

over the life cycle of the well at 1468stb/d compared to 4-1/2” production of 1444.8stb/d

at zero water cut and constant GOR of 267 SCF/STB. However, producing at 600stb/d –

1500stb/d, it is advisable to use a smaller tubing size at 2.875”, because the production

may decline over years. Tubing size of 3.5” will be too big when the production rate

declines below 800 stb/d.

Generally the tubing size is constrained by well design and 2.875” tubing is

favored over smaller sizes, when well casing and liner sizes allow, due to wireline tool

clearance issues and triaxial strength limitations of smaller tubulars. Combination tubing

strings, with 3.5” x 2.375”, or 3.5” x 2.875”. are often run for wells with liners, as

required by completion equipment. It is recommended to use 2.875” tubing for oil

producers in Gelama Merah based on Wellflo results.

Table 5.3 Production data with various tubing sizes for base case from GM-1

exploration well

110

5.3.3 Gas Lift Method Justifications

Gas lift method is widely used in Malaysia offshore because it is cost effective,

easy to implement, very effective in wide range of operating conditions and requires

small footprint in the offshore settings with only space for the compressor unit. However,

initial completion plan with tubing having side pocket mandrels at desired depth are

required to save workover cost in the future. When comparing the gas lift design for

Gelama Merah, the production rate in the later stages, it provides a higher rate compared

to the natural flow as it slowly dies off. There are other 3 commonly used artificial lift

methods which are electrical submersible pump (ESP), beam pumping and hydraulic

pumping. The justifications for gas lift method are as below.

i. Longer economic/operating life

Historically, for Malaysia offshore operations, the ESP can last for 3-6 years

before they are required to be changed and maintained. For GLV, they can be

used to a useful life of 10-20 years, and most of the time, damage only occurs

at the leakage of O-rings. This can be maintained by wireline routine jobs to

retrieve the valves and replacing new O-rings with is very low in cost

relatively compared to a new ESP. A new GLV would normally cost

approximately RM16,000-22,000.

ii. Tubing Size Limitation

The tubing that is proposed is to be 3.5” ID. For GLV, they are mainly

installed on the gas lift mandrels allocated along with the tubing, thus tubing

sizes does not pose a problem, providing there is gas supply and pump

available on the surface. However for ESP, hydraulic pump and sucker rod,

the minimum tubing diameter required would be approximately 4.5” OD

which is equivalent to 4.0” ID. Thus for the production at Gelama Merah, the

ESP, hydraulic pump and beam pump are less likely feasible to be operational.

iii. Highly deviated wells

111

In highly deviated wells, it is difficult to deploy pumping system due to

potential mechanical damage to deploy electrical cables. In addition, GLV can

be deployed at the vertical section of the horizontal wells.

iv. Production rate of field with artificial lift method

ESP may be the best artificial lift method in the world at current stage where

almost 70% of the world oil production are from the utilization of ESP.

However the production are most often for high production wells ranging

from 1000-64000 Stb./day. Since for Gelama Merah, we are only producing at

the range of 1000-2000 Stb/day, it would not be economical for ESP

utilization in the field since there is a higher capital and maintenance cost

involved, where having a gas lift on site would be sufficient to produce.

Approximately 15-20% of almost one million wells worldwide are pumped

employing the ESP method. In addition ESP systems are the fastest growing form of

artificial lift pumping technology but they are often considered high volume and depth

champions among oil field lift systems. In Sabah Operations (SBO) under PETRONAS

CARIGALI, almost 95% of the strings are utilizing the gas lift method as the artificial

method selection and only a few utilizing the ESP due to low production of less than

5000 Stb/day for relatively all the wells in Sabah Basin area.

5.3.4 Gas Lift Design

Once a well that is producing liquids along with the gas reaches the stage in

which it will no longer flow naturally, it will usually be placed on artificial lift. The

purpose of injecting gas into the tubing is to decrease the density of the flowing gas liquid

mixture and therefore decreasing the required flowing bottomhole pressure.

For the gas lift design, a maximum casing head pressure of 1400.0 psia is selected

with the operating casing head pressure of 1300.0psia. The gas lift valve differential

pressure is set to 150.0psia which is a common practice in oil and gas companies. For

Gelama Merah wells, only 3 gas lift valves are required during the design. The 4th

gas lift

valve would not be required due to the production rate given in the well test. For the 3

112

valves to be set at their optimum depth, the liquid production rate is found to be at only

700-800 Stb/day with choke size of 20/64. If the liquid production is set higher the

unloading sequence for the pressure will be below the pressure of the operating pressure

of the objective production. Therefore, at the rate of 700-800 Stb/day, the 3 gas lift

valves’s unloading sequence matches the production profile and also the maximum

casing head pressure and operating casing head pressure plot against depth.

Table 5.4 shows the gas lift valves setting depths and specifications. Three gas

lift valves were selected, consisting of 2 IPO valves for loading purposes and 1 Orifice

valve for gas to be injected for gas lift purposes. For GMJT-02A, 04B and 05C, only 1

unloading IPO valve is required, which may due to the initial high GOR from the

production.

Type

GLV 1# GLV 2# GLV 3#

IPO Valve IPO Valve Orifice

Size 1.5 1.5 -

Setting Depth, MD ft

GMJT-01A 1200 2300 2915

GMJT-02A 1200 n/a 1950

GMJT-03A 1300 2500 3125

GMJT-04B 1000 n/a 1860

GMJT-05C 1250 n/a 2175

5.3.5 Tubing Performance with increasing water cut (WC%)

Water cut is the percentage of the water produced from the total fluid. Hence, the

higher the percentage of the water cut, the most unlikely the performance of the well will

be. This is because it indicates that more water are being produced from the well. For

both the natural drive and gas-lift assisted WellFlo models, as the water cut increases, the

production rate for oil will decrease shown in Table 5.5.

The water cut at 0% gives higher production rate for natural flow compared to gas

lift assisted. However, when the water production increases, the natural well depletes at a

Table 5.3 Gas lift valves optimum setting depths for 5 wells

113

faster rate compared to the gas lifted wells where the flow capacity is not reached at

approximately 60-75% of water cut, while for gas lift assisted wells, at 90% water cut,

the well is still producing at 50-60 Stb/day. This shows that the gas-lift assisted wells

have higher sustainability for the water production as the water breakthrough is much

later. For PCSB Standards, a well will be shut in it the production is lesser than 50

Stb/day.

Water Cut GMJT-01A GMJT-02A GMJT-03A GMJT-04B GMJT-05C

Natural Flow

0 747.943 743.315 559.307 734.042 733.499

15 624.595 621.661 457.952 613.067 612.892

30 501.111 498.199 381.92 491.092 491.017

45 378.584 375.78 309.109 368.788 368.904

60 257.55 255.259 229.795 249.844 250.053

75 No OP No OP 146.192 No OP No OP

90 No OP No OP 58.192 No OP No OP

Gas Lift Assisted

0 692.644 656.612 678.332 640.346 644.678

15 584.194 551.924 576.49 537.418 543.041

30 475.362 446.988 471.819 433.874 440.609

45 366.453 341.698 364.283 329.747 337.296

60 260.446 238.754 260.792 229.467 235.727

75 158.85 142.009 159.36 134.371 139.678

90 61.59 54.079 61.936 50.688 53.084

Table 5.5 Oil production rate with increasing water cut

The propose water cut percentage for well abandonment is based on economics

between the oil production cost against the gas compressing cost and also water treatment

cost. Produced water disposal costs reported in “RPSEA Technical Assessment of

Produced Water Treatment Technologies 1st Edition” stated that the types of waste are

important for disposal cost. For example in Wyoming fields, the cost is $ 8/bbl where

dirty and more concreted waste was produced that requires pretreatment, while for

cleaner waste only at $ 0.75/bbl. While for gas lift compression cost, it would depend on

the gas liquid ratio which is to be discussed in the next section.

114

5.3.6 Tubing Performance with increasing GOR

Gas Oil Ratio (GOR) is the ratio of the gas production over the oil ratio. It is the

indication for the gas produced together with the oil in the tubing. Gas oil ratio is

important because the higher it gets, the less viscous the oil will be until a threshold limit

where the production will start to decline due to high pressure drop due to high velocity

of the gas known as oil slip issue. As the gas rate is increased, the fluid velocity and the

friction losses will increase. Table 5.6 shows the production rate of both the natural flow

well and gas lift assisted design.

GOR GMJT-01A GMJT-02A GMJT-03A GMJT-04B GMJT-05C

Natural Flow

250 739.206 736.633 548.25 728.104 725.632

500 797.44 780.734 644.328 778.682 770.939

750 785.024 763.97 746.537 763.919 752.597

1000 758.393 735.297 716.802 734.777 722.573

1250 727.259 703.941 684.799 702.859 690.333

1500 695.129 671.358 653.03 679.903 658.403

Gas Lift Assisted

250 689.385 651.054 676.031 633.308 640.127

500 703.594 696.56 685.279 688.241 683.942

750 690.375 679.585 663.231 677.01 668.479

1000 758.393 735.334 716.839 734.788 722.565

1250 727.248 703.961 684.804 702.871 690.327

1500 695.133 671.365 653.035 670.913 658.397 Table 5.6 Oil production rate with increasing GOR

The economic analysis for gas lift injection would be based on the CAPEX of the

compression unit, and also the OPEX which is the maintenance cost and operating cost to

compress the gas. For current operations, compression cost would be at approximately

$400/MMScf of gas. The pricing of the compressor unit would be based on the models.

115


From the Gelama Merah well designs, the initial oil production rates with natural

flow at choke size 20/64” are within 700-750 Stb/day. When the gas lift valves are

inserted, the initial rate reduced to 630-680 Stb/day. This may indicate the friction

pressure loss in the tubing is too high at the beginning of production. Thus, the gas-lift

valve is not recommended to be used during the start of production. Below analyzes the

gas lifting sensitivity towards increasing water cut and GOR.

Figure 5.3 Plot of Water Cut vs Production Rate for GMJT-01A

Figure 5.4 Plot of GOR vs Production Rate for GMJT-01A

From Figure 5.3, it can be observed that the production rate for natural flow is

higher than gas lifted, and gas lift only has higher production when water cut increases

above 60%. From the GOR plot in Figure 5.4, natural flow too, has higher production at

0

20

40

60

80

100

0 200 400 600 800

Natural Flow

Gas Lift Assisted

680

700

720

740

760

780

800

820

0 500 1000 1500 2000

Natural Flow

Gas Lift Assisted

WC% Production Rate, Stb/day

Oil Rate declines more

rapidly without gas lift

support at high WC%

GOR, Scf/stb

Production Rate, Stb/day

Higher initial production

via natural flow when

water cut is zero

116

GOR from 250-1000 Scf/stb. The optimum GOR that will provide maximum production

rate is approximately 500 Scf/Stb with 780-800 Stb/day.

It is recommended that the dummy valves to be installed from the first year.

Utilizing the gas lift will not affect the production rate above 1000 Scf/stb. Thus, the

orifice and unloading IPO valves should be installed only when the water cut

increase above 60% and the GOR is above 1000 Scf/stb. From the analysis done, it is

determined that gas lifting for Gelama Merah wells will not increase the production

rate significantly but, only to prolong and optimize the life of the well, when water

cut increases. Therefore, the tubing should be equipped with side pocket mandrel (SPM)

to provide future installment of gas lift valves.

5.3.8 Material Selection

Casing design itself is an optimization process to find the cheapest tubing that is

strong enough to withstand the occurring loads over time. API has designated tubing

grades based on chemical composition and physical and mechanical properties of the pipe.

Each grade has designation such as J55, K55, N80, L80, C75, and P110. The alphabetical

designation in the tubing is arbitrary, but the numerical designation reflects the minimum

material yield strength. The minimum yield strength must be sufficient to withstand

forces in the tubing caused by change in pressure and temperature at depth.The tubing

grade selected for a particular completion is the grade that satisfies the minimum

performance requirements of the application. Some grades like L80 have controlled

hardness, which provides resistance to sulfide stress cracking. These grades are generally

specified when the partial pressures of H2S or CO2 exceed National Association

Corrosion Engineers (NACE) MR0175 recommendations.When selecting completion

equipment for downhole service, it is necessary to specify equipment that is suitable for

use the production tubulars in burst, collapse, and tension. Deviating from this

requirement may be costly if equipment failure downhole occurs. Standard-service

equipment typically meets the mechanical requirements of API L-80, which is also

suitable for sour or corrosive service, regardless of temperature.

117

5.4 WELL PROFILE & SCHEMATIC

5.4.1 Orientation of producing wells

4 deviated and 1 horizontal development wells and 1 vertical injector well are to be

drilled as proposal for the Gelama Merah field. All the 5 wells are to be oil producer

entitled GMJT-01A to GMJT-05C. The well orientation or deviation in proposal is build

and hold with inclination of 30-45˚. The justifications for the selection are as follows:

i. Gelama Merah has thick gross volume of gas cap (150m) above the producing

gas zone as well as aquifer support. Horizontal production wells minimize the

severe sharp coning problem if the well is produced vertically.

ii. The permeability is moderate at 140mD, and horizontal wells can reduce the

near-wellbore velocities. This will reduce the near-wellbore turbulence and

improve well deliverability.

iii. Build and hold drilling reduces greatly the CAPEX for development as this

will reduce the number of offshore platform slots required and the number of

wells to be drilled from the surface.

iv. The oil bearing zone is only approximately 30m (98ft) thus, in order to further

enhance the productivity (for natural vertically fractured reservoirs), the

horizontal section connects the vertical fracture as well as increasing

production in thin reservoir layers.

5.4.2 Build and hold well radius profile

Proper well completion is essential to ensure a successful deviated well project in

Gelama Merah. The compatible drilling technique would be to have a Long Radius (LR)

profile of build (1000-1500ft) with 2.8 to 4.3˚/100ft build up rate to match for the slotted

screen completion in deviated wells. The slotted liner with expandable packer will be

used effectively to control sand production in the unconsolidated sand in Gelama Merah

field as discussed in the previous section. The azimuth and full details of the well

trajectory are to be discussed in the next Phase 6 – Drilling and Completion Plan.

118

5.4.3 Wellbore diagram

Figure 5.5 Well Schematic for Well 01A-05C for Gelama Merah

Software used : Stoner’s Engineering Software

2.875” tubing

2.875”

119

The Gelama Merah production zones are completed with open hole method

with expandable slotted liner for the production zones with internal zonal isolation

system. Referring to Figure 5.5 on the Wellbore Diagram, the swell packers are

located downhole to isolate the openhole and the case hole for safety concerns.

The smart-SSD is also a recommended equipment, and to be opened only

when wells are produced from zone U9.0. A smart-SSD would provide surface

controlled-hydraulic jarring of closing and open. This is because the SSD is located at

90˚ which is impossible for wireline intervention jobs (normal wireline in Sarawak

Operations can reach to 60˚) and for higher angles, a Tractor run/Roller Boggie or

Coiled Tubing Unit (CTU) is required which will contribute to very high OPEX and

time consuming.

A wireline retrievable (WRSCSSV) is also recommended as routine valve

change can be carried out every 3 years to restore the damaged O-rings for PCSB

Standard. The deviated well bore diagram can be utilized for well 01A to 05C. The

main difference would be the measured depth of setting and perforation, besides the

number of gas lift mandrel slots required. The vertical water injector requires a

perforation at the aquifer zone estimated to be at 1530 TVD m.

A detailed other sub-surface completion settings will be explained in Phase 6

under Well Completion section.

5.5 POTENTIAL PRODUCTION CHEMISTRY PROBLEMS

5.5.1 Scale Formation

Scale is organic or inorganic material which precipitates in the well itself,

surface flowline, surface facilities and/or near the wellbore formation. This

precipitation or scale deposition usually occurs with the presence of minerals from

water however, no formation water sample analysis was available from the producing

zones. It is therefore suggested to take water samples and analyzed for scale tendency

which will help in the determination of the suitable preventive actions that can be put

in place to avoid scale depositions.

120

5.5.2 Wax Deposition

Many crude oils will form a solid precipitate when they are cooled. This solid

is known as WAX. Wax varies in the form of soft to a brittle solid. The solid wax is

dissolved in the crude oil at reservoir temperature and forms a crystalline precipitate

when the temperature reduces below the cloud point (The temperature at which the

first seed crystal appear). Since pour point data is not available for Gelama Merah

field it is therefore suggested that analysis of the fluid sample be carried out to

observe the tendency for wax deposition. However, Provision of injection points for

pour point depressant (PPD) and wax dispersant shall be provided at the production

header and at the pipeline launcher to allow contingency action in case wax

deposition is observed to have occurred.

5.5.3 CO2 Content and Sweet Corrosion

Compositional analysis of stock tank and wellstream samples of unit-8.0

shows 2.85 and 0.94 mole % CO2 respectively. Moreover, with the initial GOR of 326

scf/stb and no water production, no sweet corrosion is expected to occur initially.

However, this problem would become severe after water breakthrough, mainly due to

the water injection for pressure maintenance. The 13-Chrome material will offer

sufficient corrosive resistance for all downhole equipment.

5.5.4 H2S Content and Sour Corrosion

H2S content from available results of unit-9.0 chromatography has been

observed as 0 ppm therefore, there is no harm of sour corrosion.

5.5.5 Emulsion formation

Emulsion formation from Gelama Merah crude oil is uncertain. To manage

this uncertainty provision of emulsifier injection points at the production header shall

be included in the facilities detail engineering.

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PHASE 6 DRILLING & COMPLETION PLAN

6.1 DEVELOPMENT

6.1.1 Platform location

The platform coordinate is selected to be at N 615,119m, E 276,050m for

optimization purpose since the drilling history is based on Gelama Merah -1 and ST-1

exploration wells. The platform position will provide for build and hold type and

vertical drilling. The single drilling platform will provide the drilling trajectory to all

the drainage points.

6.1.2 Drilling rig selection

Drilling rig are selected based on criteria which are water depth, seabed soil

condition (near seismic result), costing, rig capacity, and stability. Below are some

specifications of available marine offshore drilling units (MODUs).

Types of MODUs Water Depth Average Daily Rate, USD

Jacket rig 40 – 400 ft $77,000 - $137,000

Shallow draft jack-up rig 30 – 60 ft $30,333 - $48,667

Jack-up rig 60 – 330 ft $77,813 - $143,496

Tender Assisted rig Anchor length (+) $44,463 - $117,780

Semi-submersible rig 150 – 6000 ft $300,279 – $396,342

Drill ship/ Large Submersible 1000- 8000 ft $237,900 – $420,324

Table 6.1 Depth and daily rates for offshore drilling rigs (taken on 27/09/10)

The sea depth for Gelama Merah area is approximately 140 ft (42.8m) from

the mean sea level to the sea bed. From the water depth, three types of rig are feasible

which are the jacket rig, jack-up rig and the platform rig. The semi-submersible and

drill ship are not necessary due to high excess cost. The jack-up rig is the most

common offshore drilling rig and is a preferable option for Gelama Merah drilling.

The jack-up rig is towed to location with its legs elevated. Once on location, the legs

are lowered to the bottom and the platform is "jacked up" above the wave actions by

122

means of hydraulic jacks. The jack-up rig has many advantages, including a stable

work platform, good availability, relatively lower mobilization costs, versatility to

work over a platform or drill in open water and generally competitive day rate for 5-8

slots drilling in monsoon weathered environment usually in September-December

period. The jack-up rig should provide space for pipe storing, helipad, mud pumps,

tanks, power generators, cranes, and chemical stores complete with a folk lift.

6.1.3 Well types and trajectories (Stoner Engineering Software (SES)

A total of 5 wells are planned to be drilled are build-and-hold wells in Gelama

Merah. The build and hold wells are proposed to tap the drainage points where the

kick-off point will be below the surface casing shoe at 600m. The dogleg severity for

the build sections are kept at approximately 2.8-4.3˚/100ft. The drainage points are

relatively close in terms of horizontal displacement from the platform where the

distance is not sufficient for build up twice. The build-and-hold trajectory is proposed

to tap the drainage points of these 5 wells are singlecompletion with oil producers,

tapping in Unit 9.0, 9.1 and 9.2 based on Phase 4 on reservoir development plan.

The well trajectory, azimuth, inclination and the measured depth from the

platform to the well are still subjected to changes, when the development takes place.

The targets should be revised to the latest well results and finalized geological

modeling (static model) and reservoir development (dynamic model).

Hole Section Survey Tool for Deviation Logging Tool

24” Drive Pipe Gyro n/a

8-1/2” Pilot Hole MWD LWD/GR/Res

17-1/2” Surface Hole MWD LWD/GR/Res

12-1/4” Intermediate Hole MWD LWD/GR/Res

8-1/2” Production Hole MWD LWD/GR/Res

7” Open Hole MWD LWD/GR/Res

Table 6.2 Well Survey and Logging Tools

The seabed pipelines, marine cables, and seabed features (e.g.

slumping, steep incline, unusual debris) information were not provided.

Selections are made without taking these aspects into consideration.

123

Table 6.3 Gelama Merah drilling profiles

The trajectory data were obtained using the Stoner Engineering Software (SES) for

drilling specification summarized in Table 6.3. The trajectory for GMJT-01A and GMJT-

05C is plotted in Figure 6.1 and Figure 6.2 The blue line indicates the position of the well

(azimuth) where the datum of 0 is the platform location in bearing direction. While for the

red line, it indicates the 2-Dimensional trajectory of the well profile, where y-axis is the TVD

while x-axis is the displacement from the vertical section. The MD is the along hole depth

which is 1608.79m compared to the TVD of 1482.6m.

Figure 6.1 Well profile for GMJT-01A

Proposed Wells

(GMJT)

GMJT-

01A

GMJT-

02A

GMJT-

03A

GMJT-

04B

GMJT-

05C

GMJT-

WI

TVD, m SS 1482.60 1485.27 1492 1496.58 1495.93 1469.46

ΔNorth -302.41 -678.23 953.23 498.62 -36.18 0

ΔEast 343.73 -33.72 -279.39 591.43 951.6 0

DLS (Deg/ 100 ft) 2.8 2.8 2.8 2.2 4.3 0

Azimuth 131.34 182.85 343.66 49.87 92.18 0

Final Inc 33.20 47.97 63.32 90.00 39.60 0

Measured

Depth, m

SS

Vertical 600 600 600 723 200 1469.49

Build 955.73 1113.92 1267.75 1938.17 476.29 0

Tangent 1638.79 1785.09 2018.2 1974.17 1856.30 0

Displacement 404.31 622.63 990.48 498.62 36.18 0

Drainage taps 9.2 9.2 9.2 9.1 9.0 Aquifer

124

Figure 6.2 Well profile for GMJT-05C

From Figure 6.1 and 6.2, the direction (in NS direction) of the blue line is different,

indicating the difference in azimuth value which is read from the 0, 0 (platform location)

value from true north. This is shown in Figure 6.3.

Figure 6.3 Well Locations in Gelama Merah from horizontal plane

125

6.2 PRESSURE MANAGEMENT

Table 6.4 Pressure data against depth for GM

The pore pressure was obtained from the Drill Stem Test (DST) result. From

surface depth to 1320m TVDSS, the fluid gradient of 0.433-0.45 psi/ft was selected.

The pore pressure here was identified to be slightly overpressure due to two reason.

Firstly during drilling of GM-1 exploration well, the opertation encounterd

underbalanced in pressure when drilling through the hydrocarbon zone. This indicates

an increase of reservoir pressure causing the original mud weight used to be

insufficient. Second, the overpressure zone can occur in zones where there are density

differences, where the gas and oil column which are less dense than water, are merely

compacted or “sandwiched” between two water bearing zones. The fracture pressure

identification was calculated using the Eaton’s Method. A trip margin of 150psi

excess of the pore pressure and kick margin 150psi below the fracture pressure were

also calculated as a means for safety factor. The selected mud weight design should

provide pressure exceeding the trip margin, and the same time below the kick margin

pressure line.

The plot of pressure profile is shown in Figure 6.4. As can be seen, 3 different

mud weights are chosen for the different drilling depth at surface, 1320m, 1460m.

The justification for the addition of mud weight is that, during the build up section

126

and the horizontal section, higher mud weight is required to support the deviated drilling operations. When the drill string is at horizontal

direction, heavier mud weight with higher circulation rate is required to support the column of the string to prevent it from laying on the

formation due to gravity effect.

Figure 6.4 – Pressure Profiles vs Depth for Gelama Merah

127

6.3 DRILLING FLUID DESIGN

Based on the different casing design depth, the calculated result of the

formation gradient, mud weight design range, the fracture gradient and the formation,

a complete drilling fluid plan has been made for the entire operation. The proposed

drilling fluid is water based mud (WBM) that is using seawater with high viscosity

sweeps (gel mud) and KCL/PHA as additive.

PHA is Partial Hydrolyzed Polyacrylamide which is polymer for drilling mud

additive. It is used in shale stabilization, viscosities, friction reduction, fluid loss

control and lubrication. As our well formation is shaly-sand, it serves to coalesce the

small cutting and it will be easy to be removed by the drilling mud. On the other hand,

KCL which is Potassium Chloride helps prevent clay, shale formation from swelling.

This will reduce the possibility of stuck pipe during drilling operation. KCL/PHA are

added for drilling from 553 – 1587m TVDss.

Casing Depth, m TVD Size Mud Design

Conductor 0-600m 20’’ Seawater

Intermediate 0 – 1350m 13 3/8’’ Seawater + Hi-Viscosity (gel mud)

Production 0-1480m 9 5/8’’ Seawater + Hi-Viscosity (gel mud)

Table 6.5 - Mud design additives for each casing design

The mud weight proposed is similar to the one explained in the previous

section from Table 6.4 where it should be in the trip and kick pressure window for

safety factor based on PCSB Standards.

Table 6.6 – Mud weight and properties for depth 553-1587m

Depth TVD(m) 553 1120 1380 1415 1466 1488 1507 1541 1587

Mud weight (ppg) 10.2 10.2 10.4 10.4 10.6 10.6 10.6 10.6 10.6

Funnel viscosity

(sec/qt)

61 70 70 78 67 57 59 66 58

PHPA (PPb) 0.8 1.1 1.1 1.0 1.0 1.2 1.2 1.2 1.1

KCL (ppb) 13.4 30.6 30.5 30.8 30.8 30.7 30.7 30.7 30.4

128

The conventional water-based muds (WBM) offer the benefits of

environmental compliance, attractive logistics, and a relatively low unit cost but

compare to oil based. Some of the advantages and justifications for choosing the

WBM are as follows:

i. High performance water based muds (HPWBM), designed to emulate the

performance characteristics of oil based muds (OBM)/ synthetic emulsion

based muds (SBM), has been developed.

ii. The system has been successfully field tested on offshore (shelf and

deepwater) wells and has proven to be performance and cost competitive with

OBM/SBM.

iii. The HPWBM has eliminated the environmental risks and costs associated

with waste management of OBM/SBM

iv. The system is environmentally friendly and has been approved for use in the

US of Mexico and UK- sector of the North sea.

v. The system cleans up easily prior to completions and has proven to be non-

damaging to producing formations.

6.4 CASING PLAN

Figure 6.5 Casing setting depth selection method

m

m

m

m Liner

20” conductor

piling, 150m

129

The casing setting depth is ensured to be within the kick and trip loss margin interval.

The results were summarized as in Table 6.7 and Table 6.8

No well

Casing size(inch)

Casing shoe depth (m-MDSS)

20 13-3/8 9 5/8 7

GMJT-01A 150 600 1397 1609

GMJT-02A 150 600 1490 1755

GMJT-03A 150 670 1605 2018

GMJT-04B 150 610 1377 1974

GMJT-05C 150 665 1570 1826

GMJT-WI 150 600 1300 1488 Table 6.7 Casing Setting Depth in MD for individual wells

*BTC = buttress thread coupling/ LTC = long thread coupling

i. Surface hole

The 17-1/2” surface hole will be drilled with a seawater polymer/hi viscosity

gel sweep system similar to the one used during the exploration drilling for

GM-1. The well will be drilled to +/- 600m TVD before setting the 13-3/8”

casing. The mud weight will be 10.2 ppg initially, weighing up with drill

solids to avoid dumping and diluting.

ii. Intermediate hole

The 12-1/4” intermediate hole will be drilled with a 10.2ppg KLC/PHPA mud

system initially. Mud weight will be increased gradually to +/-10.6ppg prior to

reaching section hole depth depending on hole condition.

Bit

Size

(in)

Casing

Setting

Depth (m-

TVDSS)

Measured

Depth (m-

TVDSS)

Casing Design and Specification Kick

Capacity

Remarks

Size

(in)

Weight

(ppf)

Grade/

Coupling

26 150 150 26 310 X-56/

Threaded

- Conductor

Casing

17 1/2 +-600 +-670 13 3/8 98 L-80/BTC 50 bbls Surface casing

12 1/4 +- 1250 1300-1600 9 5/8 47 P-

110/LTC

50 bbls Intermediate

casing

8 1/2 1473-1491 1609-1851 7 38 V-150/

Extreme-

line

25 bbls Expandable

Slotted Liner

Table 6.8 Details of casing design

130

iii. Production hole

The 8-1/2” production hole will be drilled with a 10.4 ppg KCL/PHPA mud

system initially and increased to 10.6ppg gradually for deviated section.The

sand control and completion method chosen is a 7” expandable slotted liner

completion with partial isolation. The top of the liner will be cemented within

the intermediate casing at height interval of 100ft (31m).

The casing specification is selected based on pressure containment, cost effectiveness

and also conformance to the PETRONAS Procedures and Guideline For Upstream Activities

(PPGUA) and completion requirements based on Sumandak’s Main. Design factor that are

set by PCSB are shown in Table 6.9.

Design Factor PCSB Required Safety Factor

Collapse (psi) 1.125

Burst (psi) 1.100

Tension (lbs) 1.300

Table 6.9 Design factor for casing stress check

Table 6.10 Casing specification and load (casing stress check) based on API grade

*GMJT-WI is cased with a 7” production casing rather than a liner for water injection

purposes.

Types Conductor Surface Intermediate Liner

Size 20” 13-3/8” 9-5/8” 7”

Shoe Depth, m TVDSS 350 600 1250 1490

Grade X-56 L-80 P-110 V-150

Nominal Weight lb/ft 310 98 47 38

Wall thickness , in 0.635 0.719 0.472 0.540

Mud density 10.2 10.4 10.4-10.6 10.6

Body yield strength 1000lbf 2125 2800 1493 1644

Tension of casing, 1000lbf Pilling 250.8 260.6 241.2

Collapse Resistance, psi 520 5910 5310 19240

Collapse Load at shoe, psi Pilling 839.41 1550.91 2314.12

Burst Resistance , psi 3036 7530 9440 18900

Burst Load, psi Pilling 721.05 1777.02 1790.57

131

6.5 CEMENTING PLAN

Well Casing Top of Cement Lead (ppg) Tail (ppg)

GMJT-01A

GMJT-02A

GMJT-03A

GMJT-04B

GMJT-05C

GMJT-WI

20” Surface 15.8

13-3/8” Lead: Surface

Tail: 150m above 13-3/8 shoe

12.6 15.8

9-5/8” Lead: 150m above 13-3/8” shoe

Tail: 150m above 9-5/8” shoe

12.6 15.8

7” Top of Liner 15.8 Table 6.11 Proposed cement design

Based on the table above, it is proposed to use 15.8 ppg slurry density for tail

slurry and for both 20” casing and 7” liner while for lead slurry, it is proposed to use

12.6 ppg. 20” and 13-3/8” casing will be cemented up to surface or seabed so that the

casing will have firm condition at the surface. The total volume for cement sacks used

for each well, additives, mixing fluid and seawater are calculated and displayed in the

table below. The total cement volume for 20” and 13-3/8” casing are all the same

since its have same casing shoe depth for all wells. The total cement volume required

for each well is differ based on 9-5/8” and 7” casing shoe.

Well Casing Type of Cement /

Additives

Lead Slurry

Volume

Tail Slurry

Volume

Total

GMJT-01

GMJT-02

GMJT-03

GMJT-04

GMJT-05

GMJT-WI

20” Class “G” 1564 sxs 1564 sxs

Sea Water 193.6 bbls 193.6 bbls

Mixing Fluid 196.6 bbls 196.6 bbls

Fluid-Loss 47 gals 47 gals

13-3/8” Class “G” 541 sxs 460 sxs 1001 sxs

Sea Water 146.7 bbls 50.8 bbls 197.5 bbls

Mixing Fluid 161.0 bbls 59.0 bbls 220.0 bbls

Retarder 32.5 gals 9.2 gals 41.7 gals

Fluid-Loss 27 gals 23 gals 50 gals

Dispersants 541 gals 161 gals 702 gals

GMJT-

01A





Fluid-Loss 45.1 gals 10.5 gals 55.6 gals

Dispersants 901.1 gals 73.4 gals 974.5 gals

7” Class “G” 743 sxs 743 sxs

Sea Water 82 bbls 82 bbls

Mixing Fluid 95 bbls 95 bbls

Retarder 66.8 gals 66.8 gals

Fluid Loss 37.1 gals 37.1 gals

Dispersants 222.8 gals 222.8 gals




132

GMJT-

02A










GMJT-

03A













GMJT-

04B













GMJT-

05C













It is recommended to run Cement Bond Logs (CBL) across the planned

completion intervals, to ensure the completions are not affected by behing-pipe

communication. CBLs should be run any time losses or other problems with

cementing occur. GMJT-WI utilizes the production casing rather than liner.

133

6.6 HYDRAULIC OPTIMIZATION

The calculated balance of the hydraulic component that will sufficiently clean

the bit and wellbore with minimum horsepower.

Consideration For Hydraulic Planning

Factors Considerations

Maximize Rate Of Penetration (ROP) In medium to hard formations, maximize

hydraulic horsepower to increase

penetration rate.

Maximize hole cleaning In soft formation and high angle holes,

maximize flow rate for hole cleaning.

Annulus friction pressure In small and deep holes, limit flow rate to

minimize annulus friction pressure and

reduce the potential for lost circulation,

differential sticking and hole stability.

Hydraulic erosion In soft unconsolidated formation, limit

flow rate to minimize turbulence in the

annulus if hole wash out is problem.

Bit plugging Larger jet sizes may be required if there is

potential for lost circulation.

Table 6.12 Consideration for hydraulic planning

Factors That Affect Hydraulics

Equipment Wellbore

Pump pressure

Drill string

Down hole equipment restriction

Bit type/jets

Depth/hole size/mud type

Mud weight

Annulus friction pressure

Hole problem potential Table 6.13 Factors affecting the hydraulics

A detailed calculation and estimation of the hydraulics, torque, and drag forces

needs to be calculated once the drill string configuration is known, where this will

differ based on different service contractors providing the equipments.

134

6.7 WELL CONTROL

6.7.1 Blow Out Preventer (BOP) Specification

Single ram blowout preventer has been chosen for the well safety control

according to our maximum formation pressure (2238.69 psi) at target depth and also

because of its efficacy compare to annular blowout preventer. The advantage of the

ram blowout preventer has effective seal on an open hole compare to annular

preventer. In open hole annular preventer has to be reinforced by a series of several

ram preventers located bellow the annular preventer. The size of the BOP will be

chosen by the service specialist company according to the well tubing size. Bellow is

Single Ram BOP specifications.

Single Ram BOP Specification

Size Max.operation pressure

IN PSI

5 ½

5 ½

2,000

3,000

7

7

2,000

3,000

8 5/8 2,000

10 ¾ 2,000

16 2,000 Table 6.14 BOP Operating Pressure

6.7.2 Actuator/SSV (Model 120)

Compare to the other models the “120 model” is more related to our well

conditions such as pressure, temperature and direction. The model 120 is the low-

pressure, critical service option. Tested above and beyond API 6A PR2 requirements,

the model 120 is available from -75 to 250F, in AA-HH materials, for up to 5,000 psi.

Bi-directional sealing allows installation from any orientation, and the non-rising stem

does not allow debris to enter the packing. The model 120 series gate valves are

equipped with blowout features like threaded and anti-blowout packing nuts, bonnet

caps, packing retainers, and stem backseats that hold the stem in place. With a break

off point outside the valve cavity, the no pressure will ever escape in a contingency

situation. In addition, the slab gate does not mechanically lock so it will never have a

problem opening, closing, or servicing the valve.

135

6.7.3 Wellhead /Casing Spool

The Unihead (HU-1) type will be use as a wellhead for our well as it is

available in multiple or single head configurations. The main advantage of the

Unihead technology is that it fits virtually any surface wellhead application and has an

indication of a “though bore” wellhead system. This split Unihead system provides

time savings that drastically reduce rig costs, allowing you to maximize the

productivity of your drilling operation. It maintains well control from the reduction of

BOP nipple up and down times, and is commonly utilized for 13- 5/8" surface, 9- 5/8"

intermediate, and 4- 1/2" production casing, with a compact design that addresses

your sub-structure space constraints. Designed for quick and simple installation, the

UH-WB wellhead allows you to make up 2-4 strings of casing without removing the

BOP, optimizing mandrel hangers. Though this wellhead is comprised of 2 or more

drilling spools, they are made up as a single unit, permitting the drilling of two or

more phases at the same time - while using only 10 hours of time per stage.

AVAILABLE UH-1 CONFIGURATIONS 11’’ 13 5/8’’

Casing

head

11’’ 3k or 5k psia,

F/ 10 ¾’’ , 9 5/8’’ or 8 5/8’’

Casing

13 5/8’’ 3K OR 5K Top,

F/11 ¾’’ OR 13 3/8’’ Casing

Tubing

head

11’’ 3K X 11’’ 5K,

5K X 11’’5K, OR 11’’ 5K X

11’’ 10K

133 5/8’’ 3K X 13 5/8’’ 5K, 13 5/8’’ 5K X 13

5/8’’ 5K, OR 13 5/8’’ 5K X 13 5/8’’ 10K

Mandrel

Hanger

F/5 ½’’, 7’’, OR 7 5/8’’ Casing F/5 ½’’, 7’’, 7 5/8’’, OR 9 5/8’’ Casing

Table 6.15 – UH-1 Wellhead Configurations

Comparison of wellheads Conventional

wellhead

UH-1 Drill –

THRU Wellhead

Weld on 13 3/8’’ SOW Head, nipple up 13 5/8’’

BOP and DSA

12 10

Run and cement 9 5/8’’ casing, nipple down BOP

& DSA, install casing spool

14 3

Run and hang 2 7/8’’ tubing, nipple up 2 9/16’’

tree

6 3

Nipple up 2 9/16’’ tree 3 3

Total install time 35 16

Table 6.16 - Comparison between unihead and conventional wellhead

136

6.8 DRILLING OPTIMIZATION

6.8.1 Rotary Steerable System (RSS)

For the horizontal drilling section, the Rotary Steerable System is preferable

compared to conventional mud motors. The RSS improves the removal of the drill

cuttings from the wellbore and also eliminating the time for wellbore cleanout. A

smoother well trajectory will induce less drag on the drill string as well as the torque

required from the surface.

6.8.2 Cement Assessment Tool (CAT)

The combination of cement and Swell Technology provides a long term

isolation for the micro annulus. The Cement Assurance Tool (CAT) is to be deployed

together with the primary cementing job at the casing pipe. The benefit of the CAT is

that it can effectively seal irregular borehole geometry with complement to all cement

slurry design . For highly deviated and horizontal wells, they often have greater

exposure to the reservoir than vertical well, thus achieving zonal isolation is critical.

An incomplete cement sheath surrounding the cement might occur if casing

centralization is less than optimum, drilling cutting removal not complete, pockets of

viscous mud remaining in well.

Figure 6.6 CAT elastomer in long term zonal isolation

6.8.3 Directional Casing While Drilling (DCwD)

The DCwD using a retrievable BHA to steer the wellbore, will provide

solution for the lost circulation zone and also unconsolidated formation in Gelama

Merah borehole. Besides that, it also improve well control because they allow

circulation while the BHA is being retrieved or run into the well. During drilling, the

DCwD rotation strengthens the borehole well because of the plastering effect,

narrowing the annulus.

137

6.9 POTENTIAL DRILLING PROBLEMS

i. Occupational Safety

The potential worker safety risks include those associated with standard

construction operations. Occupational Safety and Health Administration (OSHA)

requirements must be reviewed because directional drilling, like all drilling methods

involves high noise level and hazards associated with drilling near overhead or

subsurface power lines or utilities.

ii. Hole Cleaning

Hole Cleaning is another problem posed by horizontal drilling. As the

drillstring lies on the low side of the hole, beds of cutting build up around the bottom

of edge of the drillstring. These can be very hard to shift when conventional

directional motors are used. Therefore, the RSS drilling is recommended for the

horizontal drilling section for better hole cleaning to prevent stuck pipe during

tripping operation.

iii. Torque Required

Besides that, compared to vertical wells or normally deviated wells, the

power/torque needed to turn the drill string or to pull it out of the hole are higher on

horizontal well. This is due to the drag force exhibited by the drill string when it tend

to lay on the formation due to gravitational forces. As for the horizontal section, the

surface of the drill string contacting with the formation will be much higher, thus

contributing to higher frictional force when it is tripped up to the surface.

iv. Seabed existing pipelines

Before confirming the trajectory to be drilled, the seabed pipeline and existing

marine cables (telecommunication/resource) needs to be identify. The approved

anchor pattern for any barge and platform needs to be revised as any misdrilling will

lead to leakage in the offshore area which will give a big impact to the environment

surrounding it. However, as for the Gelama Merah field, no data on the seabed or

cables were obtained yet. The drilling trajectory were designed without taking

consideration of these aspects. It should be revised once the information is in hand in

the future.

138

v. Shallow Gas

There are indications of shallow gas based on the results from GM-1. Possible

shallow gas is expected at 646 m TVDRKB. Pilot hole will be drilled in this section

as a precaution since pilot hole will limit the gas volume.

vi. Stuck pipe/differential sticking

Differential pipe sticking arises when the differential pressure (the difference

between the hydrostatic pressure of mud and formation pore pressure) becomes

excessively large across a porous and permeable formation. Moreover for wells that

have long openhole section usually 2,500 m, there is a potential for mechanical or

differential sticking problems due to swelled or collapsed clay formation. Although

the problem has not been experience in the GM-1 and GM-1ST1 however,

contingency plan in order to eliminate this problem must be considered. OBM/SBM

will probably be used to drill this hole section.

vii. Cementing/ Gas Migration

Presence of a large gas cap may cause problems wherein the potential problem

in obtaining good cement bond due to gas migration. High well angle will aggravate

the problems. Good cementation technique and cement recipe will be developed to

overcome this problem and achieve good cement strength. The composition of cement

slurries will be studied carefully to combat this problem.

6.10 BIT SELECTION

Based on the GM-1 and GM-ST1 wells, for this drilling campaign it is

proposed to use rock bit. Polycrystalline Diamond Compact (PDC) bit will be used in

case to drill through the hard formation. The bit size will be prepared according to the

planned drilling hole sizes.

139

6.11 WELL COMPLETION

The open completions of Gelama Merah field are to be completed using the

expandable slotted liner with partial completion for sand control (in Phase 5)

equipped with blank pipes and oil swellable packer. Dual completions are planned for

wells with build and hold profile where drainage points are at zone U9.1 and U9.2.

6.11.1 Swell Technology™ Packer

The main reason for the selection of liquid hydrocarbon-swell packer instead

of mechanical packer is because in the openhole, the borehole formation may not be

smooth. If the mechanical packer is utilized on borehole which have irregular caved

in section, the zonal isolation will fail. The swell packer on the other hand, will swell

to conform to the shape of the irregularities with low hardness element as the

elastomer. Second, swell packer saves rig time, as no mechanical setting or pressure

activated setting mechanism is required. Other benefit is that it helps reduce downhole

mechanics as it does not having moving parts.

The Swell Technology System is based on the swelling properties of elastomer

to create effective seal. When exposed to hydrocarbon, the diffusion process occurs

and the molecules are absorbed by rubber molecules causing them to stretch. The

process however is not reversible. The swelling is not instantaneous, and takes around

30-60 minutes to reach 200% of it’s original size dependent upon the oil viscosity,

element thickness, temperature and salinity. A packer integrity test should be

conductor after 2 hours of setting to ensure pressure drop is not above 10%.

Figure 6.7 Swellable packer in horizontal wells

Isolate layers of

zones and shale in

horizontal section

140

6.11.2 Expandable Slotted Liner (ESL) with Partial Isolation

As discussed in Phase 5, the ESL will be use as a sand control method in the

build and hold wells. The ESL could be expanded to sit on a tight fitting of the

wellbore, providing borehole stability, eliminating the annulus between the

sandscreen and the formation which will help prevent excessive erosion and plugging

compared to other sand screens or gravel packs. Refer to Phase 5 for more details.

6.11.3 Surface Controlled Subsurface Safety System

The FXE/B7 profiled-tubing retrievable SCSSV is for completion requiring

low-operating pressures because of control system limitations. The safety valve is

used for completions that may require wireline entry and also change of SCSSV in the

future. Retrievable valves are preferred as o-rings of the valves may be permanently

damaged during production and may need to be changed every 3 years in routine.

6.11.4 Tubing Installation

All tubings used are to be 2.875” based on the optimal flow as analyzed in

production technologist section with Grade L80 as explained in Phase 5.

6.11.5 Smart - Sliding Side Door (SSD)

Another recommended add-on tools to the tubing itself is the smart-SSD

which will enable control of open to close profile from the surface powered by

hydraulics to jarr up and down. The SSD is located at the near horizontal section, and

may require CTU to open/close in the future which may be very costly and time

consuming if a slickline team is required to open/close the door.

6.11.6 X-mas Tree Design

All wells are proposed to use the standard cross piece X-Mas Tree where a

series of valves which control physical or hydraulic access into the tubing and/or

annulus. The access capabilities are normally required for (1) Vertical access to lower

down wireline tools, (2) Capability to inject into the tubing., (3)Capability to

completely close off the well.

141

Christmas tree design will conform to the standard specifications of API 6A Latest

Edition. Bottom flange of Christmas tree and Tubing Hanger will be modified to

accommodate Permanent Downhole Gauges (PDG) cable. Critical design features

incorporated will include the following:

Christmas trees will comprise of 1 lower master valve, 1 upper master

valve with pneumatic actuators, 1 swab valve and 1 wing valves.

Bottom flange of Christmas tree and Tubing Hanger will be prepared for

Continuous Control Line option to avoid potential leak/damage of Hanger

Neck seal problem.

6.11.7 Wellhead and Casing Hanger

For the designed casing configuration i.e 26” conductor casing, 13 3/8”

surface casing and 9 5/8” production casing a conventional spooled wellhead is

proposed where head housing is either screwed or welded to the top joint of the casing.

Each housing will have an internal profile to accommodate casing hanger to hang the

casing.

6.11.8 Completion and Packer Fluid

Brine is selected compared to other fluids to prevent formation damage

because it minimizes the clay swelling especially inhibition (specially calcium based

fluids) and brines are also solids free where it eliminates plugging of formation. Some

of the proposed completion brines are NH4Cl, NaCl, KCl, and ZnBr for 10-11.5ppg

while for packer fluid, treated completion brines as above is recommended. The effect

of compressibility due to pressure are generally not considered unless high pressure

situation in the range of 10000psig.

However, laboratory analysis should be done to check for the compatibility of best

completion fluid and formation water for instance mixing of water sample and

analyze.

142

6.11.9 Perforation Techniques

The gun used in Gelama Merah-1 i.e Tubing Conveyed Perforation (TCP) gun

4 5/8”, 12 Shot Per Foot (SPF) with 23 gm RDX explosive has been proven to be

effective with a negative skin of -2.1, as evidenced from DST results. Therefore, the

same is suggested for all the development wells.

6.11.10 Completion Method

For the build-and-hold well profiles, it consists of a single string for oil

producer. The expected gas produced from high GOR would provide the means of gas

lifting for optimization purpose in the future. From the reservoir development, it is

determined that water injection provides a more significant increase towards the field

total productivity. The details of completions are shown below:

Well Name

GMJT-

01A

GMJT-

02A

GMJT-

03A

GMJT-

04B

GMJT-

05C

GMJT-

WI

Conductor CSG 20” 20” 20” 20” 20” 20”

Surface CSG 13-3/8” 13-3/8” 13-3/8” 13-3/8” 13-3/8” 13-3/8”

Intermediate CSG 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8”

Slotted Liner 7” 7” 7” 7” 7” n/a

Production CSG n/a n/a n/a n/a n/a 7"

Tubing Size 3.5” 3.5” 3.5” 3.5” 3.5” 3.5"

Completion Type Single Single Single Single Single Injector

Well Type

Oil

Producer

Oil

Producer

Oil

Producer

Oil

Producer

Oil

Producer

Water

Injector

Drainage Tap, m

TVDSS 1482.6 1485.27 1492.00 1496.58 1495.93 1530.00

Drainage Tap, m

MDSS 1608.79 1755.09 2018.20 1974.17 1826.30 1530.00

Table 6.17 Completion Summary for Gelama Merah

*Refer to Phase 5 – Production Technology for the Well Bore Diagram for the

illustration of the sub-surface completion profile

143

6.12 DRILLING COST AND SCHEDULE ESTIMATION

Well Name Days* Total Cost

Others Drilling Completion Cumulative

days

MYR

mil

Cumulative

MYR

USD mil

Start 0 0

Rig

Mobilization 5 - - 5 3.5 3.5 0.96

Rig Up 6 - - 11 3.7 7.2 1.02

GMJT-01 - 19.0 9.5 39.5 18 25.2 4.96

GMJT-02 - 16.5 7.5 63.5 15.5 40.7 4.27

GMJT-03 - 14.5 7.5 85.5 15 55.7 4.13

GMJT-04 - 18.0 9.0 112.5 17.5 73.2 4.82

GMJT-05 - 14.5 5.5 132.5 14.5 87.7 3.99

GMJT-WI - 10.0 4.0 146.5 12 99.7 3.31

Rig down 4 - - 150.5 2.5 102.2 0.69

Demob 3 - - 153.5 2.3 104.5 0.63

TOTAL 18 92.5 43.0 104.5 28.79

Table 6.18 Cost Summary for Gelama Merah (Source: FDP Sumandak Main)

(1) *1 days = 2 shifts, 12 hours for a single shift

(2) Exchange rate of 1 USD = 3.08 MYR as of November 2010

(3) Cost basis on rig rate of RM120K/day (USD39K/day)

(4) Estimation of 1.5 days for every 500ft without considering the types of formation

for drilling. Daily rate includes rig cost, the charge of the drilling equipments and

personnel charges.

(5) Estimation of 7.5 days for completion is based on the completion setup for a

single string. Daily rate includes rig cost, the charge of the drilling equipments

and personnel charges.

(6) 10% of contingency time is allocated for Non-Productive Time (NPT)

Waiting on Weather (WOW)

Waiting on Equipment (bit, casing, threads)

Maintenance

The values for days and cost are taken from Sumandak main field development as the

depth are in-almost similar ranges of 4000-5000ft, which same procurement companies and

service contractors. Proper testing on the core samples to determine the Drilling rock

stress index should be recognize. However, these data were not avaialble in the core

analysis report.

144

Figure 6.8 Gelama Merah Drilling and Completion Time vs Cost

0

20

40

60

80

100

120

0 5 11 39.5 63.5 85.5 112.5 132.5 146.5 150.5 153.5

Cu

mu

lati

ve

Co

st,

MY

R

Cumulative Time, Days

Drilling & Completion

Rig Up

Rig

Down

Rig

Mob

Demob

GMJT-01

GMJT-02

GMJT-03

GMJT-04

GMJT-05

The Rate of Penetration (ROP)

here is not taken into

consideration for different

types of rock, as laboratory

testing data for Rock Stress

Index is not available. The

data is based on previous

drilling in similar basin.

GMJT-WI

145

PHASE 7 FACILITIES ENGINEERING

7.1 INTRODUCTION

7.1.1 Overview on Facilities

6 wells consisting of 5 producers and 1 vertical injector were to be completed

using slotted liner with expandable packer in open hole section at highly deviated angle.

Review from the reservoir and production technologist section suggests that the gas

lifting is still not required at the early stages, gas and thermal injection not required, and

planned water injection in the early stages of production. The total estimated reserves are

approximately 19MMStb for oil.

7.1.2 Types of development platform options

The development selection takes into consideration of the required facilities on

the surface and also the environment of the platform for the safety of the structure and

workers. There are 2 options which are technically and commercially viable which are

fixed jacket platform and Floating, Production, Storage and Offloading (FPSO). The

production span for the wells are from 18 years, thus renting the FPSO would not provide

a feasible option as it is more suitable for short period production without pipeline and

currently there are only 2 FPSO being utilized in Malaysia. Besides that, the gas

compression system and possible water injection system will require major modification

towards the crude processing facilities. These facilities will also give additional weight

on the floating vessel. If the FPSO is to meet the requirement of bad weather condition, is

has to be immobile and not re-locatable due to the additional weight.

A long term and fixed on site platform is preferable such as the jacket platform

with 6 legged structure and 12 conductor slots. Jacket platform (JT) has better stability to

withstand the weather condition in Sabah offshore, where monsoon weather is expected

alternating every year. The piled base with timber would also provide a rigid fundamental

for the whole platform structure to withstand the harsh environment. Pipeline is to be

developed to transport the produced crude oil to the nearest terminal at LCOT, Labuan.

146

7.2 DESIGN FEATURES & BASIS

7.2.1 Facilities Design Concept

As to emphasize the discussion in Phase 5, the platform is planned for an

unmanned facility to eliminate the need for personnel to be on-rig. The platform shall be

designed that it can accommodate servicing barges or vessels in the future. Besides, the

design is also aimed to withstand 25 years operating life with 30 years structural design

life with the monsoon storm condition. A remote well testing is to be run on a monthly

basis. The data gathering and monitoring of information shall be managed by the PCSB-

SBO office at Kota Kinabalu, Sabah. The geological data of Gelama Merah is as follows:

Location : 75km from LCOT / 15-20km from Samarang Field

Number of wells : 6 wells consist of 5 producers and 1 vertical water injection. The

producer consists of 1 horizontal and 4 deviated wells.

Years Days Oil rate,

STB/D

Cumulative Oil

production, STB

Annual Oil

rate. STB/Y

2011 365 7825 2856180 2621426

2012 730 7825 5477606 2621426

2013 1095 7697 8056404 2578797

2014 1460 6606 10269659 2213255

2015 1825 6095 12311659 2041999

2016 2190 3791 13581731 1270071

2017 2555 2761 14506995 925263

2018 2920 2503 15345809 838814

2019 3285 2422 16157277 811467

2020 3650 2397 16960391 803113

2021 4015 2384 17759060 798669

2022 4380 1967 18418200 659140

2023 4745 1003 18754430 336229

2024 5110 676. 18981077 226646

2025 5475 578 19174885 193807

2026 5840 395 19307355 132470

2027 6205 308 19410831 103476

2028 6570 272 19502063 91231

2029 6935 225 19577700 75637

2030 7300 167 19633935 56234

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Table 7.1 Production forecast for Gelama Merah

Property Value

API Gravity 23.7° API

Wax Content 0 % w/w

Sulphur Content 0 % w/w

CO2 Content 0 % v/v

Seabed Temperature 36.2°C

Bubble Point Pressure 2014 psi

Bubble Point Temperature 155 °F

Water Specific Gravity 1.019841

Table 7.2 Reservoir fluid properties for Gelama Merah

7.2.2 Top structure

The GMJT-A topside structure will be a modularized integrated deck supporting

the main production, a mezzanine deck (gantry and jib crane on the deck) and a helideck.

The deck on top of the wellheads shall have the space sufficient to accommodate the well

servicing equipments such as the wireline and coiled tubing services. The topside shall

have a helideck that is permanently welded in place with hatches, but needs to be ensured

it does not hinder any wireline job as height of lubricators may hinder wireline jobs if the

helideck is directly above the wellhead hatch.

7.2.3 Substructure

The GMJT-A jacket shall be a six-pile steel-insert structure utilizing 8 conductor

slots and is to be designed to withstand loading resulting from operations and a 100 years

storm and to support facilities on the main production module on the top structure. The

jacket shall also accommodate the risers for production communication from seabed to

platform, caisson, and boat landing considering the sea level depth. The piling of the sea

floor base is supported by a timber plate to equally distribute the weight of structure. The

whole pile leg should be approximately 30-100m (100-328ft) considering a minimum air

gap of 5ft between the platform substructure and the sea level.

148

7.3 OPERATION FACILITIES AND EQUIPMENTS

Gelama Merah, from the well test shows a high potential of producing large

volume of gas and expected solids when water is produced. Therefore, for the surface

facilities, separation of fluids, the handling for gas and solids has to be put into

consideration, may it be for the present or future production. The selection of production

facilities for Gelama Merah field is based on four main decisional criteria. The criteria

are the transport and hydrocarbon evacuation, substructure options, processing facilities

and wellhead location.

7.3.1 Production Flowlines, Flow Control and Manifold

The production and test manifolds will allow each production completion to flow

to either the production header or the test header. A multiphase flow meter (MPFM) will

be provided for well testing purpose.

7.3.2 Wellhead

The wellhead panel will be driven by instrument air. Fluids from individual wells

will flow through the Xmas tree, after which it is routed to the production manifold via a

rotary selector valve (RSV) by individual flowlines equipped with manual chokes. The

manifold will direct flow to the main flowline to Samarang platform.

7.3.3 Gas Metering and Measurement

The gas metering hardware shall include a standard the orifice box, orifice plate,

recorder, Differential Pressure (Dp) Cell, pressure element and seal pot for the

measurement of gas volume. A circular chart shall be used for data recording. Frequent

maintenance should be carried out for the zero check, calibration, draining of seal pot/ Dp

cell logs, clock wound and time set, the pen functions properly, and the accuracy of the

orifice factor accuracy compared to the volume of gas measured. The orifice size should

be chosen correctly, where the d/D shall be between 0.2 to 0.7 and the Dp reading on

chart is between 20% and 70%.

149

7.3.4 3-Phase Separator

A three phase horizontal separator will be use at CPP. Separator receives

production from individual well via manifold. The function of separator is to separate

produced gas and sand from the incoming well fluids in order to achieve crude oil

specification which is 1% or less.

7.3.5 Water Injection

Water Injection will be use in the future as secondary recovery methods for

pressure maintenance. It is relatively low cost and efficient means of improving oil

production from a depleting field and widely used. The equipment descriptions are as

follow:

i. Water injection system consist of coarse filtration, fine filtration, deaeration

and water injection pumps, equipped with hypochlorinator

ii. Seawater Lift Pump (sucking seawater for the system)

iii. Hypochlorinator is required as an anti-fouling to prevent marine growth and

discourage microbiological activity in side pumps, piping and equipment

7.3.6 Gas Handling

The produced solution gas is not used for commercial purposes but only for the

future gas lift supply, flaring, and on-site use for operated vessels, control systems,

pumps or even compressor itself. The produced solution gas after going through the

separator might still have little content of water and needs to be dehydrated before

compressed (for gas lifting purpose). The continuous absorption in a liquid glycol

desiccant is a preferable option compared to solid desiccant of silica gel.

7.3.7 Gas Lift Surface Facilities

No long term gas lifting is envisaged for Sumandak Selatan wells since the wells

are expected to be producing at high GOR. However, provision of space is made for

future implementation.

150

7.3.8 Electrical Power and Lighting

The electric power generation and distribution system will be provided for the

facilities on the platform with provision for future installed equipment. A closed cycle

vaporized thermo generator (CCVT) or a micro-turbine is envisaged to be used with a

configuration of 2 units, 1 unit on standby basis.

7.3.9 Drain System

Drain systems are important to allow equipment to be drained, opened, inspected

and repaired. Drain piping run throughout the platform and routed to vessels on the

lowest level of the platform – gravity drainage. Open drain systems deals with drain

fluids at atmospheric pressure. Open drain lines converge into headers and then flow to

Open Drain Caisson. Water is then disposed into sea and oil is skimmed off and pumped

into Closed Drain Vessel. Open Drain Caisson has atmospheric vent to release gas.

7.3.10 Flare Boom/Vent System

The flare system in Gelama Merah platform should be used as both a means to

depressure gas from various pieces of equipment within the platform and as a safety

mechanism for abnormal process operations that may create unwanted pressure surges.

These pressure surges are relieved to the flare system via pressure relief valves to protect

equipment and personnel. The flare stack package also will burn gas vapor emitted from

the hydrocarbon liquids that accumulate in the flare knock out drum.

7.3.11 Instrument Air System

Instrument air system will be used to operate instrument valves wellhead control

panel and fusible plug loop.

151

7.4 SAFETY FACILITIES SYSTEM

7.4.1 Safety Shutdown System

Objective of the safeguarding is to safeguard both the equipment and the overall

facilities. All new components installed will therefore link up with the currently existing

safeguarding system, allowing them to be shut down as part of an emergency shutdown

(ESD) of the facility. A safety shutdown system will provide the shutdown and fire

detection function and fail safe operation of all shutdown equipment. The Safety

Shutdown System performs specified functions to achieve or maintain a safe state of the

process when unacceptable or dangerous process conditions are detected. The systems are

separate and independent from regular control systems but are composed of similar

elements, including sensors, logic solvers, actuators and support systems.

7.4.2 Automatic Fire Detection and Alarm Systems

The alarm system shall be capable of immediate automatic activation with no

manual activation by the crew. The system shall include:-

i. Means for giving a visual and audible alarm signal automatically at one or more

indicating units whenever any detector comes into operation.

ii. When activated, the indicating units show the location where the fire is detected

in any space served by the system.

iii. Indicating units shall be centralized on the navigating bridge or in the Main Fire

Control station, which shall be so manned or equipped as to ensure that any alarm

from the system is immediately received by a responsible member of the crew.

iv. Constructed so as to indicate if any fault occurs in the system.

The detection system shall be operated by an abnormal air temperature, by an

abnormal concentration of smoke or by other factors indication of incipient fire in any of

one of the spaces to be protected. The detectors may be arranged to operate the alarm by

the opening or closing of contacts or by other appropriate methods. Detectors operated by

the closing of contact shall be of the sealed contact type and the circuit shall be

continuously monitored to indicate fault conditions. Detectors shall be:-

152

i. Fitted in an appropriate position and suitably protected against impact and

physical damage.

ii. Suitable for use in a marine environment.

iii. Placed in an open position clear of beams and other objects likely to obstruct the

flow of hot gases or smoke to the sensitive element.

At least one detector shall be installed in each space where detection facilities are

required and there shall be not less than one detector for each 37 square metres (400

square feet) of deck area or as per the approved platform’s safety plan. In large spaces the

detector shall be arranged in a regular pattern so that no detector is more than 9 metres

from another detector or more than 4.5 metres from a bulkhead.

There shall be not less than two independent sources of power supply for the

electrical equipment in the operation of the fire alarm and fire detection system, one of

which shall be an emergency source. The supply shall be provided by separate feeders

reserved solely for that purpose.

7.4.3 Life Saving Appliances

Life jackets must be sufficient to accommodate twice the total number of persons

onboard. Each lifejacket is to be fitted with a whistle and a light powered by water

activated battery. Each person shall be provided with a lifejacket stowed in his

accommodation. All survival craft, life rafts, lifejackets and lifebuoys are to be fitted with

retro-reflective material. The platform also shall be provided with sufficient

communication and emergency evacuation equipment to allow a safe and controlled

evacuation in case of emergency.

7.4.4 Platform Data and Communication System

A digital microwave radio system and a marine VHF radio system will be

installed at Gelama Merah with direct routing and interfacing to and from Semarang field.

The distance of 17 kilometres between Gelama Merah and Semarang requires a satellite

connection.

153

7.5 PIPELINES & HOST TIE-INS TO EXISTING PLATFORM

7.5.1 Pipeline Tie-Ins

The nearest CPP in the Sabah offshore is located in Samarang-B Platform or

(SMP-B), approximately 15-20km from the current Gelama Merah platform location.

Tie-in to currently existing platform is preferable as it reduces the cost for processing on

GMJT-A itself and reduces the cost for leasing a FPSO vessel for the whole 20 years

cycle. It would not be necessary to have the similar processing facilities in GMJT-A as

well as it will increase CAPEX, OPEX and deck load on the platform except equipment

for gas lifting and water injection in the future.

The scope of work required for the tie-in to Samarang Processing Platform B (SMP-B)

includes the following:

i. Fabrication and installation of new riser and receiver/launcher

ii. Structural strengthening required for platform upgrading

iii. Associated piping, new vessel installation and other modifications to tie-in to

the existing facilities.

iv. Deck extension at cellar deck to accommodate the riser.

Figure 7.1 Tie-in from GMJT-A to SMP-B diagram

154

7.5.2 Pipeline Optimum Sizing using PIPESim

The detailed study on the pipeline design should includes the following elements

which are (1)Pipeline flow assurance and line sizing, (2) Pipeline route selection, (3)

Geohazard Analysis, (4) Stability analysis and determination of weight coating/trenching

requirements, (5) Determination of wall thickness and steel grade, (6) Pipe spanning

analysis and (7)Pipeline installation studies to verify alternative installation options.

7.5.2.1 Fluid flow pattern from PIPESIM®

The maximum flowrate from the Gelama Merah field is 9000 bpd. The LP and

HP separator pressures are assumed to be in range of 50 psi to 150 psi and 160 psi to 250

psi respectively. In determining the pipeline size that can cater pressure drop along the 17

km to the Samarang-B host platform, a simulator of PIPESIM® is used. The landing

pressure at Samarang-B is 200 psi, from the HP separator pressure. The pressure drop

simulation for the 17 kilometer pipeline from GMDP-A to Samarang-B was simulated for

different pipeline sizes of 8, 10, 12 and 14 inches.

The result shows that 8 and 10 inches pipe were having early pressure drop while

for 12 inches just barely drop below the landing pressure. The most suitable pipe size is

14 inch which can cater the distance and maintains above the HP separator pressure. It

can be deducted here that pressure drop can be reduced if pipe size is increased. Result

from the simulation indicate bubble flow pattern along the pipeline. However there will

be severe slug flow at riser base of the pipeline. Pigging operation also will cause

transition of flow to slug flow. Therefore, to control slug flow, automated control valve

at the upstream separator can regulate the flow and pressure into the separator. It is also

proposed to utilise pigging operation with gas bypassing capability to minimize slug flow.

However, no data were available on the seabed/soil condition, or even the

terrain of the sea. Thus the values for all these are based on an assumption figures.

These data should be recalculated once the actual information are available.

155

7.5.2.2 Flow Assurance

Flow assurance is making sure the gas/oil/water from the wells makes it to the

delivery location. Several concerns need to be considering in designing the pipeline from

Gelama Merah to Samarang-B to assure the delivery which are:

Pipeline or wellbore rupture from corrosion

Pipeline blockage by hydrates or wax

Severe slugging in riser destroys separator

Well can’t lift its liquids and dies

Separator flooded by liquids

Large pressure losses in pipelines cause flow rates to be lower than should be

7.5.2.3 Pipeline Route Selection

Various surface facilities options were studied for the selection of the appropriate

development for Gelama Merah. . The surface facilities options studied are:

As a satellite platform with multiphase pipeline tie back to Samarang-B CPP,

the oil produced with natural depletion plus water injection scheme. Water

injection came from Samarang facilities which mean a water pipeline coming

from Samarang. This is found to be the most economical option amongst the

others.

As a satellite platform, crude oil to be evacuated through multiphase pipeline to

Labuan Crude Oil Terminal where separation facility is assumed to be there.

As a satellite platform, crude to be evacuated through multiphase pipeline to a

rental FPSO. Crude processing will be done on FPSO. Oil will be exported via

oil tanker.

As a removable jack up platform with capabilities of processing or known as

MOPU (Mobile Offshore Production Unit). Crude oil will be stored on rented

FSO and exported via oil tanker.

156

For satellite platforms, gas lift is expected in future and this can be done by

utilizing gas compression facility on the host platform of Samarang. All the satellite

platform option will be treated as unmanned platform with maintenance philosophy. The

chosen development is based on minimum expenditure required to develop the facility.

7.5.2.4 Geohazard Analysis

A seismic hazard assessment involves the prediction of the level of ground motion

that could occur at a Gelama Merah. In practice, seismic hazard assessment is the

determination of a level of vibratory ground motion, based on probabilistic considerations,

to which a structure needs to be designed to comply with regulatory design criteria. This

system typically includes field assessment protocals and database applications to analyse

and manage inspection information from year to year and prioritise high risk sites for

further assessment. Using this system allows pipeline constructors to gain access to the

most current information about Gelama Merah hazards including the hazard's history,

pictures, when it was last inspected, and when it is due for inspection. This analysis need

to be done to reduce the risk during the routing, construction and operation stages of

pipeline life at Gelama Merah.

7.5.2.5 Trenching Requirements

Many pipelines are trenched to protect them from trawling damage or to enhance

stability. It is necessary for the length of all lines have some degree of protection, either

trenching (lowering) or burial (covering) over part or all of their length. Consideration

should be given as to where these measures are required along the segments of the

pipeline route. For instance, these might require application along the whole pipeline

length, or be limited to areas where the pipeline traverses shipping channels or harbour

areas. In Gelama Merah, pipeline measures can be used in combination, for instance

thicker wall pipe, concrete protective coating, trenching and engineered rock / gravel

protection may be required for offshore. The ongoing integrity of protection measures

will require periodic assessment through inspection/ survey.

157

7.5.2.6 Pipe Span Analysis

Supports for piping must be spaced with respect to three considerations:

a) Ability to place a support at some desired location

b) Keeping sag in the line within limits that will permit drainage.

c) Avoiding excessive bending stresses from the uniform and concentrated loads

between supports

Procedure for Calculation of Maximum Span Of Gelama Merah

Design formulas for calculating bending stress and deflection between supports

are derived from the usual beam formulas, which depend upon the method of support and

the type of loading.

Maximum Bending stress,

[1]

Maximum Deflection

[2]

Where, w = uniformly distributed weight of pipeline in N/m

w c = concentrated weight on pipeline in N

L = Span length in m

D = Outside diameter of pipe in m

d = Inside diameter of pipe in m

E = Modulus of elasticity of pipe in N/m2

I = Moment of Inertia of pipe in m

A. Calculation of total weight

Total weight = weight of pipe (wp) + weight of fluid (wf)

158

B. Weight of pipe

Thickness of pipe can be calculated as

[3]

Where, P = Pressure of the fluid in pipe in N/m2

S a = Allowable stress in pipe in N/m2

E = Quality Factor from ASME B 31.3

Y = Coefficient of material from ASME B 31.3

Annular cross-sectional area of pipe = [4]

C. Calculation of weight of fluid

Weight of fluid = [5]

Calculating the maximum support span for transporting water through a seamless

stainless steel pipe (ASTM A 312 TP 316 L) of 300 NPS through a distance of 17 km

from Gelama Merah to Semarang-B. Pressure in pipe is 20 bar at atmospheric

temperature.

D = 0.3239 m [2]

P = 20 bar

S b = 34.53 MPa (30% of S a = 115.1 MPa) [4]

Therefore, using equation [3], thickness of pipe comes out to be 6 mm.

Hence, d = 0.3071 m [2].

Weight of stainless steel pipe is calculated 641.16 N/m [5].

Weight of water = 726.64 N/m

Total weight = 1367.8 N/m

Moment of inertia = 1.0369 x 10-4 m 4

Modulus of Elasticity = 195122 MPa

159

L

600

Maximum Span between supports is calculated as 11.38 meters, which is rounded back to

11.0 meters. Hence number of supports required for 17 km pipeline is approx. 1364. With

the above values, deflection comes out to be 12.89 mm, which is less than . Hence

the calculated span is also safe in deflection.

7.5.3 Wax mitigation

The average pour point of crude is 27 to 29° C and cloud point is around 32 to 36°

C. The sea bed temperature is around 22° C at 43 metres water depth. From DST and

PVT data, there in no indication of wax content. But after a period of time, there can be

possibilities of wax presence. Therefore measures shall be taken to avoid wax

accumulation. The following option to mitigate possible wax at this time is insulation of

the pipeline. The insulation comes as standard of pipeline package is specified to 0.2 btu

per hour per feet area of heat transfer. Therefore it shall be enough for several hours

pipeline shutdown. Consequently, if there is wax presence in future, the wax mitigation

plan will be as follows:

Injecting pour point depressant.

Regular pigging to remove wax builds up.

Wax inhibitor injected before planned shutdown.

7.5.4 Slug Suppression System (Sss)

In a flowline/riser system large liquid slugs and surges can be formed by

operational changes or due to the flow conditions and physical characteristics of the

flowline. These liquid slugs and gas surges may result in large oil and gas production

losses when they arrive at a production platform. Fluids from Gelama Merah’s GMJT-A

will be transferred via the 14 inch pipeline, in which severe riser slugging is expected to

occur. This type of slugging takes place from the start of production and a slug

suppression system is required to break the slugs, smoothing flow streams and avoiding

plant upsets.

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7.6 PIPELINE CORROSION MANAGEMENT

7.6.1 Corrosion Inhibitor Injection

From PVT data DST sample, Gelama Merah fluids are not corrosive in nature. It

is predicted that water cut will occur to increase 30% upon production and peaking at

90% by the end of its producing life. Therefore Gelama Merah requires constant

monitoring and sampling to detect corrosion from early production life to protect the

carbon steel pipeline. Corrosion inhibitors can also be sprayed or painted on to create a

thin layer which will provide protection from corrosion. It can be applied when they oil

locks and hinges to prevent them from rusting and to keep them moving smoothly.

Corrosion inhibitor is assumed to mix with diesel onshore and supplied by boat in bulk to

the platform. System reliability target should be 95% to minimize corrosion allowance in

the subsea pipeline. The injection system is operated by utility gas.

7.6.2 Corrosion Allowance

This is provided by the difference between the diameter required for initial

pressure containment and the diameter required for laying down the pipe.

7.6.3 Pipeline Pigging

Pigging refers to the practice of using pipeline inspection gauges to perform

various operations on a pipeline without stopping the flow of the product in the pipeline.

Pigging is required for the purpose of:

i. Removal of stagnant water pools from low spots in the line where corrosion

inhibitor is diluted.

ii. Removal solids from settling in the pipeline e.g. wax

Pigs are used in lube oil or painting blending to clean the pipes to avoid cross-

contamination, and to empty the pipes into the product tanks. Initial pigging frequency

after start up is once a week. This schedule will reduce to once every three months after

operational experience is gained, which is considered adequate and to take advantage of

161

the buildup of waxy layer on the pipe wall to control corrosion. To optimize pigging

frequency, pigging debris will be analyzed for corrosion products.

7. 6.4 Corrosion Monitoring

The corrosion monitoring system will be designed for unmanned platform and the

inhibited system proposed. This will reflect the type of corrosion mechanism involved

which are mechanical, electrical, or electrochemical devices. Corrosion monitoring is

necessary to:

i. Monitor the availability of the inhibition system to optimize inspection

frequency.

ii. Monitor pigging debris for corrosion products.

iii. Cathodic protection and external anti corrosion coating shall be applied to

maintain the pipeline integrity.

7.7 ABANDONMENT

Decommissioning of Gelama Merah platform will take place when it is no longer

economical to continue production. According to the PETRONAS specification and

International Maritime guidelines for offshore development structures, the platform has

to be fully removed during the abandonment stages. The design of the initial platform

should have the design such that it can be removed readily during the abandonment

stages. The well shall be cemented and plugged above at least 100ft from the current

depleted zones and killed. The jacket piles are to be cut below the mudline level, while

the pipelines has to be pigged and capped. The cost for decommissioning are shown in

the next section, which includes the cost for cutting spread, crane spread, multi-service,

transportation spread and dumping. A total of 30-35 days is expected for complete

decommissioning of the whole jacket structure.

162

7.8 FACILITIES CAPEX , DECOMMOSSION & OPEX

7.8.1 Capital Expenditure (CAPEX)

The production pipeline is planned for a tied in to the Semarang CPP which is located

approximately 15 km from the Gelama Merah platform. The CAPEX for the facilities (without

the cost for CPP) is computed using Que$tor 9.4. The 6-legged jacket to be used is planned for

20 years of production life with 5 years assisted by water injection facilities of plateau

production at 5MSTB/day for the field. The estimated CAPEX are listed below in Table 7.3.

Cost breakdown Mil USD ($) Mil MYR (RM)

Topside

Equipment 2.687 8.27596

Materials 1.164 3.58512

Fabrication 1.516 4.66928

Installation 4.73 14.5684

Hook-up and commissioning 0.297 0.91476

Design & Project Management 1.939 5.97212

Insurance & Certification 0.493 1.51844

Contingency 1.283 3.95164

Jacket

Materials 2.21 6.8068

Fabrication 1.654 5.09432





Offshore Pipeline

Materials 0.964 2.96912





SUB TOTAL (w/o contingency) 38.8044 119.517552

TOTAL COST 43.116 132.79728

Table 7.3 CAPEX for jacket facilities for Gelama Merah

*Basis of 1USD = 3.08 MYR as of November 2010

163

7.8.2 Decommisioning Cost

Apart from the CAPEX, the decommissioning cost for abandonment phase would need to

be taken into consideration as well in the end of the production life. Four options are reviewed

for the CAPEX and Decommissioning cost which are:

Option 1: Pipeline tie-in to Samarang-B CPP (17 km)

Option 2: Pipeline to LCOT (75 km), requires GMJT-A to be a CPP

Option 3: Production via FPSO and subsea tie-back

Option 4: Production via Semi-sub

Components

Method of Production

Opt 1: Tie-in to Samarang

CPP Opt 2: Pipeline to LCOT

Mil USD Mil MYR Mil USD Mil MYR

Topside 14.109 43.456 38.513 118.620

Jacket 11.916 36.701 20.479 63.075

Offshore Pipeline 16.818 51.799 39.009 120.148

Topside Decommissioning 3.371 10.383 3.584 11.037

Jacket Decommissioning 4.478 13.792 4.478 13.792

Pipeline Decommissioning 3.4365 10.585 5.404 16.644

TOTAL 54.129 166.716 111.467 343.318

*Decommissioning includes scrap payback

Components

Method of Production

Opt 3: FPSO + Subsea

TB

Opt 4: Semi-sub + Subsea

TB

Mil USD Mil MYR Mil USD Mil MYR

Topside 26.151 80.545 17.510 53.931

Subsea Equipments 53.125 163.625 48.894 150.594

Tanker 118.316 364.413 0.000 0.000

Offshore Loading 0.000 0.000 114.352 352.204

Semi-Submersible 0.000 0.000 310.408 956.057

Topside Decommissioning 3.8405 11.828 3.7875 7.575

TOTAL 201.433 620.414 494.952 1524.451

*Decommissioning includes scrap payback

Table 7.4 Comparison of Cost for different tie-in options

164

From Table 7.3 and 7.4 comparison, the preferable option is to tie in to as there is

already an available CPP in Samarang and it involves smaller CAPEX. In order to equip the

Gelama Merah platform with CPP facilities (quarters, separation, process) would require an

additional of MYR 177 million. Utilizing the FPSO would nearly triple the CAPEX compared to

Option 1.

7.8.3 Operating Expenditure (OPEX)

The estimated OPEX for the Gelama Merah platform is as follows:

Option 1 Option 2 Option 3 Option 4

Operating Cost (OPEX) Million MYR (RM) / YEAR

Platform Inspection and Maintenance

Topside 1.509 1.146 0.748 0.440

Jacket 2.901 2.901 0.000 22.339

Tanker/Float 0.000 0.000 8.793 1.583

Pipeline Inspection and Maintenance

Survey cost 1.229 3.909 0.000 0.000

Subsea Equipments 0.000 0.000 10.219 10.186

Logistic and Consumables

Chemical Supplies 0.071 0.071 0.071 0.071

Fuel/Gas/Diesel 0.009 0.003 0.151 0.148

Supply boat / rescue boat 10.096 10.096 6.520 6.520

TOTAL ESTIMATED

OPEX 15.815 18.125 26.504 41.287 Table 7.5 Operating Cost for Gelama Merah platform

From the cost estimation for the CAPEX, OPEX and Decommissioning, it can be seen

that Option 1 provides a more feasible option to produce the hydrocarbons from Gelama Merah.

Option 3 and 4 maybe be able to store and evacuate higher volume of hydrocarbon in terms of

efficiency, however, considerations will have to be made for Gelama Merah, since it only

produces an average of 4000-6000stb on a daily basis for the field. The economic evaluation

over a 18 years of life cycle will be discussed in the next phase.

165

PHASE 8 ECONOMIC ANALYSIS

8.1 INTRODUCTION

The base case for the subsurface development for Gelama Merah field are one

vertical injector well, two horizontal wells, and two horizontal wells. The five oil

producer wells will tap on the reservoir layer at 9.0, 9.1 and 9.2. The surface development

is planned for a tie-in to the Samarang Central Processing Platform (CPP) located at

Semarang Mother Platform B (SMP-B), with approximately 15-17km length of pipelines

from GMJT-A platform. The full field development concept can be under the water

injection recovery mechanism and gas lifting for production optimization (prolong life of

well when water cut increases beyond 60%) for an estimated 20 years production on

stream.

The development option will be evaluated in terms on economic based on four

parameters which are the Net Present Value (NPV), Payback Period, Internal Rate of

Return (IRR) and also the Profit to Investment Ration (PIR) on the economic feasibility.

Sensitivity using the spider plot is also conducted for the selected case to determine and

analyze the effect of increasing and decreasing the capital expenditure (CAPEX),

operating expenditure (OPEX), oil price and production rates with reflect to the NPV.

The economic analysis will be used as a final selection method to maximize recovery for

the development strategies.

The objectives of the economic analysis on Gelama Merah field development options are

to:

i. Perform economic analysis on the available options and to identify the most

economical strategy options for development (based on NPV, Payback, IRR

and PIR)

ii. To analyze and determine the key paramaters (CAPEX, OPEX, Oil Price,

Production) that may have significant impact towards the economic outcome

of the model.

166

8.2 DEVELOPMENT EXPENDITURES

As of in the previously discussed drilling and facilities phase, four (4) options of

production method were analyzed in term of the CAPEX, OPEX and decommissioning

cost. The cost are summarized in the Table 8.1 based on Que$tor v9.4, database for

Quarter 3, 2010.

Option 1: Pipeline tie-in to Samarang-B CPP (17 km)

Option 2: Pipeline to LCOT (75 km), requires GMJT-A to be a CPP

Option 3: Production via FPSO and subsea tie-back

Option 4: Production via Semi-sub and subsea tie-back

Production Options Option 1 Option 2 Option 3 Option 4

Facilities CAPEX Mil USD 43.116 98.000 197.590 491.162

Development Wells Mil USD 34.091 34.091 34.091 34.091

Decommission Mil USD 11.285 13.465 3.841 7.575

Fixed OPEX Mil USD/year 5.135 5.885 8.605 13.405

Sub Total w/o OPEX Mil USD 88.492 145.556 235.522 532.828 Table 8.1 Summary of development costs

Estimated production life: 18-20 years

Production plateau duration: 3 years

Production rate at plateau : 5000-6000bbl/day

Estimated UR : 19.48 MMStb

RT price assumption at 2005 : Brent $25/bbl

From Table 8.1, Option 1 provides the most economical model as the CPP units

are already available in Samarang- Mother Platform B (SMP-B) and a shorter pipeline is

required compared to Option 2. Option 3 and 4 on the other hand, does not seem

economically feasible as compared to Option 1 because of the higher CAPEX and higher

OPEX. ( It can still be compared using economic model if the OPEX are lower). Thus for

the economic evaluation in the later section, the first option which is utilization of the

pipeline tie-in to the Samarang B CPP platform is considered.

167

8.3 PSC ARRANGEMENT / FISCAL TERMS

The PSC 1985 was recommended (by Coordinator) to be used for economic

analysis purposes for this field. Gelama Merah field development project involves in the

production of commercial for oil only, and therefore, the fiscal terms only deals with that

for oil.

Terms Details

Effective Date 1st January 2005

Contract Duration 24 years

- Exploration Period 5 years

- Development Period 4 years

- Production Period 15 years from 1st commercial prod

Royalty Rate 10%

Cost Oil Ceiling Rate 50%

Profit Oil Sharing (Np < 50MMbbl)

- First 10 kbopd

- Second 10 kbopd

- Above 20 kbopd

PETRONAS : Contractor

50:50

60:40

70:30

Profit Oil Share (Np > 50MMbbl) 70:30

PSC Base Price $25.00/bbl escalated 5% p.a from Effecve date

Export Duty (ED) Rate 10% of profit oil exported

Research Cess 0.5% x Contractor Entitlement

Petroleum Tax Rate 38%

Oil Supplemental Payment 70% x [(Oil Price-Base Price)/Base Price] x

(Cont PO – Export Duty)

Fixed Structure 10% per year (10 years)

Facility/Pipeline 20% Initial + 8% annual (10 years)

Tangible Drilling 20% Initial + 8% annual (10 years)

Intangible Drilling 100% write off

Table 8.2 Fiscal terms for PSC 85’

168

Figure 8.1 Revenue flow diagram for PSC between project, contractor & state

8.4 EVALUATION BASIS AND ASSUMPTIONS

i. Base Case

The proposed base case from the reservoir development are three deviated

wells to tap 9.2, one deviated to tap 9.0, one horizontal well to tap 9.1 and

one vertical well for water injection. All 5 non-vertical wells are for oil

production.

ii. Reference Year

The reference year for Gelama Merah is the year of the evaluation, which

in this case is 2004 for the escalation based on PSC 1985.

iii. First Oil

The first oil to be produced from Gelama Merah is expected to be in 2011.

169

iv. Production Period

A production period of 18 years is expected with a plateau of 7800Stb/d

for the first 2 years and declining.

v. Cash Flow Model

The cash flow model is assumed to be in the Money of the Day (MOD)

term.

vi. Base Oil Price

The oil price is assumed to be USD 25/barrel for Brent crude, and

escalation of 5.0% per annum is assumed based on the fiscal terms in PSC

1985 from year 2005. The price of oil fluactuates slightly above USD

55/barrel from year 2008-2010 and the group believes that the escalation

of 5.0% per annum should be reconsider as the oil price is believed would

not be able to sustain at price higher than USD 80/barrel.

vii. Operating Cost (OPEX)

The fixed OPEX is obtained to be approximately USD 5.13mil per year

which consist of the jacket and topside, with a pipeline connected to

Samarang-B platform facilities as central processing platform. Variable

OPEX vary from USD 2-5mil per year based on requirement for water

injector or gas lift assisted supply.

viii. Hurdle Rate for IRR

A hurdle rate for PETRONAS at 10% is chosen, which consisted of

weighted average cost of capital 8.5% and associated risk of 1.5%.

ix. Discount Rate

The discount rate assumed to be 10% during the evaluation according to

the opportunity cost of capital, acquisition cost of capital and risk

management.

170

8.5 DEVELOPMENT SCENARIOS

The Reservoir Engineer has produced six subsurface scenarios screening:

8.5.1 First Screening: Well type

There are 2 available scenarios from the reservoir initially as tabulated in Table 8.3 below:

Case Scenarios RF (%) Oil produced

(MMbbl)

A 7 vertical wells prod rate 2080stb/d,14 years 12.7 5.169

B 5 deviated wells prod rate 2184stb/d, 14 years 13.34 5.427

Table 8.3: List of Initial Subsurface Scenarios

8.5.2 Second Screening: Pressure Maintenance scheme

After that, from the analysis, there are two options available for scenario B as tabulated in

Table 8.4 below:


(MMbbl)

B1 5 deviated wells + Gas injection (3780bbl/d)

Production rate 2184stb/d,14 years 13.34 11.16

B2 5 deviated wells + Water injection(3780bbl/d),

Production rate 4326stb/d, 14 years 26.4 10.75

Table 8.4: List of second screening Subsurface Scenarios

8.5.3 Third Screening: Injection Time

The third screening for B2a or B2b depend on which one of them will give us more

production economically base on injection time as tabulated in Table 8.5 below:


(MMbbl)

B2a

5 deviated wells + Water injection(3780bbl/d) 14 year.

Production rate 2184stb/d, 14 years.

Inject after pressure start to deplete.

13.34 5.427

B2b

5 deviated wells + Water injection(3780bbl/d) 14 years.

Production rate 4326stb/d, 14 years.

Inject on 1st day of production.

26.4 10.75

Table 8.5: List of third screening Subsurface Scenarios

171

8.5.4 Fourth Screening: Injection Rate

The fourth screening for B2b1 or B2b2 depends on which one of them will give us more

production economically base on injection time as tabulated in Table 8.6 below:

Case Scenario RF (%) Oil produced

(MMbbl)

B2b1

5 deviated wells + Water injection(3780bbl/d).

prod rate 4326stb/d, 14 years.

Inject on 1st day of production

26.4 10.75

B2b2



Inject on 1st day of production

26.93 10.97

Table 8.6: List of Fourth screening Subsurface Scenarios

8.5.5 Fifth Screening: Production Control Mode

The fifth screening for B2b1a and B2b1b depends on which one of them will give us more

production economically base on production control mode as tabulated in Table 8.7 below:


(MMbbl)

B2b1a



Inject on 1st day of production. Oil control mode.

26.4 10.75

B2b1b


prod rate 3759.3 stb/d, 14 years.

Inject on 1st day of production. BHP control mode.

22.9 9.34

Table 8.7: List of fifth screening Subsurface Scenarios

8.5.6 Sixth Screening: Production Life

The sixth screening for B2b1a1 and B2b1a2 depends on which one of them will give us more

production economically base on production life as tabulated in Table 8.8 below:


(MMbbl)

B2b1a1 5 deviated wells + Water injection(3780bbl/d).

prod rate 4326stb/d, 14 years. Inject on 1st day of

production.Oil control mode. Production life 14 years.

26.4 10.75

B2b1a2 5 deviated wells + Water injection(3780bbl/d).

prod rate 4326stb/d, 14 years. Inject on 1st day of

production.Oil control mode. Production life 20 years.

47.8 19.5

Table 8.8: List of Fourth screening Subsurface Scenarios

172

8.6 ECONOMIC RESULTS

For the economic evaluation of the Gelama Merah field, the expenditures include the

development costs including the operation expenditure and capital expenditure, hence economics

evaluation were not going to cater for that particular cost. The cash flow profile is given in USD

Nominal to comprise the impact of inflation. The Net Present Value of the Gelama Merah field

project has been discounted at 10% to reflect on the cost of capital and 0% of risks since the risks’

of the acquired field can be considered negligible.

The economics calculations are done on a spreadsheet model. The results are tabulated below

consequently for all the screening available:

8.6.1 First Screening Results:

The first screening results tabulated in Table 8.9 below:

Parameter Unit Subsurface Scenarios

Case A Case B

IRR % 12 14

NPV @ 10% USD MM 3.23 8.24

Breakeven Years 7.08 6.75

PIR Ratio 0.223 0.323

Table 8.9: First Screening Results for Subsurface Scenarios

The best projects ranked by internal rate of return (IRR), net present value (NPV) @ 10%,

Breakeven and PIR is Case B. So Case B will proceed to second screening for further

improvement economically.

8.6.2 Second Screening Results:

The subsurface hydrocarbon evacuation scenarios are performed on the base case B and

the results are tabulated in Table 8.10 below for the screening of gas injection (B1) and water

injection (B2) at 3780bbl/d STB /day:

173


Case B1 Case B2

IRR % 14 18

NPV @ 10% USD MM 8.24 16.82


PIR Ratio 0.323 0.5

Table 8.10: Second Screening Results for Subsurface Scenarios

From the table it shows that Case B2 have the highest value of IRR, NPV and PIR. The best

case if ranked by breakeven also goes to Case B2. So, Case B2 will proceed to the third

screening.

8.6.3 Third Screening Results:

The subsurface hydrocarbon evacuation scenarios are performed on the case B2 and the

results are tabulated below for the screening of water Injection after pressure start to deplete

(B2a) and water injection on 1st day of production (B2b) at 3780bbl/d STB /day:


Case B2a Case B2b

IRR % 14 19.20

NPV @ 10% USD MM 8.24 18.56


PIR Ratio 0.323 0.61

Table 8.11: Third Screening Results for Subsurface Scenarios

The best projects ranked by IRR, NPV, breakeven and PIR is Case B2b. So Case B2b

will proceed to next screening for further enhancement economically.

8.6.4 Fourth Screening Results:

The subsurface hydrocarbon evacuation scenarios are performed on the case B2b and the

results are tabulated in Table 8.12 below for the screening of water Injection on 1st day of

production at at 3780bbl/d (B2b1) and 4716bbl/d (B2b2):

174

Parameter Unit

Subsurface Scenarios

Case B2b1 Case B2b2

IRR % 19.20 19.5

NPV @ 10% USD MM 18.56 17.78


PIR Ratio 0.61 0.65

Table 8.12: Fourth Screening Results for Subsurface Scenarios

The best project if ranked by IRR, NPV, Breakeven and PIR is Case B2b2. But all parameter

value for Case B2b1 and B2b2 shows a slightly different when increased the injection rate from

3780bbl/d to 4716bbl/d. By concerning the pump life, it is better to just maintain the low

injection rate since it show low increasing in parameter values of case B2b2. So, Case B2b1 is

the best case to proceed to next screening.

8.6.5 Fifth Screening Results:

The subsurface hydrocarbon evacuation scenarios are performed on the case B2b1 and the results

are tabulated in Table 8.13 below for the screening base on production control mode whether oil

control mode (B2b1a) or BHP control mode (B2b1b):


Case B2b1a Case B2b1b

IRR % 19.20 17.6

NPV @ 10% USD MM 18.56 14.34


PIR Ratio 0.61 0.43

Table 8.13: Fifth Screening Results for Subsurface Scenarios

From the table it shows that Case B2b1a is the best if ranked by IRR, NPV, Breakeven and

PIR. So Case B2b1a will proceed to the next screening stage.

8.6.6 Sixth Screening Results:

The subsurface hydrocarbon evacuation scenarios are performed on the case B2b1a and the

results are tabulated in Table 8.14 below for the screening base on production life where

production life of 14 years for case B2b1a1 and 20 years for Case B2b1a2:

175


Case B2b1a1 Case B2b1a2

IRR % 18 36

NPV @ 10% USD MM 16.82 62.9


PIR Ratio 0.5 1.36

Table 8.14: Sixth Screening Results for Subsurface Scenarios

After 5 screening stages, Case B2b1a is the best base case for the final screening stage.

From the 2 cases in the table, the best project ranked by IRR, NPV, breakeven and PIR is

Case B2b1a1. So Case B2b1a1 is the best way to develop the field economically.

8.7 REVENUE SPLIT

The figure below shows the total revenue split for Case 12 at NPV @ 10%. The total

revenue discounted at 10% is USD 552.03 MM. The Government takes the largest percentage,

followed by opex, which indicates the high operating cost associated with the project about USD

155.60 MM. The contractor is able to take the percentage of 11.4%, which is equivalent to USD

62.90 MM.

The below table shows the percentages of the split of the revenue:

NPV, USD MM Fraction Percentage, %

Government 164.98 0.299 29.9

Contractor 62.90 0.114 11.4

PETRONAS 83.64 0.151 15.1

OPEX 155.60 0.282 28.2

CAPEX 84.91 0.154 15.4

Total 552.03 1.000 100.0

Table 8.15 Revenue split for Gelama Merah project

*Refer to Appendix F for screen shot of tables

176

8.8 SENSITIVITY ANALYSIS

Economic models and evaluation were developed to test as well for the sensitivity with

the main objective to assess the robustness of the selected project. The sensitivity that were

tested are on the CAPEX, OPEX, oil price and production on the base case project.. 3 methods

were used which are the Spider Plot, Tornado Chart, and Delay or Acceleration of project year.

8.8.1 Spider Plot

The parameters are tested for a difference of +/-40% individually using sensitivity control

in spreadsheet. The results are shown in Table 8.16 and Figure 8.2.

Figure 8.2 - Spider Plot for NPV at 10% base case project

Sensitivity % 60 70 80 90 100 110 120 130 140

Production 5.42 22.4 37.46 52.99 62.9 75.72 86.4 102.94 118.4

CAPEX 84.63 79.27 73.91 68.43 62.9 57.38 51.86 46.3 40.63

OPEX 78.48 74.68 70.84 66.9 62.9 58.82 54.63 50.45 46.31

Oil Price 1.39 17.5 32.86 47.99 62.9 77.72 92.4 106.94 121.4

Table 8.16 - Sensitivities value for NPV at 10%

y = 1.3569x - 72.955

y = -0.5501x + 117.82 y = -0.4031x + 102.98

y = 1.4953x - 87.184

0

20

40

60

80

100

120

140

40 60 80 100 120 140 160

Production

CAPEX

OPEX

Oil Price

Linear (Production)

Linear (CAPEX)

Linear (OPEX)

Linear (Oil Price)

177

The analysis showed that if the OPEX are increased by 40%, the project will still

have a NPV of USD$ 46.31mil, and if the OPEX are reduced by 40%, the NPV is up to

USD$ 78.48mil. This indicates that the OPEX is robust and is not as sensitive towards

the NPV as shown by the change of CAPEX. The CAPEX at increased and decreased

40% shows a value of NPV at USD$ 40.63mil and USD$ 84.63mil respectively.

For a development of a small field, most commonly the oil price, production

annually and CAPEX are very much sensitive to variation as shown in Figure 8.2.

Spider Plot shows that the steeper the “legs” of the spider, the more sensitive the project

changes in that variable. The Production, Oil Price and CAPEX have steeper curve in the

Spider Plot. Stand alone offshore projects are typically most sensitive to variation in

CAPEX and oil price. The CAPEX is steeper than OPEX as they are the front end costs,

while Oil Price, it determines the revenue of the project. However, sensitivity analysis

does not take into account the probability of different assumptions applying and only tells

the implication if one parameter is altered one at a time.

8.8.2 Tornado Chart

Besides the Spider Plot, the Tornado chart can also be used to reflect the effect of

the economic parameter towards the project. The values of NPV at 10% from Table 8.3.

The smallest range is at the bottom and the largest will be at the top, creating an image

similar to a tornado, hence the name.

Figure 8.3 Tornado chart analysis for base case

-60 -40 -20 0 20 40 60 80

1

Tornado Chart

Oil Price Production CAPEX OPEX

178

The zero axis represents the base case with NPV of USD$ 62.9mil as in Figure

8.3. It shows that the oil price is most sensitive followed by production/reserves, CAPEX

and OPEX.

8.8.3 Delay/Acceleration Effect of Production

In addition to the sensitivity analysis using Spider Plot and Tornado Chart, the

delay and acceleration impact on the economic parameters is also analyzed. Table 8.17

below shows the summary for the NPV at 10%, IRR, Payback Period and PIR for the

cases.

Parameters Units Subsurface Evacuation Scenarios

Base Case Delay Accelerate

NPV @ 10% USD MM 62.90 54.25 83.01

IRR % 36 25 47

Payback year(s) 3.52 4.88 2.33

Economic limit year(s) 20 19 20

Discounted CAPEX USD MM 104.88 106.90 106.37

Terminal Cash Flow USD MM 115.62 125.93 118.89

CPI ratio 0.741 0.639 0.978

PIR ratio 1.102 1.178 1.118

Table 8.17 Comparison of current/delay/acceleration of project economics

The assumptions hold is that there is no geological changes in the static model in

the 3 years of study for the current base case, delayed of 1 year and acceleration of 1 year.

The life cycle is also maintained at 19-20 years. The reference year for the first

production in this case is in 2011.

As shown in Table 8.17, accelerating the production by 1 year will increase the

profibitality and investment efficiency where the CPI ratio increases as well as payback

period shortens. On the other hand, delaying the production a year will decrease the net

present worth and also increase the payback period. In all the three cases, the Capital

Productivity Index is more than zero, and therefore theoretically would be an

acceptable project.

179

8.9 RECOMMENDATIONS

The economic results for the Base Case options from Facilities and Reservoir

Development Plan can be summarized as follows:

Best Option Option 1: Tie in to Samarang CPP

Sensitivities 3 deviated wells for 9.2

1 horizontal well for 9.1

1 deviated well for 9.0

1 vertical water injector

NPV @ 10% USD$62.9 Million

IRR 36.0%

Capital Expenditure USD$ 84.93mil (undiscounted)

Pay back Period 3.52 years

Economic Life 20 years

Table 8.18 Summary of Economic Analysis

With the current base case for this option, the potential oil development of

Gelama Merah Field is quite attractive with a positive NPV at Brent Oil Price of

US$25.00/bbl at the year of 2005, which is a low case. Furthermore, with the current oil

price trend, developing Gelama Merah Field will become more economical and profitable.

The profitability and investment efficiency of this option can further be enhanced

by reducing capital expenses and recover more reserves. From the sensitivity analyses,

the most crucial parameters are oil price, reserves as well as capital costs. Maximizing

recovery reserves and minimizing capital costs are beneficial to the company since crude

oil price is not within our control. Delaying or accelerating the project by one year will

not have massive impact towards the net present value of the project as shown in Table

8.17, indicating the robustness of the project.

180

PHASE 9 HSE & SUSTAINABLE DEVELOPMENT

9.1 GENERAL HEALTH, SAFETY & ENVIRONMENT (HSE)

PCSB’s main goal for continuous improvement in HSE is towards the goal of

zero harm to the people and also the environment in regard of the assets and operation.

The performance of HSE are measured based on on-going bases against both internally

and externally set of standard with ISO 14000 certified to meet the international standard

for environmental management systems.

PCSB also aims towards positive contribution to the host communities and the

surrounding environment, and thus, supports a number of sustainable development

projects and programs at both local and international levels. Long term interest is focused

as this will integrate the trust amongst the employee, stakeholders and also the

communities.

9.2 HSE MANAGEMENT SYSTEM (HSEMS)

In all the business activities, PCSB shall comply to the HSEMS which generally

defines the policy, strategic objective, organization, and the arrangement in terms of HSE

perspective which is necessary to manage identified risks that are associated. The

approach is shown in the diagram below:

Figure 9.1 HSEMS Approach Sequence

The HSEMS provides the standard safety procedures and guidelines to be

performed and also adopted to ensure that appropriate considerations are fully taken. The

elements and principles are set that the HSEMS are mandatory and applied to all parties

that are undertaking the scope of work under the projects from PCSB.

Risk Management

Planning & Procedures

Implementation &

Performance Monitoring

HSE Policy & Strategic

Objectives

Organization Arrangements

181

The team will need to ensure and create a safe and environmentally operations in

the aspect from the fabrication, installation, commissioning, until the start of the

operation in facilities stage.Besides, the specific job specification, industry guidelines,

standards and codes under the Malaysian statutory requirements on HSE standard and

regulations has to be followed. Any deviation or non compliance should be fully justified

and formally approved by relevant parties before commencement of jobs.

9.3 SAFETY AND RISK MANAGEMENT

Personnel from all organizational levels shall provide required support and

resources, while involved in the identification of HSE risk hazards, and the recovery

measures. The requirement for a structured HSE risk management shall be applied for all

the activities throughout the operations, including the activities conducted by contractors

on behalf for the operator or even for the third party member. All identified concerned

risk on the chemicals should be listed in the Material Safety Data Sheet (MSDS) and

operational safety in the Hazards Effect Register (HER) and reduced to a certain level.

The risk management process is presented as Figure 9.2 below.

Figure 9.2 HSE Risk Management Process

Business Process

and Activity

Identify Hazards

associated with

consumables/operation

HSE Risk

Assessment

HSE Plan defining.

Control & Recovery measures

Performance

Monitoring

Dissemination and

Implementation of

Plan

Implement Control

Measure

Implement Recovery

Measure

HSE Audit and

Review

182

9.4 HSE DELINEATION OF RESPONSIBILITY

The leadership and commitment for HSE is generally expected from all of the

employees, including contractors and third party members on behalf of the operators. The

employee shall demonstrate their commitment towards the HSE requirement and the

general guideline as of various level are as below.

i. General Manager (GM)

Provides strong, visible leadership and commitment, and ensure that this

commitment is translated into the necessary resources to develop, operate and

maintain the HSEMS and to attain the HSE Policy and Strategic Objectives.

Delegates the responsibility and assigns the accountability for operations

including agreed HSE objectives, plans and targets to the respective managers.

ii. Operation Managers

Overall responsibility to the GM for the HSE performance of the Asset,

including that of Contractors.

Ensuring that all foreseeable risk associated with the operations has been

adequately identified, assessed and the necessary risk control measures

effectively implemented.

Delegating and assigning the day to day responsibility and accountability for

various platforms, facilities or part of the asset to individual employees,

dependent upon their area of responsibility.

Ensuring that each contractor’s HSE performance is monitored whilst working

on a production facility and monitoring the HSE requirements are complied with.

iii. Project Managers

Delegates the responsibility and assigns the accountability for business activities

including agreed HSE objectives, plans and targets to the respective

Supervisors/Engineers within his respective project.

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The Project Manager reports to the GM and shall have the responsibility and

accountability for the implementation of HSEMS within his respective project.

Preparation of Environmental Impact Assessment (EIA) for new project.

Ensure that the required Critical Risk Management Activities are carried out and

recommendation addressed at the project development stage.

iv. Head of Procurement & Logistics

The Head of Procurement & Logistics is the custodian of PCSB’s Procurement,

Warehouse and Logistics Operations Manual.

Ensuring that the relevant requirement of the HSEMS is adhered to in the

procurement of goods, equipment and services from contractors and suppliers.

Ensuring that all PDSB’s contractual documents contain the appropriate HSE

requirements while maintaining HSE performance database.

v. HSE Managers

Responsible for providing advice, guidance and technical support to all the

managers in meeting their HSEMS responsibilities.

Coordinates internal HSEMS Audits and records all incidents and accidents.

Coordinates HSE monitoring activities including incident investigations, planned

inspection and emergency drills / exercises.

vi. Head of Departments

Responsible for the implementation of HSEMS in respective area of authority

and ensures subordinate staff is trained and competent for assigned duties.

Shall ensure that all foreseeable risk associated with activities within their area of

operations has been adequately identified, assessed and the necessary risk control

measures effectively implemented.

vii. Superintendants / Supervisors

The Superintendants / Supervisors report to the respective Head of Department.

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Implementing and enforcing the HSE Policy arrangements including all the

practices and procedures within his area of responsibility.

Ensuring that employees and contractors personnel under his supervision are

fully competent to carry out tasks allocated to them and holds the necessary

competency certificates.

Ensuring those adequate personal protective equipment (PPE) is provided as

required.

viii. Employees and Contractors

Actively contribute to the creation and sustenance of a culture that support the

HSEMS through its policy, strategic objectives, initiatives and action plan.

Required to take responsible for the safety and health of themselves or of other

persons who may be affected by their acts or omissions at work.

9.5 QUALITY MANAGEMENT

The Project and contractor’s team must work together with parallel objectives

towards quality work and also management. In order to improve the compliance, the

approaches that have been adopted are:

Project and contractor team to foster proactive approach to project management

and Quality Assurance (QA) awareness.

Identify and apply project resources in prioritized manner to continually respond

to areas of greater quality concern.

Besides, the project team shall also have pre-planned operations with the contractor to:

Ensure contractors provide qualified and adequate QA personnel and also to

develop and implement effective Quality Management System (QMS).

Ensure sub-contractors (third party) implement an effective QMS.

Perform QA audits on contractor’s team to evaluate the compliance to work

procedures and to control or improve the work processes.

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9.6 OCCUPATIONAL HEALTH MANAGEMENT

The potential health risks to personnel during project design, fabrication, hookup

and commissioning, during operational phases such as well servicing shall be controlled

and monitored. Procedures shall be established to control such activities such as the Job

Safety Analysis (JSA), Permit to Work (PTW), toolbox meeting before operatiosn,

Material Safety Data Sheet (MSDS) for consumables and Hazards Effect Registers

(HER) where operation involves heavy machineries. The guideline to provide guidance

for personnel on effective medical and health care services in work places has been

issued in the HSEM 4.03-1 in 2001.

The facilities shall be designed in accordance with the standard requirements on

the occupational health applicable to the petroleum industry. The main objective of the

planned safety or protection system is to protect personnel. The secondary objective is to

protect equipment and facilities. A hazard analysis will be performed by on any new

facilities to ensure safe operation of the facilities. The Offshore Safety Passport system is

to ensure that each and all the personnel working offshore are fit for working offshore

before they go to the location. Appropriate PCSB Health Risk Assessment and Health

Surveillance Programs shall be carried out and the outcome of the assessment shall be

followed up to ensure that all the reasonably practicable measures shall be applied to

eliminate or mitigate any potential harm to the personnel.

9.7 ENVIRONMENTAL MANAGEMENT

Since the offshore exploration and production activities involves various

complicated processes, this cannot be undertaken without impacts towards the

environment where it may arises from waste discharge and emission from site activites.

The impacts which are likely to be associated are those contributed by drilling,

installation, development phase and well servicing where emission or discharge into

atmospheric or to the sea, affecting the local environment.

9.7.1 Environmental Waste Management

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Solid waste from drill cutting, mud, domestic waste will be limited by recycling and

reuse to prevent total waste disposal and reduction in chemical consumption.

However drill cutting disposal may result in some smothering of benthic organism,

where continued monitoring of environment of seabed is required to estimate the

overall effects.

The typically hostile marine and atmospheric environments of the offshore will

ensure adequate dilution and dispersion so that “no effects concentrations” will be

rapidly achieved. Therefore, strict control measures including environment

management procedures have been implemented to ensure all legistation

requirement are complied and exercised.

The aqueous discharge principally from produced water, cooling water, domestic

sewage, work-over fluids, and oil spills. In terms of aqueous inputs to the sea from

offshore oil and gas activities, the largest contribution comes from the produced

water. Consequently, aqueous discharges from drilling and production operations are

in general predicted to have only limited and essentially localized environmental

effects.

9.7.2 Environmental Impact Assessment (EIA)

Key environmental issues have been identified by the use of standard checklists

and matrices and preliminary consultation with statutory bodies. Baseline studies and a

literature review of the existing environmental conditions enabled both the identification

and assessment of significant effects of all PCSB projects on the environment. PCSB

have been utilized both qualitative and quantitative techniques for the prediction of

effects. The EIA has been prepared in parallel with detailed technical studies of the

overall project feasibility in order to review options and to eliminate or refine

alternatives. EIA helps to assess potential environmental impacts of the project options

and provide mitigation measures in order to minimize the impacts to environment

according to the requirements specified in Malaysia Petroleum Law, Law on

Environmental Protection and Regulations on Environmental Protection in the Petroleum

Industry.

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9.8 SUSTAINABLE DEVELOPMENT

The Field Development Project main’s aim is to optimize and maximize the

production performance of the Gelama Merah field in a long term run. To ensure

prominent performance for the field as planned, detail measures and strategies have been

put by the reservoir engineers, production technologists, facilities engineers and well

servicing. The details of these are discussed in their respective chapter in this FDP.

9.8.1 Reservoir Management

A detailed and approved Reservoir Management Plan shall be ready in place

before the field is handled over to the operation team. The element of the plan shall

include but not limited to:

Reservoir Monitoring Guidelines

Pressure surveys requirements

Update of reservoir dynamic model by time by reservoir team

Hydrocarbon accounting through monthly production well testing

Identification of blocks/area for production optimization

Pre-planned reservoir development for future (IOR, EOR)

9.8.2 Production Technology

The operations team (well integrity and production analyst/field engineer) shall

maintain active and close communication with the Resource Management (RM) team and

supply various operating limits and updates to ensure smooth and optimal productivity of

the wells. The element of the interest shall include not limited to:

Production of well survelliance (GOR, Water production, Pressure maintenance)

Production optimization (Gas Lift plans, Production Logging Plans, Zone

Change)

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Production enhancement plan (Cement packer, Additional Perforation, Acid

Stimulation) utilizing bubble maps, past production data and neighboring wells

production profile.

Continuous consideration of new technologies to be applied for suitable field

Proposal for sand control method during well servicing stages for new perforated

zones.

Full field performance review

Proper and complete well clean up directions and well kick off procedures.

Troubleshoot production problems with well integrity team and field engineers.

9.8.3 Drilling & Completion Implementation Plan

Gelama Merah is categorized as green field, thus the exploration data obtained

should be fully utilized to extract more subsurface information on the pressure data and

lithologic sequence to reduce the risk faced during drilling period. This is to ensure the

drilling operation does not exceed the time limit and trajectory are close as pre-planned.

The elements of interest includes but limited to the following:

Technical Limit Approach (TLA) in drilling to optimize cost, minimize reservoir

impairment and reducing non-productive time (NPT).

Collaborate with the contractors to improve drilling fluid formulation aiming to

minimize reservoir impairment

Flexible drilling design to cater for future possibilities with cost effectiveness

utilizing new technologies as consideration

Continuous consideration of completion profile and proper data record for future

enhancement planning.

9.8.4 Facilities Engineering & Operations

Facilities design should aim to provide storage and energy capacity of surface

facilities required to cater for possible higher than planned production. Surface facilities

should be properly designed so that operation pressure would be kept at the optimal level.

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However, over-design of facilities should be avoided as this would reduce the cost

effectiveness. Elements of interest include and not limited to:

Routine maintenance plan on the surface structure

Production system bottle neck analysis (nodal analysis) to be carried out from

time to time

Well testing procedures and schedule in place.

Attentive production surveillance with collaboration with production technologist

Well Integrity to provide full information on available tool specification for RM

team for smooth optimization plan.

9.8.5 Abandonment Options

Abandonment of the platform (similar in Phase 7 Facilities) mainly comprises of

cementing the wellbore or plugging, removing tress with the deck and parts at least 50m

below the mud line. Platform structure shall be designed such that, it can be disintegrated

safely easily based on the plan in the future. The pipeline and flowline shall be cleaned

and capped. All the HSE related issues and regulation from the local authority and

PETRONAS shall be complied. A detailed and comprehensive method must be planned

and prepared towards the end of the production life for Gelama Merah field.

9.9 QUALITY ASSURANCE

The project shall meet the terms in order to comply and meet the standards for the

safety of the people and structure, environment, quality of the operations, reliability and

operational integrity. The project shall adopt a quality management system and strive to

complete on time, within the allowable budget, and also to comply in accordance to the

specified requirements.The project team, contractor team and asset team shall be in close

communication to optimize process flow and meeting of various requirements especially

in terms of preparation and HSE. The team shall at all times internalize the 5

PETRONAS Quality Principles in every stage of the project.

PAB4034 FIELD DEVELOPMENT PROJECT (FDP) GELAMA …

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