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- 3. Company Profile Shazreena Team Leader Nur Syuhada Petrophysics Department Khairul Haziq Reservoir Department Shazreena Geology & Geophysics Department Nur Syuhada HS&E Department Muhsin Facilities Department Shazreena Production Department Faisal Drilling Department Faisal Economic Department TIMBUNAN ENERGY MISSION • To deliver the safest, most economical and reliable engineering solutions in developing Gelama Merah field to its maximum extent. • To provide the team members a steady platform for a knowledgeable, creative and competitive working environment. VISION “Delivering Solutions” 3
- 4. Presentation Outline GEOLOGY AND GEOPHYSICS PETROPHYSICS RESERVOIR ENGINEERING DRILLING ENGINEERING PRODUCTION TECHNOLOGY FACILITIES ENGINEERING ECONOMICS HEALTH, SAFETY AND ENVIRONMENT 4
- 6. Introduction Source : http://www.offshoreenergytoday.com • Coordinate : 05033’49.98’’N, 114059’06.34’’E • Specifically located in the sub block 6S-18 Block SB 301 • Located in the West Labuan-Paisley syncline, defined by NS growth Morris fault • Characterised by trending anticline with steep flank and strong faulted crest SABAH BASIN • Formed as a result of uplift and exhumation of Crocker-fold thrust belt, since Middle Miocene • Depositional environment : prograding delta and coastal • Sand packages : Interbedded sand shale, coarsening upwards Gelama Merah 6
- 7. Reservoir Geology Formation Unit Fluid Type U3.2 gas U4.0 gas U5.0 gas U6.0 gas U7.0 gas U8.0 gas U9.0 oil U9.1 oil U9.2 oil DEPOSITED FIRST LAST TO BE DEPOSITED 7 U3.2 U4.0 U5.0 U6.0 U7.0 U8.0 U9.0 U9.1 U9.2 OWC GOC TOP RESERVOIR 1200 1300 1400 1500 1600 1700 1800 1900 2000 274000 275000 276000 277000 278000 279000 280000 Depth (m) Length (m) HORIZONTAL CROSS SECTION GELAMA MERAH DEPOSITED LATER, UPLIFTED,EROSION OCCURS CAUSING UNCOMFORMITY
- 8. Petroleum System of Gelama Merah Terrigeneous organic matter mainly from stage IVA, IVC and IVD • Siliclastic reservoir ranging from coastal/ shallow marine to deep marine turbidites. • Interbedded sandtone with minor dolomite. Migration along faults, and through sedimentary facies Anticlinal features, stratigraphic traps, unconformity trapping mechanisms No major seal but shale and mudstone units throughout the stratigraphic column provide effective top 8
- 9. Well to Well Correlation – Gamma Ray Log 9 U3.2 to U8.0 were identified from GM-1 but not in GM-ST-1 Both logs show the existence of U9.0 to U9.2
- 10. Depositional Environment Fluvial to deltaic depositional environment Silt/fine sand Fining up sandstone Shale 10
- 11. Volumetric Calculation 1250 1300 1350 1400 1450 1500 1550 1600 0 2000000 4000000 6000000 8000000 10000000 Area VS Depth top bottom goc woc sp STOIIP and GIIP for Gelama Merah STOIIP = 7758 x GRV x NTG x Ф x (1-Sw) / Bo in STB GIIP = 43560 x GRV x NTG x Ф x (1-Sw) / Bg in SCF 11
- 12. Conclusion ZONE OF INTEREST 1495.3m – 1329.7m TVDSS DEPOSITIONAL ENVIRONMENT Deltaic environment SOURCE ROCK Terrigeneous organic matter RESERVOIR ROCK Interbedded sandtone with minor dolomite STOOIP 215 MM STB GIIP 71.4 B SCF 12
- 13. Petrophysics 13
- 14. • ga Log Interpretation Hydrocarbon Zone of Gelama Merah 1 Gas zone (1413m-1495m) Oil zone (1495m-1535m) Water zone (1535m-1575m)
- 15. Log Interpretation Hydrocarbon Zone of Gelama Merah ST1 Gas zone (1591m-1663m) Oil zone (1666m-1717m) Water zone (1718m-17623m)
- 16. Pressure Plot Analysis GOC = 4904.86 ft WOC = 5037.07 ft gas gradient =0.051 psia/ft oil gradient =0.375 psia/ft water gradient =0.413 psia/ft Pressure (psia) Depth (ft)
- 17. Sensitivity Analysis Gelama Merah 1 Porosity cut off pb Vshale cut off GR log Net To Gross (NTG) U3.2 0.10 2.48 0.30 65.95 0.000 U4.0 0.18 2.48 0.50 88.50 1.0000 U5.0 0.19 2.33 0.50 88.50 0.9565 U6.0 0.19 2.33 0.50 88.50 1.0000 U7.0 0.19 2.33 0.50 88.50 0.8131 U8.0 0.19 2.50 0.50 88.50 1.0000 U9.0 0.10 2.48 0.50 88.50 1.0000 U9.1 0.19 2.33 0.40 77..22 0.9674 U9.2 0.19 2.33 0.30 65.95 0.6386 Gelama Merah ST1 Porosity cut off pb Vshale cut off GR log Net To Gross (NTG) U9.0 0.01 2.62 0.20 75.06 0.97 U9.1 0.10 2.48 0.30 79.80 0.53 U9.2 0.10 2.48 0.30 79.80 0.80 Sandstone Sandstone Limestone
- 18. Conclusion 18 Porosity (min) Porosity (ML) Porosity (max) Porosity (average) Sw (min) Sw (ML) Sw (max) Sw (average) 0.1539 0.2262 0.2913 0.1993 0.2130 0.3068 0.4000 0.3228 0.1588 0.2948 0.4307 0.2899 0.0173 0.1635 0.3097 0.1226 0.1407 0.2801 0.4193 0.2855 0.0250 0.2222 0.4194 0.1329 0.1887 0.3121 0.4355 0.3255 0.0250 0.1242 0.2234 0.0931 0.1412 0.2902 0.4391 0.2230 0.0358 0.1988 0.3619 0.2198 0.1304 0.3254 0.5204 0.3308 0.0121 0.2057 0.3993 0.1302 0.1096 0.3185 0.5275 0.3424 0.0117 0.2204 0.4292 0.0823 0.1390 0.2663 0.3935 0.2821 0.0436 0.1957 0.3478 0.1012 0.1066 0.2090 0.3113 0.2186 0.0823 0.3185 0.5548 0.3149
- 20. Reservoir & Hydrocarbon Classification Reported Reservoir Conditions Reservoir Pressure ................................ Reservoir Temperature ……………… 2116 psia 115 F Constant Composition Expansion Bubble Point Pressure ......................... 2014 psig Differential Vaporization Test (at 2014 psig and 115 F) Oil Formation Volume Factor ............ Solution Gas Oil Ratio ………………… Oil Density ……………………………… 1.169 bbl/stb 336 scf/stb 0.828 g/cc Reservoir Fluid Study Report: Pi > Pb Undersaturated Oil Reservoir Component Mole % N2 2.43 CO2 0.94 C1 26.50 C2 2.63 C3 0.45 i-C4 0.15 n-C4 0.22 i-C5 0.13 n-C5 0.13 C6 0.43 C7 2.95 C8 4.18 C9 2.90 C10 4.48 C11+ 51.49 Total 100.00 Gas Condensate Compositional Analysis: 20
- 21. Fluid contact & Datum depth GOC = 4904.86 ft @ 1495 m WOC = 5037.07 ft @ 1535.3 m MDT Pressure Plot Datum: 4971 ft @ 1515.3 m Pressure psia Depth ft 21
- 22. Reservoir Fluid & Rock Study Density 6.82 lb/ft3 Specific gravity 0.65 Viscosity 0.18 cp Compressibility 6.58E-4 psi-1 Formation volume factor 7.438E-3 Solution Gas/Oil Ratio 336 scf/stb Water formation volume factor 1.0138 Gas solubility in water 20.2327 Water compressibility 2.99556E-06 Water viscosity 0.4434 Density 0.829 g/cc Specific gravity 0.83 oAPI 39.71 Viscosity 1.35 cp Compressibility 7.225E-06 psi-1 Formation volume factor 1.1678 bbl/stb Solution Gas/Oil Ratio 336 scf/stb Oil Gas Water Skin factor -2.1 22 Properties Minimum Most Likely Maximum Porosity 0.182 0.352 0.394 Permeability, md 81.7 140 1170 Sw, fraction VP 0.1027 0.4353 0.7679 Compressibility, 1/psi 3.36 X 10-6 4.69 X 10-6 7.5 X 10-6
- 23. Creaming curve 8 wells 0 10 20 30 40 0 2 4 6 8 10 12 14 16 18 CUMULATIVE PRODUCTION (MMSTB) NUMBER OF WELL Creaming curve 745 𝑓𝑡 Well Development Planning Drainage radius Bubble map 𝑟𝑒 = 43560 × 𝐴 𝜋 Possible well placement Number of well 18 possible wells
- 24. 8 production wells location Well Development Planning STRATEGY 1 Plan A B C No. of well 8 8 8 FOPT, MMstb 29.7 30.5 28.9 FGPT, MMMscf 208 206 211 Pressure @ 2038 1516 1530 1536 3 injection wells location STRATEGY 2 Option A B C No. of producing well 8 8 8 No. of injection well 3 3 3 FOPT MMstb 52.2 50.7 47.3 FGPT MMMscf 285 289 264
- 25. Sensitivity Analysis 3 different scenarios Production Forecast Pressure profile 25 SCENARIO CASE 1 CASE 2 CASE 3 No of production well 8 8 8 No of injection well 2 3 3 Drainage radius 745 745 745 Type of Injection water water gas FOPT (MMSTB) 51.6 52.9 52.2 Oil flowrate STB/d 3000 3000 3000 FGPT (MMMscf) 24.3 28.3 28.5 Gas flowrate MMscf/d 10 14 13 Recovery factor % 24 25 25 𝑅𝑒𝑐𝑜𝑣𝑒𝑟𝑦 𝑓𝑎𝑐𝑡𝑜𝑟 = 𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛 𝑆𝑇𝑂𝐼𝐼𝑃
- 26. Drive Mechanism Water Drive Gravity Drainage Combination Drive Rock & Liquid Expansion • Expansion of the individual rock grains • Formation compaction 26 Pressure profile Production profile Water production
- 27. Reservoir Simulation Static Model Dynamic Model Simulator: Eclipse 100 27 Number of cell Grid Block Size NX : 66 1000 NY : 58 1000 NZ : 1 50
- 28. Conclusion Optimum well: 8 production well, 3 injection well Recovery factor: 25% Oil estimated recoverable: 5.29E+07 STB Water injection at 3rd year of production life EOR may needed to enhance production 28
- 30. Rig Selection • Jack-up is recommended because it can operate at shallow depth since Gelama merah water depth is 42.8 m and has lower cost than other rigs. Rig type Semi-submersible Jack-up Drillship Depth Up to 3000 m (Deep water) Up to 150 m (shallow and moderate ) 610-3,048 m (Deep water) Cost (USD) 200000 180000 237,900 –420,324
- 31. Spider Plot Well Location -25 -20 -15 -10 -5 0 5 10 15 -25 -20 -15 -10 -5 0 5 10 15 20 Spider Plot Well Location P3 P1 P2 P4 P5 P6 P7 P8 I1 I2 I3 P5 P3 P1 P2 P8 P6 P7 I1 P4 I2 I1
- 32. Well Trajectory Well TVD, ft Horizontal Distance, ft Kickoff Point, ft Build Up Rate, ͦ/10 0ft Maximum Degree Inclination , ͦ Measure Depth, ft Shape P1 4,971.00 3,158.46 600.00 2.00 44.68 6,148.73 L-Shape P2 4,971.00 2,938.19 600.00 2.00 41.90 5,997.66 L-Shape P3 (Centre) 4,971.00 0.00 0.00 0.00 0.00 4,971.00 Vertical P4 4,971.00 2,855.41 600.00 2.00 40.83 5,942.94 L-Shape P5 4,971.00 4,803.04 600.00 2.00 60.72 7,464.71 L-Shape P6 4,971.00 3,073.81 600.00 2.00 43.63 6,089.76 L-Shape P7 4,971.00 5,292.37 600.00 2.00 64.00 7,898.35 L-Shape P8 4,971.00 5,346.47 600.00 2.00 64.33 7,947.05 L-Shape I1 4,971.00 1,402.28 600.00 2.00 19.93 5,207.32 L-Shape I2 4,971.00 2,328.00 600.00 2.00 33.58 5,623.85 L-Shape I3 4,971.00 4,514.80 600.00 2.00 58.50 7,216.02 L-Shape
- 33. Casing and Cementing Casing Setting Depth -500.00 0.00 500.00 1000.00 1500.00 2000.00 2500.00 3000.00 3500.00 4000.00 4500.00 5000.00 5500.00 0.00 500.00 1000.00 1500.00 2000.00 2500.00 3000.00 3500.00 4000.00 4500.00 Depth (ft) Pressure (psi) Pressure Profile Formation Pressure (psi) Trip Margin (psi) Fracture Pressure (psi) Kick Margin (psi) Full gas at 17 1/2'' Full gas at 12 1/4'' Kick Tolerance 50 bbl Kick Tolerance 50 bbl Kick Tolerance 100 bbl Full gas at 24''
- 34. Casing and Cementing Casing Type OD (in) Casing Setting Depth (ft) Conductor 26 600 Surface 20 1500 Intermediate 13 3/8 2600 Production 9 5/8 4971 GroundLevel ConductorCasing in26OD Depth600ft SurfaceCasing 20inOD Depth1500ft IntermediateCasing 133/8inOD Depth2600ft ProductionCasing 95/8inOD Depth5000ft
- 35. Casing and Cementing Casing Design Selection Pressure Design Factor (DF) Tensile 1.3 Burst 1.1 Collapse 1.0 Type of casing Surface Intermediate Production Grade K-55 N-80 N-80 OD, in 20.00 13.38 9.625 ID, in 18.28 12.33 8.25 Hole Size, in 24.00 17.50 12.25 Nominal Weight 169.00 72.00 43.50 Thickness 0.81 0.51 0.44 Burst Burst Pressure 1953.88 2690.09 3163.64 Design Factor 1.78 1.52 1.15 Collapse Collapse Pressure 2500.00 2670.00 3810.00 Design Factor 2.02 1.62 1.06 Tensile tensile 797989.62 408916.03 247053.44 Design Factor 1.76 2.54 3.34 Joint STC STC LTC Joint Strength 1402000.00 1040000.00 825000.00
- 36. Casing and Cementing Cementing Selection • Type of Cement: Class G, 2% cement • Type of Additives: Bentonite Surface Casing Surface Intermediate Production No of sacks of cement, Nc 22145.44 16907.94 18449.65 No sacks of additives, Na 442.91 338.16 368.99 Total Weight of Additive Required, Wa (lb) 41633.43 31786.93 34685.34 Total Volume of Water Required, Vw (gal) 2066.01 20506.04 22375.83 Casing Excess Volume Surface 30% Intermediate 10% Production 10%
- 37. Drill String Design Unit Surface Intermediate Production Grade G105 G105 S135 OD in 5.00 5.00 5.00 ID in 4.28 4.28 4.28 Min. Tensile psi 115000.00 115000.00 145000.00 Min. Yield psi 105000.00 105000.00 135000.00 Collapse Pressure psi 701.26 1283.05 2582.20 WOB lb 11023.10 24250.82 50706.26 Length DP ft 1400.00 2440.00 4681.00 Length DC ft 60.00 120.00 250.00 BF dimensionless 0.86 0.85 0.85 Desired MOP lb 100000.00 100000.00 100000.00 Margin Of Overpull, MOP lb 525016.80 500073.10 382582.59 Total Load lb 55229.84 80173.53 606224.27 Tensile Strenght DP lb 603411.96 295130.63 132259.36 Design Factor Static Tension DF dimensionless 54.74 24.88 15.00 Dynamic Tension DF dimensionless 10.93 7.53 5.75 MOP Tension DF dimensionless 3.89 3.35 3.28
- 38. Drill Bit Selection Type of Casing Casing OD (in) Bit Diameter (in) Bit Type Conductor 26 Piling Piling Surface 20 24 Milled Tooth Bit Intermediate 13 3/8 17 1/2 Milled Tooth Bit Production 9 5/8 12 1/4 Milled Tooth Bit
- 39. Drilling Fluid Selection Depth (ft) Mud weight (ppg) Casing Mud Base 0 – 600 0 Conductor Piling 600– 1500 9 Surface Seawater + Hi Sweeps 1500 – 2600 9.5 Intermediate Potassium Chloride, KCL 2600 – 4971 10 Production Potassium Chloride, KCL
- 40. Well Control • Blowout Preventer (BOP) is used to seal the annular space between the surface and hole when there is a pressure kick inside the wellbore. • The minimum requirement for the BOP system must meet the specification of API RP 53. • The requirement for BOP used is a diverter system, annular preventer, an 8” spool equipped with full remote control valves, a pipe ram and a blind ram. Type of Casing Depth, ft Maximum Reservoir Pressure, psi Gas Hydrostatic Pressure, psi Pressure rating, psi Conductor 600 300 30 3000 Surface 1500 680 68 3000 Intermediate 2600 1220 122 3000 Production 4971 2270 227 3000
- 41. Time-Depth Chart 0.00 500.00 1000.00 1500.00 0.00 5.00 10.00 15.00 20.00 25.00 30.00 35.00 40.00 Depth vs Days (Gelama Merah Well) Days Depth (m) Rig Move & Position Drill 24'' hole run casing and cement 20'' surface Drill 17 1/2'' hole run casing and cement 13 5/8'' intermediate Drill 12 1/4'' hole run casing and cement 9 5/8'' production
- 42. Well Cost Estimate Terms Cost (USD Million) Tangible 1.045 Intangible 2.512 Contracted 8.503 Allocations 2.074 Total Cost (15% contingency) 16.263
- 43. Conclusion • Rig Selection: Jack-up rig • Cost Estimation : 1 Well = USD 16.26 Million Surface Intermediate Production Casing Selection K-55 N-80 N-80 Cementing (sacks) 24158.66 18445.02 15617.44 Drill String Selection G-105 G-105 S-135 Drill Bit Selection Milled Tooth Bit Milled Tooth Bit Milled Tooth Bit Drilling Fluid Selection Seawater + Hi Vis Sweeps Potassium Chloride, KCL Potassium Chloride, KCL
- 45. Inflow Performance Curve and Tubing Performance Curve 0 500 1000 1500 2000 2500 0 1000 2000 3000 4000 5000 Pwf (psia) Flowrate (bbl/d) IPR 0 500 1000 1500 2000 2500 0 1000 2000 3000 4000 5000 Pwf (psia) Flowrate (bbl/d) FUTURE IPR PRESENT 2100 2000 1800 1600 1520 Pr = 2151 psi Pb = 2087 psi Qmax= 4134 bopd Pmin = 1500 psi 0 500 1000 1500 2000 2500 0 1000 2000 3000 4000 5000 Pwf (psia) Flowrate (bbl/d) TPC with different tubing size PRESENT 2100 psia 2000 psia 1800 psia 1600 psia 1520 psia 2.875 inch 3.5 inch 4.5 inch 2.875 3.5 4.5 0 500 1000 1500 2000 2500 3000 3500 0 1 2 3 4 5 Flowrate (bbl/d) Tubing size (inch) Flowrate rate vs Tubing Size 45
- 46. Sensitivity Analysis – GLR and THP 0 500 1000 1500 2000 2500 0 1000 2000 3000 4000 5000 Pwf (psia) Flowrate (bbl/d) TPC with varying GLR - 3.5 inch PRESENT 2100 2000 1800 1600 1520 GLR 200 GLR 400 GLR 600 GLR 800 GLR 1000 0 500 1000 1500 2000 2500 0 2000 4000 6000 Pwf (psia) Flowrate (bbl/d) TPC with varying GLR - 4.5 inch PRESENT 2100 2000 1800 1600 1520 GLR 200 GLR 400 GLR 600 GLR 800 GLR 1000 INCREASING GLR 0 500 1000 1500 2000 2500 0 1000 2000 3000 4000 5000 Pwf (psia) Flowrate (bbl/d) TPC with varying wellhead pressure - 3.5 inch PRESENT 2100 2000 1800 1600 1520 150 psia 250 psia 350 psia 390 psia INCREASING WHP 0 500 1000 1500 2000 2500 0 1000 2000 3000 4000 5000 Pwf (psia) Flowrate (bbl/d) TPC with varying wellhead pressure - 4.5 inch PRESENT 2100 2000 1800 1600 1520 150 psia 250 psia 350 psia 390 psia Max THP = 390 psi Min THP = 156 psi • More than enough to produce, allow well to produce naturally under all varying conditions • No tubing replacement is needed in the future since this size can cater production at the lowest expected reservoir pressure –REDUCE COST • Tubing 5.5 inch and 7 inch are too costly compared to 4.5 inch TUBING SELECTION – 4.5 inch 46
- 47. Completion String Design Completion Fluid • Brine with NaCl (8.5-9.5 ppg) Packer Fluid • Brine with NaCl – minimize clay swelling, assist in lowering corrosion rate Perforation • Not applicable – open hole completion Artificial Lift Selection – Gas Lift • Low initial reservoir pressure – 2151 psi, need artificial lift to maintain desired production rate • Gas lift is chosen because Gelama Merah has high GOR and a steady amount of gas for reinjection • Cost effective and easy installation Conventional Spooled Wellhead and standard cross piece Xmas Tree • Screwed or welded to casing top joint • Surface is located at the platform • Strong anti corrosion material 47 Slotted Liner Packer 4.5” production tubing Gas lift valve
- 48. Material Selection 𝑃 CO2 = 𝑃 𝑟𝑒𝑠 𝑥 𝐶𝑂2 𝑚𝑜𝑙%/100 = 2151 𝑥 0/100 = 0 psia 𝑃 H2S = 𝑃 𝑟𝑒𝑠 𝑥 H2S 𝑚𝑜𝑙%/100 = 2151 𝑥 0/100 = 0 psia H2S (ppm) 0 CO2 (mole) 0 Pressure (psi) 1753 Temperature (degree F) 155 𝑃 CO2 (psi) 0 𝑃 H2S (psi) 0 13Cr 48
- 49. Production Problem and Control • Occurs as formation water is produced •Carry out further studies after water starts to be produced to implement the best mitigation ways •No signs of deposition of asphaltene •Apply asphaltene inhibitor •13 Cr alloy for material selection •Use neutralizing inhibitors and reduce hydrogen ion in environment •Highly unlikely to occur, but injection points for wax dispersion should be included WAX DEPOSITION CORROSION SCALE FORMATION ASPHALTENE 49
- 51. 51 Oil and Gas Properties Component Mol% Mole fraction, Yi Molecular wt ,Mi Yoi GPM H2S - - - - - N2 2.85 0.0285 44.01 0.82 0.48 CO2 7.39 0.0739 28.01 0.81 0.81 C1 80.52 0.8052 16.04 0 0.00 C2 8 0.08 30.06 0.36 2.11 C3 0.78 0.0078 44.1 0.51 0.21 I-C4 0.16 0.0016 58.12 0.56 0.05 N-C4 0.18 0.0018 58.12 0.58 0.06 I-C5 0.05 0.0005 72.15 0.63 0.02 N-C5 0.04 0.0004 72.15 0.63 0.01 C6 0.02 0.0002 86.17 0.66 0.01 C7 0.01 0.0001 185 0.69 0.01 Total 100 3.77 By referring to Reservoir Engineering Handbook by Tarek Ahmad GPM = 11.173 (Psc/Tsc) (γi Mi)/γoi) Psc= Standard pressure, psia Tsc = Standard temperature, °R γi = mole fraction of component i in the gas phase Mi = molecular weight of component i γoi = specific gravity of component i as a liquid at standard conditions (refer to Reservoir Engineering Handbook Book by Tarek Ahmed) GPM calculation
- 52. Surface Processing Facilities 52 Process Flow Diagram
- 53. Platform Selection 53 Consideration Steel Jacket Platform Concrete Gravity Base Structure Platform FPSO Water depth Shallow Medium deep Cost Low Moderate high Sea condition and environment Good Good Moderate Lifespan >20 years >20 years <20 years Stability Good Good Moderate * Steel Jacket Platform is chosen as production platform
- 54. Platform Layout Side view of platform 54 Top view of platform Jacket Top side Flare Drilling rig Crane Helideck Power generation Quarters Bottom deck Top deck
- 55. Crude oil Transportation 55 Option 1 Pipeline tie in to Semarang CPP Option 2 Pipeline direct to LCOT and LGAST Option 3 FSO + oil tanker
- 57. Conclusion • Fixed Jacket platform is selected as it suitable to be in used in Gelama Merah Field • The best transportation of oil and gas will be via tie-in pipeline to CPP Semarang. 57
- 58. Economics 58
- 59. Economic Assumption Terms Value Oil Price USD 48/bbl Gas Price USD 2.5/MMbtu Base year 2016 Price Increment 3% on Oil and Gas Price Company Policies Terms Value Internal Rate of Return (IRR) Above 15% Payback Period Less than 10 years Net Present Value (NPV) Above 100 Million Profit Index Ratio (PIR) Above 2
- 60. Project Costs Option 1 Option 2 Option 3 CAPEX (USD Million) Based of MOD (5% escalation ) Fixed Structure Pipeline and Tangible (Well) Intangible Total Cost 142.49 198.16 15.87 356.52 142.49 285.6 17.45 445.54 350.49 197.35 17.45 565.29 OPEX (USD Million) 5 % fixed of Total CAPEX 17.8 22.28 28.26
- 61. Economic Model Terms Value (Based of PSC 1997) Royalty 10% of Gross Revenue Taxes 38% of Taxable Income Research Cess 0.5% of Profit Export Duty 10% of Profit Supplementary Payment
- 62. Project Cash Flow -$400.00 -$200.00 $0.00 $200.00 $400.00 $600.00 $800.00 $1,000.00 $1,200.00 $1,400.00 $1,600.00 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Million USD Year Project Cash Flow Option 1 NCF CNCF MCO=-373.02 Mil TCS=1495.85 Mil Payback Period: 6 years -$500.00 -$300.00 -$100.00 $100.00 $300.00 $500.00 $700.00 $900.00 $1,100.00 $1,300.00 $1,500.00 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Million USD Year Project Cash Flow Option 2 NCF CNCF TCS=1601.57 Mil MCO=-466.51 Mil Payback Period: 6.5 years -$700.00 -$500.00 -$300.00 -$100.00 $100.00 $300.00 $500.00 $700.00 $900.00 $1,100.00 $1,300.00 $1,500.00 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Million USD Year Project Cash Flow Option 3 NCF CNCF TCS=1453.84 Mil MCO=-592.22 Mil Payback period: 7.5 years
- 63. Project NPV Profile -$400.00 -$200.00 $0.00 $200.00 $400.00 $600.00 $800.00 $1,000.00 $1,200.00 $1,400.00 $1,600.00 $1,800.00 0 10 20 30 40 50 60 70 80 90 100 NPV Million Percentage % Project NPV Profile Option 1 Option 2 Option 3 Option 1: 23% Option 2: 20% Option 3: 15% Option 1: 367.80 Million Option 2: 335.12 Million Option 3: 220.29 Million
- 64. Summary For Economy Analysis • From summary, we decide to choose Option 1 because it have higher NPV,IRR and ROI and lower payback period. Terms Option 1 Option 2 Option 3 NPV (USD Million) 367.80 335.12 220.29 IRR (%) 23 20 15 Payback period (years) 6 6.5 7.5 PIR 4.01 3.43 2.45
- 65. Sensitivity Analysis • The Oil price, oil production and CAPEX are the most sensitive and any changes on these parameters will affect the sensitivity of project. 250 300 350 400 450 -15% 0% 15% NPV (million) Percentage change Spider Plot For NPV Option 1 Oil Production Oil Price Price Increment OPEX CAPEX Gas Production Gas Price
- 66. • The CAPEX, oil price, and oil production are the most sensitive and any changes on these parameters will affect the sensitivity of project. 15 20 25 30 -15% 0% 15% Percentage change (%) Spider Plot For IRR Option 1 Oil Production Oil Price Price Increment OPEX CAPEX Gas Production Gas Price Sensitivity Analysis
- 67. • The oil price, oil production and CAPEX are the most sensitive and any changes on these parameters will affect the sensitivity of project. 250 300 350 400 450 OPEX Price Increment Gas Production Gas Price CAPEX Oil Price Oil Production NPV (million) Tornado Diagram For NPV Option 1 15 -15 Sensitivity Analysis
- 68. • The CAPEX, oil price, and oil production are the most sensitive and any changes on these parameters will affect the sensitivity of project. 19 20 21 22 23 24 25 26 27 Price Increment Gas Production Gas Price Oil Price Oil Production CAPEX Percentage (%) Tornado Diagram For IRR Option 1 15 -15 Sensitivity Analysis
- 70. HSE Policies and Scopes Stringent regulatory Workplace safety Personnel welfare International standards benchmark Environmental concerns
- 71. HSE Legislations Environmental Quality Act 1974 Petroleum(Safety Measure Act) 1984 Occupational Safety and Health Act 1994 HSE legislations, regulations and standards HSE Regulations Petroleum Development Act (PDA) 1974 Factories and Machinery Act 1967 OSHA 1994 HSE Standards International Organisation for Standards (ISO) The American Petroleum Institute (API) International Electrotechnical Commission (IEC)
- 72. Hazard Identification, Risk Assessment and Risk Control Nur Syuhadah bt Abdul Fatah (HSE Officer) Timbunan Energy
- 73. Environmental Management and Control Exploration Surveying • magnetic • gravimetric • seismic Exploration Drilling • rig movement • rig building Appraisal • drill more wells Activities Development and Production • more wells were drilled after the size of oil field is known Decommissioning and Rehabilitation • removal of the equipment • restoration of the site to environmentally sound conditions • continually monitoring after the closure
- 74. Environmental Management and Control Control & Preventive Measures • appropriate international and national laws, regulations and guidelines • coherent procedures for decisions on project or activities • enforceable standards for operations • clear legislations • performance reporting • appropriate monitoring procedures and protocols
- 75. HSE Planning and Procedure • Asses and Analyse HSE Risk • Evaluate HSE Capability Questionnaire • Evaluate Historical Performance • Permit To Work Form Plan Practice Evaluate Adjust Emergency Response Plan (ERP)
- 76. HSE Planning and Procedure Evacuation Route
- 77. HSE Implementation, Performance Monitoring and Management Review Indicators on environment, health and safety KPI on safety performance Documented statistics
- 78. Conclusion • Timbunan Energy has put all aspects of company parts as crucial aspects for health and safety environment • We believe that HSE plays an important roles for a success exploration and production of oil and gas • With that, we know a safe and healthy environment is a key for optimum production and low risk in our business to ensure our goals achieved.
- 79. Overall Conclusion • Total oil production = 51.6 MM STB in 20 years with 24% RF • NPV = 367.8 million USD
Editor's Notes
- 1. A pressure plot is made by using the data from Final Well Report.
- 1. NTG is obtained by calculate net sand interval over total gross interval.
- PVT analysis Pressure Transient Analysis Routine core analysis Viscosity test
- Oil rate=150,000stb/d Gas rate=10,000 Mscf/d Water rate=1,000 stb/d BHP target=1000psia
- Pressure end at 1680psia
- Rock&Liuid expansion: Undersaturated: as pressure>bubble point – only crude oil,connate water&rock only present. As Re declines, rock & fluids expand due to compressibilities The res compressibility is the result of two factors(in slides) Combination drive: Pi=Pb Pr decline slowly
- 2.5-5 MODERATE RICH GAS 5> RICH GAS
- OIL EXTRACT FROM PROD WELLHEAD N ENTER MANIFOLD HC ENTER 3PHASE HORIZONTAL SEPARATOR 3. 3 PATH GAS OIL, WATER PATH GAS METER- MEASURE VOL OF GAS PIG LAUNCHER- TO CLEAN N ALSO INSPECT THE PIPELINE STABILSER- REDUCE RVP ( VAPOR PRESSURE)
- 1. We have listed 5 outlines for petrophysics.
- TOPSIDE DIMENSION 50 X 30 X 22 M WEIGHT TOPSIDE 4000 MT LONGITUDINAL 45 M LATERAL BETWEEN LLEG 25 M LEG HEIGHT 76 M
- PIPELINE TO LCOT HIGH COST USUALLY FSO CHARTER RATE NOT EXCEED 20 YEARS FSO NOT SUITABLE IN SHALLOW REGION
- 1. We have listed 5 outlines for petrophysics.
- 1. In Timbunan Energy, we have stringent regulatory based on international standards for all safety aspects at workplace including the environmental concerns.
- EQA 1974 is on prevention, abatement, control of pollution and enhancement of the environment. Petroleum Safety is on consolidate laws relating to safety in the transportation, storage and utilization of petroleum. OSHA 1994 is mostly on workers safety. PDA 1974 about provision in matter of exploration and exploitation of petroleum. IEC manages conformity assessment systems for electric and electronic products, systems and services. ISO ENsure that products and services are safe, reliable and of good quality. API represents all aspects of America’s oil and natural gas industry.
- 1. ERP is done for risk assessment.
- 1. ERP is done for risk assessment.
- 1. KPI is used as benchmark for safety performance.