TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper addresses the design criteria for a Floating,

Abstract. This paper describes a real "Journey" starting in 1977 with the first production well in Enchova Field, at a water depth of 110m. It covers twenty-five years, since the concept of a Mobile Offshore Drilling Unit was first used to produce an oilfield in advance of a definitive production system, evolving to a complex and fit-for-purpose Platform, able to handle all requirements of fields located in Ultra-Deep waters of around 2000m. This Journey follows, step-by-step, the technology challenges to be overcome with a sequence of field experiences as well as lessons learned at each step. The article details milestones and very innovative systems, like the first Semi-Submersible based System, with an oil production capacity of 10,000 bpd, as well as flaring of all associated gas exporting the crude to a spread-moored FSO through a floating hose. This Floating Production System combined simultaneous production and drilling capabilities. A further step was one of the first FPSOs around the world. Designed in 1977, with oil produced for the first time in 1979, it used an innovative concept that comprised atmospheric wellhead cellars (WHC) and a multiplexed subsea control system. The FPSO was installed using a tower-yoke system able to keep the Unit on station as well as to gather all fluids from the subsea system and export treated oil to a vessel moored at another tower system. With the increasing water depth, new challenges arose. They have driven PETROBRAS to innovative concepts like taut-leg mooring, vertical connection method for flowlines into subsea hardware and new flexible line developments. Since there were, at that time, no similar situations around the world, PETROBRAS had, along these twenty-five years, to take the lead and, many times, Campos Basin was used as a real fullscale lab, applying concepts that were yet to be field-proven. The operational experience throughout these years was fundamental for the new coming projects and a summary of their respective performance is also presented at this paper. Today Campos Basin has on stream 13 fixed platforms and 21 floating product systems. Four new production units will be installed until 2004 at water depths as deep as 1,250m and oil production capacities of up to 180,000bpd each. We shall compare and address key points of these new units and, in addition, show the success of Dynamically Positioned Floating System, producing wells down to 1,800m water depths. Introduction and Background. It was in 1974 that oil flowed out or the first time in Campos Basin, through an open well test of the wildcat RJS-9. This very first oilfield was named Enchova and, thus, the exploitation of Campos Basin started 25 years ago. Today, this field is still on stream and together with many others around it, contribute with more than 80% of Brazil's oil production and about 45% of the Brazilian natural gas output. Campos Basin is located on the north coast of the Rio de Janeiro State and comprises an area of around 115,000 km2.

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.

There is renewed interest in the oil and gas industry in standardisation as a mechanism for cost reduction, driven by the present low oil price and a search for efficiencies in project execution. However, the implementation of any approach to standardisation requires clarity about the objectives, benefits, and compromises that are required. This paper reviews the different approaches to standardisation that can be considered for FPSOs, examines historical examples of standardisation, and the degree to which these examples have been successful. In particular, the paper addresses the extent to which design replication is possible, and the impacts of field conditions, regional regulatory framework, and client specifications on standardisation. Based on lessons learnt from the industry, together with in-house experience of FPSO design and operation, the paper will provide guidance on the extent to which standardisation can be achieved, the areas in which it can be applied, and the potential obstacles to its successful implementation.

This paper was selected for presentation by the OTC Program Committea following review of information contained in an abstract submitted by the author(s). Contents of the paper, aspresented, haw not boon Rwiswsd by the Omhore Technology Conference and are subject to c o~o n by the author(s). The material, as presented, does not necessarily reflect any position of the Omhore Technology Conference or ih dicerr. Elactmnic reproduction, dishibution, or storage of any part of this paper for commercial purposes without the mittsn cmssnt d the Omhorn Technology Conference i8 prohibited. Permission m reproduce in print is resbicted m an abstrsct of not more than 300 words; illvsbrtions may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the papar was nraMnted sea bottom temperatures.Although Petrobras is aware of asphaltene, scale and hydrate occurrence, this paper will focus on present diificulties, solutions and procedures adopted by Petrobras to minimize wax deposit impact on deep water exploitation projects applying pigging. The use of pigging techniques implies an additional investment that must be foreseen in the initial phase of the project.The following aspects will be highlighted: AbstractPETROBRAS EXPLOITS oil from fields located in deep Strategies for pigging in subsea projects.water in Campos Basin, a subsea project which faces some problems. One of them is wax build-up subsea production flowlines. So, since 1990, methods to prevent and remove wax deposits have been studied. The occurrence of wax build-up in flowlines installed in cold sea bottoms is a permanent challenge, so pigging among other methods, is used to control wax deposition on pipeline internal surfaces. Pigging in subsea systems is a f i c u l t task, because reliability in equipment, facilities, and procedures. This paper is a continuation of other papers that Petrobras has presented in international conferences and describes pigging requirements for subsea equipment, flowlines, platforms and FPSOs designed for the Campos Basin. Some devices that Petrobras has developed to run pigs in subsea systems, such as dualdiameter scraper pig, subsea pig signaler, piggable Y, and piggable loops, are also presented.