3 Intro to Flow Assurance Upd

8/6/2019 3 Intro to Flow Assurance Upd

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INTRODUCTION TO FLOW ASSURANCE



What can stop or reduce the production ?

•Blockage of pipe by

– Hydrates

– Wax

Flow Instabilities

Accidentsand Disasters



Hydrates are

• Crystals of water and

gas molecules.Or more simply: ice ofwater andhydrocarbons



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



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



SINTEF hydrate wheel



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.



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



Example: gas condensate:

Flow rate 200 MMScfd,Saturated with water at 160 bara and 95 C

WC = 0GOR ≈ 1300 Sm3/Sm3

Pipe not insulated



Effect of MEG-inhibition

0 kg MEG/kg H2O

0.33 ”

0.67 ”



Wax

• Solid paraffins from hydrocarbon fluids.



• 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



An example

Oil pipeline: 142 km long, ID = 0.32 m

Inlet flow: 69 kg/s, Tinlet = 55 CT ambient: 4 to 5 C



Wax deposit on pipe wall (mm)

after 14 days



FLOW ASSURANCE OIL PRODUCTION



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



Terrain slugging (zero gas injection)



Well gas lift can help (ca. 72 600 Sm3/d )



Effect of insulation during cool-down

50 mm insulation

No insulation



Effect of insulation during blow-down

50 mm insulation

No insulation

Blow-down starts at 4 h

Blow-down starts at 8 h



Start-up with gas-lift – with and without insulation

50 mm insulation

No insulation



Start-up with well gas lift - with insulation



Close-up of the start-up trends

critical period



Can the Flowline/Riserbase be inhibited ?

critical part of flowline-during start-up



FLOW ASSURANCE GAS-CONDENSATE TRANSPORT



Examples:

OrmenLange

Snøhvit

Scarab-Safron



Gas-Condensate PipelinesMain concerns are:

•Production capacity

•Liquid surges

•Inhibitor supply



Production capacity

•Maximum production with minimum pipe diameter



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



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



Liquid hold-up as function ofpipe inclination and flow rate

ex iper imentsf rom IFE

Pi fil i i



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



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



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



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



Turn-down from 400 to 200 MMScfd



Turn-down from 400 to 200 MMScfdBuild-up of liquid inventory

Turn-down from 400 to 150 MMScfd



Turn down from 400 to 150 MMScfdresults in terrain induced slugging



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



Pigging at 320 MMScfd –Liquid Surge



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



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



Separator liquid level during pigging



Troll gas: Onshore slug-catcher



OLGA model



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



y

P l



Pressure loss

Upset in MEG-injection rate: 50% reduction



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



SUMMARY

Design challenge:Estimate operating area



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



T k Fl A t O ti !!



Take Flow Assurance to Operations !!

3 Intro to Flow Assurance Upd

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