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1 Dynamic Simulation Content 1. Dynamic Simulation 2. Dynamic Simulation in Gas Lift Systems ALRDC 2005 Spring GAS LIFT WORSHOP Rio de Janeiro Brazil February be dynamic by Juan Carlos Mantecon by 1

2 Dynamic Simulation 2

3 When not to use dynamic simulation? Why use a transient simulator? Normal production Sizing diameter, insulation requirement Stability - Is flow stable? 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. 3 When things are frozen in time Photo: T. Huse

4 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, 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! 4 Well Production is Dynamic!

5 Usual Potential problems for Stable multiphase flow Inclination / Elevation Snake profile Risers Rate changes Condensate Liquid content in gas Shut-in / Start up Pipeline blow down A: Slug build-up Pigging Pigging the line will create B. front arrival a large liquid slug ahead of the pig C. slug surface Flowrate gas liquid A B C D D. Pig arrival Time 5

6 Potential problems for Stable multiphase flow Flow Regime Map - Inclination: Horizontal Measured & calculated SEPARATED DISTRIBUTED 6

7 Potential problems for Stable multiphase flow Inclination impact on flow regime Pressure impact on flow regime Horizontal flow Pressure impact on flow regime Vertical flow BUBBLE BUBBLE BUBBLE SLUG FLOW SLUG FLOW 90 bar SLUG FLOW Horiz. Down Up STRATIFIED 45 bar STRATIFIED 20 bar ANNULAR 7

8 Potential problems for Stable multiphase flow Liquid Inventory Rate Changes Pipe line liquid inventory decreases with increasing flow rate Rate changes may trigger slugging Initial amount Amount removed Final amount Shut-In - Restart Liquid redistributes due to gravity during shut-in On startup, slugging can occur as flow is ramped up Shut-In - Restart Liquid redistributes due to gravity during shut-in On startup, slugging can occur as flow is ramped up A-Liquid Distribution After Shutdown shutdown gas liquid Flowrate Gas Production Rate 8 B-Gas and Liquid Outlet Flow

9 Potential problems for Stable multiphase flow Hydrodynamic Slugging Slug Length pipe 1 pipe 2 pipe a.-terrain effect and slug-slug interaction Two-phase flow pattern maps indicate hydrodynamic slugging, but slug length correlations are quite uncertain tracking of the development of the individual slugs along the pipeline is necessary to estimate the volume of the liquid surges out of the pipelines Hudson Transportation System Frequency b.-slug distribution 9

10 Potential problems for Stable multiphase flow Pigging-405.plt Riser-Induced Sluging Terrain Slugging A: Low spots fills with liquid and flow is blocked A. Slug formation Liquid seal C. Gas penetration Liquid flow accelerates B: Pressure builds up behind the blockage C&D: When pressure becomes high enough, gas blows liquid out of the low spot as a slug B.Slug production Pressure build-up Equal to static liquid head D. Gas blow-down Gas surge releasing high pressure For subsea and deepwater, the fluid behavior in the flowline and risers may actually dictate the artificial lift method, not the wellbore environment itself. 10

11 Slug Mitigation Method Increase GL gas rate Reduction of flowline and/or riser diameter Splitting the flow into dual or multiple streams Gas injection in the riser Use of mixing devices at the riser base Subsea separation (requires two separate flowlines and a liquid pump Internal small pipe insertion (intrusive solution) External multi-entry gas bypass Choking (reduce production capacity) Increase of backpressure External bypass line Foaming 11

12 OLGA/D-SPICE P/T Development Flow Assurance Total System Integration OLGA Typical phase envelopes OLGA RESERVOIR SIMULATOR (ECLIPSE) Temperature effects LIQUID Gas Condensate Gas Pressure OLGA Oil Reservoir Temperature oc / oF Emulsion Oil 40oC/ 104oF Water Wax 30oC/86oF Hydrate Hydrate 20oC/68oF GAS GAS + LIQUID ~ +4oC/39oF < 0oC/32oF (Joule Thompson) Temperature 12

13 OPERATING ENVELOPE GAS OIL RATIO [Sm³/Sm³] Gas Oil Ratio [Sm³/ Sm³ ] Standard STANDARD Liquid LIQUID Rate RATE [[Sm³] Sm³/d] Hydrate Formation Temp. 18 C Wax Appearance Temp. 32 C Reservoir Pressure 80 bara Riser Stability P = 1 bar Riser Stability P = 6 bar Riser Stability P = 12 bar Gas Velocity Limit 12 m/s Erosional Velocity Limits Stable Operating Envelope 13

14 WELL DYNAMICS Minimum stable flow rates / Slug Mitigation Tubing sizing Flow assurance, Wax, Hydrates / Corrosion rates Artificial Lift design and optimisation Gas Lift Unloading Compressors shut-down ESP sizing / Location Start-up/Shut-in Commingling Fluids Multiple completions / Multilateral Wells / Smart Wells Loading/unloading Condensate/Water Thermal transients Water accumulation studies Location of SCSSV MeOH/Glycol requirements Well Testing Wellbore Storage effects / Segregation effects 14

15 Well Heading Problems Heading / Instabilities / Slugging Slugging on Start up Tubing heading phenomenon Casing heading phenomenon (no packer) 15

16 Interaction Between Downhole & Surface Orifice If gas injection is not critical... Casing heading may happen To thoroughly eliminate casing heading, make the gas injection critical 16

17 Interaction Between Downhole & Surface Orifice Is the well unconditionally stable if gas injection is critical? Replace the orifice with a venturi 17

18 Density Wave Instability Stability map (L=2500m, PI=4e -6 kg/s/pa, P sep =10bara, 100% choke opening, ID=0.125m) Gas injection rate (kg/s) 1,25 1,20 1,15 1,10 1,05 1,00 0,95 0,90 0,85 0,80 0,75 0,70 0,65 0,60 0,55 0,50 0,45 0,40 0,35 0,30 0,25 0,20 0,15 0,10 0,05 0,00 Density wave instability can occur! P R -P sep (bar) Increasing reservoir pressure and gas injection rate increases stability. Increasing well depth, tubing diameter, PI and system pressure decreases stability Instability occurs only when P R SPE ρ P l gl sep < 1 18

19 Advanced Well Modelling Gas Lift No library of commercial gas lift valves Table input Reasonably effective at simulating the unloading operation 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 Gas Lift Production Fluids + GL Compressor-Well Gas injection Flowline Stability prediction + Slugtracking Compositional Tracking 19

20 Typical Gas Lift Well Configuration Sea level Injection Gas Mud line Production Fluid + Injection Gas Unloading Valves Production Fluid Orifice at Injection Point 20

21 Typical Gas Lift Well Configuration Sea level Modelling concerns: Mud line a) Annular Flow b) Heat Transfer c) Non-constant Composition in Tubing above Injection Point d) Unloading Valves Operation Gas Lift is clearly a transient problem 21

22 Modelling concerns: a) Annular Flow Production Gas Injection Casing Branch = GASINJ Branch = WELLH Node Branch = WELLB b) Heat Transfer ANNULUS flow model gives very exact counter-current heat exchange Full description of annular / tubing flow interactions for flow and heat transfer phenomena 22

23 Modelling concerns: Liquid Flowrate Trend at data the Wellhead Standard OLGA CompTrack OLGA c) Non-constant Composition in Tubing above Injection Point kg/s CompTrack will better account for effects of changing composition in the tubing Time [h] Liquid unloading (form of slugging) Fluid composition varies 23

24 Modelling concerns: Sea level d) Unloading Valves Operation Mud line Previously modelled as CONTROLLERs Unloading valve tables can be incorporated 24

25 Well Unloading Dynamic Simulation Following a well workover, tubing and casing are frequently filled with liquid Liquid unloaded by injection of gas at casing-head Placement and sizing of unloading valves currently performed by approximate steady-state methods A transient multiphase simulation can permit more detailed simulation of unloading process Troubleshooting can be more efficient using dynamic simulation 25

26 Gas Lift Valves (Most Common Configuration) Valve open when tubing above is full of liquid (liquid weight > opening pressure) AC PD AD PC Valve closes when liquid column weight above location is reduced (< closing pressure) PT AT Controlled (mostly) by casing pressure Valve closure ripples down string When well unloaded, only orifice at bottom open 26

27 Graphical Steady-State Method P. Gradient of liquid-filled column in the tubing P. Gradient in the Casing (gasfilled) P. Gradient in the Tubing at desired conditions API Safety Margin 27

28 Gas Lift Valve Performance Throttling Region Orifice Region 1 curve per each Casing Injection Pressure API 28

29 Tabular Valve Performance!***************************************************** **************************!- TABLE Definition! ! TABLE LABEL=GLV-1, XVARIABLE=PRODUCTIONPRESS PSIA, YVARIABLE=STDGASFLOW MMSCF/D, INJECTIONPRESS=2600 PSIA TABLE POINT=(1600,0) TABLE POINT=(1700,0.2) TABLE POINT=(1800,0.4) TABLE POINT=(1900,0.6) TABLE POINT=(2000,0.8) TABLE POINT=(2100,1) TABLE POINT=(2200,.8) TABLE POINT=(2300,.6) TABLE POINT=(2400,.4) TABLE POINT=(2500,.2) TABLE POINT=(2600,0) API! 29

30 Results of OLGA Simulation Comparison of Zero, One, and Two Unloadiing Valves Compressor Discharge Pressure - No Unloading Valves Compressor Discharge Pressure - One Unloading Valve Compressor Discharge Pressure - Two Unloading Valves Liquid Production Rate - No Unloading Valves Liquid Production Rate - One Unloading Valve Liquid Production Rate - Two Unloading Valves psia 2000 bbl/d Time [h]

31 Gas Lift One Injection Point Oil Production 500 psia sep press 3 1/2 60 F Gas lift rate Oil rate / ft Oil rate [bbl/d] Choke at injection point R = 500 scf/bbl F, 3300 psia and 3 bbl/psi Time [h] 31

32 Conclusions Steady-state methods do not capture the transients that inevitably occur in an operating gas lifted well Transient well response occurs during: - Unloading the well - Well shut-down - Normal well operation - Compressor shut-down and injection fluctuations Dynamic Simulation can be used to simulate wellbore unloading (gas lift valve tables can be used as input) Hydraulics, heat transfer and changes in fluid composition are also taken into account 32

33 Advanced Well Modelling Gas Lift Pigging-405.plt Gas Lift ID=8-in, Depth=120 m ID=8-in, Length=4.6 km Annulus ID= m Depth=2840 m PC PCV Gas Outlet W1 W2 W3 W4 Tubing ID= m ID=2 m, Length=6 m NLL=0.842 m HHLL=1.687 LLLL=0.315 LC Riser Production Separator LCV Liquid Outlet Emergency Drain Valve Emergency Liquid Outlet 33

34 Gas Lift Well Modelling Real Time Operation parameters can be modified Impact on the results is instantaneous 34

35 be dynamic Thank You! 35 Any Questions?

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