THE SOURCE FOR
FLOATING PRODUCTION
SYSTEMS SINCE 1996
A guide to Floating
Production Systems
2024
energymaritimeassociates.com
A guide to Floating Production Systems
2024
Contents
2
Chapter 1
Background on System Variations
3
Chapter 2
Floating Production Storage and Offloading Units
4
Chapter 3
Production Semis
5
Chapter 4
Tension Leg Platforms
6
Chapter 5
Spars
7
Chapter 6
Floating Liquefied Natural Gas Units
8
Chapter 7
Floating Storage and Regasification Units
9
Chapter 8
Floating Storage and Offloading Vessels
10
Chapter 9
Mobile Offshore Production Units
11
Chapter 10
Final Selection
12
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A guide to Floating Production Systems
2024
1. Background on System Variations
Floating Production systems (FPSs) emerged in
the 1970s as an option to produce hydrocarbons
that were discovered further offshore in water
depths that exceeded viability of fixed platform
installation. Today FPS units are available in
numerous shapes and size each with their own
unique characteristics, strengths and weaknesses.
Each production unit an operator selects is typically
designed for a specific offshore field though some
units have been repurposed through upgrade and/
or modification.
Initial production from FPSs began in 1975 from
Argyll in the North Sea followed by production in
1977 from Castellon in the Spanish Mediterranean.
During the next few decades FPSs were primarily
installed in the Gulf of Mexico and the North Sea.
Thereafter, exploration and discoveries in other
hydrocarbon basins worldwide saw increased
FPS installation activity off Brazil, West Africa and
Southeast Asia.
An operator’s decision to develop a field with an FPS
requires assessment of numerous factors with oil
pricing being one of the most influential and deciding.
3
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The FPS selection decision must include review
of field geology and environmental characteristics
including hydrocarbon specification, reservoir
requirements (water / gas / chemical injection),
well / subsea configuration, water depth, ocean
current and weather. Additional decision factors
include expected life of field, onboard hydrocarbon
storage and / or processing requirements, potential
tiebacks, budget, distance to shore and proximity to
any existing nearby infrastructure, on and offshore.
Since 1975, offshore field development solutions
and FPS designs have become increasingly
more complex. Additional improved hydrocarbon
extraction, zonal isolation, increased pumping
power for injection, larger mud motors, enhanced
seismic, rotary steerable systems, deeper large
bore wells, horizontal drilling, and lateral drilling
have all contributed to the expansion of the
FPS armada and flotilla. Consider the relative
simplicity of available car options in the late 70s
in comparison to the available options on a new
vehicle today – even standard vehicle safety
features have improved exponentially.
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A guide to Floating Production Systems
2024
2. Floating Production Storage & Offloading Units
Floating Production Storage and Offloading
Units (FPSO) are considered the most flexible of
all FPS types and certainly the most prevalent.
FPSOs produce and store hydrocarbons offshore
in varying water depths. These units receive the
complete wellstream, separate the oil, water and
gas, store the oil and offload the stabilized crude
oil to export tankers.
As water depths have increased for FPSO
installation so too have production and storage
capacities. Newer FPSOs have processing
capability exceeding 250,000 boe/d, up from
30,000 boe/d. Current maximum storage capacity
is at 2.3 million barrels, a considerable increase
from 11,000 barrels early on.
Capital costs for FPSOs range from $200 million to
beyond $3 billion.
As of January 2024, 169 FPSOs were in operation,
with 14 available and 33 on order.
FPSOs have three key components, the hull,
topside and mooring system. FPSO designs vary by
vessel and are tailored to a field’s characteristics.
As an example, the Turritella FPSO features a
large disconnectable buoy allowing the FPSO to
escape inclement weather, specifically hurricanes.
Hull
The first FPSO, Shell’s Castellon was installed in
384 ft (117 m) of water. Over the years installed
water depths have increased. The current water
depth record for FPSO installation is held by SBM’s
Turritella FPSO which currently services Shell’s
Stones development in the U.S. Gulf of Mexico in
9,500 ft (2,900 m) of water.
Storage of Oil or
Condensate
Topside: Processing
Facilities
Mooring:
Internal Turret
Topside
Power Generation
Water Injection;
possibly chemical
injection
Mooring System
Oil/Gas Processing
4
Mooring
& Risers
Permanent
Internal or External
Disconnectable
Internal or Extneral
Hull: Storage of
Oil or Condensate
Image Source: Bluewater
Turret
Spread Mooring
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3. Production Semis
Production Semis were initially converted from
existing drilling rigs, with the first conversion taking
place in 1975 for use on the Hamilton Brothers Argyll
and Duncan fields in the North Sea. As of January
2024, 37 Production Semis are in operation with 4
available and 7 units are on order. The units are well
suited for use on complex deepwater fields involving
a large number of wells over a dispersed area.
pontoons that rise above the water to support
the topside. The pontoons are partially filled with
seawater to stabilize the platform. Production semis
are extremely stable and have wide deck spaces
topside to support processing.
However, Production Semis do not have onboard
production storage capability and must be
connected to a pipeline or a Floating Storage and
Offloading (FSO) unit. Additionally, as Production
Semis are installed in deeper waters, the increased
mooring line weight decreases the unit’s deckload
storage capacity.
Production Semisubmersibles are non-ship shaped
units capable of production and drilling. Typically
Production Semis have two horizontal hulls
connected to four cylindrical or rectangular column
Hull
Pontoons
Topside: Production Equipment
(Drilling optional)
Risers
Topside
Power Generation
Production Equipment
Mooring Options
Drilling equipment (optional)
5
Spread mooring
Dynamic Positioning
Pontoons
Mooring:
Spread or DP
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Hull
Image Source: Hyundai
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A guide to Floating Production Systems
2024
4. Tension Leg Platforms
Tension Leg Platforms (TLPs) are the third most
popular Floating Production System and as of
January 2024, 27 currently are in operation. About
two-thirds of these units are installed in the Gulf of
Mexico, with others located off Africa, Brazil, in the
North Sea and offshore Southeast Asia.
Hull
Key components of a TLP include the hull, topside
and moorings. TLPs are production systems that
are attached to the seabed by tendons, typically
numbering between 6 and 16. The tendons allow
the buoyant hull to have limited vertical movement
while allowing for horizontal movement. Due to
tendon tension TLPs have very limited surface
motion that provides a stable platform for drilling
and dry trees. Dry trees are a major advantage
on fields with high hydrate/high wax crude where
well maintenance must be considered. However,
Topside
The first TLP, Hutton, was installed in 1984 for
Conoco for operation in the North Sea. Worldwide
water depths for installed units are between 656 ft
and 5,200 ft (200 m and 1,585 m).
TLPs can be used for production or as wellhead
platforms. Wellhead TLPs have no processing
capabilities and are attached to an accompanying
production facility. Production TLPs currently have
processing capability from 25,000 b/d to 360,000 b/d.
TLP costs range from $500 million to over $1 billion
depending on water depth, location and topside
facilities.
Buoyant structure that supports
the topside, typically with four
air filled pontoons
Power Generation
Mooring System
one drawback to using a TLP is that as tendon
weight increases (deep water installations) payload
capacity decreases.
Topside:
Production Equipment
(Drilling optional)
Risers
Oil/Gas Processing
Hull: Buoyancy
Steel Tendons
Attached to each pontoon and
fixed to the seabed
Risers
Tendons/
Mooring
Image Source: Doris Engineering
6
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A guide to Floating Production Systems
2024
5. Spars
Spars are similar to TLPs in that both are platform
structures that float vertically in the water, allowing
production or drilling facilities to be installed. As with
other floating production systems, components of a
Spar include the hull, topside and mooring system.
classic designs were built and installed: Neptune,
Genesis, and Diana. Newer spars, called truss
spars, no longer have a full length cylinder, but rather
an upper hard tank and a lower truss structure.
Spars are extremely stable, making them suitable
for drilling as well as production. Though no current
installed units offer storage, Aasta Hansteen
(topsides currently under construction) will have
onboard storage capacity of 160,000 bbls.
Spars are most commonly used in the US Gulf of
Mexico, due to their suitability for ultra-deepwater
installation and access to the GOM pipeline network.
As of January 2024, 21 spars currently are in
operation. Neptune, the first production Spar, was
delivered in 1996 at a cost of $300 million and
installed in 1,936 ft (590 m) of water. The most recent
Spar, Aasta Hansteen, cost $2.6 billion, and when
topsides are complete, will be installed by Equinor
in 4,265 ft (1,300 m) of water in the Norwegian Sea.
Perdido was installed by Shell in 8,005 ft (2,440 m) of
water and currently is the deepest Spar installation.
Additional Spar strengths include minimum
vertical movement, drilling capability, dry tree
accommodation, and relative insensitivity to
ultra-deepwater installation. However, Spars are
expensive and require a horizontal tow for installation
at destination. In addition, a heavy lift vessel or
floatover crane vessel for hull/topside mating is
necessary. Other drawbacks include minimal to zero
storage and the Spar’s stacked deck design limits
future flexibility.
Initially, Spars were designed with a full length
cylinder exceeding 656 ft (200 m), three of these
Hull
Buoyancy cylinders that acts as
primary support for platform
Topside:
Production Equipment
(Drilling optional)
Risers comes through the hull
to platform above
Hull
Power Generation
Topside
Risers
Oil/Gas Processing
For wellhead SPARs-
Heave
Plates
Dry trees and drilling
equipment
Chains
7
System
Mooring
Chains
Anchored to seabed
Soft Tank
Provides buoyancy during wettowing but then is filled with water
and acts as ballast once installed
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Soft Tank/
Ballast
Image Source: Statoil
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A guide to Floating Production Systems
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6. Floating Liquefied Natural Gas Units
Floating Liquefied Natural Gas Units (FLNGs) are the
newest type of floating production system. As of January
2024, 7 units currently are in operation with 8 on order.
FLNGs are floating gas-liquefaction plants mounted on
ship-shape or barge hulls with internal storage. The units
are designed to be positioned on or near a subsea naturalgas resource or moored in a location where gas can be
received from an onshore source.
The FLNG hull is used to store LNG and other liquids.
Topsides may be configured for liquefaction-only or
configured for both liquefaction and processing. Field
characteristics and location predominately determine
which topside configuration is installed on the unit. Current
FLNG designs are either turret or jetty moored systems.
FLNGs can be grouped into four sub-types: Mega, Midsize, Export Liquefaction Terminal, and Liquefaction
Barge. Installed in Australia’s Browse Basin, Shell’s Mega
Prelude FLNG has processing capacity of 3.5 mtpa of gas,
35,000 b/d of LPG/condensate and storage capacity of
220,000 m3 LNG and 1.3 million bbls of LPG/condensate.
Current water depths for FLNGs range between 262 ft
and 7,418 ft (80 m and 2,261 m).
The units are complex and costly, especially with the
addition of processing capability. Storage capacity,
mooring and design impact cost. Current liquefaction
only units range in cost from $300 million to $1.8 billion
and processing and liquefaction units cost between
$1.8 billion and $7 billion.
FLNG strengths include avoiding the need for pipelines
and onshore facilities. The units may be built as
serial units in a shipyard and have the potential for
redeployment/repurposing following field depletion.
Drawbacks include incorporation of technology not yet
proven in offshore service and the associated unknowns.
In addition, the separation process in LNG production
is sensitive to vessel motion. Without onshore facilities,
potential opposition from local government may exist
too, as no onshore jobs would be created.
Hull
Storage of LNG
Possible storage of
LPG and Condensate
LNG storage vessel
could be used if larger
storage required
Topside: Gas Processing, Power Generation and
Liquefaction Facilities
Topside
Power Generation
Liquefaction
Gas Processing
Mooring System
Transfer to LNG
Carrier for export
8
Turret
Internal or External
Jetty mooring
Hull: Storage of LNG
Mooring
& Risers
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Image Source: ABB
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A guide to Floating Production Systems
2024
7. Floating Storage and Regasification Units
Floating Storage and Regasification Units (FSRUs)
enable natural-gas delivery to consumers in
locations physically or commercially inaccessible
by pipeline. FSRUs function similarly to land-based
LNG regasification plants. They receive, store and
regasify LNG that is transported in LNG carriers.
Delivered LNG is stored in the FSRU until required
– then transformed to gas via a heat transfer plant
mounted on the hull.
As of January 2024, 49 units are in operation with
1 available, and 1 unit is on order.
FSRUs can be purpose built as a regasification
facility or an LNG carrier may be converted for use
as a regasification unit. Some FSRUs are former
LNG Regasification Vessels (LNG Regas). LNG
Regas units predate FSRUs and function as LNG
carriers with gasification capabilities. Some of
these units have been converted to FSRU service.
Topsides primarily contain power generation and
regasification equipment. LNG is stored in the
vessel hull and FSRUs may be moored offshore or
positioned alongside a jetty. Current FSRUs have
been moored in water depths between 66 ft and
367 ft (20 m and 112 m).
FSRUs have processing capability of between 240
mmcf/d and 1,000 mmcf/d of gas with LNG storage
between 126,000 cubic meters and 263,000 cubic
meters. Newbuild cost ranges from $200 – $300
million. Converted units are typically cheaper.
FSRUs can limit environmental opposition that would
apply to a land-based LNG regas plant. Units may be
used as a peak seasonal receiving/regas facility & as
an LNG carrier in off-peak season. With mobility, the
units may also be relocated on completion of a contract.
The FSRU’s primary drawback is generally having
less storage and regasification capacity compared
to land-based terminals.
Hull
Membrane
Containment of
LNG
Regasification facilities
Moss
SPB
Mooring System
Topside
Power Generation
9
Regasification
Pipeline to
transfer gas to
shore
Turret
Mooring: Jetty or Turret
(Internal or
External)
Jetty mooring
Image Source: Emerson
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Hull: Storage for LNG
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A guide to Floating Production Systems
2024
8. Floating Storage and Offloading Vessels
Floating Storage and Offloading vessels (FSOs) are
primarily used in conjunction with fixed platforms,
mobile offshore production units, and production
floaters (Semis, TLPs and Spars) to provide
offshore field storage of oil and gas condensate.
Most FSOs in operation are single-hull tankers
modified for storage/offloading use.
The majority of FSOs operate in Southeast Asia.
As of January 2024, 111 FSO units (96 oil and 15
LNG) are in operation.
FSOs have many mooring options based on
location and have been installed in water depths
between 49 ft and 3,871 ft (15 m and 1,180 m).
In some cases, FSOs are used as offshore storage/
export facilities for onshore production fields and as
storage/blending/transshipment terminals for crude
oil or refined products.
Converted FSOs cost between $30 million and
$200 million while newbuild FSOs cost between
$100 and $300 million. Currently, 111 units are in
operation.
Most FSOs store oil, although a few store LPG or
LNG. Oil storage capacity on FSOs range from
60,000 barrels to 3 million barrels. LPG FSOs store
between 54,000 m3 and 83,000 m3 of liquefied
petroleum gas. LNG FSOs store around 130,000
m3 of liquefied natural gas.
Strengths include large storage capacity and
multiple mooring options. Conversions to FSO are
considered relatively simple and when storage is
no longer required, the units may be relocated or
converted to FPSOs. One of the only drawbacks is
FSOs do not have processing capacity.
MR or Panamax
Hull
<600,000 bbls
Topside: Accommodation (option for power)
Aframax or Suezmax
(600,000-1m bbls)
VLCC or ULCC
Topside
(2m to 3m bbls)
Power Generation
Accommodation
Mooring Options
Turret
(Internal or External)
Spread mooring
Tower Yoke
Hull: Storage for Oil or Condensate
CALM or Anchor
10
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Image Source: Teekay
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A guide to Floating Production Systems
2024
9. Mobile Offshore Production Units
Mobile Offshore Production Units (MOPUs) are
essentially jack-up rigs with production facilities.
MOPUs are installed in shallow waters (less than
100 m) and are connected to a Floating Storage
and Offloading vessel (FSO) or pipeline. MOPUs
can be used for drilling and/or production. As of
January 2024, 2 units are on order.
The first MOPU was installed in the Ekofisk Field
in the Norwegian North Sea in 1971. The units are
mainly used in the Mediterranean, South Asia and
Southeast Asia, although a few MOPUs have been
designed for harsh environments like the North Sea
and Canada.
MOPUs may be converted from existing jackups
or purpose built. Converted units cost from
$50 million to $180 million while newbuilds for harsh
environments may cost between $200 million and
$300 million.
MOPU topsides are usually a single layer due to
deckload weight limitations and primarily contain
connection to risers, processing and/or drilling
equipment and accommodation. MOPUs have no
storage and no external mooring systems.
MOPUs are a cost effective solution for production of
marginal fields. Jackup to MOPU conversion costs
are typically lower than other options and the units
may be redeployed and re-leased. Drawbacks to
MOPU selection/usage include limited water depth
and production capacity. Lack of onboard storage
requires the addition of either a FSO or pipeline to
the production solution, further limiting flexibility.
Hull
Topside: Production Equipment
(Drilling optional)
Floats (tow to site)
Self installation by jackup legs
Topside
Power Generation
Production Equipment
Mooring System
Drilling equipment (optional)
11
Self Installing
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Jackup Legs
Image Source: Petronas
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A guide to Floating Production Systems
2024
10. Final Selection
Prior to selection of a FPS, the field operator
and its partners evaluate various options for
economic development of the field. Based on field
characteristics, oil price, water depth, weather,
location, and other variables mentioned above
commercial and strategic decisions are prepared.
Then, technical assessments and commercial
estimates are made and reviewed in an iterative
process until an optimum field development solution
is selected. Once the FPS design is chosen, the
specifications are developed and bidding documents
are prepared. Following pre-qualification of all
potential bidders, the operator submits a tender with
requests for bids to the pre-qualified bidders.
proposal fulfills all the technical, commercial, and
contractual requirements.
Eight FPS designs types have been conceptualized
and built in 50 years and these offerings provide
operators with field -specific solutions to efficiently
and effectively produce their discoveries. FPSOs
remain the uncontested crowd favorite, the newer
designed FLNG units have potential to eliminate
onshore infrastructure and FSRUs expand
hydrocarbon production to remote markets.
Likely
additional
FPS
designs
will
be
conceptualized and built during the next 50 years
as field characteristics and drilling techniques and
technologies continue to evolve. For now though,
operators must methodically choose between an
FPSO, Production Semi, TLP, Spar, FLNG, FSRU,
FSO and MOPU.
Typically 5-10 Years
This phase of FPS selection and bid tendering
process often takes as long, or longer, than the
actual FPS construction. Contract award is often
based on lowest price, assuming the bidder’s
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Exploration
Seismic
mapping
Drilling
Exploration
Drilling
Field
Development
Engineering
Offshore
Installation
Sub-sea
Construction
Production
Abandonment
Sampling
Fabrication/
Construction
Production
Drilling
Production
Operation
Maintenance
Decommission
Redeployment
or Recycling
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THE SOURCE FOR FLOATING PRODUCTION SYSTEMS SINCE 1996
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