Transportation of waxy crudesin multiphase pipelines

Hans Petter RønningsenStatoil

NTNU, 27.03.2006

Outline of presentation

Flow assurancePhase behaviourSolids precipitationWax depositionPrevention and mitigation solutionsRheology and gelling of waxy crudes

Fluid and flow assurance

0 100 200 300 400 500 600Temperature, °C

0

100

200

300

400P

ress

ure,

bar

Bubble pointProduction pathwayHydrates (H)Wax (W)Asphaltenes (A)

Fluid behaviour and control

Emulsions Fluid flow

Wax

Scale

Corrosion

Asphaltenes

Hydrates

Phase behaviour

Concept choice : Field developmentsolutions

Field installations

Operations support

Multiphase flow assurance

" The ability to produce and transport multiphase fluids from reservoirs to processing plants in economically and technically feasible way"

Operational guidelines

Conceptual design

Fluid and flow prediction

Prevention methods

Mitigation methods

Remediation methods

Flowlines and facilities

Reservoir and wells

PVT/fluid properetiesAsphaltenesScale

Sands/solidsMultiphase flow

SluggingHydrates

WaxesEmulsions

Foam

Phenomena Tasks

Production

Multiphase flow engineering

Pipeline dimension (sizing)Pipeline pressure drop (capacity)Undesirable phenomena– Slugging– Flow restrictions etc.

FlowFlow assuranceassurance ==MinimizationMinimization ofof undesirableundesirable phenomenaphenomena

Fluid mechanics:Governed by Newton

Fluid rheology:Governed by the fluid

Flow assurance:Governed by us!

Composition of petroleum fluids

Enormous range and variety of components with regard to boiling point, molecularweight, polarity and carbon number

Thousands of components from methane to large polycyclic compounds withatmospheric equivalent boiling points higher than 800°C

Molecular weights range from 16 g/mole upto several thousand g/mole

Carbon numbers from 1 to at least 100 (for heavy oils probably about 200)

Fluid behaviour and control

Heavy and waxy crudes

Typical phase envelope of a reservoir oil

-100 0 100 200 300 400 500 600 700

Temperature (deg C)

0

100

200

300

400

Pres

sure

(bar

)

Cricondenbar

CricondentermTc; Pc

Tres; Pres

Liquid

Gas

Bubble point line

Dew point line

Phase envelopes of complex mixtures

-200 -100 0 100 200 300 400 500 600 700 800

Temperature (deg C)

0

100

200

300

400

500Pr

essu

re (b

ar)

98% C195% C193% C1Texas gas cond.N. Sea gas cond.Near-crit. gascond.N. Sea volatile oilN. Sea black oilN. Sea asphalticoilN. Sea heavy oil Critical points

Hydrate and wax phase boundaries

-100 0 100 200 300 400 500 600

Temperature (°C)

0

50

100

150

200

250

300

350

Pres

sure

(bar

)

Saturation curveWaxHydrateCritical pointRes. conditions

Complex phase behaviourSecondary solid and liquid phases

0 100 200 300 400 500 600

Temperature, °C

0

100

200

300

400Pr

essu

re, b

ar

Bubble pointHydrates (H)Wax (W)Asphaltenes (A)Hy

drates

Asphaltenes + liquid

Wax

Single-phase liquid

Gas

Compact hydrate plugRef. Kværner report on cold spots in Kristin X-mas tree and choke module

Wax ’slug’ in pig trap at Statfjord B

Wax ’porosity’Composition of wax deposit from Snorre-Statfjord pipeline

Sample no. 1 Sample no. 2 Water content (wt%) 8,88 0,03

Not purified 45,3 47,3 Wax content (wt%) Purified 26,8 32,8 Dry solid content (wt%) 80,7 82,0 Ignition residue /dry (wt%) 0,1 <0,02 “Organic” content /dry (wt%) 99,9 100 Ignition residue 950 °C /dry (wt%) 0,1 <0,02

Ca. 45% waxCa. 55% non-wax

Wax precipitation curveWaxy crude oil

Norne crude at 1 bar

0

1

2

3

4

5

6

7

8

-20 -10 0 10 20 30 40 50

Temperature (°C)

Wt%

sol

id w

ax

Wax deposition test with Snøhvit oil-condensatemixture: Effect of dT/dr (ΔT)

Oil 10oCWall 4oC

Oil 8oCWall 4oC

Oil 6oCWall 4oC

Oil 4oCWall 4oC

Conclusion: Wax deposition vanishes when there is no temperaturedifference between the oil and the wall (even if the oil temperatureis far below WAT.

Somewax

Lesswax

Very littlewax

Nowax

Wax deposition profile in Kristin-Njord Y pipeline (60% porosity, 600h simulation)

Kristin-NJ/DR Wye- wax deposition and temperature profile after 600 h

0

0.001

0.002

0.003

0.004

0.005

0 20 40 60 80 100

Pipeline length [km]

Wax

dep

ositi

on [m

]

0

10

20

30

40

50

60

70

Tem

pera

ture

[°C

]

Waxdeposition

Fluidtemperature

Wax (or other deposits) may give severe increaseof pressure drop due to increased roughness

Effect of roughness on pressure drop in turbulent single phase flow

L=10km, Q=10 000 m³/d, D=254 mm, ρ =800 kg/m³

10

15

20

25

30

35

40

0 200 400 600 800 1000

Roughness, micron

Pres

sure

dro

p, b

ar

Viscosity = 2 cpViscosity = 100 cp

Veslefrikk to Oseberg38 km pipelineEffect of roughness factor

10 15 20 25 30

Date

37

38

39

40

41

42

43

44

45

46

47

Diff

. pre

ssur

e (b

ar)

Veslefrikk - Oseberg period 13.12.97-29.12.97

Case B , Pressure drop and wax volume

30

35

40

45

50

0 5 10 15 20 25 30Time (days)

Pres

sure

(bar

)

0

20

40

60

80

100

120

140

160

180

200

Volu

me

(m3 )

Pressure drop

Pressure drop, rough. 15% of waxlayerMeasured data

Wax volume

10200 Sm3/d from field 1 and 24000 Sm3/h from field 2

Simulation:

Pressure drop withroughness factor 0.15

Pressure drop withroughness factor 0

Cooldown with different overall U-values

Source: McKenchie (2001)

Methods for controlling wax depositionPipeline insulation

External insulation coating on single pipesPipe-in-pipe systems

PiggingChemicals

InhibitorsDispersantsDissolvers

Hot oil flushingHeating

BundlesElectric heating (primarily hydrate control)

FBE

PP-Adhesive

PP-SolidPP-Syntactic

PP-SolidPP-Foam

PP-Solid

FBE

PP-Adhesive

PP-SolidPP-Syntactic

PP-SolidPP-Foam

PP-Solid

PPD treated oil; this workPPD treated oil; this work

Wax inhibition

Wax management !

Waxy oils

Newtonian (at T > WAT)Shear-thinning (at T < WAT)Time-dependent (thixotropic’)Thermal- and shear-history dependentYield stress (at T <PP)Viscoelastic (at small deformations)

0 10 20 30 40 50 60 70 80

Temperature (°C)

0

100

200

300

400

500

600

700

800

Visc

osity

(mPa

s)

Newtonian30 s-1100 s-1300 s-1500 s-1

WATPP

constant=η)(

.γη f=

t),(.γη f=

TH) t,,(.γη f=

''∞=η

Rheology depends on composition and fluid

history !

MaximumMaximum pourpour pointpointconditioncondition

Minimum Minimum pourpour pointpointconditioncondition

Yield stress from controlled stress flow curveTyrihans Sør crude oil

Static yieldstress

Dynamic yieldstress (fracture onset)

Notice differencebetween thermallypretreated andnon-pretreatedoil!

MaximumMaximum pourpourpointpoint conditioncondition

MimimumMimimum pourpourpointpoint conditioncondition

Fracture

Restart of gelled oil pipeline

Prestart

Gelled oil

Void

Multiphase

Q(t)Prestart

Gelled oil

Void

Multiphase

Q(t)

Prestart

Single phaseGelled oil

Q(t)Prestart

Single phaseGelled oil

Q(t)

010

2030

4050

6070

8090

100

Static yield stress (Pa)

050

100150200250300350400

Res

tart

pre

ssur

e (b

ar)

5.5"6"9"12"

Restart pressure vs. static yield stressPipeline length = 8 km Safety margin = 50%

Effect of ‘good’ pour point depressant on wax crystal aggregation

Treated with 200 ppm PPD:Ordered aggregates

Wax-free oil

No thermal conditioning:Chaotic soup of wax crystals

Maximum pour point

Conditioned at 80°C:Aggregates

Wax-free oil

Minimum pour point

Backup

Integrated Production Umbilical (IPU)

Pour point

The lowest temperature at which an oil willflow under standard test conditions(ASTM D-97).

Not a well-defined rheological property, but indicates gellingtemperature in pipeline shut-down situations.

Follow-up with yield stress measurements if PP>0oC.

Large effect of thermal history.

Standard thermal pre-treatment (conditioning).

Typically 4-5 wt% solid wax at minimum pour point.

Large effect of dissolved gas.

Non-Newtonian viscosity modelRange 0-10% waxPedersen and Rønningsen (1999)

Non-Newtonian viscosity model

0

10

20

30

40

50

60

70

80

90

100

0 0.02 0.04 0.06 0.08 0.1

Volume fraction solid wax

Rel

ativ

e vi

scos

ity

30 s-1100 s-1500 s-1

Multiphase technology and flow assuranceIntegrated approach for wells, flowlines and facilities

Wellbore hydraulicsTransient pipeline thermohydraulics

Chemical Injection PackageSampling -

Laboratory testing

Mobile Test Unit(MTU)

Fluid propertiesRheology

Multiphase equipmentMultiphase meterMultiphase pump

ProcessSeparatorSlug catcher

Scale control Asphaltene controlWax control

Hydrate controlEmulsion control

Corrosion control

Added value due toincreased recovery by using multiphase pumping and/or subsea separationreduced downtime caused by flowline plugging(hydrates, waxes) and sluggingtailor-made separation process based on actual fluid propertiesoptimal hydrate and wax control strategies based on LCCoptimal thermohydraulic flowline design using state-of-the-art toolsincreased flowline capacities by using flowimproversreduced chemical usage and emissions by using heated flowlines and low concentration inhibitorssimplified satellite tie-in solutions by using multiphase meters