Field Development Project Group 2 Final Report

7/24/2019 Field Development Project Group 2 Final Report

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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 helpthe 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 usefulsuggestions 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

wishes for the successful completion of this project.


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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

6.4 Reservoir Fluid ............................................................................................................. 63


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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

7.12.8 Possibility of any transmission line or gas lines .............................................. 119


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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

8.6.3 Scale Formation ............................................................................................... 145


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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

10.5 Economic Assumptions ............................................................................................ 169

10.6 Development Options ............................................................................................... 172


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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

11.10.1Sustaining Development in Gelama Merah Field ............................................ 196

11.11 References .............................................................................................................. 197


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Listof Figures

Figure 2.1: Location of Gelama Merah field ............................................................... 2

Figure 2.2: Organisation and structure of the team ...................................................... 5Figure 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 5.1: Probability and Cumulative Distribution Functions of STOIIP .............. 46


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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 7.3: Subdividing the area for rig placement .................................................... 96


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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

Figure 11.1: PETRONAS HSE Management System ............................................. 186


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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 .......... 26Table 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 7.5: Rig Equipment ........................................................................................ 102


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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 ........................................................................................................................ 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 9.1: Physical properties of Gelama Merah reservoir fluid ............................. 152

Table 9.2: Reserves and Development data of Gelama Merah ................................ 152


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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

Table 10.8: Sensitivity Parameters of Option A ...................................................... 182


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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. Forthe 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.


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2Introduction

2.1Background 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


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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.

2.2Problem 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 mostlikely 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.


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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 projects 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. Yaakub

5.

Siti Mariam Annuar

6. Djamalov Shukhrat Rustamovich

7.

Lydia Bt. Mohd Yusof

2.4.2 Organisation and Structure

The organisation of the team is shown in Figure 2.2.


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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. Phase1 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.

"#$%& '$($%)*+$,-

./)0$1- 2$3+

!"#$#%&

4)53+$& 2#+6)

738,3#, 9%#

:#-# 43/#3+

(#)*+,-#./0+$1+,-#.

9 9#+3,

;


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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

Final Report Submission 29 February 2012


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Figure 2.3 Field Development Project Plan


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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


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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


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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.


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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.


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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 reservoirsare part of the prograding shelf-slope system that built out over tectonically active

shelf margins.


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3.3Reservoir 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, whichis a secondary stratigraphic trap.


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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.


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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.


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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. Thegrains 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.

Interval (1200-1600) - Dominant Claystone with minor Sandstone


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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


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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.


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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-


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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


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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.


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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 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


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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).

!!" !!

!! !! ! !! !!

Equation 3.1

where,V12

is the volume between depth 1 and 2,

A1is the surface area at depth 1,

A2is the surface area at depth 2, and

H is the height between depth 1 and 2.

Figure 3.10: Plot of contour areas with respect to depth


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3.5Conclusion

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.


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4

Formation Evaluation

4.1

Introduction

Petra- 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 itsinteractions 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, !!", respectively.


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STOIIP !

GRV!!!!!!!!! !

!!

!!"

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 12" 12"

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.


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Table 4.2: Summary of cores with shows

Core

NumberDepth (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


8 1498.1

- 15-20%- Slow blooming light bluish white fluorescence


- 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):

o

Low Gamma ray reading observed with slight fluctuations, indicating possible

sandstone formation with thin shale layers. Low Neutron porosity due to


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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.


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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.


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4.3Fluid 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


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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 WellsDepths, m

MDDF TVDSS Average

GOCGM-1 1494 1466.7

1467.0GM-1 ST1 1668 1467.3

OWCGM-1 1535 1507.7

1509.3

GM-1 ST1 1722 1510.8


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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

ContactsDepths, m (TVDSS)

Logs MDT

GOC 1467.0 1466.1

OWC 1509.3 1506.1


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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,

!!" !!"!"# ! !"!"#

!"!"#

! !"!"#

Equation 4.2

where,

!"!"# is the Gamma Ray log reading,

!"!"#

is the maximum Gamma Ray log reading,

!"!"#is the minimum Gamma Ray reading which indicates clean sand

The GRminis taken to be 52 API and the GRmaxis 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:

!!! ! !!"


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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

Vshcut-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 Vshcut-off as shown in Figure 4.4. This point on the crossplot reads GRlogof

84 API. By using Equation 4.2, the Vshcut-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 !cut-offs have been applied. The average Net-to-

Gross for Gelama Merah reservoir is calculated to be 72.2%.


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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.


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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 rel

Field Development Project Group 2 Final Report

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