A green field development project located in Sabah Basin comprises the whole upstream field development cycle from geology, reservoir studies to production facilities and economics. The objective is to come out with the best strategy to develop the field starting from our very own effort of reservoir characterization out of log and core data. Under supervision of lecturers, this project was completed as per scheduled. Among new technical methodologies applied upon the completion this project: 1. Cubic Spline Interpolation Method in bulk volume calculation 2. Monte Carlo probabilistic method in reserve estimation 3. Reservoir Opportunity Index (ROI) method in well placement Project was assessed by PETRONAS custodians.

1. Gelama Merah
Group 10
Supervisor: Muhammad Aslam B Md Yusof

2. CONTENT
INTRODUCTION
RESERVOIR ENGINEERING
DRILLING ENGINEERING
PRODUCTION TECHNOLOGY
FACILITY ENGINEERING
PROJECT ECONOMICS
HEALTH, SAFETY & ENVIRONMENT
1

3. Background & Problem Statement
Objectives & Scope of Study
Regional Geology, Petrophysics &
Volumetric
INTRODUCTION
2

4. Project
Background
Problem
Statement
Objective
The ultimate objective is to produce a
reasonable and reliable FDP report
that satisfies the needs of high-level
management in making decision of
the proposed development for
Gelama Merah field
Scope of Study
Reservoir Engineering
Drilling Engineering
Production Technology
Facility Engineering
Project Economic
Health, Safety & Environment
Facing time constraint, limited data
and large number of uncertainties,
the determination of the best
development options has been
considered as a tough challenge.
Summary Description
Block Name SB-18-12
Field Name Gelama Merah
Field
Location
Offshore Sabah,
Malaysia
Well name GM-1, GM ST-1
Well Type Exploration
Lithology Clay stone &
Sandstone
Field 29727503 m2
Marginal Field
Operator Contractor
3

6. REGIONAL GEOLOGY
• Sabah can be divided into 3 basins that are
characterized by distinct structural styles
and sedimentation histories
• Sabah Basin
• NE Sabah Basin
• SE Sabah Basin
Sabah Basin
• Located in East Baram Delta Province in Sabah Basin
• Gelama Merah field located in the West Labuan-Paisley
Syncline and identified by a major North-South growth
Morris Fault
• Deposited in the later part of Middle Miocene sands
Gelama Merah Field
4

7. PETROPHYSICS & VOLUMETRIC
Contacts
Log-Based
Method
Formation-Pressure
Method
GOC 1468.7 m TVD 1467.7 m TVD
WOC 1498.7 m TVD 1503 m TVD
Summary of Deterministic and Probabilistic Methods
Comparison of GOC and WOC
Oil Zone
Deterministic
Probabilistic
Petrel
P10 P50 P90
330 MMSTB 250 MMSTB 485 MMSTB 850 MMSTB 423 MMSTB
Gas Zone
Deterministic
Probabilistic
Petrel
P10 P50 P90
862 BSCF 678 BSCF 850 BSCF 955 BSCF 955 BSCF
5

8. RESERVOIR ENGINEERING
Reservoir Data Review
Dynamic Model Setup
Reservoir Simulation
Sensitivity Study
Reservoir Management Plan
6

9. RESERVOIR DATA REVIEW : SUMMARY
7
Information Value Source
Oil Rim Thickness 34.3 m Log & MDT
Initial Reservoir Pressure 2116 Psia PVT Report
Bubble Point Pressure 2028.7 Psia PVT Report
Oil Volume Factor 1.17 STB/bbl PVT Report
Average Permeability 140 mD DST Analysis
Average Porosity 0.27 Log
Average Water Saturation 0.36 Log
Rock Compressibility 3.22e-6 1/Psia Hall Correlation
Table: Gelama Merah Reservoir Data Summary

10. RESERVOIR DATA REVIEW : MDT & PVT
1300.0
1350.0
1400.0
1450.0
1500.0
1550.0
1600.0
2050.0 2100.0 2150.0 2200.0 2250.0 2300.0
RESERVOIRDEPTH,MTVDSS
FORMATION PRESSURE, PSIA
Formation Pressure
GOC = 1468.7 m TVDSS
OWC = 1503 m TVDSS
8

11. RESERVOIR DATA REVIEW : RCA & SCAL
y = 0.2143x-1.835
R² = 0.7269
0
5
10
15
20
0 0.2 0.4 0.6 0.8 1
J-Function
Water Saturation, Fraction
J-FUNCTION FOR CORE 1-017, 2-010, 5-002
y = 6E+06x7.8256
R² = 0.7167
0.1
1
10
100
1000
10000
0.1 0.15 0.2 0.25 0.3 0.35 0.4
HorizontalPermeability,mD
Porosity, Fraction
POROPERM CROSSPLOT GM-ST1
9
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Kr
Sg
Gas-Oil Relative Peremability
Krg
Kro
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Kr
Sw
Oil-Water Relative Permeability
Krw
Kro

12. DYNAMIC MODEL SETUP : UPSCALING
Grid Size: 50 x 50 Grid Size: 100 x 100 Grid Size: 200 x 200
Cells Number: 642000 Cells Number: 117660 Cells Number: 16848
CPU Time: 3 – 5 hours CPU Time: 1 – 3 hours
CPU Time: 5 – 10
minutes10

13. RESERVOIR SIMULATION: CASES SUMMARY
Scenario Case Description Oil RF, %
Cumulative Oil,
MMSTB
Cumulative Water,
MMSTB
Cumulative Gas,
BSCF
1 7 Deviated 11.03 49.106 20.288 1130.109
2
a
2 Horizontal + 1
Deviated
7.31 32.517 0.751 280.398
b
2 Horizontal + 2
Deviated
8.77 39.028 1.599 655.509
c
2 Horizontal + 3
Deviated
10.21 45.433 3.526 855.715
d
2 Horizontal + 4
Deviated
11.41 50.753 4.288 1037.598
e
2 Horizontal + 5
Deviated
12.16 54.096 5.36 1091.203
3
a
3 Horizontal + 1
Deviated
9.25 41.165 1.623 384.976
b
3 Horizontal + 2
Deviated
10.28 45.737 2.172 860.65
c
3 Horizontal + 3
Deviated
11.68 51.961 4.256 1022.928
d
3 Horizontal + 4
Deviated
12.7 56.508 4.558 1111.716
Reservoir Cases
Scenario 1: All Deviated
Scenario 2: 2 Horizontal
+ 5 Deviated
Scenario 3: 3 Horizontal
+ 4 Deviated
11

14. RESERVOIR SIMULATION : WELL PLACEMENT &
CREAMING CURVE
0
1
2
3
4
5
6
7
8
9
10
11
0 1 2 3 4 5 6 7 8 9 10 11 12
UR,%
WELL COUNT
Creaming Curve at AOF
0
1
2
3
4
5
6
7
8
9
10
11
12
0 1 2 3 4 5 6 7 8 9 10 11 12
UR,%
WELL COUNT
Creaming Curve 1520 STB/day
ROI
RQI
12
P8
P1
P9
P3
GM-1
P5
P6

15. RESERVOIR SIMULATION : WELL BY WELL OIL
PRODUCTION PROFILE
0
1000
2000
3000
4000
5000
6000
7000
8000
0
200
400
600
800
1000
1200
1400
1600
1800
2020 2022 2025 2028 2030 2033 2036 2039
CumulativeOil,MSTB
OilRate,STB/day
Year
Well Oil Production Profiles
Rate P6
Rate P1
Rate P3
Rate P8
Rate P9
Rate P5
Rate GM1
Cumulative Oil P6
Cumulative Oil P1
Cumulative Oil P3
Cumulative Oil P8
Cumulative Oil P9
Cumulative Oil P5
Cumulative Oil GM1
0
2000
4000
6000
8000
10000
12000
2020 2022 2024 2026 2028 2030 2032 2034 2036 2038
OilRate,STB/day
Year
Well by Well Contribution - Oil Rate
Rate GM1
Rate P5
Rate P9
Rate P8
Rate P3
Rate P1
Rate P6
Year Recovery Period, Year Field Cumulative Oil Production, MMSTB Recovery Factor, %
2025 5 20.9 4.72
2030 10 42.3 9.50
2035 15 47.8 10.82
2040 20 49.1 11.03
13

16. RESERVOIR SIMULATION: WELL BY WELL GAS
PRODUCTION PROFILE
0
50000
100000
150000
200000
250000
300000
0
20000
40000
60000
80000
100000
120000
140000
160000
2020 2022 2025 2028 2030 2033 2036 2039
CumulativeGas,MMSCF
GasRate,MSCF/day
Year
Well Gas Production Profiles
Rate P6
Rate P1
Rate P3
Rate P8
Rate P9
Rate P5
Rate GM1
Cumulative Gas P6
Cumulative Gas P1
Cumulative Gas P3
Cumulative Gas P8
Cumulative Gas P9
Cumulative Gas P5
Cumulative Gas GM1
0
100000
200000
300000
400000
500000
600000
700000
800000
2020 2022 2024 2026 2028 2030 2032 2034 2036 2038
GasRate,MSCF/day
Year
Well by Well Contribution - Gas Rate
Rate GM1
Rate P5
Rate P9
Rate P8
Rate P3
Rate P1
Rate P6
Year Recovery Period, Year Field Cumulative Gas Production, BSCF Recovery Factor, %
2025 5 100.9 9.10
2030 10 689.9 62.26
2035 15 1094.4 98.90
2040 20 1108.0 100.00
14

17. SENSITIVITY STUDY: Depletion Rate
0
10000
20000
30000
40000
50000
60000
0
5000
10000
15000
20000
25000
01/01/2020 09/27/2022 06/23/2025 03/19/2028 12/14/2030 09/09/2033 06/05/2036 03/02/2039
CumulativeFieldOilProduction,MSTB
TotalFieldOilRate,STB/day
Year
Well Production Rate Sensitivities
Rate 1000
Rate 1500
Rate 2000
Rate 2500
Rate 3000
CumOIl 1000
CumOil 1500
CumOil 2000
CumOil 2500
CumOil 3000
0
5
10
15
20
25
0 5000 10000 15000 20000 25000
PlateauPeriodandFieldLife,Year
Field Plateau Oil Rate, STB/day
Plateau Period and Field Life vs Field Plateau Oil Rate
Plateau
Period
Field
Life
15

18. SENSITIVITY STUDY: IOR
Gas Injection
(Rate: 100
MMSCF/d/well)
Water Injection (Rate:
30 MSTB/d/well)
Natural
Depletion
INJECTORS LOCATION
16

19. RESERVOIR MANAGEMENT PLAN
Reservoir
Management Plan
Data
Acquisition
Oil Rim
Development
Strategy
Coning
Mitigation
Reservoir
Surveillance
Concurrent Oil
& Gas
Development
17

20. Offset Well Analysis
Well Trajectory
Mud & Cementing
Casing
Drilling Schedule
Drilling Problems & Technology
18
DRILLING ENGINEERING

21. OFFSET WELL ANALYSIS
19
1) GM-1 Well
2) GM ST-1 Well
3) Alab-1 Well
Alab-1 field is located 50 km
north-east of Labuan and 140 km
south-west of Kota Kinabalu.
Problems encountered
 Pipe stuck
 Shallow gas

22. WELL COORDINATES & RIG SELECTION
Types of MODUs Water Depth Average Daily Rate, USD
Jack-up rig 30 – 500 ft 77,813 - 143,496
Tender Assisted rig Anchor length 44,463 - 117,780
Semi-submersible
rig
150 – 6000 ft 300,279 – 396,342
Drill ship/ Large
Submersible
1000- 8000 ft 237,900 – 420,324
Figure: Well Coordinates
Table: Rig
Selection
• Jack up rig is chosen.
• Platform 1 as mother platform, Platform 2
as an unmanned platform
• Water depth : 42.8 m = 140.2ft
• 6 deviated wells and 1 vertical well (7
wells)
• Well 4 and Well 7 functions as appraisal
wells
20

23. WELL TRAJECTORY
Figure : Spider Plot for the 7 production wells21

24. MUD WINDOW & CASING DEPTH
Type of Casing Depth (Ft-SS) Hole Size Casing Size
Conductor casing 0 - 360 Piled case 20"
Surface casing 360 - 2170 17.5" 13.375"
Production casing 2170 – Target Depth 12.25" 9.625"
Figure: Mud Window
22
Seabed – 229.92 ft
RT

25. CASING SELECTION, WELL SCHEMATICS &
CEMENTING
Type of casing OD (inch) Grade
Nominal
Weight (lb/ft)
Collapse
Pressure (psi)
Internal Yield
Pressure (psi)
Joint Strength
1000 lbs
ID
(inch)
Connection
Type
Conductor 20 API 5L X-56 154.0 2140 3680 2540 18.500 XLC-S
Surface 13 3/8 J-55 54.5 1130 2730 909 12.615 BTC
Production 9 5/8
VAM TOP
( 80 ksi )
40.0 3080 5750 916 8.75 VAM TOP
Casing Type
Total
Cement
Slurry
(cu.ft)
No of sacks
(sk)
Mix Water
Required
(gal)
Additive
(cu.ft)
Surface 25348.739 21301.462 110767.60 5069.74
Production 28541.731 24187.908 125777.12 5708.34
Total 53890.471 45489.370 236544.72 10778.09
Conductercasing
20''piled-360 ft
seabed
Seabed-229.92 ft RT
Surface casing 13
3/8' 360 ft-2170 ft
Productionsasing
9 5/8 - 2170ft -TD
17 1/2''Hole
17 1/2''Hole
TOCSurface &
Productioncasing
at seabed
Table : Casing selection and grade
Table : Well Cementing
Figure : Well Schematics
23

26. BIT SELECTION AND DRILLING FLUID
Interval Surface Production
Hole size (in) 17 1/2 12 ¼
Casing OD (in) 13 3/8 9 5/8
Bit diameter (in) 17 1/2 12 ¼
Depth in (m-RT) 70.1 732
Depth out (m-RT) 732 Target Depth
Roller cone bit & PDC bit
Depth,TVD-
SS (ft)
Mud Weight
(ppg)
Mud design
70.1 – 2170.0 8.7 Seawater Polymer Mud
2170.0 –
Target Depth
9.8 WBM - KCL/PHPA
Table: Bit Selection
Table: Drilling Fluid
• WBM is chosen,
• OBM and SBM are expensive and
mainly for HPHT wells
• Shale inhibitor is required :
Partially-hydrolyzed Polyacrylamide
(PHPA) + KCL
• Polycrystalline Diamond Compact bit
(PDC) can operate in medium hardness
formation and also hydratable
sediments; sand and shale.
• Economically wise, PDC can’t be used
throughout the drilling
• Roller cone bits will be used with PDC
as the alternative option when rock bit
faces high wear rate
24

27. DRILLING SCHEDULE
Year 2017
TaskName Startdate TimeTaken Jan Feb Mac April May June July Aug Sept Oct Nov Dec Jan
GelamaMerah
Platform1 24-Feb-16 5
Well4 1-Mar-16 40
Well1 11-Apr-16 40
Well2 21-May-16 40
Well3 1-Jul-16 10
Platform2 11-Jul-16 10
Well7 21-Jul-16 40
Well5 1-Sep-16 40
Well6 11-Oct-16 40
Demob 21-Nov-16 5
270
2016
Figure: Drilling Schedule
25

28. DRILLING PROBLEMS & TECHNOLOGY
Figure: Drilling Schedule
26
Drilling problems are identified from the offset well analysis. Here are the possible problem that may occur:
I. Pipe stucking
II. Shallow gas
III. Lost circulation
IV. Kick & Blowout
Drilling technology assists the team in overcoming possible drilling problems. Here are some technologies
which can be used for the drilling plan.
I. Drill Dog™ Electro-Magnetic Measurement While Drilling
II. Cement Assurance Tool (CAT)
III. Directional Casing While Drilling (DCwD)

29. Well Performance Analysis
Production Technology Plan
Sensitivity Analysis
Well Completion
27
PRODUCTION TECHNOLOGY

30.  PROSPER: Nodal Analysis
WELL PERFORMANCE
ANALYSIS
Figure: Node Locations Figure: PROSPER interface28

31. Figure : IPR at Reservoir Pressure 2116 psia
PI : 3.95STB/day/psi
AOF : 4724.8STB/Day
PRODUCTION TECHNOLOGY PLAN
IPR Curve
Well Performance Analysis
Reservoir pressure 2116 psia
Reservoir temperature 155 *F
Water cut 0 %
Fluid Oil and water
Method BLACK OIL
GOR 336 scf/stb
Oil gravity 27.3 API
Gas gravity 0.745 sg
Water salinity 30000 ppm
H2S 0 mole%
CO2 0.62 mole%
N2 0.57 mole %
29

32. PRODUCTION TECHNOLOGY PLAN
Figure: System analysis
Operating Point
Rate 1803 STB/d
Pressure 1560 psig
System Analysis
30

33. Figure: Tubing performance with different water cuts, and @ Pr = 2116psi.
OUTFLOW PERFORMANCE PREDICTION
W C 0 10 30 40
Tubing diameter
(in)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
2 1412 1295 930 663
2.75 1800 1596 1041 785
3.5 1881 1648 1015 n/a
4 1881 1622 n/a n/a
4.5 1874 1571 n/a n/a
 Sensitivity Analysis: Tubing variance vs water cut
31

34. Figure Tubing performance with water cut = 0, and @ Pr = 1500 psi.
Reservoir
pressure
(psia)
2116 2000 1800 1500
Tubing
diameter
(in)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
Oil
rate
(Stb/d)
2 1412 1172 758 n/a
2.75 1800 1440 827 n/a
3.5 1881 1471 n/a n/a
4 1881 1446 n/a n/a
4.5 1874 1343 n/a n/a
Figure: Performance @ Pr 1800 psia.
Tubing variance vs reservoir pressure depletion
SENSITIVITY ANALYSIS
32

35. Figure 7.10 Tubing performance with different WHP @WC=0%.
WHP (psia) 100 300 450
Tubing
diameter (in)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
2 2064 1485 841
2.75 2908 1931 909
3.5 3317 2036 811
SENSITIVITYANALYSIS: TUBING VARIANCE VS WHP
33

36. Functional Requirement Component
Optimize production Tubing Size ID 2.75”
Isolate producing zones Packer
Emergency containment subsurface controlled sub
safety valve (SCSSV)
Gas lift valve installation Side pocket mandrel (SPM)
Routine down-hole operation Xmas tree
Isolation devices that prevent
communication between the
tubing and the annulus.
Dummy valve
WELL COMPLETION MATRIX
Table : Completion String Components
Well Name Type
Perforated
interval, m
Remark
P1 Deviated 1502 - 1540 Producer
P3 Deviated 1505 - 1534 Producer
P5 Deviated 1499 - 1522 Producer
P6 Deviated 1468 - 1496 Producer
P8 Deviated 1503 - 1519 Producer
P9 Deviated 1496 - 1525 Producer
GLM Vertical 1521 - 1530 Producer
Table : Production Well & Perforation Interval
34

37. WELL COMPLETION MATRIX
Figure: Completion Schematic
Wellhead equipment that meets API Specification 6A
(equivalent to ISO 10423) is available in standard pressure
increments:
• 13.8 MPa (2000 psi)
• 20.7 MPa (3000 psi)
• 34.5 MPa (5000 psi)
• 69.0 MPa (10,000 psi)
• 103.5 MPa (15,000 psi)
• 138.0 MPa (20,000 psi)
• 207 MPa (30,000 psi)
35

38. Rod pump PCP
ESP Gas Lift
Artificial
Lift
• Low operating cost. Compression cost depends on the fuel
cost and compressor maintenance.
• Suitable for both conditions (gas coned well and water
coned well)
• Gas lift is believed to have a longer lifespan (10-20 years)
Gas Lift Method Justifications
ARTIFICIAL LIFT RECOMMENDATION
36

39. • Preference : Continuous Gas lift
• Reasons :
 High gas-oil ratio (GOR) produced fluid.
 High reservoir inflow productivity index.
 Use of side pocket mandrels allows easy wireline
replacements of gas lift valves.
 Sufficient producing gas to be used as injecting
gas.
ARTIFICIAL LIFT RECOMMENDATION
37

40. ARTIFICIAL LIFT DESIGN
 Maximum gas available, which is the
amount of gas present in the reservoir
 Maximum gas during uploading which
the gas each well can handle.
 Water cut which was set at 50 %
Figure: Gas lift design data selection.
38

41. Figure: Gas lift vales MD proposed by PROSPER
Type
GLV #1 GLV #2 GLV #1
IPO IPO Orifice
Size 1.5 1.5 -
Setting Depth, MD
P1 760 1233 1489
P3 765 1228 1495
P5 768 1231 1496
P6 750 1235 1490
P8 755 1222 1487
P9 760 1233 1499
Pilot Well, GLM 767.157 1230.43 1494
Gas lift must be installed above production packer
ARTIFICIAL LIFT DESIGN
39

42. PRODUCTION PLAN
ARTIFICIAL LIFT RECOMMENDATION
Figure Performance Curve Injection Gas Rate
Lift gas details
Injection Rate 3.35 MMscf/d
Inject. Pressure 1520 psig
Production Rate 1560 STBD
W C 0 10 30 40
Tubing
diameter
(in)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
Oil rate
(Stb/d)
2 1412 1295 930 663
2.75 1800 1596 1041 785
3.5 1881 1648 1015 n/a
4 1881 1622 n/a n/a
4.5 1874 1571 n/a n/a
40

43. Concept Design
Extraction Facility
Processing Facility
Exporting Facility
41
FACILITY ENGINEERING

44. Exporting
Processing
Extraction
Facility
*** Main design requirement:
Water depth
Environmental
conditions
Number of wells
Equipment
requirements
Life of the field
Frequency of
human
intervention on
the platform
Interfacing
requirements
 42.8 m
 not very harsh but with
alternating monsoon
period.
 7 deviated wells
 Integrated WHP-CPP-LQ in
single Jacket
 20 years.
 24/7
 subsea pipeline system
42

45. Location of wells and platforms Topside Structure Schematics
Subsea Structure SchematicsEquipment Arrangement plan
WHY Jacket?
 Support large deck loads
 Large field, long term
production
 Piles result in good stability
 Little effect from sea floor
scour
 Used for production up to
130m water depths
 Cheaper
43

46. Dry Tree Wet Tree
Advantages
 Tree and well control at surface
in close proximity of people
 Direct vertical access to wells for
future intervention activities
 Minimal offshore construction
 Enable future drilling and
expansion
- Tree and well access the
seabed isolated from people
- Full range of gull types can be
used
- Simplified riser/vessel
interfaces
- Preferable for deep water
installation
 Christmas Tree
Wellhead and Manifold
Conventional Approach Multiport Flow Selector (MPFS)
Complex piping arrangement / valves /
actuators and controls
 Simple piping arrangement with
minimum valves
Large number of leak points risking
production downtime
 Reduced leak points
Occupies more space and much higher
weight
 Compact system, reduced space and
weight
Prone to Human error  Reduced/ minimum human error
Expensive  Economical
 Manifold
44

47.  Separator
Reciprocating Compressor Centrifugal Compressor
- Low horsepower (< 2,000 hp)
- High-ratio applications
- Size up to 10,000 hp
- Higher fuel efficiency
- Much higher turndown
capabilities
 High horsepower (>4,000 hp)
 For low ratio (<2.5) in 1000 hp
 Cheaper
 Takes less space
 Less weightage
 Has higher availability
 Lower maintenance costs
 Compressor
 Gas Lifting Surface Facility
Horizontal Vertical Spherical
 Can handle much higher GOR
 Cheaper than the vertical
separator
 Easier and cheaper to ship and
assemble
 greater liquid capacity
 Reduces turbulence and reduces
foaming, thus it can handle
foaming crude
- Easier to clean
- Save space
- Provides better
surge control
- Liquid level control
is not critical
- Cheapest
- Better
clean-out
45

48.  Produced Water Treatment
 Gas and Oil Metering system
 Flaring and Venting System
Multiphase
flow meter
(MPFM)
Simple Design
Low maintenance cost
Reliability
Weight and space reduction ability
 Emergency Shutdown System
* ESD valves for flowline and pipeline should be located away
from facility.
46
* The Flaring system
contains of a flare boom
linked with pipes to
accumulate the gas to be
burnt.
 Drainage System
Open Drains –water from rain, seawater spray.
Closed Drains – collects water from process areas, where water is polluted
and hazardous

49. Power Generator Type Advantages
Gas Turbines
 Economic for continuous operation of
generators
 Tolerant to high ambient conditions and
elevations
 Low owning and operating costs
 Best fuel efficiency
 Low emission level
 No local fuel storage requirement
Diesel Generator
Renewable Energy
High voltage direct current
 Power Generation  Communication Links
 Seawater Systems
 Helifuel System
Link type Advantage
Microwave line
of sight
Low cost equipment, high
capacity, high reliability.
Troposcatter
 High capacity, high
reliability, no delay, no
recurring monthly
costs, distance 30-250
km.
Fresh water system - Vapour Vacuum Compression (VVC) distillation
Cooling system for generators, ventilation, and air conditioning
Washing facilities - the treatment for water from kitchen, showers and
toilets before being discharged to sea.
Bilge system is a pump system that is used to prevent from flooding of
machinery spaces and pump rooms.
Fixed fire fighting system: fire main and helideck foam systems
* Fuel filter
* Flow meter
* Hose reels with dispensing nozzles
* Electric bonding and spill containment foam based fire fighting system
 Sand Separation System
* The sand that separated from hydrocarbon fluids should
be removed and transported ashore for disposal.
47

50. Pipeline System: safe, high efficiency for oil transmission, wide transmission capacity, high
economic profit for long life field.
Petronas’s Samarang (1975) oil field with 6-
in. OD natural gas pipeline and 8-in. OD
crude oil pipeline.
Pipeline Flow Assurance:
Hydrate formation
Maintain system operating pressure lower
than hydrate formation threshold
Corrosion Protection System:
Internal Protection
External Protection Cathodic protection
DC current through metal
Corrosion inhibitors
Pigging debris
Location of GM and Samarang fields
48

51. 49
Revenue Over Cost PSC
Fiscal Terms
Economic Assumptions
Development Options
Economic Analysis
PROJECT ECONOMICS

52. REVENUE OVER COST PSC (1997)
• Encourage additional investment in
Malaysia’s small/marginal oil and
gas discoveries
• Allows contractors to accelerate
their cost recovery if they perform
within certain cost targets
• Allow contractor to own higher
share of profit when their
profitability is low
• Increase NOC’s share of profit when
the contractor’s profitability
improves
• Essentially a self-adjusting formula
of =
Cumulative Revenue
Cumulative Cost
50
Gross
Revenue
Profit Split
Contractor : NOC
(Depends on R/C)
Cost Ceiling
(Depends on R/C)
Government Cash
Flow
Petroleum Income Tax 38%
Royalty 10%
Petroleum Income Tax 38%
Cost
Ceiling
Contractor’s Profit
Contractor Cash
Flow
NOC Cash Flow
NOC Profit

53. FISCAL TERMS
Contractor’s
R/C Index
Cost
Ceiling
(%)
Profit Ratio (%)
Below THV
NOC : Contractor
Above THV
NOC : Contractor
0.0 < R/C <= 1.0 70 20 : 80 60 : 40
1.0 < R/C <= 1.4 60 30 : 70 70 : 30
1.4 < R/C <= 2.0 50 40 : 60 70 : 30
2.0 < R/C <= 2.5 30 50 : 50 70 : 30
2.5 < R/C <= 3.0 30 60 : 40 70 : 30
R/C > 3.0 30 70 : 30 90 : 10
Note: Oil THV (30 MMSTB) and Gas THV (750 BSCF)
Terms Details
Royalty 10%
Export Duty 10%
Petroleum Income Tax 38%
Contract Period:
Exploration
Development
Production
3 years
4 years
20 years
Research Cess 0.5% (Not inclusive in Cost Oil)
Cost Ceiling Sliding Scale (Up to 70%)
Profit Sharing R/C Index (Max 70%)
NOC Participation Min 15%
Supplementary Payment 70%
51
Table: Fiscal Terms
Table: R/C Index

54. ECONOMIC ASSUMPTIONS
Fiscal Terms Export Duty, Research Cess and NOC Participation was not taken into account.
Reference Year The year of evaluation is 2016.
First Oil The first oil to be produced from Gelama Merah is expected to be in 2020.
Production Period
A production period of 20 years is expected with a plateau of approximately 10642
stb/day for the first 10 years and then declining.
Decommissioning Year Decommissioning period will be after 20 years of production period in 2039.
Oil and Gas Price
The oil and gas price is assumed to be $60/bbl and $4/mscf respectively based on
previous oil crash trends.
OPEX
The base OPEX is obtained to be approximately $6.35 million/year but will increase
based on the requirement for gas lift and produced water treatment.
Compounding Factor An escalation of 2.5% per annum is assumed to account for the inflation rate.
Discount Rate
Assumed to be 10% WACC during the evaluation according to the opportunity cost
of capital, acquisition cost of capital and risk management.
52

55. DEVELOPMENT OPTIONS
Criteria Unit Option 1 Option 2 Option 3
Cumulative Oil MMSTB 49.08 54.03 56.45
Cumulative Gas TSCF 1.13 1.09 1.11
Cumulative Water MMSTB 20.21 5.28 4.52
CAPEX $MM 247.75 290.75 301.75
NPV @ 10% $MM 564.71 406.11 392.94
IRR % 47 28 28
Payout Period Years 2.19 3.74 3.79
PIR Ratio 6.02 5.31 4.79
Drilling Option
 Option 1: 7 Deviated wells
 Option 2: 5 Deviated and 2 horizontal wells
 Option 3: 4 Deviated and 3 horizontal wells
Facility Option
 Option 1: Tie-in pipeline to Samarang pipeline
 Option 2: Pipeline to LCOT
Criteria Unit Option 1 Option 2
CAPEX $MM 247.75 289.51
NPV @ 10% $MM 564.71 552.19
IRR % 47 41
Payout Period Years 2.19 2.48
PIR Ratio 6.02 5.05
53

56. ECONOMIC ANALYSIS
-250
-50
150
350
550
750
950
1150
1350
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039
CashFlow($MM)
Cash Flow Profile
Net Cash Flow Cumulative Cash Flow
Development AbandonmentProduction
Project
Starts 2016
Project
Ends 2039
1st Production
in 2020
Payout Period =
6.19 years
PIR =
$ 𝟏𝟑𝟐𝟔 𝐦𝐢𝐥𝐥𝐢𝐨𝐧
$ 𝟐𝟐𝟎 𝐦𝐢𝐥𝐥𝐢𝐨𝐧
= 6.02
Maximum Capital Outlay
= $ 220 million
Breakeven
Terminal Cash Plus
= $ 1326 million
Year
Net Cash Flow
($MM)
Cumulative
Cash Flow
($MM)
2016 -73.5 -73.5
2017 -82.24 -155.74
2018 -52.4 -208.14
2019 -12.28 -220.42
2020 120.703 -99.717
2021 78.9047 -20.812
2022 111.403 90.5909
2023 109.72 200.311
2024 85.6383 285.949
2025 53.0546 339.004
2026 122.462 461.466
2027 77.6566 539.123
2028 120.815 659.938
2029 165.752 825.689
2030 202.998 1028.69
2031 100.727 1129.41
2032 67.7283 1197.14
2033 46.5664 1243.71
2034 37.2602 1280.97
2035 33.5185 1314.49
2036 13.5407 1328.03
2037 11.2728 1339.3
2038 5.49916 1344.8
2039 -18.36 1326.44
54

57. ECONOMIC ANALYSIS
Discount Rate
(%)
Unit 0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100
NPV $MM 1326 852 565 382 260 176 115 70 35 8 -14 -32 -47 -60 -71 -81 -89 -97 -103 -109 -114
-200
0
200
400
600
800
1000
1200
1400
0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100
NPV($MM)
Discount Rate (%)
NPV vs Discount Rate
IRR = 47%
WACC = 10%
55

58. ECONOMIC ANALYSIS
250
350
450
550
650
750
850
-90% -75% -60% -45% -30% -15% 0 15% 30% 45% 60% 75% 90%
NPV@10%($MM)
Spider Plot
Oil Production Oil Price
CAPEX OPEX
Gas Production Gas Price
Tornado Plot
0% 100%-100%
Gas Price
Gas Production
Oil Price
Oil Production
CAPEX
OPEX
56
Parameter
NPV @ 10% ($MM)
-90% -75% -60% -45% -30% -15% 0 15% 30% 45% 60% 75% 90%
OPEX 579 577 575 573 571 568 565 562 560 557 556 553 551
CAPEX 618 609 606 605 592 580 565 549 532 514 495 476 457
Oil Production 297 354 413 468 513 546 565 583 621 641 677 681 713
Oil Price 295 342 390 434 478 522 565 607 649 687 727 767 806
Gas Production 280 343 401 457 511 521 565 568 604 642 628 661 694
Gas Price 274 323 374 418 466 515 565 614 664 712 761 809 858
Table: Sensitivity Parameters

59. HSE Development Plant
HSE Management System
Abandonment
57
HEALTH, SAFETY & ENVIRONMENT

60. Objectives:
 To minimize any negative impact that may occur
 To reach the highest possible level of safety
 To protect its employees, contractors,
customers and local surrounding
HEALTH, SAFETY AND ENVIRONMENT
58
 Safety precaution when
conducting exploration,
development and abandonment

61. Example of HSE plan
• PETRONAS Health,
Safety & Environment
Management System
(HSEMS)
• Comply to PETRONAS
Regulatory
• Any negligence or
deviation should be
justified.
HSE DEVELOPMENT PLAN
59

62. Before Exploration
• Secure the area
• Risk assessment
• Selection of contractor and
equipment
During Exploration
• Periodic inspection
• HSE Training Programme
• Cultivate awareness
• Practice emergency drill
Development
• Risk assessment
• Determine treatment
system
Production
• System selection to control
flow rate
• Pipeline inspection for
corrosion purpose
Abandonment
• Determine depth to plug the
well
• Inspection of any
contamination
• Recycle/dispose equipment
HSE DEVELOPMENT PLAN
60

63. 1
• HSE Policy and Strategy Objective
2
• Organization
3
• Arrangement
4
• Risk Management
5
• Planning and Procedure
6
• Implementation and Performance Monitoring
HSE MANAGEMENT SYSTEM
Figure : HSE Management System
61

64. ABANDONMENT
• Comply with minimum requirement for Plug and
Abandonment(P&A)
• Plug must be verified by the particular engineer that in charge
for particular well
• Well P&A programme and suspension should be submitted to
PETRONAS for approval
62
Perforate

65. THANK YOU
Question
&
Answer
63