Acknowledgements
First of all we would like to express our gratitude to all those who has contributed in any way for the success of this Field Development Project (FDP). We take immense pleasure in thanking Dr. Ismail B. Mohd Saaid and Dr. Khalik B. Mohd Sabil for being very helpful in giving us assistance,
advices, and supervision. We would also like to express our deep sense of gratitude to the coordinators of this project; Pn. Mazlin Idress and En. Iskandar B Dzulkarnain. The supervision and support that they gave help
the progression and smoothness of this FDP.
We were deeply indebted to A.P. Dr. Swapan Kumar Bhattacharya, Dr. Ali Fikret Mangi, Dr. Zuhar Zahir B. Tuan Harith, Dr. Askury B. Abd Kadir, Mr. Mohammad Amin Shoushtari, Ms. Raja Rajeswary Suppiah, M. Faizal
Sedaralit (PCSB), Pn. Mazrah Bt. Ahmad (PCSB), En. Ramlan Latif (PCSB) and En. Rozmee Ismail (PCSB) for their guidance and useful
suggestions which helped us in completing this project in time.
Words are inadequate in offering our thanks to all our lecturers both from Heriot-Watt University and Universiti Teknologi Petronas (UTP) who had
taught us in our previous modules and put us in prepared theoretically for this project.
Finally, yet importantly, we would like to express our heartfelt thanks to our beloved family for their blessings, our friends/classmates for their help and
Table of Contents
1 Executive Summary ... 1
2 Introduction ... 2
2.1 Background of Study ... 2
2.2 Problem Statement ... 3
2.3 Objective and Scope of Study ... 3
2.3.1 Objective ... 3
2.3.2 Scope of Study ... 3
2.4 The Team ... 4
2.4.1 Team Members ... 4
2.4.2 Organisation and Structure ... 4
2.4.3 Project Planning ... 5
3 Geology ... 8
3.1 Introduction ... 8
3.2 History and Geological Description of Sabah Basin ... 8
3.2.1 Sabah Basin ... 8
3.2.2 Southern Inboard Belt ... 10
3.3 Reservoir Geology ... 13
3.3.1 Depositional Environment ... 13
3.3.2 Lithology Descriptions ... 15
3.3.3 Stratigraphic Correlation ... 17
3.3.4 Petroleum System ... 19
3.4 Calculations of Gross Rock Volume ... 20
3.4.1 Planimeter Method ... 21 3.5 Conclusion ... 24 3.6 References ... 24 4 Formation Evaluation ... 25 4.1 Introduction ... 25 4.1.1 Objective ... 25 4.1.2 Data ... 26 4.2 Petrophysical Analysis ... 27 4.2.1 Gelama Merah-1 ... 27 4.2.2 Gelama Merah-1 ST1 ... 28
4.3 Fluid Analysis ... 30 4.3.1 Fluid Contacts ... 30 4.3.2 Fluid Types ... 33 4.4 Properties Calculation ... 33 4.4.1 Volume of Shale ... 33 4.4.2 Net-to-Gross ... 34 4.4.3 Porosity ... 35 4.4.4 Water Saturation ... 37 4.5 Core Analysis ... 38 4.5.1 Poro-Perm Relationship ... 38 4.5.2 Capillary Pressure ... 40 4.5.3 Buckley-Leverett J-Function ... 40 4.6 References ... 41 5 Volumetric Estimation ... 42 5.1 Introduction ... 42 5.2 Deterministic Methods ... 42 5.2.1 Planimeter ... 43 5.2.2 Petrel Parameters ... 44 5.2.3 STOIIP Comparison ... 44 5.3 Probabilistic Method ... 45
5.3.1 Monte Carlo Method ... 45
5.3.2 Probabilistic STOIIP and GIIP ... 46
5.4 Sensitivity Analysis ... 47
5.5 Uncertainties ... 48
5.6 Conclusion ... 49
6 Reservoir Engineering ... 50
6.1 Introduction ... 50
6.2 Reservoir Data Analysis ... 51
6.2.1 Reservoir Temperature ... 51
6.2.2 Reservoir Pressure ... 51
6.3 Rock Physics Properties ... 52
6.3.1 Porosity-Permeability Relationship ... 52
6.3.2 Capillary Pressure ... 54
6.3.3 Relative Permeability ... 58
6.3.4 Rock Compressibility ... 63
6.5 Well Test Analysis ... 67
6.6 Reservoir Simulation Study ... 68
6.6.1 Preliminary Studies of Reservoir Drive Mechanisms ... 69
6.6.2 3D Geological Static Model Export ... 70
6.6.3 Simulator Data Input ... 71
6.6.4 Model Initialization ... 72
6.6.5 Operating Constraints ... 72
6.6.6 Simulation Studies ... 73
6.6.7 Reservoir Management Plan ... 83
6.6.8 Reservoir Surveillance Plan ... 84
6.6.9 Considerations for Enhanced oil recovery ... 85
6.6.10 Uncertainty Analysis ... 86
6.7 References ... 87
7 Drilling Engineering ... 88
7.1 Introduction and Objectives ... 88
7.2 Drilling History ... 89
7.3 Drilling Targets ... 92
7.4 Platform Location ... 94
7.5 Well Trajectories ... 97
7.6 Rig Selection ... 101
7.7 Available Well Configuration ... 103
7.8 Drillbit Selection ... 104
7.9 Drilling Fluid ... 107
7.9.1 Pressure Profiles Considerations ... 109
7.10 Casing Design ... 109
7.10.1 Casing Cementation Programme ... 113
7.11 Logging Programme ... 115
7.12 Potential Drilling Hazards and Mitigations ... 116
7.12.1 Shallow Gas ... 116
7.12.2 Unconsolidated Sand problems/Stuck pipes/ wellbore stability ... 117
7.12.3 Lost Circulation ... 117
7.12.4 Shale Instability ... 118
7.12.5 Presence of CO2, H2S or Hydrocarbon Gases ... 118
7.12.6 Presence of Faults ... 119
7.12.7 Abnormal Pressures ... 119
7.13 Well Control ... 120
7.13.1 Blow-Out Preventer (BOP) Configuration ... 120
7.14 BHA Performance Considerations ... 121
7.15 Drilling Time Estimates ... 121
7.16 Costs Estimates ... 124
7.17 Drilling Optimizations and Sustainability ... 125
7.17.1 Installation of Conductors ... 125
7.17.2 Casing While Drilling ... 126
7.17.3 Monitoring Drilling Performances ... 126
7.18 References ... 126
8 Production Technology ... 128
8.1 Introduction ... 128
8.1.1 Objectives ... 128
8.2 Well Performance Prediction ... 129
8.2.1 Base Case Model ... 129
8.2.2 PVT Correlation Matching ... 129
8.2.3 Tubing Size Optimisation ... 130
8.2.4 Well Performance Sensitivity Analysis ... 133
8.3 Artificial Lift Requirement ... 134
8.3.1 Advantages and Disadvantages of Major Artificial Lift Systems ... 134
8.3.2 Artificial Lift Selection Criteria ... 134
8.3.3 Gas Lift Sensitivity Analysis ... 135
8.4 Sand Control Requirement ... 137
8.4.1 Sand Failure Prediction ... 137
8.4.2 Sonic Transit Time and Depth Relationship ... 138
8.4.3 Geological Description of Formations ... 138
8.4.4 Risk Regional Analysis ... 138
8.4.5 Advantages and Disadvantages of Sand Control Method ... 138
8.4.6 Sand Control Criteria ... 139
8.5 Well Completion Design ... 140
8.5.1 Wellhead / X-mas Tree ... 142
8.5.2 Material Selection ... 143
8.6 Production Chemistry ... 144
8.6.1 Wax Deposition ... 145
8.6.2 Corrosion ... 145
8.6.4 Emulsion formation ... 145
8.7 Well Unloading Philosophy ... 146
8.8 Well Surveillance Philosophy ... 147
8.8.1 Permanent Downhole Gauge System (PDGS) ... 147
8.8.2 Inflow Control Device ... 147
8.9 References ... 148
9 Facilities Engineering ... 150
9.1 Introduction ... 150
9.2 Design Basis and Philosophy ... 150
9.2.1 Design Basis ... 150
9.2.2 General design information ... 151
9.2.3 Design Philosophy ... 153
9.3 Development Concept and Screening Process ... 153
9.4 Gelama Merah Facility Selection ... 155
9.4.1 Description of Selected Option ... 155
9.4.2 Process Flow Descriptions ... 156
9.4.3 Description of Substructure and Topside ... 156
9.4.4 Description of Surface Facilities and Equipment ... 157
9.5 Pipelines and Host Tie-ins to Existing Facilities ... 160
9.5.1 Pipelines ... 160
9.5.2 Hoist Tie-ins ... 162
9.6 Facilities CAPEX Estimation and Project Schedule ... 162
9.6.1 Facilities CAPEX Estimation ... 162
9.6.2 Project Schedule ... 162
9.7 Operation and Maintenance Philosophy ... 163
9.7.1 Operation Philosophy ... 163 9.8 Abandonment/Decommissioning ... 164 9.9 References ... 165 10 Economics ... 166 10.1 Introduction ... 166 10.2 Objectives ... 166 10.3 Field Summary ... 167 10.4 Fiscal Term ... 167
10.4.1 Production Sharing Contract (PSC) ... 167
10.6.1 Economic Analysis Results ... 172
10.7 Production Profiles ... 173
10.7.1 Option A: 9000 bbl/d for Two (2) Years ... 174
10.7.2 Option B: 7000 bbl/d for Two (2) Years ... 175
10.7.3 Option C: 6000 bbl/d ... 176
10.7.4 Economic Analysis Results ... 177
10.7.5 Net Cash Flow Profile ... 179
10.7.6 Revenue Split ... 180
10.8 Sensitivity Analysis ... 181
10.9 Conclusion ... 183
10.10 References ... 183
11 HSE and Sustainability Development ... 185
11.1 Introduction ... 185
11.2 HSE Management Philosophy ... 185
11.2.1 HSE Management Policy ... 185
11.2.2 Risk Acceptance Criteria ... 185
11.3 HSE Management System ... 186
11.3.1 Gelama Merah HSE Objectives ... 187
11.3.2 HSE Hold Points ... 188
11.3.3 HSE Responsibilities ... 188
11.4 Occupational Health and Safety Issues ... 188
11.5 Safety System ... 189
11.5.1 Safety Shutdown System ... 189
11.5.2 Flare and Emergency Relief System ... 189
11.5.3 Emergency Evacuation Plan ... 190
11.6 Environmental Obligations ... 190
11.6.1 Environmental Impact Asssessment (EIA) ... 190
11.7 Environmental Concerns ... 190 11.7.1 Upstream Activities ... 191 11.7.2 Downstream Activities ... 192 11.8 Quality Assurance ... 194 11.9 Abandonment/Decommissioning ... 194 11.10 Sustainable Development ... 195
11.10.1 Sustaining Development in Gelama Merah Field ... 196
List of Figures
Figure 2.1: Location of Gelama Merah field ... 2
Figure 2.2: Organisation and structure of the team ... 5
Figure 3.1: Structural elements of Sabah Basin, showing basin boundaries and tectonostratigraphic provinces ... 9
Figure 3.2: Regional cross-section of the Sabah Basin showing the Southern Inboard Belt and East Baram Delta ... 9
Figure 3.3: Map of Southern Inboard Belt in Sabah Basin ... 11
Figure 3.4: Palaeogeographic reconstruction of the Sabah Basin ... 12
Figure 3.5: West-East cross-section of Gelama Merah field ... 13
Figure 3.6: Tectonic setting of Sabah Basin ... 15
Figure 3.7: Lithology correlation between Gelama Merah-1 and Gelama Merah-1 ST1 ... 19
Figure 3.8: A Planimeter tool ... 21
Figure 3.9: Structural map for Unc/U3.2 layer ... 22
Figure 3.10: Plot of contour areas with respect to depth ... 23
Figure 4.1: GOC and OWC determined from the Neutron-Density and Resistivity logs for Gelama Merah-1 ... 30
Figure 4.2: GOC and OWC determined from the Neutron-Density and Resistivity logs for Gelama Merah-1 ST1 ... 31
Figure 4.3: Fluid contacts obtained from MDT data ... 32
Figure 4.4: Finding Vsh Cut-off from GR-Density crossplot ... 34
Figure 4.5: Definitions of Gross Sand, Net Sand and Net Pay (Petroleum Geoscience, Heriot-Watt University) ... 35
Figure 4.6: Poro-Perm relationship to obtain Porosity Cut-off when k = 0.1 mD ... 36
Figure 4.7: Obtaining water saturation cut-off from core data ... 38
Figure 4.8: Poro-Perm relationship showing three facies in Gelama Merah reservoir ... 39
Figure 4.9: Capillary pressure as a function of water saturation for the 10 core samples ... 40
Figure 4.10: J-function of Gelama Merah field ... 41
Figure 5.2: Probability and Cumulative Distribution Functions for GIIP ... 47
Figure 5.3: Sensitivity Analysis for STOIIP ... 48
Figure 6.1: Gelama Merah reservoir temperature profile ... 51
Figure 6.2: Gelama Merah reservoir pressure profile ... 52
Figure 6.3: Poro-Perm relationship ... 53
Figure 6.4: Capillary Pressure (Pc) vs Water Saturation (Sw) for every sample ... 54
Figure 6.5: Capillary Pressure (Pc) (Oil-Gas) vs Water Saturation (Sw) ... 56
Figure 6.6: Capillary Pressure (Pc) (Oil-Water) vs Water Saturation (Sw) ... 56
Figure 6.7: J-Function vs Pseudo Wetting Phase Saturation ... 58
Figure 6.8: End Point correlation vs Log Permeability ... 59
Figure 6.9: End Point correlation vs Porosity Fraction ... 60
Figure 6.10: Oil-Water Relative Permeability curve for Facies 3 (Good Rock) ... 61
Figure 6.11: Oil-Water Relative Permeability curve for Facies 2 (Moderate Rock) . 61 Figure 6.12: Gas-Oil Relative Permeability curve for Facies 3 (Good rock) ... 62
Figure 6.13: Gas-Oil Relative Permeability curve for Facies 2 (Moderate rock) ... 62
Figure 6.14: Gas-Oil Relative Permeability curve for Facies 1 (Poor rock) ... 63
Figure 6.15: Phase diagram of Gelama Merah reservoir fluid ... 64
Figure 6.16: PVTi plot for Oil Relative Volume Factor ... 65
Figure 6.17: PVTi plot for Gas Oil Ratio ... 65
Figure 6.18: PVTi plot for Gas Formation Volume Factor ... 66
Figure 6.19: Drive mechanism of Gelama Merah ... 70
Figure 6.20: 3D Geological Static model ... 71
Figure 6.21: FOPR (bbl/day) & RF vs Time (yr) for Horizontal and Vertical Wells 75 Figure 6.22: FOPT (bbl) vs Time (yr) for Horizontal and Vertical Wells ... 76
Figure 6.23: FOPR (bbl/day) & RF vs Time (yr) for 7, 8 and 9 Horizontal Wells .... 77
Figure 6.24: FOPR (bbl/day) & RF vs Time (yr) for GI, WI and ND ... 79
Figure 6.25: FOPR (bbl/day) & RF vs Time (yr) for 7000 and 9000 bbl/day ... 80
Figure 6.26: FPR (psia) vs Time (yr) for No Limit and Limit of 30MMSCF/day .... 81
Figure 6.27: FOPR (bbl/day) & RF vs Time (yr) for 9000 bbl/day ... 82
Figure 7.1: Diagram showing all the target locations with the exploration wells in place ... 93
Figure 7.2: Possible location to place the rig (highlighted orange) ... 95
Figure 7.4: Highlighted area showing the window zone which could be used to drill
the targets ... 98
Figure 7.5: Top view of the trajectories ... 98
Figure 7.6: Side view of the trajectories ... 99
Figure 7.7: Top view showing trajectories with the exploration wells ... 99
Figure 7.8 Side view showing the exploration wells and the producing wells ... 100
Figure 7.9: Available well configuration ... 104
Figure 8.1: Well completion diagram from GMP-1 ... 141
Figure 9.1: Schematic diagram of Gelama Merah conceptual facility design ... 155
Figure 9.2: Conceptual Process Flow Diagram design ... 156
Figure 9.3: Sensitivity analysis for pipeline diameter ... 160
Figure 9.4: Sensitivity analysis for pump power and efficiency ... 161
Figure 9.5: Project Schedule of Gelama Merah field ... 163
Figure 10.1: Gelama Merah Project Schedule ... 167
Figure 10.2: PSC Concept ... 169
Figure 10.3: Historical Brent Oil Price from 1947 - October 2011 ... 170
Figure 10.4: Production Profile of Option A (9000 bbl/d) ... 175
Figure 10.5: Production Profile for Option B (7000 bbl/d) ... 176
Figure 10.6: Production Profile for Option C (6000 bbl/d) ... 177
Figure 10.7: Net Cash Flow Profile for Option A (RT US$ 2012) ... 179
Figure 10.8: IRR Estimate ... 180
Figure 10.9: Option A NCF in Money of the Day and Real Terms 2012 ... 180
Figure 10.10: Revenue Split at NPV [0.10] (RT US$ 2012) ... 181
Figure 10.11: Sensitivity Analysis for Option A ... 182
List of Tables
Table 2.1: Important dates during the course of the project ... 6
Table 4.1: Logging program for Gelama Merah-1 and Gelama Merah-1 ST1 ... 26
Table 4.2: Summary of cores with shows ... 27
Table 4.3: Comparison of fluid contact depths between GM-1 and GM-1 ST1 wells ... 31
Table 4.4: Comparison of fluid contacts between logs and MDT tool ... 32
Table 4.5: Fluid type identification from the MDT plot ... 33
Table 4.6: Facies group according to their range of permeabilities ... 39
Table 5.1: Boi and Bgi obtained from PVT data ... 43
Table 5.2: Gas Initially In-Place calculated for each sand unit ... 43
Table 5.3: Stock Tank Oil Initially In-Place calculated for each sand unit ... 44
Table 5.4: Comparison of STOIIP between two deterministic methods ... 44
Table 5.5: Probabilistic STOIIP and GIIP values ... 47
Table 5.6: Reservoir parameters and their controlling factors on uncertainties ... 48
Table 6.1: Group of facies according to their permeabilities ... 53
Table 6.2: Laboratory-Reservoir fluid properties for capillary conversion ... 55
Table 6.3: End Point correlation ... 60
Table 6.4: Fluid properties in Gelama Merah reservoir ... 66
Table 6.5: Oil PVT properties ... 66
Table 6.6: Gas PVT properties ... 67
Table 6.7: Fluid densities at surface conditions ... 67
Table 6.8: Summary of rock facies ... 72
Table 6.9: Base case results ... 74
Table 6.10: Simulation results on production and recovery of different depletion cases ... 79
Table 6.11: Production Profile for Gelama Merah ... 82
Table 7.1: Summary of previous well data ... 89
Table 7.2: Co-ordinates of the targets to be drilled ... 92
Table 7.3: Summary of consequence of placing rig in each section ... 96
Table 7.4: Summary of the producer wells to be drilled ... 100
Table 7.6: Rig Construction Details ... 102
Table 7.7: Summary of the drillbits used when drilling the GM-1 ... 105
Table 7.8: Summary of the drillbits used when drilling the GM-1 ST1 ... 106
Table 7.9: Mud types used during drilling the exploration wells ... 107
Table 7.10: Mud design to be used during drilling the Gelama Merah Producer wells ... 108
Table 7.11: Summary of casing shoe depths ... 109
Table 7.12: Kick tolerance used in designing the casing shoes ... 110
Table 7.13: Design factors used in the casing designs ... 110
Table 7.14: Casing material selection ... 112
Table 7.15: Cementing summary for all the producing wells 1 to 4 ... 114
Table 7.16: Cementing summary for all the producing wells 5 to 8 ... 114
Table 7.17: Logging summary for the field development project ... 115
Table 7.18: BOP configuration from the exploration wells ... 120
Table 7.19: Template for drilling a producer well ... 122
Table 7.20: Showing the duration of drilling for each of the producer well ... 122
Table 7.21: Summarised table for the combined drilling operation estimate ... 123
Table 7.22: Tentative drilling operation dates ... 124
Table 7.23: Total drilling cost estimate using Que$tor software ... 124
Table 7.24: Estimated cost for each well ... 125
Table 8.1: The black oil correlation used to match the PVT data (Velarde, 1996) . 129 Table 8.2: Grouping of the wells according to their plateau production rate and identifying the target oil rate for simulation purposes ... 131
Table 8.3: The optimum tubing size for Gelama Merah Producers ... 131
Table 8.4: The result after running sensitivity analysis on water cut and layer pressure ... 133
Table 8.5: The production rate without GLI and with GLI at 50% water cut for GMP-1 ... GMP-136
Table 8.6: Summary of the optimum gas injection rate and the water cut when gas lift injection is introduced ... 136
Table 8.7: Summary of the well completion design for the Gelama Merah Producers ... 143
Table 9.3: CAPEX, OPEX and Abandonment Costs for facilities options ... 154
Table 10.1: Terms and Details of PSC for Gelama Merah field ... 168
Table 10.2: Range of Brent Oil Price (2006-2016) ... 170
Table 10.3: Economic Results for Different Development Options ... 172
Table 10.4: Production Profile of Option A (9000 bbl/d) ... 174
Table 10.5: Production Profile for Option B (7000 bbl/d) ... 175
Table 10.6: Production Profile for Option C (6000 bbl/d) ... 176
Table 10.7: Economic Results for Different Plateau Rates ... 178
1 Executive Summary
Gelama Merah field is located in the offshore Sabah Basin in Block SB-18-12 which is 130 km southwest of Kota Kinabalu, 43 km northwest of Labuan and approximately 10.5 km east of Samarang Complex. Sabah Basin is a shallow marine environment with water depth of 42.8 m. Two exploration wells were drilled in this field; Gelama Merah-1, a vertical exploration well and Gelama Merah-1 ST-1, a sidetracked well. Nine sand units interbedded with thin shale layers were discovered. Presence of hydrocarbon was successfully encountered at the stage IVC middle unconformity sand and in the updip position of unit 9. Also resulting from drilling the exploration wells information was gathered to proceed with the Field Development Plan. Objective of this project is to carry out a technical and economic analysis of the Gelama Merah field, which leads to the production of a development plan of the field using the latest technology, economics, environmental and political conditions. This project is divided into several phases namely; Geology & Geophysics, Formation Evaluation, Reservoir Engineering, Drilling Engineering, Production Technology, Surface facilities and Economics. From the Geology & Geophysics, the main lithology found is sandstone interbedded with claystone. For the Formation Evaluation phase, the gas oil contact and the oil water contact from the petrophysical logs is found to be 1467 m-TVDSS and 1509.3 m-TVDSS respectively. The volumetric estimation is determined using deterministic and probabilistic method. The Stock Tank Oil Initially In Place is found to be ranging from 73 MMstb to 105 MMstb with 88 MMstb to be the most likely value. Same for Gas Initially In Place, ranging from 78 BScf to 112 Bscf with 94 Bscf to be the most likely value. From Reservoir Engineering, the best option to develop Gelama Merah field is by drilling 8 horizontal production wells, producing for 15 years. For the economics, the Maximum Capital Outlay is USD 82.0 Million with a Net Present Value of USD 15.5 Million at 10% discount rate and Internal Rate of Return at 19%, the breakeven is estimated to be 2.9 years.
2 Introduction
2.1 Background of Study
Gelama Merah field is located in South China Sea, Sabah Basin with average water depth of 42.8 m and is in Block SB-18-12 offshore Sabah in Malaysia with the latitude of 5° 33′ 49.98′′ N and longitude of 114° 59′ 6.34′′ E (Figure 2.1). It is located 130 km southwest of Kota Kinabalu and 43 km northwest of Labuan and approximately 10.5 km east of the Samarang Complex.
The only major fault occurrence in the region is the Morris Fault which is 1.5 km from the Gelama Merah field. Reservoirs are characterized by interbedded sand, shale coarsening upward sequence. The sedimentological analysis confirms a shallow marine, storm and wave influence settings.
Figure 2.1: Location of Gelama Merah field
Two wells were drilled in the Gelama Merah Field. The first well namely Gelama Merah-1 (GM-1) was drilled vertically from 70.1 m to 1636 m from the Kelly bushing TVDDF. The presence of a hydrocarbon reservoir was successfully encountered at the Stage IVC middle unconformity sand. The second well is Gelama
Merah-1 ST1 (GM-1 ST-1) which was sidetracked to find oil in the up-dip position of Unit 9. The estimated speculative recovery of oil is 5mmbls.
A field development plan is required to be carried out to produce the oil and gas from this field. This study will help in providing the details to optimally develop the Gelama Merah field.
2.2 Problem Statement
We have been given a field, Gelama Merah and the Management would like to know whether profitable development of this field can be achieved. If so, what are the most likely reserves?
If the development plan is possible, how should it be adopted? What are the risks and uncertainties associated and how would this lack of information affect the decision- making? What further information would be needed to reduce the risk?
2.3 Objective and Scope of Study 2.3.1 Objective
The objective of this project is, therefore, to carry out a technical and economic analysis of the Gelama Merah field, which leads to the production of a development plan of the field using the latest technology, economics, environmental and political conditions.
2.3.2 Scope of Study
In the Geology (Chapter 3) section, we are looking at the top structure of the reservoir, understanding the lithology based on the core data. With this information, we will come up with a reservoir description based on the field given. Log analysis will be carried out in Chapter 4 during the Petrophysical evaluation in order to obtain reservoir parameters such as porosity, water saturation, permeability and so on, thus to be used in reserves estimation and volumetric calculations of hydrocarbons.
In the Reservoir Engineering section, the scope of study will be Well Test Analysis, PVT data and recovery method, while Drilling Engineering involves the preparation of drilling schedule, directional planning, casing design and mud programme. Production Technology section focuses on production plan as well as reservoir management and monitoring. It also include the design of surface facilities.
Economic evaluation handles the cost estimates and cash flows of the project. It will also look into IRR and sensitivity analysis. Risk and Uncertainties section incorporates how insufficient information and uncertainties may lead to risks and how we will address them. We will also look at the impact of this project’s activities on the environment, such as decommissioning, and also the sustainability of the development in the Health, Safety and Environment section.
2.4 The Team
2.4.1 Team Members
The Gelama Merah field development project is participated by: 1. Mohammad Adi Aiman B. Hj. Sarbini (Team Leader) 2. Mohamed Wuroh Timbo
3. Hasnain Ali Asfak Hussain
4. Hj. Muhammad Zulfadhli Putra B. Hj. Ya’akub 5. Siti Mariam Annuar
6. Djamalov Shukhrat Rustamovich 7. Lydia Bt. Mohd Yusof
2.4.2 Organisation and Structure
Figure 2.2: Organisation and structure of the team
2.4.3 Project Planning
This Field Development Project spans over four months, commencing from 1 November 2011 to 29 February 2012. The project is divided into three phases. Phase 1 is the Geology and Geoscience period where both geologist and petrophysicist will be involved extensively. The next stage, Phase 2, is more on the reservoir engineering and simulation. The last Phase 3 is the development stage, where drilling engineer, production technologist and facility engineer as well as the economist will be involved. See Figure 2.3 for the full project planning.
There are several milestones during the duration of the project, which are summarised in Table 2.1 below.
Field Development Project Team Geology Mohamed Timbo Hasnain Ali Siti Mariam Formation Evaluation Adi Aiman Zulfadhli Putra Lydia Reservoir Engineering Hasnain Ali Adi Aiman Mohamed Timbo Drilling Engineering Zulfadhli Putra Hasnain Ali Shukhrat Production Technology Siti Mariam Shukhrat Lydia
Facilities & HSSE Shukhrat Mohamed Timbo Adi Aiman Economics Lydia Adi Aiman Siti Mariam
Table 2.1: Important dates during the course of the project
Milestones Dates
FDP Kick-off and Data Handover 1 November 2011
G&G Phase 1 November 2011
FDP Seminar 2 November 2011
Interim Report Submission 16 November 2011
Reservoir Engineering Phase 19 December 2011
Interim Oral Presentation 23 December 2011
Development Phase 9 January 2012
Final Draft Report Submission 13 February 2012
Final Oral Presentation 20 February 2012
3 Geology
3.1 Introduction
The Geology section of this report includes the description and history of the Sabah basin, reservoir geology and the determination of the gross rock volume from contour maps.
The description and history of the Sabah basin includes its location, geological age, the date of discovery and by whom, the geological settings, and the provinces that make up the basin. It also includes the geological description of the Southern Inboard Belt province, where the Gelama Merah field is located according to the coordinates from the field report.
The reservoir geology includes the description of the depositional environment, the lithological make up, tectonics and sedimentation and stratigraphic correlation.
The gross rock volume is determined using two methods. These methods are the Planimeter method and the use of software (Petrel). In this project we are required to use the planimeter to calculate the gross rock volume. The value obtained from Petrel is used to compare with the gross rock volume from the Planimeter to determine how much the values deviate from one method to another. The Petrel value will be also used in producing the dynamic model from the static geological model in the reservoir engineering phase. The gross rock volume is used in the estimation of STOIIP and GIIP (See Section 5).
3.2 History and Geological Description of Sabah Basin 3.2.1 Sabah Basin
The Sabah basin is located on the northwestern continental margin of Sabah state. This is shown in Figure 3.1. The age of the Sabah basin ranges between the middle Miocene and Recent, which means that the basin came into existence between the Tertiary and the Quaternary periods of the Cenozoic era. The basin unconformably
overlies deformed deep water sediments and now forms the Crocker formation and Rajang group. The structure and stratigraphic evolution of the north western continental margin was first discovered by Hinz et. al. and Hoorn in 1980. The basin also exhibit features of compressional margins characterized by thrust and wrench tectonics, which reflects the strong influence tectonics has had over its structural evolution.
Figure 3.1: Structural elements of Sabah Basin, showing basin boundaries and tectonostratigraphic provinces
Figure 3.2: Regional cross-section of the Sabah Basin showing the Southern Inboard Belt and East Baram Delta
The Sabah basin is divided into provinces that are characterized by distinct structural styles and sedimentation history. The provinces include the Baram Delta, Inboard belt, Outboard belt, Sabah Troughs and the northwest Sabah Platform. Its sedimentation history involves basically the northwestern progradation of siliclastic shelf. Sedimentation since the middle Miocene was the early phase of the deep marine sedimentation. Sedimentation was separated by several regional unconformities at the basin margin.
There are two phases of deposition recognised by Noor Azim Ibrahim in 1994. These include a very rapid subsidence phase during the early middle Miocene to early late Miocene which result in deltaic aggradation. The second phase is a slower subsidence phase accompanied by western progradation of shelf- slope system as sediment accommodation rates exceed the rate of increase in accommodation space.
3.2.2 Southern Inboard Belt
According to the co-ordinates given in the final well report and rig data, the Gelama- Merah field is located at the southern inboard belt nearby the Morris faults. The southern inboard belt is made up of the North to South and the North-North-East to the South-South-West trending anticlines with steep flanks and strongly faulted crests. The synclines are the kitchen source areas for the hydrocarbons in the surrounding structures. The core of the anticlines mainly comprises of uplifted deep marine Stage III shale. Large scale sinistral strike faults and cumulative horizontal displacement of nearby 100 km in length have been found in the southern inboard belt.
Figure 3.3: Map of Southern Inboard Belt in Sabah Basin
The initial deltaic progradation in the Southern Inboard Belt traced back from the Labuan-Paisley syncline and was followed by a rapid north-western progradation of a major delta towards the Samarang area (connecting with the East Baram Delta). This progradation was maintained by uplifting of the hinterland and erosion of the older forest (Rice Oxley, 1999). Stage IVA represents the first significant deposition of alluvial, coastal plain and deltaic sediment in the inboard belt.
Stage IVB is a thin transgressive marine sequence which is absent over some of the syn-depositional highs. Stage IVB mudstone has been encountered in the drilling of the exploration wells but most of the sand rich upper portions has been eroded. Intense deformation during the late Miocene and subsequent tectonic stability is characteristic of the Southern Inboard Belt. The deformation process results into the tightening of the earlier formed structures and the inversion of the depositional troughs to form a complex pattern of ridges and synclines.
Figure 3.4: Palaeogeographic reconstruction of the Sabah Basin
The main hydrocarbon zones are in the stage IVC which directly overlies the stage IVA at the upper intermediate unconformity area as a result of submarine erosion and slumping at the late Miocene shelf edge (Level and Kasumaja, 1985). The structures were affected by the late Miocene Shallow Regional Unconformity deformational event which resulted in the secondary migration of the hydrocarbon from stage IVA. The reservoirs are shallow marine storm wave influenced environment with slight fluviomarine influence (Johnson et al, 1989). The reservoirs are part of the prograding shelf-slope system that built out over tectonically active shelf margins.
3.3 Reservoir Geology
3.3.1 Depositional Environment
The reservoir is shallow marine storm influenced environment with slight fluovioma- rine influence. The deposition of the sediment occurs when the storm influenced wave causes erosional slumping of the continental shelf in the late Miocene shallow regional unconformity deformational event. This results into the migration of the hydrocarbon from the stage IVA sediments to the stage IVC which is a potential sandstone reservoir.
Figure 3.5: West-East cross-section of Gelama Merah field
Figure 3.5 represents the cross-section of the Gelama Merah field. The cross-section is asymmetrical in shape, which means that one flank is longer than the other. The west part of the cross-section is towards the shore and the east side is towards the seaward direction.
The layers U3.2 to U8.0 are merged according to the Gelama Merah-1 ST1 when correlated with Gelama Merah-1 as shown in Figure 3.6, which is an evidence of erosion of these layers. This results in the formation of angular unconformity, which is a secondary stratigraphic trap.
The layers U9.0 to U9.2 have no evidence of unconformity since these layers are conformed according to the correlation of the two wells. The oil-water contact and the gas-oil contact cuts through all the layer.
Shallow Marine Environment
In the shallow marine environment the dominant process is the wave action, but can also be affected by tidal currents. The rate of deposition of sediments in the shallow marine environment depends on the energy of the wave. Low wave energy tends to produce a bedform such as wave ripples. High energy waves such as storm waves transport sediments into deep water and after deposition the storm waves rework the sediments continuously. The higher the energy of the wave the coarser the sediments. As the sediments are overstepped seawards in a sequence stratigraphy offshore, they produce upward coarsening facies sequence.
Tectonics and Sedimentation
Tectonics is responsible for uplift and subsidence of rock area and influences the structure of the reservoir. After the rock undergoes uplifting, it is eroded and therefore gives rise to angular unconformity. The angular unconformity gives rise to stratigraphic traps, which is an arrangement of seal and reservoir rocks. The uplifted or folded rocks results into debris which are transported to a zone of subsidence. The subsidence zone will convert to a depositional environment through geological time. Figure 3.6 shows the tectonic setting of Sabah Basin.
Figure 3.6: Tectonic setting of Sabah Basin 3.3.2 Lithology Descriptions
According to the report from the two wells drilled, the Gelama Merah-1 and Gelama Merah-1 ST1 proved that the reservoir is made up of three rocks. These are sandstone, claystone and dolomite. sandstone forms the largest part the formation, followed by claystone and a very small portion of dolomite.
Based on The Petroleum Geology and Resourcees of Malaysia by Petronas (1999), the porosity varies from 20%-35% and permeability values of 600-2000 mD.
Gelama Merah-1
The Gelama Merah-1 well was drilled from a depth of 553 m to a total depth of 1636 m. Cores were taken from 3 intervals within the total depth of the well.
• Interval (553-1120) - Interbedding of Sandstone, Claystone and Dolomite
Sandstone — is mainly soft to friable in texture, with partly medium hard, which indicates that it is unconsolidated. The grains ranges fine to very fine quartz, moderately to well sorted, sub-angular to sub rounded in shape.
Claystone — is mainly soft to firm in texture, partly moderately hard, amorphous to sub blocky in shape. It comprises mainly of silt and very fine quartz grain. Some traces of carbonate rocks such as dolomite and pyrite were observed.
Dolomite — is hard to very hard in texture and the grains are sub-angular to angular in shape.
• Interval (1320-1636) - Interbedding of Sandstone and Claystone
Sandstone — is mainly soft to friable in texture, partly medium hard. The grains are quartz dominated, sub angular to sub-rounded in shape, moderately to well sorted grain size. Traces of carbonaceous matter were observed.
Claystone — is very soft to soft in texture, amorphous in shape. It is partly silty with very fine quartz grains. Traces of carbonaceous matter were observed.
Gelama Merah-1 ST1
The Gelama Merah-1 ST1 well was drilled from a depth of 560m to a total depth of 1797m. Cores were taken from 3 intervals within the total depth of the well.
Claystone — is soft to moderately hard in texture, partly soluble, Sub blocky to amorphous in shape. It comprises of mainly silt and partly very fine quartz grains. Traces of carbonaceous matter were observed.
Sandstone — is moderately hard to hard in texture, mainly comprises of loose quartz grains, sub angular to sub rounded in shape, sorting is moderate to well sorted, and traces of carbonaceous matter were observed.
• Interval (1600-1797) - Interbedding of Sandstone and Claystone with minor Dolomite
Sandstone — is moderately hard to hard in texture, comprises of loose quartz grains, which are moderately to well sorted, Sub-angular to sub-rounded in shape, and traces of carbonaceous matter were observed.
Claystone — is very soft to soft in texture, mainly amorphous in shape and partly sub blocky. It comprises of slit and traces of very fine quartz grains.
Dolomite — the grains are moderately hard to hard in texture, with angular shapes.
3.3.3 Stratigraphic Correlation
Stratigraphy is the pattern of succession of rock strata in an area represented diagrammatically by a stratigraphy or geological column. Stratigraphic correlation is the process where rock unit and other features such as fossil, magnet etc, which are correlated through wells to determine their lateral extension within the reservoir. Lithostratigraphy is commonly used and it gives an understanding of the lateral extension of lithified rock units, thereby enhancing knowledge on reservoir characteristics. Correlation of lithology will give knowledge of the arrangement of the facies, porosity and permeability zones, flow units and potential barriers in a reservoir and also the volume and extent of the reservoir. According to the law of
superposition the older rocks are deposited first before the younger rocks, and therefore a succession that has not been overturned will have the older rocks at the base and the younger at the top. Lithostratigraphy correlation involves correlating the older rocks first at the base of the well before the younger rocks.
According to the logs obtained from the two wells in the Gelamah Merah field, Gelama Merah-1 and Gelamah Merah-1 ST1 (Figure 3.7) there is an evidence of erosion on layers U3.2, U4.0, U5.0, U6.0, U7.0, U8.0 as they are correlated between the two wells. This evidence is supported by the fact that these layers are laterally discontinuous on Gelama Merah-1 ST1. The erosion also gives to the evidence of an angular unconformity, which forms stratigraphic traps. Stratigraphic traps are formed from an arrangement of seals and reservoir rocks. Correlation of layers U9.0, U9.1 and U9.2 through both wells show that there is lateral continuity of these layers, although the thickness varies from one well to the other.
The main uncertainty in the Gelama Merah field is the fact that the two wells cannot give the information of the reservoir rock, properties such as porosity and permeability throughout the extent of the reservoir. If more wells are drilled in line and correlated then the uncertainty will be reduced and the reservoir structure and characteristics will become more clearer.
Figure 3.7: Lithology correlation between Gelama Merah-1 and Gelama Merah-1 ST1
3.3.4 Petroleum System
Source Rock
The source rock of the Gelama Merah field is found in the stage IV sequences (post DRU). It is mainly rich in terrigenous organic matter derived from land plants .Small quantities of liptinic organic matter which comprises of cutinites and resinites is also present. The Labuan paisley synclines are believed to be the possible kitchen source for hydrocarbons. The erosion of the northwest Sabah margin during early Miocene-
middle Miocene, and the outbuilding of Stage IV siliclastics, which results in the deposition of source beds rich in terrigenous organic matter.
Trap
The trap mechanism in the Gelama Merah field is a combination of structural and stratigraphic traps. The structural traps includes folding (anticline) due to tectonic activities and erosion of the anticlines results into unconformities which is an indication of stratigraphic traps.
Seal
The presence of shale (claystone) in the sand units forms the seal to the hydrocarbon traps.
Reservoir
The reservoirs in the Gelama Merah field were deposited during the stage IVC as shallow marine coastal sands influenced by both wave and storm activities.
3.4 Calculations of Gross Rock Volume
Gross rock volume is the total volume between the mapped surface that defines the top of the reservoir or potential reservoir and the hydrocarbon contact or expected hydrocarbon contact. In this report, structural maps are used to determine the gross rock volume by using two methods:
1. Using a mechanical device known as planimeter 2. The use of software – Petrel
To calculate the gross rock volume the surface areas on contour maps are first calculated.
Once the surface area has been calculated through the above methods the gross rock volume can be computed using the trapezoidal rule, Simpsons rule or the peak rule for calculating volume. The true stratigraphic thickness (isopach) is used in the calculation of the gross rock volumes. The isopach can also be used to generate the
base structure map if the base structure map is not available. This is done by subtracting the contour map of sand thickness from the top structure to give the structure at the base of the reservoir.
The main purpose of the gross rock volume is to determine the hydrocarbon initially in place, gas initially in place and the stock tank oil in place. This calculation is carried out by integrating the gross rock volume with porosity, net to gross, hydrocarbon saturation and formation volume factor.
3.4.1 Planimeter Method
Planimeter is a mechanical device operated manually to measure the areas of the structural maps. Figure 3.8 shows the image of a planimeter.
Figure 3.9 shows a structural map of sand unit U3.2 where the area within a selected depth interval is measured (Jahn et al., 1998).
Figure 3.8: A Planimeter tool
Methodology
1. Calibrate planimeter for each structural map. Each map has a different scale and hence different calibration.
2. Once the planimeter is calibrated, planimeter each contour to find the area. The stylus of the planimeter is guided around the depth to be measured and the respective area contained within this contour can then be read off (Jahn et al, 1998).
3. After the area is found, construct a plot of depth against area, connect the measured points. This will result in a curve showing the area-depth relationship of the top of the reservoir. Increasing area-depth, the area measured for each depth will also increase. The GRV is calculated by the product of the area (A) and the gross interval thickness. Note that this method assumes that the reservoir thickness is constant across the whole field.
Figure 3.9: Structural map for Unc/U3.2 layer
Planimeter Results
The contour areas obtained from the gas cap depth to the oil-water contact using the Planimeter are plotted in Figure 3.10. Although there are some close proximities from Layer U3.2 to U7.0, there is no overlapping between the area lines from the
graph, implying that all the layers are subsequently confined underneath one another. This may explain the presence of some uncomformities along the sand units.
The planimeter area numerical results can be found in Table A.1-1 to Table A.1-3 from the Appendix. Calculation of GRV is done using Trapezium Rule (Equation 3.1).
𝑉!"= 1
2× 𝐴!+ 𝐴! ×𝐻
Equation 3.1
where,
V12 is the volume between depth 1 and 2,
A1 is the surface area at depth 1,
A2is the surface area at depth 2, and
H is the height between depth 1 and 2.
3.5 Conclusion
The reservoir in the Gelama Merah field is mainly made up of siliclastic rocks namely claystone and sandstone. Carbonate rocks such as dolomite is also present in the lithological make up but in small quantity. The reservoir comprises of interbedded sandstone claystone and dolomite according to the two wells drilled during exploration which confirms that our reservoir is moderately homogenous. The depositional environment is shallow marine which means that the sediments are influenced by wave action and energy with a slight fluviomarine influence.
3.6 References
PETRONAS. (1999). In The Petroleum Geology and Resources of Malaysia (pp. 500-542).
Heriot-Watt University. (2005). Petroleum Geoscience.
Jahn, F., Cook, M., & Graham, M. (1998). In Hydrocarbon, Exploration and
Production (First ed., p. 155). Elsevier B.V.
Forrest, J. K., Hussain, A., Orozco, M., Bourge, J. P., Bui, T., Henson, R., et al. (2009). Semarang Field - Seismic To Simulation Redevelopment Evaluation Brings New Life to an Old Oilfield, Offshore Sabah, Malaysia. 8.
4 Formation Evaluation
4.1 IntroductionPetra- is a latin word for rock, while physics is the study of nature. Petrophysics, therefore, is the study of rock nature. By definition, Petrophysics is the study of the physical and chemical properties of rocks and fluids contained.
Petrophysics enables the determination of reservoir and fluid characteristics such as lithology and bed boundaries, porosity and permeability, fluid properties such as saturation, types, etc. and flow between different fluid phases.
In order to determine such properties and characteristics of the reservoir as mentioned above, petrophysics involves the analysis of data obtained from the logging tools as well as from the physical core.
4.1.1 Objective
Formation evaluation is to study and understand the reservoir based on its interactions with the logging tools as well as from the core data analysis. This, in turn, will help in the determination of the reservoir rocks and fluid characteristics.
Hence, the objective of this part of the project is to obtain numerical values of several reservoir parameters that will aid in the volumetric calculations such as HIP (STOIIP, GIIP) and reserves. Such parameters include:
• Net-to-Gross, • Porosity, and • Water saturation
Once these parameters have been obtained, their values are plugged in to the STOIIP (or GIIP), combined with other parameters acquired from the Geologist and Reservoir Engineer, which are the Gross Rock Volume and Oil Formation Volume Factor, 𝐵 , respectively.
STOIIP= GRV× 𝑁 𝐺 ×∅×(1 − 𝑆!) 𝐵!"
Equation 4.1 4.1.2 Data
Logging Program
The logging programs for both Gelama Merah-1 and Gelama Merah-1 ST-1 are listed in Table 4.1 below.
Table 4.1: Logging program for Gelama Merah-1 and Gelama Merah-1 ST1
Wells Gelama Merah-1 Gelama Merah-1 ST1
Hole section 12¼” 12¼”
Depth 553m – 1636m 560m – 1797m
Logging tools Super Combo
MDT CSI SWC Super Combo DSI Remarks: MDT run #2 failed due to stuck in hole, fished out with DP
Petrophysical Logs
The well logs available to be imported into the well data is obtained from the LAS file format were the Resistivity (RDEED_1, RSHAL_1 and RMICRO_1), Density (DEN_1), Caliper (CALI_1), Neutron (NEUT_1), Gamma Ray (GR_1), Spontaneous Potential (SP_1), Sonic Logs (DTCOMP_1, and DTSH_1) and Photoelectric (PEF_1).
Sidewall Cores
There were 26 sidewall cores taken from Gelama Merah-1 between depth of 1086m to 1617m, out of which only 22 cores were recovered while the remaining 4 cores returned empty. Among the successful cores, however, only 3 of them that have shows, which were taken from depth 1498.1m to 1573.1m as shown in Table 4.2 below. No sidewall core were retrieved from Gelama Merah-1 ST-1.
Table 4.2: Summary of cores with shows Core
Number Depth (m) Shows
5 1573.1
- 15-20%
- Slow blooming light bluish white fluorescence - Bluish white residual thin film
- Weak odour
6 1558.0
- 5%
- Very slow blooming bluish white fluorescence - Bluish white residual thin film
8 1498.1
- 15-20%
- Slow blooming light bluish white fluorescence - Bluish white residual thin film
- Weak odour
4.2 Petrophysical Analysis
Microsoft Excel was used to run and analyze the petrophysical analysis. 4.2.1 Gelama Merah-1
See Section B.1.1 in the Appendix for the Petrophysical logs of Gelama Merah-1. Depths below are in MDDF.
1300-1330m:
o High Gamma Ray reading can be seen indicating high shale content in the formation. Possibly shale formation. High Neutron porosity is observed indicating high content of hydrogen index possibly due to claybound water. Density reading also high (2.4 g/cm3). Resistivity logs read low indicating
conductive, saline claybound water in the formation.
1330-1460m (Layers U3.2, U4.0, U5.0, U6.0, U7.0 and U8.0):
lacking of H-index is observed. Density also reads low (2.0 g/cm3) from the logs, creating cross-overs, which is due to effects of gas present in the formation. High resistivity fluctuations indicating potential hydrocarbon
1465-1510m (Layer 9.0):
o Gamma ray logs still read low, thus sandstone formation. Density-Neutron crossovers still occurring indicating gas presence down to depth 1490m. After 1490m, Neutron logs read sudden increase in H-index (high Neutron porosity). Density reading also increased, indicating possible fluid change from gas to liquid. High resistivity remains observed, thus, potential hydrocarbon present in the formation, possibly oil.
1520-1530m (Layer 9.1):
o Low Gamma Ray is observed. Neutron porosity remains high with density slightly fluctuates. Resistivity is seen to remain high due to the presence of potential hydrocarbon (oil).
1530-1550m:
o High, fluctuating Gamma Ray is observed indicating shale content. Possible shale layer in the formation. Density logs read relatively higher (2.4 g/cm3) and Neutron porosity remains high. Low resistivity is observed, indicating the presence of claybound water. Possible water-bearing zone.
1350-1600m (Layer 9.1):
o Low Gamma Ray counts indicate possible sandstone formation. High H-index is seen in Neutron logs (high Neutron porosity). Density remains fluctuating. Resistivity is seen low indicating conductive fluid in the formation. Possible water-bearing zone.
4.2.2 Gelama Merah-1 ST1
See Section B.1.2 in the Appendix for the Petrophysical logs of Gelama Merah-1 ST1. Depths below are in MDDF.
1200-1590m:
o High Gamma Ray reading is observed, indicating high shale content. Possible shale formation. High H-index (high Neutron porosity) and high density (2.4 g/cm3), potential claybound water. Low resistivity is observed indicating conductive fluid present i.e. saline claybound water.
1590-1660m (Layer U9.0, U9.1 and U9.2):
o Relatively lower Gamma Ray is seen indicating possible sandstone formation with thin shale layers. Low Neutron porosity is observed (low H-index). Cross-overs are seen in the Neutron-Density logs, indicating possible gas presence. High resistivity is observed, gas is potentially hydrocarbon.
1660-1720m (Layer U9.2):
o Gamma Ray remains low. Cross-over dimishes as Neutron porosity increases (high H-index). Density also starts to increase, indicating change in fluid phase. Resistivity remains high. Possible GOC is located with potential hydrocarbon (oil).
1720-1760m (Layer U9.3):
o Relatively low Gamma Ray reading is seen indicating possible sandstone formation. Density logs showing increasing value whilst Neutron porosity remains high. Resistivity reading is reduced, indicating conductive medium is detected. Possible OWC is located with potential water-bearing zone.
4.3 Fluid Analysis 4.3.1 Fluid Contacts
Determination from Logs
The Density-Neutron is first used to interpret the GOC, which usually can be seen by its diminishing crossovers - indicating the change of fluid phase from gas to oil. In this case however, the crossover in the oil zone is very small or almost absent. Resistivity log is then needed to check for the presence of oil as it would indicate high resistivity. Looking at the resistivity in the water-bearing zone, we can conclude that the formation water is saline due to its low resistivity.
• Gelama Merah-1
o For the Gelama Merah-1 well, it can be seen from Figure 4.1 that GOC is present within Layer U9.0 at the depth of 1494 m (1466.7 m TVDSS). The OWC, on the other hand, is indicated to lie below the base of Layer U9.1 (outside the zone of interest). This depth is equivalent to 1535 m (1507.7 m TVDSS).
Figure 4.1: GOC and OWC determined from the Neutron-Density and Resistivity logs for Gelama Merah-1
• Gelama Merah-1 ST1
o The GOC in GM-1 ST1 is located at 1668 m (1467.3 m TVDSS). This Gas-Oil Contact lies in Layer U9.2. The OWC is indicated in Layer U9.3 at the depth of 1722 m (1510.8 m TVDSS). See Figure 4.2.
Figure 4.2: GOC and OWC determined from the Neutron-Density and Resistivity logs for Gelama Merah-1 ST1
The difference of fluid contacts between the two wells are small. By taking average, this gives a uniform GOC depth at 1467.0 m, and OWC at 1509.3 m in TVDSS. There is a uniform 42.3 m gross thickness of oil column present across the reservoir.
Table 4.3: Comparison of fluid contact depths between GM-1 and GM-1 ST1 wells
Contacts Wells Depths, m
MDDF TVDSS Average
GOC GM-1 1494 1466.7 1467.0
GM-1 ST1 1668 1467.3
OWC GM-1 1535 1507.7 1509.3
Determination from MDT
Fluid contacts obtained from petrophysical logs can be confirmed with the pressure data plot obtained from MDT as shown in Figure 4.3. Converting the depth as TVDSS, the GOC is located at 1466.1 m, and OWC at 1506.1 m.
Figure 4.3: Fluid contacts obtained from MDT data
From MDT data, it can be seen that OWC depth is shallower than that obtained from the logs as tabulated in Table 4.4. This is because MDT detects only mobile hydrocarbons. Unlike logs, which record the presence of both mobile and immobile hydrocarbons.
Table 4.4: Comparison of fluid contacts between logs and MDT tool
Contacts Depths, m (TVDSS)
Logs MDT
GOC 1467.0 1466.1
4.3.2 Fluid Types
The fluid types in the reservoir can be identified from the pressure plot (Figure 4.3) by looking at the gradients, where the gas gradient turns out to be 0.046 psi/ft, oil gradient is 0.35 psi/ft and water gradient is 0.43 psi/ft. Table 4.5 below summerises the fluid classification.
Table 4.5: Fluid type identification from the MDT plot Fluid Types Gradients, psi/ft
Gas 0.05
Oil 0.35
Water 0.43
4.4 Properties Calculation 4.4.1 Volume of Shale
To determine the volume of shale, Vsh, in the interested zones, the first step is to
calculate the Gamma Ray Index, IGR, which can be represented by the following
equation,
𝐼!" = 𝐺𝑅!"#− 𝐺𝑅!"# 𝐺𝑅!"# − 𝐺𝑅!"#
Equation 4.2
where,
𝐺𝑅!"# is the Gamma Ray log reading,
𝐺𝑅!"# is the maximum Gamma Ray log reading,
𝐺𝑅!"# is the minimum Gamma Ray reading which indicates clean sand
The GRmin is taken to be 52 API and the GRmax is 100 API as seen in Figure B.1-1 in
the Appendix B.1. The volume of shale is related to the Gamma Ray Index by the following relationship:
See Table B.1-1 in the Appendix for shale volume of each sand unit for both Gelama Merah-1 and Gelama Merah-1 ST1 wells.
Vsh Cut-off
Vsh cut-off is the maximum amount shale content present in the formation which is
considered to be sand or reservoir rock. The cut-off is calculated by using a Gamma Ray-Density crossplot where point when the density reaches the plateau is taken to be the Vsh cut-off as shown in Figure 4.4. This point on the crossplot reads GRlog of
84 API. By using Equation 4.2, the Vsh cut-off is calculated to be 66.7%.
Figure 4.4: Finding Vsh Cut-off from GR-Density crossplot
4.4.2 Net-to-Gross
The Net-to-Gross is calculated by taking the ratio of Net Sand thickness to the Gross Interval thickness. Figure 4.5 shows the definitions of reservoir thicknesses. Here, the gross interval is the total height of the sand unit, and the net sand term is the sand thickness after both the Vsh and ϕ cut-offs have been applied. The average
See Table B.1-3 in the Appendix for the Net-to-Gross values for each sand unit for both Gelama Merah-1 and Gelama Merah-1 ST1 wells.
Figure 4.5: Definitions of Gross Sand, Net Sand and Net Pay (Petroleum Geoscience, Heriot-Watt University)
4.4.3 Porosity
Porosity is the amount of space in the rock that can contain hydrocarbons. Therefore, determining the pore space of the reservoir rocks is vitally important as this allows the volume of hydrocarbons to be calculated. Porosity can be calculated from Density, Neutron and Sonic logs. However, a combination of these logs are often used to acquire better values of porosity. In this case, only Density-Neutron logs are used due to the presence of gas which has major impact (overestimation) on porosity calculations using Sonic logs. The porosity of the Gelama Merah reservoir is calculated to be 27.9%, and the corresponding effective porosity of 24.0%. From the porosity values in each layer from Table B.2-1 in the Appendix, the porosity varies from 24.9% to 30.1% - an evidence of a moderately homogeneous reservoir.
See Section B.2 in the Appendix for steps in calculating porosity using Density-Neutron logs.
Porosity Cut-off
Porosity cutoff is the minimum porosity that is considered to valid when differentiating between reservoir and non-reservoir rocks. In other words, any porosity value that is lower than the cutoff is rejected and considered as non-reservoir rock. A Poro-Perm plot established from the available core data is used to obtain this porosity cut-off of 12.6% as seen in Figure 4.6.
In the calculation of the porosity cut-off, a permeability of 0.1 mD is taken as the cut-off point where the formation is no longer able to make fluids flow. This is equivalent to the porosity cut-off value mentioned previously.
See Table B.4-1 in the Appendix for the core data grouping.
Figure 4.6: Poro-Perm relationship to obtain Porosity Cut-off when k = 0.1 mD
Porosity Averaging
Average porosity, 𝜙! is carried out using arithmetic thickness average, 𝜙! = !!!!𝜙!ℎ!
ℎ!
! !!!
Equation 4.3
Where,
𝜙 is the porosity, and ℎ is the height.
4.4.4 Water Saturation
Archie’s Saturation
The application of Archie’s equation in a shaly reservoir like Gelama Merah is not a valid approach as this would result the water saturation calculated to be underestimated. Other methods should be used instead, such as Dual Water Model and Buckley-Leverett J-Function.
Dual Water Model
Dual Water is a more accurate model to be used in calculating the water saturation index to take into account on the presence of shaly sandstone that exists in the Gelama Merah reservoir. Based on a calculated formation water resistivity of 0.274 Ωm, the average water saturation is 39.2%.
See Section B.3 in the Appendix for the step in calculating water saturation using Dual Water Model.
See Table B.3-1 in the Appendix for water saturation values of each sand unit in both Gelama Merah-1 and Gelama Merah-1 ST1 wells.
Water Saturation Averaging
A thickness, porosity averaging method is used to calculate the water saturation of the Gelama Merah reservoir.
𝑆! = !!!!𝑆!𝜙!ℎ! 𝜙!ℎ! ! !!! Equation 4.4 where,
Sw is the water saturation,
ϕ is the porosity, and h is the net pay thickness.
Sw Cut-offs
Water saturation cut-off is calculated using the ratio of relative permeabilities which is obtained from SCAL analysis (Gelama-2 ST1 Core Anlaysis Report) as shown in Figure 4.7. By taking the ratio of relative permeabilities of the cut-off to be 1, the water saturation cut-off is equivalent to 59%. See Table B.3-2 for data table.
Figure 4.7: Obtaining water saturation cut-off from core data
4.5 Core Analysis
4.5.1 Poro-Perm Relationship
Porosity has the most obvious control on permeability. This is because, larger porosities define that there are many more and broader pathways for fluid to flow. A plot of permeability (on a logarithmic scale) against porosity for a formation will result in a clear trend with a degree of scatter associated with the other influences
controlling the permeability. This Poro-Perm crossplot can be constructed to help clearly define lithologies or reservoir zones.
From the given core data, a Poro-Perm relationship can be established by plotting log of permeability against porosity of the core samples, which can be seen in Figure 4.8.
Figure 4.8: Poro-Perm relationship showing three facies in Gelama Merah reservoir
From Figure 4.8, three groups of facies can be identified by separating the cores based on their permeabilities as shown in Table 4.6 below.
Table 4.6: Facies group according to their range of permeabilities
Facies Permeability, mD Remarks
1 < 20 Poor rock
2 20 < k < 150 Moderate rock
3 >150 Good rock
Once the Poro-Perm relationship has been established from the core data, permeability values from the petrophysical logs can be estimated. See Table B.4-1 in the Appendix for the core data grouping.
4.5.2 Capillary Pressure
There are 10 core samples that have capillary pressure data provided from the Gelama-2 ST1 Core Analysis Report (see Table B.4-2 in the Appendix). The core samples are grouped together according to their facies type as laid out in Table 4.6.
Capillary pressure curves as a function of water saturation is plotted as shown in Figure 4.9.
Figure 4.9: Capillary pressure as a function of water saturation for the 10 core samples
4.5.3 Buckley-Leverett J-Function
The purpose of J-Function is to convert all capillary pressure data into a single universal curve as a function of porosity, permeability and capillary pressure. Its advantage is the ability to predict water saturation anywhere in the reservoir – unlike wireline tools which can only measure water saturation within the vicinity of the wellbore. Leverett defined the dimensionless function of saturation (J-function) as:
𝐽 𝑆! =
𝑝!(𝑆!) 𝑘 𝜙 𝜎 cos 𝜃 where,
