1
BERLIAN EASTFIELD DEVELOPMENT PLAN
Prepared by G2:
Amira binti Abdul Rasib
Chiew Kwang Chian
Dexter Brian Anak Nyambang
Mohamad Azir Syazwan bin Sufri
Mohammed Ahmed Omer
Mohd Farid Bin Mohd Toha
Muhammad Syafiq Syahidzat Sabri
Thian Hui Chie
Supervisor: Dr Khaled Abdalla Elraies
2
RESERVOIR ENGINEERING
3
OUTLINE
Introduction Reservoir Data Depletion Strategy Proposed Number of Wells Production Profile Reservoir Management Plan (RMP) EOR Considerations
4
INTRODUCTION – PREVIOUS VOLUMETRIC ESTIMATION
SandSTOIIP (MMstb)
Low Case Base Case High Case
M 2/3 23.4 50.5 89.8
M 7/8 52.4 62.1 73.4
M 9/14 33.9 41.9 58.0
M 15 3.8 5.0 6.4
TOTAL 113.5 159.5 227.6
SandGIIP ( Bscf)
Low Case Base Case High Case
L 16.6 22.9 30.9
M 2/3 2.8 3.2 3.7
TOTAL 19.4 26.1 34.6
5
PVT DATA & INFORMATION PVT data of bottomhole sample from BE-1, M2A sand
Pi >>
Pb >>
• Datum = 1300 m ss• Initial Pressure (Pi) @ datum = 1854 psig• Reservoir Temperature @ datum = 215 °F• Bubble Point Pressure (Pb) = 1332 psig
6
GOR & RS
Rsi = 1400 scf/stb
Pb = 1332 psig
Source: Reservoir Engineering Handbook by T.Ahmed (2001)
7
PVT DATA & INFORMATION Hydrocarbon Analysis on surface fluids:
8
DEPLETION STRATEGY
2 depletion strategies are proposed: Natural depletion drive Water injection depletion drive
Natural Depletion Drive: Recovery factor ≈ 20% of STOIIP Initial production rate = 2000 – 3000 stb/d (from
production test results) Production rates decline (exponentially) @ 38% per year Each well is expected to produce ≈ 3 MMstb Well lifetime ≈ 10 years Abandonment rate = 150 stb/d of gross liquid Water cut < 6% throughout production life
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DEPLETION STRATEGY
Water Injection Depletion Drive: Natural aquifer does not contribute much Water is injected to support reservoir pressure (not to
flood or displace oil) Recovery factor ≈ 35% of STOIIP Initial production rate = 3000 – 4000 stb/d (from
production test results) Production rates remain constant (plateau) until 40% of
EUR had been produced, then decline @ 40% per year Each well is expected to produce ≈ 5 MMstb Well lifetime ≈ 10 years GOR = Rs throughout production life since Pres > Pb
Maximum injection rate = 4000 stb/d Voidage replacement ratio, VRR = 1.44
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PROPOSED NUMBER OF WELLS & LOCATIONS – NATURAL DEPLETION
UnitSTOIIP
(MMstb)EUR (20%)
No. of Wells*
Dual Completion
M2/3 50.52 10.10 31
M7/8 62.09 12.42 4
M9/14 41.86 8.37 21
M15 4.98 1.00 0
Total 159.46 31.89 9 2
TOTAL WELLS 11
* Each well will produce ≈ 3 MMstb of oil throughout production life
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PROPOSED NUMBER OF WELLS & LOCATIONS – NATURAL DEPLETION
11 producers
12
PROPOSED NUMBER OF WELLS & LOCATIONS – WATER INJECTION DEPLETION
UnitSTOIIP
(MMstb)EUR (35%)
No. of Wells*
Dual Completio
n
No. of Injectors**
M2/3 50.52 17.68 31
14
M7/8 62.09 21.73 4
M9/14 41.86 14.65 31
M15 4.98 1.74 0
Total 159.46 55.81 10 2
TOTAL WELLS 12 14
* Each well will produce ≈ 5 MMstb of oil throughout production life
** VRR =1.44 rb/stb; Highest production rate = 39 Mstb/day; Max injection rate = 4000 stb/d
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PROPOSED NUMBER OF WELLS & LOCATIONS – WATER INJECTION DEPLETION
Injectors12 producers, 14 injectors
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PRODUCTION PROFILE (MONTHLY) – NATURAL DEPLETION
1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 1011050.00
5.00
10.00
15.00
20.00
25.00
30.00
35.00
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
Rate (Mstb/d) Cumulative Production
Month
Prod
uctio
n Ra
te (M
stb/
day)
Cum
ulati
ve P
rodu
ction
(MM
stb)
Rate decreases due to S/D of wells which flows below abandonment rate
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PRODUCTION PROFILE (YEARLY) – NATURAL DEPLETION
1 2 3 4 5 6 7 8 90.00
5.00
10.00
15.00
20.00
25.00
30.00
35.00
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
Rate (Mstb/d) Cumulative Production
Year
Prod
uctio
n Ra
te (M
stb/
day)
Cum
ulati
ve P
rodu
ction
(MM
stb)
16
PRODUCTION PROFILE (MONTHLY) – WATER INJECTION DEPLETION
1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 1011050.00
10.00
20.00
30.00
40.00
50.00
60.00
0.0
10.0
20.0
30.0
40.0
50.0
60.0
Rate (Mstb/d) Cumulative Production
Month
Prod
uctio
n Ra
te (M
stb/
day)
Cum
ulati
ve P
rodu
ction
(MM
stb)
Plateau ends after 40% EUR is produced
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PRODUCTION PROFILE (YEARLY) – WATER INJECTION DEPLETION
1 2 3 4 5 6 7 8 90.00
10.00
20.00
30.00
40.00
50.00
60.00
0.00
10.00
20.00
30.00
40.00
50.00
60.00
Rate (Mstb/d) Cumulative Production
Year
Prod
uctio
n Ra
te (M
stb/
day)
Cum
ulati
ve P
rodu
ction
(MM
stb)
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COMPARISON OF PRODUCTION RATE DECLINATION
1 2 3 4 5 6 7 8 90.00
5.00
10.00
15.00
20.00
25.00
30.00
35.00
40.00
45.00
Natural Depletion Water Injection
Year
Prod
uctio
n Ra
te (M
stb/
day)
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COMPARISON OF CUMULATIVE PRODUCTION
0 1 2 3 4 5 6 7 8 9 100
10
20
30
40
50
60
Natural Depletion Water Injection
Year
Cum
ulati
ve P
rodu
ction
(MM
stb)
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RESERVOIR MANAGEMENT PLAN Objectives:
Maximize recoverable oil Maintain reservoir pressure above bubble point (1800 psia) Abide by PETRONAS Procedures and Guidelines for Upstream
Activities (PPGUA)
Operation Strategies: Water Injection to keep P > Pb
VRR = 1.44 and maximum injection rate per well = 4 Mstb/d Gas lift in third year to maintain well rate
Surveillance & Monitoring: Monitor water cut & GOR Utilize S/I for well tests (e.g. interference test, pulse test)
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ENHANCED OIL RECOVERY (EOR) CONSIDERATIONS
EORTherm
alGas
Chemical
Others
EOR Considerations
Thermal Very costly, suitable for field with oil of high viscosity and low API gravity
Chemical Costly and dependent on many factors: current oil price, water hardness, salinity, temperature etc.
Gas Most suitable compared to other EOR methods. Can consider gas re-injection.
Other Microbial & electromagnetic – new technique, less confidence
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DRILLING
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OUTLINE
Rig selection Casing design Bit selection Drilling Fluid design Cementing design
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RIG SELECTION
• Cost• Rig stability• Water depth offshore
Sea level for Berlian East field = 249.28ft (76m)
Drilling Rigs Water Depth (ft) Average Day Rate (USD)
Jacket Rig 40 – 400 ft $ 40,000
Tender Assisted Rig Anchor length $ 130,000
Jack Up Rig < 350 ft $ 140,000
Semi Submersible Rig 150 – 6000 ft $ 414,000
Drill Ship/ Submersible Rig 1000 – 13000 ft $ 450,000
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Jack-up Rig• Suitable for shallow depth water • Stable work platform• Lower mobilization cost• Safer and lower risk
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CASING DESIGN
Casing Casing OD (in) Depth (m-TVDSS)
Conductor 26 “ 80
Surface 13 3/8 “ 400
Intermediate 9 5/8 “ 850
Production 7 “ 1330
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CASING SETTING DEPTH
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BIT SELECTION
Casing Casing Size OD (in)
Type of Bit Bit Size (in)
Conductor 26 Rock Bit 30
Surface 13 3/8 Rock Bit 17 ½
Intermediate 9 5/8 PDC Bit 12 ½
Production 7 PDC Bit 8 ½
•PDC bit has most efficient cutting mechanism in sedimentary rock such as sandstone and shale•PDC also have high rate of penetration and long bit life span.
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DRILLING FLUID DESIGN
Depth, m-TVDSS Mud Design
0-200 Guar Gum Spud Mud
200-1330 High Performance Water Based Mud (HPWBM) + KCL/PHPA additive
• HPWBM performance comparable with Synthetic Based Mud.• Offer environment compliance.• Has been successfully tested on offshore (shallow and depth water). • Cost effective compared to Oil Based Mud.
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CEMENT DESIGN
Class “G” cement type Additives:
Retarder Fluid loss Dispersant
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COMPLETION
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OUTLINE
Preliminary Studies and Well Test Well Locations Completion Matrix Well Completion Options Proposed Well Completion Proposed Perforation Design Proposed Sand Control Design Completion Design Diagram Completion Problem
PRELIMINARY STUDIES AND WELL TEST Field should be developed by initially targeting;
M formation > L formation Sand production were traced in 6-well High permeability; 118-900md Geologically younger Tertiary sedimentary
formations; little cementation material between sand grains
WELL LOCATIONS
12 producers, 14 injectors
COMPLETION MATRIX
UnitSTOIIP (MMst
b)
OIL PRODUCER WELL
W1 W2 W3 W4 W5 W6 W7 W8 W9 W10
W11
W12
M2/3 50.52
M7/8 62.09M9/1
4 41.86
M15 4.98
WELL COMPLETION OPTIONS
COMPLETION PARAMETERS OPTIONS
Tubing size Range from 2-3/8” to 4-1/2”
Type of completion Single or Dual String
Tubing material Carbon steel, Low Alloy Steel or Corrosion Resistance Alloy (CRA)
Perforation Tubing Conveyed Perforating/ Wireline Conveyed Perforating
Artificial Lift ESP or Gas Lift
Sand Control Sand Screen or Gravel Pack
WELL COMPLETION SELECTION COMPLETION PARAMETERS SELECTION COMMENT
Well Orientation Vertical Low risk
Tubing size 2-7/8”, 6.5 PPF, J-55
Based on Nodal Analysis, Shallow Depth
Tubing materialCorrosion Resistance Alloy (CRA)
Due to high carbon dioxide, CO2
Perforation TCP 200psi overbalance (6 shots/foot, 60⁰ degree)
Sand Control Sand Screen Sand production traced
Artificial Lift Gas LiftDepending on production requirements at designated depth
Type of completion
Single and Dual String
For well more than 2 drainage points, used dual strings
PERFORATION DESIGN
Parameters Selection Justification
Perforation Density (spf) 6
Low flow rate of single perforation, low fluid velocity, low sand
Phase 60 provide more efficient flow characteristics
Charge Type DPProvide mechanical stability
Penetration Depth 10-30ft
Perforation Diameter
8-10 times size of the particle Best effectiveness
Completion FluidNitrogen and Clear Solid Brine
Cheap, avoid contaminants precipitation and crystallizationDensity: 7.5 – 10ppg
SAND CONTROL DESIGN CRITERIA
Gravel Packing
Parameters Criteria
Size US Mesh 12/20 – 40/70 (5 times mean diameter of formation sand)
Sphericity ≥0.6
Roundness ≥0.6
Class Natural or Manmade
Screen
Gravel Size (US Mesh) Gravel Size (in.) Screen Gauge (in.)
12/20 0.0660-0.0330 0.020
16/30 0.0470-0.0230 0.016
20/40 0.0330-0.0165 0.012
40/60 0.0165-0.0098 0.008
COMPLETION SCHEMATIC DIAGRAM(SINGLE STRING)
Wellhead1. Assemble 1
1. 2-7/8” Flow Coupling2. 2-7/8” TR-SCSSSV3. 2-7/8” Flow Coupling
2. 2-7/8” GLM (Dummy Valve)3. 2-7/8” CIV Mandrel4. 2-7/8” PDG Mandrel5. 2-7/8” Sliding Sleeve6. 2-7/8” XN Nipple7. Single Swell Packer8. EOT
1
2
34
567
8
COMPLETION SCHEMATIC DIAGRAM(DUAL STRING)
Wellhead1. Assemble 1
1. 2-7/8” Flow Coupling2. 2-7/8” TR-SCSSSV3. 2-7/8” Flow Coupling
2. XN-Nipple3. 2-7/8” GLM (Dummy Valve)4. Assemble 2
1. Flow Coupling2. XD-SSD3. Flow Coupling
5. Dual Swell Packer6. Assemble 37. Single Swell Packer8. XN Nipple9. EOT
12
3
45
6
78
9
COMPLETION SCHEMATIC DIAGRAM(INJECTION WELL)
Wellhead1. Assemble 1
1. 2-7/8” Flow Coupling2. 2-7/8” TR-SCSSSV3. 2-7/8” Flow Coupling
2. X-Nipple3. XD-SSD4. Single HYD Packer5. X-Nipple6. EOT
1
2
34
5
6
COMPLETION PROBLEMSPRODUCTION
PROBLEM EFFECT MITIGATION PLAN
Wax deposition • Flow assurance issue• Surface/downhole
equipment blockage
• Thermodynamic or chemical injection approach
• Maintenance pigging operation
Scale formation • Wellbore and flowline blockage
• Reduction in production rate
• Fluid filtration • Scale inhibitor• Acid treatment
Emulsion formation
• Cause formation damage• Well productivity decrease
• Use surfactant; reduce surface and IFT of fluids
High CO2 content
• Facilities corrosion (valve, pipeline)
• Use corrosion inhibitor, CRA
Sand Production • Erosion at surface and downhole equipment
• Collapse of the formation
• Sand screening, minimum entry hole diameter, high shot density
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FACILITIES
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OUTLINE
Design Philosophy Proposed Philosophy Proposed Development Plan Screening Process Development Plan Selection
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INTRODUCTION
Provide information on the surface facilities
based on the subsurface production in order to
develop Berlian East Field
Design basis
Environment
Sea Floor Site
Production
Processes
Flexibility
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26 wells [12 producers and 14 water injectors]
tie-in with 2 mother platforms (2 SWP for each mother platform)
Full well stream the crude oil to Berlian complex via pipelines
DESIGN PHILOSOPHY
49
Unmanned facilities
Minimum maintenance
Meet simultaneous production and drilling
operations and workover requirements.
Remote well testing on monthly basis.
Maximise remote monitoring and control
capability from supply terminal at pekan.
Over 9 years of operating life and 30 years of
design life.
PROPOSED PHILOSOPHY
50
PROPOSED DEVELOPMENT PLAN
Option A – Satellite Wellhead Platform:
A1) Satellite wellhead platform, tie-in to
mother platform and full well stream
pipeline to Berlian complex.
A2) Connecting the Satellite Wellhead
platform to a FPSO.
A3) Connecting the Satellite Wellhead
platform to a MOPU.
51
Option B – Subsea Wellhead Platform:
B1) Subsea wellhead platform, tie-in to
mother platform with full well stream
pipeline to Berlian Complex.
B2) Connecting the Subsea wellhead
platform to a FPSO
B3) Connecting the Subsea wellhead
platform to a MOPU
52
Option C – Central Processing Platform:
C1) Central processing platform and tie-in
with Berlian export oil pipeline to
Pekan Crude Oil Terminal
C2) Central processing platform and
pipeline to Pekan Crude Oil Terminal.
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SCREENING PROCESS
FPSO eliminated;
High cost – rental
Major modification
Bad weather condition
Subsea Wellhead Platform eliminated;
Only for deepwater operation
High cost
54
CPP eliminated;
High cost – start-up, operating &
abandonment
Require manpower
Complexity operation
MOPU
Bad weather – same as FPSO
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DEVELOPMENT PLAN SELECTION
We opted the Satellite wellhead platform, tie-
in to mother platform and full well stream
pipeline to Berlian complex (Option A1)
Reason;
Low CAPEX and OPEX
Unmanned operation
Existing facilities utilized
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Substructure 6 pile-steel Riser (seabed to platform) Boat landing bay Pipeline
Top structure Crane Helipad Well servicing equipment Main production facilities;
Wellhead Three-phase separator Gas injector Electrical / lighting Flare boom
Safety equipment
57
Schematic diagram of Berlian East conceptual facility design
58Schematic diagram for each well location in Berlian East field
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ECONOMICS
60
FISCAL TERM FOR PSC 1997
Terms Details
Contract area EPCP Block
Contract duration Max 22 years
Production period 15 years
Royalty rate 10%
Cost oil ceiling rate Oil Gas
50%60%
Profit oil share (PETRONAS: Contractor) 60:40
PSC base price US$40/bbl escalated 3% p.a. from current year
Export duty (ED) rate 10% of profit oil exported
Research cess 0.5% oil/gas entitlement
Abandonment cess 5 USD Mill
Petroleum tax rate 38%
Oil supplemental payment 60% (PSC oil price – base price) cont. PO – export duty
Fixed structure 10% per year (10 years)
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Base case
Reference year
First oil Expected to be in 2016
Production period 10 years
Decommissioning year
Exactly after 10 years of production period (2013)
Cash flow model Assumed to be in the Money of the Day (MOD) term
Base oil price US$40/bbl escalated 3% p.a. from current year
Operating cost (OPEX) 4% of cum. CAPEX per annum (fixed OPEX) plus US$3.50/bbl (variable OPEX)
Hurdle rate for IRR 15%
Discount rate 15%
ECONOMIC ASSUMPTIONS
62
Production facilities Option A1: Satellite wellhead platform, tie –in to mother platform and full stream pipeline to Berlian complex
Production case • 11 producer wells•14 injector wells• RF of 20% = 5 MMSTB
NPV @ 15%
IRR 25%
CAPEX USD 393 Million
OPEX USD 303 Million
Decommisioning USD 119 Million
Payback period 2 years
Economic life 10 years
DEVELOPMENT OPTION
63
1 2 3 4 5 6 7 8 9 10 11 12 13
-200
-100
0
100
200
300
400
Net Cash Flow Diagram
Year
USD
Mill.
64 Payback period = 2.3 years after first oil @ year 5
1 2 3 4 5 6 7 8 9 10 11 12 13
-400
-300
-200
-100
0
100
200
Cum Net Cash Flow Diagram
Year
USD
Mill.
65
REVENUE SPILT
Summary of Economic Indicators
Contrac.Petronas Govern. Capex Opex Total Project
PV Cash Surplus @ 15% 89 329 611 277 139 1445 379
Internal Rate of Return (IRR) 25% 46.8%
Payout Time 2 Years
USD Mill.
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SENSITIVITY ANALYSIS
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HSE & WELL ABANDONMENT
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HEALTH, SAFETY AND ENVIRONMENT
Objective: The design of the Berlian East facilities shall be
in accordance with the relevant PETRONAS Technical Standards (PTS).
to ensure that the facilities are operated in a safe and responsible manner.
Identified, evaluate and control all potential hazards that could cause a major accident
69
HSE MANAGEMENT SYSTEM (HSE-MS)
70
APPROACHES:
Safety & Risk Management Occupational Health Management Quality Management Environmental Impact Assessment
71
WELL ABANDONMENT
To isolate the reserves remaining in the reservoir
No fluid movement
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ABANDONMENT DESIGN
1. Isolate perforation intervals
2. Isolate tubing & casing annulus
3. Isolate non-cemented annulus
4. Cut and pull the casing5. Plug surface cement
Well abandonment planning is considered during well construction planning.
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CONCLUSION
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CONCLUSION Reservoir Drilling
12 producer wells 14 injection wells
Completion• Internal gravel pack with wire wrapped screen
(WWS)• Tubing: 2-7/8”, 6.5 PPF, J-55 (CRA)
Facilities• 4 satellite wellhead, 2 mother platforms• Tie-in to Berlian CPP
75
Economics• Payback period=??
o HSE & Well Abandonment• Personnel, equipment & facilities comply to HSE
policy
76
THANK YOU
77
BACK UP
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DATA AVAILABLE – FORMATION WATER Sample taken from BE-3, M2/3 sand
Appearance – Light blackish Total dissolved solids – 30.13 g/L Specific gravity @ 750 °F – 1.023 pH @ 22 °C – 8.14
Formation Water Analysis:
79
DATA AVAILABLE – WELL TEST RESULTS
80
DATA AVAILABLE – WELL TEST RESULTS
81
SUMMARY OF RESERVOIR FLUID
Sampling datum = 1300 m ss Reservoir Pressure @ datum = 1854 psig Reservoir Temperature @ datum = 215 °F Bubble Point Pressure, Pb = 1332 psig
Oil FVF, Bo = 1.4372 rb/stb
Initial Solution Gas Ratio, Rsi = 1400 scf/stb
82
PROPOSED WELL LOCATIONS – NATURAL DEPLETION
83
PROPOSED WELL LOCATIONS – NATURAL DEPLETION
84
PROPOSED WELL LOCATIONS – NATURAL DEPLETION
85
PROPOSED WELL LOCATIONS – NATURAL DEPLETION
86
PROPOSED WELL LOCATIONS – WATER INJECTION DEPLETION
Injectors
87
PROPOSED WELL LOCATIONS – WATER INJECTION DEPLETION
Injectors
88
PROPOSED WELL LOCATIONS – WATER INJECTION DEPLETION
Injectors
89
PROPOSED WELL LOCATIONS – WATER INJECTION DEPLETION
Injectors
90
SAFETY AND RISK MANAGEMENT
All personnel shall show leadership and commitment towards the HSE requirements.
HSE Hold Points shall be held to ensure that all the HSE activities requirements stipulated in the PETRONAS HSE-MS shall be carried out.
All identified concerned risk on the chemicals should be listed in the Material Safety Data Sheet (MSDS) and operational safety in the Hazards Effect Register (HER) .
91
OCCUPATIONAL HEALTH MANAGEMENT
Guidelines and procedures shall be establish and implemented: Job Safety Analysis (JSA), Permit to Work (PTW), Material Safety Data Sheet (MSDS) for
consumables. Hazards Effect Registers (HER) where operation
involves heavy machineries. Offshore Safety Passport system for all
personnel - to ensure the fitness of the personnel working offshore
92
QUALITY MANAGEMENT
Objective: Provide assurance and maintain control in
ensuring that all services and products resulting from its activities are in accordance with the specified requirements.
Demonstrate that any non-compliance has been appropriately endorsed, documented and resolved/close-out.
Ensure that records and hand-over documentation are properly planned, compiled and completed during work.
93
ENVIRONMENTAL MANAGEMENT
Environment Impact Assessment (EIA) Approval seeking from Department of
Environment prior to project start. comprise three major steps; Preliminary
Assessment, Detailed Assessment and EIA Review.
be prepared in parallel with detail technical studies of the overall project feasibility in order to review options and to eliminate or refine alternatives regarding to environment effects.
Waste Management pollution and waste management during
installing, hook up and commissioning, drilling and production activities.
94
POTENTIAL DRILLING PROBLEM
Mechanical Pipe Sticking Loss of Circulation Hole Deviation Hydrogen Sulfide- Bearing Zones and Shallow
Gas