3_ScandPower_Watercut

*be dynamicImpact of Dynamic Modelling on The Optimum GL Implementation ScheduleContent Dynamic Simulation Dynamic Well Modelling Optimum Gas Lift Implementation Schedule

ALRDC 2004 Spring GAS LIFT WORSHOP

by Juan Carlos Manteconwww.scandpowerpt.com

*1. Dynamic Simulation

*Dynamic Simulation

*Dynamic Engineering

*Dynamic EngineeringAPPLIED THROUGHOUT THE PROJECT LIFE-CYCLEFIRST OILDETAILEDDESIGNPRODUCTIONCONCEPT/FEEDOPERATIONSSCREENING Fluid Properties Production Profiles Well Locations Pipeline Routings Process OptionsAS-BUILDING As-built Profiles Tuned Models Capacity Constraints Prod. Optimisation TroubleshootingSIMULATION Operating Procedures Pipeline Management Well Management Training Simulators On-line/Off-line

INTEGRATION Field Layout Well Allocations Pipeline Data Process Scheme Control Scheme

*ROUTINE CONSIDERATION OF TRANSIENT EVENTSHydrate Inhib.Wax / Corrosion Slugging PiggingRate ChangesNORMALPRODUCTION Steady State

*ProductionProfileDevelopment Plateau DeclinePerformanceMeasuresCAPEXWell CostRate of CompletionWell UptimeProduction VolumeIncremental ProductionOPEXData QualitySafety & EnvironmentBusinessDriversEarly ProductionCAPEX MinimisationMaximise Total ProductionReduce Production DeclineMinimise OPEX28Dynamic SimulationGoals Alignment

Why use a transient simulator?Normal productionSizing tubing / pipeline diameter, insulation requirementStability - Is flow stable? How to achieve stable productionGas Lifting / CompressorsCorrosionTransient operationsShut-down and start-up, ramp-up (Liquid and Gas surges)PiggingDepressurisation (tube ruptures, leak sizing, etc.)Field networks (merging pipelines / well branches with different fluids)Thermal-Hydraulics Rate changesPipeline packing and de-packingPiggingShut-in, blow down and start-up / Well loading or unloadingFlow assurance: Wax, Hydrate, Scale, etc.

*When things are frozen in timeWhen not to use dynamic simulationPhoto: T. Huseb

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

P/T Development Flow AssuranceTemperature effects

*2. Dynamic Well Modelling

*Dynamic Well Modelling Especially suited for:

Start-up and shut down of productionProduction from several reservoir zonesReservoir injectionAnalysing cross flow between reservoir zonesFlow from multilateral wellsSmart WellsGas LiftingWell testing SegregationGas/Condensate Wells - DewateringSimulation of fluid flow in conventional and underbalanced drilling operationsBlowout simulations

*Advanced Well Module IPR models in OLGA 2000

Constant Productivity IndexForcheimer modelSingle Forcheimer model (High Pressure Gas Wells)Vogel equationBackpressure equation (Gas Wells)Normalized Backpressure (Saturated Oil Wells)Tabulated IPR curve

*Advanced Well ModuleThe reservoir can be divided into multiple zones with differences in properties and IPR models

Properties can be defined as time series (wells life cycle) for each zone:Reservoir pressureReservoir temperatureGas fraction / GORWater fraction / Water cutDrainage radiusSkinFracture pressure

*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

Advanced Well Module

*PHASE = GAS - = STDFLOWRATE

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 ModuleMass Sources

*PHASE = OIL - = STDFLOWRATE

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 ModuleMass Sources

*Advanced Well ModuleAnnular 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:

*Advanced Well ModuleGas lift

No library of commercial gas lift valvesOLGA 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 valveCasing and/or Tubing sensitive valves

Concentric casing or parasite string injectionWell kick-off Continuous GL to reduce static pressure

Riser gas liftingTo reduce static pressureTo reduce / avoid slugging

Stability prediction with Slugtracking

*Advanced Well ModuleGas lift

The OLGA bundle can be use to calculate a source temperature at injection pointe.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

*Advanced Well ModuleGas 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 tubingEach 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 controllerse.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

*3. Optimum Gas Lift Implementation Schedule

*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 wellsWells will encounter kick-off problems at a lower watercut than their their natural flow limitDetermining the kick-off limits is a key issue for determining the optimum gas lift implementation scheduleThe 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 pressuresWatercut 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 ModellingWatercut Limit for Kick-off / Shut-in Segragation

*Elevation Profile vs. Horizontal and Tubing LengthModel from Reservoir to Christmas tree number of pipes =F(trajectory), pipe is divided into 50m section lengths


Well #SPT69

-3000

-2500

-2000

-1500

-1000

-500

0

0

500

1000

1500

2000

2500

3000

3500

Position [m]

Elevation [m]

Horizontal Length

Pipeline Length

Top of tubing

Top of tubing

Reservoir

*Productivity Index and Oil Rate vs. Water CutThe reservoir fluid PVT is critical to the model resultsThe time at which the well will not naturally kick-off is dependent on PI, Reservoir Pressure and Watercut.


Well SPT69 - FTHP = 500 psia

0

5,000

10,000

15,000

20,000

25,000

0

10

20

30

40

50

60

70

Watercut [%]

Oil Rate [STB/D]

2500 psia

3000 psia

3500 psia

3600 psia

3800 psia

Well SPT69

0

5

10

15

20

25

30

35

40

45

0

10

20

30

40

50

60

70

80

90

Watercut [%]

Production Index [bbls/d/psia]

*Watercut Limits Steady State OLGA vs. ProsperThe 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



27

31

39

47

54

28

36

44

52

62

0

10

20

30

40

50

60

70

2700

2900

3100

3300

3500

3700

Reservoir Pressure [psia]

Water-cut [%]

Prosper

OLGA 2000

*Watercut Limits Steady State vs. Kick-OffThis well will only kick-off for 20-26% lower watercuts (absolute) than it will produce at steady state (this may increase with R pressure)



28

36

44

52

62

0

10

24

32

38

0

10

20

30

40

50

60

70

2500

2900

3100

3300

3500

3700

Reservoir pressure [psia]

Watercut [%]

Steady state

Kick-off

*Watercut Limits Steady State vs. Kick-OffRoughness and U-value sensitivitiesLow (half), Base and High (double) Overall transfer Coefficient


Well SPT69 - 3000 psia reservoir pressure

46

44

44

26

24

24

0

5

10

15

20

25

30

35

40

45

50

0.0006

0.001

0.002

Roughness [inch]

Watercut [%]

Steady state

Kick-off


44

44

44

24

24

22

0

5

10

15

20

25

30

35

40

45

50

Low

Base

High

U-value

Watercut [%]

Steady state

Kick-off

*Watercut Limits Steady State vs. Kick-OffFTHP and PI sensitivitiesWatercut limits increase a little with increasing PIWatercut limits are more sensitive to FTHP changes



40

44

48

20

24

28

0

10

20

30

40

50

60

Low

Base

High

Productivity Index

Watercut [%]

Steady state

Kick-off


60

44

28

38

24

6

0

10

20

30

40

50

60

70

500.00

700.00

900.00

FTHP [psia]

Watercut [%]

Steady state

Kick-off

*Watercut Limits Steady State vs. Kick-OffTemperature profiles at different points in time base case


Well SPT69 at 3000 reservoir pressure and 20% WC

0

20

40

60

80

100

120

0

500

1000

1500

2000

2500

3000

3500

Pipeline length [m]

Temperature [C]

Steady state

1 hour after shut-in

3 hours after shut-in




*Watercut Limits Steady State vs. Kick-OffSegregation during Steady State before Shut-in Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


*Watercut Limits Steady State vs. Kick-OffSegregation during Shut-in Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psiaThe apparently sudden changes in O,W & G hold-up are due to the graphs being plotted as TVD rather than along the hole.


*Watercut Limits Steady State vs. Kick-OffSegregation during Shut-in Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


*Watercut Limits Steady State vs. Kick-OffSegregation during Start-up Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


*Watercut Limits Steady State vs. Kick-OffSteady State after Start-up Watercut = 20%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


*Watercut Limits Steady State vs. Kick-OffSteady State after Start-up Watercut = 26%, Reservoir Pressure 3,000 psia, FTHP = 500 psia


*Dynamic Wells ModellingWatercut 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 wellsWells will encounter kick-off problems at a lower watercut than their their natural flow limitDetermining the kick-off limits is a key issue for determining the optimum gas lift implementation scheduleThe 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 pressuresWatercut 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)

*be dynamicThank You! Any Questions?

*****Typical oil & gas phase envelopes are displayed to capture the differences between gas and oil systems.

Remember that standard conditions are 14.7 psia and 60 F

**

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