Unlock marginal and stranded reserves in shallow waters that are far away from existing infrastructure. The solution is a system that employs a jack-up based mobile offshore production unit (MOPU) in combination with a modular subsea storage system. The storage system is an unmanned solution that is designed with an integrated offloading system. Integrated into a single, integrated system, this robust solution encompasses all necessary components thus reducing both CAPEX and OPEX. The case is based on standard MOPU designs with compact process modules to reduce weight and cost. Additional cost savings come from standardization and placing fully integrated components subsea. An integrated process train ensures the right quality of oil or condensate is sent to the subsea storage tanks, ready for tanker pick-up. This paper also describes how the associated gas will be handled. The field-proven offloading system is linked to storage, ensuring correct metering and safe mooring for any vessel. Combining modular subsea solutions with field-proven components gives operators access to technologies that provide an increased return on invested capital. The storage system is developed based on existing storage solutions. It is an energy-efficient system with a low environmental footprint. Recent engineering studies and testing have proven the feasibility of operating a subsea storage unit with a flexible membrane defining the horizontal interface between oil and seawater. This paper presents new results from a downscaled subsea storage system model testing conducted by an original equipment manufacturer (OEM) together with a major operator. The innovative cluster design will enable re-deployment of the storage units, which opens new combination possibilities with MOPU's. Interfaces between the various system components have been streamlined to create an integrated system and when deploying these different building blocks in that way, a custom field solution can be provided for marginal field developments – including an option to modify and re-deploy. Research has shown that replacing the floating storage and offloading vessel (FSU/FSO) with subsea storage reduces offshore manning and the environmental footprint. This technical paper explains the modularity and the economics of an installation-friendly design. Lower complexity, in combination with cost-effective installation, introduces new opportunities for field developments. The integrated solution is also designed with the option to operate below wax appearance temperature and can make even smaller field developments profitable at a lower cost, in an energy-effective manner, and with a low environmental footprint. With this new solution available, the market can take a whole new view on small pool developments.

This paper is part of the special OTC session "Floating Memories-Look Back to Leap Forward" intended as a historic retrospective of the evolution of the four major types of floating production platforms: Floating Production Storage and Offloading (FPSO), Semisubmersible (FPS), Tension Leg Platform (TLP) and Spar, from their inception to the present day. The session includes a look ahead to the future of these floating platforms and what it will take to sustain their commercial viability as they adapt to headwinds from continuous volatility of oil and gas prices and competition from onshore tight oil projects. This paper's focus is the Semisubmersible Floating Production System (FPS). It chronicles the forty five year progression of FPS technology from its humble beginnings in 1975 as a converted Mobile Offshore Drilling Unit (MODU) deployed on the Argyll field in the North Sea in 80 m of water, to Appomattox, the most recent FPS, that began production in 2019 in 2250 m of water in the Gulf of Mexico (GoM) . It also touches briefly on the evolution of the FPS hull, mooring and riser systems and addresses future trends and prospects. From Argyll to Appomattox

Offshore oil production with the employment of FPSOs (Floating, Production, Storage and Offloading) unit faces the challenge of increasing well volumes, processing and storage capacity and ultimately oil offloading and transportation. Following the natural activity development in some oil fields, the number of spread-moored FPSOs and the employment of Dynamic Positioning Shuttle Tankers increased, however represent altogether a bottleneck for the production capacity and considerable transportation cost increment. The need to implement alternatives for the use of larger and conventional tankers is evident, and several attempts and use of technology are being tested and proposed. The work presents preliminary numerical and cost analysis of an innovative Oil Loading Terminal (OLT) for deep water. Based on field data, metocean studies and extensive practical experience, the OLT should allow direct offloading from the FPSOs onto conventional shuttle tankers including VLCCs. The OLT concept allows the transfer of oil from an FPSO to a conventional tanker moored in CALM Buoy through submerged oil offloading lines (OOLs) supported by a tethered submerged buoy. The conventional tanker will receive the oil through a floating hose string. The cornerstone of this OLT concept is the subsurface buoy application to support the OLLs and consequently de-coupling the FPSO and CALM Buoy motions simultaneously. As a result, the OOLs loads and fatigue efforts under the CALM Buoy also decrease. The paper evaluates an OLT specific conception for the Brazilian offshore pre-salt area and results related to the numerical analysis carried out are presented considering one submerged buoy connected to a FPSO and CALM Buoy via flexible offloading lines respectively. The results appoint to a technically feasible solution that can be complementarily laboratory and field tested. Further, the solution cost impact has been assessed and initial figures demonstrate that the final testing, construction and installation of one system will need investment that cost a fraction of tanker lifting costs currently requiring Ship-to-Ship oil transfers. The economies assessed with the use of this innovative solution include total avoidance of Ship-to-Ship costs; cuts transportation cost per ton in up to 50% (fifty percent), eliminates offloading bottlenecks allowing better use of FPSO storage and plant processing capacity, and ultimately decreases the number of tanker offloading operations with considerable benefit to operational safety by reducing risk exposure.

During the 1970s, the Oil and Gas (O&G) offshore industry undertook the first few projects that exploited oil fields by using a tanker-ship as a hull to host its process plant and store the produced oil. Both the Shell project in the Castellon field in Spain and the Petrobras project in the Garoupa field in Brazil are considered pioneers of the Floating Production Storage and Offloading (FPSO) concept. The FPSO concept has many inherent advantages when compared to other types of floating facilities. However, the concept did not immediately become a preferable option for operators around the world. Throughout the 1980s, the industry did not experience a significant increase of FPSO-type projects. During this time, there was a clear preference for non-FPSO floating production units, despite the need for additional storage and a continuous export system. Additionally, port administrations treated all ship-shaped production units, including FPSOs, as tanker-ships. As such, they had to be compliant with International Maritime Organization (IMO) tanker requirements. This classification made it difficult to use FPSOs as permanent solutions to exploit offshore oil and gas fields. The IMO tanker requirements mandated that FPSOs could not stay on location longer than 3 years, although a 1-2 year extension could be granted, depending on inspections and other operational requirements. These requirements were enforced even if the operators and FPSO contractors designed the FPSO for a longer life. This paper describes the first steps, both regulatory and standardization of technical design requirements, in the approval process related to FPSO use for oil and gas fields. The paper describes how the United States (US) Environmental Impact Statement (EIS), and other initiatives between 1999 and 2001, paved the way for the US acceptance of FPSOs. Finally, the paper explains why the first FPSO in the US Gulf of Mexico (GoM) had a moored, single point, internal turret with a planned disconnection system as opposed to other design options that were evaluated and rejected.

Abstract Sevan Marine has successfully pioneered the cylindrical floater concept to the market with 3 FPSOs and 2 MODUs in operation and an additional 4 FPSOs and 2 MODUs in construction. The paper will present these units and the operational experience in harsh environments in the UK Central North Sea. Through studies supported by major oil companies, a concept for safe permanent mooring of a floater through the typical design tropical cyclone in areas like NW Shelf Australia, South China Sea or Gulf of Mexico is demonstrated to be feasible. The paper will present the analysis, model tests and full scale motion recordings, supporting this conclusion. Finally some new methods for offloading to export tankers will be presented, also including systems relevant for LNG offloading to standard LNG tankers from an FLNG unit. Introduction Operation of FPSOs in areas exposed to tropical cyclones is today largely based on disconnect-able ship-shaped units. The disconnect requirement has several disadvantages such as production downtime, complexity of disconnect system, requirement for the unit to operate as a navigable ship. Yearly production downtime will be based on number of disconnects and duration of production downtime due to disconnect. The additional downtime will vary from one area to another, but an additional downtime of 5–10% can be seen in many cases. Added complexity for the mooring and riser system in order to allow for safe disconnects and re-connects of mooring lines and riser bundle will add in the order of magnitude 30–50% to the turret mooring system. For operating the FPSO as a navigable ship, a marine crew as well as propulsion and navigation systems have to be in place, adding significantly to both FPSO construction cost as well as cost of daily operation. Based on the operational experience with the world's 3 first cylindrical FPSOs as well as extensive analysis and model tests carried out, it has been possible to demonstrate that a cylindrical FPSO can be designed for safe permanent mooring in areas exposed to tropical cyclones.

Abstract This paper will present a Discrete Event Simulation (DES) based solution for an optimum shuttle tanker fleet to serve the present and future FPSO based Gulf of Mexico (GoM) production. The simulation takes into account average ‘field lifecycle’ based production rates of specific developments and the sensitivity of ‘offloading availability’ to variables such as shuttle tanker size, loading rate, distance to market etc. A probabilistic representation of downtime associated with wave, wind, currents, maintenance etc. at the FPSOs and random weather and non-weather delays at the receiving terminals have also been considered in this effort. Despite the impressive pipeline infrastructure available in the GoM, none of it currently reaches some of the newer fields being discovered in over 5000ft water depths in the lower tertiary trends. The high cost of pipeline extensions in ultra-deep water (UDW) and uncertainty in the producibility of reservoirs has multiple operators considering an FPSO - Shuttle Tanker (ST) based solution for production export. This paper would help operators considering this option to understand the limitations and potential options in using shuttle tankers in serving the field(s). The assessment of offloading availability for shuttle tankers to serve multiple fields would be made on the basis of production rate, loading rate and tanker size using a Discrete Event Simulation (DES) model subject to threshold and offloading operational downtime. The development of the Cascade-Chinook field at the US GoM has established its viability using dedicated shuttle tankers. However, potential of synergy in using a common fleet of shuttle tankers exists subject to further FPSO based developments in the near future. This paper explores the technical and logistical feasibility of such a possibility.

Abstract This paper is based on the work performed during the design, implementation and operation of the Cascade and Chinook fields, located offshore the United States Gulf of Mexico (USGoM) - the first deployment of an FPSO in the region. It presents an overview of the reservoir rock and fluid properties, the design and construction of wells, the design and installation of the subsea system and FPSO BW Pioneer, the oil export system through shuttle tankers, the gas export through pipelines and the regulatory framework of the project. It also presents operational information about the first wells on stream in each field. The information provided in this paper is a useful reference for petroleum field operators when designing development concepts for ultra-deep water discoveries, not only in the USGoM but also worldwide. It is especially useful for the design of field development and early production systems located far from pipeline infrastructure. It is useful for contractors to identify the technologies which are most suited for application on deep wells and ultra-deep water subsea systems and production platforms. The initial phase of development, already implemented, consists of two subsea wells in Cascade and one in Chinook tied back, through a field-specific subsea system, to a Floating, Production, Storage and Offloading (FPSO) platform. Oil is transported from the FPSO in shuttle vessels to terminals of opportunity along the USGoM and gas is exported through pipeline. Wells started-up production in 2012. Future phases of development will depend on the performance of the wells.

Abstract This paper is based on the work performed during the offloading operations in the Cascade and Chinook fields in Ultra Deep Waters of the U.S. Gulf of Mexico. It addresses the tandem offloading from the first FPSO to operate in the Ultra Deep Waters of the U.S. Gulf of Mexico to the first use of purpose-built Jones Act shuttle tankers to perform such operations in the U.S. waters. The paper also covers the experience of the shuttle tankers crew on offloading operations as well as the proved performance of the vessels equipment. The main technical contributions of the work presented in the paper are associated with the unique features of the first use of purpose-built Jones Act shuttle tankers in the Gulf of Mexico, such as: Bow Loading System (BLS); Green Line System; and Differential Absolute and Relative Positioning Sensor (DARPS). The successful use of tandem offloadings from the FPSO to shuttle tankers at Cascade and Chinook fields confirms the adequacy of such solution in the U.S. Gulf of Mexico, and opens the possibility for growth in the Jones Act shuttle tanker fleet. Introduction Produced oil from the Cascade and Chinook (C&C) fields is being successfully and safely exported from the Floating Production Storage and Offloading vessel BW Pioneer (FPSO) to shore via Shuttle Tankers (ST). Petrobras pioneered the tandem offloading concept between FPSO and ST in Ultra Deep waters of the U.S. Gulf of Mexico (USGoM). Petrobras executed the first C&C offloading operation on June 8th, 2012, which was the first tandem offloading operation conducted in the USGoM where produced oil was transferred from a FPSO to a ST via tandem offloading system specifically designed for use over the entire duration of the FPSO operation at C&C fields. This paper describes key aspects associated with the use of STs for oil export in the USGoM, including information on the main characteristics of the STs and offloading operation. The content of this paper includes technical contributions associated with the unique features of the STs, as well as its impact on future USGoM Ultra Deep water field development.

Abstract This paper summarises original development work implemented by Ocean Resourceinto a new type of Unmanned Production Buoy facility, the Sea Producer. Thiswork, which is both comprehensive and wide-ranging, covers the use ofautonomous buoy technology to develop various offshore oil and gas productionscenarios which would otherwise be uneconomic or indeed impossible. Recentlythis technology has received considerable interest as it represents, for somesmaller developments, possibly the only sensible and economic way forward. Thedesign concept is flexible and has applications well beyond simple production. Ocean is carrying out on-going development work into the use of the concept forcarbon sequestration allied to enhanced oil recovery. This novel developmentwill provide an initiating technology for offshore carbon sequestration againat hitherto highly economic costs. The detail of this is, however, beyond thescope of this paper. Ocean Resource has developed and pioneered the concept of remote offshore oilor gas production from an unmanned production buoy over a period of 20 yearsand is the only company with specific experience and expertise in this complexarea. Ocean has designed, built, operated and maintained its own high stabilitybuoy systems and has completed a number of buoy designs for working buoysystems in use with Apache, Mossgas Pty, Exxon-Mobil and others for oil relatedoperations. More recently Ocean Resource has been responsible for the design ofa 5MW Power Buoy for CNR International UK Ltd (Canadian Natural Resources). Unfortunately Monitor Oil PLC, the principle constructor, went into liquidationprior to completion of the project but it is envisaged that this unit, which is95% complete will shortly be redeployed on another field. The Power Buoylocated at Dundee is subject to an option agreement for this purpose. Ocean Resource's low cost autonomous buoy systems represent a game-changingtechnology that will enable the economic development of hitherto unexploitableor stranded oil and gas reserves. The technology is generally branded as SeaCommander where it relates to field control buoys (a developed product) and SeaProducer where it relates to production. Sea Producer enables a step-change in offshore development expenditure loweringcapital costs at the start of project together with greatly reduced operationalcosts leading to low " through-life" costs for standalone, step-out developmentsor early production scenarios. Furthermore the relatively minimal nature of theoffshore facilities comprising the buoy and storage system leads to rapiddeployment and hence faster income and profit return to any offshoreproject. The unique autonomous buoy technology has been developed by Ocean Resource overa period of 20 years and is an evolution of existing systems first deploed inthe 1980's. It is therefore both mature and proven. It can be used for sub-seaoil and gas field control, remote pigging, multi-phase pumping, chemicalinjection, subsea production support and remote flaring.

Abstract Tandem transfer of crude oil and condensate in dynamic marine conditions has a long history with much accrued experience. Initial systems relied simply on a hawser connection, which was subsequently improved with the advent of Dynamic Positioning Systems. The new requirement to transfer LNG in true dynamic conditions between two very large floating structures, whilst respecting the stringent rules governing the safety of such operations, has led to the design, testing and qualification of a new heavy duty transfer system, known as the Amplitude-LNG Loading System (ALLS). The transfer of produced products, mainly LNG but also LPGs and condensate, has to proceed on a regular and repeatable basis, with 2 of the main criteria being: Continuous production and operation of the FLNG over a 20 to 30 year period Project monetization linked to LNG-C rotations To ensure that these criteria can live in harmony the LNG transfer system must ensure that the correct volumes of LNG can be safely and efficiently offloaded from the FLNG to the LNG-C whilst minimising the turn around time of the carrier. The ALLS incorporates a custom built Constant Position Monitoring System (CPMS) which can ultimately be integrated into the DP system of the LNG-C and / or the FLNG, and may eventually lead to on-site operations without the need for a hawser link. However full analysis of the project specific conditions will be required prior to taking such an important step. An offshore LNG project is a multi-billion dollar investment, from subsea drilling and development, through construction of the floating process & liquefaction plant (FSPO-FLNG) to operation of a fleet of LNG carriers, some of which may be dedicated on a project basis. As such the reliability and repeatability of the CPMS / DP couple is a key element in the overall functioning of the offshore LNG transfer system, as any emergency shut down and prolonged interruption in fluid transfer can have significant consequences on the functioning of the FLNG and its capacity limits for storage. This paper will investigate the history and evolution of tandem transfer in open sea conditions, elaborate on these issues from the points of view of the Client, the Operator and the transfer system supplier, and detail the importance of a fully integrated and modern LNG transfer system. Introduction When developing and proposing new methods and systems to the Oil and Gas Industry, especially when safety of personnel and equipment is paramount, co-operation between the main involved parties at an early stage gives a firm base from which to work. In marine environments involving the transfer of LNG and gas, a concerted approach between the end user, the equipment supplier and experienced marine operators will ensure that practical procedures will result whenever possible in similar methods, based on existing know-how.

Abstract One of the most challenging questions with regard to the technical part of the LNG (Liquefied Natural Gas) supply chain has not been answered satisfactorily yet: How can LNG be safely and reliably transferred between a floating terminal platform (Floating Production, Storage and Offloading - FPSO or Floating Storage and Re-gasification Units - FSRU or comparable) and a shuttle tanker in harsh environmental conditions? The problem consists of two main technical issues: The first is the vessel mooring configuration (e.g. side-by-side (SbS), tandem); the second is the type and appropriate handling of the transfer lines for the cryogenic liquid. As both problems are interacting, no convincing solution has been developed until now.. The innovative offshore LNG loading system "Maritime Pipe Loading System 20" (MPLS20) is proposed by the project partners Nexans and Brugg, leading manufacturers of vacuum insulated, flexible cryogenic transfer pipes, IMPaC, an innovative engineering company that has been involved in many projects for the international oil and gas industry for 25 years and the Technical University Berlin, Department of Land- and Sea Transportation Systems, with great expertise in numerical analyses and model tests. The new concept is based on a unique tandem mooring configuration (see Fig. 1). In comparison to standard operations used in the oil business for about 40 years, the concept introduces a mooring bay for the shuttle tanker. Extensive numerical simulations are conducted to determine the envelope of motions and mooring forces. As the Nexans/Brugg corrugated metal pipes provide a double containment system all relevant safety issues are well addressed, as required by EN1474-2/-3. Thus, LNG transfer can take place even under severe environmental conditions which makes this new concept superior to other approaches such as side-by-side configurations using composite hoses.

Abstract The LNG market is expanding, and development plans exists for LNG processing plants in Arctic Russia. This paper discusses a possible transport chain for LNG produced at shore-based terminals on the Yamal Peninsula. The recent disagreement between Russia and Ukraine on gas export to Europe has demonstrated the vulnerability of the present overland export system for natural gas. The planned North Stream will increase energy security for several European countries. However, a sea transport system may create a win - win situation for Russian gas producers and world-wide customers of natural gas. The first part of the paper describes the individual legs of the proposed transport chain. The second part discusses ship-to-ship transfer of gas in general, followed by a review of LNG ship-to-ship transfer, and ends with a specific case, of which high-seas ship-to-ship transfer in Arctic waters is a critical element. The final part of the paper describes necessary developments in cargo-handling equipment and operational procedures for LNG transfer between two large LNG vessels in Arctic waters. Ship-to-ship transfer of oil and gas is a routine operation in many parts of the world. A cost-effective transport system from Arctic LNG plants in the western part of the Russia to markets in Western Europe and east coast US/Canada could be achieved through the use of dedicated icebreaking LNG tankers transloading their cargo to conventional LNG carriers in ice-free waters in the Barents Sea. 1 Introduction With the expected increase in demand for oil and decrease in production in certain areas in 2010 - 2020, pressure to develop the Arctic region is growing. The extreme conditions with ice and very low temperatures will make even more stringent demands of the ships, equipment and crew than normal. The Arctic is particularly sensitive and vulnerable, and the vision of zero harmful discharges is now generally accepted. A sharper focus on the part of IMO, EU and Arctic organizations, on environmental issues and safe operations will influence vessel operation. There will be a focus on new and innovative costeffective solutions to satisfy the strict requirements for ships and equipment from ship-owners, class societies, operators, the authorities and other stakeholders. The development of the Snøhvit gas field with its Melkøya LNG terminal has moved offshore gas production far north. Much larger offshore and onshore fields exist in the Russian sector of the Barents Sea and on the Yamal Peninsula. The recent problems with Russian gas export to Europe may increase pressure to develop an independent sea export route from the Russian European Arctic in addition to the planned North Stream pipeline. Current plans for development of LNG plants include a plant in Teriberka, where the Shtokman gas will be landed, and a facility on the Yamal Peninsula. Ship-based export from these plants will give the Russian gas company Gazprom access to both the European and North American markets.

Abstract This paper presents the issues specific to the engineering and operation of FPSOs in the US Gulf of Mexico, and discusses the design of one FPSO currently under development and how it addresses those issues. The areas of the FPSO design which are discussed in this paper include: Regulatory and environmental requirements Vessel selection and refurbishment for design life extension Riser and station keeping/mooring design for hurricane and loop current conditions in deepwater Topsides design including associated gas disposal Oil import and export facilities Shuttle tanker requirements The design basis of this FPSO has been developed with the intent of enabling the unit to be easily redeployable in different locations, either as an Early Production System (EPS) for large fields, or a Full Field Development on marginal or medium size fields (30- 80,000 bopd). Different technologies are compared and their design and operational limitations identified, for riser design (flexible risers, hybrid riser towers, top tensioned risers, single well riser towers, permanent and disconnectable) and station keeping design, (permanent or disconnectable, dynamic positioning or anchor leg moorings, polyester or wire rope mooring systems). Those aspects of the design which require technology new to the Gulf of Mexico, will be highlighted and comparable applications of the technology elsewhere in the world, if applicable, identified. There has been an increased interest recently in the application of FPSOs for the development of deepwater fields in the Gulf of Mexico. Damage to offshore facilities and the pipeline infrastructure during recent hurricane seasons, has made the benefits of the FPSO concept more apparent, with its large onboard oil storage capacity and capability to offload via shuttle tankers or pipelines, and its ability to disconnect from risers/moorings and avoid the hurricane conditions design case. Understanding the issues relative to the use of FPSOs in the Gulf of Mexico and developing a design, which utilizes the proven technology of FPSOs elsewhere in the world, is key to applying this concept successfully in this region. Introduction So far there have been no FPSOs installed in the US portion of the Gulf of Mexico (GoM) even though the concept has been increasingly selected for field developments elsewhere in the world. What are the key issues when reviewing the suitability of an FPSO for this region, and what has changed recently to affect the selection process? The damage caused to the offshore units and pipelines system by hurricanes Ivan, Katrina, and Rita, plus the continuing exploration success in the ultra deepwater beyond the continental shelf, are two of the main drivers towards the current interest in FPSOs in the Gulf of Mexico. The ability of the FPSO to be designed to disconnect and sail away prior to the arrival of a hurricane, and the fact it is not dependent on the pipeline network to transport oil, makes it an inherently more robust and safe design concept.

Abstract Campos Basin, the main production province in Brazil, was discovered in 1974. It is located on the North coast of the Rio de Janeiro State and comprises an area of around 115,000 km2 (28,400 acres), as shown in Figure 1. The producing oil fields are between 70 and 150 km (43 to 93 miles) far from the seashore. It started its production on August 13th, 1977 with 10,000 bopd (barrels of oil per day) from the well 1-EN-01-RJS, which produced to a semi-submersible platform; this well has produced nearly 35 million barrels of oil until February 1998, when it was shutdown for economical reasons. Today, after more than twenty-five years of continuous operation, the overall production system comprises 13 fixed platforms and 24 Floating Systems distributed among 42 oil fields, which account for the production of 1.21 million bopd - which corresponds to more than 80% of Petrobras oil production, plus 18.9 million m3 of gas per day - or 43% of the gas production (as of December 2002). Such an evolution was supported by investments in exploration and production development, in deepwater technology developments and in continuous management improvement. This paper describes the main driving forces to exploit Campos Basin - especially its deep and ultra-deepwaters fields, the technological and production developments performed, the experience accumulated by Petrobras along these 25 years of operations as well as its contribution to the global oil industry. Introduction The 1973 world oil crisis brought a tremendous economical impact on most countries, especially on those with strong dependence on imported oil, such as Brazil. This led a worldwide increase in investments on oil and gas exploration and production, including the search of new technology for producing fields located in hostile environment. The first oil discovery in Campos Basin occurred in 1974, while Brazil was facing the economical commotion created by the crisis, worsened by the country's unbalanced external payments account. Bringing the newly discovered prolific oil province on to production, as fast and at the lowest cost as possible, became a key issue for Petrobras. The increased throughput would help reducing the burden of Brazil to manage its increasing external debts. The oil imports were responsible, at that time, for a significant portion of the Brazilian payment unbalance. The country had to simultaneously reduce its oil consumption and increase its production. The reduction would come with the introduction of alcohol-fueled vehicles, and the use of other alternative energy sources, while the increase would mainly come through the Campos Basin offshore development. The problem was to produce in conditions never experienced before. The Garoupa and Enchova Fields, the first ones in the basin, located in 120 m water depth (WD), were already considered in deep waters, at the time. The available field-proven solutions using fixed platforms were technically and economically feasible, but it would take years for its implementation, and the costs were relatively high. The country also had to limit the use of foreign services and goods to a bearable minimum, to not worsen the economical scenario.

Abstract In remote deepwater fields, it is efficient to exploit reservoirs via numerous wells from a dedicated dry-tree wellhead facility. Reservoir fluids are passed to a closely located floating production, storage and offloading (FPSO) vessel, from which oil is then intermittently offloaded to a shuttle tanker via offloading lines and an anchor leg mooring buoy. While accepted as being commercially effective, the complexity of the behaviour of such integrated systems imposes constraints upon the designer unlike those seen for simpler field architectures. Specifically, the response of each component in such systems is influenced by the mechanical and hydrodynamic coupling effects and proximity of the other components. Consequently, if the feasibility of such systems is to be proven or demonstrated, coupled analysis techniques, which facilitate the accurate prediction of all responses without imposing conservatism associated with commonly used analysis techniques, must be employed by the designer. A coupled analysis capability has been developed and extensively verified, which integrates radiation/diffraction theory with a beam finite element (FE) time-dependent structural analysis technique for slender offshore structures. This paper describes the coupled analysis capability and its application to a West of Africa type offloading system. The underpinning theoretical background and the inclusion of coupled frequency dependent excitation, inertia, damping and stiffness characteristics of floating components together with similar characteristics for attached mooring and transfer lines in a non-linear time-domain finite element solution scheme, is outlined. Numerical examples are described to illustrate the operation of the technique for design of deepwater systems. Introduction As the emphasis on development shifts to increasingly remote, deepwater fields, novel field architectures have to be employed to economically exploit these reserves. The lack of available export pipeline infrastructure in remote locations necessitates the use of systems that rely on intermittently offloading oil to a shuttle tanker by means of an anchor leg mooring buoy. Such a system typically consists of a dedicated dry-tree wellhead platform, which may for example, be a tension-leg platform (TLP) or Spar, that facilitates both drilling and production for closely located wells. Reservoir fluids are transferred via transfer lines from the wellhead platform to a (FPSO) unit. Oil is then offloaded from the FPSO by means of either a catenary anchor leg mooring (CALM) or taut anchor leg mooring (TALM) offloading buoy, which is connected to the FPSO by steel or flexible offloading lines. Safety considerations necessitate that a horizontal separation of up to 2km be maintained between the FPSO and the offloading buoy/shuttle tanker. During the offloading procedure, the shuttle tanker connects to the offloading buoy using a hawser, which serves to maintain the shuttle tanker in position.

Abstract The risk of collision between shuttle tanker and FPSO during off-loading is strongly dependent on Human and Organisational Factors. The contributions to the collision frequency have been analysed in terms of Risk Influencing Factors, which are structured in an extensive risk influence diagram. Contributions from various Risk Influencing Factors is achieved by data from incidents and near misses, as well as from expert meetings. Recommendations for risk reduction are presented in relation to field configuration, minimum time to be available for recovery from drive-off scenarios, as well as crew competence, positioning systems, interface on shuttle tanker, FPSO and between the vessels. Introduction Turret moored FPSOs of the mono-hull type have been used in the North European waters since 1986 [Petrojarl I], so far without serious accidents to personnel or the environment. The use of such vessels for field development has increased during the last 5-10 years, and in these waters more than 25 fields are currently either in operation or being developed with FPSO units, mainly new built vessels. The vessels being installed in the North Sea, North Atlantic and Norwegian Sea fields have traditionally been designed for considerably higher environmental loads and often also higher throughput as compared to installations in more benign waters. Without exception, the ones so far installed or under construction for these areas have what is termed 'internal' turret, in the bow or well forward of mid ships, with transfer of pressurized production and injection streams through piping systems in the turret. Although FPSOs are becoming common, operational safety performance may still be considered somewhat unproven, especially when compared to fixed installations. Floating installations are more dependent on manual control of some of the marine systems, during normal operations as well as during critical situations. Accidents are often initiated by errors induced by human and organisational factors (HOF), technical (design) failures or a combination of these factors. Effective means to prevent or mitigate the effects of potential operational accidents are therefore important. The overall objective of the programme was presented in Ref. 1. The programme has considered the following phases: Methodology development 1996-1997: Pre project, definition phase 1997-1998: Analysis of riser damage, inadequate turret operations 1999-2000: Collision with shuttle tanker (ST) Collision Frequency Study 2000-2002: Extended study of collision risk The work up to 1998 has been summarised in an OTO report (Ref.2), published by the UK Health and Safety Executive (HSE). The details of the analysis during 1999-2002 are presented in Refs. 3, 4, 5 and 6, of which the latter is published by the HSE. This paper is a summary of the work carried out during 2000-2002.

Abstract Some observers estimate that more than 70 Floating Production, Storage and Offloading Systems (FPSOs) are in operation worldwide. Currently, there are no FPSOs in use in the United States (U.S.) sector of the Gulf of Mexico. Recent U.S. regulatory developments have improved the chances that a FPSO will be proposed for use on the U.S. Outer Continental Shelf (OCS). Recent quantitative and qualitative risk assessments commissioned by the U.S. government have concluded that offshore lightering between FPSOs and shuttle vessels has a low overall risk of accidents and oil spills that is comparable with other offshore oil production and transportation options. Current Coast Guard rules that apply to offshore lightering are published at 33 Code of Federal Regulations (CFR), Part 156, Subparts B and C (33 CFR 156.200 - 156.330). These requirements are general in nature and not focused on FPSO operations. In addition, the operational requirements in 33 CFR 156, Subpart C only apply to lightering operations conducted within specific areas in the Gulf of Mexico designated by the U.S. Coast Guard (USCG). Thus, a regulatory gap currently exists with respect to operational requirements for offshore lightering involving FPSOs and shuttle vessels not operating within these designated lightering areas. The offshore marine industry now has an opportunity to help define an appropriate scheme of operational procedures for FPSO/shuttle vessel lightering. Several guidance documents produced by the Oil Companies International Marine Forum (OCIMF) and the International Association of Independent Tanker Owners (INTERTANKO) may provide flexible guidance on offshore lightering involving FPSOs and shuttle vessels. These documents summarize the experience of FPSO operators in the North Sea and worldwide and provide guidance in developing operational procedures to minimize risk. A summary of key operational procedures is provided to assist potential operators of FPSOs and shuttle vessels. The reader is referred to the actual source documents for detailed guidance in developing appropriate procedures for FPSO/shuttle vessel operations. Introduction For several years, the U.S. Minerals Management Service (MMS) and the USCG have been considering the regulatory and environmental issues associated with the potential use of FPSOs on the U.S. OCS. On February 2, 2001, the MMS released the final Environmental Impact Statement (EIS) on the proposed use of FPSOs on the Gulf of Mexico OCS (Central and Western Planning Areas)1. The FPSO EIS is a programmatic document developed in accordance with the National Environmental Policy Act to evaluate the potential impacts from the proposed use of an FPSO in the Western and Central Planning areas. On December 13, 2001, the MMS Associate Director for Offshore Minerals Management signed the Record of Decision for the FPSO EIS2. In it's Record of Decision, the MMS approved the conceptual use of FPSOs in the Western and Central Planning Areas of the deepwater (greater than 650 feet) Gulf of Mexico, with the exception of USCG designated lightering prohibited areas. This MMS decision increases the likelihood that an offshore operator will propose the use of an FPSO to develop a deepwater oil discovery.

Abstract The United States Department of the Interior (DOI), Minerals Management Service (MMS) prepared an environmental impact statement (EIS) 1 to evaluate potential environmental effects of the proposed use of floating production, storage, and offloading (FPSO) systems in the deepwater parts (i.e., in areas >650 feet [200 meters] in depth) of the Outer Continental Shelf (OCS) in the Central and Western Planning Areas of the Gulf of Mexico. The EIS was prepared in accordance with the National Environmental Policy Act (NEPA), as amended, 42 U.S.C.§§ 4321-4370(d)(1994). The FPSO EIS is a programmatic document to examine the concept of, and fundamental issues associated with, the petroleum industry's proposed use of FPSO's on the OCS of the Gulf of Mexico. The EIS considers a generic FPSO system and operation, as well as a range of technical variations. The "base case" evaluated is a permanently moored, double-hulled, ship-shaped FPSO with up to 1 million barrels of crude oil storage capability. This NEPA/EIS process will result in one of three basic decisions by the Federal Government: conceptual approval of FPSO's, conceptual approval of FPSO's with certain restrictions or conditions, or a decision for no action (i.e., no conceptual approval by the Government at this time). In accordance with the requirements of the NEPA, the Government's decision will be detailed in a Record of Decision (ROD) and published in the Federal Register . The ROD has not yet been issued at the time of this writing. Background In 1996, OCS operators, as well as FPSO operators and builders, began having serious discussions with the MMS about the possibility of using FPSO systems in the Gulf of Mexico. FPSO's are floating production systems that store crude oil in tanks located in the hull of the system and offload the crude to shuttle tankers or ocean-going barges for transport to shore. FPSO's may be used as production facilities to develop oil fields in the deepwater areas of the Gulf of Mexico OCS that otherwise would challenge or exceed the limits of current deepwater production and transportation infrastructure and technologies. Recognizing that the use of FPSO's would represent new technology and potential impacts in the Gulf of Mexico, the MMS approached the issue on several fronts. The EIS was initiated to evaluate the potential environmental impacts. The EIS process provided for public disclosure and input. The MMS funded a comparative risk assessment to evaluate the risks associated with FPSO technology as well as those associated with three types of existing Gulf of Mexico deepwater facilities. The U.S. Coast Guard (USCG), U.S. Fish and Wildlife Service (FWS), and the National Marine Fisheries Service (NMFS) were consulted on FPSO-related issues under their respective jurisdictions. The MMS sponsored and participated in several joint Federal/industry workshops to identify the technical, safety, and environmental issues and information needs related to FPSO's, as well as to gain a better understanding of FPSO technology and scope of operations around the world.

Abstract This paper describes a study to compare the risks of Floating Production Storage and Offloading Systems (FPSO's), which have never been used in the Gulf of Mexico, with the risks for existing deepwater production systems in the Gulf of Mexico. The major conclusion is that the expected risks for fatalities and oil spills associated with FPSO's are comparable to those for already accepted alternatives for deepwater production. In addition, the oil spill risks are dominated by spills that occur during transportation of oil from the production facility to the shore with either pipelines or shuttle tankers. The major recommendation is to periodically update these results so that they serve as a baseline for future analyses of risk in the Gulf of Mexico. This study was undertaken for the Minerals Management Service to provide information for their use in developing a policy for FPSO's in the Gulf of Mexico. Introduction To date, deepwater (more than 3,000-foot water depth) reserves in the Gulf of Mexico have been developed primarily with the following types of production systems: Spars; Tension Leg Platforms (TLP's); and Subsea Well Systems tied back to these floating systems or to shallow water jackets that may also serve as hubs for other deepwater production systems (Hub/Host Jacket). All three of these types of systems rely on pipelines to transport oil to shore. A potentially attractive alternative to these systems is a tankerbased Floating Production Storage and Offloading (FPSO) system with oil transportation to shore via shuttle tankers. Floating Production Storage and Offloading systems have been used in many areas of the world, but not the Gulf of Mexico. The Minerals Management Service (MMS) funded the Offshore Technology Research Center (a National Science Foundation engineering research center located at Texas A&M University and The University of Texas at Austin), with EQE International, Inc. as a subcontractor, to conduct a Comparative Risk Analysis (CRA). The purpose of this study was to assess and compare the system risks for FPSO's with those for existing deepwater production systems, specifically TLP's, Spars and Hub/Host Jackets. This study was conducted concurrently with an Environmental Impact Statement (EIS) study for FPSO's in the Gulf of Mexico1. Information from both the Comparative Risk Analysis and the EIS will be used by the MMS in developing policies concerning the use of FPSO's in the Gulf of Mexico. The primary objectives of the Comparative Risk Analysis were the following: Assess and compare the system risks for FPSO's with those for existing deepwater production systems, specifically Spars, TLP's, and Hub/Host Jackets; and Understand the contributions to system risk by subsystems and phases of operation. Approach The approach used to conduct the Comparative Risk Analysis was developed with the following goals in mind: Provide the MMS with information that can be used for a consistent and objective comparison of the risks associated with the four production systems; Provide the MMS with a level of detail necessary to compare and understand overall system risks for typical production systems

Abstract Recent deepwater discoveries in the Gulf of Mexico, where the nearest pipeline infrastructure may be more than 100 miles away, pave the way for an innovative approach to development, particularly for "marginal" sized fields. This paper takes a look at the activities, and explores some of the systems and sub systems, that could be used to support production operations. The paper describes some of the key concepts and drivers surrounding marginal field development and presents an innovative approach based on existing and proven technology. The development concept presented is for a water depth of 2000meters, and consists of a Dry Tree Unit (DTU) with a disconnectable turret-moored Floating, Production, Storage and Offloading vessel (FpSO) in close proximity to it. The FpSO, and transportation of produced oil, are based on the use of Articulated Tug Barge (ATB) units. Midwater flowlines between the DTU and the FpSO are utilised, together with integrated moorings. "Proof of Concept" model basin testing has been performed to verify the integrated solution as well as behavior of the individual units in varying sea state conditions. Findings confirm that use of a DTU, close coupled to a disconnectable FpSO, is both a feasible and cost effective alternative for deepwater GOM production. In addition, the use of synthetic mooring lines, abreast offloading and ATB's are also possible. Introduction Approximately eighteen months ago, an expert team was formed within Texaco to study different development scenarios for deepwater production. This was in anticipation of bringing production on line as soon as practical should the need arise. The development parameters guiding the team's work were: Conventional, current technology would be used where possible. Innovative, emerging technology would be used where it presented a practical alternative. Development economics would be optimized where possible. Safety considerations would be paramount to any concept studied. Methods to reduce development costs would be investigated. The purpose of this paper is to share Texaco's approach and findings regarding the cost-effective development of deepwater prospects in the Gulf of Mexico. It is presented in three sections, with the first outlining the preferred concept, the second describing the mooring arrangements together with the results from "proof of concept" model basin tests, and the third discussing marine transportation issues. System Description The proposed development system comprises the following: A purpose built, double hulled, deep notch, FpSO barge of 500,000 barrel capacity, fitted with a submerged turret loading system. The unit is capable of loading, treating, storing and discharging crude oil to transfer vessels via either side or stern fitted discharge equipment. The vessel has self-contained accommodation for a minimum of 20 persons, and is capable of site abandonment in the event of a hurricane. A purpose built double hulled, dynamically positioned (D/P), articulated tug/barge shuttle tanker of 500,000 barrel capacity An integrated mooring system, comprising chain/synthetic/wire ropes, connecting the FpSO to the DTU through both independent and common lines. Flexible mid-water risers. ?Close proximity mooring of the FpSO to the DTU, at a distance of 700 meters.