The use of floating production platforms for the development of offshore hydrocarbon resources has been made possible by the evolution of subsea production systems allowing wells to be completed on the seabed. The ability to drill and complete the well on the seabed has obviated the need to extend the well back to the surface facilities and has thus allowed the use of platforms having a much greater facility than was hitherto acceptable.

It has thus been possible to depart from the fixed jacket or gravity base structure and consider alternative platform arrangements where field constraints, such as water depth reservoir size, hazardous environment etc., mitigate against the use of a fixed structure.

Table I shows the different types of platform ranked very approximately by structural flexibility. The buoyant tower, guyed tower and tension leg platforms were evolved to use buoyancy to assist in the structural support of the platform while at the same time restricting the deck motion to a level which would allow the use of surface wellheads and trees. Floating production units either of the monohull or semi-submersible type, relying upon catenary moored anchoring systems, exhibit most relative motion between the platform and the seabed and thus have to date only been used in conjunction with subsea completed wells.

Table I Relative Platform Flexibility (available in full paper)

When considering the overall design of a field development using either a monohull or semi-submersible floating production unit it is important that the floating unit, the mooring system and the subsea production system are ‘matched’ in order to minimize the total project expenditure. When undertaking such a matching, it is necessary to trade off a number of conflicting requirements which each have significant cost implications and by a process of optimization arrive at a solution which incorporate satisfactory standards of safety, system availability, operability, maintainability and reservoir exploitation. As with all floating and subsea systems, particular attention is necessary in estimating the operating expenditure (OPEX) which is usually more subject to variation than the initial capital expenditure (CAPEX).

The ‘matching’ and trade-offs for deepwater development, say for the purposes of this chapter 300 to 1200 m, are even more difficult because of the state of development of technology for the completion and production of wells in this depth of water. Although wells have been drilled in deep water for a number of years, it is only recently that FPVs have come into use, principally in Brazil and lately in the Gulf of Mexico. The capital costs of riser systems, mooring systems and subsea components are such that significant variations in costs are possible under different design situations. It is obvious that if a very stiff mooring system is installed, then the production riser design is simplified in that it has to accommodate less relative movement between the seabed and the vessel. Additionally, if the FPV is to be used for development drilling, well completion and workover, operation costs and schedules will be reduced if the FPV has lower motion response to environmental loadings.

This content is only available via PDF.
You can access this article if you purchase or spend a download.