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be dynamic

Dynamic SimulationDynamic SimulationContent

1. Dynamic Simulation2. Dynamic Simulation in Gas Lift Systems

ALRDC – 2005 Spring GAS LIFT WORSHOPRio de Janeiro – Brazil – 21-25 February

bybyby Juan Carlos Juan Carlos Juan Carlos ManteconManteconMantecon

www.scandpowerpt.com

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Dynamic Simulation

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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.

When things are frozen in time

When not to use dynamic simulation?

Photo: T. Husebø

When things are frozen in time

When not to use dynamic simulation?

Photo: T. Husebø

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• 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)

Unstable vs. Stable Flow Situations

Multiphase Flow is Transient !Multiphase Flow is Transient !Well Production is Dynamic!Well Production is Dynamic!

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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• Pigging

– Pigging the line will create a large liquid slug ahead of the pig

A: Slug build-up

B. front arrival

C. slug surface

D. Pig arrivalTime

Flo

wra

te

gas

liquidA B C D

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Flow Regime Map - Inclination: Horizontal Measured & calculated

SEPARATED

DISTRIBUTED

Potential problems for Stable multiphase flow

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Inclination impact on flow regime

Potential problems for Stable multiphase flow

Down

Horiz.

Up

SLUG FLOW

STRATIFIED

BUBBLE

Down

Horiz.

Up

SLUG FLOW

STRATIFIED

BUBBLE

Pressure impact on flow regime

Horizontal flow

20 bar

45 bar

90 bar

SLUG FLOW

STRATIFIED

BUBBLE

20 bar

45 bar

90 bar

SLUG FLOW

STRATIFIED

BUBBLE

Pressure impact on flow regimeVertical flow

SLUG FLOW

ANNULAR

BUBBLE

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• Rate Changes– Pipe line liquid inventory decreases

with increasing flow rate – Rate changes may trigger slugging

Gas Production Rate

Liq

uid

Inve

nto

ry

Initialamount

Finalamount

Amountremoved

Potential problems for Stable multiphase flow

• 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

B-Gas and Liquid Outlet Flow

A-Liquid Distribution After Shutdownshutdown

Flo

wra

te

gas

liquid

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Hydrodynamic Slugging

Frequency

Slu

g L

eng

th

b.-slug distribution

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pipe 2 pipe 3pipe 1

1 2

a.-terrain effect and slug-slug interaction

Hudson Transportation System

Potential problems for Stable multiphase flow

• 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

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• Riser-Induced Sluging

A. Slug formation

B.Slug production

C. Gas penetration

D. Gas blow-down

Liquid flow accelerates Liquid seal

Gas surge releasing high pressure Pressure build-up

Equal to static liquid head

• Terrain Slugging– A: Low spots fills with

liquid and flow is blocked

– 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

For subsea and deepwater, the fluid behavior in the flowline and risers may actually dictate the artificial

lift method, not the wellbore environment itself.

Potential problems for Stable multiphase flow Pigging-405.plt

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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

A 20 km, 16” Dubar-Alwyn flowline , riser depth 250 m

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P/T Development – Flow AssuranceTotal System Integration

Oil

Gas Condensate

Pre

ssu

re

Temperature

LIQUID

GAS

GAS + LIQUID

Typical phase envelopes

Gas OilReservoir Temperature

70 -110 oC /160 - 230oF

Emulsion 40oC/104oF

30oC/86oF

20oC/68oF

WaxWater

HydrateHydrate

< 0oC/32oF(Joule Thompson)

~ +4oC/39oF

Temperature effects

OLGA OLGA

OLGA RESERVOIRSIMULATOR(ECLIPSE)

OLGA/D-SPICE

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OPERATING ENVELOPE

0

100

200

300

400

500

600

700

800

900

1000

0 100 200 300 400 500 600 700 800 900 1000

STANDARD LIQUID RATE [Sm³]

GA

S O

IL R

AT

IO [

Sm

³/S

m³]

Stable Operating Envelope

Standard Liquid Rate [ Sm³/d]

Gas

Oil

Rat

io [

Sm

³/ S

m³

]

Hydrate Formation Temp. – 18°C

Wax Appearance Temp. – 32°C

Riser Stability – ∆P = 1 bar

Riser Stability – ∆P = 6 bar

Reservoir Pressure – 80 bara Riser Stability – ∆P = 12 bar

Gas Velocity Limit – 12 m/s

Erosional Velocity Limits

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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

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Well Heading Problems

Heading / Instabilities / Slugging

• Slugging on Start up

• Tubing heading phenomenon

• Casing heading phenomenon (no packer)

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Interaction Between Downhole & Surface Orifice

• C a s in g h e a d i n g m a y h a p p e n

• T o t h o r o u g h l y e lim ina te c a s i n g h e a d i n g , m a k e t h e g a s inject ion critica l

If g a s in je c t io n is not cr i t ica l. . .

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Interaction Between Downhole & Surface Orifice

Is the well unconditionally stable if gas injection is critical?

Replace the orifice with a venturi

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Density Wave Instability

Stability map (L=2500m, PI=4e-6kg/s/Pa, Psep=10bara, 100% choke opening, ID=0.125m)

0,000,050,100,150,200,250,300,350,400,450,500,550,600,650,700,750,800,850,900,951,001,051,101,151,201,25

30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230 240 250 260 270 280 290 300 310

PR-Psep (bar)

Gas

inje

ctio

n ra

te (k

g/s)

Density wave instability can occur!

• Increasing reservoir pressure and gas injection rate increases stability.

• Increasing well depth, tubing diameter, PI and system pressure decreases stability

• Instability occurs only when

1<−

gL

PP

l

sepR

ρ

SPE 84917

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Advanced Well ModellingGas 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

• Compressor-Well – Gas injection Flowline• Stability prediction + Slugtracking• Compositional Tracking

ProductionFluids + GL

Gas Lift

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Typical Gas Lift Well Configuration

Mud line

Sea level

Injection Gas

Production Fluid

Production Fluid + Injection Gas

Orifice at Injection Point

Unloading Valves

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Modelling concerns:

Mud line

Sea level

a) Annular Flow

b) Heat Transfer

c) Non-constant Composition in Tubing above Injection Point

d) Unloading ValvesOperation

Typical Gas Lift Well Configuration

Gas Lift is clearly a transient problem

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Modelling concerns:

a) Annular Flow

b) Heat TransferProduction

Branch = “GASINJ”

Branch = “WELLH”NodeBranch = “WELLB”

Gas Injection

Casing

Full description of annular / tubingflow interactions for flow and heat transfer phenomena

ANNULUS flow model gives very exact counter-current heat exchange

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c) Non-constant Composition in Tubing above Injection Point

Trend data

Standard OLGACompTrack OLGA

kg/s

40

35

30

25

20

15

10

5

0

Time [h]76.565.554.543.5

Liquid unloading (form of slugging) – Fluid composition varies

Liquid Flowrate at the Wellhead

CompTrack will better account for effects of changing composition in the tubing

Modelling concerns:

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Mud line

Sea level

Previously modelled as CONTROLLERs

d) Unloading ValvesOperation

Unloading valve tables can be incorporated

Modelling concerns:

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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

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AC PC

PT

PD

AD

AT

• Valve open when tubing above is full of liquid (liquid weight > opening pressure)

• Valve closes when liquid column weight above location is reduced (< closing pressure)

• Controlled (mostly) by casing pressure

• Valve closure “ripples” down string

• When well unloaded, only orifice at bottom open

Gas Lift Valves (Most Common Configuration)

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Graphical Steady-State Method

P. Gradient in the Tubingat desired conditions

P. Gradient in the Casing (gas-filled)

P. Gradient of liquid-filledcolumn in the tubing

Safety MarginAPI

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Gas Lift Valve Performance

Orifice RegionThrottling Region

1 curve per each Casing Injection Pressure

API

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Tabular Valve Performance

!*******************************************************************************!- TABLE Definition!-------------------------------------------------------------------------------!TABLE LABEL=GLV-1, XVARIABLE=PRODUCTIONPRESS PSIA, YVARIABLE=STDGASFLOW MMSCF/D, INJECTIONPRESS=2600 PSIATABLE 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

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Results of OLGA SimulationComparison of Zero, One, and Two Unloadiing Valves

Compressor Discharge Pressure - No Unloading ValvesCompressor Discharge Pressure - One Unloading Valve

Compressor Discharge Pressure - Two Unloading ValvesLiquid Production Rate - No Unloading Valves

Liquid Production Rate - One Unloading ValveLiquid Production Rate - Two Unloading Valves

psia

3500

3000

2500

2000

1500

1000

500

bbl/d

20000

15000

10000

5000

0

-5000

Time [h]54.543.532.521.510.50

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0

1000

2000

3000

4000

5000

6000

0 5 10 15 20 25 30

Time [h]

Oil

rate

[b

bl/d

]

0.0

0.5

1.0

1.5

2.0

2.5

Gas

lift

[M

Msc

fd]

Gas lift rate Oil rate

Gas Lift – One Injection PointOil Production

60°F

250°F, 3300 psia and 3 bbl/psi

10000 ft

GOR = 500 scf/bbl

3 1/2”

5 1/2”

500 psia sep press

Choke at injection point

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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 wellboreunloading (gas lift valve tables can be used as input)

• Hydraulics, heat transfer and changes in fluid compositionare also taken into account

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Advanced Well ModellingGas Lift

Pigging-405.plt

W1 W2 W3 W4

PCV

LCV

Production Separator

PC

LC

Gas Outlet

Liquid Outlet

Emergency Liquid Outlet

Emergency Drain Valve

ID=2 m, Length=6 mNLL=0.842 mHHLL=1.687LLLL=0.315

Riser

Annulus

Gas LiftID=8-in, Depth=120 m

ID=8-in, Length=4.6 km

Depth=2840 m

Tubing ID=0.1143 m

ID=0.2159 m

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Gas Lift Well Modelling – Real Time

Operation parameters can be modified

Impact on the results is instantaneous

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be dynamic

Thank You! Any Questions?