dynamic simulation best practice - alrdc · 3 • dynamic simulations provide valuable information...
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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