INTRODUCTION The lead time for offshore projects has traditionally ranged from three to five years, from the time the operator commits to a development until first production is achieved. During this period a number of basic assumptions are made upon which the financial viability of the project is evaluated. These assumptions tend to cover both commercial and technical factors, such as type of development, field life, oil price, inflation etc., and during the period of the project the relationship between these factors will change. The impact of the rising oil price in the 1970s provided unexpected windfalls to operating companies, while the corresponding fall in 1986 resulted in a significant belt-tightening exercise During the project cycle, decisions previously made on the basis for the development will be questioned in a never ending search to keep the project "on schedule and within budget". The engineering industry, for example, will be very familiar with weight-saving (shaving) exercises as topsides become heavier and budgets spiral upwards. However, even in the price collapse of 1986, the industry did not shelve projects which they had started, instead, companies looked for the opportunity to reassess earlier decisions and to effect changes/reductions within their budgets. During a project it is the operator who retains control over the budget and who will make the key decisions. In the preliminary engineering phase, detail evaluations of various schemes will be undertaken and an approved development configuration will ultimately be selected The selection process will consider both technical and commercial factors and relate them to safety, reliability and cost effectiveness. A cheap but unproven option will be penalized through the application of a higher contingency factor than an option that demonstrates the use of proven technology. If the FPF is to be seen as a serious contender for a development project then it will need to demonstrate low risk and high reliability. There is little benefit in trying to persuade the oil companies that a "new FPF design concept" will offer even greater savings unless they are already satisfied that the FPF is technically and financially competitive with other development schemes. It is one thing to suggest that savings of up to 30% may be made on the cost of a new-built FPF, through the application of 20/20 hindsight, but this will not convince operators that they can be any more confident in the performance of the unit at the end of the day. 1986 was a year that saw the delivery of two new concepts in floating production. The Petrojarl PTS, a sophisticated monohull, began production testing on the Oseberg Field for Norsk Hydro, while the GVA 5000 FPV began production for the North Sea Sun Oil operated Balmoral Field. These two units share the distinction that in their own class they were the world's first purpose-designed and -built floating production units; they also share the distinction that both were ordered in a high oil-price environment.

This chapter reviews the merits of semisubmersible and tanker-based production systems and traces some developments aimed at improving the economic performance. Special reference is made to the use of two-axis control Dynamic Positioning (DP) thruster configuration. INTRODUCTION Today, when most of the major geological prospects in most offshore regions have already been explored, the discovery of large fields becomes less likely. Offshore technology is being driven relentlessly towards finding better ways to produce the smaller discoveries which are often geologically more complex, and for which development information is generally much less certain At than that at which the larger field developments were initiated Attention is increasingly directed towards reducing the cost per throughput barrel of the production facilities. The application of the floating production unit is now well established, and there are more than 25 systems in use in different parts of the world. The expression "marginal field" is often used when discussing the economics of production, but this is a relative term Its meaning shifts not only with the production cost rate which is applied but also with the variations in the price of crude oil and applicable taxation regimes One effect of the recent price falls was to raise the required production rate for fields to remain within the "marginal" classification As a result of this, a general increase in the design capacity of floating production systems has been indicated. THE FLOATING FACILITY The advances in offshore drilling techniques, together with the design of subsea completions, manifolds and risers, allow this type of equipment to be combined with floating surface facilities thereby yielding a wide range of approaches to the design of production systems which can act as viable alternatives to offshore platforms. For the floating part of the system, the choice lies between using a semisubmersible and a monohull or ship-shaped vessel. The semisubmersible is basically designed to be a method of supporting an operational platform using a buoyancy configuration which is more transparent to waves than a barge, whereas the tanker is designed to operate in a particular orientation and features flared bows to reduce resistance to waves and water movement Both types of vessel require a method of mooring to retain them on the assigned location. With the low utilization in today's market, tankers and drilling semisubmersibles are economically attractive possibilities for conversion into floating production units. To optimize their use, it is interesting to compare their various features, as follows. Storage Capacity A semisubmersible can be used to provide operational control, riser suspension, separation process and flaring facilities. This may be entirely sufficient to provide an extension to an existing facility, for instance a nearby production platform, but for an autonomous system in the sense of one which is not sufficiently near to an existing facility to enable the economic export of the crude oil via a reasonably short pipeline, production storage capacity will be required Although this can be provided by a shuttle tanker, such a method exposes the system to production downtime when the shuttle is not connected due to transit voyaging or laying-off due to weather conditions (Fig.1)

INTRODUCTION The use of flexible dynamic risers in conjunction with floating production systems is rapidly becoming the preferred method for developing small- to medium-sized offshore oil- and gasfields. The systems are based on the following types of units: lack-up ship/tanker semisubmersible tension-leg platform As of April 1987, some 75% of the estimated total 32 floating production systems in operation worldwide were fitted with flexible riser pipes, with an additional ten units of an advanced stage of design/construction. The majority of existing systems are located offshore Brazil, the Far East and in the Mediterranean The use of flexible riser systems in harsh environmental conditions has, however, gradually gained acceptance, partly due to the Hamilton Argyll, Sun Balmoral and Golar Nor Petrojarl projects. Amerada Hess has, for instance, confirmed the use of flexible riser pipes for the Rob Roy/Ivanhoe Field development, with Sovereign expected to follow suit when developing the Emerald Field. An advance on the Marathon Kakap FPSO system is the use of a semisubmersible production unit linked to a lightweight wellhead platform via a series of flexible riser pipes. The concept is shown in Fig 1 and has been put forward for Statoil's Veslefrikk and Norsk Hydro's Oseberg phase two field developments. A more novel application for flexible riser pipes is Placid Oil's US Green Canyon project, featuring a hybrid riser (Fig. 1 is available in full paper) system. Flexible risers are used to link the floater to a 420 m buoyant rigid riser in order to enhance the compliancy of the system. Plans for using flexible riser pipes to tie-in additional remote satellite wells to a tension-leg platform is a further manifestation of the increased acceptance of flexible pipes. Both the TLP proposed for Saga's Snorre Field and the TLWP destined for Conoco's Green Canyon Jolliet Field will feature such systems. To assist the engineer in the initial stages of design, this chapter sets out to define the component parts of a flexible dynamic riser system, and also provides guidelines for the selection of system configurations and methods for design. Aspects of installation, as well as system inspection, maintenance and repair, are then briefly discussed. SYSTEM DEFINITION General A dynamic flexible riser system will generally comprise of any of the following component parts. flexible riser pipe including end terminations upper end connector and release system subsurface buoys or buoyancy modules riser bases or pipeline end manifolds (PLEM) The selection and design of each component part is closely interlinked with the overall design of the riser system. It is therefore essential that the design engineer has a good understanding of the specific function of each component part as well as their influence on the global behaviour of the system. The system should also be designed in close cooperation with the flexible pipe supplier, to ensure that loads and the geometry of the pipe are maintained within acceptable limits

INTRODUCTION In a review of various control system types for floating production facilities, it is quickly seen that most system options have been developed assuming that the operator is hydraulically operated. Direct hydraulic, the various piloted options and acoustic control are well defined in a variety of publications. In this chapter will be described a direct hydraulic control system required by Production Vessel-Test (PV-T), a joint venture formed by Houlder Offshore and North Sea Terminals. The intent of this chapter is to optimize one parameter - the cost. HISTORIC The earliest example of floating production control of a(Fig. 1 is available in full paper) subsea well is on the Castellon ?B? project offshore Spain, as shown in Fig. 1. Direct hydraulic control of a single well causes production fluids to flow through the single-anchor leg system (SALS) to the storage tanker. Since then, there has been an increase in the complexity of the subsea architecture, notably the introduction in the Hamilton Brothers Argyll Field of a multiwell development to a semisubmersible floating facility with export system Recent years have seen the development of multiwell multifacility subsea producing to a floating facility; for example, Sun Oil's Balmoral, Amerada Hess Ivanhoe/Rob Roy and the proposed Sovereign Emerald. Where is the next generation system required? The chapter will discuss this. THE NEED PV-T is intent on well testing and pilot production. As a contractor, they are intent on having the most simple, robust, reliable system possible The oil price fluctuations in very recent times have shown that for a system to be economic throughout its design life, the overall costs must be minimized in such a way that break-even is reached at a low revenue per barrel produced It is not the intention of this chapter to determine what is a marginal field, only to show methods of reducing capital costs on certain equipment. On that basis, there is a need for a low-cost control System. DESIGN PREMISE Simplicity alone would require this system to comprise a pump, a hose and a ganged connection to all subsea valves. Flexibility of operation would be minimal, but cost and maintainability would be maximized. A more serious definition of the design premises would be as followed high operability low maintenance simple planned maintenance low purchase cost low maintenance cost does not compromise safety To expand on the above, the system must be in a working state at all times To achieve high reliability in a complex system involves a high cost: the response to the first design premise in this instance must therefore be simplicity. Low maintenance in a system echoes the previous statement in that minimization of components and complexity reduces the need for maintenance. Simple planned maintenance requires the designer to keep as much of the system package on the surface and a minimization of hardware on the sea bed at the installation.