Offshore Floating Production

Edited by Stuart Beadnall; Simon Moore; Max Lemanski

Document

Appendix A

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Floating production units – history, design, installation and operation

Dr James R MacGregor

Part (i) – FPSO history

A Overview

A.1 There have been three main phases in the development of the FPSO concept:

1. The 1970s to early 1990s saw a 20-year period of slow growth, characterised by small, low budget projects, in mild environment areas. Virtually all projects were based on converted tankers, and floating production technology was not widely accepted (especially for harsh environments) by the oil majors and large contractors. Key technologies such as turret moorings, production swivels and flexible risers were developed and refined;
2. In the 1990s there was a period of transition in which the FPSO technology matured and several parallel developments led to widespread acceptance. The volume of oil production handled by FPSOs quadrupled during the 1990s. Low oil prices and new FPSO leasing contractors facilitated the acceptance in the North Sea area. This familiarised the oil majors with the technology and allowed them to consider FPSOs for future major projects elsewhere. A mix of newbuild vessels and converted tankers were used but sizes and production capacities remained relatively modest;
3. 2000 onwards, FPSOs became the key enabler for development of large oilfields in deep water offshore West Africa and Brazil. Many of these projects required large, purpose built FPSOs with heavy topsides, and were often led by the oil majors. The FPSO is accepted as a ‘standard’ technology.

A.2 The key period of the 1990s was characterised by the move towards deep water, making fixed platforms difficult and expensive, and a low oil price environment (especially in the early 1990s) limiting the funds available. At the same time, there was a desire to develop smaller fields remote from existing pipeline export infrastructure, and the emergence of FPSO leasing contractors willing to take risks associated with investment and residual value in FPSO vessels.

B Early platforms for offshore oil production

A.3 Offshore oil and gas production began in the shallow waters of the Gulf of Mexico and was initially based on extending existing civil/harbour engineering technology to

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permit fixed bottom founded structures. These were lattice type steel structures (‘jackets’) made from relatively small diameter tubular members supported by piles driven into the sea floor. The hydrocarbon production equipment and decks were mounted on top of the jacket, in weather dependent offshore lifting and construction campaigns. A.4 Some alternatives to steel jackets began to appear in the early 1970s. In 1973, the first concrete gravity platform built inshore, floated to the site, and installed on the bottom appeared in the North Sea. These platforms required deep coastal waters to build, but the ability to float permitted the topsides to be installed in a controlled inshore environment. A.5 After the first oil shock of the early 1970s, offshore oil and gas exploration moved into deeper waters at a rapid rate, facilitated by the use of floating drilling rigs. When reserves were found in these waters the subsequent production platforms were forced to deal with these increased depths. Some notable examples of the huge jackets required in the Gulf of Mexico were Shell’s Cognac platform in 311m of water in 1977, followed by Bullwinkle in 492m water depth.

C The drive to deeper water

A.6 These projects were pushing the practical boundaries of fixed offshore structure technology which was not economically feasible for the development of oil and gas fields in waters reaching more than 1,000m depth. Floating systems are much better candidates because the weight and cost increase gradually with water depth, while that of fixed structures increases more or less exponentially. The growth in floating production, storage and offloading systems (of various types, functions and features) began. A.7 Around the turn of the millennium, floating platform technology received a further boost when deepwater drilling units capable of operations in water depths of 3,000m or more began to appear (before then, 500 metres was considered ‘deep’). Oil and gas reserves were soon found in these deep waters and for these cases FPSOs or other floating production concepts became necessary. A.8 Some examples of the water depth progression of drilling technology and FPSOs are given by Agip’s Firenze (1998) in 830m in the Adriatic, Shell’s BC-10 (2009) in 1,780m offshore Brazil using steel catenary risers, and Shell’s Stones FPSO (2016) in 2,900m in the US Gulf of Mexico.

D FPSO use on marginal fields – milder environments

A.9 At the same time as moves towards deeper water were taking place in the 1980s, smaller, marginal oil fields were being developed in remote regions where there was little infrastructure and subsea oil export pipelines could not be economically justified. For such projects, often in relatively shallow water, the tanker based FPSO was a convenient solution, as the oil could be stored onboard and periodically exported by tanker rather than by pipeline. Floating production units were attractive for marginal fields with short production durations because their ability to be moved elsewhere allowed (in theory at least) their cost to be spread over more than just the initial short life of the marginal field. These projects allowed the FPSO technology to be developed and gain acceptance during the 1980s. A.10

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In 1977, Shell deployed the first FPSO at the Castellon field offshore Tarragona, Spain. The Castellon FPSO had a simple topsides with a modest processing capacity of 20,000 bopd,1 and the hull was a conversion of a 60,000 DWT tanker. A.11 In 1979 offshore Brazil, Petrobras followed Castellon with an FPSO that started production at the Garoupa field. As floating production became a more popular option, FPSO use expanded, but mainly in milder environments such as West Africa and the Mediterranean. In 1985, the number of FPSOs in operation could still be counted on one hand. It took about 15 years from Castellon (1977) until general acceptance. A.12 By the 1990s, confidence in the technology had grown sufficiently to allow deployment of FPSOs in the harsh and highly regulated environment of the North Sea. Again, the driver here was not water depth but economics, driven by a low oil price environment and smaller field sizes. The North Sea FPSOs were generally deployed on smaller fields which could not justify oil export pipelines. The presence of leasing contractors willing to take financial risk on the residual value of the FPSOs assisted in making some of these field development projects viable.

E FPSO application to harsh environments – North Sea

A.13 In the North Sea, early reluctance to use FPSOs was primarily due to technical concerns related to the effect of the harsh environment on the vessel motions and moorings. A few monohull floating storage and offloading units (FSOs) had been used in the UK North Sea since 1981 (Shell’s Fulmar floating storage unit – a converted tanker). The breakaway of this unit from its rigid single point mooring in 1989 did not help the case for deployment of FPSOs. A.14 However, by the early 1990s the declining size of field discoveries on the UK sector and a resulting need to use more economic development techniques coincided with increasing confidence in the key FPSO technologies. Advances in mooring and offloading systems and in fluid swivel technology were key factors in the acceptance and development of modern FPSOs. A.15 There are three candidates for the title of the first FPSO to work in the North Sea:

1. The Petrojarl I was a turret moored FPSO ordered in Japan on speculation by a Norwegian ship owner. The vessel, although small, was sophisticated and purpose designed. She arrived in Norway in 1986, where she was initially engaged in well testing at the Oseberg field from 1986–1988. This was followed by several short-term test contracts until Amerada Hess hired the vessel for its first full field development contract at the UK Angus field from 1991–1993. This was followed by multiple later deployments (Petrojarl I is still operating in Brazil as of 2021);
2. BP’s dynamically positioned Seillean produced and stored oil in the North Sea shortly before the Angus field commenced production. This unique vessel was BP’s idea for sequential production from small fields and was also a sophisticated, purpose-designed newbuild. Unfortunately, the concept used the soon to be outdated rigid riser technology and dynamic positioning instead of mooring.

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Seillean produced at the Cyrus field (1990–1992) and the Donan field (1992–1997). This vessel did not offload by shuttle tanker or pipeline and had to disconnect and sail to shore to discharge its cargo. The cargo capacity was limited because the process plant was located below decks (consuming storage tank volume). In 1998, the Seillean went to Brazil where she worked successfully in deep water;
3. Another key North Sea milestone was the successful use in 1993 of an FPSO by Kerr McGee for full field development of the Gryphon field. This FPSO was based on a fast-track topsides addition to a purpose designed but speculatively built hull. The field was still producing in 2021.

A.16 In the 1980s and early 1990s, pioneering FPSOs were used in the Australian Timor Sea region, due to their ability to disconnect from the riser when a cyclone approached. A.17 Following these developments, the number of FPSOs selected for field developments in the UK and Norway increased considerably during the mid-/late 1990s. This adoption of the technology in the North Sea seemed to coincide with a general acceptance by the oil majors that the FPSO was a suitable platform type for major projects. By the early 2000s, more than 90 FPSOs were in service and more than 20 FPSOs were under construction. These numbers have increased dramatically in the decades following, and the FPSO is now accepted as a standard platform type.

Caption: Tanker based North Sea FPSO Bleo Holm from the late 1990s

F

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Technological barriers and breakthroughs for acceptance of FPSOs

A.18 Until the late 1990s, the FPSO concept often met with resistance from engineers and firms who preferred to use fixed platform technology. This resistance was strongest in hydrocarbon basins where the weather was harsh, the water depth not too great and where the regulatory regime was ‘sophisticated’; areas such as the North Sea (UK and Norway). A.19 The primary concerns were the reliability/feasibility of station-keeping (i.e. mooring) and fluid transfer, especially in harsh environments. A related concern at the time was that the motions would be too much for efficient separation of oil and gas in the topsides process plant (in the end this was not a major problem). A.20 The move away from the early single point mooring systems towards turret moorings was important. While both permitted weathervaning, the former were (rightly) perceived to be susceptible to single point failures (e.g. Garoupa, Fulmar). In contrast, the ‘earth fixed’ part of the turret mooring is connected to multiple mooring legs, offering some redundancy. The development of high-pressure swivels associated with these turret moorings permitted the well fluids to be brought onboard a weathervaning monohull. A.21 Before the advent of flexible risers, fluid transfer from the seabed to the surface was another concern for FPSOs. While semi-submersible FPUs could handle rigid production risers, the greater motions of a monohull meant that this was a much greater challenge for an FPSO, especially in rough weather locations. A.22 Therefore, a key enabler of the FPSO concept was the emergence in the early 1980s of flexible riser technology which allowed floating vessels to be safely connected to subsea wells despite wave induced motions and excursions on the mooring systems. These riser pipes are composite structures of steel and synthetic materials which can safely contain hydrocarbons under high pressure. A.23 Brazil was where much of the pioneering work with subsea production systems and flexible risers took place. In 1979, the first flexible production risers were deployed on the Penrod 72 semi-submersible FPU at Enchova Leste. In the North Sea, the first use of flexible risers was for water injection duty on the 1983 tieback of the Duncan field to the Transworld 58 semi-submersible FPU on the Argyll field (the production risers were rigid). This was followed in 1986 by a full suite of flexible production risers on the Balmoral semi-submersible FPU. A.24 Brazil has continued to pioneer various aspects of floating production and subsea systems (e.g. first use of a steel catenary riser on the P18 semi-submersible in 1998).

Part (ii) – Different types of mobile production units

A Introduction

A.25 Mobile production units (MOPU) are moveable platforms designed for the handling of streams from hydrocarbon production wells and the onboard separation of the well fluids into oil, water and gas. In addition, they may be required to inject water for reservoir support or compress gas for ‘lifting’ the production from the well. A.26 The output of these production units is stabilised oil and gas (although some now export liquefied refrigerated gas). The produced oil is exported by visiting tanker

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or pipeline. Excess gas must be disposed of by pipeline export, reinjection or flaring (nowadays less and less acceptable for environmental reasons). A.27 For these production and export duties mobile and floating units compete with fixed platforms supported by steel jackets or concrete gravity base platforms. Such fixed production platforms dominated the early years of the offshore oil and gas industry and were usually owned by the oil companies. Floating designs have assumed greater importance as the oil and gas industry has moved into ever deeper water over recent decades. A.28 The mobile and potentially reusable nature of floating production units has encouraged ownership by firms other than oil companies. Thus, the fleet of mobile production units is divided into those directly owned by the oil companies and those chartered in from production contractors. A.29 Regardless of ownership, the hull types employed as floating production units are varied. In the early phases of development they tended to be based on tankers from the conventional shipping industry or semi-submersibles and jackups converted from drilling duty. A.30 Nowadays, mobile production systems may be in the form of monohull floating production storage and offloading vessels (FPSO), semi-submersible floating production units (FPU), tension leg platforms (TLP), spars or bottom fixed jackup units. A.31 Hulls for TLPs and spars are always newbuild projects and are almost all owned by oil companies. Hulls for FPSOs, semi-submersible FPUs or jackup MOPUs may be newbuild or conversion projects, and more of these tend to be leased rather than owned by the oil company. The hydrocarbon processing topsides are always newly built for the project at hand.

B Characteristics of different hull types

(i) Jackups and bottom fixed platforms

A.32 A jackup rig is a self-elevating bottom-fixed platform with three or four tall legs. During operation, the legs rest on the seabed and the hull with mission equipment is jacked up on the legs until it is well above the sea surface and the reach of the waves. When the legs are not deployed downwards, jackups float on a hull which is normally triangular in shape (three-legged jackups) or rectangular (four-legged designs). A.33 These hulls allow jackups to be towed from location to location or transported on heavy lift ships. However, careful weather routing is normally required for long ocean transits. Because of their great height, jackup legs can suffer rapid and catastrophic fatigue damage if the rig experiences extreme motions when transported with the legs elevated upwards. A.34 Jackups developed as the most popular type of mobile drilling unit because, being bottom supported, they provided a very stable working platform. Some have been adapted for use as production or accommodation platforms. In production service, the stability of the jackup platform allows surface wellheads to be used, rather than the more expensive and difficult to access subsea wells associated with FPSOs or semi-submersible production units. Such jackup units are normally operated in conjunction with an export pipeline, or a nearby floating storage tanker or subsea oil tank. A.35

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The first oil produced in the North Sea was from the converted jackup MODU Gulf Tide at the Ekofisk Field in June 1971. Oil was exported to tankers via CALM buoys. This continued until the Gulf Tide was replaced by fixed platforms. A.36 The leg elevating system is usually a powerful hydraulically or electrically driven pinion gear and rack system (the rack mounted on the leg). Alternative designs use hydraulic cylinders and pins which extend and retract to ‘climb’ up and down the legs. The integrity of the jacking and locking equipment and the associated control systems is clearly critical for the safety of the unit. A.37 The interface between the rig legs and the seabed is also very important for the safety of the operation and requires consideration of soil mechanics which vary from site to site. To provide stability on soft or uneven seabed soils, each leg bottom is usually fitted with cylindrical steel shoes known as spudcans. If the soil is very soft, it may be necessary to drive the legs many metres into the soil before sufficient leg stability is achieved. A.38 To spread the load of the legs in soft soils, some older designs used a single large horizontal structure connecting the feet of all the legs, known as a ‘mat’. Some production jackups have been installed in conjunction with a separately constructed steel or concrete tank, which provides a large and stable foundation to which the legs may be secured and effectively increases the water depth for which the rig’s legs are suitable. These seabed tanks also serve the purpose of storing produced oil prior to offtake by tanker. A.39 Leg length is clearly a critical limiting factor for any jackup design. Some special designs are capable of operations in 150m water depth, but 100m remains a more

Caption: Production jackup (MOPU) with three tubular legs (Credit: Shutterstock id 1202128009)

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common depth limit. The legs support the hull and the heavy mission systems (drilling or production equipment) and so their design has to take careful account of the stresses encountered during installation/preloading operations and in harsh weather, as well as the fatigue damage imposed by the constantly occurring moderate wind and waves. A.40 Most modern jackups use legs of an open space-frame or truss type design, made of tubular steel sections. These sections utilise high strength grades of steel, making the legs strong but lightweight. The quality of the welding at the many connections within these legs is important. Some jackups have legs made of large diameter circular steel tubes, which are cheaper to fabricate, but heavier and less suited for use in deep water. A.41 Modern jackups are designed by a few specialist companies which license their technology for use by owners or shipyards. Some of these companies also provide critical components such as jacking equipment.

(ii) Semi-submersibles

A.42 For many decades, the offshore industry has used the semi-submersible hull form, with its deeply submerged lower hulls (pontoons) and relatively slender columns or legs, to provide a stable drilling platform in water too deep for jackups, especially in exposed locations. This hull concept is relatively transparent to wave action, permitting operations to continue in conditions where conventional monohull designs would experience extreme motions. The semi-submersible form has also been used to provide stable and comfortable offshore accommodation units, floating production units (FPU), and offshore construction and crane vessels. A.43 In some of the later developed oil and gas basins the offshore production units were semi-submersibles, such as at the Argyll Field in the UK (first oil in 1975) and offshore Brazil. This was possible because the low motion characteristics of the type permitted the use of rigid risers (adapted from drilling duty) before flexible risers were developed. A.44 Several early semi-submersible production units converted from drilling rigs were leased by the oil companies from their contractor owners. However, most modern semi-submersible production platforms are purpose designed and built and owned by the oil companies. A.45 Most semi-submersibles are built to the rules of a classification society and the IMO MODU Code (the equivalent of SOLAS). Tragic accidents involving semi-submersible units (for example, the accommodation unit Alexander Kielland in 1980 and the drill rig Ocean Ranger in 1982) caused significant loss of life and led to the development of special rules for the stability, structural integrity and ballasting systems of these vessels. A.46 In addition, such units are generally considered to be offshore installations by coastal states and so are subject to special legislation governing the hydrocarbon activity, which is usually more onerous than standard maritime regulations. Application of such coastal state requirements can cause problems in project execution if they are not clearly defined and diligently followed up. A.47 In production duty the benefits of the semi-submersible are a reasonably large deck area and the ability, if required, to permit workover of the subsea wells via an onboard rig because of the low motion characteristics. A.48 All semi-submersible production units make use of multi-leg spread moorings. Unlike a monohull, a semi-submersible has no need to weathervane to face extreme

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weather, meaning that semi-submersible FPUs may avoid the complexity and cost of a turret or swivel to transfer production fluids from the subsea wells. A.49 Compared to a monohull of similar steel weight, a semi-submersible is more complex and expensive to build. Other disadvantages of the semi-submersible concept are its poor transit performance (not a major issue for typically stationary production duty) and its low ratio of payload capacity to self-weight (lightship weight). The latter means that relatively small errors in the lightship weight can mean a great loss of payload capacity or variable deckload. A.50 In production duty this feature means that onboard oil storage is not feasible in practical quantities and so an oil export pipeline is often required. There are few examples of semi-submersible production units with oil storage, but one was the P36 which sank off Brazil in 2001 following an accident associated with a small oil storage system. A.51 Many problems and disputes have arisen in connection with semi-submersible projects because the weight of the hull or the topsides equipment has proved to be heavier than was expected at the time of contracting. This often means that the hull has to be modified by adding sponsons to the lower pontoons and/or blisters to the columns so that adequate carrying capacity for variable load such as fuel, drilling pipe and process liquids may be guaranteed. A.52 In the early days of the offshore industry, there existed a wide variety of semi-submersible designs, but now most are built under license from a few specialised design consultancies. The preferred design is usually selected by the vessel owner and used

Caption: Semi-submersible FPU showing connected flexible risers (Credit: Shutterstock id 3331022)

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during the tender process, but the responsibility for the design is usually taken over by the builder at the time of contact.

(iii) Spar

A.53 The spar hull is a long, slender vertical hull, usually of circular cross section. This hull shape offers excellent heave, pitch and roll motion characteristics. The vertical motions are so small that some applications have used rigid risers with surface Christmas trees. A.54 Surface Christmas trees are particularly advantageous in oil fields where the wells may require frequent access for workover. With subsea wells in deep water, workover would require a hired-in semi-submersible or drillship, which is very expensive. A.55 The very deep draught means the topsides must be installed in deep water offshore after upending the hull (the complete platform construction cannot be completed at one site). A.56 The concept is not tolerant of weight growth in design or in service (due to its small waterplane area). The limited deck area forces a vertical arrangement of the topsides which may mean that accommodation etc. is located over or near to wells and production (which can be a safety concern). A.57 This low tolerance for weight changes means that no useful oil storage is normally possible – so a pipeline or FSO is required to export produced oil.

(iv) Tension leg platforms (TLPs)

A.58 The tension leg platform is a buoyant hull, looking somewhat like a semi-submersible, tethered to the seabed by vertical tendons. Usually, the hull has horizontal pontoons

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and several vertical columns. As with a semi-submersible, the topsides are mounted above the columns. Most TLPs offer a fairly large deck area, rectangular or square in plan view.

Caption: Slender hulled spar production platform (majority of the hull is underwater) (Credit: Shutterstock id 1044959344)

Caption: Hull of a four-legged tension leg platform on a heavy transport vessel (Credit: Shutterstock id 156143378) A.59 The buoyancy of the surface hull form is greater than its weight, which means that the tendons are under tension. Unlike a free-floating hull, with a tethered hull the vertical forces caused by passing waves do not cause the platform to heave or pitch. A.60 Like the spar, the primary advantage of the TLP is the very small vertical motion obtained as a result of the tensioned tethers. This permits the use of surface mounted Christmas trees. A.61 Although the concept was developed specifically for deep water, the first application of the technology was by Conoco at the Hutton field in the North Sea in 1984. A.62 As with spars, the TLP is not tolerant of weight growth in design (the tethers need to be kept in tension) or in service and this means that no useful oil storage is normally possible – so a pipeline or FSO is required to export produced oil. A.63 While no turret bearing or swivel is required, the mooring is expensive (due to the tethers which are fairly sophisticated engineered products). In addition, the concept is perceived as being expensive high technology.

(v)

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Floating production, storage and offloading vessels (FPSOs)

A.64 FPSOs are the most common type of mobile production unit. When originally pioneered in the 1970s they were based on conversions of trading oil tankers. This is still popular, although newbuild hulls have also become common. The tanker hull offers a very big carrying capacity in proportion to its own weight and this permits large oil storage volumes as well as supporting heavy topsides. Most tanker conversions make use of 2 million barrel capacity VLCC hulls, although some projects in certain parts of the world have utilised smaller vessels of Aframax size (about 700,000 barrels) or even less. A.65 The design is generally tolerant of weight alterations during design or service and the large deck area permits arrangement to suit conflicting safety and process demands. The motions do not permit the use of surface Christmas trees and so FPSOs are all associated with subsea wells or nearby wellhead platforms. Motions again mean that the use of an onboard rig for performing workover operations on subsea wells is generally not a practical option. A.66 The marine aspects of tanker conversions are generally centred around life extension and enhancement of the hull structure and coatings to achieve a long life offshore without docking, increasing the accommodation capacity, together with the modifications required to interface with the topsides processing equipment and the mooring system. A.67 In sea areas with relatively modest wave conditions and/or a predominant direction for the environmental forces (such as West Africa), FPSOs may be moored by means of spread moorings. In such cases, the subsea risers may simply be hung off the side of the vessel. In such cases there is relatively little complexity and cost associated with the shipyard scope for the mooring and riser systems. A.68 In harsher environments such as the North Sea, vessel motions and mooring loads may be reduced by allowing the FPSO to weathervane into the weather. This requires a turret bearing system and a high-pressure swivel system which transfers fluids from the earth-fixed risers below the FPSO to the process systems onboard which are fixed to the FPSO and so rotate around the mooring. These turret and swivel systems can become large and complex, with some weighing more than 10,000 tonnes and costing considerably more than the FPSO hull. There are few qualified suppliers of such special systems. Fabrication and integration of the turret mooring system is therefore a major element of such projects, and the project contracting strategy must account for this. A.69 In some parts of the world, disconnectable turret moorings are employed, in order to allow the FPSO to avoid rare but extreme events such as hurricanes, typhoons or icebergs. These FPSOs maintain a self-propulsion capability and the ability to navigate as a conventional ship. For most other FPSOs there is no propulsion equipment, or it is used only on the delivery voyage to the field.

(vi) FPSO buoy shaped (Sevan type)

A.70 This is an FPSO, simply of a different shape to conventional ships or barges. The hull is circular in plan view, meaning that the area presented to the wind and waves is the same in any direction. This means that a weathervaning mooring is not required (such FPSOs are always spread moored), which means that the expensive

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turret swivel and bearing can be dispensed with. However, this saving is offset to some extent by high mooring line loads due to the large dimensions presented to the environment (a Sevan unit of 300,000 barrels storage capacity will have a diameter of 60 metres, compared to the 44 metre beam of a conventional monohull able to store 1 million barrels).

Caption: Internal Turret Mooring at bow of FPSO (Credit: J R MacGregor) A.71 As with other FPSOs, the design is reasonably tolerant of weight growth in design and operation and the concept has a shallow lightship draught so that topsides can be completed at an inshore build site. Hull storage means there is no need for an oil export pipeline, but the hull diameter becomes very large for significant oil storage quantities (e.g. 90m hull diameter for 1 million barrels storage). A.72 Due to less hull bending the structure should be less sensitive to fatigue issues than conventional long ship-type structures. The motion characteristics are worse than a semi-submersible but comparable or better than many conventional monohulls. A.73 Some disadvantages arise from the circular deck area. This does not readily permit the simple lateral separation of safe and hazardous areas which is common on conventionally arranged monohull FPSOs. Several Sevan type FPSO projects have ended up with very tall process modules due to insufficient deck space.

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Caption: Circular hulled FPSO on a heavy lift transport vessel (Credit: Shutterstock id 623728346)

C Liquefied gas platforms

(i) LNG regasification units (FSRUs)2

A.74 FSRUs are not, strictly speaking, production units, as they are not connected to hydrocarbon reservoirs and simply receive product (LNG) from visiting tankers and export it in the form of gas. However, they are typically owned by shipping companies or offshore contractors and chartered into energy projects which differ significantly from the standard cargo transportation business the basis LNG ships were originally developed for. They are discussed briefly in this Appendix for that reason. A.75 LNG carriers have been converted or built from new to serve as LNG importation terminals, capable of regasifying methane cargo prior to sending onshore into a client onshore gas pipeline network. The ship receives LNG from visiting LNG carriers and serves as a floating storage and regasification unit (FSRU). The regasification equipment is modest in terms of size and complexity, effectively heating the cold LNG with warm seawater so that it vaporises. A.76 While the donor LNG carrier will be derived from a well-established design, many other FSRU design aspects will be bespoke for the intended place of operation and the client’s requirements. The FSRU will also be part of a much larger project, which introduces design interfaces and areas where the non-performance of one aspect of the project may affect another. A.77 Unlike a standard LNG carrier, the FSRU must have a permanent mooring system to maintain its own position. This may be a fixed jetty or a weathervaning type turret mooring system, through which is connected the gas export pipeline. While many

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FSRUs are moored in sheltered harbour areas, some FSRUs are now moored in relatively exposed offshore locations which pose a significant challenge. Unlike standard LNG carriers which normally transit with tanks full or empty, the cargo containment system for an exposed location FSRU must be adequate for the sloshing loads experienced with part filled tanks in rough weather conditions.

Caption: Inshore moored FSRU in Lithuania (cryogenic loading hoses hanging amidships, berthing fenders alongside) (Credit: Shutterstock id 2075528728) A.78 In addition, the FSRU must be designed to accept the berthing and mooring alongside of visiting LNG tankers, which may be of different sizes. Cryogenic hoses or motion tolerant rigid loading arms are required for safely transferring LNG between the visiting tanker and the FSRU. A.79 While some LNG trials may be carried out before delivery, regasification acceptance testing can be performed successfully only at the place of operation. The FSRU will usually be dependent on the installation by others of the gas export pipeline, and the arrival of a test cargo from the client.

(ii) Floating LPG offtake

A.80 Floating units capable of storing liquefied petroleum gases (LPG) such as butane and propane and offloading the product to visiting LPG tankers are an important stepping stone towards the modern FLNG. They embody certain key features such as refrigeration offshore, side-by-side berthing and offtake operations, and cryogenic cargo transfer at sea. A.81

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One notable example is the Ardjuna LPG FSO (floating storage and offloading) which commenced operations in 1976 in the Java Sea offshore Indonesia. This was a concrete barge with 60,000m3 gas storage vessels mounted on deck. The unit was moored with a weathervaning mooring and swivel which accommodated an 8 inch input riser for warm LPG. A.82 Refrigeration onboard cooled the product to −48oC and it was exported to visiting LPG tankers (moored alongside) by articulated rigid loading arms.

(iii) Floating LPG production

A.83 The first floating LPG production vessel was the Sanha LPG, which has been in production since 2005 offshore Angola. A.84 This unit has cryogenic LPG storage of 135,000m3 in the steel hull. The hull and storage technologies employed were those of standard LPG trading tankers. The production capacity is 5,940m3/day of butane and propane.

(iv) Floating LNG production vessels

A.85 Unlike FSRUs which are designed to receive already processed liquid LNG, floating LNG production vessels (FLNG or LNG FPSO) are designed to receive gas (sometimes combined with other well fluids) and export LNG. The core of all FLNG units (and onshore LNG trains) is therefore a liquefaction plant capable of lowering the

Table A1 FLNG units in operation as of 2021

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