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As part of the Monaco offshore urban extension project, Bouygues TP is in charge of design & build a maritime infrastructure as the first step of the six-hectare expansion of the city into the sea. This maritime infrastructure consists of a fill enclosed by a band of trapezoid concrete caissons and will serve as base for construction of the new residential area. The paper focuses on some of the problems which had to be solved: optimization of promenade level and wave absorbing chambers in conjunction with minimal reflection and safety related to overtopping, accounting for sea level rise and correlation between extreme waves and water levels. caissons and rubble mound foundation stability related to waves and seism, including extra seismic forces due to buildings considering the high reclamation height and the immediate proximity of building foundations. the way in which caissons representing nearly 80,000 m3 of concrete can be built in a floating and continuous manner via a caisson box (or "caissonnier" in French), within a particularly short time frame presence of a small craft harbor with shops along the quays, whose location was fixed for urbanistic reasons, which requested optimizations in detail of anti-overtopping devices as much as possible integrated in the urban context, need to convert a breakwater caisson into a low crested swimming pool caisson, with plexiglas windows exposed to wave slamming from outside, but also from inside due to overtopping impacts over the swimming pool basin. Ecodesign has been closely associated with hydrodynamic and coastal engineering, based on estimation of wave pressures and induced velocities in the different possible locations (chambers, walls, structures toes …). The eco-friendly development strategy is based on the wide-scale deployment of a range of 11 solutions which will be described (potential for caissons to be colonized, nursery function development, etc…). Moreover, posidonia transplantation has been done via concrete open boxes, whose stability under storm waves has requested CFD calculations to model local velocities and optimize their shape.

The paper is in support of the effort by the Marine Renewable Energy (MRE) Committee of the ASCE Coasts, Oceans, Ports, and Rivers Institute (COPRI) for setting up a guide document for offshore renewable energy foundations. The guide would use standard design codes for fixed foundations and mooring anchors in API, ISO and DNV. This paper focuses on specific aspects of design of offshore wind turbines that distinguish them from oil and gas installations. Emphasis is placed on the source of loading and the corresponding response of soil resistance. The paper also how soil investigation for offshore windfarms differ from oil and gas and economic procedures for carrying out such investigation. Foundation design of offshore structures requires identifying the critical loads. In the case of oil and gas foundations, the source of the load is the wind or wave or a combination of both. For offshore wind towers on fixed foundations, an additional source of dynamic load is the turbine blade rotation during operation. The frequencies of the rotor revolution and that of the blade passing the tower, need to be checked in relation to the resonance frequency of the foundation. The foundation dynamic response therefore depends largely on the stiffness and dampening characteristics. Most offshore wind turbines tend to be located in relatively shallow water depth where difficult multi-layered soils tend to be dominate. This paper also discussion installation suction buckets of fixed foundation in difficult multi-layered soils.

The Stones project is located in the Walker Ridge (WR) area approximately 200 miles due South of New Orleans in ~9500 feet of water. The host facility is a Floating Production Storage and Offloading (FPSO) vessel with a disconnectable moored turret buoy (BTM) that allows the FPSO to move off site in a hurricane event. Each of the nine moorings are made up of a suction pile – chain – polyester – chain – spring buoy – top chain assembly. These connect to the circumference of the BTM at the keel. The subsea infrastructure, including 2 flow-lines, one gas export pipeline, and two umbilicals, are supported by the BTM. The pipelines and all umbilical fluids, electrics, and fiber are connected or disconnected from the FPSO via dry internal turret connection systems. This paper provides an overview of the transportation and installation of the moorings, turret buoy. Key challenges include water depth world record for FPSO moorings, transportation and handling of the world's largest disconnectable buoy, and project execution during an extreme eddy current event.

A new set of Load and Resistance Factor Design (LRFD) based structural design criteria that is compatible to the existing Working Stress Design (WSD) criteria in the ABS classification rules for mobile offshore units (MOUs) and floating production installations (FPIs) has recently been developed. This paper presents an overview of the new LRFD-based structural design criteria with a primary focus on their applications, the load combinations, and the partial safety factors. The paper also presents a summary of the verification case studies for typical MOUs and FPIs. The case study results provide a direct comparison between the new LRFD-based design criteria and the current ABS WSD criteria, which have been used for designing numerous MOUs and FPIs. The verification case studies demonstrate the suitability of the LRFD-based design criteria. The new LRFD-based design criteria are expected to provide an alternative method to designers, owners and operators, who can choose their preferred design approach that meets the local national requirements and better utilizes their experience and resources.

Objective Traditionally, over the decades majority of offshore oil and gas operating companies (OPCOs) have managed their electrical power demand independently using localized open cycle gas turbine generators. With the declining reservoir plateau, adoption of new reservoir development techniques for sustained production, calls for increase in power demand (from few hundreds of megawatts to few thousands of megawatts). Alternative means of safe, reliable, environmental friendly and economically viable solutions become inevitable. The objective of this paper is to share our experience, key challenges and benefits in developing a strategic power supply master plan for all offshore OPCO's. Approach, Methodology and Process As a first step, feasibility studies were carried out to identify alternative means of sourcing the power which shall cater for the long term power needs of all offshore oil and gas facilities and facilitate phasing out of aged GTGs. The following options of power supply were considered for evaluation: Continue localized gas turbine generation (Business as usual)Renewables (solar, wind, tidal)Formation of power clusters by interlinking facilities and Centralized offshore generationPower from onshore Considering the order of power demand at each location, large infrastructure requirements at offshore where space is a premium and high cost localized, gas turbine generation and renewable energy resources were not considered as an optimal solution for long term offshore power supply for oil and gas facilities. Other alternative schemes of long term offshore power supply were evaluated. Offshore facilities were interconnected by subsea cables to form power clusters based on geographical proximity. Each power cluster shall have a centralized power hub which could be located on a natural island or on a platform. One latest trend is to build artificial islands in shallow waters for this purpose. Cluster power demand and distance from shore are drivers in techno-economic evaluation. Extensive feasibility studies followed by techno-economic screening shall be undertaken to develop a strategic master plan for phased implementation. As the power demand approaches the order of gigawatts, HVDC systems become more attractive. While offshore HVDC network interconnecting onshore source and centralized power hubs serve as the backbone, the HVAC network facilitates power distribution up to individual facilities (rated in megawatts). Novelty. Considering the consequences of production loss due to power outage, stringent reliability requirements were adopted which calls for multiple interconnections. This necessitates forming HVDC grids offshore. Use of redundant bipole converter stations at each power hub in order to effectively utilize the inherent reliability of bipole configuration is first of its kind for this order of magnitude. Phased implementation of redundant bipole converter stations by installing monopole configuration initially and converting it to bipole configuration at a later stage, provides maximum flexibility and defers the investments, thereby making HVDC option more attractive. Implementation of offshore HVDC grid for offshore oil and gas facilities mandates unique expertise of both offshore OPCOs and onshore utility power companies. Observations and Conclusions. Aggressive growth in power demand is imminent for Offshore Oil and Gas Companies to meet their business objectives and to implement state of art technologies. Interlinked grid operation of HVDC system necessitates the enhancement of HVDC breaker technology International standards are required to facilitate the seamless integration of HVDC systems by various original equipment manufacturers

Abstract With the rapid development of computing and mapping software, meteorologists are able to create graphical marine weather forecasts to provide drilling operations a better picture of the weather windows for their operations. By being able to combine satellite, radar, operation locations, wind and wave forecasts onto one map, the operator has a quick overview of the weather's impacts on his/her operations. Global models are now available every 6 hours giving various forecasts of winds and waves out to 15 days. This information can be used to have a preliminary view of what weather one could encounter for support vessels or for weather sensitive operations. Examples of weather in the North Sea, Gulf of Alaska, and Gulf of Mexico will be given to show how technology has changed and how the meteorologists communicate the weather to the oil and gas industry.

Abstract In the ongoing process of the offshore industry to improve safety aspects of drilling operations, ABS continues to provide support by developing enhanced safety requirements. This paper addresses the latest research that ABS performed to enhance its understanding of critical safety aspects in drilling operations and subsequent utilization of the results in updating the ABS Guide for the Classification of Drilling Systems (ABS CDS Guide). Several U.S. government regulatory initiatives have been implemented relative to offshore drilling operational safety. Other governmental regulators have also taken a similar approach in assessing their existing regulations with the focus on safety improvements. In parallel, the revised ABS CDS Guide provides updated safety requirements to assist industry to (1) improve overall safety in drilling operations and (2) meet regulatory compliance for the drilling systems. ABS commenced the criteria revision process with a gap-analysis between the existing offshore drilling practices and technology (including deepwater), applicable U.S. and worldwide regulations, recognized industry codes and standards, etc. Additionally, a survey was conducted with manufacturers, operators, and drilling contractors to identify main areas where the safety aspect of drilling operation could be improved. Based on the research and survey, industry's participation was a critical element in the rule making process - it provided insight into various safety issues, concerns in drilling operations and improved understanding between the industry and the regulators or Class society. From this process, ABS was able to develop additional measures to enhance existing criteria for drilling operations, while adopting a holistic approach to the classification process of drilling systems and equipment with consideration to the applicable regulatory initiatives. This paper outlines the currently developing regulatory changes to the U.S. drilling industry that may potentially impact worldwide drilling activities. This paper highlights the new safety requirements from our research and from the U.S. regulatory perspective, including: BOP recertification, maintenance, and testing, API RP 53 rewrite to API Spec 53 for adoption into the U.S. CFR, management of safety and environmental systems of API RP 75, safety case initiatives and the role of third-party certification. This paper discusses the adoption of a performance-based standard for offshore drilling operations in conjunction with the current prescriptive regulatory regime. Introduction Historically, incidents often lead to reforms and/or revisions of existing regulations and standards. In the U.S., the blowout on the Platform A-21 in the Santa Barbara Channel in January 1969 resulted in a large oil spill. Reforms from the Platform A-21 incident resulted in the passage of the National Environmental Policy Act (NEPA). In July 1988, the accident on Piper Alpha, in the UK sector of the North Sea, led to significant changes to the North Sea safety procedures, with enforcement of these changes delegated to the United Kingdom Health and Safety Executive (UK HSE). Similarly, the Macondo incident in the U.S. resulted in a range of reforms to the U.S. regulatory scheme for the offshore drilling industry. The offshore drilling industry has also taken the initiative to revise and update existing recommended practices, codes and standards associated with offshore drilling operations. ABS recognizes that there is a need to assist the offshore industry by developing enhanced criteria which can lead to improved safety aspects of drilling operations. As the offshore industry seeks the development of hydrocarbon reserves in deeper water and harsher environments through advancements in offshore technology, ABS also recognizes the need to maintain our Rules with the main intent of providing for the safety and security of life, property and the natural environment.

Abstract This paper presents an overview of available standards and recommended practices concerning station keeping with synthetic fiber ropes. The coherence between documents is presented, and an overview is given for where to find the specific information that may be needed throughout a project from the perspective of owner/operator, contractor or equipment manufacturer. An overview is given of recent document changes, and what will be published in 2011. The paper explains how findings from joint industry projects and other research efforts are incorporated. Det Norske Veritas (DNV) has recently updated its offshore codes in the form of rules, standards and recommended practices related to offshore mooring. The recent updates have different implications for drilling units moored for periods of less than 5 years, and for floating production units that keep position permanently for a duration that can extend anywhere between 5 - 30 years. Fiber ropes behave very differently to steel ropes or chain when subjected to mean and dynamic loads due to varying stiffness characteristics and time-dependent behavior. The documents now reflect that failure modes and mechanisms differ from those of mooring-equipment made from steel. Continuous development of standards and recommended practices is considered a key contribution to the available tools and methods for design, testing and analysis of offshore mooring fiber ropes. Since late 1990s comprehensive work has been undertaken in the area of offshore mooring systems including fiber rope material. Ever since synthetic fiber ropes have been found as a viable option for offshore mooring applications, there has been a considerable interest in understanding the behavior of fiber ropes to meet the challenges of the future. As the number of fiber-rope based mooring system continually increases, the need for standards and practices will continue to develop. Introduction Working with components for position mooring systems under the auspices of Det Norske Veritas (DNV), there are several documents available. The types of documents are organized according to information category such that the information will be easy to find. This paper is presented in order to provide a convenient overview, and to highlight some particulars of the DNV documents that might differ from other standards and guidelines. New elements in the most recent issues are also discussed, together with foreseen development of the documents. The arrangement of the DNV documents For each global topic, the documents are divided into the following main types:Offshore Service Specification (OSS)Offshore Standard (OS)Recommended Practices (RP) The Service Specifications, Standards and Recommended Practices issued by DNV can be obtained free-of-charge on the following link: http://www.dnv.com/resources/rules_standards. A brief explanation to each of the following document categories is presented in the following. Figure 1 illustrates how the document categories cohere through serving an explicit purpose for each information category. The Offshore Service Specifications contain procedural requirements for obtaining and retaining class certificates and other conformity statements for offshore vessels.

Abstract This paper presents an overview of the offshore construction insurance market, their perception of offshore risk, and the consequential impact that this has on project insurance terms and conditions, and economics. The purpose of the paper is to provide project teams with an understanding of the key issues and concerns within the insurance industry hat could negatively impact the implementation of a project insurance program or risk management strategy. The paper will focus on the advantages of project differentiation through detailed technical evaluation of project risk features, including new technologies. This paper will discuss the merits of risk engineering & risk appraisal and debate it's effectiveness as a mechanism to counter any inherent prejudices that may exist within the insurance market towards certain projects characteristics or those projects with unfamiliar risk profiles. This process has been further adapted to address the challenges and contractual relationships inherent to decommissioning risks. By way of introduction this paper will address the following points:An overview of the 2006 / 2007 offshore construction insurance market.A guide to insurance marketing strategyAn emphasis upon high quality technical underwriting informationRisk evaluation and risk appraisal.Risk RankingRisks and Mitigants: Some concerns of Insurers and the benefits of the Risk AppraisalDecommissioning: potential key risks and threats, and our recommended approach for the management of these risks and the typical insurance market offeringReputation protection. Conclusion: If the result of a bid, project approval or project economics is dependant upon a successful risk and insurance solution this paper provides very relevant debate. Insurance Market Overview There was a period of significant turbulence in the insurance market at the end of 2005/early 2006, and insurance rates hardened across all lines of Energy business in response to the natural hazard events in the Gulf of Mexico of 2005. However, what we have seen over the second half of 2006 and continuing in 2007 is a revived appetite for offshore construction business as good underwriting returns continue for the class of business. This is especially the case for those projects from a well respected Operator who has appointed what the insurance market perceives as experienced, well recognized contractors; At the current time, the construction market can be summarised as follows:A stable market with a wide choice of leadership and consensus on pricing;Rating levels stable but with a marked softening now being seen for most projects with underwriters having a "hunger" for premium income;However a more conservative approach is seen in relation to projects with higher contract values, with application of new or complex technology and or in deepwater, environmentally sensitive or frontier regionsRate reductions from what could be called the "market average" can be negotiated, even on projects with a higher risk profile, when the projects are successfully differentiated by high quality technical underwriting information/presentations to underwritersA move towards lower deductibles across the different project phases, i.e. procurement, fabrication, offshore transits and installation.

Abstract On large diversified projects, it can be very difficult to get the various project stakeholders (i.e. departments, regional offices, owner representatives, engineering firms, contractors, and vendors) to use a "common language" to discuss project deliverables. As one of the first steps in implementing a common project language for a major worldwide offshore contractor, the authors facilitated and lead a corporate committee that developed and implemented a common Work Breakdown Structure (WBS) for all engineering, fabrication, and marine work performed at company facilities located around the world. The standard WBS has become the unifying element that ties the company operations, accounting, scheduling, and material management systems into a single project management system. Major benefits realized include reduced project management costs, tying together of cost and schedule management, and the ability to roll up cost and schedule performance for reporting purposes while retaining the capability to "drill down" to lower levels to determine the root source of project variances. Introduction As the quest for oil and gas drives the industry into deeper and deeper waters, the complexity and risks associated with offshore projects has increased dramatically over the last twenty years. In the late 1970's, a thousand-foot jacket and accompanying decks were considered the frontier of offshore development; today delivery systems for acreage in 10,000 feet of water are being developed that require new floating, subsea, riser, platform, and market delivery systems. To deliver these types of projects, a contractor must be able to assemble and coordinate a team for engineering, fabrication, and marine scopes of work. In addition, major specialty contractors, engineering consulting firms, and key vendors must be integrated seamlessly into a cohesive whole that is focused on delivering quality project deliverables at a competitive cost. Other key project stakeholders including owner representatives and regulating agencies must also be integrated into the team so that the finished project meets the needs of its owners and satisfies government regulations. Given the technical complexity of the project scopes and the communication challenges presented by such a diverse array of project participants, the contractor's project management group is faced with the dilemma of how to describe the project in terms that everyone from the corporate shareholder to the field worker can comprehend. The project management group must also develop budgets, report progress, and track actual costs for the described elements of the project. As Figure 1 (by Resource), Figure 2 (by System), Figure 3 (Traditional Accounting Breakdown), and Figure 4 (WBS) demonstrate, there are several ways of describing the project scope. In companies with regional offices, some offices may choose to report using Figure 3 while other offices may use Figure 4 to describe their portions of the same project. Which is the "best way" or the best practice for the contractor to identify and report on project scope?

Abstract The Petrobras 40 is the result of the conversion of the former McDermond derrick barge DB100 into a semi-submersible production unit of 150.000 bpd oil production. The naval design of the unit has being carried out by PROJEMAR S.A. and the process plant design by IESA Engineering. FPSO Construction Inc is holding the conversion work at Jurong Shipyard in Singapore and the whole project managed by MarÍtima. Designed to operate in South-Marlin field - Campos Basin, offshore Brazil during 20 years, the Petrobras 40 will be moored in 1080 m of water depth by a passive 16 lines chain-polyester-chain taut-leg mooring system. The Unit was planned to be installed in February 2000 and is now scheduled to be in the field by the middle of the year. This paper describes the work performed for the complete design of the mooring system. The initial design concept, the model tests performed at MARINTEK model basin, the optimization of the system based on model tests results and offshore installation considerations, the final mooring analysis and the offshore installation procedures are presented. The modifications in the initial concept due to the design evolution are discussed and the offshore experience used to evaluate the design basis. Introduction The intent of this paper is to describe the mooring system design from the initial design concept to the offshore installation that has been carried out for the semi-submersible unit Petrobras 40. The platform was designed to operate at South Marlim Field - Campos Basin - Offshore Brazil with a peak production of 150,000 barrel of oil per day. The average water depth at the location is 1080 m. The mooring system is a passive taut-leg system composed of 16 chain-polyester-chain lines designed for 20-years of life in the location. The system was designed according to API RP 2SK as a permanent mooring system. Site environmental conditions were specified for the design based on Metocean Data obtained by Petrobras. Offshore operational procedures for the mooring legs installation and platform hook-up have been developed to be carried out by an installation contractor. Mooring System Design Strategy The mooring system design strategy adopted for the P40 project was based in a methodology that divided the design in two distinct phases: Phase One, or initial design, carried out in order to provide data for the tank model tests and Phase Two, or final design, carried out after the tests. The two phases are divided by the tank model tests, and can be summarized on the following : Phase One: Pre-dimensioning: The objective of this phase was the dimensioning of the mooring system to be tested in the tank tests. Additionally it provided the initial data to be used on the technical specifications of the on-vessel and off-vessel mooring system components, that initialized the procurement process of these equipment. Phase one had the following steps:General Arrangement DefinitionWind Tunnel Model TestsMotion AnalysisStatic Riser AnalysisInitial Mooring System DesignComputer Simulations of Tank Test ConditionsTank Model Test

Abstract Offshore construction vessels are a special breed that differs substantiallyfrom conventional cargo ships. Although these offshore units have some physicalsimilarities with passenger ships, the nature of their construction andoperation is quite different. Therefore, offshore construction vessels should not be subjected to the samerange of stability requirements as passenger vessels. Application of SOLASpassenger ship type stability regulations for a construction vessel in intactand damaged condition may well lead to a G'M requirement that causes anunfavourable motion response. This does not serve the purpose of enhancing thesafety of crew and vessel at sea. Stability requirements based on the IMO MODUCode, such as HSE and NMD, are deemed more appropriate to offshore constructioncraft than SOLAS. The assumed extent of damage prescribed in stability regulations oftengoverns the watertight subdivision. The internal arrangement of cargo spacesand tanks, however, should also satisfy operational requirements. In thepresent design practice one is obliged to run many optimisation loops ofdeterministic stability calculations, with the sole purpose of achievingcompliance of the unit's subdivision with all the specific criteriaimposed. If one subjects one and the same watertight subdivision to many differentrequirements, this leads to closer spacing of transverse bulkheads. Safety isnot served with this, since each of the penetrations and closing appliances ofthese extra bulkheads introduces additional flooding risks. The rigorousapplication of extreme stability requirements during short periods ofcontrolled offshore operations may be debated. Offshore vessels are weight critical, in terms of payload and compliance tostability requirements. Therefore, an accurate weight estimate should beavailable at an early stage of the design, and weight control should beexercised throughout construction. Frequent verification of the weight controlprogress through a displacement test is recommended. It may be wise to allowfor operational contingencies on the lightweight and its vertical centre ofgravity. Offshore craft tend to grow at deckhouse level during theiroperational lifetime. Whenever there is a small discrepancy between alightweight calculation and the lightweight as deduced from a measureddisplacement, most Authorities require that a full inclining experiment needsto be redone.

ADSTRACT Since early 1980, Technip-Geoproduction (TPG), as designer or as installation contractor, has been using with success the float over system "UNIDECK-TPG" for the transportation and installation of integrated decks for offshore platforms. The concept offers the advantages of significant savings in transportation and installation cost by minimizing the installation time and offshore hook-up and eliminating the need for a heavy Lift derrick barge. The paper describes the technology used for the installation, the required engineering studies, the consequences of using such a concept on platform design and the selection of an appropriate barge size to be used. INTRODUCTION TPG has developed the integrated deck concept, called UNIDECK-TPG, with the objective at minimizing the overall cost by offering the advantage of having a deck which can be installed on a jacket as a single unit, filly completed and tested without using a conventional crane barge. The concept has been successfully used several times in both favorable and more severe sea conditions with deck weight ranging from 2,500 to 9,500 metric tons. The technology combines ballasting and jacking to improve the stability of the cargo barge during the transportations phase and by jacking to provide a safe and quick transfer of the deck weight onto the pre-installed jacket. After having designed platforms in shallow waters as jack-up, this method was used first by TPG for (Fig. 1) :KOC Southern Gas Project (in early [980),the Ethylene Offshore Terminal in Egypt for EGPC (2,300 tons),the relocation of Zakurn Accommodation Platform (7,000 tons) for ADMA OPCOthe ADNOC Khuff Gas Production Platform (2,500 tons), and recently for :" the North Field Qatargas Process and Utilities Platform (7,500 tons),the COB-PI Production Platform, for Sonangol and for Elf Exploration Angola (9,500 tons) for which TPG acted as general contractor. The deck has been installed early 1996 with 1.2 m significant wave height. This is the first time that such installation method has been used in the long swell of south Atlantic Ocean. The UNIDECK-TPG method is applicable to three main categories :in shallow water where there is not sufficient draft for a derrick barge to enter the site," when heavy lift derrick barges are not readily available resulting in a prohibitive mobilization cost,when an integrated deck would be too heavy for existing derrick barge. In each case, the installation method can be adapted to the environmental conditions and to the weight and final elevation of the deck so as to minimize the cost of the operation.

ASTRACT Giant deepwater oilfields had been discovered in Campos Basin, offshore Brazil, through the eighties. After overcoming initial problems while drilling the exploratory wells, appraisal wells were drilled under regular performance standards, comparing to shallow water previous data. At that time, Albacora and Marlim field development plans were considering improved performances to occur due to the expected learning effects. The combination of the simultaneous use of dynamic positioned and deep anchored rigs with the technical improvements in well operations resulted in an outstanding overall drilling performance for the development campaign of those fields. The drilling program was concluded well ahead of schedule, establishing guidelines for future deepwater field exploitation. This paper describes Petrobras experience of planning and drilling deepwater development wells, showing the principal measures and factors that led to an update of our operational standards. Also, the ultra deepwater drilling R&D projects carried out at the moment are briefly introduced, being their aims to keep or even improve our performance and safety records as water depths up to 2,000 m are considered for oilfield developments offshore Brazil in the future. INTRODUCTION In late 1984, Petrobras started drilling the so-called deepwater wells, beyond 400 m water depth, in the Campos Basin area (figure 1), located at Rio de Janeiro State, using dynamic positioned (DP) drill ship. The first wells had striked the Marlim field and confirmed the extension of Albacora field into deeper waters. The Marlim field is located 100 km off the coast, in the eastern part of Campos Basin. Total reserves are estimated to be 1.5 billion barrels of oil in an area of 132 sq. km, straddling from 600 to 1,050 m water depth. The pilot system is composed of 10 wells, already producing 50,000 bopd to a stationary production unit (SPU). The Phase I of the field development is divided in two modules; current module 1 consists of 28 wells, being 16 production and 12 injection wells. From this total, 26 wells had been drilled and 9 wells had been completed so far. The module 1 SPU, Petrobras XVIII, has been installed at 910 m water depth, setting a new world record of stationary production unit anchoring. The Albacora field is located 107 km off the coast, in the northeastern part of Campos Basin. Total reserves are estimated to be 640 million barrels of oil in water depths varying from 230 to 2,000 m. Development Phase I consisted of 16 wells, already producing to a stationary producing unit, Petrobras XXIV. As in the Marlim field, Albacora field Phase II is also divided in two modules; current module 1 consists of 28 wells, where 22 wells had been drilled and 9 wells had been completed up to the tubing hanger so far. Seven years elapsed before the decision of developing both fields was finally taken. During this period of time, 59 wells were drilled with DP rigs up to 1,565 m water depth and other 26 wells were drilled using moored rigs up to 600 m water depth, mainly in Campos Basin area.

ABSTRACT Shallow caisson foundations are considered as alternative anchors for permanent mooring of a process barge at an oil and gas field developed by ELF Congo in the Gulf of Guinea. The 12 mooring lines are scheduled to be installed on site in July 1995 and the process barge will be connected in 1996 for start of production. b14tha water depth of about 170m, this field will be the deepest one offshore Western Africa to date. The soils at the site consist of soft normally consolidated clays. The paper presents the results of a comparative study of potential anchor solutions for this production barge, including high capacity drag anchors, driven piles, and shallow caisson foundations installed by under pressure. This comparative study, including design, construction, and installation of the mooring system, has shown that the caisson foundations represent the best suited solution, technically as well as on an economical point of view, because of the following advantages:vertical load capability, thus allowing to reduce the anchoring pattern,oncepositioned on the seabed, the location of each anchor is fixed and known with accuracy, andmore simple and shorter installation procedure, since caisson anchors, as piles, do not require to be proof-loaded on site. INTRODUCTION With oil exploration wells and development of offshore fields coming into deeper water depths, innovative concepts of structures and foundations are considered, with the aim to develop alternative solutions that can yield cost savings, but with similar or improved reliability. The NKossa oil and gas field presently developed by ELF Congo in 170m of water depth will be the deepest field in the Gulf of Guinea to date. It includes two steel jackets (installed early 1995) with tender-assisted drilling, one process and accommodation barge (presently under construction and scheduled to be at the site in 1996 for start of production), and two floating storage and offloading tankers, one for oil and one for LPG (see Figs. 1 and 2). The present paper gives the results of a comparative study on potential anchor solutions forpermanent mooring of the process barge, including high capacity drag anchors, driven piles, and shallow cylindrical steel caissons. The shallow caisson foundations, penetrated into the seabed by means of under pressure in the water inside the caisson (also called "buckets", "skirted foundations" or "suction anchors" in the literature), were first introduced by Senpere and Auvergne (1) as alternative anchors for mooring of a storage tanker at the Germ field offshore Denmark. More recently, and due to its simplicity and reliability, this foundation concept has found a renewed interest in the offshore industry. The geotechnical analysis of skirted foundations is based on the experience gained from large North Sea gravity structures. Model tests have been performed in clays by the NGI for application to the Snorre TLP (Dyvik et al, 2; Andersen et al, 3), as well as for studying the performance of anchors under horizontal loading (Keaveny et al, 4). Since then, it has been applied for different types of structures.

ABSTRACT The integrated design process for offshore developments utilizing the design spiral concept is discussed. Methodologies for reaching decisions in a systematic way and that can deal with the choice amongst competing alternatives, while considering a variety of criteria that range from economic and technical feasibility to performance are addressed. A low cost production system utilizing a contract platform and pipeline is discussed. Reliability based design methods are identified as a means of rationally designing ocean structures by balancing the consequence of failure against design and construction costs. The impact on future of engineering in the oceans is examined. It is recognized that economics rather than technology will set the pace and direction for engineering development in the ocean. A major conclusion is that the challenge to our industry is the internationalization process of developing reliability based design standards that show potential to reduce the life cycle costs of offshore development. It also is noted that to regain the technological edge that the US oil industry once had will require the coordinated efforts of the educational system, the government, private industry, and most importantly, we, the individual engineers that can make it happen. Mandating of continuing education as a licensing requirement, and its inclusion in the accreditation process, is a real possibility and seen as a positive move. INTRODUCTION The offshore industry, most notably the petroleum sector, has faced a challenge to move into deepwater for several decades. There have been numerous milestones along the way, and recent technology has extended the capability to produce from compliant platforms. Conoco's Jolliet Tension Leg Well Platform (TLWP), operating in nearly 2000 feet of water in the Gulf of Mexico, is a prime example (Birrell 1991). The Auger TLP installed in 2860ft GOM during Dec. '93 and scheduled for production early this year, is another good example (Snyder 1994). With the continued pressure on the industry to eliminate jobs in the face of low prices, environmental costs and government restrictions on exploration and production in this country, (Mitchell 1992) our challenge as engineers is to reduce costs through implementation of innovative technology and better design. During the 1980's, politics and economics led to a greater reliance on the market to manage energy trade. Deregulation and greater price sensitivity have resulted in markets that are more responsive to changes in supply and demand. This was clearly demonstrated during the 1990-91 Persian Gulf crisis, when prices rose rapidly following the loss of Iraqi and Kuwaiti supplies, but quickly returned to equilibrium once uncertainty over future oil supplies was reduced. As this crisis reminded us, the risk of oil price shocks remains, and such shocks can significantly impact economic growth and the need for new technology. Middle Eastern politics have been the major source of post-World War II price shocks, and international political events will continue to have the greatest potential to destabilize oil markets.

ABSTRACT This paper provides an overview of the offshore portion of the Mobile Bay Project, including a review of the installation methods used. Also included is a discussion of the key focus areas and program elements of the safety process implemented during the Project. The unique aspects of the Project led the Owner to use a different approach to managing the work for a Gulf of Mexico installation. The Owner assembled and led a team of many contractors to plan and complete the multifaceted scope. Most of the work was done on a reimbursable cost basis which allowed the Owner to be highly involved in selecting contractor personnel and equipment, in developing the detailed work plans, and in making the day-to-day decisions during the installation. This approach resulted in a successful installation which met all Project requirements including achieving outstanding safety performance. OFFSHORE OVERVIEW Facilities General The Mobile Bay Project is the world's largest offshore sour gas development. Located near the entrance to Mobile Bay, Alabama, the development consists of three fields; the Bon Secour Bay field inside the bay and the Northwest Gulf and North Central Gulf fields just outside the bay in the Gulf of Mexico (Figure 1). In the bay the water is relatively protected and shallow, 13 feet or less, with a muddy bottom. Offshore the fields are in waters up to 50 feet deep with a sandy bottom. The current is strong at the mouth of the bay, swells are typically found in the area, and ten foot seas are not uncommon in storms. The offshore work was done under rigid environmental stipulations that required all discharges to be collected and barged for offshore disposal. Additional measures were needed to prevent silting of the numerous oyster beds in the area. There are currently eleven wells with shut in pressures as high as 10,600 psi and with flowing temperatures of 300 degrees Fahrenheit. The produced gas ranges from 10% H2S in one of the Bon Secour Bay wells to only 50 ppm H2S in the North Central Gulf Field. Production Platforms Within each field, produced gas from the wells flows through flowlines to a production platform for separation and dehydration. Each of the three platforms is an eight-pile structure supporting a one and a half level deck with the largest measuring 210 feet × 120 feet. The decks were outfitted as a single unit with total weights ranging from 3,700 tons to 4,800 tons. A separate 42 person living quarters platform is bridge-connected to the Northwest Gulf platform. Well Templates Each production platform has a separate bridge-connected template for one or more producing wells. There are also five remote well templates, for a total of eight, with the furthest being about 4 miles from the production platform. The templates are 50 feet × 60 feet single-level decks supported by three-legged structures with the well conductor acting as one of the support legs.

ABSTRACT The Ninian Field, operated by Chevron on behalf of the Ninian Field Group, is a mature North Sea producer. Rationalisation of the topside facilities and declining production rates had left spare equipment and capacity in the Platform production systems. This spare capacity coupled with Ninian's strategic location in the Northern North Sea made it an ideal candidate for tie-in of subsea fields. Staffa, Lyell and Strathspey, operated by Lasmo, Conoco and Texaco respectively, are three such third party subsea developments using Ninian topside facilities. The Ninian Third Party Project is unique since it is the first offshore development where three third party operated subsea fields are processed by another operator and developed within the same timescale. In addition, major topside modifications were performed while Ninian continued to operate. Through sharing the lessons learned by Chevron as operator and manager of the Third Party Project, others will benefit in improved efficiency, planning and organisation for similar future endeavors. The impacts of managing a major project (over 3 million offshore construction manhours) with an existing operations infrastructure, interfaces with Third Party Entrants, safety, productivity and efficiency results are among the issues which will be addressed. INTRODUCTION The Ninian Field is located some 110 miles North East of the Shetland Islands within Blocks 3/3 and 3/8 in the area commonly known as the East Shetland Basin. The Ninian Field maintains a strategic position in the Basin. The field was discovered in February 1974 and began production in December 1978. With an estimated 3 billion barrels of oil in place, the field is expected to recover 1.2 billion barrels of oil producing well into the next century. The field was developed using three platforms, the giant concrete Ninian Central and the two conventional steel structures of Southern and Northern. Oil export from Ninian is via a 36" pipeline to the largest terminal in Europe - Sullom Voe located 110 miles away on the main island of the Shetlands. Oil from Ninian Southern is pumped up and over Central through a manifold to the 36" export line. Ninian Central also acts as a hub gathering production from Unocal's Heather Field, BP's Magnus Field and Total's Alwyn North Field. Since their initial construction, all three platforms have received regular updates to their production systems. On Ninian Southern and Central Platforms the original two train, three vessel production separator systems have been optimised to single train, two vessel operation, leaving redundant production vessels in place. Also on Ninian Southern Platform in response to Ninian's declining production and reduction in associated fuel gas availability the LPG recovery plant was decommissioned. For these, and other reasons, Ninian Southern and Central Platforms were best suited for host satellite developments.

ABSTRACT The Shell U.K. Exploration and Production (Shell/Esso) Underwater Manifold Centre (UMC), a development which extended the frontiers of subsea technology, was installed in 1982 in the Central Cormorant Field and has now been in operation for more than 10years. It has been a profitable system with an excellent availability record. A number of operational experience topics, considered unique for Central Cormorant, are presented in this paper. INTRODUCTION This paper describes the operational experience with the Central Cormorant subsea facilities with emphasis on the period post 1986 (A review up to 1986 has been presented in paper OTC 5314). The reference date for this paper is 31 December 1993. After a system overview, several reservoir management aspects are discussed including the role of the TFL system. Well maintenance and some events requiring substantial DSV intervention are described, followed by a final remark and an overall conclusion. SYSTEM OVERVIEW The Cormorant Field (See Fig. 1) is located in the Northern North Sea, approximately 150 km North East of Shetland. It extends over 25 km North - South, and consists of four individual fault blocks. Expected ultimate recovery is 607 MMstb. The nine well Underwater Manifold Centre (UMC), installed in 1982, is located between the two fixed production platforms, Cormorant-A and North Cormorant, in 150 m water depth. Its purpose is to produce the 130 MMstb of reserves in Block 1, which was considered outside the reach of both platforms. The Central Cormorant Underwater Production System (See Fig. 2) also included a single satellite well known as "PI" which produced directly into the Cormorant-A platform. P1 incorporated the same level of technology as the UMC and as such was used as a pilot scheme to prove the numerous innovative components and techniques included in the UMC design. The success of P1 was a key factor in the decision to install the UMC. Production from P1 commenced in January 1981 and after more than ten year in service without any workovers, a leak developed in the downhole completion. As the remaining reservoir could now be accessed utilising extended reach drilling from the platform, it was decided in 1991 to abandon P1. During its period in operation, PI produced 17.5 MMstb of oil. The UMC (See Fig. 3) is designed for four basic functions:to collect fluids from subsea completed wells and deliver these to the Cormorant-A platformto distribute treated seawater, pumped from the platform, to water injection wellsto provide a template for drilling, and to connect and service satellite wells drilled at locations remote from the templateto permit servicing of all wells using the Through FlowLine (TFL) system. The UMC has considerable system and component flexibility and redundancy. The structure supports a total of nine wells (although more are possible with modifications), which may be drilled as template or satellite, and configured as either water injector or oil producer.

ABSTRACT In order to bring into production Brazilian most prolific offshore fields, all of them situated in water depths beyond 400 m, Petrobras, the Brazilian Oil Company, has developed a simple, reliable and cost effective Guidelineless Wet Christmas Tree, designed for applications up to 1,000 m (3,281 ft) water depth]. After installing 16 such trees in Campos Basin, at a maximum depth of 781 m (2,562 ft), the Company faces the challenge of putting onstream Marlirn-4, a well at 1,027 m (3,370 ft) water depth, in the south area of the Marlim Complex. In addition to its strategic role in the Company's endeavor to produce from increasingly deep waters, Marlim-4 will also establish a new world record for subsea completions. This paper presents a brief summary of Marlim's development plan and describes the activities programmed for Marlim-4' s completion. INTRODUCTION Since the first oil strike in Campos Basin, back in 1974, Petrobras has been setting several milestones in the Offshore Industry, developing new production system concepts and improving subsea equipment design. Every achievement attained through these years was based on four major principles: careful planning, feedback from field experience, intensive research and courage to take risks. As exploratory work went on, hydrocarbons accumulations were discovered in waters deeper than ever before, pointing out the necessity to upgrade the available technology to produce the newly-found areas. From 1984 on, giant fields, such as Albacora and Marlim, were spotted in ultra-deep waters, representing a challenge harder than the previous ones. To cope with the difficulties of the new enterprise a step by step development plot has been chosen, aiming to get technological capability for fill recovery of the existing reserves, placed in water depths ranging from 400 m (1,312 fl) to 1,000 m (3,281 ft). Looking back at the outstanding success accomplished in the last years, one can easily confirm that this was the right strategy to be followed: 219 WCTS have already been installed in Brazilian's continental shelf and technology to produce wells up to 1,000 m (3,281 ft) is completely dominated, despite the capital constraints suffered by the Company. Nowadays, an outlook of the two most important offshore provinces in Brazil, Santos and Campos Basins, shows that the future lies in waters even deeper, what imposes the need for another strategy to be defined in order to reach anew target. The experience gained during the development of the Marlim Pilot System has showed that the installation of an early Floating Production System pays, even in deep waters. It is a good manner to pave the way to master new technologies, anticipating oil and gas production and collecting reservoir data that can help to minimize the uncertainties related to geological aspects and production mechanisms, thus increasing the chances of success and decreasing the risks involved.

ABSTRACT Subsea technology has proved itself as an alternative for marginal or deep water field developments. This paper will describe six years of operational experience on the Albacora field, an important subsea development project being carried out offshore Brazil. Main results and major difficulties encountered during this period will be discussed in the text. INTRODUCTION Albacora is one of the last decade discovered deep water giant fields, located at Campos Basin, offshore Brazil. Being explorated since 1968, Campos Basin became the main petroleum province in Brazil. Ranging from shore to 3,400 m WD, with a total area of 110,000 Km2 its total proved reserves, in WD u; to 1,000 m, reaches 2.78 X 109 barrels of oil and 58.2 × 109 std m3 of gas, 16 % of this being located in the Albacora field (Fig. 1). In 1984, with the wiIdcat well 1RJS297, drilled at 293 m WD, the Albacora field was discovered. Further efforts led to the knowledge of the field's full extension, which is presently accepted as covering an area of nearly 235 Km2. Since this first discovery and the following successes in Marlin field, the basin development strategies had been reviewed to attain those new chal Ienges in deep waters. GEOLOGY OF THE ALBACORA FIELD The Albacora field is located nearly 110 Km from the coast, in water depths varying from 230 to 1600 m. Its main oil occurrences are found in the Tertiary / oligocene, Eocene and Miocene sandstones (Campos/Carapebus) and in the Cretaceous/Albian sandstones (Macae/Namorado), all of turbiditic origin (Fig.2). A total of eight different oil reservoirs ranges from 2350 to 3260 m TVD, with a significant variation in porosity, water saturation, oil gravity, etc2. Its proved reserves are of 0.455 × 109 barrels of 26/29 °API oil and 8.48 × 109 std m3 of gas. FIELD DEVELOPMENT MILESTONES To cope with geological and reservoir uncertainties, as well as technological limitations and budget requirements related to the deep water / giant field combination, it has been planned to develop the Albacora field by stages. Each stage provides reservoir data, technology field testing and early cash flow to support the following stages3,4,5. The project's milestones are listed bellow:1984 - Drilling of the well 1RJS297, discoverer of the field;1987 - Drilling and successful testing of the well 1RJS367 at 1565 m WD, a world record;1987 - Phase 1 (Pilot System) start-up: The Pilot System comprised 6 wells connected to a diver assisted subsea manifold, producing to a FPSO consisted of a tanker (P.P. Moraes) and a monobuoy in SBS configuration, at 230 m WD. This conception combines a CALM type monobuoy rigidly connected through a yoke to the tanker. OiI sales were conducted through the SBS monobuoy to a shuttle tanker tied to a second monobuoy.

ABSTRACT The Balmoral development constituted one of the largest subsea facilities at its time of commissioning in 1986 and included a purpose built floating production vessel (FPV). Experience gained over seven years in the operation of pipelines, risers, subsea controls, downhole pressure monitoring systems and other equipment are presented in this paper. INTRODUCTION The Balmoral field (Block 16/21) is located in the UK sector of the North Sea, some 140 miles NE of Aberdeen in a water depth of 145 metres. The field was discovered in 1975 and development drilling began in 1984 with production commencing in November 1986. The Balmoral facilities (fig 1) comprise the world's first purpose built floating production vessel (FPV) moored over a large subsea template accommodating ten subsea production wells, three manifolds and major components of the electrohydraulic control system. The FPV and template are connected by a system of flexible risers and a dynamic riser control umbilical. Ten template productions and nine satellite wells (three production, six water injection) tied back to the template were included in the initial project. At the time of commissioning, Balmoral was one of the largest subsea complexes in the North sea. Since then, three further Sun operated satellite developments have been linked into the Balmoral facilities Glamis (1989), Blair (1989) and Stirling (1993). Although Blair is now abandoned, the complex as a whole has included seventeen production and seven water injection wells. The inbuilt flexibility in the original Balmoral topside and subsea facilities has enabled these other fields to be included with relative ease and potential still exists for future tie-ins. In seven years of operation, Sun has gained invaluable experience in operating a floating/subsea complex, some of which have been detailed previously (ref 1-7). The Balmoral reservoir located approximately 7000 R below sea level was initially judged to have a STO11P of between 187 and 299 MMSTB of which 67 million were recoverable. These figures were based on the results of appraisal drilling and a 2-Dimensional seismic survey. By 1992, it was apparent that the reservoir was over performing and a reservoir simulation model indicated a revised STO11P of Up to 2S6 MMSTB with recoverable barrels of 100 million. In 1992, a 3-Dimensional seismic survey was conducted and the exercise has confirmed the recoverables at the revised figure of 100 million, but reduced the potential variation of STO11P to between 173 and 210 MMSTB. Recoverable reserves were raised by over 30% with the accuracy much improved so allowing better technical and financial assessment of field life and potential for future in-till wells. The Glamis field, located approximately 7 km south east of Balmoral, has proved to be a source of additional production and revenue. Coming on stream in 1989, this Jurassic accumulation was estimated to possess 17 MMSTB, since revised upwards to 21 MMSTB. An additional benefit is that the high GOR (1037 scf/stb) of the crude provided gas for the gas lifting of Balmoral wells which were experiencing decline in flow rate due to increased water cuts.

INTRODUCTION A tension leg platform was just recently installed in the Gulf of Mexico in almost 3000 feet of water. How did the industry get there? Possibly more significantly, how much deeper can we go, and when? I will try to answer the first question by reviewing the history of offshore operations, and I'll then make a stab at answering the other two questions. In addressing the first question, I will focus primarily on technical developments over the past 40+ years in several areas: knowledge of the environment, e.g., oceanography, hydrodynamics, meteorology, and to a less extent, seismicity; analysis; design; soil mechanics/ geotechnology; materials; construction; and instrumentation, testing and calibration. Of course, overshadowing all of these subjects is economics-the bottom line-but my emphasis will be on the technical areas. I will concentrate on steel drilling/production structures in the Gulf of Mexico and Offshore California, fully realizing that concrete structures have played and will play a significant role in deep water, certainly in the North Sea, and quite possibly in the Gulf of Mexico in the future. I have divided the fifty-year period somewhat notionally into five segments: The Beginnings; The Learning Curve; Maturity; Alternatives; The Future. THE BEGINNINGS One of the first offshore drilling operations took place in 1938 in 18 feet of water, about 1-1/2 miles offshore Texas, from a wooden deck platform supported by 100 timber piles, each 65 feet long. A long trestle to shore, supporting railroad tracks, supplied the platform. The first "permanent" steel platform (the timber platform noted above was severely damaged by a 1938 hurricane) was installed in 1947 offshore Louisiana in 20 feet of water. The platform employed six templates and was supported by 267 piles made of 8-inch and 10-inch pipe. The design and construction of such steel platforms were dictated by available sizes of structural members and by existing construction equipment (70-ton crane). Design wave height in 1947 was 32 feet, upped to 40 feet in 1949 when a hurricane hit the Texas Coast. Design wind velocity in 1949 was 125 miles/hour. Wave forces were calculated based upon a chart using solitary wave theory. The forces were less than 1/3 of those which would be used today. Foundation design was based upon a series of seven core tests, some taken to 400 feet, along the eastern Louisiana coast. Pile driveability tests were also conducted to 165 feet of penetration. By 1953, seventy steel platforms had been installed, the deepest in 70 feet of water. In 1955, a platform was installed in 100 feet of water, followed in 1959 by the installation of a 4-pile "minimum" platform in 204 feet of water. Major advances during this period were in the area of installation equipment. A 150-ton derrick barge specifically built for offshore use was available in 1950. By 1953, another barge of 250-ton capacity was in service. Platforms were lifted into place by the crane, not launched. If the platform weighed too much for one crane, two were used.

ABSTRACT The paper describes BP's subsea production projects on the Buchan, Magnus, Don, SWOPS and High Island fields and the operational experience and lessons learnt on these developments. It concludes with a summary of how BP will be meeting the future subsea challenges from past experience. BP'S ACHIEVEMENTS The BP involvement in subsea completion's started more than 12 years ago with the development of the Buchan oil field, and now there are some six separate producing developments world-wide (see figure 1). Four of these have what can be called "permanent" facilities, with the other two subsea completion's being accessed through BP's novel Swops vessel, the "Seillean". Buchan The Buchan oil field lies some 154 kilometres ENE of Aberdeen and 46 kilometres NW of BP's Forties field. Economic appraisal of the field with a complex and relatively small reservoir required a low-cost, fast track approach to the development. The development now has the following subsea components (see figures 2, 3 and 4):A floating oil production platform converted from a semi-submersible drilling rig installed in a water depth of 118 metres over a subsea template and manifold arrangement,There are five production wells drilled through a steel template, with four satellite wells, the furthest being some 2.5 kilometres from the platform, linked to the manifold by 4-inch rigid steel flowlines and associated hydraulic control umbilicals.A production/export riser system consisting of a single 12-inch export riser surrounded by nine 4-inch production risers and one 4-inch service riser. These nine production risers are clamped in tandem with 2-inch gas lift risers.Two wells have 2-inch flexible gas lift flowlines connected to them. This was the first time BP used flexible lines in the North Sea. Oil production began in May 1981, and various management improvements throughout the fields life have been undertaken. The Buchan floating production system has proved technically and commercially successful as a means of crude oil recovery from a marginal field such as the Buchan reservoir. Buchan was BP's first subsea production system and although there have been problems it has been a technical and commercial success which is still in production. The fundamentals of the design are based on similar systems with 1970's drilling technology, In particular the rigid riser system and controls would seem dated today but overall they have worked well albeit with a high maintenance cost and steep learning curve in the first few years. Particular issues have included:-DHSV failures, earlier flapper type valves were changed out for dual piston type.Tubing hanger orientation problems were overcome with improved tools.The manifold and tree valves were an early source of problems with numerous leaks, this led to an intensive and successful programme for improved materials, assembly procedures and QA.The direct hydraulics system has worked safely but is very cumbersome in the moonpool area. There have been substantial corrosion problems due to incorrect materials, poor QA and contaminated hydraulic fluid. This led to hydrate formation in the control lines.

ABSTRACT The Aquila project guidelines and actual results will be discussed in this paper. Drilling features (in particular the drilling information system and the drilling of the drain hole), the completion and the long production test using a tanker for storage will be discussed. The logistic and environmental problems associated with the mooring system, including the tanker, will also be covered. INTRODUCTION Deep water hydrocarbon reserves are considered one of the most promising frontiers for E&P activity in the near future. Technology, considered as a combination of innovator equipment and experience, will play a leading role in providing an economic and safe means of confronting the emerging deep water challenges. The southern Adriatic Sea is an area of high hydrocarbon potential in deep waters. This basin is located in water depth of 500-1000 m. The first investigation, dating back to the late Seventies gave encouraging results (fig. 1). However, the technology available at that time did not offer any acceptable technical and economical solutions in order to test the well on a viable way. With advances in deep water completion technology it has become possible to adequately manage environmental and safety constraints. The Aquila appraisal well was drilled in 820 m of water and an LPT was performed, using a last generation moored semisubmersible rig, assisted by a storage tanker. Facilities were designed to meet local regulations concerning environmental aspects and the sour gas content of the produced crude. The drilling activity was monitored in real time at the AGIP Ortona District and at the Company's headquarters in Milan through the in-house developed "Advanced information Drilling System" (ADIS). nother challenge was the development of a safe and reliable surface, storage and transport system in an area where weather conditions can become really severe. A project of such complexity required multidisciplinary tasks and the adoption of the most advanced technologies. Although technology concerning completion aspects can be considered as relatively new, it still requires careful evaluation for specific field application. Further studies on the implementation of subsea production equipment for water depths in excess of 800 m are in progress. SYSTEM DESCRIPTION AND GENERAL PREMISES A production test, consisting of continuous production from the Aquila drain hole, lasted 85 days. Testing equipment was installed on the same semisubmersible platform used for drilling. The produced and treated oil was conveyed from the semisubmersible through a flexible buoyant line to a storage tanker moored to the platform (fig. 2). CHARACTERISTICS OF THE SYSTEM Drilling rig. The FGL-1020 trendsetter R&B "Jack Bates" drilling rig was used. H was equipped with thrusters and a mooring system that allows safe mooring in water depth in excess of 1000 m, with 18 ¾"-15,000 psi multiplex BOP stack and a lower marine riser package (LMRP) quick reacting time (20 sec.). The platform was designed to work under particularly severe weather conditions and to allow "zero discharge".

ABSTRACT The rapid changes in information technology (Iv and its application have helped to improve efficiency and reduce operating costs offshore. Developments in IT itself, in terms of technology organization and standards together with cultural change have created new opportunities. In the application of IX the most significant impact on Operations costs and effectiveness has come from the use of information throughout the lifecycle, and improved telecommunications. This paper describes recent developments in IT and its application, and cites examples where oil companies have derived major benefits. INTRODUCTION There has been a widespread business imperative to reduce costs throughout the oil industry, driven to a large extent by the falling price of crude in real terms. These pressures have been particularly prevalent in North Sea Operations, with the development of smaller and increasingly marginal fields. Information Technology (IT) clearly plays a significant role in these calculations, both in terms of its intrinsic cost, and of its application in optimizing performance. IT costs have in the past, not always been understood by management, who have perceived them to be ever spiraling upwards and out of control: The more important issue is, however, getting value from the IT dollar and using IT for more effective Operations. This is of increasing significance with IT becoming an essential part of virtually all different functions including:Process ControlLogistics (including maintenance)EngineeringSafetyGeosciences and Drilling IT itself is changing rapidly to the customer's advantage in terms of:technologyorganizationservices, such as facilities managementsoftware productsstandard's Hence a strategy for reducing Operational costs through the effective use of IT must address the changes in the IT industry as well application within the business. as their relevant. DEVELOPMENTS WITHIN IT Cultural changes within the oil industry and technological and organizational changes within IT have had a direct impact on the service provided and the cost of that service. The oil majors are demonstrating a willingness to accept that their problems are not unique and to work together in partnership. For example, Chevron and Amerada Hess are developing an integrated maintenance, materials and purchasing package for the North Sea - which contrary to previous practices will also be available on the open market. Similarly Logica are developing a common Personnel Tracking System. Partnering arrangements are not only proceeding between Operators, but also with suppliers, who are now working together to produce "industry solutions" rather than selling hardware, proprietary software and other discrete options. In organisational terms, the requirement for IT is now predominantly driven by business advantage rather than technical novelty, although in practice the advice given tends to depend on the source, with traditional IT departments often unlikely to propose outsourcing, and software development firms to recommend packages. Nevertheless, recent radical measures include the outsourcing of complete departments - such as BPX contracting out accounting to Andersen Consulting - in addition to the traditional outsourcing of certain specialist IT services (eg disaster recovery or payroll).

ABSTRACT The use of duplex stainless steels Offshore has rapidly increased in recent years. At the same time the number of specifications for duplex stainless steel has also rapidly increased. This paper examines the requirements of these specifications, highlights conflicts and questions the need for certain tests. INTRODUCTION In recent years the use offshore of duplex (22%cbrmium) stainless steel and super duplex (25%chromium) Stainless steel has considerably increased. Their combination of increased Strength and corrosion resistance over austenitic grades, at a relatively low increase in C0st, has led to the materials being Specified for CO2, and H2S containing Process lines, where the high partial Pressure of CO2, precludes the use of carbon steel, and where high temperatures (>60°C)preludes the use of austenitic Stainless steels. The results in term of application in the North Sear has been twofold;An increased usage at higher temperature (up to 120°C), where the material limitations for stress corrosion cracking from either H2S or chloride ions are not clearly defined.A multitude of specifications, each giving a variety of requirements, each of which is deemed necessary in order to control the properties and fabrication duplex stainless steels. A further complication occurs with respect to specifications for the 25% Chromium alloys since they are also used for seawater pipinq, and specifications for this type of service often have requirements transferred from a process application, and vice versa. The present paper briefly reviews the Limitations to the application of duplex Stainless steels from data already available; it also identifies information that is lacking and the methods required to resolve "problem areas" whilst acknowledging efforts already being made to rectify the situation (Ref 1,2). The approach in the paper is made from the purchaser's viewpoint who, ideally, would like to minimise any additional testing when making material selection. Following on from the above, a detailed review of a nurd3erof specifications from recent North Sea projects for both duplex and super duplex alloys is given. This critically examines the applicability and validity of some requirement, whilst questioning the reasons for differences between the specifications. Finally a summary is given of the area requiring mm work or clearer attention whilst highlighting steps the purchaser can take to improve the situation. A number of different types of duplex Stainless steel have seen extensive use In the North Sea in the past few years. These have included numerous variants of both 22% Chromium and 25% Chromium alloys. The application shave covered all types Of quiz and include pipe, fittinqs, flanges, valves, separators, shell and tube hate exchangers etc. A brief summary of duplex types available and typical applications is given in Tables 1 @ 2. However, the principal duplex stainless steels of interest are 22Cr, 5Ni, 3K (UNSS31803) and 25Cr, 7Ni, 3M0 (UNSS32750/S32760), and the following discussions will be restricted to these alloys in principally topsides applications.

ABSTRACT Recent work in the provision of guidance for offshore structural applications of stainless steel is discussed. Existing data from worldwide sources and new data were assessed in the preparation of the design recommendations. The differences between stainless steel and c-steel behaviour in respect of mechanical properties, local and overall buckling and connections are highlighted. Greater use will be made of cold formed and welded members for stainless steel as the availability of hot produced sections is more limited than for c-steel. This has resulted in a synthesis of design practices for cold formed and welded sections, these practices being usually separated for c-steel. INTRODUCTION Stainless steel has been used for over 50 years in construction, mainly in fixings, fasteners and cladding applications. Certain industries, such as the offshore hydrocarbon industry, impose greater demands on materials than met in common construction. These demands relate to durability and corrosion resistance and in many instances stainless steel can provide a maintenance-free, cost effective, structural solution. Stainless steel can also provide exceptional ductility, fire resistance and nonmagnetic properties, all of which may lead to the specification of stainless steel as a structural material in particular circumstances. The main offshore use of stainless steel is in pipe work, either for hydrocarbon transport, for flare systems subject to low temperature design conditions or for certain seawater systems. However, substantial amounts of stainless steel are specified for non process components such as cable trays and ladders, ventilation louvres, floor panels, fire and blast walls, ladders, walkways and module cladding. Despite these and other structural applications there is a surprising lack of design guidance worldwide for structural application of stainless steel, with the one notable exception of the American code for cold formed sections 1. In order to develop suitable design guidance for offshore stainless steel structural applications, a joint industry project was conducted at The Steel Construction Institute under the sponsorship of eight participating organisations. It was agreed that the guidance should be prepared in a limit state format in which separate load and resistance factors are applied to specified loads and characteristic resistances. The following aspects are included in the resulting design manua12:Cold formed and welded membersClassification of cross-sections and local buckling behaviourResistances of beams, columns, beam-columns and tie membersBeam deflectionsBolted and welded connectionsFabrication aspectsFatigue aspectsA full supporting commentary to the design recommendations. It was decided to initially concentrate on three grades of stainless steel. The three grades chosen were 18Cr 10N1 0.03C (304L), 17Cr 13Ni 2½ Mo 0.03C (316L) and an austenitic-ferritic duplex grade - 22Cr 5Ni 3M0 0.03C (duplex 2205) on the basis of familiarity, corrosion resistance, mechanical properties, weldability, availability in a wide product range, and formability. However, the recommendations for member and connection resistances are applicable to other austenitic grades.

ABSTRACT Two series of experiments are described in which tubulars typical of offshore construction are subjected to dynamic lateral impact and then residual strength tests. Model material selection end preparation which involves heat treatment are reported together with the lateral impact test procedure, Damage in the from of local dents and overall bows is reported and dimensionless semi-empirical relationship presented which relate this damage to the initial kinetic energy. it is possible to identify the range of parameters for which damage will not occur. To determine residual strength a selection of damaged and undamaged tubulars was subjected to axial compression s/one and when combined with external pressure. The test rig and procedure are briefly described and results presented. A semi empirical relationship between axial compressive residual strength and extent of damage is presented. Finally, a method is presented by which full scale measurements of damaged tubulars can be interpreted for use in the residual strength equations. INTRODUCTION A significant number of studies have been devoted to the problem of damage to tubular members which comprise offshore structures. These have included experimental [1-7j, analytical [8-14] and numerical [15,1 6] investigations. The objective of the analytical and numerical studies has generally been to reproduce aspects of the experimental results, usually the residual strength behaviour. In this respect, some of the theoretical solutions provide close estimates but rarely consistently. The reasons for this are detailed but include the following:the solution procedure simulates the behaviour after damage without first re-creating the damage process;solution procedures can only try to replicate the test as reported which will not always reflect the experiment to the degree actually required for a simulation. Apart from some of the test specimens of [4], all the above cited test series have been conducted on the basis that the behaviour they are attempting to simulate occurs statically. Yet they seek to represent the consequences of vessels and dropped objects impacting a tubular forming part of an offshore structure. The minimum design vessel impact speed is usually 2 m/s which locally translates into a strain rate at which at least the yield stress will be enhanced above its static value during the event. The static value is the one generally reported by experimentalists when conducting such tests. For assessment of damage, this oversight can possibly be partially rectified by using a value of yield stress taken from the mill certificate. However, from a simulation standpoint, the use of a static approach omits a number of important energy balances. For example, as will be demonstrated later, most impacts involve rebounds so that not all of the impact energy is converted to damage as it is during a static simulation of the event. Also, although it may not contribute significantly in the forms of damage under consideration, distorted shapes which occur dynamically can differ from those generated by the equivalent static event. Some of the static test series aimed to achieve dent damage only whereas, as shown later, both dent and overall bow damage occurs during dynamic impacts.

ABSTRACT In the 80's there has been a quiet revolution regarding steels offshore Norway. Duplex stainless steel (type 2205) was installed in hydrocarbon systems (together with AISI 3161 and carbon steel). Highly alloyed austenitic stainless steels (type 6 Mo) were applied primarily in seawater-containing fluids (together with cupronickel). A small amount of highly alloyed duplex steel (super duplex) was used e.g. in a process system. The reason for this development was expected lower total life-time costs for the oil/gas production, due to improved corrosion resistance of the new steels. In the 90's it is presumed that titanium, glass fibre reinforced plastics, and perhaps a new super austenitic grade with increased nitrogen content will take a bigger share of the market for sea water containing fluids. This paper summarises the Norwegian practice with respect to steel properties, requirements, engineering features, and use, the latter including some elucidation of needed quantities. Finally, a brief outlook to future use and competitive materials is presented. INTRODUCTION During the 80's there was a quiet revolution in the North Sea regarding materials for offshore production platforms. It related especially to corrosion resistant steels, i.e. stainless steels. Apart from the well known 18-8M0 steel, AISI 316 L, particularly duplex, super duplex, and super austenitic (6 Mo) were used in lieu of carbon steel and cupro-nickel. The first large-scale application was offshore Norway where significant parts of the process and utility systems - piping and vessels - were made of duplex and 6 Mo steels. Shortly thereafter many British platforms were equipped with equal materials. The main reason for this development that still goes on, is lower total life-time costs expected with these steels. This again depends on the relatively high maintenance costs on the particular type of platforms installed in the North Sea. One must take into account that carbon steel corrodes quickly and may have to be repaired or replaced several times during the lifetime of the platform. THE SUPER STAINLESS STEELS Background When the converter processes AOD (argon - oxygen - decarburisation) and VOD (vacuum - oxygen - decarburisation) were introduced in the 70's, a revolutionary development of stainless steels started These refining methods resulted in very pure steel, especially with respect to oxygen, sulfur, carbon and slag inclusions; moreover, the methods allowed narrow compositional ranges. In this way it became possible to improve e.g. hot workability, weldability, and corrosion resistance of the steels, and more highly alloyed grades could be produced. The improvements were obtained to reduced costs, e.g. caused by less chromium loss during refining of low-carbon melts. Production costs were further lowered by applying continuous casting techniques. Even foundries have today found benefits by using the methods at least for premelted raw materials, and the most advanced of them have invested in small AOD-converters.

ABSTRACT Titanium alloys offer a unique combination of high strength, low modulus, excellent seawater toughness/endurance limits and superior resistance to seawater and produced fluids, making them the technically correct material for numerous offshore components. These attractive properties and practical material and design aspects are reviewed in relation to current and candidate titanium alloy applications offshore outlined in the paper. INTRODUCTION The search for new vast hydrocarbon reserves to replace and augment existing reserves has led oil/gas producers into deeper waters offshore. Although deeper water activity is stimulated by and becomes more justifiable as oil/gas prices increase, it has been the development and availability of improved drilling and subsea well production technology that defines the window of available reserves. Offshore systems capable of operating in water depths of 2400 meters have been projected by the year 2000', As water depths exceed approximately 310 meters, floating-type product ion systems become favored economically over the gravity-based systems. Common floating systems include semi-submersibles (see Figure 1), tension-leg platforms TLP), and drillship. Highly critical aspects of floating systems include weight (center of gravity), available topside deck space, and, as with all offshore systems, high cost penalties associated with maintenance and downtime. These requirements specifically favor the consideration and use of titanium alloys, based on their superior corrosion resistance and strength to density (light weight) characteristics, The unique synergistic combination of these properties with low modulus (high flexibility) and excellent air/seawater endurance limits often make these alloys technically correct for numerous stat is and dynamic offshore applications. Despite their obvious benefits and a growing and established favorable service record in hydrocarbon processing, production, and offshore systems, significant user and designer misperception and apprehension related to the fabrieability, field weldability, cost, availability, hydrogen resistance, and galvanic compatibility of titanium alloys in offshore service still exists. It is the intent of this paper to address and dispel these concerns by furtherincreasing user/designer familiarity with relevant titanium alloy mechanical, physical and corrosion properties, and offering basic design criteria andguidelines for specific component applications. A brief overview of existing and future prospective applications of titanium alloys in offshore hydrocarbon production is also provided. INCENTIVES FOR UTILIZING TITANIUM ALLOYS The basic characteristics of titanium alloys which synergistically motivate their use on offshore production pledforms and subsea systems include:Family of alloys offering a wide range of strengthsAttractive mechanical propertiesUnique combination of physical properties, particularly low modulus and densityHigh strength to density ratio to achieve light weight structuresSuperior corrosion and erosion resistance, especially in seawater, marine, and hydrocarbon product ion environmentsGood fabrieability and weldabilityReasonable cost and availability

ABSTRACT In the fall of 1991, Texaco successfully tied back three subsea template wells to a deepwater conventional platform atGarden Banks Block 189. Since these were Texaco's first subsea wellhead tiebacks in the Gulf of Mexico, Texaco solicited recommendations from various contractors (as well as from other operators) in regard to design and operational considerations which would increase the chances of a successful tieback project. The considerations presented in this paper involve drilling operations, template design, platform design and actual tie back operations. INTRODUCfION Since the early 1970' s, operators have employed subsea wellhead tiebacks as a means of retaining costly exploration wells and later utilizing them as an early production source for a new platform installation. One desirable aspect of this approach is that it allows development drilling and platform construction to occur concurrently. In the span of the last few decades as worldwide exploration drilling has extended into deeper waters, this concept has become increasingly more common among an ever-increasing number of operators. Just as the drilling technology has changed to meet the new challenges, considerations have also changed for template design, jacket design and ultimately tieback operations to be used on these deepwater projects. The Gulf of Mexico now has two conventional platforms located in excess of 700 feet of water which have successfully incorporated a multi-wellhead template/subsea tieback system. The design philosophy used at both of these installations varies greatly from those earlier projects completed in shallower water depths. One of the most important contrasts is that the planning must focus on using a diverless system when performing the wellhead tiebacks. This is significant in that the average water depth of the eleven tentative tieback operations presently being planned worldwide is approximately 550 ft. This paper updates earlier presentations by incorporating new information gained from recent experience in designing tiebacks for these deeper water depths. One of the most important aspects in planning deepwater tiebacks is to put equal emphasis on all phases of the operation. Proper design considerations should begin prior to the drilling of thefirst discovery well and continue throughout the planning of the template and platform jacket structures. If the first three aspects of the project arecarefully approached and given equal importance the final phase involving the actual subsea wellhead tieback will be performed more efficiently with a greater probability of success. DRILLING OF WELLS Every subsea well which has the remote possibility of being incorporated into a deepwater platform tieback project must be properly designed at the very initial stages. This begins with the choice of the subsea wellhead system to be used for drilling the well. All conventional subsea wellhead systems offer the option to tieback to platforms. In determining which system is better suited for the project, more consideration for the decision needs to be given to the tieback features of the system as compared to the drilling features.

ABSTRACT. This paper reviews the planning, preparation and initial implementation of drilling operations for the latest phase of development of Phillips Petroleum's Ekofisk Field in the Norwegian Sector of the North Sea. This development includes the addition of 32 new production and injection wells to the existing t 80 well field. The unique aspect of the project was that, at the time of conception of the project, only 8 spare slots were available on existing structures, and preliminary economics proved the addition of a new structure unfavorable. The decision to utilize existing structures for the additional wells created many challenges for Phillips Petroleum Norway's engineers and this paper describes a number of the more interesting and unexpected of those challenges and their solutions. BACKGROUND. The Ekofisk field is the largest of the Phillips Norway Group's seven field " Greater Ekofisk" operation, located in the south west corner of the Norwegian sector of the North Sea. An overview of the " Greater Ekofisk" infrastructure is shown in fig.1. The Ekofisk field itself now comprises three production and two injection platforms, as well as eight other accommodation, process and transportation facility platforms. Production from the Ekofisk field peaked in 1980 with production figures of 618rO00 BOPD and 1,860 NMSCFD of gas. production decline, led to the evaluation and pilot study of a field water injection program. In 1986, the Ekofisk field water injection program commenced from the 2/4 Kilo injection platform (30 well slots capacity). Water injection into the Ekofisk reservoir reached 375rO00 BWPD in 1990 into a total of 20 wells. Positive results prompted Phillips to evaluate further development of water injection coverage, as well as adding producers to optimize recovery from the reservoir. The location of 2/4 Kilo, near the north end of the Ekofisk field, limits access to the center and south end of the field for injection purposes. Also, in 1986r nearly all 56 well slots located on the three Ekofisk production platforms, 2/4 Alpha (16 slots), 2/4 Bravo (24 slots) and 2/4 Charlie (16 slots) had been utilized. As a result, studies were initiated to evaluate the options for increasing the number of well slots at different locations in the field. Various scenarios were considered including new wellhead platforms, cantilever extensions to existing structures, and modifications to existing facilities. The decision was finally made a) to modify two of the existing production platforms (2/4 Alpha in the South of the field, and 2/4 Charlie near the field center) to add eight extra well slots on each structure, and b) to modify one of the bridge support tripods at the south end of the Ekofisk complex to accept a wellhead module for eight water injection wells. The location of the bridge support was ideal, in that it gave access to center and southern areas of the field for improved water injection coverage. The new injection platform was assigned the designation - 2/4 W.

ABSTRACT The Spar is a deep-draft floating steel caisson, which can be designed to drill, produce and store oil. It is very stable and relatively insensitive to deck loads. Drilling and production equipment are supported on the decks above the waterline. Oil may stored in the lower portion of the hull. The centerwell protects drilling and production risers down to 650 feet. The Spar can be moored with conventional or taut catenary mooring lines using embedment or pile anchors. Because of its deep draft and large displacement mooring line dynamic loads are relatively low. Fabrication and installation plans together with cost estimates are included for a 36-well design for Chevron in the Gulf of Mexico. Predicted motions under normal and maximum sea states are shown together with the results of global motion analysis using both frequency and time domain programs. The sensitivity of the design to mooring parameters, draft, diameter and Spar mass properties is discussed. Potential applications are briefly reviewed. INTRODUCTION The concept of a Spar (a slender vertical structure) stable floating ocean platform has been recognized for years. The Flip Ship (Fisher and Spiess, 1963) was built in 1962 as a stable platform for oceanographic measurements. Its favorable motion properties are well documented (Rudnick 1964, 1967, 1971). The potential for use of the Spar in the offshore industry was recognized in the 1970s with the construction of Shell's Brent Spar for oil storage and offloading in the North Sea. Other potential uses and the salient motion properties were discussed by van Santaan and deWerk (1976). Research on the Spar as a storage and/or production vessel was carried out by some oil companies in the mid 1970s, however additional use of the Spar concept did not materialize. It has again recently been proposed as a low cost production facility for remote subsea well sites (Kerckhoff and Pijfers, 1989). This paper describes a full drilling and production Spar designed for a 2,700 foot water depth in the Gulf of Mexico. Oil storage is not a requirement for this site, but could be a major advantage of the Spar for remote areas of the world. The proposed Spar is an order of magnitude larger (in displacement) than the Brent or Flip designs, however, it retains the stability and simplicity intrinsic to the concept. SPAR CONCEPT The Spar is a large, deep draft, cylindrical, floating platform (Figure 1) designed to support drilling and production equipment and to store oil. It is permanently moored with multipoint catenary anchor lines over a multiwell seafloor template. Wells can be drilled and completed with the BOP stack either on the surface or on the seafloor. Risers are held in tension by hydraulic tensioners or by buoyancy modules (Figure 2). The most obvious features of the Spar are its extreme draft, straight sides, large centerwell, and large displacement (Figure 1).

ABSTRACT Development of deep water oil and gas reserves require pipeline installation using J-Lay methods, limiting the number of working stations to 1 with the pipe axis vertical. This program researched the welding technology for J-Lay pipeline welding. It was found, with minor modifications, the narrow gap welding technology used for conventional offshore construction could be used effectively for J-Lay pipeline welding. Welding procedures were developed, mechanical properties tested and a simulated field trial performed successfully. INTRODUCTION Conventional offshore pipeline installation is done with the pipe axis in the horizontal position (5G) on the "lay barge". The lay barge typically have a series of tensioners to hold the pipe into an "S bend. This technology is not suitable for "deep" water. The maximum effective depth for S-Lay is dependent on the pipe diameter and lay vessel characteristics. For pipelines in water depths beyond S-Lay capabilities, the J-Lay technique must be used. The J-lay technique places the pipe axis in the vertical position (2G) on the lay barge with a continuous radius to the sea bottom. Generally, this technique reduces the tension required and makes it possible for much smaller vessels to perform the pipelay operation. The major limitation of the J-Lay technique is the number of working stations. A conventional lay barge will have 5 to 10 working stations. The work of welding, inspection, repair, and field coating is divided over these stations to maximize production. In the case of J-Lay construction all these functions must be performed in one station making the cycle time of adding one pipe length much longer than on a conventional barge. This group sponsored program was organized to research the application of high productivity, narrow gap, welding technology normally used for conventional pipeline welding for 2G pipeline construction. The sponsors of the program were:AMOCO Corporation BP ExplorationChevron Corporation Conoco, Inc.Exxon Production Research Kawasaki Steel Corp.Shell DevelopmentSumitomo Metal America, Inc.The program was carried out in 8 separate phases. They were:Phase 1- Equipment ModificationPhase II - Process EvaluationPhase Ill - Joint Design EvaluationPhase IV - Welding Position EvaluationPhase V - Welding Consumable EvaluationPhase VI - Pinal Procedure EvaluationPhase Vll - Cooling rate MeasurementPhase Vlll - Mechanical Property Testing MATERIALS The pipes used in this investigation were:24-inch-diameter, O.810-inch-wall, double-submerged-arc welded (DSAW), API 5LX-60 grade, and16-inch-diameter, 0.740-inch-wall, seamless, API 5LX-60 grade. The 24-inch-diameter pipe was controlled-rolled, accelerated-cooled (TMCP). The 16-inch- diameter pipe was quenched-and-tempered. The chemical compositions of these pipes are shown in Table 1. Both metal-core and solid filler wires were evaluated during Part II, Process Evaluation. The metal-core electrode was 0.035-inch-diameter, Alloy Rods, Coreweld 70 of the AWS E 70 T-1 classification. Solid wires of 0.035,0.040 and 0.045-inch-diameter of the four alloy groups, C-Mn, C-Mn-Ni, C-Mn-Ti, and C-Mn-Ti-B were used. The chemical composition of these solid, filler wires is shown in Table 2.

ABSTRACT The paper describes the main conceptual and design aspects of a Jack-Up Monopile Platform concept intended for drilling and production in North Sea and which combines technology from Gravity Base Platforms and Jack-Up Rigs. The platformcomprises3 main elements:An integrated deck, completely equipped and tested on shore prior to installationA single supporting leg with its associated jacking systemA gravity base that ensures the stability on site and during towing and can provide for extra storage The derrick and drill floor operate over the centre of the leg structure, and risers are installed through its centre, thus providing protection against damage from supply boats. The Jack-Up Monopile Platform has been designed for 150 meters water depth in North Sea environment. It provides for a total deck payload of 10 600 tonnes which includes:Accommodation facilities for 160 personsDrilling equipments for 24 wells at 7 000 metres depthProduction equipments including injection equipment for processing 120 000 barrels oil per dayPower and utilities necessary to maintain the efficient platform operation The design allows complete fabrication and hook up of all the platform facilities to take place at an offshore construction yard prior to installation at a field location, without the need of deep water mating sites nor the use of heavy lift vessels. The key advantage is its ability to be decommissioned easily and relocated after any eventual upgrading of its facilities. This improves the cost effective aspect of such a design and makes it specially fitted to marginal field development. The Jack-Up Monopile Platform has been Specifically developed to meet North Sea environmental conditions and regulations and is self erected, self installed, with risers efficiently protected and can be easily decommissioned for use on other fields, thus providing operators with a cost effective development solution. INTRODUCTION For big oil fields, a conventional development scheme consists in installing a jacket or a concrete platform with several separate modules (drilling, production, injection, accommodation, etc...) to be towed out and installed on the site, thus requiring heavy lift vessels and high hook up costs. Such a development can take several years before first oil and so corresponds to a very high investment cost before production. For satellite or marginal fields, some other possibilities exist such as subsea developments or use of floating production facilities. They imply subsea wellheads and completions for which technology is sophisticated. For many years now, designers have proposed mobile concepts that combine both drilling and production options. One of this transposition concerns the jack-up concept which technology is cost-effective and well-proven now. With regards to semis which motions can be important and which are weight sensitive, jack-ups allow for early production using conventional wellheads at the platform level. Unfortunately, conventional jack-ups cannot operate in water depth greater than 100/110 metres in North Sea.

ABSTRACT The Kittiwake oil field has been developed using the first of a new generation of liftable slimline jackets to be installed in the North Sea by Shell UK Exploration and Production, known as Shell Expro, operator in the UK sector the North Sea on behalf of Shell and coventurer Esso Expro. Production began in September 1990 - almost exactly 15 years after Shell Expro began production from Auk, its first North Sea oil field. This paper considers the progress of jacket engineering over these 15 years by comparing two jackets supporting topsides facilities which perform comparable functions in very similar conditions. INTRODUCTION The Kittiwake platform is a self contained drilling, production and accommodation platform located in 85 metres of water approximately 100 miles east of Aberdeen in the Central North Sea sector of the UK Continental Shelf. Recoverable oil reserves from the field are approximately 70 million barrels, making Kittiwake one of the smallest North Sea fields to be developed as a standalone facility. Kittiwake was originally part of the Gannet Cluster project which was suspended during the 1986 oil price collapse. It has now been developed using a 4 leg lift installed jacket which supports an integrated deck, living quarters module and drilling mast. The platform has 16 well slots, facilities for up to 36000 barrels of oil production per day, and accommodation for 80 men. Oil is exported via a 2km. long 8 inch diameter pipeline and a loading buoy into shuttle tankers. The Kittiwake tankers are dynamically positioned, enabling them to continue loading oil in rougher seas than moored tankers - an important advantage as Kittiwake has no storage and therefore is shut down when the tanker is not loading. Associated gas is exported via a 2km. long 4 inch diameter pipeline into the nearby Fulmar gas line. The Kittiwake jacket, which had a lift weight of 5400 tonnes, is supported by twelve 2.134m. diameter skirt piles each driven to 60m. seabed penetration. The jacket framing is depicted in Fig. 1. The four leg structure stands 106.6m. tall and directly supports the 7000 tonne lift weight integrated deck without an intermediate module support frame (MSF). The bracing pattern is very simple, having three X-braced vertical frames and four diamond braced horizontal frames at elevations +14m., -15m., -47m., and -82m. respectively. The nominal lateral dimensions of the jacket are 25m. by 22.6m. at the top, and 38m. square at the base. These plan dimensions are unusually small for the support of a large integrated deck, as Fig. 1 illustrates. After initial jacket design by Shell Expro, detailed design was undertaken by Earl & Wright, London. RGC, Methil then fabricated the jacket and piles. Installation of the complete platform was performed by HeereMaC using the semi-submersible crane vessel (SSCV) DBI02, under subcontract to McDermott International Inc. It is noteworthy that many of these companies were also principal players in the execution of Shell Expro's Auk project.

Abstract Two exploration wells were drilled in U.K. North Sea block 16/7a in 1984/5 using modular guide base structures with the second well-head cantilevered from the first and the two wells sharing the centre two guideposts. The wells have subsequently been re-entered and completed for production sub sea, in such a way as to allow clearance to land a tree on each wellhead and so that with a tree installed on either well, access is available to run a BOP stack on the other well. This paper describes the wellhead modifications required, the unique sub sea tree design, and the associated equipment required to complete two wells in such close proximity. Introduction The Central Brae field was discovered in 1975 by well 16/7a-3 approximately 155 miles (249 kilometers) north east of Aberdeen in 350 ft (107 m) of water (Figure 1). An appraisal well, 16/7a-27 was drilled in 1984 with a primary guide base of a modular wellhead system used as the permanent guide base for the well. A second appraisal well l6/7a-29 was drilled in 1985 using a cantilevered guide base hung from the primary guide structure of l6/7a-27 (Figure 2) In this configuration the wells are 8'6" (2.6m) between centers and share the two centre guideposts having only six posts between the two wells. The main reason for using the modular wellhead system was to allow the wells to be tied back to a jacket at a later date should a platform development prove viable. Due to the calculated size of the field and prevailing economics the decision was taken to develop the field using sub sea technology. The Central Brae field is an Upper Jurassic black oil reservoir (37°API, 1400 scf/bbl GOR) containing approximately 70 million barrels of recoverable liquid hydrocarbons. Process Facilities on the Brae ' A' platform 4.3 miles (7 Km) away with spare capacity, allowed a sub sea development to utilize the existing infrastructure with minimum platform modifications. In spring 1989 an eight slot sub sea template weighing 650 tones was placed adjacent to the two existing wells (Figure 3) The template structure extends to give protection for the two 'off template' wells and provides Mani folding for production, injection and service line tie-ins. In addition control line jumper bundles including electrical power and signal cables, and hydraulic lines were pre-installed on the template prior to launch. The template provides the guidance for drilling up to eight additional wells utilizing a modified permanent guide base to allow well completion. Control is provided to the template via a 4.3 mile (7 KID) electro-hydraulic umbilical tied back to the Brae 'A' platform. On the template an electro-hydraulic distribution box provides signals and ontrol fluid to each well bay. In addition, a chemical injection umbilical capable of providing wax inhibitor, scale inhibitor, hydrate inhibitor and corrosion inhibitor is tied in to the template produced fluid lines.A Two 6" flow lines connect Central Brae to the Brae 'A' platform along with a 10" water injection line and a 4" service line. The template has Mani folded piping allowing the future installation of a further two 6" flow lines.

ABSTRACT The Veslefrikk concept represents a new way to layout an offshore production and drilling facility. A drilling wellhead platform (VFA) is connected to a floating production vessel (VFB), which is a converted drilling rig. This paper presents the general philosophy for developing the concept, split of systems between the platforms, and highlights specific features of the system design. Major modifications to the existing rig systems, and handling of the documentations for these systems will be described. INTRODUCTION Field Location The Veslefrikk field is an offshore oil field located as shown in Fig. 1. Concept Development During the spring of 1986 the oil prices fell drastically, and this reduced the need for drilling rigs in the North Sea. that time a Norwegian rig owner was constructing a forth generation drilling rig on a four-year charter to Statoil at a South Korean yard. The drilling rig was to be delivered to the rig owner by the end of 1986. Because of the reduced need for drilling rigs as a consequence of the reduced oil prices, Statoil proposed considering the use of the drilling rig as a production vessel at Veslefrikk. A brief study carried out by the rig owner revealed that the rig could be used as a field installation on Veslefrikk in combination with a sub-sea installation. Other concepts than sub-sea installations with transfer of the well stream in flexible hoses to the production vessel were studied in order to reduce or avoid the use of flexible hoses. The final solution was to use a drilling wellhead platform connected to VFB by flexible hoses, and a telescopic bridge. The concept is shown in Fig. 2. TRANSPORT OF PRODUCTS Stabilized oil is transported in a 16 " pipeline to the Oseberg A platform and from there in a 28" pipeline to a crudeoi1 terminal at Sture on the Norwegian West Coast. The gas delivered from Veslefrikk is to fulfill the following specifications:Cricondenbar pressure: < 110 bargeCricondentherm: < 40°Water content: < 40 mg/sm3Carbon dioxide content: < 2.0 vol.%Dihydrogen sulphide content: < 2.5 ppmPipeline inlet pressure: 167 barg The gas will be exported through the Statpipe/Norpipe system to Emden in West Germany. The gas export pipeline from Veslefrikk is a 10" line. This is connected to Statpipe at a preinstalled subsea T connection as shown in Fig. 3 and 4. Statpipe is a 30" line while the dimension of the T-connection in 20". At the T is installed valves and piping with the possibility to connect a subsea pig receiver. GENERAL PHILOSPHY FOR DEVELOPMENT OF THE CONCEPT During the initial study phase of the project, in the summer of 1986, it became evident that the converted floater could accommodate all process, utility and mud handling required. VFB The philosophy for VFB was to keep modifications to a minimum, and to use as many as possible of the existing systems for the production vessel.

ABSTRACT This paper discusses the design, analysis, and performance requirements of the satellite sub sea trees and electro hydraulic controls equipment used in the development of small fields, considerably offset from existing platforms in the Bass Strait, Australia. The two initial systems were installed on previously drilled wells and permit connection of an additional well in a daisy chain manner. INTRODUCTION Offshore production from the Bass Strait has been ongoing sincen 1969 and has reached a relatively mature state, however, there are several small shallow water fields, with marginal economics, which have been considered for production. Two of these fields, Seahorse and Tar whine, were selected for initial development using electro hydraulically controlled single satellite trees which will produce to the existing Barracuda platform. Figure 1shows the relative location between the two development fields and the existing production platform. This paper discusses the project approach, the design of the electro hydraulic control system, subentries, work over controls, the overall development arrangement, and the unique daisy chain or piggy back requirements of the system. PROJECT APPROACH Two primary objectives of the project were to minimize development costs and to obtain a quality product. Some of the items which contributed to meeting these objectives were:Development of simple contractual documents including equipment specifications, quality assurance requirements. and terms and conditions. These items were project specific and were reviewed in detail prior to initiation of work to ensure understanding and workability. This ultimately reduced administration costs.Establishment of clear communication lines which included dedicated project teams with clearly defined responsibilities and project seniority. Direct communication, including use of facsimile, was encouraged between team members which minimized turnaround time and misunderstandings and contributed to lower administration costs.Single source supply for both tree and controls equipment eliminated interface communications between different suppliers and provided a clear line of responsibility resulting in decreased contract administration and risk.Use of the daisy chain concept eliminated the requirement for a separate production flow line and control umbilical from the second well back to the production platform. Rather, short lines to the primary well only would be required reducing capital costs.Utilization of field-proven equipment, existing specific components or design features can and was achieved reducing design cost and increasing reliability and quality, which decreased manufacturing costs.Extensive acceptance and site integration testing and training prior to equipment installation contributed to reduced rig n installation time. The equipment design was based on a comprehensive customer specification Which required field-proven components and practices which emphasized simplicity and reliability. All designs passed through a customer review/approval cycle and the sub sea production equipment required an additional Third Party Certifying Authority Review. General equipment design guidelines included: Sized to suit typical semi submersible moon pool dimensions and crane capacity; All equipment interchangeable between both existing wells; Installation with minimum diver assistance and subsequent intervention with ROV; Secondary mechanical overrides on the valves and connectors; Designed for 15 years of sub sea service; Material compatibility with environment, well fluid, injection chemical

ABSTRACT The paper out1ines objectives and concepts of BP Exploration's DISPS Project development programme, which is developing diverless subsea production technology for 350-750 metres water depths. The principal systems, subsystems and components which have been developed and tested are introduced and their inter-relation explained. The whole programme is overviewed, the experience gained from the extensive test programme outlined, and conclusion and lessons learnt summarised. INTRODUCTION DISPS is the acronym for BP Exploration's Diverless Subsea Production Systems Project, a deepwater subsea technology development programme, which started in 1985. Its objective is todevelop diverless subsea production technology and gain confidence in the principles, equipment and techniques that BP would use to exploit an oil or gas discovery in water depths up to 750m, such as would be encountered west of the Shetland Islands to the north of Scotland, United Kingdom. Two phases were foreseen when the Project commenced. The first phase consisting of major engineering design, development and testing of components and system testing is largely complete. The timing for the second phase, namely prototype application of the developed technology in diver accessible depths to gain operating experience, isdependant on the exploration programme and the actual future application in deep water. This paper will introduce and overview the principal systems and subsystems which have been engineered and tested to date. These are described in further detail in the complementary DISPS papers which follow. STATEMENT OF REQUIREMENTS When the DISPS Project Team was formed in early 1986 its first task was to crystallize the previous studies and reviews into an agreed techno1ogica1 package for the Statement of Requirements (SOR). This document set out BP Exploration's requirement as sponsor of the development programme, and to ensure that it adequately addressed BP's business needs the SOR was approved by a Steering Committee of Seni or Managers from several departments within BP Exploration and BP Engineering. In preparing the SOR the Project consciously narrowed the scope of work to fit available resources and timeframes guided by a perceived priority list of technology gaps. The Project also acknowledged that the SOR would be a snapshot of BP's perception as of mid 1986. and included sections of work in the SOR to help with future reviews of the work programme. The SOR, the Project's reference book, summarised the background and detailed the objectives. It set out the design premises and philosophies, described the concept used as a basis to implement the programme, and it formed the technical basisfor the first few engineering study contracts. The concept of DISPS being an enabling technology was promulgated In order to closely focus the programme the technology development was limited to subsea facilities and surface equipment to handle them, flowlines and umbilicals and their subsea terminations. STUDIES AND CONCEPTUAL DESIGNS The SOR was taken as the basis for studies of the major technology areas, and preparation of conceptual designs.

ABSTRACT The design and construction planning of deepwater tunneled ocean outfalls involves both underground and offshore engineering. In particular, the demands placed on the outfall seabed riser structures requires consideration of many of the engineering disciplines associated with the offshore industry. This paper describes the investigations, design and construction planning that is required in the development of the seabed diffuser structures and riser shafts of deepwater tunneled outcalls. Explains how modem technology has been integrated with offshore construction and drilling methods typically found in the offshore oil and gas industry. INTRODUCTION For many years now coastal cities and communities around the world have been discharging their waste water and sewage into the surrounding coastal waters. Often this discharge or effluent has been untreated and in some locations discharged virtually at the shoreline through open pipelines or via shallow water Outfalls. The result of such practices, in many instances, has been a significant increase in the level of pollution of the marine environment to such an extent that the quality of life in those cities and communities is now becoming threatened. Governments and regulatory authorities are coming under increased public pressure to rectify this environmental pollution, and in many instances actions have been taken and projects initiated to reduce the level of pollution of the coastal environment. A recognized method of reducing the pollution of coastal waters is to first treat the wastewater and sewage by means of processes which remove the toxins, greases and harmful bacteria, and then to discharge the treated effluent through deep water ocean outfalls. A deepwater outfall is a conduit that takes treated effluent from an onshore treatment works to a predetermined seabed site some distance offshore. The effluent is discharged into the marine environment at this seabed site through a structure known as a diffuser. The area of discharge is known as the diffuser zone, The outfall conduit can be either a seabed pipeline or a submarine tunnel. Deep water outfalls usually require conduits in excess of four feet diameter, and discharge in water depths in excess of 60 feet. This paper concentrates on the offshore engineering aspects of deep water tunneled outfalls, and in particular, the design and construction planning of the offshore riser assembly, Particular reference is made to the Sydney Ocean Outfall Project currently under construction off the coast of Sydney, Australia. There are three deep water tunneled outfalls involved in this Project and the outfalls are considered the most technically advanced of this kind ever undertaken. Reference is also made to the planned Boston Outfall, which when constructed will be the largest tunneled outfall in the world. OUTFALL CONFIGURATION A tunneled outfall comprises the following components:An access shaft from the onshore treatment works to the start of the submarine tunnel.A submarine tunnel extending from the base of the access shaft to the offshore diffuser zone.A diffuser zone which consists of a collection of riser assemblies. Refer to Figure 1 for the general arrangement of a deep water tunneled outfall.

ABSTRACT This paper describes the design, analysis, testing and the resources devoted to the development of an advanced sub sea wellhead system. This wellhead system significantly improves casing suspension/load capacities, annulus sealing and rig floor operations. INTRODUCTION Wells are now being drilled in water depths over 7,500 ft. with reservoir pressures approaching 15,000 psi, and temperatures approaching 180°C. A high-performance sub sea wellhead system providing simple rig operations, reliable sealing and improved load carrying capacity is an important element in safely and cost effectively drilling and developing deepwater fields. In developing this system, major emphasis was placed on:passive load transfer.All metal SealingSimple weight set operation. These elements, combined with other specific system performance goals, provided the benefits necessary to warrant this project. The approach was to define a specification based on historical perspective and present day customer input, to design and analyze the elements using the most modern technique: available, to rigorously and thoroughly test the equipment under laboratory and field-simulated conditions, and to perform field trials. The wellhead resulting from this research is shown in Figure 1. Specification The detailed specification is a lengthy document covering all associated equipment from spud-in to tieback and sub sea completion interfaces. The basic requirements for the wellhead are:18-3/4 in. -15,000 psi rated working pressure.compliance with industry specifications: API 17D, NACE MR-01 75, and Certifiable for North Sea operations.Temperature range - 4°C thru + 120°C.Simple reliable installationWeight set operation.Passive casing suspension load carrying system.Single trip installation of hanger and seal assembly.Minimization of the number of trips and tools.Load carrying capacity -7.1 million lb.1 million lb. per hanger (13-3/8 in., 9-5/8 in., 7 in.).4.1 million lb. end-load due to 15 Ksi full bore test.Highly reliable all metal sealing.Maximized flow-by area and particle size.Compatibility with sub sea production systems as well a platform or TLP tieback systems. DESIGN Wellhead Housing The external design of the housing is standard and can be fitted with a mandrel or a hub profile to interface with the BOP stack connector. The load transfer system from casing hanger to wellhead housing is completely passive as shown in Figure 2. Unlike previous systems, no mechanisms, shear pins or addition trips are required to provide over 7 million lb. of load carrying capacity. The high-strength load shoulder insert in the wellhead housing has bore clearance for a 17-1/2 in. bit. The pre-installed wert provides additional bearing area on the NACE-rated housing material while maintaining 360° of contact with the first casing anger. This hanger-to-housing interface allows the hanger to simply land upon a conventional angular shoulder while maintaining the ability to support a load-tested 8 million lbs.

1. ABSTRACT This paper highlights the experiences of introducing Electronic Imaging to a major offshore project in Norway, to store and distribute all drawing documentation. The paper describes the objectives and features of the system and ultimately practical experiences with the system. The paper concludes by recommending it as a powerful tool for future major projects. 2. INTRODUCTION Gyda is a $1.3 billion project to develop an integrated oil platform in the Norwegian sector of the North Sea. It has a production capacity of 60,000 BPSD and delivers oil to Teesside in the UK and gas to Emden in West Germany. The purchase of an Electronic Imaging System arose as a result of a requirement for CAD facilities during the fabrication, installation and commissioning phases of the project. After a thorough investigation of possible alternatives it was considered that Electronic Imaging was the only method of accommodating all the dissimilar drawing media inherited from the Norwegian design contractor (Figure 1 shows a breakdown of the media received from the contractor). Prior to "close-out" of the detailed design Contractor, 16,500 design and supplier drawings were scanned over a period of 4 weeks. As a temporary measure all scanned data was stored on magnetic tape prior to delivery of the system in April 1989. One of the major justifications for making all drawings electronic on the project was the fast transmission of drawing documentation to the widely dispersed remote sites on the project (Figure 2 shows the geographical locations of the remote sites accessing the Electronic Imaging System). There are two alternative methods of storing drawing data on an Imaging System known as "Raster" and "Vector". Raster data is received directly from a document scanner and is rather like an electronic version of a high resolution tealeaf image. The drawing, once scanned, is represented as a series of non-intelligent dots at a density of 200 Dots/inch. Vector data is more intelligent and is made up of geometric entities such as lines, arcs, circles, etc., the entities can be manipulated as self contained objects. CAD systems exclusively use Vector data, but Imaging Systems can use a combination of both to fit the purpose. They also have the capability to convert Raster data into Vector known as "factorizations". Raster drawing data requires a lot of storage space, therefore it is necessary to use data compression techniques to reduce storage demands. On Gyda all drawing data is held as highly compressed Raster data and no attempt has been made to convert this into Vector data. Since timescales were short and the compressed image file sizes were slightly less than Vector, it was decided to edit and store drawings solely in Raster.

ABSTRACT The purpose of the project is to develop the "Automated Offshore Drilling System" and to establish its basic design. Since 1984, research. investigation work. design. fabrication, and field test have been executed to develop the "Automated Offshore Drilling System" by Japan Ocean Industries Associations (JOIA), jointly with Mitsui Engineering & Shipbuilding CO., Ltd.(MES), and other member companies under the auspices of the Ministry of Trade & Industries (MIT!). Field tests of prototype mud pulse MWD and demonstration tests of 1/2 (one-second) scaled pipe handling systems including racking system, top drive system, draw works, Auto Roughneck, Pipe Handler, etc. had been completed successfully. INTRODUCTION The oil & gas extraction from offshore fields has become one quarter(1/4) of the world product. This percentage is expected to increase, and the development targets of future offshore fields will move toward a harsher environmental area, i.e., deeper water and arctic areas. On the other hand, "automation" is the demand of the times, in the industries and all human lives. however, the equipment and system on the drilling rigs seem to be far from automated. The major reason of the above is, the drilling operation strongly depends on experience and special skills of drilling crews. At the same time, a shortage of skilled drilling crews will become a critical issue. The current low level of the day rates earned by offshore drilling rigs and the reduced level of drilling by oil companies, has reduced the R&D efforts. The oil companies and contractors are rather conservative, then the rigs with totally different drilling system such as National A10-32 are very few. Developments of robotic drill pipe handling unit such as Temco in Norway have not been succeeded. R&D PROJECT To meet the demands of the times, MITI has been promoting the "Highly efficient offshore oil & gas drilling project", to develop an "Automated Offshore Drilling System", and entrust its practice to JOIA. This project, started in 1984, has a goal aimed atthe 1989 fiscal year to establish the basic design of the "Automated Offshore Drilling System". The project committee has been organized by JOIA with 12 member companies in Japan, to discuss the R &D work. The philosophy of this project is to develop the "Automated Offshore Drilling System" as an extension of the present concept, the system can be applied to any type of existing drilling rigs with small modifications to some extent. Among many sub-systems to be automated, the following five have been selected for this project:Central control &monitoring systemReal time measuring system (MWD)Mud control systemPipe handling systemBarge control system

ABTRACT Recent acquisition and processing of marine seismic data using the variable depth hydrophone array or detuned array produces much better data. This technique has been utilized in many areas and water depths in the Gulf of Mexico, North Sea, Angola Cabinda, Congo, and Ethiopia. comparisons are made from data acquired simultaneously with twin hydrophone streamers; one streamer was towed slanted and one towed flat. Acquisition and processing techniques are demonstrated and benefits discussed. Comparisons include examples, diagnostics, and final processed data sets. Results indicate alternate solutions to the tuning effect of narrow band flat arrays and the broad band effect of slant-arrays, This broad band approach, possible with the s1ant array, yields much better stratigraphic data at the reservoir level. INTRODUCTION Normally, marine seismic data is acquired using multiple hydrophone groups arranged in continuous towed streamer arrays, deployed at relatively shallow uniform water depths. Flat streamer cables are typically towed at nominal speeds of 4 to 6 knots to enable CRP data to be gathered as efficiently and as noise free as possible. In the late 1970's, new Cable Levelers were developed allowing hydrophone depths to be controlled remotely from the recording vessel. This, coupled with the development of digital streamers, set the stage for hydrophone deployment at independently selected depths, In 1979, the first Slant Cable operations were conducted using a high resolution seismic system. The purposeful benefits were to remove the surface reflection distortion, or "Ghost", so that high resolution could be maintained and surface noise reduced as the cable was deepened. The procedure worked well and several programs were conducted with the system, after which u.s. Patent #4,353,121 was issued, It remained until 1986, before the larger exploration systems were deployed in the Slant Cable mode. BY this time, computer capacity and software capability had both been developed sufficiently to make processing cost-effective and competitive with typical Flat Cable technology, New software was developed, automating the procedures, allowing 2-D data to provide new insight into better structural and stratigraphic views of reservoir geology. This undertaking involved analyses of the Slant Cable seismic system response in both time and frequency domains, using actual Air gun array signatures for wavelet processing, DISCUSSING Air gun array data, when recovered from variable depth hydrophone groups, demonstrates some startling changes, The far field Air gun signature, as depicted in (Figure 1, Trace 1 on the left of the expanded view) as a down going wavelet, ghosted from deployment 25 feet below the water surface, The detected upward returning signature now characterized as a reflection, is then further ghosted by a second down going return from the water surface on trade 2 for a two foot hydrophone depth; on trace 3 for a 3 foot depth, and continuing at one foot deeper increments to a hydrophone depth of 200 feet on the right, The vertical sofa: lines are 20 milliseconds apart. surface ghost returns, in both cases, is reversed in polarity and nearly equal in amplitude to the primary.

ABSTRACT Industrial operations in ice-infested environments must take into account environmental factors or constraints that are not applicable in more temperate climates. This paper outlines the background and provides an overview of the role of the environmental factors to the malfunction or faults in ocean engineering systems of the Arctic and Subarctic. The necessity of careful reliability and safety analysis of arctic offshore systems as an integrated whole isemphasized. Some practical solutions to the environmental problems in the Baltic Sea are discussed. INTRODUCTION Basic information on environmental factors acts as a foundation for development work on arctic structures and its planning as well as arctic logistic problem solving. Environmental protection requires the same kind of data on the environment. Thus, it is apparent that the more detailed the information we have on the environment, the better we will be able to solve the technical problems of the arctic regions and overcome the difficulties involved in environmental protection. Unfortunately in most practical cases we lack this information which must be compensated for by systematic research and careful reliability and safety analysis and estimation of risk. The environmental and economic consequences of accidents or faults in the offshore systems of the Arctic are severe. This has resulted in that offshore industry and authorities have actively sought the best available technology for arctic spill response. Extensive research and development has been undertaken, numerous field tests and equipment modifications of various oil recovery and disposal systems have been accomplished. Less efforts have been put to considering safety and reliability aspects beforehand in the planning stage of theoperations. Environmental problems of the Arctic and Subarctic can be solved by carefullyanalyzing the coherent system of industrial operations. OUTLINING OF THE SYSTEM A simplified block diagram of a general safety system of an offshore operation in the Arctic is presented in Fig. 1. The diagram has been simplified by examining in more detail only the consequences of the possibility of an oil spill. From this diagram we can make the following important findings:The environment embraces all the other elements of the diagram. As was pointed out in the introduction, in most cases the environmental data is scarce. This increases the uncertainty in the functioning of all the elements of the system.The human element is in one way or another an effective factor in all the other elements of the system. Human actions can be predictable or random. The randomness of human actions causes problems especially in random environmental conditions.Discovering the causes of the malfunction or fault in the operational elements is the main object of safety and reliability engineering. The most effective means to avoid accidents during the system operation is to eliminate or reduce hazards and danger during design anddevelopment.The possibility of an oil spill is not the only consequence. Unfortunately, public opinion and authorities have paid attention to the non controlled oil spill element.

ABSTRACT The Jolliet project fabrications are noteworthy, not only for their unique designs am record setting installations, but also for the novel materials, welding procedure requirements, am construction procedures. 'Ibis paper will discuss the novel aspects and techniques used to construct the major component for the Jolliet am Marquette projects. These components consisted of the templates, the 'TIWP structure, the tendons, the two fixed jackets, am the pipelines. Additionally, experiences with using am welding new generation steels will be presented. Further more, the benefits from requiring am adhering to very specific fabrication am welding procedures will be demonstrated by comparing repair rates for these component. INTRODUCTION The materials, welding am fabrication of the Jolliet am Marquette field development components accounted for over 30% of the two projects' costs. Also, these activities were always on the critical path for installation am the on-time scheduling of the project. since the budget am schedule were significant parts of the project, special requirements were developed, when necessary, to assure that the time am investment in these areas were as trouble-free as possible. 'Ibis is especially critical when construction problems with the Hutton tension leg platform (TLP) were considered. Construction problems with the Hutton tension leg platform were related to welding am hydrogen/cold cracking of susceptible structural steel. 1 These problems were significant since they resulted in a delay of approximately nine months to the project's production of first oil. These problems were not related to the design am application of the novel tension leg platform technology. However, the fabrication problems were significant due to the delays. The problems am recommended solutions discussed in this reference pointed out the need for specific materials, welding, am fabrication requirements to prevent the problems from reoccurring. 'Ibis would apply not only to tension leg type platform construction, but to any structural steel construction. 'These learned lessons were applied during the design, engineering, and construction of the Jolliet am Marquette project components. '!he main components discussed in this paper have 4 described in detail in other papers. " These components are the tension leg well platform ('TIWP) structure, the drilling am foundation templates, the tendons, the Jolliet am Marquette project fixed jackets, and the pipelines/in-field flow lines. This paper will discuss the precautions am special requirements taken to provide for minimum trouble fabrications. 'These trouble-free fabrications were instrumental in the resultant on-time am under budget Jolliet project. Additionally, the novel construction procedures for special components will be detailed. MATERIAL SUMMARY The approximate steel weights associated with the main project components are shown in Tables I, II, am III. 'These tables shown the respective weight breakdown of the components related to the TIWP, the Jolliet central production platform (CPP) jacket, and the jacket for the companion Marquette field development. Additionally, the pipeline steel, which weighed approximately 13,400 tons, are not included in the tables.

ABSTRACT This paper presents an overview of the installation of the Jolliet TLWP including the drilling template, foundationttmplate, tem30nsd TLWP itself. Novel installation techniques were Used and same of these are describes. Attention is focused on not only what went well, but also some of the problems encountered and the solutions achieved. The paper also describes some of the very intensive planning, installation engineering and testing that was performe3in preparation for the work. Specialized installation equipment procedures are described. Introduction The Jolliet project marks several -first in the industry, the most note worthy Of which is the world?s water depth record for a production platform and the novel Tension Leg Well Platform (?ITWP)approach to production platform design. Installation was, therefore a key consideration throughout the execution of the project beginning in the early conceptual phases. A driving consideration for nearly all the marine components of the TLWP was install ability -how to transport and install it off shore. This was particularly so for the templates and the tendons. The TLWP is described in Reference 2 and will Not be repeated here, expect to focus on some Aspects of the various systems which have key implications to installation The TLWP was installed in three distinct stages as follow :Stage1 - A field dedicated multi-use mooring system was installed followed by installation of the drilling template, allowing drilling operations to commence from a semi-submersible drilling vessel (SSDV). This was performed in June/July,1987.stage2 - The drilling operations were temporarily suspended, the drilling vessel moved off location, and the TLWP foundation template was installed with a large semi-submersible crane vessel (SKY). After template installation in August/September, 1988 the SSDV was Brought back in to resume drilling operations.Stage3 - After drilling operations were complete, the SSDV permanently moved off, and the TLWP was installed. This operation Was performed in June/July, 1989. The following text summarizes some key events And considerations in the three stages with particular focus also on the various planning and preparatory work that was involved in this job

VESLEFRIKK FIELD DEVELOPMENT CONCEPT ABSTRACT This paper gives a brief description of the Veslefrikk Field development concept, from the start of the conceptual phase to the construction and start-up phases. The different main contracts are described as well as some challenges and experiences gained duringthe execution of the Project. FIELD HISTORY AND RESERVOIR The decision to develop the field was taken in 1986, just as the oil price had suffered a dramatic drop. As a consequence of this, the field had to be developed to meet a low oil price. Veslefrikk is located in block 30/3 situated 145 km west of Bergen in WestNorway, and close to the Oseberg Field. Statoil was appointed as operator in 1979, and the first oil was found in 1981. The field was declared commercial by Statoil in the autumn of 1986. The owners of the field are:(Available In Full Paper) The reservoir is estimated to contain 36.4 million m3 oil and 4 billion m3 gas. The detailed engineering started in October 1987; the production start-up was 26 December 1989, that is to say 27 months later. The daily production is estimated to be 10.000 m3 oil (65000 bbl/day) and 1.5 million m3 gas. The field will reach peak production in 1990. After 3 to 5 years the output will decrease and the production will come to an end after 20 years. Thewater depth at the field is 174m. The reservoirs are located at the depths of 2800 m and 3050 m. The total number of wells is 18 of which 11 are producers and 7 are injectors. PROJECT PLANNING Studies for development of the Ves1efrikk Field were started in the autumn of 1985. Because of a water depth of 174m a whole range of field installations were studied. During the spring of 1986 theoil prices fell drastically presenting a new challenge in the development i.e. tomeet an oil price down to 12 USD/bb1. The following 3 main concepts were evaluated in detail:Integrated process, drilling and quarters platform like Statfjord and Gullfaks, but downscaled.Floating production platform connected to a fixed drilling platform of steel or concrete.Subsea wells linked to a floating production platform. During technical and financial evaluations the integrated process, drilling and quarters platform turned out to be more expensive for this field compared to the selected alternative. The floating production platform was evaluated with two options, one as a purpose-built platform, and the selected alternative with conversion of an excisting rig. The selected alternative showed a cost saving and also a schedule saving of one year. As a result of these evaluations the optimal solution appeared to be drilling facilities supported by a steel structure in combination with a floating production and quarters unit see figure.