Offshore energy market conditions change rapidly, with consequential demand changes for installation equipment, floating units and support vessels. Newbuilding requires a substantial investment and often takes (too) much time to obtain maximum benefit from an emerging opportunity. Upgrading or conversion of an existing unit can be a good alternative. There are eight different hull types to choose from for floating offshore units. The most common vessel type is the ship-shaped monohull. Within the large pool of existing merchant and offshore vessels, both new and ageing, there are many suitable candidates for upgrades and conversions. Such a new lease of life expands their operational and economical portfolio and serves the offshore industry in reaching spectacular advances in transport, construction and installation performance. When upgrading or converting existing units multiple tiers of capability increase are distinguished. Each tier brings increasing complexity, risks and re-building costs. Options range from life extension and modernization of an older vessel, temporary conversion, capacity upgrade, adding functions, changing the present function, to ultimately the complete transformation of an older merchant cargo vessel into a brand new offshore unit. Major vessel conversions can be competitive with newbuilding options, provided that such a complex conversion project is prepared and managed well. New insights into the market drivers for upgrading and conversion of floating offshore assets are provided. The broad range of offshore vessel modifications presented is an industry first. Some remarkable examples of capacity upgrades, double conversions and complete vessel makeovers are presented.

This paper details the process undertaken for the design of a novel windfarm Service Operations Vessel (SOV). This paper covers: An offshore wind energy sector overview Characteristics of the Compact Semi-Submersible (CSS) platform Design and analyses required for concept SOV validation Design challenges, risks and solutions Approval in Principle (AiP) process with class The information within this paper will be useful to design companies moving away from their typical knowledge base and vessel portfolio. Venturing into a new market sector or new type of vessel always presents risk. This early stage AiP process reduces that risk before a project and design gains too much momentum to be able to incorporate regulatory updates or interpretations at a later stage. Challenging area's based on the designer's and classification society's experience are discussed with proposed solutions as well as areas to focus on and develop with up and coming rule updates, guides and interpretations. The CSS platform is classed as a Mobile Offshore Unit/Mobile Offshore Drill Unit (MOU/MODU) due to previous versions of the design being classed in such a manner for the offshore Oil and Gas sector. Applying a vessel designed for this sector to a new but similar sector which requires alternate regulations calls for clear interpretations and rule compliance. The relevance and applicability of more recent class notations such as "Ship Shaped Unit" are still being investigated and analyzed. This could allow for more relevant and typical vessel like criteria to be applied to the platform when transiting to and from shore and between turbines but then allows for MODU like notations to remain when gangway connected or operating on station and in Dynamic Positioning (DP) mode. HAZID workshops are highly recommended for novel concepts such as this to identify and eliminate "show stoppers" during initial design stages. Time spent undertaking such reviews at this stage pay for themselves in a reduction in design rework during class, functional and production design stages. The relatively immature and rapidly evolving nature of this industry sector leads to many challenges for all involved and the willingness and cooperation that classification societies play during early stage designs to provide the necessary guidance to safely meet the developing market segments is critical. Offshore Oil and Gas regulations become the founding basis for many novel offshore designs but are not always entirely appropriate because the mechanical, structural, stability, safety and habitability requirements differ in many ways. The AiP process undertaken between designer and classification society for this project highlighted many of these areas and highlighted areas in which rules require development and careful interpretation.

Abstract This paper describes the design, building and functioning of a ship forsingle-lifting of topsides of offshore platforms up to 53,000 short tons(48,000 metric tons) and jackets up to 27,500 short tons (25,000 metrictons). The vessel will have a wide slot at the bow which fits around platformsubstructures and is equipped with a hydraulically operated topsides liftingsystem. For installing or removing platform jackets she will have a system oftwo tilting lift beams at the stern. Very large lifts can substantially reduce offshore hook-up costs in topsidesinstallation. In topsides decommissioning, single-lifting can make laborious module removalunnecessary. The offshore environment is spared and the safety of personnel atwork offshore is enhanced. In rough areas such as the North Sea, a motion elimination system is anecessity to avoid re-impact of a lifted structure onto its base structure, which could cause severe damage. The vessel may not always find sufficient occupancy in very heavy lifting workand therefore will also be a pipelayer with an S-lay tension capacity up to2200 short tons (2000 metric tons) for installing heavy pipelines in shallowand deep water. The building of the vessel and equipment is in progress; she is scheduled to becommissioned by the end of 2013. Traditional modular lifting versus topsides float-overs Installing large offshore platforms has so far generally been done with cranevessels. Large topsides have to be installed module by module to ensure thatthe lifts remain within the capacity of the cranes. This can lead to considerable offshore hook-up costs to complete the topsides, which is more expensive than when done on land. However, by single-lifting the offshore hook-up costs can be significantlyreduced. If a topside structure is completed on land and installed in onepiece, the making of all the connections between elements or modules -structural, electrical, hydraulic and piping - is faster and less costly. Installation of large integrated topsides by a "float-over" method has alreadybeen proposed since the 1970s, and in benign waters has been applied by severalcontractors. In the Gulf of Mexico, Versatruss successfully applies single-lifting with aninnovative system of large frames on two barges in still water. The large semi-submersible crane vessels of Heerema and Saipem havesuccessfully done integrated lifts of up to 12,000 short tons (11,000 metrictons) with two cranes, in very favorable weather conditions. Removing large topsides by traditional crane vessels requires the topsides tobe removed module by module, or by more time-consuming, hazardous and expensivedismantling offshore in small pieces. When removing topsides in a modular way, every module must be cut loose fromthe surrounding modules, lift points must be re-installed, and lift riggingmust be attached. Platform walkways, escape routes and safety plans must beadjusted several times during the removal process. Several "make safecampaigns" are required offshore and onshore. At an early stage theaccommodation facilities will have to be removed because of their outsideposition and then will no longer be available to the dismantling crew.

Abstract The UAE has made significant strides in the field of artificial island construction in mega projects for a wide range of applications including real estate, tourism, airport runways and other transportation causeways. Now, artificial island technology is being extended into the oil and gas industry. Space limitation on natural islands and the urgency to develop strategic offshore oil fields within Abu Dhabi's Exclusive Economic Zone, and to upgrade or expand storage and offloading facilities spell the need to rapidly adopt and adapt the technology. With favorable water depths and environmental conditions, artificial islands at times prove to be more economical than traditional fixed steel jacket platforms. In addition to reducing both CAPEX and OPEX, greater well capacity may be made available earlier when the artificial island option is selected. Certain environmental advantages can also materialize with respect to the artificial island option in the Arabian Gulf. Most recently, ADMA-OPCO has been engaged in applying the technology to projects such as the Das Island Permanent Accommodation (DIPA) project as well as the Satah Al-Raaz Boot (SARB) field development. ZADCO has made significant progress in expanding drilling and production from the Upper Zakum field using artificial islands (UZAI). On Das Island, a major land reclamation undertaking is ear-marked for the construction of a new, state-of the art village for oil and gas industry personnel operating on the island, in compliance with the UAE 2014 Camp Regulations. The island expansion will create sufficient space for ADMA-OPCO and ADGAS to expand their industrial facilities in the center of the island; while creating a safety Buffer Zone between industrial and accommodation designated areas. Significant cost and schedule optimization will be realized with the selection of the artificial island option for the SARB and Zakum fields. The new islands will last the entire life of the developments, in contrast with the possibility of having to replace discrete well-head towers before field depletion. Additionally, the increased spread of the artificial islands and the possibility of utilizing more conventional onshore technologies will translate into ease of access and maintenance around the facilities and enhanced safety on the islands relative to those on equivalent jacket supported platforms. Introduction The practice of constructing artificial islands is relatively common, especially in the UAE. They are built for a wide range of uses, including real estate, tourism development, airport construction, and transportation links, as well as oil and gas production. The most important consideration for island design is the definition of the project operational requirements. To meet those requirements, factors to consider in design include target commissioning dates and site inputs such as bathymetry, seismic activity, metocean and geotechnical conditions. In this paper, three projects are highlighted where land reclamation and artificial island technology is utilized to meet the project requirements in the most feasible manner. These projects are yet in their early stages and follow up will be made in future publications.

Abstract Introduction With the shortage of 2D and 3D seismic vessels, rather than build a new vessel some companies are converting suitable candidate vessels into seismic vessels. Building new vessels is expensive and presents difficulty in finding a yard with vacant spots for the build and the necessary expertise to construct such a quality vessel. One way of providing a faster, quicker method of producing a seismic vessel is to find a suitable hull and type of vessel capable of being converted into a seismic vessel and carrying out the engineering and installation of the equipment during a conversion. This is a cost effective method approach of achieving the required vessel in timely fashion at a much reduced cost. This paper describes the conversion of such a vessel in Canada and the factors which attracted the owner to have the work done in a Canadian Yard. Doing Business in Canada Canada has earned an international reputation for providing quality shipyard service in both the marine and offshore sectors and as such is poised for continued global growth. Canadian shipyards have both the ability and the expertise at the ready for ship repair, complex conversions and new construction projects For this reason Canada has created a number of financing solutions with the objective of stimulating demand for new Canadian built vessels, complex conversions, and large life extension projects on ocean going ships, MODUs, MOPUs, accommodations vessels, etc. The vessel highlighted in this presentation took advantage of these programs. We will provide a brief description of the two cornerstone programs available to this owner. Financing Export Development Canada (EDC): EDC is an agency of the Canadian Government that operates like a commercial financial institution, offering a full range of trade finance services to Canadian companies and their buyers in some 200 countries around the world. EDC is able to offer competitive financing to Canadian Shipbuilder's foreign buyers, and add to the often limited capacity of conventional financial institutions. EDC provides support in three (3) areas: New Construction Conversions Ship repairs Eligibility: EDC support is based on the credit worthiness of the borrower. It's pricing and terms of the loan are based on commercial principles. In order to be eligible for the EDC financing, the proposed transaction must involve: Shipyard (s) operating in Canada; A benefit to Canada; and Vessels / rigs that operate internationally Even if the transaction does not meet these requirements, EDC may still be able to provide a financing solution that meets your specific needs.

Abstract The simian / sapphire fields are located 114 km and 74 km respectively from shore ranging from 500m up to 1100m water depth in the west delta deep marine concession offshore Egypt in the eastern Mediterranean. These fields lie in the vicinity of the existing scarab / saffron fields and produce via manifolds and infield pipelines into existing offshore pipelines (24-inch and 36-inch) which bring the gas to a terminal onshore. The development concept is a long distance subsea tieback of the wells direct to the control platform and shore with control by umbilicals. This paper describes the different way to develop simian / sapphire two fields as a stand alone through controls platform. One of the keys to a successful simian / sapphire subsea development is the control philosophy and umbilical design. A long distance tieback is an issue due to the location of fields from the shore and the number of wells needs to be accommodated within both two fields. This paper will explain the advantage, disadvantage and lessons learned form having a shallow water control platform to control both two fields. And accommodate future expansion. Introduction Simian / Sapphire fields development comprise fourteen (14) wells, four subsea manifolds, two tie-in manifolds, four subsea distribution assembly, two main hydraulic and electric umbilicals connect the subsea distribution assembly to the control platform and power communications cable umbilical connect the platform with the onshore facilities. This paper is concerned with the following: Having controls platform to monitor and communicate between Simian Sapphire subsea wells and onshore terminals. controls platform case study advantage, disadvantage and lessons learned from using the controls platform Conclusion Fields layout Simian, Sapphire and Scarab/ Saffron general locations are shown in figure 1. Starting in the deepwater area, the Scarab/Saffron, Simian and Sapphire fields comprise 8, 6 and 8 wells respectively. Wells at each field are connected to subsea distribution assembly (SDA) for control and susbsea manifolds for gas flow collection. Each field export lines pass the gas production to the subsea pipe line end manifold (PLEM) located at 95 m water depth. From the PLEM, two main export lines 36-inch and 24-inch carry the production gas to the onshore terminal. Main export lines are designed to accommodate the flow from Scarab/Saffron, Sapphire and Simian fields, future field's development.

Abstract To fulfill energy needs, Exploration and Production Companies are searching for oil and gas in deeper and deeper water. Consequently, installations are being positioned farther from shore and the length of stay aboard these installations for crews could also increase. Long stays offshore for crew members can challenge their mental and physical fitness levels, which in turn may impact crew and installation productivity, performance, and safety. To help maintain appropriate levels of fitness, crew members must be provided with properly designed accommodations and workspaces with favorable ambient environmental factors. To assist crew members in maintaining appropriate levels of fitness, ABS has developed a comprehensive guide that integrates human factors and ergonomics with accommodations and ambient environmental design criteria. The purpose of this paper is to describe the development of the ABS Guide for Crew Habitability on Offshore Installations, which includes accommodations and ambient environmental criteria and measurement methodologies, as well as the results of field-test validation measurements for ambient environmental criteria on ships and offshore installations. Introduction In the offshore industry. crew members are often required to live at their workplaces (i.e., aboard offshore installations). While this facet is shared with some other industries, the conditions that personnel may be subjected to are unique and under some conditions may even be considered harsh. These conditions can take a toll on offshore crew members and can influence their performance by increasing physical and mental fatigue that can lead to an increased potential for human errors. The quality of accommodations together with the ambient environmental conditions can also influence crew members' job performance, overall sense of comfort, and well-being. Additionally, attempts at optimizing staff levels and increases in the complexity of on-board systems due to technological advances, makes it vital that offshore crew members maintain enhanced levels of mental and physical fitness while aboard offshore installations. To maintain these enhanced levels of fitness, crew members need to be provided with well-designed accommodations spaces and workspaces. Accommodations spaces and work spaces include areas where crew members work, rest, recreate, relax, and dine. Ambient environmental factors include vibration, noise, lighting, and indoor climate variables. All of these factors can influence human performance. For example: Vibration - Extreme levels, low and high, can expose the human body to acceleration vectors of varying directions and magnitudes, which can consume energy and induce fatigue. Noise - High noise from environmental or mechanicalsources, can significantly affect voice communications, audibility of signals and alarms, and the ability to rest. Lighting - Appropriate lighting levels are critical because vision is the dominant sensory channel for receiving information. Indoor climatic - Indoor climate variables can influence performance when conditions either change or become extreme. The author's believe that the accommodations and ambient environmental criteria presented in ABS Guide for Crew Habitability on Offshore Installations1 will costeffectively improve system performance and reliability by optimizing personnel performance, and promote health and safety by providing acceptable levels of crew habitability aboard offshore installations. For the purposes of this paper, "offshore installation" is defined as a manned facility that contains hydrocarbon production and processing sys

Abstract An overall conceptual design development of a deep sea FPSO suitable for the Gulf of Mexico area is described. The oil storage capacity was determined after the market screening by analyzing the answers to questionnaires submitted to potential field operators. The locations of turret, accommodation, topsides, flare boom and offloading equipment have been studied carefully before selecting the final location on the general arrangements. The basic drawings of general arrangements, lines, mid-ship section, accommodation layout and outfitting systems are developed. The basic hydrostatic calculations, stability, motions, mooring, structural and riser analyses are also carried out. The model tests are carried out at 2-dimensional wave flume for roll motion and wave model basin for global performances. In order to reduce the roll motion, a box-like mid-ship section is adopted with projected bilge keels. The model tests confirmed the expected good motion performances. A turret moored, one million barrels storage capacity, double hull FPSO is found to be most suitable in the Gulf of Mexico. Introduction The Gulf of Mexico was the last offshore oil field area not open for FPSOs. The absence of FPSOs from the GoM is partly due to the well-developed production and pipeline infrastructure. Another reason is the relative prevalence of gas developments in the GoM. As production enters deeper water and far away from any export infrastructure, the demand for FPSOs gets stronger. The final threshold to open the GoM for FPSOs was a safety confirmation. MMS (the Minerals Management Services) have expressed concerns about FPSO deployment, which have focused on the performance of offloading operations and the vessels' survivability during hurricanes in the GoM. According to the EIS (Environmental Impact Statement) recently issued by MMS, potential sitespecific impacts are essentially the same as with other deepwater development and production systems. The FPSO has been widely used as a most competitive production system concept in other offshore fields where infrastructure is not sufficient, or where the fields are marginal. As the water depth for offshore fields increases, more offshore operators have selected the FPSO concept. Considering the size of the oil reservoirs in the GoM, FPSOs will be widely adopted by the main operators. On December 31st 2001 the MMS announced its decision to allow the industry to propose using FPSOs in the central and western Gulf of Mexico. This paper presents an overall conceptual design development of a deep sea FPSO suitable for the Gulf of Mexico area. The locations of turret, accommodation, topsides, flare boom and offloading equipment have been studied carefully before selecting the final location on the general arrangements. Environmental conditions in the Gulf of Mexico, such as hurricanes, ultra-deep water depth and loop currents, required special consideration in the dimensioning and arrangements.

Abstract During the last years, the interest in LNG FPSO's has been revived. One of the challenges in designing a LNG FPSO is the liquid sloshing in partial filled tanks. One of the unique features of the spherical tank is that it is certified for operation with part filling to any level. It is therefore well suited as containment system for floating LNG production units. The spherical tank was developed as a containment system for LNG carriers more than 30 years ago. The tank is essentially a shell supported by a cylindrical skirt through a patented transition joint. The spherical shape results in membrane type operational stresses and bending moments are limited to the transition area where they are carefully controlled. The tanks are today constructed entirely of aluminum by specialized shipyards around the world. The spherical LNG tank is installed in close to 70 LNG carriers, some of which are nearly 30 years old and have recently been certified for another 20 years service. All vessels built are still in service today and no serious incidents directly attributed to the tank construction have ever been reported. Through a number of studies for major oil companies we have acquired a solid database and a good overview of the technical and economical challenges which must be met and the safety requirements that have to be adressed. This paper will outline the unique features of a floating LNG production facility based on the spherical tank system. It will be shown how the overall safety is enhanced through the use of the spherical tank and how it can be adapted to suit requirements for harsh as well as mild weather conditions, different production capacities and feed compositions. INTRODUCTION Although having been the subject of numerous concept studies and proposals for the last years, the idea of LNG production on a floating structure is by no means new. In the mid-to late 1970's a LNG FPSO was offered to Iran for the Kangan field. A full basic engineering design including comprehensive safety assessments was carried out and Det Norske Veritas prepared a Rule Proposal. The unit consisted of 6 spherical LNG tanks and a 2-train APCI process in a steel hull. The hull was weathervaning on a single point mooring and the unit had a LNG production capacity of 2,8 MMTPA and a storage capacity of 165 000 m3. Complete front-end engineering was carried out for this project including comprehensive risk assessment. The project was terminated for political reasons. The main features of the Kangan LNG FPSO are shown in Figure 1. Figure 1 - General arrangement and main features of the Kangan LNG FPSO(Available in full paper) Since then, a number of concept studies have been done for oil companies on the same subject. However, recently these activities have become more and more frequent due to thegeneral interest throughout the LNG industry.

Abstract. The Kapok gas field development, along with the concurrent Bombax pipeline project, will double BP's offshore Trinidad gas delivery capacity from the current 1.5 bscfd to 3 bscfd. This step change in delivery requires significant additions in both facilities and wells. The Kapok project team was tasked to deliver a field development scheme that not only would meet rate profile demands, but would do so while reducing the cumulative environmental impact of both new and existing infrastructure and introduce BP's highest level of health and safety standards to it's Trinidad operations. In a relatively short timeframe, the project team evaluated distinctly different schemes and arrived at a solution that: increases the overall safety of personnel working in the infrastructure; reduces the cumulative environmental impact of the new and existing infrastructure; addresses popular issues including mud cuttings discharge, disposition of produced water, and ESD flaring; and meets the desired financial parameters associated with the step change in BP's gas business. This paper outlines the challenge, presents the evaluation of differing development schemes, and details the novel solution that will significantly alter the way in which BP delivers world-class gas reserves offshore Trinidad. Introduction. The Republic of Trinidad and Tobago's gas business has grown rapidly over the past decade, successfully supplanting a declining oil business dating back some 40 years. The pace of growth has been fueled both by the nation's competitive source of gas supply and the ability to monetize its gas through proximity to Atlantic rim gas markets. BP Trinidad and Tobago LLC's (bpTT) share of the gas supply has grown from less than 350 mmcfd in 1994 to over 1000 mmscfd today. And with additional downstream projects, including the commissioning of two new liquefied natural gas trains to be completed by mid-2003, BP's gas production is set to increase to over 1800 mmscfd by 2004. Buoyed by sustained world-class exploration success, BP is considering additional opportunities that could more than double its share of the country's expanding gas business over the next 10 to 15 years. To date, BP's gas projects in Trinidad and Tobago have progressed on an as required basis, focused at fulfilling a specific market need. As such, field developments utilized offshore facilities and processes that were remarkably similar to each subsequent development, whilst making incremental improvements. These relatively small platforms served multiple purposes: accomodating 16-32 wells; basic production process facilities ranging from 300-825 mmcfd capacity; the termination point for multiple large diameter risers; the base for a temporary, modular platform drilling rig and drilling crew accommodations; and accommodations for permanently based offshore production and maintenance staff. Collectively over time the transportation and process infrastructure of these fields has overlapped. Fig. 1 depicts BP's offshore Trinidad gas infrastructure, as it exists today. Fig. 1 Existing bpTT Gas Infrastructure(Available in full paper) Notably, the major platforms range in age from 20 years old (Cassia) to a recent installation (Amherstia).

SYNOPSIS The Glas Dowr FPSO paper describes a modern "Fast Track" Bluewater Project that began in December 1995 and will be completed with "First Oi/" targeted in May 1997. The Glas Dowr was "Converted and Outfitted" for installation in the Amerada Hess (AHL) Durward & Dauntless Field, UK Central Sector of the North Sea. The Glas Dowr, which is Cornish for Bluewater, commenced life in a Japanese shipyard, before sailing 14,000 nautical miles to Harland & Wolff (H&W) in Belfast for the Project Conversion Phase. The Glas Dowr project continued with the sea tow from Belfast to the Tees Offshore Base for the Outfitting Phase of the project, this covered the installation and integration of the Pre- Assembled Units (PAU's) with the Ship Marine and Utility Systems. From Tees Offshore Base, the FPSO will be towed to the North Sea Durward & Dauntless Field, UK Blocks 21/16 and 21/11 for installation and hook up to the pre installed anchors, Subsea wellheads and manifolds. The paper describes the project strategy adopted, the Operations influenceon the project plus a description of the Self Verification process to obtain the necessary Certification for North Sea FPSO duties. The names Durward and Dauntless are derived from the classic novels of Sir Walter Scott. Dauntless was the epithet applied to Harold, son of a Danish Viking, whowas granted land between the Wear and the Tyne. The Quentin Durward novel chronicles the activities of a young Scott who enlists in the Corps of Scottish Archers in 15th century France. 1. Introduction to the Field The Durward and Dauntless Fields are located in the Central North Sea in water depths of 90 metres, approximately 140 Km east of Aberdeen. The Durwardand Dauntless reservoirs were discovered in 1993 and 1994 respectively, the distance between the two fields being 7.5 Km. Amerada is the Operator of both the fields. The Glas Dowr is located between the two fields in the pipeline corridor, at approximately 4.3 Km from the Durward Field, north of the Fulmar pipeline. The Glas Dowr is anchored to the sea bed using a combination of chains, wires and anchors set in a triangular configuration with nine anchors in groups of three spaced 120 degrees apart. The subsea wells are tied back to the FPSO through a series of subsea manifolds, pipelines, riser bases and riser systems connecting into the turret. A combined subsea production and water injection manifold is located at the Dauntless Field and a separate water injection and production manifold is located at the Durward Field. The Subsea Control System is an Electro-Hydraulic System combining Field Bus communications and electronic technology with an established high pressure hydraulic system designed to provide control and monitoring of Subsea wellheads and manifolds. Theinitial control requirement is for 7 wells, 5 producing wells and 2 water injection wells. The system is designed for the future control of 45 wells.

Abstract This paper presents improvements on basic and engineering design of four converted VLCCs that will be operated as FPSOs in Brazil's Campos Basin. Conbersion of these VLCCs is under way, worked on by contractors around the world, the first of them being scheduled to start operations by the middle of 1997. Project economics demand that the units be operated during the next 20 years without docking. PETROBRAS offshore operations and maintenance expertise were applied to achieve this goal, meeting unique FPSO operating conditions. Experience and data gathered by project team members and technical staff are now being incorporated into next generation units, which are at present moment in Design Basis phase. Although these improvements will only show their effectiveness after units come into steady operation, we are confident that major achievements in safety and economics have been made successfully. Introduction The discovery of Marlim and Albacora, giant deep water fields in Campos Basin, offshore Rio de Janeiro state, will allow PETROBRAS, a remarkable increase in national oil production. On the other hand, due to the difficulties related to deep water production, distance from the shore and from existing facilities, the start of commercial production of hydrocarbons from those fields as quickly as possible, in the most economical way, within good reservoir exploitation techniques and preserving the environment is also an enormous challenge to the Company. The traditional solution adopted by PETROBRAS for offshore production, the utilization of semi-submersible platforms (SS) as floating production units (FPS) and the pumping of oil and dispatching of gas by pipelines or the pumping of oil through monobuoy, was used in pre-pilot and pilot units in Marlim field (P-XI11 and P-XX), Stationary Production Unit (UEP) N.l in Marlim (P-XVIII), and in Albacora field (P-XXIV and P-XXV). Other units of the same type are planned, such as UEPs 2 and 3 in Marlim (P-XIX and P-XXVI). However, in order to complete development of the fields, it would be necessary to expand the pipeline network, by the construction of new pipelines, or by the installation of new monobuoys, considered to be the "weak links" in the system, as the existing pipelines could not stand the increased flow. The technical and economical viability study shows as the best option, the installation of FPSOs. Due to the estimated field life of 20 years, and considering the complexity of the pull-in and pull-out operations, the study indicates the permanency of the units on location until the end of the life of the field, without docking. The definition of the necessary storage capacity of the FPSOs took into consideration the estimated oil flows forecast for the fields, the availability of the tanker fleet to be used as relief vessels and, aiming to reduce operational costs, a lower frequency of offloading operations. With PETROBRAS having some VLCCs available, the option of converting them into FPSOs came into consideration.

Abstract Purpose-built FPSOS have at present gained a position by operators as a viable and technically fully acceptable solution compared with the cautious attitude experienced only a few years ago. During these years we have also seen that the majority of the FPSO's have been contracted to traditional shipbuilders for construction. The transition from the typical ?fixed offshore platform' environment to the ?floating offshore installation' environment of marine builders (i.e. shipyards) has posed quite a few challenges to all involved parties. The role of offshore legislators and their adaptation to the new players. i.e. yards, vendors, ship owners as well as Marine Administrations and Classification Societies have and will continue [o undergo changes to adjust to the offshore industry which extends way beyond the mobile drilling unit practice. However, the tradition and the practical approach of the maritime industry can be satisfactory mated with fixed offshore practice contingent that the two cultures are willing to appreciate the best of the other. Among the challenges to be taken in this respect, the most important task is for the marine industry to take and exercise a dedicated ownership of the philosophy and principles of risk based design and implement it throughout all stages of an offshore project. 1. INTRODUCTION FPSO's, or Floating Production. Storage and Offloading Vessels, are by no means a new concept nor unproved, but the North Sea Continental Shelves have not been folly aquatined with these until the recent years. Tankers for oil and a few column stabilised units have been converted into FPSO/ FSO / FPU'S for operation in Brazilian and Asian waters the last two decades and proven to suit the demands set forward by the operators, The UK Continental Shelf (UKCS) has also seen an increased volume of converted tonnage enter into FPSO service in harsh environments, but it was not before the entrance of the Petrojari 1, a purpose built new production, storage and offloading ship. that FPSO's attracted serious attention from major Norwegian operators. However, it took another two FPSO new buildings initiated on a speculative basis by Norwegian ship owners before the concept of FPSO's gained the present dominant position in the North Sea region. In regions outside the North Sea, converted tankers or semi's are still the preferred option, although a few new built FPSO's have entered into service in Asian and Australian waters. The transition from the typical ?fixed offshore platform' environment with a network of well established offshore fabricators, engineering companies and vendors 10 the ?floating offshore installation' environment comprising of marine builders (e.g. shipyards) with their network. has posed quite a few challenges.

Abtract A vast experience on design of gas and oil processing facilities baaed on fixed platforms exists all over the world. A development of the last yews is to place the facilities on a floating tanker which serves as storage unit as well as foundation. The so-called Floating Reduction and Storage Units are usually "weather-vaning" around the turret. Wind, waves and current cause motions of the FPSO and the various loading and ballasting conditions result in semi static inclinations. The various motions and barge conditions have an effect on the topsides processing facilities. In this paper the effects on the topsides layout, the design of process equipment and the detailed structural and piping design of the topsides are presented. Introduction The Guillemot and Teal project was started in January 1994when Shell Expro, who operate in the North Sea on behalf of Shell UK and Esso UK, awarded a contract for the lump sum turnkey delivery of the floating production and storage facilities to Single Buoy Moorings Inc (SBM), Fribourg. This company awarded a similar subcontract for the barge and the topsides to respectively Mitsubishi Heavy Industries (MH1), Nagasaki and Stork Protech Schiedam. Design of the turret would be executed by the Single Buoy Moorings lnc in the offices in Monaco. At a later stage in the project both Single Buoy Moorings Inc and Stork Protech awarded a contract for the fabrication and installation of the turret and topsides to AMEC Energy and Process Ltd, Newcastle. The main purpose of the FPSO is to produce dead cru& for export via shuttle tankers, to treat and export associated gas into the Fulmar Gas Line, to treat produced water prior to disposal overboard and to treat and inject seawater for water injection. The facilities will be installed on a newly built barge of approximately 132,000 tones dwt, The FPSO will be permanently moored by means of an integrated turret mooring system which will support the transfer facilities for well fluid and produced fluid streams to and from the FPSO. This paper describes the facilities provided on the Anasuria FPSO, the lay-out of the topsides equipment on the FPSO deck, the influence of the "weather-vaning" and other motion effects on the topsides lay-out and on the design of process equipment. Furthermore, the influence of FPSO movements on the structural and piping design is described The paper concludes with some lessons learned and recommendations on the basis of gained experience, Relevant Barge Movements The FPSOis subject to various types of motions and conditions arising from environmental forces, from barge loading and ballasting conditions and from operating procedures. Therelevant types of movements and conditions are categorised and described in some detail below, Weathervanistg. Weathervaningis the rotation of the barge around the fixed moored turret at the bow. Weathervaning is the result of environmental forces exerted by the wind, the waves and the currents. The turret allows 360 degree weathemirring. Weathewaning is a complex phenomenon, in which also the draft conditions of the barge play a role.

ABSTRACT FPSO technology over the past years has rapidly evolved from tanker based units with classical mooring systems to purpose-shaped new built vessels equipped with DP assistance, sophisticated permanent turrets or disconnectable mooring systems. FPSO's cover today a much wider range of applications than a few years ago, and are contemplated for ever more demanding field developments. Selecting the optimum FPSO concept at the beginning of a project is therefore a new step in the early phases of conceptual engineering. This paper describes the main design parameters of current FPSO projects, and evaluates the significance of their influence on the overall design. Several guidelines and insights are provided to help in selecting and combining together technical options available for specific field development cases. The detailed engineering, execution and operational experience gained on recent projects and actual realisations are largely called upon so that pragmatic considerations and recommendations can be suggested for achieving optimized FPSO configurations in a wide range of applications. WHAT IS AN FPSO? The "FPSO" acronym stands for: Floating Production, Storage and Offloading, which well defines the systems in question. The FPSO is one branch of the growing family of Floating Production systems, and differs from its colaterals by its capability to store and export oil in addition to producing from an offshore field, all in a single unit. While loading terminals or export pipelines are generally required with Floating Production systems, oil is directly offloaded to export tankers with an FPSO. Although not reflected in its name, facilities upstream of the production equipment can also be integrated with the FPSO system, including subsea well control, subsea flowlines, risers and manifolding. GENEALOGY (ORIGIN AND EVOLUTION) The ancestor was pioneered in 1976 by Shell in their Castellon Field offshore Spain. A 60,000 DWT tanker, "lldeFonso Fierro", was converted to an FPSO, producing oil from a single subsea well (Photo 1). It was soon followed by a twin in the Nilde Field offshore Sicily for Agip. The FPSO concept then evolved to handle production from several wells (Cadlao, Tazerka, Garoupa) and with more and more comprehensive process installations (Hondo). While it was favoured for developing several marginal fields in mild environments such as offshore west Africa, it also adapted itself to ever more demanding requirements, such as the threat of typhoons in south east Asia, with disconnectable mooring systems (ACT's Nan Hai FaXian, Photo 2), or to the stringent conditions of the North Sea with newbuilt units (Petrojarl 1). If a single picture of the whole FPSO family was possible today, no doubt it would be extremely colourful and contrasted. In the eighties, two factors contributed to the initial growth of FPSO's both in maturity and number: the availability of relatively young tanker tonnage at very low prices, the sustained development of swivels, flexible risers and subsea well technologies. However, the emergence of FPSO's as a standard way of developing a field is fairly recent, and this is probably due to the extension by the Oil Companies of the boundaries for the development of new fields.

ABSTRACT DESCRIPTION: This paper describes the engineering requirements which need to be complied with for the Classification and Certification of Floating Production, Storage and Offloading Units. Specific attention is drawn to the problems associated with the processing systems, storage facilities and the utility and auxiliary engineering systems. In order to ensure flexibility for specific charter requirements, the unit will have to meet a wide variety of site-specific regulations, and the approach to minimizing confusing and sometimes conflicting regulations is discussed. The paper addresses the above for both new constructions and conversions and discusses the relativemerits of each. INTRODUCTION In recent years, when developing oil and gas fields offshore, declining oil prices have meant that developers have had to look away from the concept of fried platforms. Instead of proposing a fixed platform to develop an oil or gas field, the decision is often taken to place a moored or positioned floating production facility on site to develop the field. Floating Production Facility (F. P.F,) is a master phrase for a variety of differently designed floating structures used for storing or processing hydrocarbons from the field to be developed. These "facilities" can range from unpropelled storage or dumb barges to specially designed self-propelled floating production, storage and offloading units. When an operator decides to go ahead with the development of an oil or gas field, and should the decision be to develop the field with an F. P. F., then such units are either purpose built for the specificlocation or are conversions of existing ships. Semisubmersible units, jack-ups, tension leg units and other specialised types of floating units can also be options pen to an operator. However, should the option be an F; P, F., then-in general the following type may be employed: (Available In Full Paper) Lloyds Register (L.R.) has been involved with many F.P.F.'s through the years, the most significant are detailed in Appendix 1. Before the approach to accepting an F.P.F. as fit to operate at an offshore location is discussed it is necessary to outline the principal Conventions, Rules and Regulations governing the approval procedure. INTERNATIONAL CONVENTIONS AND REGULATIONS Conventions: The International Maritime Organisation (I,M,O) is an organisation devoted to promoting safer shipping and cleaner oceans. Over the years it has developed more than 30 Conventions and Protocols dealing with maritime safety. The two most important Conventions are mandatory for ships engaged in international trade and are: 'The International Convention for the Safety of Life at Sea (SOLAS)' and 'The International Convention for the Prevention of Pollution from Ships (MARPOL). SOLAS The International Convention for the Safety of Life at Sea was convened in the year 1914. as a result of the loss of the White Star liner Titanic with 1500 lives. The latest publication is the 1992 edition which presents a consolidated text of the Convention, it's Protocol of 1978, and all amendments up to and including the 1990 amendments.

ABSTRACT The Norne Production and Storage Vessel (PSV) will be the largest monohull production facility in the world with a throughput capacity of 173,000 bbl oil and 238 mill scf gas per day, Production will be based on subsea completed wells, drilled through five templates and connectedto the turret moored PSV via flexible rises and flowlines. A high capacity swivel stack has been designed fortransfer of oil/gas/water between turret and facilities on the process deck. The Norne field is located further north than any other Norwegian field in operation or under development, and the water depth on location is 380 m. INTRODUCTION The Norne field is located in Block 6608/1 O, about 200 km west of the mid-Norway coast. The water depth on location is about 380 m. The top of the reservoir is found at a depth of 2525 m below MSL. At a reference depth of 2639 m the formation pressure is 273 bar and the temperature 98 degrees C. The recoverable oil reserves are about 72 mill. Sm3. The reservoir drive mechanism will be a combination of water and gas injection. Initially all produced gas will be reinjected into the gas cap. The plateau production rate representing a yearly recovery rate of 12.57. of total recoverable reserves Will be maintained for 3-4 years. The field will produce forabout 16 years. The development scenario is based on a Production and Storage Vessel (PSV) in combination with a subsea production system comprising 6 oil producers, 6 water injectorsand 2 gas injectors. The wells will be drilled through five subsea templates, two located in the northern part and three in the southern part of the field. The templates will be connected to the PSV via flexible flowlines and risers. THE PRODUCTION AND STORAGE VESSEL The PSV is a turret moored, ship-shaped production, storage and offloading vessel of Tentech 850 S design, see Fig.1. With throughput capacities as listed below the Nome PSV will be the largest monohull production system in the world. (Available In Full Paper) The vessel will, on location, be moored by means of a 12 point mooring system with 12 anchor chain winches arranged on the turret of the vessel. Five fully azimuthing, variable speed thrusters will be utilized as an active element in the station keeping and heading control, see section Instrumentation and control. The turret which will be held geostationary by the mooring lines, will also serve as attachment for all the flexible risers. From the swivel, on top of the turret, {he well stream is transferred to the inlet separator on the process deck. A total of 16 storage tanks and 2 slop tanks with a total capacity of 117,000 m3 will be arranged in the hull. Double bottom tanks, wing tanks and peak tanks provide ample capacity (about 48,000 m3) to maintain sufficient draught in ballast condition. All water ballast tanks and systems are segregated from the oil storage tanks. Accommodation for 120 persons will be arranged in the forward part of the vessels.

ABSTRACT The Gryphon 'A' Floating Production Storage and Offloading (FPSO) unit is the first purpose built permanently moored FPSO in the North Sea. The ship is moored some 1500m from the field wellhead cluster. Each well is connected to the ship with a jlexible J70wline using a "steep S" catenary from the seabed to the turret. The vessel is moored with a 10 anchor mooring system supplemented by an active position mooring system. Five fully azimuthing thrusters provide automatic thrust assistance. The Gryphon 'A' incorporates a "turret transfer system" to transfer hydrocarbons, utilities, electrical power and instrument signals between the "fixed" turret and the "turning ship". This system is unique in that it uses a vertical drag chain to effect the transfer. The main processing plant is single train with two stages of separation followed by an electrostatic coalescer. The ship has a storage capacity of 525,(XM barrels and is designed for offloading to a tandem moored shuttle tanker for export. INTRODUCTION Among an increasing number of floating production facilities throughout the world, the Gryphon 'A' is the first purpose built, field specific Floating Production, Storage and Offloading Unit (FPSO) operating in the North Sea. This paper describes the technical aspects of the Gryphon 'A' facility including the overall field layout, the subsea configuration and riser system, the vessel's marine systems and utilities, and the topside process equipment. FIELD LAYOUT The Gryphon field development comprises a total of 14 wells: 8 producers, 4 water injectors, I aquifer supply well and 1 gas supply/injector well. Figure 1 illustrates the FPSO with a shuttle tanker connected, the riser system, the flowline corridor and the wellhead cluster. The orientation of the field, with the wellhead cluster located 1500m to the South West of the FPSO, accounts for the prevailing weather from that direction. It also reduces potential interference between tanker operations during approach and connection and any drilling or well workover operations that may be taking place. With this arrangement it is possible to continue drilling and/or working over wells while maintaining production and offloading operations from the FPSO. Figure 2 shows the combined anchor patterns of the FPSO and the drilling semi-submersible on location over the wellhead cluster. In order to avoid any anchor line crossovers or interference during reconnection of semi-submersible anchors during future workover operations, the two shorter lines for the semi-submersible are connected to anchor piles. SUBSEA Well Cluster The subsea wells are tied back by individual flexible flowlines to the FPSO. The well cluster consists of two rows of individual wells spaced 10m apart with 30m between the two rows. Figure 3 shows the Well Cluster Layout. FIowlines The flowlines and the control/gas lift umbilicals from the ship to the well cluster are arranged in a flowline corridor 60m wide. Flowlines run directly between the xmas trees and the riser bases located beneath the FPSO. Risers connect between the riser bases and the turret via riser guide tubes.

ABSTRACT Fields with relatively few wells or imposed restrictions on topsides weight can benefit significantly from Tender Assisted Drilling (ZAD) mode of operation. In particular, marginal or satellite field developments can benefit economically by the use of the TAD concept for Platform drilling. This paper will focus on the use of TAD in harsh environment conditions such as the North Sea, and will review the technical aspects of conversion of existing semisubmersible drilling units to tender assist role to achieve the required performance in terms of operability and safety. To illustrate the various aspects of TAD mode of operation, reference will be made to the development of Total Oil Marine's Dunbar Field where the Sedco 706 semisubmersible is selected as the Tender Support Vessel (TSV). INTRODUCTION Current depressed day rates for drilling semisubmersibles caused by a downturn in exploration drilling activity has created a unique opportunity for low cost development of marginal fields. Most obvious is the conversion of a drilling semisubmersible rig to a floating production facility. However, less obvious but frequently more economical is the use of the vessel for a TAD mode of operation in combination with a fixed platform development. Making use of the drilling vessel's accommodation, power generation, mud pumping, cleaning and storage facilities etc. can reduce the Platform topsides weight by up to 3000 tonne [1], which in turn may make a Ml installed jacket feasible saving an additional 2500–3500 tonne of jacket steel [2] [3]. Such weight and associated cost savings may comfortably offset the extra cost of conversion of the drilling rig for TAD and vessel day rates during the drilling campaigns illustrated in Figure 1. Additionally the use of TAD with lead to reduced future operating costs as less Platform maintenance work is required. The reduced Platform accommodation capacity possible with TAD may also be a potential major operating cost saving and is definitely a significant contribution to increased Platform safety. Whereas TAD has long been common place in calm seas, it was not until the 80's that it emerged as a technique valid for harsh environment conditions like those prevailing in the North Sea, where two types of tenders may be considered: A jack-up operation, also referred to as "skid-off" mode. A semi-submersible vessel. The current differential in dayrates between jack-up rigs and semisubmersible rigs in combination with the faster mobilisation and demobilisation possible with a semisubmersible favour the latter. This paper will describe the use of a semisubmersible for TAD operation in harsh environment such as the North Sea. To illustrate the particular problems and possible solutions the paper will make reference to the Dunbar Field development. The Dunbar Field is located approximately 22 km South of the North Alwyn Field in the northern part of the UK North Sea. The Dunbar development comprises 2 separate hydrocarbon accumulations: The Dunbar Field, which is developed with a freed Platform, and the subsea developed Ellen Field located approximately 9 km from Dunbar and connected with subsea flowlines to the Dunbar Platform.

ABSTRACT Early in 1991 Santa Fe Drilling Company (North Sea) Ltd. decided to take a lead in developing their offshore Safety Cases particularly with respect to their 'forthwith"items. To achieve this aim they contracted Noble Denton to assist them in carrying out the Cullen "forttmvith" studies. This paper describes the methods and assumptions made in undertaking these analyses. INTRODUCTION Lord Cullen published his report on the Piper Alpha Disaster in November 1990(1)and by so doing set the scene for major changes in the way offshore structures, and the companies that operate them, areassessed, The report contains 106 recommendations that are likely to become part of the legal frameworkcovering the U.K. offshore continental shelf. In producing these recommendations Cullen drew heavily the results of similar enquiries, the Control of Industrial Major Accident Hazard (CIMAH) regulations and the Norwegian regulations. The intent is that, by taking on his recommendations, offshore safety will be improved and that the propensity for catastrophic events will be significantly reduced. In order to achieve this he concluded that: Companies should be required to submit a safety case demonstrating that their installation are safe and that the management structure issuch as to be responsive to safety issues That the current prescriptive regulations shouldbe changed out with regulations based on the precept of setting goals. The regulatory bodies concerned with safetyoffshore should be rationalized to be more in line with other onshore industries When the report was issued, it was realized that there could be some considerable delay before theregulatory regime could be changed to reflect the recommendations. In order to circumvent some of this delay, certain recommendations were made with the statement that the relevant study be performed "forthwith.., without waiting for legislation". These studies are?available in full paper There is little dispute that Cullen's report contains many very important and valuable proposals, some of which have been around since the turn of the century (2) . However the report also has some limitations, particularly when applied to Mobile Offshore Drilling Units (MODUs). In many cases these are only problems of detail, but they are indicative of a deeper problem. Take, for example, the emergency systems review: Cullen specifies that the severe accidents that he had in mind when producing recommendation 69 were fire, explosion and strong vibration. The emergency systems were to include the emergency power supply, communications and the Emergency Shutdown (ESD). While these systems and accidents may be sensiblechoices on a fried production platiorm, they are less than ideal for a MODU. On a MODU, the ESD system is basically synonymous with the BOP system, However in no way can the simplicity of this system be compared with the complexity of a production platform ESD. The potential accidents on a MODU, and the vital/emergency systems need to be considered in a different light from those on a production platform. Indeed this difference applies to much of what is said in Volume Two of Cullen's report.