Field Development Plan

2. Vision&Mission
Vision: To be a worldwide leader in exploration and production using the
industry’s best people and technologies in a safe and environmentally
responsible manner.
Mission: To enhance and optimize production rate, and maximize the
company’s value.
2

3. Objectives
3
The aim of this Field Development Plan is to maximize the economic
recovery of oil and gas resources of Sirri-A
The objectives of FDP 2 are:
• To develop a reservoir dynamic model
• To technically evaluate the selected field
• To propose development strategies (drilling and production strategies)
• To do the Design facilities
• To determine cash flows.

4. 4
OrganizationChart
Project Manager
and Reservoir Eng
Mahmood
Geologist &
Geophysics
Aseel
Drilling Eng & Well
Completion
Waseem
Production Eng
Hani
Economics, HSE &
Sustainable
Development
Raeef

5. Sirri-A(Alvand)FieldLocation
Persian Gulf, Sirri island (IRAN)
Sirri island
5

6. 6
3/7/2019 3/27/2019 4/16/2019 5/6/2019 5/26/2019 6/15/2019
Objective
Vision & Mission
Geological AND Geophysical part
Reservoir section
Drilling and well completion section
Production
Economics
HSE & sustainable development
Presentation of the project
Gantt Chart of the project
GanttChartoftheproject

7. 7
FieldDevelopmentPlanstages

8. ASEEL

9. Objectives
• To construct the top structure map, cross-sectional area, net to gross
(N/G), porosity, and oil saturation map.
• To determine the producible layer, lithostratigraphy correlation, porosity,
water saturation, and types of hydrocarbon from logging data.
• To calculate the stock tank oil initial in place (STOIIP) of the producible
layer.
9

10. AvailableData
Well Logging:
• Electrical logs
• Density logs
• Neutron logs
• Sonic logs
• Gamma-ray logs
Pressure, Volume, Temperature (PVT) data:
• Initial pressure= 3488 psi
• Temperature = 197 oF
• Oil gravity = 35 API°
• Bo = 1.264 bbl/stb
• Rs = 373 scf/stb
• Pb = 1358 psia
• Ct = 3 ×10-6 psi-1
10

11. ReservoirDescription
• Alvand oil field (Sirri-A) is located in the Persian Gulf in the Iranian sector.
• Exploration for oil was starting in 1968.
• The field is part of a series of Cretaceous Strata Basins.
• Alvand field is Sedimentary environment.
• Limestone formation.
• Undersaturated and homogeneous reservoir.
11

12. RegionalGeology
• Alvand oil field (Sirri-A) is located in the
Persian Gulf Basin, is found between
the Eurasian and the Arabian Plates.
The Persian Gulf is described as a
shallow marginal sea of the Indian
Ocean that is located between the
southwestern side of Iran and the
Arabian Peninsula
12

13. Ageofformation
Oil field
Sirri-A Limestone
Cretaceous Oil reservoir rock
13

14. Depositionenvironment
14
Marine
sediment

15. ContouringMap
Top depth (3900 ft)
Bottom depth (4900 ft)
Surface map:
Length (Km)
Width
(Km)
15

16. InterpretationOfWellLogs
16
Well 1 Well 2 Well 3

17. InterpretationOfWellLogs
17
Oil zone
h=525 ft
Limestone

18. Layer-A(Porosity)
Length (Km)
Width
(Km)
Top Map
18
N
Length (Km)
Width
(Km)
N
Bottom Map

19. Layer-A(N/GMaps)
Length (Km)
Width
(Km)
19
N
Length (Km)
Width
(Km)
Top Map
Bottom Map
N

20. Layer-A(OilSaturationMap)
20
Length (Km)
Width
(Km)
N
Length (Km)
Width
(Km)
N
Top Map Bottom Map

21. FluidContact
21
Length (Km)
depth
(ft
)
depth
(ft
)

22. VolumetricBulkVolume
Total Bulk Volume = 217.5 MMM ft3
22
Length (Km)
Width
(Km)
N

23. Summaryof results
Average Porosity (Ф) 10.5%
Bulk Volume (Vb) 217.5 MMM ft3
Total STOIIP 1.78 MMM STB
23
Data Values

24. MAHM
OOD

25. Objectives
• To obtain the PVT data
• To find the Liquid Contact
• To find the drive mechanism of the reservoir
• To develop a reservoir dynamic model
• Predict the performance of the reservoir in future
25

26. Staticmodel
26
Top Depth (ft)
Bottom Depth (ft)

27. LiquidContact
27
Oil
Gradient
Water
Gradient
Contac
t
Log
response
Pressure vs
depth
TVD(ft) TVD(ft)
OWC 4525 ft 4530

28. Relativepermeability
28

29. PVTdata
29
PVT Data Values
Temperature 197℉
Pressure 3488 psi
Pb 1358 psi
GOR 373 scf/stb
Oil PVT Data Values
Bo 1.264 RB/STB
𝜇o 1.109 cp
API 35API°
Water PVT Data Values
Bw 1.0244 RB/STB
𝜇w 0.393 cp
𝜌w 65.13 ib/ft
Water compressibility 3*10^-6 1/psi

30. 30
WellTestAnalysis
Build-up test
Bourdet Et al, Curve
HORNER plots (Skin factor)

31. 31
Properties Values
K.h, md.ft 4310
Absolute Permeability, mD (oil zone) 8.2
Skin 3.2
Initial pressure, psi 3475
WellTestAnalysis

32. DriveMechanism
Water Drive Index
We = Np +(Bt+(Rp -Rsi )Bg) - N ((Bg -Bo)+ mBti (Bg / Bgi-1) +Bti (1 +
m)(
𝑆𝑤𝑖𝐶𝑤+𝐶𝑡
1−𝑆𝑤𝑖
)ΔP)+WpBwp
We=76.9mmbbl m=
𝐺𝐵𝐺𝑖
𝑁𝐵𝑜𝑖
= 0
A=Np(Bt+(Rp – Rsi)Bg) = 95mm
WDI=(We-WpBw)/A
WDI=0.804
32

33. DriveMechanism
DDI=N(Bt-Bti)/A
DDI=0.12
EDI =1-SDI-DDI-WDI
EDI=0.076
Depletion drive Index Expansion Drive Index
33
Drive Mechanism Values
WDI 0.804
DDI 0.12
EDI 0.076
Water Drive Index
WDI=(We-WpBw)/A
WDI=0.804

34. DriveMechanism
 Water drive
 Depletion drive Index
 Expansion Drive Index
34

35. 35
ReserveEstimation
One of the most highly appreciable applications of the risk assessment
is the estimation of volumetric reserves of hydrocarbon reservoirs
(Monte Carlo).
Estimation Values
Proved 600 million
Probable 1050 million
Possible 187 million

36. 36

37. STOIIP
37
Volumetric = 1.78 billion bbl
Oil in place by simulation = 1.72 billion bbl
Difference = 3.37%

38. 38

39. 39
Scenarios No of Wells
Base Case 3
Base Case with Perforations 3
First Scenario 30
Second Scenario 20
Secondary Recovery 36
Tertiary Recovery 34
SimulationProcess

40. 40
BasecaseoftheDynamicModel

41. 41
Basecaseresult
Oil recovery factor 2.25 %
Water cut 0

42. 42
BasecasewithPerforations

43. 43
Basecaseresult
Oil recovery factor 8.5%
Water cut 0

44. 44
FirstScenario

45. 45
FirstScenarioResults
Oil recovery factor % 28.52
Oil production rat bbl/day 11932.3
Water cut % 23.47

46. 46
SecondScenario

47. 47
Oil recovery factor % 26.4
Oil production rat bbl/day 12142.6
Water cut % 22.3
ResultsfortheSecondScenario

48. 48
CreamingCurve
0
5
10
15
20
25
30
0 5 10 15 20 25 30
RF
Wells Drilled
Creaming Curve
FORECAST TREND

49. 49
WaterInjectionCase

50. 50
OilSaturationMaps

51. 51
Oil recovery factor 44.1%
Oil production rat 58204.9bbl/day
Water cut 86.9%
ResultsfortheWaterInj

52. FutureWork
The future work will be specified by using the screening criteria
Time of EOR
52

53. 53
Immiscible injection
 Water Flooding
 Gas Injection
• CO2
• N2/Air
 WAG
Most EOR screening values are approximations based on successful north
American project.
EORSelection

54. 54
WAGInjection

55. 55
OilSaturationmaps

56. 56
Oil recovery factor 52.3%
Oil production rat 60849.1 bbl/day
Water cut 92.1%
ResultsforWAGInj

57. 57
SummaryresultsofallCases
Oil Recovery factor (Base C) 8.5%
Oil Recovery factor (S) 26.4%
Oil recovery factor (W inj) 44.1%
Oil recovery factor (WAG) 52.3%

58. Waseem

59. • To Select Drilling Rig
• To Design Well Trajectory
• To Design Casing
• To Design Drilling Fluid Program
• To Formulate Cement Job
• To Design Well Completion
• To Organize the Drilling Schedule
• To Estimate the Cost of Drilling and Well Completion
Objectives

60. Why Jack-up rig
Selectionofdrillingrig

61. WellCoordinateForPrimaryScenario

62. WellCoordinateForSecondaryscenario

63. WellCoordinateForTertiaryscenario

64. 64
Vertical Well Trajectory for Primary Scenario

65. 65

66. 66

67. 67

68. VerticalWellTrajectoryDesign
68

69. 69
Deviated Well Trajectory for Primary Scenario

70. DirectionalwellA1trajectory
70

71. DirectionalwellA3trajectory
71

72. DirectionalwellA9trajectory
72

73. Directionalwell`B1trajectory
73

74. Directionalwell`B3trajectory
74

75. Directionalwell`B5trajectory
75

76. Directionalwell`B7trajectory
76

77. Directionalwell`B9trajectory
77

78. 78
Vertical Well Trajectory for Secondary Scenario

79. 79

80. 80

81. 81

82. 82

83. 83
Vertical Well Trajectory for Tertiary Scenario

84. 84

85. CasingDesign
85

86. 86
Casing types Depth Mud
density
Casing Size Drilling Bit
size
Conductor Casing 300
ft
10 ppg 24
inch 26
Surface Casing 1200
ft
10 ppg 16 inch 20 inch
Intermediate
Casing
2850
ft
16 ppg 10 ¾ inch 14 ¾ inch
Production
Casing
3500
ft
12 ppg 7 inch 8 ¾ inch
BitSizeSelection

87. Table: Casing Size and Grade
Table: Cement Job Design
Casingselection,Wellschematics&Cementing
87

88. CCI equal to 0.5 or less, the hole cleaning is poor.
CCI grater than 0.5, the hole cleaning is good.
DrillingFluidProgram
Table (1) Table (2)
88

89. DrillingBitSelection
Roller cutter TCI PDC
89

90. 90
ChristmasTreeSelection

91. WellCompletion
91
7500ft

92. Drillingschedule
92

93. Drillingschedule
93

94. Total Cost for Drilling Wells = 97,590,860 $
CostOfDrillingWells

95. 95
Drilling Bit Cost
Mud Cost
Vertical & Deviated Casing Cost
DrillingBitCost,MudCost&CasingCost

96. HANI

97. • To optimize the production rate
• To effectively utilize equipment and materials to maximize production.
• To ensure safe flow of the fluid within the entire production system.
• To select suitable type of platform
• To determine the transportation method
• To identify they capacity of the separator
Objectives
97

98. Reservoir Pressure 3488 psia
Reservoir Temperature 197 F
Water Cut 0 %
productivity index 2.34 bbl/d/psi
AOF 6621.1 STB /d
98
Fluid Water and Oil
Method Black oil
GOR 373 scf//STB
Oil Gravity 35 API
Water Salinity 40000 ppm
InflowRelationshipPerformance(Well-1)

99. 99
OutflowPerformanceRelationship(TPRCurve)Analysis –Well

100. 100
SelectedTubingDaimler

101. 101
SensitivityAnalysis

102. 102
ChokeSizeAnalysis

103. Reservoir Pressure 3488 psia
Reservoir Temperature 197 F
Water Cut 0 %
productivity index 2.01 bbl/d/psi
AOF 5688 STB /d
103
Fluid Water and Oil
Method Black oil
GOR 373 scf//STB
Oil Gravity 35 API
Water Salinity 40000 ppm
InflowRelationshipPerformance(Well-2)

104. 104
OutflowPerformanceRelationship(TPRCurve)Analysis–Well

105. 105
SelectedTubingDaimler

106. 106
SensitivityAnalysis

107. 107
ChokeSizeAnalysis

108. 108
Flowcapacitybefore&after optimization
Well No Tubing I.D,
inches
Flowline I.D,
inches
Choke size,
inches
Wellhead pressure,
psig
Qo, STB/d
Well-1 3.5 4 32/64 580 3083
Well-2 3.5 4 32/64 430 2814
Well-3 3.5 4 32/64 541 5016
Well No Tubing I.D,
inches
Flowline I.D,
inches
Choke size,
inches
Wellhead pressure,
psig
Qo, STB/d
Well-1 3.5 4 48/64 652 6127.9
Well-2 3.5 4 46/64 491 3521
Well-3 3.5 4 48/64 541 5016
Before Optimization
After Optimization

109. 109
Artificiallift

110. Recoverable Oil 900 MMbbl
Required daily production rate 123288 STB /d
110
Production Wells
Tubing Diameter 3.5 inch
Production Rate for ( 3.5 inch ) 4000 STB /d
Number of production wells =
𝑇ℎ𝑒 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑑 𝑑𝑎𝑖𝑙𝑦 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛 𝑟𝑎𝑡𝑒
𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛 𝑟𝑎𝑡𝑒 𝑓𝑜𝑟 3.5 𝑖𝑛 𝑡𝑢𝑏𝑖𝑛𝑔 𝑠𝑖𝑧𝑒
No of Production Wells 30 Producers
ProductionSelectionPlan

111. 111
• Emulsion
• Hydrate
• Erosion
FlowAssuranceIssues

112. 112
• Viscosity is not high to cause high
pressure drop
• No pressure drop
FlowAssuranceIssues-Emulsion

113. 113
• No hydrate formation
• Well condition should be
considered
FlowAssuranceIssues–Hydrate

114. 114
• No Erosion formation
FlowAssuranceIssues–Erosion

115. 115
(FPSO)
Floating, Production, Storage and Offloading
(Pipelines)
Typesofdevelopmentplatformoptions
Pipelines

116. 116
Facilities Design Concept
• To withstand 25 years of operating life.
• To accommodate servicing barges or vessels in the
future.
• Location : 48.034 km from Sirri Island Refinery.
DesignFeatures&Basis

117. 117
ProductionSystems
High-pressure (oil-gas –water separation) 2 minutes
of retention time
W= (1440×27.2)/2 = 19584 bbl/day

118. 118
Summarizestheresults
Export pipeline
Coppper Tube size CTS
L=48 km
ID = 16in
OD = 16.07 in
Separator
Size = 60˝×20́
Settling volume = 27.2 bbl
P = 800 psi
Separator
Size = 60˝×20́
Settling volume = 27.2 bbl
P = 800 psi
Pipeline
L=5 km
ID = 8in
OD = 8.375in
Pipeline
L=0.3km
ID = 10in
OD = 10.375in
Pipeline
L=0.3km
ID = 10in
OD = 10.375in
Well head
P = 200 psi
Well head
P = 200 psi

119. 119
Summarizestheresults
Export pipeline
Coppper Tube size CTS
L=48 km
ID = 16in
OD = 16.07 in
Separator
Size = 60˝×20́
Settling volume = 27.2 bbl
P = 800 psi
Separator
Size = 60˝×20́
Settling volume = 27.2 bbl
P = 800 psi
Pipeline
L=5 km
ID = 8in
OD = 8.375in
Pipeline
L=0.3km
ID = 10in
OD = 10.375in
Pipeline
L=0.3km
ID = 10in
OD = 10.375in
Well head
P = 200 psi
Pipeline
L=0.3km
ID = 10in
OD = 10.375in

120. 120
Summarizestheresults
Export pipeline
Coppper Tube size CTS
L=48 km
ID = 16in
OD = 16.07 in
Separator
Size = 60˝×20́
Settling volume = 27.2 bbl
P = 800 psi
Separator
Size = 60˝×20́
Settling volume = 27.2 bbl
P = 800 psi
Pipeline
L=5 km
ID = 8in
OD = 8.375in
Pipeline
L=0.3km
ID = 10in
OD = 10.375in
Pipeline
L=0.3km
ID = 10in
OD = 10.375in
Well head
P = 200 psi
Pipeline
L=0.3km
ID = 10in
OD = 10.375in
Pipeline
L=0.3km
ID = 10in
OD = 10.375in

121. RAEEF

122. • To plan an economic strategy for different scenarios regarding rig cost and
selection, drilling, facilities and pumps scenarios.
• To provide the resources, competency training, knowledge, and culture to
carry out health, safety and environmental responsibilities.
• To proactively minimize the impacts of operations on health, safety and
environment.
• To achieve the highest level of safety.
122
Objectives

123. ProductionSharingContract(PSC)
Fiscal terms table
123
PSC

124. Deviated wells (8) 75.0528
Vertical wells (12) 55.6
Design & Project
Management 5.2
Insurance & Certification 2.26
Contingency 5.57
total cost 189.7828
124
Drilling operation Mill USD $
Jack-up rig and
Installation
48.1
Facilitiesestimatedprice
Vertical wells (18) 83.4
Design & Project
Management 6.23
Insurance & Certification 3.75
Contingency 5.83
total cost 115.25
Drilling operation Mill USD $
Jack-up rig and
Installation
16.04

125. Topside Mill USD $
Equipment 12.09
Materials 5.238
Fabrication 6.822
Installation 16.555
Design & Project
Management 3.88
Insurance & Certification 0.60
Contingency 2.57
total cost 47.76 125
Jacket Mill USD $
Materials 9.945
Fabrication 7.443
Installation 19.32
Design & Project Management 4
Insurance & Certification 0.87
Contingency 2.83
total cost 44.41
Facilitiesestimatedprice

126. 126
Facilities CAPEX 2720.605
Development Wells 56.091
Decommission 11.285
Fixed OPEX 10.135
Sub Total w/o OPEX 192
Mill USD
Facilitiesestimatedprice
Offshore Pipeline Mill USD $
Materials 4.346
Installation 22.62
Design & Project
Management 1.356
Insurance & Certification 1
Contingency 3.67
total cost 32.72

127. 127
description unit value
Royalty Rate % 20.00
Capital Allowance %/year 10.00
Tax Rate % 40.00
WACC % 10.00
Oil Price Base (year 0) USD/Bbl 62.12
Escalation
Oil Price Base % p.a. 1.80
Total Opex (fixed & variable
opex) % p.a. 1.20
Production Data
STOIIP MMM bbl 1.72
THV (Threshole volume) bbl 100,000,000
Facilitiesestimatedprice

128. 128
Results
NPV= 10453 MMUSD

129. 129
Results
Total Revenue 53224.2 Mill. USD
Total Cost 6952.11 Mill. USD
R/C 7.66
THV 85597 Mill. bbl >100 Mill. bbl (above)
P/C 90/10
Cost Ceiling Rate 30%
Contractor Profit 2457.2 Mill. USD

130. 130
Results
60% 70% 80% 90% 100% 110% 120% 130% 140%
Productio
n 5141 6492 7841 9196.75 10451.9 11927 13262 14617 16336
CAPEX 19404.3 17166.2 14928.1 12690 10451.9 8213.7 5975.5 3737.3 1499.1
OPEX 10826.7 10733 10639.3 10545.6 10451.9 10358.2 10264.5 10170.8 10077.1
oil price 5030.9 6386.15 7741.4 9096.65 10451.9 11807.2 13162.5 14517.7 16236.5

131. 131
Results
Net Cash Flow
Payback Period
3 years

132. 132
Summarizestheresults

133. 133

134. Riskmanagement
Hazard Identification
Identify hazards associated with the job tasks and work place
Risk Assessment
Evaluate the likelihood of an injury or illness occurring, and its consequences
Control Selection
Identify practicable control measures
Control implementation
Implement control measures as per a plan
Risk
Assessment
Process
134

135. Health
PRE-MEDICAL CHECK-UP
HEALTH
monitoring
MONITORING PROGRAM FIRST AID
WEATHER SHOULD be considered to avoid injuries and illness.
Temperature would fall to 18c since our field location is offshore (Persian gulf)
In this case our employees will be provided with:
 Rain coat
 Sweaters 135

136. Safety
 In term of safety training
Evacuation
training
Offshore
survival
training
health, &
safety
training
Major
Emergency
Management
(MEM) training
H2S prevention
training
PPE H2S indicator Life
boats
Life
jackets
Fire
protection
system 136
 In term of safety equipment & Facilities

137. SafetyinOilPlatform
137
Hydrogen Sulphide (𝐇𝟐𝐒)
• Present in oil & gas deposits
• High levels can be fatal & small doses can cause respiratory problems
Safety Measures against 𝐇𝟐𝐒
• H2S gas monitor
• Full face respirator
• Self-contained Breathing Apparatus (SCBA)

138. SafetyinOilPlatform
138
Drilling Fluids
• High volume of drilling fluids during circulation.
• Workers exposed to smell can have dizziness, drowsiness, headaches &
nausea
• Skin contact can cause dermatitis
Safety Measures against Drilling Fluids
• Washing Facilities
• Working Hours
• Goggles, gloves, boots & suits

139. SafetyinOilPlatform
139
Silica
• Cement & sand contains silica.
• Prolonged breathing causes silicosis.
• Silicosis cause respiratory problems
Safety Measures against Silica
• Respirator.
• Working Hours.

140. SafetyinOilPlatform
140
Naturally Occurring Radioactive Materials (NORM)
• Present in Earth’s crust.
• Sludge or drilling fluids may contain high levels of NORM.
• Workers exposed during cleaning or disassembly of equipment.
• Cause cancer.
Safety Measures against NORM
• NORM monitor present with worker.

141. SafetyinOilPlatform
141
Confined Space
• Partially closed area big enough for one employee to enter.
• For inspection, cleaning, maintenance & repair.
• Obstruction can make entry & exit difficult.
Safety Measures against Confined Space
• Harness attached to worker.
• Blower System – to provide air in space.
• Self-contained Breathing Apparatus (SCBA)

142. SafetyinOilPlatform
142
Noise
• Comes from mud pump, shale shaker, derrick, dog house, pipe decks
Safety Measures against Confined Space
• Curtains & walls for sound attenuation.
• Hearing protection device.
• Annual hearing tests.

143. Environmentregulations&Acts
Clean Water Act (CWA)
Impose restrictions and strict controls with respect to the discharge of pollutants,
including spills and leaks of oil and other substances into the waters.
Resource Conservation and Recovery Act (RCRA)
Regulates the generation, transportation, treatment, storage, disposal and
cleanup of hazardous and non‐hazardous waste.
Oil Pollution Act (OPA)
Sets minimum standards for prevention, containment and cleanup of oil spills.
143

144. 144

145. • To achieve a better and more sustainable project.
• To protect the eco-system and surroundings.
145
Objectives

146. MOROFOsustainability
Researches found many instances where renewable energy technologies are already
economic for oil and gas, particularly when competing against expensive diesel- or
propane-based power in off-grid applications.
Solar/Wind-powered autonomous well platform
35% of power supply to the rig
146

147. MOROFOsustainabledevelopmentgoals
147
1) Prevent and mitigate the
health impacts by
hydrocarbon extraction
process
2) Reduce occupational risks
1) Improve energy efficiency in
operation and production
2) Improve access to energy
services through shared
infrastructure

148. MOROFOsustainabledevelopmentgoals
148
1) Encourage local
procurement and supplier
development
2) Foster full and productive
local employment and
workforce development
1) Improve energy
efficiency in
operation and
production
1) Mitigate emissions
within oil and gas
operations
2) Partner in research and
development and
education outreach

149. RAEEF

150. StepsofAbandonment
150
8 steps of Offshore Platform Decommissioning
1) Project Management, Engineering and Planning
• Three years before the well runs dry.
• Contractors for each job set of decommissioning.

151. StepsofAbandonment
151
2) Permitting and Regulatory Compliance
• Permits for decommissioning are obtained.
• An Execution Plan is made.
3) Platform Preparation
• Tanks, processing equipment and piping are cleaned.
• Pipes and cables between deck modules are cut.
• Marine growth removed from jacket facilities.

152. StepsofAbandonment
152
4) Well Plugging and Abandonment
• Produced fluids are circulated out or bull headed.
• Heavy drilling fluids are inserted in hole.
• Christmas tree removed and production tubing removed.
• Cement pumped inside liner and production casing.
• Intermediate casing shoe plugged with cement.
• Tests to ensure proper cementing.

153. StepsofAbandonment
153
5) Conductor Removal
• Pulling/ Sectioning: conductors are removed and cut into segments.
• Offloading: cranes raise the conductor casing and offload in the boat.
transported to offshore disposal site.
6) Mobilization and Demobilization of Derrick Barges and Platform Removal
• Derrick Barges: transport topsides and substructures
• Jacket: removed in pieces by abrasive cutting or mechanical technology and
transported.

154. StepsofAbandonment
154
7) Pipeline and Power Cable Decommissioning
• Cables are removed by electricians.
• Pipelines decommissioned by cleaning and disconnecting them.
8) Materials Disposal and Site Clearance
• Materials are recycled, refurbished and reused or disposed in specified
landfills.
• Divers are send to check the vicinity.
• Test trawling performed.

156. 156
References
 https://www.sciencedirect.com/topics/engineering/producing-formation
 http://homepages.see.leeds.ac.uk/~earpwjg/PG_EN/CD%20Contents/G
GL-66565%20Petrophysics%20English/Chapter%203.PDF
 https://www.spec2000.net/01-permeability.htm
 https://www.semanticscholar.org/paper/Uncertainty-in-WAG-
Injection-Modelling-using-and-Suramairy-
Abdulrahman/46fac79845b187a68f6398f9ac5b860e82ee6c17

157. Stratigraphy
157

158. 158

159. 159

160. 160

161. Appendices
161
USAGE RULES:
 Use anytime. Porosity method may be better
if core data is available.
 Not reliable in fractured or heterogeneous
reservoirs.
 Parameters need to be calibrated to core data
for most zones.
The Wyllie and Rose relationship modified by
Schlumberger

162. Reservoirfluid
Black Oil
When the reservoir pressure lies anywhere
along line 1 → 2, the oil is said to be
undersaturated, meaning the oil would
dissolve more gas if more gas were present.
pressure
Temperature
162

163. 163
The Timur relationship for granular rocks
(sandstones and oolitic limestones), which
generally gives a more conservative
estimate of permeability.

164. PorosityVsPermeability
164
164

165. Watersaturation
165

166. 166