flow assurance introduction
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MSc O&G and Subsea Engineering
Flow Assurance
Introduction to Key Concepts in Flow Assurance
Tom Baxter, Senior Fellow Chemical Engineering
Technical Director, Genesis Oil and gas Consultants
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Subsea Pipeline Flow Assurance
• Introduction to Flow Assurance
• Offshore infrastructure
• Key challenges
• Phase behaviour
• Multiphase flow• Heat transfer
• Production chemistry - hydrates, wax, scale and asphaltenes
• System integrity – corrosion, erosion
• Operations
• Subsea processing
• Conclusions and key messages
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Flow Assurance
Flow assurance encompasses the thermal-hydraulic
design and assessment of multiphase production/transportsystems as well as the prediction, prevention, andremediation of flow stoppages due to solids deposition(particularly due to hydrates and waxes). In all cases, flow
assurance designs must consider the capabilities andrequirements for all parts of the system throughout theentire production life of the system.
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Subsea Systems
The fluids within a subsea pipeline arecategorised as;
• Single phase liquid – export oil,
injection water
• Dry gas – export gas, lift gas
• Wet Gas - export gas, lift gas
• Multi-phase fluid – production fromsubsea well
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Platform Infrastructure
Gas Oil
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Subsea SystemsSubsea – Platfrom Infrastructure
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Concept Hosts - Steel Jackets
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Harding
Elgin
Shah Deniz
TPG/Jack-Ups
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Tension Leg Platforms
Mars – After Katrina
Ram Powell1000m water depth
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Semi-SubmersibleSemi-Submersible
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Semi-Submersible
BP’s Thunder Horse (GOM)
production-drilling-quarters (PDQ) isthe world's largest production semi-
submersible ever built. The platform'stopside area is the size of threefootball fields.
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SPAR
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Concrete
Hibernia
Brent D
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Ice Scour Protection
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FPSO
BP Skarv
BP Schiehallion
BP Fionaven
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The turret is a key part of many FPSOs. It is the point around which the FPSOweather vanes and at which all risers are gathered. The number of risers is the key
parameter which defines the diameter and size of the turret. The turret is also thepart of the FPSO which is moored to the seabed. Any turret therefore has a “fixed”
part (moored to the seabed) and a rotating part (part of the hull).
There are many designs of turret available. Turrets can be designed to bepermanent or disconnectable (e.g. Cossack Pioneer, Australia). They can also beinternal or external.
A key component of a turret system of the swivel which contains fluid path swivelsto transfer all production and utilities fluids from the fixed to the rotating part of theFPSO.
Liquid Flowpath
Leak recuperation path Seal OilLeak Rec. path
Gas Path
Turrets
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Sevan FPSO
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Greater Plutonio – Spread Moored
Hull does not weather vane – suitable for consistent directional environmentalloadings
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Depth Summary
O h T i l
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Onshore Terminals
Oil T i l F ti
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Oil Terminal Functions
• Basic oil terminal functions are:
• Reception of crude oil from pipelines or shuttle tankers• Stabilisation of crude oil (including dehydration/desalting, gas/water
treatment)
• Fractionation of associated gas into:
• Lighter gases (methane and ethane) normally used as fuel for
power generation• Propane (LPG)
• Butane(LPG)
• Storage of stabilised crude and LPG
• Export / trans-shipment of productsinto tankers or pipelines fordistribution to refineries for furtherdownstream processing
G T i l F ti
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• Gas dehydration
• Removal of natural gasliquids – ethane,propane, butane andheavier components
• Removal of carbon
dioxide and sulphurdioxide
• Removal of otherunwanted components
– mercaptans, mercury
Gas Terminal Functions• Gas terminals are intermediate gas treatment
facilities collecting partially processed gas from
offshore facilities and pipelines.
• Reception of gas from pipelines
• Treatment of the gas for sale to the onshoregas grid;
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The Main Challenges
• Accurate prediction of :
• Pressure profile
• Temperature profile• Flow Instabilities:
• Slugging
• Pipeline Blockages:
• Hydrates
• Wax
• Asphaltenes
• Scale
• Loss of Containment:
• Corrosion• Erosion
Much of the flow assurance challengereduces to identifying, understanding
and managing uncertainty
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Deep Water Challenges
• Remote and inaccessible.
• Low ambient water temperatures.• Long distance tie-backs.
• Long risers – hydrostatic head.
• 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
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Single-component Phase
Behaviour
Critical Point
Triple Point
Liquid
Gas
Solid
Dense PhaseSupercritical
Superheated
Gas
Temperature
P r e s s u r e
R i Fl id
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Reservoir Fluids
METHANE &
ETHANE
CARBON DIOXIDE
HYDROGEN SULPHIDE
SAND
WATER
LOWEST
BOILING POINT
HIGHEST
BOILING POINT
gases
naphtha
gasoline
kerosene
diesel oils
Lubricating
oils
Fuel oil
residue
Propane and butane gas for lighter fuel
& camping stoves
Chemicals for medicines, plastics, paints,
cosmetics & clothing materials
Petrol for vehicles
Jet fuel and paraffin
Diesel fuel
Machine oil, waxes and polishes
Fuel for ships and central heating
Bitumen for road surfaces and roofing
materials
SUBSTANCE USES
Other components which may
require treatment/considerationare;
• Hydrogen Cyanide (HCN)
• Carbonyl Sulphide (COS)
• Carbon Disulphide (CS2)
• Mercaptans (RSH)
• Nitrogen (N2)
• Sulphur Dioxide (SO2)• Mercury
The proportions of the components will vary depending on field type.
Oil d G C tR i Fl id
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Oil and Gas Components
Alkanes (Parrafins).
Methane (CH4)
Ethane
Propane
Butane
……….
Octane (C8H18)
Aromatics
Benzene
Napthenates
one or more cyclicstructures
Cycloparaffins
one or more cyclicstructures
Reservoir Fluids
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0
20
40
60
80
100
120
140
-100 -80 -60 -40 -20 0 20 40 60
P r e s s u r e ( b
a r a )
Temperature (C)
Multi-component Phase
Behaviour
Cricondenbar
C r i c o n d e n t h e r m
Critical Point
Liquid
MultiphaseGas
10%
20%
30%
70%
50%
40%
Dense Phase
Wellhead
Host
Liq ids and Gases
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Liquids and Gases
• Incompressible - Liquids offer resistance tocompression. Volume changes are negligible with
pressure.
• Compressible - Gases and vapours are compressible.
Volume changes with pressure. Density changes with
pressure.
Key physical properties;
• Density• Viscosity
• Specific heat
• Thermal conductivity
Pressure Loss Friction
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Pressure Loss Friction
The prediction of the pressure in a pipeline system is a keyelement of subsea pipeline design. Pressure losses will becritical to predicting whether a well will flow to host, the size ofthe pipeline required, the mechanical design of the pipe, thematerials of construction, requirement for gas lift.......
D
v L f P f
2
2
The analysis of pressuredrop in multi-phase flow issignificantly more complexthan single phase flow .
Head and Pressure
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Head and Pressure
If the pipeline flows vertically (riser) or down/uphill, in addition to frictionanother pressure loss occurs due to the change in elevation (change in
potential energy). This is referred to as head elevation losses/gain. It isdependent upon fluid density.
Determination of
density in multi-phasesystems can be difficultdue to phase slippage.
Gas Lift
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Gas Lift
Lift gas is delivered from
the receiving facility. The liftgas is introduced into theproduced fluids reducingthe system density.
The gas compressionfacility on the host has tohandle returning lift gas andthe gas associated with theproduced oil.
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The well and subsea hydraulics
must be matched with the
reservoir characteristics
Horizontal Flow Regimes
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Horizontal Flow Regimes
Vertical Flow Regimes
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Vertical Flow Regimes
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Multiphase Flow Maps
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Slug Flow
• Unstable flow - intermittent slugs / surges of liquid and gas delivered to
downstream processing facilities
• Perturbations in gas and liquid flow can cause serious control problems with
receiving process plant
• Three mechanisms by which slug flow can develop during normal steady state
operation:
- hydrodynamic - flow regime based.
- terrain - undulating seabed.- “severe” riser slugging (a form of terrain induced).
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The Severe Slug
Overall Heat Transfer Coefficient U
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l
q
f T
aT
oT
iT
Inside/outside boundary layers:
Overall heat transfer (including fluids):
Inside and outside film coefficients canbe estimated from empirical correlations.
aooo T T Ahq
i f ii T T Ahq
a f
oo
t
ii
T T q Ah
R Ah
11
a f T T UAq ref
oo
n
m m
mimo
ii hd k
r r
hd l
A
U
1
2
ln11
1
ref where:
Overall Heat Transfer Coefficient, U
Units for U are Watts per square metre per Kelvin (W/m2/K).
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Heat Transfer - Flowing Pipeline
Heat loss from fluid : xdx
dT cm x
dx
dT T T cmdq
f
p
f
f f p
Heat loss through wall : a f T T U xd dq ref
Temperature decays exponentially, if fluid properties and OHTC are constant
a f
p
f T T
cm
U d
dx
dT
ref x
cmU d
a f
a f peT T
T T
ref
1
Equate heat loss and integrate:
f T xdx
dT T
f
f
x
dq
x
m1 f T
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OHTC = 0.8 W/M2DegC
OHTC = 2 W/M2DegC
OHTC = 10W/M2DegC
Heat Transfer – Identification of U
Value
Insulation
can be veryexpensive.
S
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Pipeline Insulation Systems
• Insulation systems are classed as WET or DRY , depending onwhether the insulation is contained inside a structural carr ier
pipe
Solid insulating material(at ambient pressure)
Anti-corrosion
coating
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
W t I l ti S t
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Wet Insulation Systems
• Deepwater wet insulation is typically based on
syntact ic p olyurethane (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 glass for extreme depths.
• Theoretically applicable in depths down to 2800m
• Limited maximum temperature at about 115 ° C
• Alternatives can be based on composi te
polypropylene (PP) systems
• Composed of a layer of foamed PP surrounded by athick layer of solid PP
• PP has higher operating temperature at about 155 ° C
• Typical OHTCs in the range 2.0 to 3.5 W/m 2 /K
Bredero Shaw ThermoFlo® SPU system
Bredero Shaw Thermotite® PP systemMajor suppliers include Dow Hyperlast, Bredero Shaw and EUPEC
D I l i S
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Dry Insulation Systems
• Dry insulation must be contained
in a structural carrier pipe
• Carrier pipe must be watertight andcollapse 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 woolbased materials offer low OHTC
and high temperature service
• OHTC ~0.7 W/m2 /K
• Max temperature >200 ° C
Aspen Aerogels – Pyrogel®
Outer pipe providesmechanical protection for
insulating material.
H t d Fl li C t
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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 bundledwith production pipes in a common carrier
• Electrical systems may also be direct or indirect
• Direct electrical heating (DEH) relies on pipeline steelcarrying the heating current
• Indirect heating systems use induced currents in thepipeline or direct thermal contact with electricallyheated cables
El t i ll H t d S t
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Electrically Heated Systems
• Systems can be Direct Electrically Heated (suitable for single pipe
and pipe-in-pipe systems) or Indirect Electrically Heated (suitablefor bundled applications)
• 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)
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Subsea Cooling Spool
H d t
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Hydrates
• Hydrates are crystalline solids formed in
the presence 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!
H d t F ti
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1
10
100
1000
0 5 10 15 20 25 30 35
P r e s s u r e
( b a r a )
Temperature (C)
Methane Ethane Carbon Dioxide Hydrogen Sulphide
Hydrate Formation
• Hydrates form when a small
molecule (guest mo lecule )
stabilizes hydrogen bondsbetween water molecules (host
molecules )
• The host molecules form cages
(12, 14 or 16 sided) round the
guest molecule• Different hydrate types have
different cage 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
Host
Molecules
Guest
Molecule
Hydrate Management
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yd ate a age e t
There are generally three prevention methods:
1. Water removal.
Free water is removed through separation, and waterdissolved in the gas is removed by drying with tri-ethylene
Glycol or a molecular sieve to obtain water contents which
are sufficiently to prevent water from condensing as the
pipeline contents cool. Clearly this option would not be
possible for a subsea development where unprocessesd
reservoir fluids and transported to a host installation.
2. Maintaining high temperatures
High reservoir fluid temperature may be retained through
insulation and pipe bundling, or additional heat may be input
via hot fluids or electrical heating.
3. Addition of hydrate inhibition chemicals
Chemicals such as methanol (MeOH), mono-ethylene glycol
(MEG) or Threshold Hydrate Inhibitors (THI) can added. These
chemicals suppress the formation of hydrates or prevent
hydrates forming blockages.
H drate Management
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Hydrate Management
• Low Dosage Hydrate Inhibitors• Kinetic inhibitors slow the crystallization
of hydrates but do not provide long termprotection during shut-down.
• Anti-agglomerates prevent crystals from
sticking 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
to predict effectiveness
Oceaneering Multiflex electro-hydraulic umbilical
W
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Wax
• Wax is formed from long chain
paraff ins and naphthenes
• Wax crystals precipitate out of
solution at low temperatures
• The wax appearance temperatur e
(WAT) or cloud po in t is the
temperature at which wax crystalsfirst appear
• Wax can only deposit if the pipe wall isbelow WAT
• The pour po in t is the lowest
temperature at which the oil can bepoured under gravity
• A yield force is required to start fluidsflowing if temperature is below thepour point
Wax Deposition
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Wax Deposition
• Wax solidifies if the fluid temperature is
below WAT
• Wax crystals will remain suspended unlessthere is a temperature g radient
• Deposition of wax occurs as a result of
molecular diffusion and shear dispersion
• Wax may harden over time
• Wax inhibition chemicals used to mitigate
effects,
Concentration gradient influid as heavy moleculessolidify drives lightmolecules away from wall
WAT
Tinlet
Tambient
Asphaltenes
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Asphaltenes
• Dark brown or black solids that
precipitate in the presence of n-pentaneor n-heptane
• Asphaltenes are solid particles in a
dispersed phase within the oil
• Flocculate (come out of suspension) as
a result 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
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Other Issues
Corrosion
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).
Other Iss es
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Other Issues
• Solids• Solids (sand and debris) will
deposit along with wax ifvelocities are insufficiently high
• Bottom solids provide sites formicrobial growth (and
subsequent corrosion)• Physical removal by pigging isthe only assured solution
• Emulsions
• Water and oil phases can formstable emulsions if there is
sufficient mixing in the presenceof emulsifying agents
• Emulsions make the fluids non-Newtonian
• Generally, emulsions are more of a problem forprocessing, but can make transportation overlong distances less predictable
E i
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ErosionThe wastage of material due to mechanical removal of the
material surface by a flowing environment.
Operational Issues Transients
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Operational Issues - Transients
• The principal objective for the Flow Assurance 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 withoutflooding platform based receiving plant,
• shut-down without causing temperature related issues,
• 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)
Transients/Operating Procedures
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Transients/Operating Procedures
Pipeline Warm Up
INNER WALL SURFACE TEMPERATURE,BRANCH-PIPE [C]
0[s]
1801[s]
3602[s]
5403[s]
7205[s]
9006[s]
1.081e+004[s]
1.261e+004[s]
1.441e+004[s]
1.621e+004[s]
1.801e+004[s]
2.432e+004[s]
4.32e+004[s]
70
65
60
55
50
45
40
35
30
25
20
15
10
5
0
Length [m]Otter to Eider - Steady State Basis and Restart Case 5 - 40 mbd 30% Wcut
2500020000150001000050000
Subsea Blue Skies Future?
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Subsea Blue Skies Future?
• No limit to tie back distance• No offshore production surface facilities• Satellite with broad band control & communications• Through water/ air interface radio communications• Subsea power generation• Beach based or long distance existing platform field control• Subsea storage of produced product with consideration to ‘Cold Flow’ technologies • Intelligent monitoring and safety shut down systems
Subsea Separation
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Subsea Separation
Subsea Water Injection and
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Subsea Water Injection and
TreatmentTraditional topsides
plant includes;
-Filtration-Deaeration-Chemical treatment
-Pumping
Locate on seabed.
Multiphase Metering
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Multiphase Metering
Framo - meter
Seabed Multi-phase Pump
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Subsea Compression
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Subsea Compression
Wellhead pressure reduction allowing increased flowrate and improved recovery.
Cold Flow
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Cold Flow
Laggan Tormore Project
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The overall development concept consists of along distance tie-back of subsea wellsconnected to a new gas processing terminal at
Sullom Voe on Shetland, with further export ofthe processed gas to the UK Frigg (FUKA)pipeline system in the North Sea.The subsea production system offshore willconsist of two identical six slot template-manifolds, with up to eight development wells
required to produce the expected reserves andan initial plateau production rate of 500MMscfd. The commingled, multiphase fluidstream will be transported to shore via two120km, 18” production flowlines. The subseawells will be controlled via an electro-hydraulic
control umbilical with a separate smallerdiameter flowline injecting a continuous streamof MEG to inhibit the production of hydrateswhich can form at the low temperatures andhigh pressures experienced.
Flow assurance is the
enabling technology whichmakes this developmentcommercially attractive.
Key Messages and Conclusions
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Key Messages and Conclusions
• Production fluids are very complex and can block (or restrict)
flow:• Multiphase flow – optimisation of system requires the correct application of
complex thermohydraulic analysis
• Hydrates – high temperatures or bulk chemical injection required, leadingto insulated or heated systems and blow-down or dead-oil displacementstrategies for long term shut-down
• Wax – high temperatures and pigging strategy should be maintained(sometimes inhibitor chemicals)
• Asphaltenes – careful design to avoid precipitation or chemical treatment
• Scale – chemical injection required
• Corrosion – chemical injection or material selection issues, plus long terminspection strategies (intelligence-pigging)
• Erosion – velocity control and material selection
Key Messages and Conclusions
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Key Messages and Conclusions
• Flow assurance drives architectures and layouts:
• One, two or more production pipelines (slugging, round-trip pigging, deadoil 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)
• Thermodynamic hydrate inhibitor supply (Methanol or MEG servicepipeline)
• Umbilical chemical cores (scale inhibitor, corrosion inhibitor, wax inhibitor,LDHI)
• Manifold functionality (temporary or permanent pig launch facilities, ventarrangements for depressurisation)
Key Messages and Conclusions
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Key Messages and Conclusions
• If the flow assurance analysis isincorrect, the design and operation
of the pipeline and supporting
systems will be flawed and in theextreme the system may be
inoperable.