Field Development Plan

1. 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

2. 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.

3. 4 OrganizationChart Project Manager and Reservoir Eng Mahmood Geologist & Geophysics Aseel Drilling Eng & Well Completion Waseem Production Eng Hani Economics, HSE & Sustainable Development Raeef

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

5. 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

6. 7 FieldDevelopmentPlanstages

7. ASEEL

8. 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

9. 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

10. 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

11. 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

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

13. Depositionenvironment 14 Marine sediment

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

15. InterpretationOfWellLogs 16 Well 1 Well 2 Well 3

16. InterpretationOfWellLogs 17 Oil zone h=525 ft Limestone

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

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

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

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

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

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

23. MAHM OOD

24. 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

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

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

27. Relativepermeability 28

28. 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

29. 30 WellTestAnalysis Build-up test Bourdet Et al, Curve HORNER plots (Skin factor)

30. 31 Properties Values K.h, md.ft 4310 Absolute Permeability, mD (oil zone) 8.2 Skin 3.2 Initial pressure, psi 3475 WellTestAnalysis

31. 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

32. 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

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

34. 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

35. 36

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

37. 38

38. 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

39. 40 BasecaseoftheDynamicModel

40. 41 Basecaseresult Oil recovery factor 2.25 % Water cut 0

41. 42 BasecasewithPerforations

42. 43 Basecaseresult Oil recovery factor 8.5% Water cut 0

43. 44 FirstScenario

44. 45 FirstScenarioResults Oil recovery factor % 28.52 Oil production rat bbl/day 11932.3 Water cut % 23.47

45. 46 SecondScenario

46. 47 Oil recovery factor % 26.4 Oil production rat bbl/day 12142.6 Water cut % 22.3 ResultsfortheSecondScenario

47. 48 CreamingCurve 0 5 10 15 20 25 30 0 5 10 15 20 25 30 RF Wells Drilled Creaming Curve FORECAST TREND

48. 49 WaterInjectionCase

49. 50 OilSaturationMaps

50. 51 Oil recovery factor 44.1% Oil production rat 58204.9bbl/day Water cut 86.9% ResultsfortheWaterInj

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

52. 53 Immiscible injection  Water Flooding  Gas Injection • CO2 • N2/Air  WAG Most EOR screening values are approximations based on successful north American project. EORSelection

53. 54 WAGInjection

54. 55 OilSaturationmaps

55. 56 Oil recovery factor 52.3% Oil production rat 60849.1 bbl/day Water cut 92.1% ResultsforWAGInj

56. 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%

57. Waseem

58. • 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

59. Why Jack-up rig Selectionofdrillingrig

60. WellCoordinateForPrimaryScenario

61. WellCoordinateForSecondaryscenario

62. WellCoordinateForTertiaryscenario

63. 64 Vertical Well Trajectory for Primary Scenario

64. 65

65. 66

66. 67

67. VerticalWellTrajectoryDesign 68

68. 69 Deviated Well Trajectory for Primary Scenario

69. DirectionalwellA1trajectory 70

72. Directionalwell`B1trajectory 73

77. 78 Vertical Well Trajectory for Secondary Scenario

78. 79

79. 80

80. 81

81. 82

82. 83 Vertical Well Trajectory for Tertiary Scenario

83. 84

84. CasingDesign 85

85. 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

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

87. 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

88. DrillingBitSelection Roller cutter TCI PDC 89

89. 90 ChristmasTreeSelection

90. WellCompletion 91 7500ft

91. Drillingschedule 92

92. Drillingschedule 93

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

94. 95 Drilling Bit Cost Mud Cost Vertical & Deviated Casing Cost DrillingBitCost,MudCost&CasingCost

95. HANI

96. • 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

97. 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)

98. 99 OutflowPerformanceRelationship(TPRCurve)Analysis –Well

99. 100 SelectedTubingDaimler

100. 101 SensitivityAnalysis

101. 102 ChokeSizeAnalysis

102. 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)

103. 104 OutflowPerformanceRelationship(TPRCurve)Analysis–Well

104. 105 SelectedTubingDaimler

105. 106 SensitivityAnalysis

106. 107 ChokeSizeAnalysis

107. 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

108. 109 Artificiallift

109. 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

110. 111 • Emulsion • Hydrate • Erosion FlowAssuranceIssues

111. 112 • Viscosity is not high to cause high pressure drop • No pressure drop FlowAssuranceIssues-Emulsion

112. 113 • No hydrate formation • Well condition should be considered FlowAssuranceIssues–Hydrate

113. 114 • No Erosion formation FlowAssuranceIssues–Erosion

114. 115 (FPSO) Floating, Production, Storage and Offloading (Pipelines) Typesofdevelopmentplatformoptions Pipelines

115. 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

116. 117 ProductionSystems High-pressure (oil-gas –water separation) 2 minutes of retention time W= (1440×27.2)/2 = 19584 bbl/day

117. 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

118. 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

119. 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

120. RAEEF

121. • 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

122. ProductionSharingContract(PSC) Fiscal terms table 123 PSC

123. 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

124. 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

125. 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

126. 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

127. 128 Results NPV= 10453 MMUSD

128. 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

129. 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

130. 131 Results Net Cash Flow Payback Period 3 years

131. 132 Summarizestheresults

132. 133

133. 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

134. 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

135. 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

136. 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)

137. 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

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

139. 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.

140. 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)

141. 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.

142. 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

143. 144

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

145. 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

146. 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

147. 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

148. RAEEF

149. 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.

150. 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.

151. 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.

152. 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.

153. 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.

154. 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

155. Stratigraphy 157

156. 158

157. 159

158. 160

159. 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

160. 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

161. 163 The Timur relationship for granular rocks (sandstones and oolitic limestones), which generally gives a more conservative estimate of permeability.

162. PorosityVsPermeability 164 164

163. Watersaturation 165

164. 166

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