3 Intro to Flow Assurance Upd
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INTRODUCTION TO FLOW ASSURANCE
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What can stop or reduce the production ?
•Blockage of pipe by
– Hydrates
– Wax
Flow Instabilities
Accidentsand Disasters
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Hydrates are
• Crystals of water and
gas molecules.Or more simply: ice ofwater andhydrocarbons
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Hydrates continued
• Hydrates form (andmelt ) at elevated T at
high P – thus theycan block wells andpipes.
Predicted hydrate curvefor gas-condensate with
water cut of 5%
0
100
200
0 20 40
T (C)
P (
b a r a )
Prediction of formationin real fluids areuncertain.
They can take manyforms- from slushy,sticky lumps to a finepowder
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Hydrate wheel – operated by SINTEF
Video c am era is
f ix ed on t he w hee l
Used for hydrate predictions for real
fluids at real P and T
w hee l is rot aded
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SINTEF hydrate wheel
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Inhibition
• Common inhibitors are:
“Thermodynamic” i.e. they move the melting curve
of the hydrates towards lower T:• Alcohols (MeOH)
• Glycols (Mono Ethylene Glycol – MEG)
• New inhibitors LDHI (Low Dosage Hydrate Inhibitors)modify crystal growth or crystal structure to avoidblockage.
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Hydrate curves with MEG - inhibition
0
25
50
75
100
125
150
175
200
0 5 10 15 20 25
T (C)
P ( B A
R A )
0 MEG0.33 kg MEG/kg H2O
0.67 kg MEG/kg H2O
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Example: gas condensate:
Flow rate 200 MMScfd,Saturated with water at 160 bara and 95 C
WC = 0GOR ≈ 1300 Sm3/Sm3
Pipe not insulated
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Effect of MEG-inhibition
0 kg MEG/kg H2O
0.33 ”
0.67 ”
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Wax
• Solid paraffins from hydrocarbon fluids.
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• When the fluid is cooled wax will form at the WaxAppearance Temperature (WAT)
• When further cooled wax increase the viscosity tothe point where the oil forms a gel i.e. reaches its Pour
Point.
WAT and Pour Point
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An example
Oil pipeline: 142 km long, ID = 0.32 m
Inlet flow: 69 kg/s, Tinlet = 55 CT ambient: 4 to 5 C
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Wax deposit on pipe wall (mm)
after 14 days
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FLOW ASSURANCE OIL PRODUCTION
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our example :
-2000
-1500
-1000
-5000
500
-1000 0 1000 2000 3000 4000 5000
Well
Flowline-Riser
gas inj.
out le t
Pres 150 bar
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Terrain slugging (zero gas injection)
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Well gas lift can help (ca. 72 600 Sm3/d )
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Effect of insulation during cool-down
50 mm insulation
No insulation
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Effect of insulation during blow-down
50 mm insulation
No insulation
Blow-down starts at 4 h
Blow-down starts at 8 h
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Start-up with gas-lift – with and without insulation
50 mm insulation
No insulation
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Start-up with well gas lift - with insulation
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Close-up of the start-up trends
critical period
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Can the Flowline/Riserbase be inhibited ?
critical part of flowline-during start-up
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FLOW ASSURANCE GAS-CONDENSATE TRANSPORT
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Examples:
OrmenLange
Snøhvit
Scarab-Safron
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Gas-Condensate PipelinesMain concerns are:
•Production capacity
•Liquid surges
•Inhibitor supply
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Production capacity
•Maximum production with minimum pipe diameter
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Maximum capacity• high flowrates - high pressure loss
– friction dominated flow
– wall friction is most important
Flow rate
I n
l e t P r e s s u r e
Friction dominated
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Liquid surges
Gas P roduction Rate
L i q u
i d C o n
t e n
t
Initialamount
Finalamount
Amount
removed
Restart after turn-down and liquid inventory build-upsweep out of liquid by rate increase
Pigging
inspection and distribution of inhibitor liquid inventory adjustments
Li id h ld f ti f
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Liquid hold-up as function ofpipe inclination and flow rate
ex iper imentsf rom IFE
Pi fil i i
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Pipe profile is very important
Inclination of basic pipeline, Deg
L e n g t h o f
p i p e l i n e ( m )
accu racy
c omput i ng t im e
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Check sensitivity of liquid inventory to pipe
inclination
Liquid inventory as function of pipe
inclination to horizontall
020
40
60
80
100
120
140
160
-5 0 5
deg
m 3
150 MMScfd
test with OLGA of a
2000 m straight pipe, 19 ” ID
Flowrate 150 MMScfd
Inclination angle varied from-5 to 5 degrees
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Phase envelope (water – free)
0
100
200
300
400
500
600
-200 0 200 400 600
T ( C )
P
( b a r a )
Dew
Bubble
CriticalPipe outlet cond.
98 vol % gas
93 vol % gas
-65.1 C, 238 bara
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0
25
50
75
100
125
150
0 50 100 150 200 250 300 350 400 450
Flow rate (MMScfd)
I n l e t P r e s s
u r e ( B a r a )
0500
1000
1500
20002500
3000
3500
4000
4500
5000
L i q u i d i n v e
n t o r y ( m 3 )
P (Bara)
Liq Inv (m3)
Inlet pressure and liquid inventory as function of gasrate.
GOR ≈ 1300
Sm3
/Sm3
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Turn-down from 400 to 200 MMScfd
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Turn-down from 400 to 200 MMScfdBuild-up of liquid inventory
Turn-down from 400 to 150 MMScfd
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Turn down from 400 to 150 MMScfdresults in terrain induced slugging
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Pigging at 320 MMScfd (80% of max prod.)
• Pigging with a liquid inventory resulting from320 MMScfd flow
• Rate turned down to 150 MMScfd prior to pig launch
• Flow turned up again after pig arrival
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Pigging at 320 MMScfd –Liquid Surge
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Pigging at 320 MMScfd – Max Liquid Surge
Pigging at 320 MMScfd
0.0
100.0200.0
300.0
400.0
500.0
600.0
700.0
800.0
900.0
1000.0
400 500 600 700 800 900 1000Drain Rate (m3/h)
M a x S
u r g e V o l u m
e i n t o S e p a r a t o r
( m
3 )
Assuming constant liquid drain rates
Max drain rate = 120 % of liquid production at
400 MMScfd = 666 m3/h
Max Surge: 649 m3
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Include slug catcher and level control
• Slug catcher model : L = 92 m , D = 4 m
• Max liq. drain CV : 622 (based on 120% of max liq. prod.)
• Separator pressure: ≈ 67 bara
• Drain back-pressure: 66 bara
• Set-point liquid level: 0.35
• HH liquid volume : 60% of total slug catcher volume
P
L
Separator liquid level during pigging
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Separator liquid level during pigging
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Troll gas: Onshore slug-catcher
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OLGA model
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Base case
400 MMscfd of gasGOR 1300 Sm3/Sm3
WC 0Fluid saturated with H2O at 165 bara and 95 C
80 wt% MEG: 4 kg/h per MMScfd
Steady state: fluids are inhibited with 30 w% MEG
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y
P l
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Pressure loss
Upset in MEG-injection rate: 50% reduction
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Effect of a 50% reduction in MEG injection rate
-40
-35
-30
-25
-20
-15
-10
-5
0
5
0 1 2 3 4 5 6 7 8 9 10 11 12
Time (h)
D T H
Y D ( C )
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
M E G
f r a c t .
( - )DTHYD pipe inlet
DTHYD pipe outlet
MEG mass fraction pipe inlet
MEG mass fraction pipe outlet
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SUMMARY
Design challenge:Estimate operating area
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Estimate operating area
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]
G A S
O I L
R A T I O [
S m ³ / S m ³
Stable Operating Envelope
Standard Liquid Rate [ Sm³/d]
G a s
O i l R a
t i o [ S m
³ / S m
³ ]
Hydrate Formation Temp. – 18°C
Wax Appearance Temp. – 32°C
Riser Stability – ΔP = 1 bar
Riser Stability – ΔP = 6 bar
Reservoir Pressure – 80 bara Riser Stability – ΔP = 12 bar
Gas Velocity Limit – 12 m/s
Erosional Velocity Limits
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T k Fl A t O ti !!
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Take Flow Assurance to Operations !!
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