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Impact of Dynamic Modelling on The Optimum GL Implementation Schedule Content Dynamic Simulation Dynamic Well Modelling Optimum Gas Lift Implementation Schedule ALRDC – 2004 Spring GAS LIFT WORSHOP by Juan Carlos Mantecon. be dynamic. www.scandpowerpt.com. 1. Dynamic Simulation.

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  1. Impact of Dynamic Modelling on The Optimum GL Implementation Schedule Content • Dynamic Simulation • Dynamic Well Modelling • Optimum Gas Lift Implementation Schedule ALRDC – 2004 Spring GAS LIFT WORSHOP by Juan Carlos Mantecon be dynamic www.scandpowerpt.com

  2. 1. Dynamic Simulation

  3. Dynamic Simulation

  4. Dynamic Engineering

  5. Dynamic Engineering • SCREENING • Fluid Properties • Production Profiles • Well Locations • Pipeline Routings • Process Options • INTEGRATION • Field Layout • Well Allocations • Pipeline Data • Process Scheme • Control Scheme CONCEPT/ FEED PRODUCTION OPERATIONS DETAILED DESIGN • 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 FIRST OIL APPLIED THROUGHOUT THE PROJECT LIFE-CYCLE

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

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

  8. 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.

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

  10. Multiphase Flow is Transient !Well Production is Dynamic! 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)

  11. Typical phase envelopes LIQUID Gas Condensate Reservoir Temperature 70 -110 oC /160 - 230oF Gas Oil Pressure Emulsion 40oC/104oF Oil Water Wax 30oC/86oF GAS Hydrate Hydrate 20oC/68oF GAS + LIQUID ~ +4oC/39oF < 0oC/32oF (Joule Thompson) Temperature P/T Development – Flow Assurance Temperature effects

  12. 2. Dynamic Well Modelling

  13. 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

  14. 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

  15. 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

  16. Advanced Well Module 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 PIProsper):The GOR is given in standard cubic feet per standard barrels, the densities as kilograms per cubic meters and the water-cut in fraction

  17. Advanced Well Module Mass Sources • 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 = GAS - = STDFLOWRATE PHASE = LIQUID - = STDFLOWRATE

  18. Advanced Well Module Mass Sources • 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 = OIL - = STDFLOWRATE PHASE = WATER - = STDFLOWRATE

  19. 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, Dh:

  20. Gas Lift Production Fluids + GL Production Fluids + GL 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

  21. Production Gas Injection Casing Branch = “GASINJ” Branch = “WELLH” Node Branch = “WELLB” 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

  22. 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

  23. 3. Optimum Gas Lift Implementation Schedule

  24. 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 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)

  25. Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation • 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

  26. Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation • 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.

  27. Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation • 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

  28. Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation • 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)

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

  30. Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation • 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

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

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

  33. Dynamic Wells Modelling Watercut Limit for Kick-off / Shut-in Segragation • 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.

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

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

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

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

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

  39. 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)

  40. be dynamic Thank You! Any Questions?

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