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Dynamic SimulationDynamic SimulationBest PracticeBest Practice

bybyby Juan Carlos ManteconJuan Carlos ManteconJuan Carlos Mantecon

www.scandpowerpt.com

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• Dynamic modelling standard best practice recommendations are required for the development of “offshore and subsea” fields, in order to effectively build and use models to optimise the design and operation of the field during its productive life.

• The unique features and flow assurance requirements of offshore/subsea wells and flowlines, along with the high associated capital costs, clearly merit detailed dynamic analysis for design development.

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• Dynamic simulations provide valuable information for savings and reduction of potential problems (risk reduction) during well completions and production system kick-off operations.

• The knowledge of the minimum flow rates required to clean up the wells will have relevant implications on equipment selection (size) and therefore cost minimisation.

• Furthermore, the ability to predict (what if cases) and be prepared to deal with potential problems (or GL need) not only can save millions of dollars but can minimise any environmental impact.

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Dynamic Simulation

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What’s a Dynamic 3-phase Flow SimulatorA set of coupled first order non-linear, one dimensional partial differential equations, with rather complex coefficients

8 Field Equations

Fluid Properties

Conservation of mass (5)Conservation of Momentum (2)

Conservation of energy (1)

Closure Laws

Mass TransferMomentum Transfer

Energy Transfer

BoundaryConditions

Initial Conditions

Numerical solution scheme: semi-implicit integration method –allows for relatively long time steps with efficient run times

Closure laws are semi-mechanistic and required experimental verification

Two momentum equations are used: 1) a combined one for the Gas and possible Liquid droplets, 2) a separate one for the Liquid film

Separate continuity equations for the Gas, Liquid bulk andLiquid dropletscoupled through interphasialmass transfer.

A mixture energy conservation equation is applied. Dynamic

Simulator

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1 2 543

1 2 543

1,2,3,…,5 (inside) : section volumes

1,2,3,…,6 (outside): section boundaries

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100m - 2 pipes - 8.861" 160 m MODU ID WallP13 P12

P11 8.861" Wall Riser-air130 m Sea Level

P10 8.861" Wall Riser-seaOlga 0 m SS Tree 7.0625"

Wellhead 6.25"Riser P9 6.184" Wall 1

70 SCSSV 6.25"Wellbore

P8 8.861" Wall 70345 m 20" Csg shoe

P7 8.861" Wall 3451100 m TOC

P6 8.861" Wall 11001950 m Mandrel 6.18"

P5 6.765" Wall 19502000 m Nipple 5.75"

P4 8.681" Wall 20002100 m

P3 8.681" Wall 21002850 m

P2 6.184" Wall 28503000 m

P1 6.184" Wall Reservoir3050 m

Well XX14 - OLGA Wellbore Model

Steel

Cement

Formation

MD 4935.9 m

MD 3153.8 m

BRANCH: WELL-LOWWALL: Tubing-3

MD 2766.1 m BRANCH: WELL-LOWWALL: Tubing-2

MD 1432.2 m

BRANCH: WELL-UPPWALL: Tubing-1

-3500

-3000

-2500

-2000

-1500

-1000

-500

0

-3500 -3000 -2500 -2000 -1500 -1000 -500 0

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Convection

Conduction

Radiation in annulus (Minor Effect)P, T Q

1 D - Well 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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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)

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Transient vs. Steady State

• The weak points of NODAL analysis SS software when compare with Dynamic (Transient) numerical simulation are:

• Slugging Prediction – terrain induced slugging

• Flow Regime Map – inclination, horizontal flow, etc.

• Black oil• Use of correlations• SS conditions only

• Flow assurance• Start-up / shut-down• Corrosion• Chemical injection

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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

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Potential problems for Stable multiphase flowFlow Regime Map - Inclination: Horizontal Measured & calculated

SEPARATED

DISTRIBUTED

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Potential problems for Stable multiphase flow

Pressure impact on flow regime

Horizontal flow

Pressure impact on flow regimeVertical flow

Inclination impact on flow regime

Down

Horiz.

Up

SLUG FLOW

STRATIFIED

BUBBLE

Down

Horiz.

Up

SLUG FLOW

STRATIFIED

BUBBLE

20 bar

45 bar

90 bar

SLUG FLOW

STRATIFIED

BUBBLE

20 bar

45 bar

90 bar

SLUG FLOW

STRATIFIED

BUBBLE

SLUG FLOW

ANNULAR

BUBBLE

Slug flow area decreases with increasing pressureSlug flow area increases with

increasing upward inclination

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Potential problems for Stable multiphase flow

• Rate Changes– Pipe line liquid inventory decreases

with increasing flow rate – Rate changes may trigger slugging

Gas Production Rate

Liqu

id In

vent

ory

Initialamount

Finalamount

Amountremoved

• 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 Shutdown

Flow

rate

gasliquid

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Potential problems for Stable multiphase flowHydrodynamic Slugging (Slip between liquid and gas phase)

Frequency

Slug

Len

gth

b.-slug distribution

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pipe 2 pipe 3pipe 1

1 2

a.-terrain effect and slug-slug interaction

Hudson Transportation System

• 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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Pigging-405.pltPotential problems for Stable multiphase flow

• 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 pressurePressure 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.

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Oil

Gas Condensate

Pres

sure

Temperature

LIQUID

GAS

GAS + LIQUID

Typical phase envelopes

Gas OilReservoir Temperature

70 -110 oC /160 - 230oF

Emulsion 40oC/104o

F30oC/86oF

20oC/68oF

WaxWater

HydrateHydrate

< 0oC/32oF(Joule Thompson)

~ +4oC/39oF

Temperature effects

P/T Development – Flow AssuranceTotal System Integration

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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 [S

m³/S

m³]

Stable Operating Envelope

Standard Liquid Rate [ Sm³/d]

Gas

Oil

Rat

io [S

m³/

Sm³]

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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Interaction Between Downhole & Surface GL Orifice

� C asing heading may happen

� To thoroughly eliminate casing heading, make the gas injection critical

If gas injection is not critical...

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Interaction Between Downhole & Surface GL OrificeIs the well unconditionally stable if gas injection is critical?

Replace the orifice with a venturi

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Density Wave InstabilityStability 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, P I and system pressure decreases stability

�Instability occurs only when

1<−

gLPP

l

sepR

ρ

SPE 84917

Two-phase vertical flow under gravity domination often is unstable, particularly in gas lift wells.

Because the gas-injection rate is constant, any variation in liquid inflow into the wellbore will result in a density change in the two-phase mixture in the tubing. The mixture-density change results in a change in the hydrostatic pressure drop. The mixture-density change travels along the tubing as a density wave.

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Advanced Well ModellingGas Lift

• Unloading Gas Lift – GLV performance Table input– Reasonably effective at simulating the unloading operation

• Continuous 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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Typical Gas Lift Well Configuration

Mud line

Sea level Modelling concerns:

a) Annular Flow

b) Heat Transfer

c) Non-constant Composition in Tubing above Injection Point

d) Unloading ValvesOperation

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 Flowrate at the Wellhead

Modelling concerns:

Liquid unloading (form of slugging) – Fluid composition varies

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

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Modelling concerns:

Mud line

Sea leveld) Unloading ValvesOperation

Modelled as choke-leak and Table input of VPC

VPC software can be incorporated

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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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0

1000

2000

3000

4000

5000

6000

0 5 10 15 20 25 30

Time [h]

Oil

rate

[bbl

/d]

0.0

0.5

1.0

1.5

2.0

2.5

Gas

lift

[MM

scfd

]

Gas lift rate Oil rate60°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

Gas Lift – One Injection Point - CGLOil Production

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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

• Dynamic (flow) Modelling can be an invaluable tool when properly applied (flow assurance, predict fluid properties, etc.) – standard best practice recommendations are required

31Thank You! Any Questions?

be dynamic