POINT - Design & Op of FPSO & Subsea Systems.ppt

Design and Operation of an FPSO and
Subsea Systems
Point Engineering Ltd.
Port Harcourt, Lagos

What is an FPSO ?
 A Floating, Production, Storage and Offloading
(FPSO) unit is a vessel that is kept stationary in deep
water over a hydrocarbon production field to serve as
a refinery platform and product storage for off-loading
to tankers for worldwide distribution.
 An FPSO is tied to subsea production wells via a
system of subsea manifolds, jumpers and risers.
 An FPSO processes well stream fluids into oil, LPG or
LNG.
 Units without processing facilities are referred to as
Floating Storage & Offload (FSO) units.

FPSO Dimensions (Sample)
 Length = 280 m
 Breadth = 45 m
 Displacement = 185000 tonnes
 Storage Cap. = 900000 bbl
 Process Cap. = 200000 bbl/day
 Design life = 20 years

FPSO Advantages
 They eliminate the need for costly long-distance
pipelines to an onshore terminal.
 Particularly effective in remote or deep water
locations where seabed pipeline are not cost
effective.
 In bad weather situations (cyclones, icebergs
etc.) FPSOs release mooring/risers and steam to
safety.
 Upon field depletion FPSOs can be relocated to
a new field.

FPSO Milestones
 First Oil FPSO was built
in Spain in 1977 – Shell
Castellon.
 First Liquid Petroleum
Gas (LPG) FPSO build
completed in 2005 –
“Sanha”, operates on the
Chevron/Texaco Sanha
Field in Angola.
 First Liquid Natural Gas
(LNG) FPSO was
conversion of LNG
Carrier Golar by Keppel
in Singapore in 2007.
LPG FPSO “Sanha”
FPSO Golar

Worldwide Growth of Floating Production
Systems (FPS)

FPSO – Marine Loads
 Waves
 Wind
 Currents

FPSO – Turret Loads
 Turret weight
 Mooring loads
 Riser loads
 Buoyancy load
 Dynamic loads
 “Added mass” with
vessel motion

Flexible Risers – Critical Areas

FPSO – Loads Calculator
 Input: Updated light ship condition, loads from anchor lines,
risers, variable weights, tank levels, drafts (fore and aft), wind
loads.
 Output: Stability data, stability margins, hull bending moment
and shear loads with limit curves.

FPSO – Wave Impacts
Lessons Learnt – Forward Superstructure
High forecastle
Strong windows
Solid design forward

FPSO – Gas Dispersion and Explosion
Modeling
Using Computational Fluid Dynamics (CFD)
models to study concentration levels and
temperatures, taking into account wind
direction…

FPSO – General Arrangement and Lay-out

FPSO – Turret / Swivel Area
Risers inside guide
tubes
Riser ESV fire
protection on:
 2-hrs jet fire
Open lay-out

FPSO – Material Handling
Lay-down areas
Storage areas
Crane operations
Crash barriers
Lifting restrictions

FPSO – Vessel Motions
Note: pronounced Helideck motion in particular

FPSO - Weather Limitations
Helideck
Heave
Pitch
Roll
Night flights

FPSO – Off-loading Arrangement
Challenges:
Environmental
issues
Simple handling
necessary
Preventing ship
collision

FPSO – Collision Avoidance
Alarm zones
Longer off-loading hose(s)
Strict approach requirements for the tankers

FPSO – Risk / Safety Analyses
 Concept Risk and Emergency Preparedness
 Design Accidental Load Specification
 Gas Dispersion Study
 Fire Risk Assessment
 Explosions Evaluation report
 Qualitative Assessment of Escape and Evacuation
 Risk Analysis of Pedestal Cranes
 Qualitative Analysis of Ballast System
 Quantitative Fire and Explosion Study of Oil Storage Systems
 Reliability Analysis of Instrumented Overpressure Protection for Cargo Tanks
 Passive Fire Protection Optimization
 Environmental Impact Assessment
 Emergency Preparedness Analysis
 Quantitative Risk Assessment (QRA)
 Safety Review of Emergency Power System
 Risk Analysis Related to Material Handling
 Collision and Damaged Stability Assessment
 and more…

FPSO – Safe Design Summary
 Good segregation between hydro-carbon areas and safe areas.
 Living quarters, evacuation means and HVAC intake upwind.
 Safe escape route (or escape tunnel below production deck)
along the whole ship.
 Process area is segregated from cargo deck/area.
 Water ballast tanks around the cargo tanks – double barrier
(double hull).
 Open layout in Modules; reduced explosion risk.
 Design the aft for ship collision.
 Include measures for collision avoidance.
 Design for large helideck.
 Flare tower and other gas exhausts to be located as far as
possible from the helideck and quarters.

FPSO – Mooring Systems
There are three main types:
Spread Mooring
FPSO is moored in a fixed position.
Single Point Mooring (SPM) Systems
FPSO weathervanes around a fixed point.
Dynamic Positioning (DP)
Does not require anchor wires/chains or piled/seabed
anchors. This system is the most accurate for station keeping
but the most expensive to operate.
Single Point Mooring
Spread Mooring
Dynamic Positioning (DP)

FPSO – Largest Planned: Shell Prelude FLNG
 Due on station 2017, North-western coast of Australia in 820 feet
(250 m) water depth (25 years; permanently moored).
 Built by Samsung Heavy Industries (SHI)
 SHI & Technip consortium will engineer, procure, construct & install.
 Capable of producing:
 5.3 million tons per annum (Mtpa) of liquids
 3.6 Mtpa of LNG,
 1.3 Mtpa of condensate and
 0.4 Mtpa of LPG.
 1,600 feet (488 m) bow to stern (longer than four soccer fields).
 243 feet (74 m) wide.
 600000 tonnes when loaded, 260000 tonnes of which will be steel.
 Six times heavier than the world’s largest aircraft carrier.
 Chills natural gas to -162o
C shrinking the volume by 600 times
 World’s largest floating offshore facility.

Why Subsea?
Reasons for Using Subsea Systems
 Economics: production may not justify the
CAPEX for a platform.
 Field reservoir areas may not be reached by
delineated drilling from surface wells.
 The water depth may be too great to use a surface
well platform.
 Early Production: fast-track development is
required.

Subsea Systems
Advantages
Eliminate or reduce CAPEX of platform
Cost burden transferred from CAPEX to OPEX
Construction cycle is conducive to fast-track projects
Suitable to phased projects
Disadvantages
Complex hardware
Inaccessible for maintenance and repair.
Intervention is expensive and complex

What is a Subsea Wellhead ?
The subsea wellhead is
the interface between sub-
surface equipment
(downhole) and the
surface equipment (tree,
blowout preventer – BOP,
flowlines, host, etc.)
Subsea Wellhead

What is the Purpose of a Subsea
Wellhead ?
 Support the BOP (Blowout
Preventer) and seal the
well during drilling.
 Support and seal the
subsea tree during
production.
 Support the tubing hanger
in a conventional subsea
tree.
 Act as a hanger for the
casing strings in the well
annulus.

Subsea Wellhead Classification
 Typical Sizes: 13 ⅝ in,
16 ¾ in, 18 ¾ in, 21 ¼ in
 Most Common: 18 ¾
inch
 Pressure Ratings:
10,000 lb/in2
or 15,000
lb/in2
 Common Standard: 18
¾ in x 10,000 lb/in2
 18 ¾ in x 15,000 psi is
quickly becoming the
new standard

Subsea Wellhead Profiles
 All wellheads have an external
profile for BOP or tree connectors
 Cameron “hub” or Vetco
“mandrel” profiles are the most
common.
 Cooperative license agreements
allow competitors to provide
profile selections.
 The wellhead profile must match
the BOP or tree connector.
 BOP connectors can be changed
out but subsea trees require a
conversion spool called a tubing
spool.

Subsea Trees – What is a Subsea Tree ?
A set of valves and piping to
allow the control of a well at
the mudline and remote to
the host facility during
production.

Types of Subsea Trees
Mudline tree
Conventional tree
Horizontal tree

Subsea Tree – Major Components

Horizontal vs. Conventional Trees
Configuration

Conventional Trees
Disadvantages
The tree must be pulled if tubing must be pulled.
Dual bore Installation/Workover riser required.
More valves required per tree.
More running tools required.
Advantages
Vertical access to annulus.
Tubing is undisturbed if tree is pulled.
Dual completion designs are available.
Tubing hanger seals are not exposed to
well fluids.

Horizontal Trees
Disadvantages
The tubing is pulled if the tree fails.
No vertical access.
Tubing hanger seals are exposed to well fluid.
Advantages
Installation/workover riser not required.
Requires fewer valves per tree.
Tree is undisturbed if the tubing is
pulled.
A larger vertical bore is available.
Fewer running tools required.

Miscellaneous Tree Hardware “Jewelry”
 Retrievable subsea chokes
 Tree mounted pressure and
temperature transducers
 Downhole pressure and
temperature transducers
 Downhole flow meters
 Tree mounted flow meters
 ROV overrides on tree valves
 Seal test ports
 Trawlboard and dropped object
protection

Subsea Tree Characteristics
 Type: Conventional or Horizontal
 Working Pressure Rating : 5000,
10000, or 15000 psig
 Tubing Size: production tubing
and annulus tubing ( 4 in x 2 in)
 Any Special Features: integral
block, clad, guideline/
guidelineless, split, TFL, etc.
 Example: Horizontal 4 x 2- 10000
psi, Inconel clad, guidelineless
subsea tree

Subsea Manifold Systems
 A collection of valves,
pipework and
connection devices
located in a structural
cage on the seabed.
 A subsea manifold
collects flow from
multiple wells before
transporting the fluid
to the host facility.
What is a Subsea Manifold ?

Subsea Manifold Systems
 Provide an economical
alternative to individual
flowlines.
 Commingle production
from individual wells.
 Provide a mechanism
for well testing.
 Allows first oil to be
produced in a phased
well development
program.
Why are subsea manifolds necessary ?
 Collect flow from a number of subsea wells into a single
transportation system.

Subsea Manifold Types
 Template Manifolds
 Cluster Manifolds
 Large Gathering
Manifolds
 Hybrid Manifolds

Subsea – Template Manifolds
 Provide drilling
base and manifold
in one structure.
 Provide a multi-
well drilling
template.
 May be small (i.e.
3-slot) or large (i.e.
24-slot)
 Provide multi-well
subsea tieback to
a host facility.

Subsea – Cluster Manifolds
 Trees are located within 15 to 50 m.
 Generally small (4 or 6-slots).
 Commingle production or distribute injection.
 Have a retrievable module design.

Subsea – Modular Manifolds
 Modular ‘Building block’ arrangement
 Size may be increased after installation
 Some designs fold up for smaller
installation package
 Standard design

Subsea – Hybrid Manifolds
 Are Template Manifolds
that allow satellite well
tie-ins.
 Generally large
structure for high well
count.
 Have associated
production riser system.
 Are generally located
near the platform
facility.

Basic Subsea Manifold Designs
Single Header Manifolds
 Water injection
 Gas injection
Dual or Multiple Header Manifolds
 Oil and gas production systems
 Dual flowlines
 Well test and gas lift capabilities

Basic Manifold Designs – Single Header
Single Header Manifolds
 Typical of gas or water injection manifolds
 As wells connected to the main header
 Non-piggable

Basic Manifold Designs – Dual Header
Dual Header With Selective Branch Valves
 Selective routing of wells to headers
 Allows round trip pigging
 Accommodates well test via isolation
 Allows dual pressure regime production

Basic Manifold Designs – Multi-Header
Multi-Header With Selective Branch Valves
 Selective routing of wells to production header or
test line
 Allows round trip pigging
 Allows dual pressure regime production

Manifold Assembly Examples
Template Manifold
Cluster Manifold
Cluster Manifold

Subsea Jumper (Tie-in) Systems
What is a Subsea Jumper ?
 A means of
connecting subsea
equipment together
 Consists of
connection devices at
either end of a jumper
spool piece (pipe)

Subsea Jumper Systems
Subsea Jumper Basic Types
Rigid Pipe Spool
 Equipment is
connected using a
jumper fabricated
from rigid pipe.
 Can be fabricated
on site or onshore.
Flexible Pipe Spool
 Flexible pipe spool
(e.g. Coflexip)
 Equipment is
connected using
flexible pipe.
 Manufactured on
shore and shipped
complete.

Rigid Jumpers - Examples

Flexible Jumpers - Examples

Horizontal Connection System
Horizontal Arrangement
 Stab and hinge-over design
(SHO).
 Mating hubs are positioned
together horizontally.
 Connection made by running
tool or integrated hydraulics.
 Hubs are pulled (running tool)
or stoked (integrated
hydraulics) together before
connection is made.
Horizontal Connection

Vertical Connection System
 Does not require a pull-in capability.
 Stroking and connection is carried out by
the Connector itself, or by the ROV
operated Connector Actuation Tool (CAT)
system.
Vertical Connection
Collet Connector
Receiver

Subsea
Jumper
Systems

Subsea Control Systems
FUNCTION
Tree valves
SCSSV’S
Chokes
Manifold valves
Pipeline valves
Throttle valves
PREVENT
Operator error
Overpressure
Incorrect valve operation
MONITOR
Pressure
Temperature
Flow rate
Choke position
Valve position
Erosion rates
Corrosion rates
RESPOND
Automatic well shut-in
Automatic choke control
Automatic system shut-in

Electro-Hydraulic Control System Components
 Hydraulic power unit (HPU)
 Master control station (MCS)
 Electrical power unit (EPU)
 Uninterruptible power supply (UPS)
 Topside umbilical termination assembly (TUTA)
 Subsea umbilical
 Umbilical termination unit (UTA)
 Subsea distribution unit (SDU)
 Flying leads
 Subsea control module (SCM or Pod)

Hydraulic Power Unit (HPU)
 Provides system hydraulic
pressure.
 Stores control fluid energy.
 Supplies clean hydraulic
fluid.
 Regulates supply pressure.
 Sends status information to
the MCS.
 Allows remote or local
control.

Master Control Station (MCS)
 Operator control station.
 Supplies and monitors
subsea power.
 Sends and receives signals
via the SCM.
 Allows operator intervention.
 Provides interface with
platform control system.

Subsea Control Pod
 Subsea control center
 Executes commands from the
surface
 Features:
 Must be fully retrievable
 Receives and sends signals to MCS
 Tracks internal status and transmits
to the MCS
 Operates subsea valves
 Monitors subsea sensors
 Re-configurable from the topside
 May operate 18-24 hydraulic
functions
 May monitor 8-10 remote sensor
inputs

Subsea Umbilicals
 Provide link between surface (operator) and subsea
equipment.
 Supply hydraulic fluid to operate subsea valves and
chokes.
 Supply electrical power to operate subsea electronics.
 Transmit electronic signals to execute operational
commands subsea.
 Return electronic data to the surface from subsea
instrumentation.
 Umbilicals of many
types/sizes/configurations/materials exist.

Subsea Umbilicals (cont’d.)
 Many factors affect their design:
 Water depth
 Tie-back type
 Internal pressure
 Tie-back length
 Installation methods
 Chemical compatibility
 Flow rates
 Size of field
 Service life

Subsea Umbilicals (cont’d.)
 Types:
 Hydraulic umbilicals
 Electrical electric umbilicals
 Electro-hydraulic umbilicals
 Construction:
 Thermoplastic tube umbilicals
 Steel tube umbilicals
 New Configurations:
 Integrated service umbilicals (ISU)
 Integrated production umbilicals (IPU)

Direct or Piloted Hydraulic Umbilical
 Simple
o Short tie-backs
o Steel tube or hose
 All hydraulic systems

 Complex
o Electrical power pairs
o Electrical signal pairs
o HP hydraulic supply –
hose or tube
o LP hydraulic supply –
hose or tube
 Most common type
o Deep water applications
o Long offsets
Electro-Hydraulic Umbilical

Subsea Umbilicals
 Water depth
 Tie-back type
 Tie-back length
 Service life
 Installation
 Chemical compatibility
 Flow rates
 Internal pressures
 Size of field
Design Considerations:

Subsea Umbilical Terminations
 Provides the subsea
termination for the
umbilical.
 Can be the subsea
distribution point for
hydraulic fluid, electrical
power, electronic signals,
and injection chemicals.
 Provides an interface for
flying leads or subsea
distribution units (SDUs).
 Can be retrieved for
maintenance.
Umbilical Termination Unit (UTA)

Subsea Distribution
 Connect UTA or SDU
to subsea trees and
manifolds.
 Provide distribution of
hydraulic fluid,
electrical power,
electronic signals, and
injection chemicals to
subsea equipment.
Flying Leads
maintenance.
 May be high collapse resistant
thermoplastic or steel tube
configurations.

Subsea Distribution Unit (SDU)
 Provides distribution
of hydraulic fluid,
electrical power,
electronic signals, and
injection chemicals to
subsea equipment.
 Provides interface for
flying leads.
 Can be an isolation
point for supplies.
maintenance.
 Can be reconfigured
subsea.

Sample Applicable Standards
 American Petroleum
Institute (API):
 RP2G, RP14E,
RP17A, RP57,
RP505, RP551,
RP579, RP1110,
Spec. 5L, Spec. 4F,
Spec. 6A, Spec. 6D,
Spec. 14A, Spec.
17D, Spec. 17E, Std.
510, Std. 537, Std.
570, Std. 617, Std.
618, Std. 619, Std.
660, Std 2610, etc.
 American Society
of Mechanical
Engineers
(ASME):
 B16.5, B31.1,
B31.3, B31.4,
B31.8, etc.
 Boiler and Pressure
Vessel Code
Sections I – IV,
Section VIII,
Divisions I and II,
etc.
 International
Standards
Organization
(ISO):
 3183, 10417,
10423, 11950,
15649, 15547,
13623, 15590,
13500, 13628,
19900, etc.

POINT - Design & Op of FPSO & Subsea Systems.ppt

End of Presentation
Thank you.
Point Engineering Ltd.
Port Harcourt, Lagos

POINT - Design & Op of FPSO & Subsea Systems.ppt

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