INTRODUCTION Working underwater is a lot more difficult than working above water or on land, therefore the incentives to do so must be found in some aspects of project realization, such as reduced cost, advantageous schedule, improved technology In this chapter these aspects will be considered for a number of cases of floating systems and subsea developments which have been carried out The North Sea provides examples of floating systems, starting with Hamilton Brothers'/Argyll, and the development of the buoyant tension-legged platform of Conoco Hutton TLP in production in 1984 Subsea systems are complementary to existing fixed structures and increase the recoverability, for example, BP Magnus has seven satellite wells Subsea production began with the Zakum Subsea Production Scheme (1969–72) and now subsea systems are used m field developments in the North Sea, for example, the Shell UMC, Texaco Highlander and North-East Frig This chapter also discusses some prospective developments in applications, techniques and equipment. Other chapters in this volume will elaborate on many of the topics which will be raised. Early practitioners of the art of working underwater include marine salvagers and offshore drillers, and techniques which were developed for these activities are being elaborated and unproved upon for those more complex activities of offshore oilfield development Experience, and common sense, has taught that complicated construction work should be done as completely as possible on land before taking units offshore for installation, and that only minima1 assembly of pieces be required subsea Examples of subsea construction activities include well templates, manifolds, pipelines, multiple flowlines, anchor foundations, use of divers and remotely operated vehicles Prospects for the future of subsea activities are assured by the present keen interest in floating production systems and subsea satellite developments to be tied-back to existing installations The future North Sea development m the UK sector will be primarily smaller fields, satellite fields, condensate/sour gas Deepwater developments present greater challenges but, with the discovery of sufficient reserves, there is no doubt that these developments wtl1 also stimulate new requirements as well as new capabilities for underwater construction. ARGYLL FIELD The Argyll Field layout is represented in Fig 1, and the key information summary is presented m Table I The production riser system is of particular interest Production riser system The production riser system at Argyll is made up of standard drilling components assembled in what was a unique system, in 1975 The(Fig 1 is available in full paper) system consists of five basic elements from the sea bed upwards - the mass anchor, permanent base, manifold, risers and flexible connections. The central riser is of 10 in * nominal bore and serves as the main supporting member and export (or shipping) riser. This element consists of a stab sub-assembly, universal joint and SLX 40 ft* joints of 10 in riser pipe connected with standard marie riser joints.

INTRODUCTION The Occidental Consortium's newly developed "Scapa" field has now come on-stream as planned, some 14 months after Department of Energy approval The Scapa development consists of a major subsea facility connected to the Claymore platform, 3 miles* away by two pipeline bundles and associated control umbilicals (see Fig 1) The new topside facilities are connected in turn to the pipelines by a large bundle riser, carrying the produced oil and lift gas, with a facility for a utility if required The field is estimated to have recoverable reserves of 40 million barrels of oil with a gravity of 32 5 ° API to be extracted from a Lower Cretaceous reservoir The Scapa development had a considerable engineering content The main production riser and template each required a large proportion of this engineering for the installation design It was a requirement that all of the subsea work should be completed with one season. To accommodate this the contracts were broken down into elements template - fabricate and install, bundle - fabricate and install (Fig 1 is available in full paper) riser-fabricate riser-install These packages therefore gave the flexibility to maximize the offshore work programme involving vessel availability and installation capacity This chapter gives a short overview of Scapa's facilities and installation difficulties, together with a fuller description of the riser and template It should be noted with interest that the total weight of Scapa additions to the jacket is approximately 800 tomes, or 2 3% of Claymore's jacket and topside weight The structure's capability of accepting the extra load required verification FACILITIES Pipelines and umbilicals The template is connected to the Claymore platform by an extensive pipeline system, consisting of two 28 m * multi-line composite bundles, an 8 in water injection line and a 3 in bulk chemical treatment line, as shown in Fig 1 Each pipeline bundle is approximately 2 8 miles long and contains a 10 in. production line, a 6 in test/service line and three 3 in gas lift lines. The bundles are connected to the template manifold and the platform production riser by flexible spools. The two pipelines, which are the longest of their type to be towed to date, were installed using the mid-depth tow method. Using the natural buoyancy of the pipeline to raise the line off the sea bed and chains to control this flotation, the lines were towed using two tugs These tugs kept a set tension on the line during tow and the level of tow was varied depending upon the weather conditions. The towlines were attached to the bundles by specially designed tow heads These tow heads also served to splay the integral lines for accommodating the flange tie-in points. To confirm manual calculations, tests were carried out on a scale model of the tow head to determine.

INTRODUCTION The recent reduction in oil prices throughout the world has led to an increase in the number of offshore oil and gas fields attracting marginal status. The reduction has led many operators to reconsider the conventional offshore development scenario involving above-water production facilities and associated export pipelines. This revaluation has led to a significant increase in the number of subsea satellite developments, together with the accompanying transport and service lines tied back to existing production facilities. This approach often allows for maximum utilization of existing investments by the addition of further throughput achieved by a new, relatively low-cost satellite development Currently, the lack of available subsea process facilities-demands that wellhead flowlines be manifolded and extended back to the "parent" facility Typically, this may result in a number of flowlines between the satellite development and existing facility to provide services such as oil and gas production, well test, gas lift, and chemical and water injection Some examples of development schemes of this type currently in production or being constructed are as follows Texaco-Highlander Field tied back to Tartan (North Sea, UK Sector), Occidental-Scapa Field tied back to Claymore "A" (North Sea, UK Sector), Statoil Tommeliten Field tied back to Edda (North Sea, Nonvegan Sector), Mobil Ness and BBSWI tied back to Beryl "B" (North Sea, UK Sector) In contrast with conventional above-water developments, this new generation of offshore oil and gas fields may involve the installation of a significant number of small-diameter, relatively short-length pipelines This feature requires that the use of the conventional high-cost third-generation lay-barge, developed for deepwater installation of larger-diameter pipelines be re-evaluated Consequently, detailed consideration should also be given to alternative methods of pipeline installation Moreover, as the provision of pipelines forms a large proportion of the capital cost of a satellite development, it is necessary for the pipeline designer to evaluate carefully all available installation methods early m the design process, in order to identify the most cost-effective solution This chapter presents a brief review of the requirements for pipelines for this application of satellite developments, and the suitability of various pipeline design and installation methods GENERAL DESIGN CONSIDERATIONS Design requirements for traditional offshore pipelines are well documented and are not addressed here However, where multiple small-diameter pipelines are envisaged for satellite developments, special consideration of the following areas may be required during pipeline design. material selection, thermal insulation, installation - pipeline corridor requirements, tie-ins, deepwater installation and tie-in Internal corrosion may result from high hydrogen sulphide or carbon dioxide levels in the produced reservoir fluid However state-of-the-art technology relating to subsea process equipment is not yet sufficiently developed to influence internal corrosion in satellite field export pipelines Consequently, selection of more-exotic materials, such as duplex stainless steel or carbon steel clad with stainless steel, may prove to be more attractive than the use of an anticorrosion chemical-injection system.

A BRIEF HISTORY OF THE USE OF FLEXIBLE FLOWLINES Although flexible flowlines had been used earlier elsewhere with varying levels of success, the advent of their use in the North Sea occurred in the mid-1970s Early instances of their utilization in the North Sea occurred in Mobil's Beryl Field (1975), Shell's Brent Field (1976), Beryl (1978), Hamilton's Argyl Field (1979), Beryl (1979) and Chevron's Ninian Field (1979) These applications were almost invariably concerned with the transport of oil from subsea development wells to a central surface installation for manifolding, processing and export ashore. At about the same time flexible flowlines were employed extensively m the development of other offshore oil-producing areas, nota6lyTWest-Africa, Brazil, the Middle East and, to a lesser extent, in the Gulf of Mexico. SOME ADVANTAGES OF FLEXIBLE FLOWLINES In certain circumstances the use of flexible flowlines presents useful technical and economic advantages over the use of steel, or rigid, flowline In broad terms, these advantages become significant when connections have to be made over relatively short distances, and where the presence of surface installations, or subsea equipment, restricts the access of the laying vessel. The virtue of flexibility is a considerable asset when several flowlines have to be accommodated and connected in close proximity to each other, e g at subsea templates and manifolding centres. The technical benefits may be summarized as follows the ability to accommodate misalignments, it may be installed from small, manoeuvrable lay-vessels, the ease of installation in restricted areas, the ability to curve around obstructions, the ability to conform to an irregular sea bed, the ease of recovery for repair on the surface It is difficult to separate completely the economic from the technical implications, as one is frequently interdependent on the other However, the principal economic advantages of flexible flowline are derived from the greater ease and simplicity of its installation and connection compared with rigid steel flowline In general terms, the economc benefits include the lower day-rate for laying vessel, the faster laying speeds attainable, the reduced time required to connect ends, that span rectification/stabilization are seldom required, the flowline may be recovered and used again elsewhere TYPICAL APPLICATIONS FOR FLEXIBLE FLOWLINES As short jumpers (10–50 m) Situations frequently arise in which two lengths of rigid line have to be connected, and in which there is a limited degree of control over the relative location of the ends of these lines The effects of thermal expansion may have to be accommodated, or the connection may have to be effected across an area of unstable or u-regular sea bed Rigid spool pieces are costly, requiring accurate on-site measurement by divers of the relative location and orientation of the flanges to be connected, followed by manufacture and test of sections of rigid line to bridge the measured gap.