With world-class experience and capability in metal additive manufacturing (AM), Siemens is introducing this game-changing technology throughout the entire gas turbine portfolio. Today Siemens Gas and Power has a dedicated organization to implement and adopt this technology, which enables engineers to design new components free of the barriers and constraints of conventional manufacturing methods. A product like the SGT-A35 (Industrial RB211) gas turbine, which has earned a dependable reputation worldwide in offshore applications, has been enhanced in several ways by additive manufacturing. This paper will explore some of the AM development efforts for the SGT-A35, as well as the many benefits being realized. These benefits include improved reliability and performance, manufacturing and supply chain simplification, faster iterations and shortened development programs and opportunities for new repair and aftermarket solutions.

Floating liquefied natural gas (FLNG) solutions are built from matured oil floating production, storage and offloading (FPSO) technology, primarily to monetize stranded offshore hydrocarbon reserves by locating a floating production system at the offshore reservoir location. The wellhead gas is brought from subsea completion systems and manifolds to the topsides of the FLNG vessel for oil/water/gas separation, where needed, and gas pretreatment and liquefaction. FLNG solutions are also being considered for exporting nearshore gas reserves or gas from an on-land pipeline network by locating the liquefied natural gas (LNG) production facility near the shore. The larger on-land baseload LNG export production plants require significant capital and take four to five years to be brought online. The FLNG concept provides a faster way to build a small-scale to midscale LNG production facility nearshore in protected waters and/or dockside and provides flexibility for progressive project development and variable LNG sales commitment volumes. Liquefaction production capacity is generally governed by the size of the reservoir, gas availability and the strategy to export LNG (volume). The quality (composition) of feed gas brought onboard will dictate the complexity and cost of the FLNG facility. Raw gas from the wellhead may contain a large amount of liquids and condensate and heavier hydrocarbons (rich gas), while a pipeline gas from the onshore pipeline network may be very lean. The FLNG facilities for processing and liquefying raw gas could be complex and expensive. Lean gas does not require complex systems. However, in both cases, with a simple single mixed refrigerant (SMR) liquefaction technology, the facility can be cost-efficient, faster to build and easier to operate. Several innovative, low-cost and game-changing FLNG configurations have been conceived based on the space-efficient and simple-to-operate liquefaction technology – PRICO ® SMR – for both offshore and nearshore applications. The simplicity, flexibility and scalability of this process allow a wide range of liquefaction capacities in a unique single- or multiple-train configuration. These configurations include new-built carriers and conversion of existing LNG and bulk carriers. This paper covers the development of innovative FLNG solutions, including all critical systems and other aspects of the technology and their impacts on the configuration of these solutions, offshore or nearshore.

Renewable energy sources, such as solar and wind, are attractive energy sources for the Oil & Gas industry, particularly in remote or off-shore applications. The challenge with these energy sources is that they cannot provide a steady, reliable source of energy on their own. To date, most systems rely on large battery banks or oversized generators to supplement the renewable power. The shortcomings include cost, size, weight and maintenance. Tetra West Technology has conducted a series of technical studies in order to optimize the integration of renewable energy, back-up power generation, and battery storage. These design studies have resulted in development of a system which maximizes the use of the renewable energy source, minimizing the required battery capacity, and further minimizes operating time and size of the back-up generator. Advanced integrated power management techniques can achieve 35% savings for a given solar application while assuring 99.999% power supply reliability, including remote land or off-shore locations. Integrated power management systems can be sized for a wide range of power requirements, allowing maximum benefit of renewable power – particularly when managing motor start or short term surge power requirements. These advances in power system integration are scalable and can be applied to a wide range of applications – from small remote pumping stations to large off-shore facilities. Employing components proven for these environments, an optimized integrated power management system provides a high degree of both system and power delivery reliability. With proper system sizing, these integrated systems can assure low cost and high reliability energy in a wide range of applications.

Abstract The inspection of unbonded flexible risers poses a number of challenges several of which are linked to the complex nature of the pipe's construction. This precludes the application of most conventional inspection techniques. Further difficulties arise because in many cases the critical region of the riser is at the top end; from the splash zone to the termination. This area is particularly congested where the presence of the bend stiffener and I-tube structures means there is no access for inspection equipment. This paper describes a unique inspection approach which overcomes these challenges and its implementation on an FPSO operating in the UKCS by Shell. The inspection technique concerned employs electromagnetic stress measurement technology that when mounted onto the external surface of the riser can sense into the riser construction and measure the stress in the tensile and pressure armour wire layers, the primary load bearing elements within the riser design. From this information the integrity of these layers such as the presence of wire breaks can be determined. A key feature of the approach is the concept of ‘reach’. As the layers within the pipe wall are unbonded the effect of a wire break can be seen many metres away from the location of the break itself: so an inspection at a single location can determine the state of the riser armour wires over the complete length of the critical top section. The application on the FPSO formed part of Shell's riser integrity management and life extension programme. A simple scanning device was deployed allowing a stress measurement probe to sense the state of all of the armour wires in the riser from a single point in the turret region. The results of the scan demonstrated that the armour wires of the riser were in a sound condition for continued service. This paper will provide the background to the underlying technology and its embodiment within an inspection system, together with the results from the inspection campaign.

Abstract In certain parts of the world it is highly relevant to use spiral welded pipes for offshore applications. This is driven by cost, project characteristics and the desire to manufacture the pipe close to where it is to be used. Spiral welded line pipe has been used extensively for onshore applications, however there has been some reluctance to specify spiral welded line pipe for offshore applications. A joint industry project is beeing carried out together with coil manufacturers, pipe manufacturers, installation contractors and operators to review the status regarding offshore applications for spiral welded pipes and identify the most critical technology gaps using a technology qualification process. Detailed suggestions as to how the gaps can be met have been made. An update on efforts to close these gaps is ongoing. The challenges for spiral welded line pipe include design, metallurgical and quality control issues. The design issues include fracture arrest, collapse and displacement controlled loading conditions which are all highlighted in DNVs standard for submarine pipelines (DNV OS F101). The design issues regarding load controlled displacement are mainly due to limited experience with spiral welded line pipe subjected to large strains. For running fracture the limited experience with spiral welded pipe for offshore applications is an issue. There are 5 new spiral welded pipe mills in United States so availability has improved. The review includes an assessment of typical pipe material test results and whether properties required for offshore applications can reasonably be expected. Introduction Det Norske Veritas (U.S.A.), Inc. (DNV) and MCSKenny are carrying out a joint industry project (JIP) to investigate the suitability of spiral welded pipe for offshore applications. It appears that the industry has a general understanding that the performance of spiral welded (SAWH) pipes is different to Submerge Arc Welded (SAWL)/ High Frequency Welded(HFI)/ Electric Resistance Welded ERW linepipe when exposed to the same loading conditions, and that currently existing design standards for offshore applications may not be applicable. An important issue is to establish how the spiral wound linepipe can be produced consistently to a high level of quality, and what is required by the design standard for spiral welded pipe to be fit for purpose for offshore use. Some of the main areas of concern regarding the quality of spiral wound linepipe will be discussed. The aim is to assess whether SAWH linepipe can be considered equivalent to SAWL and HFI/ERW linepipe. The use of spiral welded linepipe (SAWH) for pipelines has generally been the most popular manufacturing choice of linepipe for onshore low pressure pipelines, pipelines transporting water, ship borne piping, or very shallow water, low pressure pipelines (= 500 ft). Recently there has been more interest in the use of spiral wound linepipe, due to the following reasons: There are five new SAWH pipe mills in America with "state-of-the-art" technology. SAWH linepipe is a cost-effective solution compared to the other manufacturing processes. Generally, the chemical compositions, mechanical properties and dimensional tolerances are assumed to be comparable to SAWL pipe. SAWH linepipe can be manufactured in 80 ft lengths with diameters from 20 to more than 100-inch OD and wall thicknesses ranging from approximately 9 to 25 mm. Some SAWH pipe mills have coating capabilities for 80 ft pipe lengths (FBE and 3-layer coating systems). 80 ft pipe lengths could mean less fabrication costs for the installation contractors.

Abstract The world wide market for LNG continues to grow rapidly. Traditionally, base load LNG plants have provided the majority of this LNG supply. As the industry has grown, base load plants have grown increasing larger and more difficult to site. Additionally, the number of fields with sufficient reserves is diminishing. Owners are now turning to developing mid-scale projects with Floating LNG production systems. A variety of configurations have been put forth and a few are progressing. The single mixed refrigerant process offers an excellent approach to developing the topsides process units required for LNG production. With real estate on floating structures at a premium, compact, modular facilities are a must. The SMR process is readily modular and scalable to fit the production profile of these projects. Modular concepts from 0.5 MMTPA to 6.0 MMTPA have been developed to fit both tanker retrofits and new build ships. Also, the process offers significant reduction in equipment and power versus expander based processes. This paper will cover the technology as applied to floating structures with emphasis on efficiency and footprint for a variety of feed gas applications. Offshore Process Requirements LNG production facilities to date have all been onshore locations. While many of the same processes are used for both onshore and offshore locations, the requirements for offshore developments are unique to this environment. Some of the key criteria include: Minimizing footprint- Offshore real estate is the critical item in project cost. The minimization of the footprint of the process plant is essential to developing an economically attractive project. Minimize equipment items- The key objective for the process units to achieve an optimal footprint is to minimize the number and complexity of the equipment needed. Single mixed refrigerants produce the lowest equipment count of all processes. Minimize weight and single module lift weights - The cost of structures to support the equipment and modules is a key cost item. Also the lift weight of the individual modules is critical. Minimize module interconnections- The simplification of processes to minimize interconnections reduces the cost and complexity of the installation. Multiple loop refrigeration systems suffer from extreme numbers of interconnections between the loops. Accessibility- The offshore process systems must be accessible for maintenance and egress Flexibility to handle multiple feed gas cases- Onshore developers have learned (some the hard way) the liquefaction processes need to be able to handle a range of feed gases. Single mixed refrigerants excel in this area due to ease of changing the system during operation.

Abstract The lastest discoveries of oil and gas reserves in the Brazilian offshore area present new challenges on gas transportation due to their location, far away from the coast. For these new scenarios, Floating Liquefied Natural Gas (FLNG) units may be a good solution for a natural gas volume production around 2.5 MTPA. It is worth saying that this technology hasn't been proved yet. So, there are many challenges to overcome to turn the FLNG into an economically and technically feasible solution for these new scenarios. One of the main challenges for establishing a LNG (liquefied natural gas) offshore unit is the definition of the liquefaction process technology to be used. Characteristics such as motion effects, footprint, robustness, operational flexibility and asiness, safety, maintenance and availability must be considered when the main differences between the processes are being identified. Depending on the capacity to be attended, liquefaction processes may use hydrocarbon refrigerant mixtures or inert refrigerant fluids. Due to the environmental conditions in Brazilian waters, side-by-side offloading operations are not possible, as the operational availability would not be large enough. Therefore, LNG offloading would only be achieved through the tandem operational mode. Since the technology available for this kind of operation uses aerial hoses, it will be necessary to provide a bow loading system (BLS) installed on the LNG carrier and also a dynamic positioning system (DP) may be needed for an accurate control of the positioning and maintenance of a relative heading. The study indicates that the cargo containment system (CCS) should fulfill some constraints: let free upper deck area for topsides facilities; withstand any partial filling condition (sloshing impacts); have a good track record; and its configuration should allow inspection and maintenance in the offshore environment. This paper reports the Petrobras findings on the evaluating of the FLNG technology. Petrobras considers the FLNG unit an attractive option for its scenario, although many sub-systems still present important challenges in order to achieve a good overall performance. The choice of the best technology for each sub-system is still on-going, aiming the largest reliability and the minimum cost possible. Introduction The international natural gas market has been growing at a very high rate in the last decades. The mature technologies for natural gas bulk transportation are pipelines and the LNG considering a supply chain based on onshore liquefaction plants and LNG carriers. The natural gas consumption in Brazil has been growing since 2000. The Brazilian Government's goal for the natural gas participation in the energy matrix is 10% by 2010. PETROBRAS is the main company for Natural Gas (NG) production, transportation and supply in Brazil.

Description of the Proposed Paper: The paper will be presented using a combination of live interactive graphics, and PowerPoint slides with embedded AVI movies. The paper will reflect some activities of an ongoing offshore project in the US GoM. The "natural" way to visualize a complex subsea installation project from the procedural stage, through systems integration tests (SIT) and finally during the offshore installation sequence is preferably in 3 dimensions (3D). Project teams build real-scale models and execute a full system integration tests to visualize and hence better understand the nature and scale of the project through its various stages of development. It's more than a human comfort zone; it's a fast track to better understand and be able to gauge the interaction, the potential clashes and the relative distances between elements in the installation scene. During the presentation we will demonstrate several innovative interactive methods for the simulation of procedural sequences in 3D for complex SCR, PLET and jumper installations. We will also move to the next stage, where this approach is used as part of the real-time installation operation offshore where it is integrated with real-time vessel and subsea equipment positioning. A particular focus will be given to the benefit of integrating 3D visualization with a true geographic coordinate system and the use of accurately dimensioned 3D models of subsea hardware. A further integration of 3D visualization with engineering software for full SCR catenary analysis and display will also be discussed and the benefits to the engineer and project teams reviewed. Application Both 3D simulation and real-time 3D visualization (i.e., 4D) has been used recently in multiple offshore applications. The applications highlighted within this paper are primarily related to Construction Installation Services (CIS), System Concepts and Field Development Evaluation Selection (FDE). In summary the applications are: Development of interactive 3D procedures in a dynamic graphic environment offering the viewer control and the ability to create 3D procedures linked to standard written procedures, related drawings, AVI movies and other related procedural documents. The final 3D procedure is delivered on a CD or published via a network server for true multi-user viewing on a standard PC. Display of subsea field installation operations in 4D during SCR, PLET and jumper installations. This includes SIMOPS with multiple vessels, multiple ROVs and multiple down lines in the water column. Results, Observations, and Conclusions Recently, the use of 3D visualization has become an accepted method in everyday life ranging from 3D engineering, to graphics in education and for entertainment with computer games. Its power to depict the spatial relationships of physical objects and technical sequences is intuitive and unrivalled. These real benefits are now being used for complex offshore subsea installation projects on a global scale. The use of real-time visualization for a subsea installation involves a combination of detailed engineering information, real-time offshore positioning technology, both surface and subsurface, all within the context of a real world coordinate frame. All this information is worked within a dynamic computer graphics environment.

Abstract Written and presented to be in keeping with the theme of the 2003 Offshore Technology Conference, ENVISION - ENABLE - ENACT, this paper speaks to a broad application to more conventional offshore drilling of the tools and technology one normally associates with underbalanced drilling (UBD). The specialized tools developed primarily for the safe practice of UBD are first and foremost wellbore pressure management tools and when applied to more conventional overbalanced drilling in marine environments have significant positive Health, Safety, and Environmental (HSE) implications, may lower overall spread sheet costs, and in some cases, render -economically undrillable wells-viable prospects. Underbalanced drilling and conventional well control are similar technologies. That is, the well is shut in against pressure in the wellbore and the well is circulated through a choke. Most of the challenges (barriers to economically drillable wells and a litany of drilling related issues) facing the shallower and deeper water wells have well control implications, either directly or indirectly. Managed Pressure Drilling (MPD) is the term given when the use of UBD technology and its specialized equipment is deployed for the purpose of overcoming a number of drilling related barriers or problems commonly encountered when drilling overbalanced. Additionally, MPD facilitates Low Head (near-balanced) and balanced drilling. An important point presented in this paper illustrates that offshore practice of MPD has the potential to enhance well control in the process with an enhanced ability to avoid underground blowouts and may add an additional barrier (in well control terms) for HSE benefit. Envision - Visualize the barriers to economically drillable wells and the litany of drilling related issues facing shallow water drilling from rigs with surface BOP's, in deep water from floating rigs with subsea BOP stacks, and the practice of slim riser deepwater drilling with surface BOP's. All of these challenges either directly or indirectly have the potential to have a detrimental impact on well control, some more so than others. Enable - Specialized tools developed for UBD, when used onshore and offshore, enable full time -well control-, as in underbalanced drilling the well is -live- while drilling ahead. Often UBD tools are used to overcome drilling and formation damage issues when drilling more conventionally, and the industry has found that doing so has enabled a significantly better well control track record compared to wells drilled without the benefit of any of the tools developed for the safe practice of UBD. Enact - UBD equipment has been applied to many tens of thousands of onshore wells over the past 30 years. Offshore from rigs with surface BOP stacks, over a hundred have been drilled underbalanced or nearer balanced than could have been safely practiced otherwise. One well has been drilled underbalanced in deep water from a floating rig with a subsea BOP. As offshore hydrocarbon resources deplete and the need to drill in deeper water grows, more wells will be drilled underbalanced in the future, as that will be the only technology available to do so.

Abstract While technological advances within the energy industry have made dramatic improvements in lowering the cost of finding, producing and refining oil, vast quantities of remote and stranded gas still wait to be developed. Emerging gas-to-liquids (GTL) technologies may play a significant role in helping oil companies develop and monetize these resources. These factors are particularly important to offshore applications given that roughly half of the world's stranded gas is located in water. This paper will consider potential offshore gas reserves that could represent applications for GTL technology. It will also examine current GTL process developments and their significance relative to offshore petroleum operations, including discussion of air-based vs. oxygen based GTL systems. In conventional synfuel processes, syngas is generated from natural gas via partial oxidation with oxygen, requiring an air separation plant to provide the oxygen. In these approaches, nitrogen is eliminated from the synthesis gas stream as an unwanted inert. In an air-based system the syngas step, by contrast, uses air-carried oxygen, rather than eparated oxygen, to produce a nitrogen-diluted synthesis gas. This eliminates the expense of an air separation plant needed to produce oxygen used in typical plants. It thus reduces capital costs, making possible plants with considerably smaller footprints, and also provides for a safer operating environment. In addition, this paper will examine some of the strategic implications facing the petroleum industry from the growing potential of applying GTL technology. Introduction At the close of the 20 th century, in spite of all the scientific and engineering achievements that have been made in the energy industry, we have left behind a vast storehouse of remote and substandard gas reserves. Estimates published in Oil & Gas Journal indicate that discovered global reserves of natural gas exceed 5,000 trillion cubic feet. It is estimated that over half of these reserves are considered stranded-largely unmarketable because of prohibitive costs of transportation to market. It is further estimated that over half of these stranded reserves are located in water. Against this backdrop, and apart from current low oil prices, the petroleum industry faces a number of challenges, including environmental mandates for cleaner fuels, raw materials getting heavier and dirtier, process upgrading investments more difficult to justify, tightening supplies for middle distillates and naphtha, surging demand for clean fuels for power generation and transportation vehicles, and most of the reserves of the cleanest fuel-natural gas-too remote for economic delivery to market. In this setting, economical GTL is an event waiting to happen. GTL could turn unmarketable reserves of natural gas into a form that overcomes prohibitive transportation costs, avoids long--term, high-risk, take-or-pay contracts, and helps satisfy the demand for cleaner liquid products. It could help recover some of the sunk costs in offshore gas finds that have yet to be monetized. Hence, it is among these combinations of incentives and threats that the petroleum industry is looking closely at the new generations of GTL technologies to 1) provide profitable ways for monetizing reserves they already have discovered but are currently worthless, and 2) respond to growing market demands for cleaner fuels that are becoming more expensive to meet with conventional oil. Given the huge quantities of natural gas that reside offshore, many oil companies have focussed attention to the possibility of utilizing GTL technology in the marine environments. Taking any form of new process techn

Abstract Hydrocyclone-based systems for downhole separation of produced oil and water and subsequent disposal of the produced water by reinjection within the same wellbore have been successfully applied in a number of onshore wells. Benefits of these systems include reduced produced water lifting and disposal costs, as well as significant reduction in liquid load on surface processing facilities 1 . Reduction in surface equipment requirements is of primary interest in offshore applications, where significant reduction in the size and cost of surface separation facilities promises to extend field life and make marginal developments economically viable. Further development of downhole separation and reinjection systems is under way in order to provide a range of hardware systems suitable for a variety of offshore applications. Introduction Initial onshore installations of Downhole Oil/Water Separation (DOWS) systems were designed to prove the concept with off the- shelf pump and hydrocyclone designs, and included only minimal downhole instrumentation. Target wells were often of little value, with low oil production and very high water cut. The successes achieved using this approach have proven the viability of the system, and a significant number of systems have been installed based on their commercial merit. 2,3,4 Failures to date have highlighted limitations of the initial hardware design and well selection criteria, indicating areas' where further development is required. Owing to the increased financial risk involved with offshore application, significant development has been undertaken to increase the success rate and commercial benefits of the system. An analysis of applications to date, including both successful and unsuccessful installations, has allowed understanding of the reasons for success or failure. Current and planned development activities include improvements in durability of the pump/separator system, improved hydrocyclone separation performance, improved application screening methods, application of downhole instrumentation and control systems, development of higher capacity systems, and development of completion designs for reinjection of water either uphole or downhole from the producing zone. DOWS Systems - Basic Configurations There are a variety of downhole separation systems in use today, including systems for gas/liquid, liquid/solid, and liquid/ liquid separations. A range of separator types are employed, including in some cases the wellbore itself as a gravity separator. This paper relates specifically to high volume (2,000 to 25,000 bpd) oil/water separation systems using centrifugal separators. Downhole centrifugal separators have also been employed with Rod Pumps, but these are not considered economic for offshore application and will not be discussed in detail. ESP DOWS. Fig. I illustrates the most common configurations where Electric Submergible Pumps (ESPs) are used. For the purposes of this paper, an ESP is defined as a downhole, multi-stage centrifugal pump, driven by a downhole electric motor. Production is drawn into the Injection Pump, which boosts the pressure and feeds the separator. The separator divides the liquid into two streams: a concentrated oil stream to be lifted to surface; and an oil-depleted water stream for injection into a disposal zone. The water stream flows through the injection tubing string, past an isolation packer, and to the injection perforations. The oil stream flows through a channel (normally consisting of 2 or 3 small diameter tubes) which routes the flow around the pump and motor, and to the production tubing.

Abstract Flexible piping systems are critical elements in the design and operation of floating systems for offshore oil and gas production. Applications are "static" or "dynamic." staticapplications involve the use of flexible pipe to simplify design or installation where there is no, or, little, relative movement between supply and delivery points. Dynamic applications involve relative motion between supply and delivery points. These applications usual involve an offshore floating production system. Dynamic piping is currently provided by special designs using steel, titanium, or flexible pipe systems. Each system has its strengths and weaknesses. The forces that drive a particular design strategy are weight, strength (pressure and tensile), collapse resistance and corrosion resistance, operating and component costs. As operations move into deeper water the performance specification for flexible piping systems are becoming more severe. Future design conditions are expected to include: Operating pressures to 690 bar (10,000 psi) Temperatures to 145°C (300°F) Depths exceeding 1,500 meters (4,920 ft) Extremely sour production fluids The importance of these systems is evidenced by industry activity. There are a number of joint industry projects (JIP) and manufacturer-funded research programs to develop lightweight, high strength flexible pipes, or riser systems. The driving force in these developments are weight reduction, enhanced corrosion resistance and means for predicting /monitoring fatigue life of the product. None of the programs currently underway take advantage of the full potential of an emerging technology such as that offered be advanced composite spoolable tubular. This paper will discuss the progress of a JIP m Identifying applications and design specifications, and test results for qualifying spoolable non-metallic structures that may offer nabling technical and cost advantages as replacements forflexible pipe in offshore applications. Introduction Conoco Inc. began to develop high performance, spoolable composite pipe technology in a program that started in 1988. The original focus was on corrosion-resistant water injectionlines and later evolved to a J.5-in. OD composite coiled tubing service string 1 . The development effort led to a composite tube design formed by surrounding a thermoplastic liner with a high strength fiber and epoxy matrix structure. The fibers utilized include glass, carbon and aramid. The advantage of a composite spoolable pipe over steel pipe is that it can be "engineered" for particular applications to take advantage of the composite's enabling attributes. These attributes includecorrosion resistance, high strength to weight ratios, high working pressure capability, excellent cyclic fatigue resistance and low material density. In fact, the current composite tubing designs weigh in at 25 to 33% the weight of a like OD steel tube in air and are 14% the weight of steel in water. This obvious advantage allows longer and larger strings of composite tubing to be handled by coiled tubingunits of lower pull capabilities or lifted onto offshore platforms with smaller crane capabilities 2 .

Abstract Since 1993, Devonport Management Limited (DML) has been developing techniques for strengthening, modifyirrg and repairing existing steel structures using composite materials. Composites were first used for such applications in the defence industry where a number of successful warship strengthening and repair projects were carried out. In developing techniques for use to the offshore industry much importance. was placed on the development of in-situ application methods that did not require special environmental controls or process equipment, A further consideration was to validate the performs of both the composite materials and modified structures in order to demonstrate the suitability of the composite reinforcement to regulatory and certifyin authorities. The first major offshore project has now been completed successfully turn this has led to the creation of a Joint Industry Product to widen the range of situations where composites can he considered for strengthening, modification and repair (SMR) such structures. This paper presents the background to the requirement for SMR, explains the advantages of composites, provides some case study information and describes the joint industry initiative to widen the use composites in SMR. Introduction There are now almost 250 offshore installations in the UK waters. The average age of these structures is more than 15 years. Many of the structures are reaching the end of their original design life. Improved hydrocarbon recovery, the need reduce costs by utilising existing infrastructure in the development of new fields, and the need to re-consider the adequacy of existing structures during the preparation of the safety cases which was required for every UK installation following the Piper Alpha disaster, have led to a requirement for strengthening, modification and repair (SMR) of existing installations to: epair damage (fatigue or corrosion) to existing structures to allow the life of an installation to be extended. Modify (which might include repair and strengthening of the existing structure and the addition of new structure existing structures to allow the incorporation of new equipment. Strengthen existing structure to cater for additional load cases that have been identified during the preparation of the safety case e.g. blast loads. The usual methods available to carry out such work have been strengthening using welding or bolting, Recently, however, composite materials have been used for such work. The composite materials are usually based on one or more types of carbon fibre either an epoxy or a vinylester resin. Trials programmes have been completed successfully for two operators, whilst one major offshore strengthening project has now been successfully completed. A Joint Industry Project (JIP), jointly undertaken by DML and MSL Engineering Limited, is now underway with the aims to develop materials data, validated design tools and a Design Guide to allow wider use of composites in offshore applications. The composite materials, which have led to their selection for the above projects and to the JIP initiative, compared with more traditional SMR methods, are initially discussed below.

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 manua1 2 : Cold formed and welded members Classification of cross-sections and local buckling behaviour Resistances of beams, columns, beam-columns and tie members Beam deflections Bolted and welded connections Fabrication aspects Fatigue aspects A 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 6% Mo austenitic stainless steels are increasingly being used in the offshore industry as a construction material for handling seawater and hydrocarbon/seawater mixtures containing hydrogen sulfide. The paper describes the specific investigations conducted on the various components relates to the Saga Snorre project for their corrosion and metallurgical characteristics. Over 1,000 tons of seamless/welded pipes, forgings, large radius induction bends, and various fittings were manufactured and tested. Corrosion behavl0r under hydrogen charging condition and chlorinated seawater were also studied. The paper discusses suitability of the alloy for conditions prevailing in the Snorre field of Saga Petroleum, at approximately 150 Km off the Norwegian coast. INTRODUCTION Materials used in the offshore industry encounter numerous corrosion and mechanical problems. They consist of submerged and atmospheric marine corrosion, mechanical stress (static and/or dynamic) due to wind and mechanical wave action and marine fouling. Unfortunately, many other factors, other than the mere considerations of corrosion resistance in so-called "normal seawater" have to be taken into consideration when making material selection. This applies in particular for piping systems. These include: oxygen content (aerated/deaerated fluids) presence of wet CO 2 presence of H 2 S and other sulfur compounds chlorination used to control biofouling crevice corrosion conditions stagnant conditions galvanic interaction in presence of dissimilar metals cavitation, erosion and abrasion due to velocity effects environmental embrittlement temperature effects stress effects produced brine and seawater salinity The seawater temperature and salinity can vary widely from 2°C (36°F) in the arctic to 30°C (85°F) in the tropics to 46°C (115°F) and higher at the outlet of some condensers. The salinity can vary from dissolved salt content of 7 g/kg in Baltic to 43 g/kg in the Persian Gulf. A seawater piping system consists not only of pipe (seamless and welded) but other accessories such as pipe spools, pipe bends, reducers, flanges, return bends, tees, elbows, pumps, valves and metering devices. The important properties governing proper material selection are: resistance to various forms of corrosion, especially localized corrosion and stress corrosion cracking. physical and mechanical properties (coefficient of thermal expansion, thermal conductivity, tensile properties, erosion resistance, low temp. toughness) galvanic compatibility good fabricability and weldabi1ity resistance to marine growth availability of various product forms successful case histories costs A careful study of the above factors must be conducted prior to making a material selection. MATERIALS FOR OFFSHORE APPLICATION A large amount of data concerning behavior of materials in seawater has been generated over the last few decades and is well publicized in technical literature. These include uniform corrosion, pitting/crevice corrosion, galvanic interaction, fatigue, stress corrosion cracking, erosion-corrosion and others which aid in intensifying the corrosion damage such as velocity effects, weld decay, fouling and heat transfer. Even though the precise determination of all corrosion variables as relating to offshore marine corrosion is not available, there is ample laboratory, field and case history experience available to make cost effective and

ABSTRACT High-alloy stainless steels and nickelbase alloys offer great potential in revolutionizing well completion design by increasing allowable stress levels, removing corrosion inhibitor systems, and basically making it possible to do operations, not possible using conventional technology. Further, substantial savings in weight and space for deck equipment can be accomplished. The role of corrosion resistant alloys (CRA) for deep gas wells has become well established. Better understanding of the corrosive behavior of H 2 S / C0 2 / brine environments at high pressure and temperature, and the performance limitations of certain materials of construction, has translated into improved operation and high equipment reliability. Guidelines in alloy selection and a number of case histories will be presented to assist the design engineer. The completion string of an oil or gas well is the heart of a production facility, and its safe and reliable operation is critical to the overall profitability of a field. In many offshore applications CRA's can be economically justified as an alternate to carbon steel with continuous corrosion inhibition. Repairs to the completion system often run into millions of dollars. It is desirable to decide on the use of CRA tubulars for downhole, sea water and product piping systems in the early development of an offshore field, especially in deeper waters. INTRODUCTION It has taken the oil and gas industry three years to convince itself that OPEC is serious about $15-$18 a barrel oil. Operators have now adapted and are increasing their budgets to find ways to bolster rapidly depleting reserves. All signs point to increased activity in 1989-1992. A growing share of world oil and gas production is now obtained from offshore areas. Innovation on know-how and new concepts for field development have been the key phrases. This is a time for new opportunities. Stainless steels and nickel-base alloys are increasingly applied for exploitation of sour crudes in order to provide high reliability and low maintenance cost. Increased safety and reduced equipment weight are additional advantages. And as water depth increase and wells become more critical, their use will intensify. These sour crudes, containing considerable quantities of H 2 S, C0 2 and salted formation waters, show a high corrosivity with respect to general corrosion, to localized pitting and crevice corrosion, and to stress corrosion cracking by sulfides (SSCC), by chlorides (CSCC), or by their combined action. Traditionally, corrosion resisting alloys (CRA) are used in oil and gas production as a last resort when protective coatings, cathodic protection or corrosion inhibitors prove to be inadequate. Examples of these are development of .deep sour gas wells, C0 2 enhanced oil recovery, and with in-situ fireflooding operations. This is an undesirable practice, particularly for offshore installations where the decision for utilization of CRA should be made in the pre-engineering stage. Full advantage should be taken of the higher allowable stress levels of downhole tubulars and of saving weight in platform deck and support structures by utilizing CRA for process and fire-fighting piping.

ABSTRACT Combining their specific knowledge in the fields of lightweight materials technologies and the oil industry, Aerospatiale and l' Institut Francais du Petrole (IFP) have been conducting research and development programmes on high performance composite tubes for offshore applications since 1978. Their experience in terms of research and development achievments, technical alternatives and cost effectiveness is addressed in this paper. The technica1 aspects are introduced through a series of typical oilfield tubular applications describing design and test results. Advantages and potential cost savings resulting from the replacement of a conventional steel riser by a composite riser are analysed for a TLP in different water depths, combining the effects on cost of top tension, deck weight, hull size and mooring loads. INTRODUCTION With ever deeper waters, hostile and remote locations, the oil industry has always managed to adapt the offshore technology to new working conditions and design requirements, pushing back its own frontiers. During the last decade, offshore activities have grown fast, large capital and production costs being by that time offset by high crude price. In today's situation, development of offshore oil and gas reserves is a challenge demanding new technologies and materials to offer greater simplicity and higher reliability at a lower cost. To face such a challenge, lightweight, high performance composite tubes derived from aerospace techno logy offer one possible alternative. On drilling or product ion floating un its, the use of these composite materials results in a significant reduction in the equipment weight and deck load which then allows further reductions in the amount of material in the colunms and pontoons of the platform. In addition, excellent fatigue properties, capital and operating cost savings work in favor of these materials for future offshore applications. OBJECTIVES Composite materials made from carbon fibres and/or glass fibres set in resin have been in current use in the aerospace industry for many years. A joint research and development programme on high performance composite tubes was started in 1978 to study tubes made from these materials for specific applications in the oil industry. The main objectives of this research effort were as follows: to create a suitable design of advanced composite tubes, including end couplings, to develop a reliable manufacturing process for length up to 25 m (80-ft) and for large diametres, to demonstrate the general feasibility and good behaviour of composite tubes by a great variety of tests; static, dynamic fatigue, ageing, temperature, etc, in the case of weight sensitive structures to substitute current tubular goods by advanced composite materials. TECHNOLOGY High performance composite tubes are composed of several layers with independant functions. Structura1 1ayers made of high resistance fibres set in a resin matrix, are filament wound and consist of circumferential layers, perpendicular to the tube axis, to resist bursting stresses and longitudinal layers, helically wound, to resist axial forces.

ABSTRACT The design and the evaluati on of a submarine composite power cable with optical fibers, for application in offshore activity, are described here. The general design of composite cable and specific prob1ems of offshore application are analysed and lead to the proposed cable. The 1aboratory tests data and fie1d results are given including tests description. 1/ INTRODUCTION For many years, a lot of submarine cab1es, either power or telecommunication, were installed all over the world. Starting from our background, new development and know-how in long haul optical telecommunication links, and proven watertight power cable technology, we can propose a hew-design which increases reliability and lifetime of submarine composite cable links. After listing the needs and constraints in offshore application, we propose-a design for the cable and check its compliance with the above requirements (laboratory tests and field results). 2/ SUBMARINE COMPOSITE CABLE IN OFFSHORE 2.1 GENERAL The oil offshore production is increasing and its part in total world production was 20 % in 1979 and 28 %in 1984. In that way the installation of offshore platforms and submarine completions for production are more and more important and as the usual solutions for power feeding and telecommunication are: – Very costly like power group, – Not well adapted, on a technical point of view, like radiolink or microwave. – Or not applicable - in case of submarine completion, – The use of submarine cables is, in several cases, a good solution if we can propose: very high reliability and very long length for installation in deep water. – The world record up to now is about 400 m for submarine completion 2.2 MAIN NEEDS FOR SUBMARINE CABLE In that paper we present a submarine composite cab1e with a power part and an optica1 fibers part: – From some KV up to around 35 KV – From low to medium power – From one (single mode or mu1timode) to thirty six optical fibers (three optical modulus in angles). The target is: – Reliability - more than 25 years – Long unit length - more than 50 km, without any complete submarine junctions, – Laying in great depth - more than 400 m, – Easy possible repair on site in hazardous submarine surroundings 2.3 EXTERNAL HAZARDS During its life a submarine cable is subjected to a lot of stress. 2.3.1 Manufacturing stress Mechanical strain on the components during the different steps: of manufacturing but especially for optical fibers during laying up. 2.3.2 Transport and installation stress Mechanical and bending strain: – For winding and coiling up – For laying, possible recovery and jointing – For burying if requested

ABSTRACT The behavior and properties of ASTM Specification A710 Grade A Class 3 75 ksi (517 MP?) minimum yield strength plate steel are presented. A review of the historical development of this Cu-Ni-Cr-Mo-Cb steel and the metallurgical design of the alloy are reported. The results of production from 11 heats of steel resulting in over 400 plates up to 2-¼in (75 mm) thick are reviewed, indicating the high toughness and strength level of the alloy. More detailed studies are presented for 3 production plates. These properties included tensile, full Charpy-V-notch impact toughness transition and metallographic examinations. Additionally, the elastic-plastic fracture toughness properties of these plates are characterized using both J-1ntegral and crack-tip-opening displacement test methods. These properties were found to be as good, if not better than A633 Grade C steel. The fatigue crack propagation behavior of A710A-3 is found to be similar to A6-3C. A review of the'weldability of this steel is provided, which emphasizes that it is readily fabricated under shop or field conditions. The excellent properties of A710A-3, together with its higher strength and excellent weldability, supports its consideration for offshore structures, where weight savings, fabrication and service performance are most critical. INTRODUCTION Specifications ASTM Specification A710' Grade A(l) applies to structural, high strength (75 ksi {5l7 MFa} minimum yield strength), low carbon, copper precipitation hardened plate steels, which are finding increasing application in offshore structures because of their excellent toughness and weldability. A710A is part of a family of Cu-Ni-Cr-Mo-Cb steels, which have been identified by a number of designations over the years. During its early development in the late 1960's and first commercial production in 1970, the steels were known as IN-7S7*(2-4). ASTM Specifications were subsequently developed for structural (A7IDA) and pressure vessel (A736A) applications over 10 years ago. More recent interest and application of this family of steels by the U.S.Navy as a replacement for HY-SO (M1L-S-16216), has lead to the development of a military specification MIL-S-24645(SH)(5), also initially known as "HSLA-8O". Both A710A and MIL-S-24645(SH) can be produced in three classes, while A736A is available in only two classes. Class 1, as-rolled and aged plates are available to 0.75 in (19 mm) thickness in A7l0A and to 0.3125 in (7.9 rom) thickness in MIL-S-24645(SH). Class 2, normalized and aged plates are obtainable to 0.3125 in (7.9 rom) thickness in MIL-S-24645(SH), while there is no thickness maximum for A710 or A736. Class 3, austentized, quenched in water and aged plates are attainable up to 2.5 in (64 rom) thick in M1L-S-24645(SH), while A71DA and A736A have no thickness maximum. Because of thickness and application requirements, Class 3 plates are of primary concern in offshore structures. For abbreviation, these steels will be referred to as A710A-3 in the remainder of the paper, although differences with the military specification will be noted.

ABSTRACT High-alloy materials possessing good corrosion resistance in hot, sour brines are being seriously considered for offshore applications. These alloys are available in a wide range of strength levels which can be attained by the methods of cold working or precipitation hardening. Results of testing INCONEL* alloys 625 and 718 and INCOLOY* alloys 825 and 925 for resistance to general corrosion, hydrogen embrittlement, and stress-corrosion cracking (SCC) are presented. This paper also contrasts the range of mechanical properties available in precipitation-hardened materials with properties of coldworkedalloys. INTRODUCTION The severe environments presently encountered in intermediate-depth wells coupled with increasing costs of inhibition, particularly in offshore wells, have caused considerable interest in highly alloyed, corrosion-resistant materials 1 . To meet the high strength requirements, tubular products in nickel-base alloys can readily be produced with uniform properties via cold working processes. Wellhead and subsurface equipment frequently cannot be uniformly cold worked, thus creating a need for alloys that achieve high strength through a precipitation heat treatment. This study focuses on two precipitation-hardened alloys, INCOLOY alloy 925 and INCONEL alloy 718, plus two cold worked alloys, INCONEL alloy 625 and INCOLOY alloy 825. Basically, the four alloys represent two different classes of nickel alloys. Alloys 625 and 718 contain more nickel and refractory elements (Mo and Nb) than alloys 825 and 925, whose lower nickel contents place them closer to the iron-base alloys. The alloy classes will behave differently in differing corrosion environments. They represent varying levels of resistance to hydrogen embrittlement, SCC, and general corrosion. Table 1 shows the nominal compositions of the four alloys. MECHANICAL PROPERTIES Cold Drawn Tubulars. Mechanical properties are shown in Tables 2 (production tubing) and 3 (casing and coupling stock) for cold-worked tubular products. The minimum annealed yield strength of alloy 825 according toASTM B-423 is 30 ksi. Note that moderate cold working raises the yield strength to that of the higher strength API grades. Comparable reductions for alloy 625 produces an even greater yield strength increase owing to its higher work-hardening response. Properties of cold-worked alloy 925 are similar to those of alloy 825. Much concern 2 has been expressed about the effects of " well aging" (under the high downhole temperatures encountered in service) on the stability of highly coldworked alloys. Data in Tables 2 and 3 indicate that the mechanical properties of alloys 825 and 925 are only slightly affected by aging at 6000 F for 1000 hours. Precipitation-Hardened Product Forms. Alloy 925 was recently developed to provide high strength while retaining good ductility in both tubular and solid products. Gamma prime precipitation develops the desired properties in this alloy system. Table 4 compares the yield strengths of alloys 825 and 925. The same thermal treatment was used for both alloys, clearly demonstrating the higher strength capabilities of precipitation-hardened, alloy 925. In addition to providing an alternative strengthening mechanism to cold-working, precipitation hardening also provides an improved combination of strength and ductility for a given strength level.