pab4034 field development project (fdp) gelama …
TRANSCRIPT
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.
iv
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
5.3.7 Recommendations
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
8.6.5 5th Screening Results
8.6.6 6th 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 4.27 : Optimum Well Location for Reservoir 9.1 86
Figure 4.28 : Optimum Well Location for Reservoir 9.2 87
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
Table 4.13: GM-1 Single-Stage Separator Flash Analysis Case 2 71
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 4.16: GM-1 Single-Stage Separator Flash Analysis Case 3 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
2 U4.0Top Erosion No U4.0 Top Yes U4.0
3 U5.0Top Erosion No U5.0 Top Yes U5.0
4 U6.0Top Erosion No U6.0 Top Yes U6.0
5 U7.0Top Erosion No U7.0 Top Yes U7.0
6 U8.0Top Erosion No U8.0 Top Yes U8.0
7 U9.0Top Conformable No U9.0 Top Yes U9.0
8 U9.1Top Conformable No U9.1 Top Yes U9.1
9 U9.2Top Conformable No U9.2 Top Yes U9.2
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
Gamma Ray reading gives low reading; indicate low radioactive formation,
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
Gamma Ray reading gives low reading; indicate low radioactive formation,
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
Gamma Ray reading gives low reading; indicate low radioactive formation,
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
3.5.2 Recommendations
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
As shown in Figure 4.5
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
As shown in Figure 4.6
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
As shown in Figure 4.7
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
As shown in Figure 4.8
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)
Component Mole % Molecular
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
Case 2 – at 265 psig and 84°F
Case 3 – at 60 psig and 91°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
Component Mole % Molecular
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.
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 4.14 : Composition of the Liberated Gases Collected from GM-1 Single-Stage Separator Flash Test Case 2
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
Specific Gravity 0.640 0.748
Calculated Gross
Heating Value
(BTU/scf of gas)
940.76 1118.55
72
Table 4.15 : Composition of Residual Oil from GM-1 Single-Stage Separator Flash Test Case 2
Component Mole % Molecular
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.
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.
73
Table 4.17 : Composition of the Liberated Gases Collected from GM-1 Single-Stage Separator Flash Test Case 3
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
Specific Gravity 0.667 0.729
Calculated Gross
Heating Value
(BTU/scf of gas)
977.13 1094.73
Table 4.18 : Composition of Residual Oil from GM-1 Single-Stage Separator Flash Test Case 3
Component Mole % Molecular
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
Figure 4.27 : Optimum Well Location for Reservoir 9.1
87
Figure 4.28 : Optimum Well Location for Reservoir 9.2
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
Type of formation Sandstone or carbonate, with few fractures and high
permeability streaks
Average Permeability Not critical
Depth, ft Not critical
Temperature, F 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
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
Temperature, F Not critical
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-02A Deviated Unit 9.2 Single oil producer
GMJT-03A 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
5.3.7 Recommendations
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.
121
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
9-5/8” Class “G” 901 sxs 210 sxs 1111 sxs
Sea Water 244.4 bbls 23.2 bbls 267.6 bbls
Mixing Fluid 268.2 bbls 26.9 bbls 295.1 bbls
Retarder 54.1 gals 4.2 gals 58.3 gals
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
9-5/8” Class “G” 683 sxs 210 sxs 893 sxs
Sea Water 185.1 bbls 23.2 bbls 208.3 bbls
Mixing Fluid 203.2 bbls 26.9 bbls 230.1 bbls
132
GMJT-
02A
Retarder 41.0 gals 4.2 gals 45.2 gals
Fluid-Loss 34.1 gals 10.5 gals 44.6 gals
Dispersants 682.6 gals 73.4 gals 756.0 gals
7” Class “G” 452 sxs 452 sxs
Sea Water 50 bbls 50 bbls
Mixing Fluid 58 bbls 58 bbls
Retarder 40.6 gals 40.6 gals
Fluid Loss 22.6 gals 22.6 gals
Dispersants 135.5 gals 135.5 gals
GMJT-
03A
9-5/8” Class “G” 658 sxs 210 sxs 868 sxs
Sea Water 178.3 bbls 23.2 bbls 201.5 bbls
Mixing Fluid 195.7 bbls 26.9 bbls 222.6 bbls
Retarder 39.5 gals 4.2 gals 43.7 gals
Fluid-Loss 32.9 gals 10.5 gals 43.4 gals
Dispersants 657.6 gals 73.4 gals 731.0 gals
7” Class “G” 414 sxs 414 sxs
Sea Water 46 bbls 46 bbls
Mixing Fluid 53 bbls 53 bbls
Retarder 37.3 gals 37.3 gals
Fluid Loss 20.7 gals 20.7 gals
Dispersants 124.3 gals 124.3 gals
GMJT-
04B
9-5/8” Class “G” 804 sxs 210 sxs 1014 sxs
Sea Water 218.1 bbls 23.2 bbls 241.3 bbls
Mixing Fluid 239.4 bbls 26.9 bbls 266.3 bbls
Retarder 48.3 gals 4.2 gals 52.5 gals
Fluid-Loss 40.2 gals 10.5 gals 50.7 gals
Dispersants 804.3 gals 73.4 gals 877.7 gals
7” Class “G” 643 sxs 643 sxs
Sea Water 71 bbls 71 bbls
Mixing Fluid 83 bbls 83 bbls
Retarder 57.9 gals 57.9 gals
Fluid Loss 32.2 gals 32.2 gals
Dispersants 193.0 gals 193.0 gals
GMJT-
05C
9-5/8” Class “G” 576 sxs 210 sxs 786 sxs
Sea Water 156.3 bbls 23.2 bbls 179.5 bbls
Mixing Fluid 171.6 bbls 26.9 bbls 198.5 bbls
Retarder 34.6 gals 4.2 gals 38.8 gals
Fluid-Loss 28.8 gals 10.5 gals 39.3 gals
Dispersants 576.5 gals 73.4 gals 649.9 gals
7” Class “G” 396 sxs 396 sxs
Sea Water 44 bbls 44 bbls
Mixing Fluid 51 bbls 51 bbls
Retarder 35.6 gals 35.6 gals
Fluid Loss 19.8 gals 19.8 gals
Dispersants 118.7 gals 118.7 gals
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
147
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.
160
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
Installation 5.969 18.38452
Design & Project Management 0.856 2.63648
Insurance & Certification 0.417 1.28436
Contingency 1.083 3.33564
Offshore Pipeline
Materials 0.964 2.96912
Installation 11.622 35.79576
Design & Project Management 1.476 4.54608
Insurance & Certification 0.562 1.73096
Contingency 2.194 6.75752
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:
Case Scenarios RF (%) Oil produced
(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:
Case Scenarios RF (%) Oil produced
(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
5 deviated wells + Water injection(4716bbl/d).
prod rate 4412stb/d, 14 years.
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:
Case Scenario RF (%) Oil produced
(MMbbl)
B2b1a
5 deviated wells + Water injection(3780bbl/d).
prod rate 4326stb/d, 14 years.
Inject on 1st day of production. Oil control mode.
26.4 10.75
B2b1b
5 deviated wells + Water injection(3780bbl/d).
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:
Case Scenario RF (%) Oil produced
(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
Parameter Unit Subsurface Scenarios
Case B1 Case B2
IRR % 14 18
NPV @ 10% USD MM 8.24 16.82
Breakeven Years 6.15 5.43
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:
Parameter Unit Subsurface Scenarios
Case B2a Case B2b
IRR % 14 19.20
NPV @ 10% USD MM 8.24 18.56
Breakeven Years 6.15 4.43
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
Breakeven Years 4.43 4.46
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):
Parameter Unit Subsurface Scenarios
Case B2b1a Case B2b1b
IRR % 19.20 17.6
NPV @ 10% USD MM 18.56 14.34
Breakeven Years 4.43 6.03
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
Parameter Unit Subsurface Scenarios
Case B2b1a1 Case B2b1a2
IRR % 18 36
NPV @ 10% USD MM 16.82 62.9
Breakeven Years 5.43 3.52
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.
183
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.
184
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.
185
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
186
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.
187
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)
188
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.
189
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.