0. Flow Assurance

DP Conference MTS Symposium

Flow Assurance

Elijah KemptonTommy Golczynski

Marine Technology SocietySeptember 30, 2004

OwnerText BoxReturn to session directory

Session Outline

Flow Assurance OverviewKey Flow Assurance Issues

WaxHydratesSlugging

Deepwater Impacts on Flow AssuranceEmerging Technologies

Design ConsiderationsBlack Oil SystemsGas Condensate Systems

Flow Assurance Overview

What is Flow Assurance? Analysis of the entire production system to ensure that

the produced fluids continue to flow throughout the life of the field.

Optimization of the design and operating procedures to cost effectively prevent or mitigate slugging, surge volumes, wax deposition, gelling, hydrates, asphaltenes, etc.

Key Flow Assurance Issues

Wax (Paraffin) What is it?A solid hydrocarbon which precipitates from a produced fluidForms when the fluid temperature drops below the Wax Appearance Temperature (WAT)Melts at elevated temperatures (20F+ above the WAT)Rate of deposition can be predicted for pigging frequency


WaxSince 1996, there have been 51 major occurrences that the MMS had to be involved in

All were paraffin-relatedMeans of remediation

PiggingContinuous inhibition (150-250 ppm for Gulf of Mexico)Reduced wax deposition rate by 60-90%

Industry TechnologyModeling is overly-conservative (6X pigging frequency)


Above WAT Wax Crystals (WAT)

Seabed Temp. (40F)

Example WAT Measurement


Factors effecting wax deposition rate

Wax Appearance Temperature, WAT

Production Fluid Temperature

Flowline U-value

Fluid PropertiesViscosityN-Paraffin Content


Wax Deposition Insulation Impact


Hydrate What is it?An Ice-like solid that forms when:

Sufficient water is presentHydrate former (i.e., methane) is presentRight combination of Pressure and Temperature (High Pressure / Low Temperature

Molecular Structure of

Hydrate Crystal


HydratesPrimary cause for insulated flowlinesDeepwater operations

Increased operating pressureCold ambient temperatures

Means of remediationCrude oil displacement (looped flowlines)DepressurizationCoiled tubingContinuous Inhibition (Prevention Only)Methanol/MEGLDHI

01000

2000

3000

4000

5000

6000

7000

8000

9000

10000

40 45 50 55 60 65 70 75 80 85

Temperature, F

P

r

e

s

s

u

r

e

,

p

s

i

a

Pure Water

Sea Water

Produced Water


Hydrates Base Information

Hydrates NoHydrates

0.300

0.325

0.350

0.375

0.400

0.425

0.450

0.475

0.500

0.525

0.550

0.575

0.600

50 75 100 125 150 175 200 225 250 275 300

Shut-in Pressure, bara

M

e

t

h

a

n

o

l

D

o

s

a

g

e

,

B

B

L

M

e

O

H

/

B

B

L

W

a

t

e

r

761 GOR 1100 GOR

1700 GOR 2500 GOR

0

5

10

15

20

25

30

35

40

45

50

1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

Flowrate, B/d

M

e

t

h

a

n

o

l

R

a

t

e

,

g

p

m

5% Water Cut

10% Water Cut

20% Water Cut

25% Water Cut

30% Water Cut

40% Water Cut

50% Water Cut

25 GPM


Hydrates Base Information


Slugging What is it?Periods of Low Flow Followed by Periods of High FlowOccurs in Multiphase Flowlines at Low Gas Velocities


SluggingCauses

Low fluid velocityBigger Better

Seabed bathymetry (downsloping)Riser typeLazy-S is a slug generator

Means of preventionIncrease flowrateSeparator pressureGas lift Difficult with

Catenary Risers

Lower Temperatures

Relative Inexpensive

Erosion Concerns

Proven Technology

DisadvantagesAdvantages

Gas LiftOverview


Slugging Gas Lift Impacts

0

10000

20000

30000

40000

50000

60000

3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0

Time (hours)

L

i

q

u

i

d

O

u

t

l

e

t

F

l

o

w

r

a

t

e

(

B

/

d

)

0 MMSCFD Gas Lift

0

5000

10000

15000

20000

25000

30000

35000

40000

3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0

Time (hours)

L

i

q

u

i

d

O

u

t

l

e

t

F

l

o

w

r

a

t

e

(

B

/

d

)

5 MMSCFD Gas Lift

0

5000

10000

15000

20000

25000

3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0

Time (hours)

L

i

q

u

i

d

O

u

t

l

e

t

F

l

o

w

r

a

t

e

(

B

/

d

)

10 MMSCFD Gas Lift

-150

-100

-50

0

50

100

150

3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0

Time (hours)

L

i

q

u

i

d

A

c

c

u

m

u

l

a

t

i

o

n

A

b

o

v

e

N

o

r

m

a

l

(

b

b

l

)

0 MMSCFD Gas Lift

5 MMSCFD Gas Lift

10 MMSCFD Gas LiftSurge Volume


Other IssuesAsphaltenes

ScaleCorrosion

Emulsions

Pour Point

Liquids Management

Cooldown Times

Flare Capacity

C-Factors

ErosionDepressurization

Surge Volume

Pigging

Chemical Inventory

Sand

Deepwater Impacts on Flow Assurance

Hydrate Formation/Wax DepositionLeads to:

Insulation / dual flowlinesDry oil flushingActive heatingChemicalsRevamped operating strategies

Lack of pressure / need for boostingDeepwater + high water cut + long tiebacks

Riser base gas liftMultiphase pumpingSubsea separation

Potential Energy Losses

Gas does work in moving fluids

Function of water depth

Expansion Cooling (Joule-Thomson Effect)

Exacerbated at large pressure differentials

RISER DOMINATES DEEPWATER SYSTEMS

Insulation may not be the answer!

Deepwater: Temperature Losses

95

100

105

110

115

120

125

0 1 2 3 4 5 6 7 8

FLOWLINE

RISER BASE

TOPSIDES

RISER

WELLHEAD

Distance (miles)

T

e

m

p

e

r

a

t

u

r

e

(

F

)


Joule-ThomsonCooling

46%

Surroundings(U-Value)

6%

Potential Energy(Work)

48%

16.59.215

16.62.96

16.61.23

RiserFlowline

Temperature Drop (F)Flowline Length(miles)


Heat transfer coefficient (U-value) dictates steady state temperatures Q (heat loss) = UAT U-Value , Q T

Thermal mass (, Cp) impacts transient performance Measure of heat storage

Prolongs cooldown times

Prolongs warm-up times


Te

m

p

e

r

a

t

u

r

e

(

F

)

Time(hours)

40

50

60

70

80

90

100

110

0 5 10 15 20 25 30 35 40

HIGH (Gelled Fluid #2 Water Base)

MEDIUM (Gelled Fluid #1 Oil Base)

LOW (Nitrogen)

Transient Temperature Loss

Pr

e

s

s

u

r

e

(

p

s

i

a

)

0

500

1000

1500

2000

2500

0 1 2 3 4 5 6 7 8

Distance (miles)

FLOWLINERISER BASE

RISER

WELLHEAD

TOPSIDES

Deepwater: Pressure Losses

176440515

17912386

18121433

RiserFlowline

Pressure Drop (psia)Flowline Length(miles)

Deepwater: Pressure Losses

Dry trees preferred for accessibility

Dry trees more difficult for flow assurance

Typically cannot depressurize

Short cooldown times (2-8 hours)

Fewer insulation/heating options than subsea

Limited chemical (MeOH/MEG) deliverability

Wax deposition more difficult to remediate

Deepwater:Dry Trees vs. Subsea Tieback

Dry Tree Analysis: Cooldown ComparisonProduction Fluid Temperature

40

45

50

55

60

65

70

75

80

85

90

95

100

0 1 2 3 4 5 6 7 8 9 10 11 12

Time (Hours)

T

e

m

p

e

r

a

t

u

r

e

(

F

)

Solid - Conduction

Liquid - Conduction+Convection

Gas - Conduction+Convection+Radiation

HYDRATE FORMATION TEMPERATURE

Dry Tree:Conduction / Convection / Radiation

Concentric Non-Concentric

Heat Transfer: Q = kAT / L(Conduction Only)

Accommodate Auxiliary Lines?

Dry Tree:Concentric vs. Non-Concentric

Dry Tree:Concentric vs. Non-Concentric

Te

m

p

e

r

a

t

u

r

e

(

F

)

Time (Hours)

40

50

60

70

80

90

100

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0

15 psia N230 psia N259 psia N2102 psia N2

Dry Tree:Gas Properties

Transient issues drive deepwater design

Cooldown / restart - Hydrates Typical deepwater practice

Dual flowlines / crude oil displacement

Typically cannot depressurize (oil systems)

Consider potential for future expansion Insulation Topsides facilities

Design for Expansion

22.5 km

10 km8 km

8 km

Design for Expansion

Total Time to Displace Existing System = 22 Hours (Sequential)

Total Time to Displace Integrated System = 45 Hours (Sequential)High Level Insulation, or Additional Topsides Facilities Required!

Emerging Technologies

Passive Insulation Solutions

Microporous Insulation

Phase Change Materials

Artificial Lift

Subsea Separation (-)

Multiphase Pumping (+)

Gas Lift (+ / -)

Emerging Technologies

Active Heating

Hot Water Circulation

Electrically Heated

Electrically-heated ready

Chemicals

Low Dosage Hydrate Inhibitors

Cold Flow

Design Considerations:Black Oil and

Gas Condensate Systems

Black Oil System:Steady State Design Checklist Hydraulics

Line sizing Dry tree vs. subsea tieback Single vs. dual flowlines Dual flowlines becoming standard for deepwater

Pressure drop Velocity / erosion (minimum / maximum) Slugging

Thermal Insulation requirements

Hydrate formation Wax deposition Gel formation

Shutdown Planned Unplanned

Depressurization Restart

Warm Cold

Fluid displacement / pigging Flowline preheating

Black Oil System:Transient Design Checklist

Black Oil Systems:Steady State Design Considerations

Black Oil System:Steady State Hydraulics

Pressure drop effects Physical

Line size Tieback distance Water depth Multiphase flow:

Head losses head gains Pipe roughness (typical values) Steel: 0.0018 Tubing: 0.0006 Flexible pipe: ID/250

Fluid properties Gas/oil ratio (GOR) Density Viscosity May require insulation to limit viscosity

P

r

e

s

s

u

r

e

(

p

s

i

a

)

0

500

1000

1500

2000

2500

0 1 2 3 4 5 6 7 8

Distance (miles)

Black Oil System: Slugging Hydrodynamic

High frequency Minimal facilities impact

Terrain High liquid / gas flowrates Topsides concern Riser fatigue concern Utilize gas lift

Hydrodynamic SluggingGas Outlet Flow

0

1

2

3

4

5

6

7

1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0

Time (hours)

Terrain SluggingLiquid Outlet Flow

0

10000

20000

30000

40000

50000

60000

70000

80000

1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0

Time (hours)

Black Oil System: Slugging Slugging issues

Sensitivity to Fluid GOR / water cut

7500 / 7512500 / 10015000 / 1500

5000 / 40017500 / 25020000 / 12517500 / 100

1300 GOR 1800 GOR760 GOR

10000 / 20026000 / 3256015000 / 13024000 / 1754015000 / 12520000 / 16020

DNF

Terrain Slugging Regime (BPD) / Surge Volume (BBL)

5000 / 30080

Water Cut (%)

Black Oil System: Slugging Slugging issues

Sensitivity to Trajectory: up vs. downslope

-8600

-8500

-8400

-8300

-8200

-8100

-8000

-7900

-7800

-7700

-7600

-7500

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40

Distance, miles

W

a

t

e

r

D

e

p

t

h

,

f

t

Original Route - 40 miles total length

Alternate Route #1 - 36 miles total length

Alternate Route #2 - 45 miles total length

WELLHEAD RISER BASE

0

50

100

150

200

250

300

350

400

0 1 2 3 4 5 6 7 8

Time (hours)

L

i

q

u

i

d

A

c

c

u

m

u

l

a

t

i

o

n

A

b

o

v

e

N

o

r

m

a

l

*

(

b

b

l

)

Original RouteAlternate Route #1Alternate Route #2

50 bbl Slug Catcher Capacity

>24 hour Ramp-up Required

10 hour Ramp-up Required

Hydrates Maintain steady state temperature

above hydrate formation region, down to reasonable flowrate

Looped flowline ~ 25% of field production (50% per flowline)

For low water-cut systems, continuous hydrate inhibition is possible

Future: continuous LDHI inhibition

Black Oil System:Steady State Thermal Design

Wax Maintain temperature above WAT (stock

tank), down to reasonable flowrate Looped flowline ~ 25% of field production

(50% per flowline)

Maintain viscosity at acceptable levels to reduce pressure drop

Insulate to minimize pigging frequency Pigging frequency > residence time

Continuous paraffin inhibition (if necessary)



Limited insulating capacity0.75 1.50Flexible

Riser installation difficulties0.20 0.25Pipe-in-pipe

Dependant on soil propertiesCombined with insulation

0.50 1.00Burial

Buoyancy issues0.50 0.75Wet (Syntactic)

0.08 0.10

Achievable U-value(BTU/hr-ft-F)

Industry acceptanceMicro-porous

Issue / ConcernInsulation Option


Arrival TemperatureWater Cut = 0%

20.0

22.0

24.0

26.0

28.0

30.0

32.0

34.0

36.0

38.0

40.0

42.0

44.0

46.0

48.0

50.0

7500 10000 12500 15000 17500 20000 22500 25000 27500 30000 32500 35000 37500 40000Liquid Flowrate (blpd)

A

r

r

i

v

a

l

t

e

m

p

e

r

a

t

u

r

e

(

C

)

0.5 W/m.K1.0 W/m.K2 W/m.K3.0 W/m.Kno heat loss

0.50 BTU/ft hr F

0.30 BTU/ft hr F

0.20 BTU/ft hr F

0.09 BTU/ft hr F

Adiabatic (0 BTU/ft hr F)

Black Oil Systems:Cooldown Design Considerations

Shutdown statistics Typical shutdown durations

89% shutdowns < 10 hours 94% shutdowns < 12 hours 99.9% shutdowns < 24 hours

Typical shutdown causes

Black Oil System: Cooldown

PumpsScaleCorrosionSandParaffinHydratesAsphaltenesSeparationOther

Planned shutdown Procedure Inject hydrate inhibitor for one residence time

(minimum) At high water cuts, may need to reduce flowrate to

effectively treat system

Inject hydrate inhibitor into subsea equipment Particular attention to horizontal components Self-draining manifold / jumpers Treat upper portion of wellbore

SCSSV vs. top ~50 ft

Shut-in system


Unplanned shutdown Procedure Determine minimum cooldown times

No-Touch Time ~2-4 hours / no action taken subsea

Light Touch Time ~2-4 hours / treat critical components Time is a function of chemical injection philosophy / number of wells

Preservation Time Time required to depressurize or displace flowlines with non-hydrate

forming fluid


Time=0 Time=8Time=4

No-Touch Light Touch Preservation

Insulation selection Cooldown time determined

by: U-Value Thermal mass (, Cp)

Measure of heat storage

Line size impacts Bigger = More

Thermal Mass

Gas / liquid interface typically controlling point

Gas = low thermal mass Highest pressure Coldest temperature


40

50

60

70

80

90

100

110

120

130

140

150

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Time (hours)

T

e

m

p

e

r

a

t

u

r

e

(

F

)

Pipe-in-Pipe (0.20 BTU/hr-ft-F)

Wet Insulation (0.75 BTU/hr-ft-F)

Flexible Pipe (1.00 BTU/hr-ft-F)

HYDRATE FORMATION (PURE WATER)


30

40

50

60

70

80

90

100

110

120

130

140

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0

Distance (miles)

T

e

m

p

e

r

a

t

u

r

e

(

F

)

0 hours (Steady State)

1 hours

2 hours

4 hours

6 hours

8 hours

10 hours

12 hours

18 hours

24 hours

RESERVOIRWELLHEAD

FLOWLINE

RISER


0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0

Distance (miles)

P

r

e

s

s

u

r

e

(

p

s

i

a

)


24 hours

RESERVOIR

WELLHEAD

FLOWLINE

RISER


0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0

Distance (miles)

L

i

q

u

i

d

H

o

l

d

u

p

(

-

)


24 hours

RESERVOIRWELLHEAD

FLOWLINE

RISER


-30

-20

-10

0

10

20

30

40

50

60

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0

Distance (miles)

H

y

d

r

a

t

e

P

r

o

p

e

n

s

i

t

y

,

T

-

T

h

y

d

(

F

)


1 hours

2 hours

4 hours

6 hours

8 hours

10 hours

12 hours

18 hours

24 hours

RESERVOIR

WELLHEAD

FLOWLINE

RISER

Is there adequate chemical injection to treat subsea components within cooldown time? Wellbore Trees Jumpers Manifolds

What is the subsea valve closure philosophy? Packed: More liquid / higher pressures Un-packed: Less liquid / lower pressures

Does insulation provide sufficient cooldown time? No-touch Light-touch Preservation

Is gel formation a possibility? If yes, system design philosophy changes

Is SCSSV set deep enough to avoid hydrates?

Black Oil System:Cooldown Checklist

Black Oil Systems:Depressurization Design

Considerations

Hydrate remediation strategy Reduce pressure below hydrate formation pressure at seabed

Effectiveness based on: Fluid properties

GOR Water cut

Seabed bathymetry Upslope Downslope

Deepwater issues Reduce pressure to ~200 psia at seabed Maintain pressure below hydrate conditions during restart

Black Oil System: Depressurization

Time=0 Time=8Time=4

No-Touch Light Touch Preservation:Depressurization

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

40 45 50 55 60 65 70 75 80 85

Temperature, F

P

r

e

s

s

u

r

e

,

p

s

i

a

Pure Water

Sea Water

Produced Water

Phyd ~ 200 psia

0500

1000

1500

2000

2500

3000

3500

4000

4500

0 1 2 3 4 5 6 7 8 9

0.0 hours0.5 hours1.0 hours

P

r

e

s

s

u

r

e

(

p

s

i

a

)

Distance (miles)

FLOWLINE

MUDLINE

BOTTOM HOLE

RISER BASE

Depressurization:Subsea Tieback

0500

1000

1500

2000

2500

3000

3500

4000

4500

0 2000 4000 6000 8000 10000 12000

0.0 hours

0.5 hours

1.0 hours

Distance (feet)

P

r

e

s

s

u

r

e

(

p

s

i

a

)

MUDLINE

BOTTOM HOLE

GAS/LIQUIDINTERFACE

SCSSV

Depressurization Dry Tree

Can you depressurize below hydrate formation conditions? If YES, can you depressurize in late-life at high water cuts? If YES, can you maintain pressure below hydrate formation conditions

during restart? Difficult for deepwater

If YES, is there a pour point concern? Depressurization increases restart pressure requirements

If NO, consider the following for hydrate prevention: Displacement (dual flowlines)

Active heating

Continuous chemical inhibition

Black Oil System:Depressurization Checklist

Black Oil Systems:Displacement Design

Considerations

During Prevention time, displace produced fluids from flowline Unable to get hydrate inhibitor to in-situ fluids

during shutdown Dual flowlines required Sufficient insulation / cooldown time Function of flowline length

Black Oil System: DisplacementHydrate Prevention - Shutdown

Time=0 Time=8Time=4

No-Touch Light Touch Preservation:Displacement

Black Oil System: DisplacementDischarge Pressure Required

HOLD BACKPRESSURE AT OUTLET


Dead Oil Flushing - Year 5FPSO Pump Discharge Pressure

FPSO Arrival Pressure Controlled at 1500 psia

0

200

400

600

800

1000

1200

1400

1600

1800

0 0.5 1 1.5 2 2.5 3 3.5

Time (H)

Pig reaches base of first riser

Produced fluids move up second riser

Gas breaks through

second riser

Pig moves up second riser

During Prevention time, displace produced fluids from flowline Topsides design considerations

Available backpressure Circulation rate Limited by pig integrity Typically 3-5 ft/sec May be faster for straight-pipe

Storage volume Circulation passes With pig: 1 residence time Without pig: 2-3 residence times for efficient water removal


Black Oil System: DisplacementHydrate Prevention Dry Tree

During shutdown, how quickly will fluids fall below SCSSV? Very little work done with L/D ratios >100 (deepwater riser

~10000) Field data shows oil/water separation ~ 70-80 ft/hr

Bullhead / displace with non-hydrate forming chemical to SCSSV Methanol/MEG (volume concerns) Heavy diesel (high density, by-pass produced fluids) Dead oil

Ability to bullhead a function of displacement rate

Is there sufficient time to accomplish displacement operation? Sufficient insulation / Cooldown time

Is the topsides facility designed to accomplish displacement operation? Pump capacity Storage capacity

Can system be restarted into crude-oil filled flowline? Displace with gas? High pour point fluids what is the restart pressure required?

For dry trees, is a proper fluid available for displacement?

Black Oil System:Displacement Checklist

Black Oil Systems:Restart Design Considerations

Black Oil System: Cold Restart System pressure < hydrate formation conditions throughout

restart? For deepwater, hydrostatic pressure in riser too high Separator pressure: may need alternate start-up vessel

Hydrate inhibition required until arrival temperature reaches Safe Operating Temperature (SOT) Maintain hydrate inhibitor rate: Fluid completely inhibited Reduce hydrate inhibitor rate: Fluid not completely inhibited to

shut-in conditions

SOT is minimum topsides temperature that provides sufficient cooldown time, in the event of an interrupted restart

Black Oil System: Cold Restart

Shut-in Pressure, psia

M

e

t

h

a

n

o

l

D

o

s

a

g

e

,

B

B

L

M

e

O

H

/

B

B

L

H

2

O

0.30

0.35

0.40

0.45

0.50

0.55

0.60

1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000

PRODUCEDWATER

SEA WATER

PURE WATER


Flowrate, BPD

M

e

t

h

a

n

o

l

,

g

p

m

0

5

10

15

20

25

30

35

40

45

50

2000 3000 4000 5000 6000 7000 8000 9000 10000

5% WATER

50% WATER

25% WATER

75% WATER

Black Oil System: Cold Restart Achievable restart rates determined by:

Shut-in conditions Fluid GOR Water cut Hydrate inhibitor

Rule of Thumb: Greater inhibitor injection rates result in lower overall inhibitor volumes used during restart Small tiebacks: 5-10 gpm / well Large deepwater: 25+ gpm / well

Warm-up trends: Wellbore: Very quick (

1.12.95.8Micro-porous

1.58.4> 24Buried1.13.210.6Flexible1.23.59.2Conventional1.13.06.1Pipe-in-pipe

Max Flowrate

10000STBPD

5000 STBPD

Insulation Type

Cold Restart: Case Study3 Mile Tieback Warm-up Time

7.013.0> 24Micro-porous

> 24> 24> 24Buried12.3> 24> 24Flexible10.9> 24> 24Conventional7.214.0> 24Pipe-in-pipe

Max Flowrate

10000STBPD

5000 STBPD

Insulation Type

Cold Restart: Case Study15 Mile Tieback Warm-up Time

772798> 850Micro-porous

> 2300> 1700> 850Buried1053> 1700> 850Flexible1074> 1700> 850Conventional781814> 850Pipe-in-pipe

Max Flowrate

10000STBPD

5000 STBPD

Insulation Type

Cold Restart: Case Study15 Mile Tieback MeOH Volume

Is there sufficient hydrate inhibitor available? Delivery rates Storage volumes

How will multiple wells be restarted? Single well at max. rate Multiple wells at reduced rate Single flowline vs. dual flowline

What is the minimum temperature required to achieve safe conditions? Safe Operating Temperature (SOT)

Black Oil System:Restart Checklist

Hydraulics Ensure Production Delivery Throughout Field Life Minimize Slugging

Wax Deposition Minimize Wax Deposition (Insulation/Pigging/Chemicals)

Hydrate Formation Avoid Steady State Hydrate Formation Optimize Cooldown Times (Insulation) Prevent Transient Hydrate Formation

(Depressurization/Displacement/Chemicals) Minimize Inhibitor Consumption

Black Oil System:Summary of Design Considerations

0. Flow Assurance

Documents

Transcript of 0. Flow Assurance