INTRODUCTION For a conventional multiwell offshore field development, traditionally drilling could only commence after a fixed platform had been installed and commissioned. This meant that the gas or oil was not recovered until well into the development programme, and that the cost of developing fields m deepwater or marginal fields became, if not unpractical, then certainly less financially attractive It is usually cost-effective for an operator to begin production at the earliest opportunity, because recovery of capital outlay cannot commence until the first gas or oil flows. Earlier production can be achieved by pre-drilling the wells through a drilling template previously installed on the sea bed. The wells can then be tied back to surface production facilities typically installed on a fixed platform or a tension-leg platform. The early production of gas or oil must, of course, be offset against the costs of the template, pre-drilling and tie-back operations Where the cost of providing a fixed structure proves to be uneconomic, then the use of a template containing the production facilities should be considered. It can provide the drilling facilities in addition to accommodating Christmas trees, production piping, well killing and pigging facilities. The template can act as a gathering point for satellite wells, and export by pipeline to either a jacket located in shallower water or via a riser to a floating structure within the development Its use m this fashion allows the economic development of a marginal field and even small pockets of a large field not accessible by deviation drilling from a central platform The technology used and the expertise gamed from such operations will also prove useful in exploiting the reserves in the deepwater fields which are currently being investigated. The major considerations governing the design and installation of these structures form the basis of this chapter. DESCRIPTION General When a fixed or tension-leg platform is to be used m conjunction with pre-drilled wells it is first necessary to drill some or all of the wells through a previously installed template. The platform is subsequently installed, the subsea wellheads are tied back to the production trees on the deck, and any further wells can be drilled from the platform Such a template structure, which is only required during the drilling operation, is generally referred to as a drilling template, a typical example of which is shown in Fig 1. As an alternative, it is possible to locate the production trees on a subsea template and then tie-in to a floating production facility (e g a modified tanker or drilling vessel) or a remote platform The oil or gas is exported to the floater via a riser or to the platform by flowline Such a structure is commonly referred to as a production template (a typical example is given in Fig 2), and is expected to act as a guide and support for the drilling operations and to house the Christmas trees throughout the life of the installation

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.

INTRODUCTION Monohull vessels make up by far the most wdely used hull form on the waters of the world, and not least m the field of subsea construction The workhorses of the offshore industry, the monohulls, have been designed, modified and often converted to facilitate a multitude of tasks. It is acknowledged that the semi-submersible hull form is playing an increasing role in subsea construction, but it is the numerically superior and often more versatile monohulls upon which so much still depends. It is not the purpose of this presentation to analyse comparisons, but rather to illustrate the abilities of monohull vessels in subsea construction DESIGN AND SPECIFICATION Subsea construction vessels tend to fall into two categories The first are those which are designed and constructed to perform a task or tasks, with diving very much a secondary capability. The second category consists of vessels that have a major diving capability but are also able to carry out a number of other tasks. Vessels forming the former group are the crane barges, lay barges and general-purpose construction vessels, for example, Reel Ship Apache , and the newly built DB Challenger The latter group are the diving support vessels, for example Arctic Seal and newly built Seawell One Both categories must be able to perform to meet high specifications and the following considerations must be made during design and budding dimensions, power; positioning systems, subsea construction facilities. Dimensions Length, beam and draft make up the vital statistics which dictate the actual size of a vessel However, it is the way in which these measurements are arranged that is important. The monohull must be full enough in the beam to provide a stable and sea-kindly work-platform, but must be an efficient profile to enable good transit speeds to be achieved and economically maintained. The draft of a vessel must be considered, not only as a component of stability but also in order to keep a wide choice of ports and harbours available, as one of a monohulls strengths is its ability to go alongside a jetty or quay for load-out and mobilization. When considering a vessel for specific workscopes, size plays an important part in the selection process For the most part, larger vessels will be utilized for the heavier tasks and when large numbers of personnel are required. This does not by any means preclude the smaller vessels, as they come into their own for lightweight tasks and where access may be restricted Often a large vessel may carry out a single part of a project and a smaller vessel may then take its place to complete the work. Deck and working areas are proportional to the overall dimensions of a vessel and the accommodation requirement. The scope of work will dictate how much deck is required, and therefore vessel selection. The loading capability of a deck must also be considered, as specialist construction equipment may cause problems requiring the fabrication of additional grillage and sea fastenings.

INTRODUCTION Most forms of subsea installations have, as a common feature, a requirement of physical contact directly or indirectly with the sea bed The nature of that sea bed greatly influences the design and installation technique adopted, and consequently the economics of the project Furthermore, incorrect assumptions about the sea bed can necessitate expensive remedial measures, since little flexibility is available to adjust the design at the tune of installation Despite these factors, site-specific knowledge of the sea bed is often unavailable for subsea installations. Designs based on sod conditions at platform sites many kilometres away are not uncommon This chapter describes some of the influences that the geotechnical conditions can have on the design and operation of subsea installations, and demonstrates the desirability of the acquisition of site-specific soil data FOUNDATION LOADS For the purposes of classifying their basic foundation loads, subsea units can be divided into three categories units which are set completely below sea-bed level, units which are set at or slightly below sea-bed level, units which float above the sea bed and are anchored to the sea bed In each case the purpose of the foundation member is to support the loads Imposed by the unit and any external forces applied to the unit safely, effectively and at an acceptable deformation. The first stage in deciding on the type of foundation unit to be adopted (and hence on the soil data requirements) is to establish the magnitude of the loads for the various options under consideration Fully recessed sea-bed units are currently only adopted where local conditions render surface units vulnerable to damage Typically, silos may be adopted where iceberg scouring of the sea bed can occur Such units, by their nature, do not attract high accidental lateral loads, and silos are generally able to support their own weight and that of the unit by external-skin friction very adequately They therefore provide their own foundation, and the only geotechnical areas for particular study are those governing their installation. Surface units represent the vast majority of existing and planned subsea installations The first generation consisted of a wellhead with a rigid riser and a production tree affording well control. The next stage was the development of manifold units to permit collection from a number of satellite wells and to allow transportation to adjacent topside production facilities. Current and future developments include sea-bed separation units, thus making possible long-range sea-bed transportation and the use of modular 1 atm units serviced by submersible Unless requiring the special protection afforded by category (a) above, these units are all normally placed on the sea bed and require support by the sea bed. Vertical loads generated by these units and their protection cages are generally much lower than the range of loads normally associated with platforms. Vertical components of foundation loading arise from

INTRODUCTION This chapter is concerned with the suitability of long and wide piles for different subsea applications A brief overview of the development of large hammers for driving long jacket piles is presented, and the suitability of wide piles for other applications is discussed Methods of interconnecting wide piles are described, and finally there is an account of the development and testing of a launching system for piling off small vessels. Note In the context of this chapter, a "long" pile has an aspect ratio (length breadth) in excess of 20 1, whereas a "wide" pile has an aspect ratio of nearer 5 1 APPLICATIONS FOR OFFSHORE PILES Applications for offshore piles may be divided into three broad categories Jacket piles to support production platforms. Pile loads are principally axial compressive, supporting the structural weight, with some lateral and tensile loading due to the overturning effect of storm conditions on the platform Subsea structures such as templates and protective structures Pile loads are much smaller than for jacket piles, principal loads being horizontal or vertical, compressive or tensile, caused by snagging or deflection of fishing gear Self-weight compressive loads are generally small by comparison. Anchor piles for permanent moorings of floating production systems, loading buoys and circumstances where sea-bed flowlines do not permit conventional moorings. Pile loads are principally horizontal, with some vertical tensile in extreme conditions Since engineering solutions are predicated by available techniques and the mainstream of offshore hammer developments has been towards large hammers for jacket piles, a brief overview is appropriate OVERVIEW Mainstream piling techniques The two principal techniques for installing piles offshore are (a) Impact driving and (b) drilling and grouting Other techniques such as jetting, vibration or jacking may be advantageous or of assistance in certain circumstances, but are of application to a more limited number of soil types, and are unreliable in others Offshore construction projects tend to be of much shorter duration than their onshore equivalents, employing more-expensive equipment The penalties of downtime are therefore more severe, so that driven or drilled piles have been most frequently used. The principal application for offshore piling has been to support the weight of steel jackets and production platforms on sedimentary sods Bearing capacities up to 2000 tonnes/pile may be required, with typical pile diameters of 1–2 m to transmit the load. Driven piles are better suited to such large-scale applications, because the reaction to the energy input is provided by the hammer itself, and because final pile sets provide a recognized measure of the capacity of the installed pile By contrast, a drilling technique necessitates satisfactory torque reaction, and this presents problems at large scale In addition, the installed grout envelope around the pile is often irregular and unpredictable in shape, so that the pile must be proof-tested in-situ unless it is of very conservative design

The original electricity link between England (Dungeness) and France (Equihen) was formed by a pair of d c. cables laid on the sea bed. The link was very unreliable due to the large number of anchors and trawl boards that damaged either or both of the cables Repairs were continually being carried out using a specially fitted-out vessel, the Dame Caroline Haslett, previously a collier vessel A typical repair is shown in Fig 1 Once the faulty section of cable is removed a new length held m store on the repair vessel is joined to one end of the original cable The new length of cable IS then re-laid on the sea bed until the second end of the original cable is reached. This cable is then recovered to the repair vessel and joined to the new cable, the end of which is retained on the vessel. A loop of cable approximately equal to twice the water depth is finally laid on the sea bed in the form of a bight or loop Any cable laid on the sea bed is vulnerable to anchor and trawl damage, and repair loops as described above add to the risk Such repairs are, however, relatively easy to carry out, but subject to adverse weather Fig 1 A typical repair(Available in full paper) Fig 2 Electricity connections between England and France(Available in full paper) The new electricity connection between England (Folkestone) and France (Sangatte) (Fig 2) has the submarine cables buried 1 5 m into the sea bed Whilst this affords protection against trawl boards and the majority of anchors, it does present difficulties in repairing the cables when faults occur If the previous method of repairs were adopted it is considered extremely difficult to bury a repair loop, and if surface protection were used the cable would be at risk where it leaves the top of a "hard" walled trench Surface protection in many cases, i e concrete mattresses, is not considered a satisfactory method, although this has been accepted in certain circumstances To overcome the above problems of repairing submarine cables the CEGB and EdF had a feasibility study carried out. This study was to examine all the problems and determine whether it was possible to produce a suitable environment on the sea bed in which a cable joint could be made on a high-voltage cable The prime requirement was for trained and experienced cable jointers to be able to operate in their normal environment, as it was not considered practical to tram divers to carry out this work With the age of such cable jointers being 30/35+ years it was considered necessary to have the habitat working at normal atmospheric conditions A further reason for such conditions was that with a relative-humidity requirement of 20% with a temperature of 20°C it was not considered possible to achieve this under hyperbaric conditions