flow assurance

EG55F8 Flow Assurance

MSc in Subsea Engineering

Introduction and Key Concepts in Flow AssuranceIntroduction and Key Concepts in Flow AssuranceIntroduction and Key Concepts in Flow AssuranceIntroduction and Key Concepts in Flow AssuranceMurray AndersonMurray Anderson BEngBEng PhDPhD CEngCEng MIMechEMIMechEHead of Flow Assurance and Field Development Engineering, AtkinsHead of Flow Assurance and Field Development Engineering, AtkinsMurray AndersonMurray Anderson BEngBEng PhDPhD CEngCEng MIMechEMIMechEHead of Flow Assurance and Field Development Engineering, AtkinsHead of Flow Assurance and Field Development Engineering, Atkins



Subsea Pipeline Flow Assurance

Introduction to Flow Assurance The main flow assurance challenges Production fluids and phase behaviour Multiphase flow Hydrates, wax and asphaltenes Overall Heat Transfer Coefficient Insulation systems (wet insulation and pipe-in-pipe) Heating systems Chemical treatments Operating strategies Conclusions and key messages



Oil and Gas Development Options

Onshore Shallow-water Offshore Deep-water Offshore

Shallow Reservoir

DeepReservoir

Subsea Step-out

Deep-waterHPHT

Deep-waterCluster

up to3km

up to10km

DeviatedWell

up to150km

up to5km

ImpermeableCap Rock

Oil/Gas bearing Rock

Fault Fault



Reservoir Pressure

4



“Flow Assurance” Definition

Themo-hydraulicModelling

SystemDesign

ProcessingRequirements

Appraisal

PressureProfiles

DesignConcept

Sampling OperatingPhilosophy

TemperatureProfiles

Pipeline Sizesand Pressure

ProtectionFluid Analysis Start-up and

shut-down

Flow RegimesInsulation and

ThermalManagement

Fluid ModellingPigging and

PlannedIntervention

Hydrates, Wax,Asphaltenesand Scale

ChemicalRequirements

Un-plannedintervention

SystemOperation

Project Life Cycle



The Main Challenges

Flow Instabilities: Multiphase flow Slugging

Pipeline Blockages: Hydrates Wax Asphaltenes Scale

Loss of Containment: Corrosion Erosion

Much of the flow assurance challengereduces to identifying, understanding

and managing uncertainty



Deep Water Challenges

Remote and inaccessible. Low ambient water temperatures. Long distance tie-backs. Long risers. Extremely high cost of intervention. Complex subsea systems.

BP operated Nakika floating production facility in1930m water depth in the Gulf of Mexico

FPSO Espirito Santo moored in 1789m in theCampos Basin off Brazil

Minimise hardware CAPEX while assuring OPERABILITY



Hydrocarbons FluidsHydrocarbons

Aliphatics Aromatics

Alkanes(Paraffins)

Alkenes(Olefins) Alkynes Cycloaliphatics

CH HH

H

CHH

HCH

CH

HH

CH HH

methane

ethane

propane

n-butane

iso-butane(methylpropane)

CHH

HCH

HH

CHH

ethene(ethylene)

propene(propylene)

ethyne(acetylene)

propyneC

H H

C HH

cyclopropane

CHC

H

CH

CH

CH

C Hbenzene

CH

HCH

H

CH

HCH

CH

HH

C C HH

CH C CH

HHCH

H

HCH

HCH

HH

CHH

HCH

HCH

HC HH

H



C

Non- hydrocarbon Fluids

SH

H CH

H

OCOH

HCH

HH

H

OHH

H

H

Non-hydrocarbons incorporate atoms such as nitrogen, oxygen and sulphur

Organic Compounds

Resins andAsphaltenes Alcohols Glycols

Mercaptans(Thiols)

Inorganic Compounds

methanol

ethanol(IMS) MEG

methyl mercaptan

OCH

H

HH C

H

H

NNnitrogen

H OH

water

O C Ocarbondioxide

H SH

hydrogensulphide

solids

metals

ASPHALTENES are insolublein petroleum and are solid andnonvolatile

RESINS are readily soluble inpetroleum and may be volatileliquidsor sticky solids

Hg, Ni, V

large organic molecules withring structures and one tothree sulphur, oxygen ornitrogen atoms

mineral salts

sand,diamondoids

CaCO3, BaSO4,NaCl

Non-hydrocarbons



Single-component Phase Behaviour

Critical Point

Triple Point

Liquid

Gas

Solid

Dense PhaseSupercritical

SuperheatedGas

Temperature

Pre

ssur

e



0

20

40

60

80

100

120

140

-100 -80 -60 -40 -20 0 20 40 60

Pre

ssur

e(b

ara

)

Temperature (C)

Multi-component Phase Behaviour

Cricondenbar

Cric

onde

nthe

rm

Critical Point

Liquid

MultiphaseGas

10%20%

30%

70%50%40%

Dense Phase

Typical Rich Gas, S.G. ~1.0



Multiphase Flow Regimes

Stratified/Wavy Flow:Liquid and gas separate due to low gas velocityVelocity differences may produce surface wavesOften seen in downward sloping pipe sections

Dispersed Bubble Flow:Liquid dominated systems with low gas ratesOccurs at all angles of inclinationAppears as gas bubbles entrained in liquid phase

Annular-mist Flow:Gas dominated systems with low liquid ratesOccurs at all angles of inclinationAppears as liquid droplets entrained in gas phase

Hydrodynamic Slug Flow:Surface waves in stratified flow bridge the pipeFlow can be very unsteadyOften seen in upward sloping pipe sections



Multiphase Flow Parameters

gA

lA

SuperficialVelocity

Phase volume flow

Total cross sectional area gl

lls AA

QV

gl

ggs AA

QV

MixtureVelocity

Total volume flow

Total cross sectional areagsls

gl

glm VV

AA

QQV

PhaseVelocity

Phase volume flow

Phase cross sectional area l

ll A

QV

g

gg A

QV

LiquidHold-up gl

ll AA

AH

Phase cross sectional area

Total cross sectional area

Dispersed Bubble

Stratified/Wavy

Hydrodynamic SlugAnnular-mist

log(Superficial Gas Velocity)lo

g(Su

perf

icia

lLiq

uid

Velo

city

)

gV

lV



Gas

Why is it important?

• Pipeline Sizing• Small diameter gives increased pressure loss but reduced slugging

• Liquid Loading:• High pressure required to restart wells• Equipment sizing for initial start-up slug• Large liquid volumes during pigging

• Steady-state Transients:• Vessel sizing must accommodate maximum slug• High loading/fatigue on pipe supports• Downstream process stability (gas starvation)

Production Flowline

Gas Lift Flowline

Riser BaseGas LiftManifold

Well-head

Well-head

WaterOil



Hydrates

Hydrates are crystalline solids formed in thepresence of water and small non-polar molecules

Hydrates are ice-like compounds Hydrates form at high pressure and low

temperature Critically, at high pressure hydrates can form at

up to 30°C

0.1m3 hydrate ~ 18scm gas!



1

10

100

1000

0 5 10 15 20 25 30 35

Pre

ssur

e(b

ara)

Temperature (C)

Methane Ethane Carbon Dioxide Hydrogen Sulphide

Hydrate Formation

Hydrates form when a small molecule(guest molecule) stabilizes hydrogenbonds between water molecules (hostmolecules)

The host molecules form cages (12,14 or 16 sided) round the guestmolecule

Different hydrate types have differentcage configurations

Type I hydrate: 2 x 12 sided cages + 6 x 14 sided cagesType II hydrate: 16 x 12 sided cages + 8 x 16 sided cages

HostMolecules

GuestMolecule



Wax

Wax is formed from long chain paraffinsand naphthenes

Wax crystals precipitate out of solution atlow temperatures

The wax appearance temperature (WAT)or cloud point is the temperature at whichwax crystals first appear Wax can only deposit if the pipe wall is

below WAT

The pour point is the lowest temperature atwhich the oil can be poured under gravity A yield force is required to start fluids

flowing if temperature is below the pourpoint



Wax Deposition

Wax solidifies if the fluid temperature is below WAT Wax crystals will remain suspended unless there is a

temperature gradient Deposition of wax changes the fluid composition at the

wall Wax will harden over time because of concentration

gradients The upstream few kilometres of an uninsulated pipeline

are most susceptible to wax WAT

Tbulk

Twall

Solid wax phaseprecipitates on wall

Concentration gradient influid as heavy moleculessolidify drives lightmolecules away from wall

WATT inlet

Tambient



Asphaltenes

Dark brown or black solids that precipitate inthe presence of n-pentane or n-heptane

Asphaltenes are solid particles in adispersed phase within the oil

Flocculate (come out of suspension) as aresult of Pressure drop Gas lift (with rich gas) Mixing of incompatible oils

Asphaltenes do not melt Flocculation may be irreversible Highly soluble in aromatic compounds

(xylene) Asphaltenes are stabilised by the presence

of resins



Other Issues

Corrosion (covered in depth elsewhere) Principally results from CO2 dissolved in water

(carbonic acid) or by-products of bacterialactivity (microbially influenced corrosion)attacking mild steel.

Scale Mineral deposits (carbonates and sulphates)

resulting from reductions in solubility withchanging P and T.

Also occurs when incompatible water streamsare mixed (e.g. injection water plus formationwater

Mitigation requires injection of inhibitors and/or wash water

Salt Halides (commonly sodium chloride) can deposit in significant quantities, particularly

as a result of evaporation or if MEG injection reduces solubility. May require injection of wash water (clean desalinated water) to dilute produced water.



Other Issues

Solids Solids (sand and debris) will

deposit along with wax ifvelocities are insufficiently high

Bottom solids provide sites formicrobial growth (andsubsequent corrosion)

Physical removal by pigging isthe only assured solution

Emulsions Water and oil phases can form

stable emulsions if there issufficient mixing in the presenceof emulsifying agents.

Emulsions make the fluids non-Newtonian Generally, emulsions are more of a problem for

processing, but can make transportation overlong distances less predictable.



Summary

Unprocessed well fluids are a mix of gas, oil, wax, asphaltenes, resins,water, salts, solids and production chemicals.

At flowing pressures and temperatures, most unprocessed fluids will bemultiphase.

Maintaining stable multiphase flow through field life can be difficult, if notimpossible, and requires careful selection of pipeline size and number ofpipelines.

Changes in conditions along a pipeline system can lead to the formation ofsolids, which can cause blockage.

Maintaining a blockage free system requires careful control of fluidpressures and temperatures through field life.

Unprocessed fluids can be highly corrosive, and require exotic materials orinhibitor chemicals for transportation.



ir

l

oT

iT orq

One dimensional conduction equation:

tT

cqrT

krrr

v

1

rT

krl

q

2

Fourier law of heat conduction:

Steady state, no qv, constant k:

0

rT

rr

io

i

oi

i

rrrr

TTTT

lnln

R

TTq oi

klrr

R io

2ln

where:

Conduction in Cylindrical Shells



ir

l

1T2ToT

iT1r

2r orq

Conduction in Concentric Shells

oo TTqR 22

11 TTqR ii

oioi TTqRRR 2121

2112 TTqR

Fourier law of heat conduction:

Heat transfer (excluding fluids):

oit TTqR

oi TTUAq ref

n

m m

mimo

krr

lA

U 1 2ln1

refwhere:

Normally Aref is the outside area of the steel pipe, but should always be explicitly stated.



l

q

fT

aT

oT

iT

Inside/outside boundary layers:

Overall heat transfer (including fluids):

Inside and outside film coefficients canbe estimated from empirical correlations.

aooo TTAhq

ifii TTAhq

afoo

tii

TTqAh

RAh

11

af TTUAq ref

oo

n

m m

mimo

ii hdkrr

hdlA

U1

2ln11

1refwhere:

Overall Heat Transfer Coefficient

Units for U are Watts per square metre per Kelvin (W/m2/K).



oo

n

m m

mimo

iil hdkrr

hdU1

2ln111

1where (theoretically):

Heat Transfer per Unit Length

For composite systems (i.e. flexible pipes) Aref is notalways easily defined, but:

lUlUdAU l refref

where Ul is commonly referred to as the “heat transfercoefficient per unit length”.

In this case: afl TTlUq

Units for Ul are Watts per metre per Kelvin (W/m/K).

Do not confuse OHTC and HT per unit length – always check units and Aref.



Heat Loss in Pipelines

Heat loss from fluid: xdx

dTcmx

dxdT

TTcmdq fp

fffp

Heat loss through wall: af TTUxddq ref

Temperature decays exponentially, if fluid properties and OHTC are constant

afp

f TTcm

Uddx

dT

ref x

cmUd

af

af peTTTT

ref

1

Equate heat loss and integrate:

fT xdx

dTT f

f

x

dq

x

m1fT



Pipeline Insulation Systems

Insulation systems are classed as WET or DRY, depending on whether theinsulation is contained inside a structural carrier pipe

Solid insulating material(at ambient pressure)

Anti-corrosioncoating

Pipeline

External hydrostatic pressure transmittedthrough insulation (liable to crushing)

Anti-corrosioncoating

Pipeline

Typical Wet Insulation System

Carrier Pipe

Foamed or blanket wrapinsulating material (at orbelow atmosphericpressure)

External hydrostatic pressuretaken by carrier pipe

Typical Pipe-in-pipe Insulation System



Wet Insulation Systems

Deepwater wet insulation is typically based on syntacticpolyurethane (SPU). SPU is solid PU containing a matrix of microscopic low

conductivity microspheres. Microspheres are typically ceramic for moderate depths (low

conductivity but relatively poor collapse resistance) and glassfor extreme depths.

Theoretically applicable in depths down to 2800m Limited maximum temperature at about 115°C

Alternatives can be based on composite polypropylene(PP) systems Composed of a layer of foamed PP surrounded by a thick

layer of solid PP PP has higher operating temperature at about 155°C

Typical OHTCs in the range 2.0 to 3.5 W/m2/K

Bredero Shaw ThermoFlo® SPU system

Bredero Shaw Thermotite® PP systemMajor suppliers include Dow Hyperlast, Bredero Shaw and EUPEC



Deepwater Wet Insulation

Bredero ShawThermotite® PP system



Dry Insulation Systems

Dry insulation must be contained in astructural carrier pipe Carrier pipe must be watertight and

collapse resistant Annulus may be at or below atmospheric

pressure

Insulating materials include: polyurethane foam (Logstor, Bredero Shaw,

EUPEC)

microporous silica blanket wrap (Aspen

Aerogels, Cabot, InTerPipe)

mineral wool (Rockwool)

Microporous and mineral wool basedmaterials offer low OHTC and hightemperature service OHTC ~0.7 W/m2/K Max temperature >200°C

Aspen Aerogels – Pyrogel®

Cabot Nanogel®compression packsfitted in pipe-in-pipesystem



Heated Flowline Concepts

Two basic concepts for heating a subsea flowline Convective heating or “Hot Water” systems Electrical heating

Hot water systems can be direct or indirect Direct heating systems have the heating medium flowing round the outside of the

production pipe (annulus heated systems) Indirect heating systems have heating pipes bundled with production pipes in a

common carrier

Electrical systems may also be direct or indirect Direct Electrical Heating (DEH) relies on pipeline steel carrying the heating

current Indirect heating systems use induced currents in the pipeline or direct thermal

contact with electrically heated cables



Direct Hot Water Heating

Production Flowline (14-inch ø)

Insulation (13mm)

Carrier Pipe (37-inch ø)

Heating Medium Supply (12-inch ø)

Heating Medium Return

Test Flowline (8-inch ø)

Methanol Service Line (3-inch ø)

Heating Medium Supply

Insulation

Jacket Pipes (12-inch ø)

Production Flowline 1 (8-inch ø)

Heating Medium Return

Production Flowline 2 (8-inch ø)

Britannia Bundle (NS), 15km:

King Flowline Loop (GoM), 2 x 27km:



Production Flowline

Heat Transfer Medium

Insulation

Jacket Pipe

Production Fluids

Heating Medium

Heating Medium Supply/Return Flowlines

Indirect Hot Water HeatingCarrier Pipe (40-inch ø)Gas Injection (8-inch ø)

Electro-hydraulics

Methanol (2-inch ø)

Sleeve Pipe (40-inch ø)

InsulationHeating Medium Return

(2-inch ø)

Heating Medium Supply(3-inch ø)

Heat Sensor

Heat Transfer Medium

Production Flowline(8-inch ø)

Production Flowline(6-inch ø)

Kessog Single Flowline Option

Gullfax Phase 1 Bundle



Electrically Heated Systems

Systems can be Direct Electrically Heated (suitable for single pipe and pipe-in-pipe systems) or Indirect Electrically Heated (suitable for bundledapplications)

DEH systems include: Closed Loop Single Pipe (grounded and ungrounded) Open Loop Single Pipe Pipe-in-pipe (centre feed and end feed)

IEH systems include: Tube Heating (induction and conduction) Trace Heating

Open loop single pipe DEH is field proven for long North Sea tie-backs Åsgard (8.5km), Huldra (16km) , Kristin (6.7km), Norne (9km),

Tyrihans (43km)

Pipe-in-pipe DEH systems are field proven in deep water GoM Serrano (6km), Oregano (7.5km), Habanero (17km), Na Kika (section lengths

2km to 13km)



Single Pipe DEH Systems

Single Phase AC Power SupplyIsolation Joint

Electrical Cable

Closed Loop Ungrounded DEH

Single Phase AC Power Supply Electrical Cable

Closed Loop Grounded DEH

Single Phase AC Power Supply

Electrical Ground

Electrical Cable

Open Loop DEH

Isolation Joint

Isolation Joint

Electrical Ground

Electrical Ground

Non-hydroscopic Thermaland Electrical Insulation

Non-hydroscopic Thermaland Electrical Insulation

Thermal Insulation



Pipe-in-pipe DEH Systems


End Feed Pipe-in-pipe DEH

Isolation Joint

Dry Pipe-in-pipe Thermaland Electrical Insulation

Bulkhead (Electrical Connection)


Centre Feed Pipe-in-pipe DEH Dry Pipe-in-pipe Thermaland Electrical Insulation

Bulkhead (Electrical Connection)Bulkhead



Indirect EH SystemsThree Phase AC Power Supply

Electrical Common

Induction Tube Heating

Conduction Tube Heating

Thermal Insulation

Ferromagnetic Tube (x3)Supply Cables (x3)

3x Single Phase AC Power Supply

Conducting Metallic Tube (x3)

Thermal Insulation

Trace Heating

Three Phase AC Power Supply

Heating Cables (multiples of 3)

Thermal Insulation

Electrical Common



Operational Issues

The principal objective for the FlowAssurance Engineer is to deliver andmaintain an operable system

Systems must reliably: start-up with wells and pipelines hot or

cold, depressurised or liquid flooded, ramp-up and ramp-down without

flooding platform based receivingplant,

• shut-down without over-pressurizing or over-heating pipeline systems,• blow-down to safe pressure in a practical time frame without flooding flare systems,• maintain performance throughout field life.

• Hydrate blockages on start-up of deep-water systems are very high risk• it may not be possible to sufficiently reduce pressures in deep water to dissociate

hydrates – a blockage can potentially write off a subsea pipeline (>$300MM)• A hydrate management strategy is required…



Operating Strategies

Continuous chemical inhibition Thermodynamic inhibitors: methanol (MeOH) or

mono-ethylene glycol (MEG). Low dosage hydrate inhibitors (LDHI):

anti-agglomerates (AA) or kinetic inhibitors (KI).

MeOH and MEG May be used on a continuous basis, but must be

recovered from the produced fluids to be economically viable. MeOH is highly flammable and is distilled out of the water phase: significant

amounts of MeOH partition into the gas phase and are lost. MEG is more viscous and heavier (requires larger diameter supply pipeline) and

is not effective at start-up or for hydrate remediation (no partitioning to gasphase).

methanol

mono-ethylene glycol

• MeOH used in oil dominated systems.• MEG preferred for gas dominated systems (particularly if

continuous injection required), but MeOH also required for start-up.• Large quantities of either chemical is required: typically 3-inch to 6-

inch supply lines.




LDHI Kinetic inhibitors slow the crystallization of

hydrates but do not provide long termprotection during shut-down.

Anti-agglomerates prevent crystals fromsticking together and growing to form apotential blockage.

Only small quantities required; may bedelivered through conventional umbilical cores(½ -inch or ¾ -inch)

Require extensive lab testing and difficult topredict effectiveness

Oceaneering Multiflex electro-hydraulic umbilical




Intermittent chemical injection Relies on injection of bulk chemicals before

start-up and shut-down. Reliable providing temperatures are kept

high during normal operation. Requires insulated or heated pipelines. Unplanned shut-down (with no bulk

chemicals in the system) represents asignificant problem.

No touch time - blow-down and deadoil displacement Passive insulation cannot prevent hydrate/wax blockage indefinitely. Insulation requirement defined by the required no-touch time. Pipelines must be blown-down to below hydrate formation pressure or hydrate

forming fluids must be displaced before temperatures become critical. SIGNIFICANT LOST REVENUE FROM LONG PIPELINES - FLARING. Dead oil (or diesel) displacement may be the only option for long, deep pipelines,

but requires a large diameter service pipeline.



Practical Considerations

Subsea temperature transducers donot measure bulk fluid temperature

The sensor is encased in aconducting paste within a thermo-well

The thermo-well is mounted in a teeand set back from the pipeline wall

The thermo-well is usually stainlesssteel with poor conductivity

The tee is often uninsulated andclose to seabed temperature

The temperature off-set may beanything up to 15°C

Welded Tee

Thermo-well

Pipeline

TemperatureSensor

Insulation



Practical Considerations

Subsea pressure transducers are (often) offset through impulse lines May be mounted on uninsulated double-block-and-bleed units Small diameter impulse lines are extremely vulnerable to blockage

PressureTransducer

MountingFace

Pipeline TeeMountingFaceImpulse line

Bleed line



Key Messages and Conclusions

Production fluids are very complex and can block (or restrict) flow: Multiphase flow – requires careful sizing of pipeline and first-stage separator and

can give rise to fatigue issues in unsupported pipework (risers) Hydrates – high temperatures or bulk chemical injection required, leading to

insulated or heated systems and blow-down or dead-oil displacement strategiesfor long term shut-down

Wax – high temperatures and pigging strategy should be maintained (sometimesinhibitor chemicals)

Asphaltenes – careful design to avoid precipitation or chemical treatment Scale – chemical injection required Salts – wash water service line Corrosion – chemical injection or material selection issues, plus long term

inspection strategies (intelligence-pigging) Solids – pigging strategy (round-trip pigging or subsea launchers)



Key Messages and Conclusions

Flow assurance drives architectures and layouts: One, two or more production pipelines (slugging, round-trip pigging, dead oil

displacement, late field life turn-down) Pipeline design (wet insulation, pipe-in-pipe insulation, heated pipelines) One, two or more service pipelines (lift gas, wash water, dead oil supply, venting

for hydrate remediation) Umbilical chemical cores (scale inhibitor, corrosion inhibitor, wax inhibitor, LDHI) Manifold functionality (temporary or permanent pig launch facilities, vent

arrangements for depressurisation)



Questions?

BHP Billiton Atlantis Production Facility, 2000m Water Depth, Gulf of Mexico

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