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8. 8 be dynamic www.scandpowerpt.com

9. 9 1. Dynamic Simulation

10. 10 Dynamic Simulation

11. 11 Dynamic Engineering

12. 12 Dynamic Engineering APPLIED THROUGHOUT THE PROJECT LIFE-CYCLE FIRST OIL DETAILED DESIGN PRODUCTION CONCEPT/ FEED OPERATIONS SCREENING Fluid Properties Production Profiles Well Locations Pipeline Routings Process Options AS-BUILDING As-built Profiles Tuned Models Capacity Constraints Prod. Optimisation Troubleshooting SIMULATION Operating Procedures Pipeline Management Well Management Training Simulators On-line/Off-line INTEGRATION Field Layout Well Allocations Pipeline Data Process Scheme Control Scheme

13. 13 ROUTINE CONSIDERATION OF TRANSIENT EVENTS Hydrate Inhib. Wax / Corrosion Slugging Pigging Rate Changes NORMAL PRODUCTION START-UP Start-upPressurisation Steady State PLANNED SHUTDOWN Short Term Inhibit or Displace Long Term EMERGENCY SHUTDOWN Short Term Inject Inhibitor Blowdown Cooldown

14. 14 Production Profile Development Plateau Decline Performance Measures CAPEX Well Cost Rate of Completion Well Uptime Production Volume Incremental Production OPEX Data Quality Safety & Environment Business Drivers Early Production CAPEX Minimisation Maximise Total ProductionReduce Production Decline Minimise OPEX 28 Dynamic Simulation Goals Alignment

15. Why use a transient simulator? Normal production –Sizing – tubing / pipeline diameter, insulation requirement –Stability - Is flow stable? How to achieve stable production –Gas Lifting / Compressors –Corrosion Transient operations –Shut-down and start-up, ramp-up (Liquid and Gas surges) –Pigging –Depressurisation (tube ruptures, leak sizing, etc.) –Field networks (merging pipelines / well branches with different fluids) Thermal-Hydraulics –Rate changes –Pipeline packing and de-packing –Pigging –Shut-in, blow down and start-up / Well loading or unloading –Flow assurance: Wax, Hydrate, Scale, etc.

16. 16 When things are frozen in time When not to use dynamic simulation Photo: T. Husebø

17. 17 Unstable vs. Stable flow situations Pipeline with many dips and humps: –high flow rates: stable flow is possible –low flow rates: instabilities are most likely (i.e. terrain induced) Wells with long horizontal sections – Extended Reach Low Gas Oil Ratio (GOR): –increased tendency for unstable flow Gas-condensate lines (high GOR): –may exhibit very long period transients due to low liquid velocities Low pressure –increased tendency for unstable flow Gas Lift Injection –Compressors problems, well interference, choke sizing, etc. Production Chemistry Problems –Changes in ID caused by deposition Smart Wells – Control (Opening/Closing valves/sliding sleeves) Multiphase Flow is Transient ! Well Production is Dynamic!

18. P/T Development – Flow Assurance Oil Gas Condensate Pressure Temperature LIQUID GAS GAS + LIQUID Typical phase envelopes GasOil Reservoir Temperature 70 -110 o C /160 - 230 o F Emulsion40 o C/ 104 o F 30 o C/86 o F 20 o C/68 o F WaxWater Hydrate < 0 o C/32 o F (Joule Thompson) ~ +4 o C/39 o F Temperature effects

19. 19 2. Dynamic Well Modelling

20. 20 Dynamic Well Modelling Especially suited for: Start-up and shut down of production Production from several reservoir zones Reservoir injection Analysing cross flow between reservoir zones Flow from multilateral wells Smart Wells Gas Lifting Well testing – Segregation Gas/Condensate Wells - Dewatering Simulation of fluid flow in conventional and underbalanced drilling operations Blowout simulations

21. 21 Advanced Well Module IPR models in OLGA 2000 –Constant Productivity Index –Forcheimer model –Single Forcheimer model (High Pressure Gas Wells) –Vogel equation –Backpressure equation (Gas Wells) –Normalized Backpressure (Saturated Oil Wells) –Tabulated IPR curve

22. 22 Advanced Well Module The reservoir can be divided into multiple zones with differences in properties and IPR models Properties can be defined as time series (well’s life cycle) for each zone: –Reservoir pressure –Reservoir temperature –Gas fraction / GOR –Water fraction / Water cut –Drainage radius –Skin –Fracture pressure

23. 23 Productivity Index in OLGA The following equations are used to calculate the PI for the oil, water and gas to be used by OLGA. The PI in OLGA is the TOTAL PI (the associated gas must be added to the given PI Prosper ): The GOR is given in standard cubic feet per standard barrels, the densities as kilograms per cubic meters and the water-cut in fraction Advanced Well Module

24. 24 PHASE = GAS - = STDFLOWRATE GOR The following equations show how the total mass flow is calculated in OLGA when Watercut, GOR and Volume flow are known The properties at standard condition are taken from the PVT table. PHASE = LIQUID - = STDFLOWRATE Advanced Well Module Mass Sources

25. 25 PHASE = OIL - = STDFLOWRATE GOR The following equations show how the total mass flow is calculated in OLGA when Watercut, GOR and Volume flow are known The properties at standard condition are taken from the PVT table. PHASE = WATER - = STDFLOWRATE Advanced Well Module Mass Sources

26. 26 Advanced Well Module Annular flow In annular flow there will be a higher wetted surface area compared to the flow area In OLGA 2000 a single pipeline with corresponding flow area is assumed The wall interfacial friction is calculated based on a hydraulic diameter, D h :

27. 27 Advanced Well Module Gas lift No library of commercial gas lift valves –OLGA is reasonably effective at simulating the unloading operation Specific valve characteristics or controller routines can be defined: –The LEAK command coupled with the CONTROLLER command provides a means of reasonably accurate representation of an unloading valve Casing and/or Tubing sensitive valves Concentric casing or parasite string injection –Well kick-off –Continuous GL to reduce static pressure Riser gas lifting –To reduce static pressure –To reduce / avoid slugging Stability prediction with Slugtracking Production Fluids + GL Gas Lift Production Fluids + GL

28. 28 Advanced Well Module Gas lift The OLGA bundle can be use to calculate a source temperature at injection point –e.g. gas flowing in the annulus of the CARRIER Annulus flow model with normal OLGA Branch features gives very exact countercurrent heat exchange It is possible to combine various branch models with the BUNDLE, the SOIL and FEM-Therm Branch = “GASINJ” Branch = “WELLH” Node Branch = “WELLB” Gas Injection Production Casing

29. 29 Advanced Well Module Gas lift Unloading (Duals, Check Valve Wash-out, etc.) The “Annulus’ keyword is used to model the GL annulus with a number of ‘Leaks’ installed to provide communication between the well annulus and the tubing –Each ‘Leak’ is then assigned a GLV to control the opening and closing of the valve The GLV operation is simulated using a combination of cascade and PID controllers –e.g. Pdome is modified based on temperature and depth. The output is then used to determine the Ptbg at which the GLV will open based on the local Pcsg. This is compared against the actual Ptbg to determine if the GLV is open

30. 30 3. Optimum Gas Lift Implementation Schedule

31. 31 OLGA is a powerful tool for establishing the watercut limits for which the well would not produce at steady state and where it would not kick off – investigate a future kick-off problem –Gas Lift will be required at some time in the future in order to kick-off the wells –Wells will encounter kick-off problems at a lower watercut than their their natural flow limit –Determining the kick-off limits is a key issue for determining the optimum gas lift implementation schedule The installation cost of a GL system to support the kick-off of the well is high and deferring this expenditure is of high NPV ($MM). On the other hand, the inability to kick-off the well has a high impact cost in terms of deferred production ($100MM). –Watercut limits may increase with increasing Reservoir pressures –Watercut limits are more sensitive to FTHP and PI. The matrix of results (dynamic sensitivity runs) will determine at what point in the future the well will need GL to overcome the impact of fluid segregation on kick-off (and optimum GL volume) Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

32. 32 Elevation Profile vs. Horizontal and Tubing Length –Model from Reservoir to Christmas tree – number of pipes =F(trajectory), pipe is divided into 50m section lengths Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

33. 33 Productivity Index and Oil Rate vs. Water Cut –The reservoir fluid PVT is critical to the model results –The time at which the well will not naturally kick-off is dependent on PI, Reservoir Pressure and Watercut. Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

34. 34 Watercut Limits – Steady State – OLGA vs. Prosper –The watercut limits at steady state may be found using OLGA (Transient) and Prosper (Steady State) software. Differences for the particular study case are shown below – WC predicted by Prosper are lower than predicted by OLGA Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

35. 35 Watercut Limits – Steady State vs. Kick-Off –This well will only kick-off for 20-26% lower watercuts (absolute) than it will produce at steady state (this may increase with R pressure) Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

36. 36 Watercut Limits – Steady State vs. Kick-Off –Roughness and U-value sensitivities –Low (half), Base and High (double) Overall transfer Coefficient Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

37. 37 Watercut Limits – Steady State vs. Kick-Off –FTHP and PI sensitivities –Watercut limits increase a little with increasing PI –Watercut limits are more sensitive to FTHP changes Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

38. 38 Watercut Limits – Steady State vs. Kick-Off –Temperature profiles at different points in time – base case Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

39. 39 Watercut Limits – Steady State vs. Kick-Off –Segregation during Steady State before Shut-in – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

40. 40 Watercut Limits – Steady State vs. Kick-Off –Segregation during Shut-in – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia –The apparently sudden changes in O,W & G hold-up are due to the graphs being plotted as TVD rather than along the hole. Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

41. 41 Watercut Limits – Steady State vs. Kick-Off –Segregation during Shut-in – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

42. 42 Watercut Limits – Steady State vs. Kick-Off –Segregation during Start-up – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

43. 43 Watercut Limits – Steady State vs. Kick-Off –Segregation during Start-up – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

44. 44 Watercut Limits – Steady State vs. Kick-Off –Steady State after Start-up – Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

45. 45 Watercut Limits – Steady State vs. Kick-Off –Steady State after Start-up – Watercut = 26%, Reservoir Pressure 3,000 psia, FTHP = 500 psia Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation

46. 46 Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation OLGA is a powerful tool for establishing the watercut limits for which the well would not produce at steady state and where it would not kick off – investigate a future kick-off problem –Gas Lift will be require at some time in the future in order to kick-off the wells –Wells will encounter kick-off problems at a lower watercut than their their natural flow limit –Determining the kick-off limits is a key issue for determining the optimum gas lift implementation schedule The installation cost of a GL system to support the kick-off of the well is high and deferring this expenditure is of high NPV ($MM). On the other hand, the inability to kick-off the well has a high impact cost in terms of deferred production ($100MM). –Watercut limits may increase with increasing R pressures –Watercut limits are more sensitive to FTHP and PI. The matrix of results (dynamic sensitivity runs) will determine at what point in the future the well will need GL to overcome the impact of fluid segregation on kick-off (and optimum GL volume)

47. 47 be dynamic Thank You! Any Questions?