Are you confused about the many variations of Floating Production Systems?
Here is everything you need to know about the 8 types of systems currently in operation worldwide.
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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. 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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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 of December 2019, 174 FPSOs were in operation, with 25 available and 25 on order.
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.
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.
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.
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Tension Leg Platforms
Tension Leg Platforms (TLPs) are the third most popular Floating Production System and as of December 2019, 28 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.
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, one drawback to using a TLP is that as tendon weight increases (deep water installations) payload capacity decreases.
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.
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Floating Liquefied Natural Gas Units
Floating Liquefied Natural Gas Units (FLNGs) are the newest type of floating production system. As of December 2019, four units currently are in operation with four 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 natural-gas 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, Mid-size, 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.
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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.
As of December 2019, 102 FSO units are in operation.
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.
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.
Most FSOs in operation are single-hull tankers modified for storage/offloading use. The majority of FSOs operate in Southeast Asia.
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).
Converted FSOs cost between $30 million and $200 million while newbuild FSOs cost between $100 and $300 million. Currently, 102 units are in operation.
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.
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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.
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 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.
