DEEPWATER DRILLING & PRODUCTION Floating production facilities key to lower cost deepwater development

Peter Behrenbruch HP Petroleum PART 1: This article is the first of a two-part series on the development of floating monohull and semisubmersible production systems. Part II will appear in the November issue. Phillips Petroleum's Nanhai Kai Tuo represents the latest in disconnectable internal turret technology. The unit was installed recently on the Xijiang Field offshore China. The internal turret, shown here on an FPSO, is instrumental in low-cost field development. (photo courtesy


Peter Behrenbruch
HP Petroleum
PART 1: This article is the first of a two-part series on the development of floating monohull and semisubmersible production systems. Part II will appear in the November issue.


Phillips Petroleum's Nanhai Kai Tuo represents the latest in disconnectable internal turret technology. The unit was installed recently on the Xijiang Field offshore China.


The internal turret, shown here on an FPSO, is instrumental in low-cost field development. (photo courtesy Phillips Petroleum).

Floating production facilities have gained more and more acceptance, particularly over the past 10 years. Today, there are more than 40 ship-shape and semisubmersible production vessels in operation worldwide.

The gain in popularity is primarily due to the economic benefit in utilizing such facilities. In many cases it has been the only economic means to develop an offshore oil field as companies explore in remote and deep water areas, and as smaller marginal fields are developed in mature areas.

Secondly, technology in the areas of mooring design and subsea systems has reached an advanced stage where both increased feasibility and unit cost reduction have had a favorable impact in selecting floating facilities over more conventional options.

Why use a floating facility, or - more appropriately, why use a fixed structure? Today, the base case should be a floating facility, just as horizontal wells have taken preference over vertical wells and 3D seismic is the preferred choice in delineating offshore fields.

In terms of application, these facilities are being predominantly used in four different situations:

  • Remote developments (no nearby infrastructure).

  • Small and marginal fields.

  • Early production systems.

  • Extended well testing.

Apart from the final economic evaluation, the decision for the optimum facilities involves four key considerations: field reserves, water depth, number of wells, and distance to infrastructure. These four aspects more than any other influence the fundamental choice of the type of production facility. Other important technical considerations, particularly as they relate to floating facilities are the following:

  • Reservoir aspects: areal field extend, also in comparison to formation thickness: number of reservoirs, both vertically and areally; and reservoir and well productivity.

  • Type of vessel: ship-shape, semi-submersible or other; new-built or second hand (conversion); and storage, loading and transport requirements.

  • Type of mooring arrangement: environmental conditions - weather; bottom soils - hard or soft; and vessel is (semi) permanent or moveable (i.e. disconnectable).

Commercially, there are also considerations that can have a significant impact on project economics. They are costs (capex and opex), incremental recovery (or loss) when compared to other development options (both for the total field and on a per well basis), facilities limitations and the impact on production profile (particularly as related to the maximum number of wells and throughput) and implementation time (i.e. time to first oil).


Floating production facilities and their use required a number of innovations before more practical and extensive designs could be implemented. The four main components are a suitable vessel (to carry the production/process equipment), the mooring system (to hold the vessel on location), the fluid transfer system (between wells, facility and export pipeline/storage vessel) and subsea trees/ manifolds which extend the number of applications considerably.

Ship-shape floating systems employ a single point mooring (SPM) system which had its origin with the conventional buoy mooring (CBM) system design implemented in 1959 in Sweden by Imodco. This small, 4.5-meter diameter buoy was anchored by four chains and weighed just 60 tons. It was initially designed to handle tankers and warships up to 2,000 deadweight tons (dwt). Such early systems, utilizing a simple buoy in form of a catenary anchor leg mooring (CALM), were used for mooring storage or transport vessels.

It should be noted that Shell was also engaged in early CALM buoy design and the first SBM was installed in Miri in Brunei in 1960, followed by an improved design for Shell's refinery in Niigata, Japan in 1961, the latter accommodating ships up to 47,000 dwt. Such basic designs are still in use today.

A second approach to mooring a tanker was the use of a small fixed structure with a rotating head. Such a design was first implemented for refinery applications by Dalmine and later Italprogetti in Italy, the first system being installed in 1963 by Micoperi at Fiumicino. While the CALM buoy is by far the most common CBM design, the tower concept proved to be a viable alternative to CALMs and several improved designs have been installed worldwide. However, the danger of collision and restricted water depth are the two main limitations to this type of SPM design.

To further extend tanker mooring applications, in particular to minimize downtime, Esso initially utilized a complex tower and pylon design by van Houten at Brega in Libya. Subsequently, further improvements resulted in the first mooring utilizing a universal joint at sea-bottom. The first single anchor leg mooring (SALM) of this type was then installed at Brega in 1969 and the design was further extended by Sofec for other applications. While the subsea fluid swivels used in the original design proved to be operationally difficult and costly to maintain, this design nevertheless further advanced this type of technology.

A third type of mooring design is the articulated column which had its beginnings in 1963 in France. Following a five year research and development period, EMH eventually originated a design which was installed in 1968 in the Bay of Biscay in 100 meters of water. The Elf ocean tower was an experimental oscillating column, seven meters in diameter and 128 meters long. While the concept was proven over a three year period, it did not offer any cost effectiveness over a conventional fixed platform and the concept has not been used to date as a production platform. However, there have been a number of other North Sea applications: flaring towers (Shell's Brent Field and ELF's Frigg Field, 1973/4) and a loading tower (Mobil's Beryl Field) and further columns have been installed since these early applications.

The fourth generic mooring system is the more recent UKOLS (Ugland Kongsberg offshore loading system) which has been developed since 1985. The system is very simple in concept and consists only of a Pipeline End Manifold (PLEM) with a vertical, fixed riser held in position with a subsea buoy. A swivel arrangement to a second flexible catenary riser is located and submerged at the top of the vertical riser until utilized by a dedicated dynamically positioned (DP) shuttle tanker. The first system was installed in 1986 to replace the Statfjord A articulated column which required replacement. Drawbacks are the subsea swivel arrangement mentioned above and the exclusive use of more specialized DP tankers (higher charter rates).

In conjunction with some of the mooring systems described, advances were also required in loading/offloading hose design, hawsers, mooring chains, and for greater versatility, improved subsea components, including flexible flowlines.

The first application which used a single floating production, storage and offloading (FPSO) vessel moored to a SALM was Shell's Castellon project offshore Spain (1977). This was then the first application combining all field requirements of production, storage and offloading. The 60,000 dwt tanker was located in 117 meters of water. A similar design was used at the Nilde Field and an improved SALS (Single Anchor Leg Storage) design at the Tazerka Field.

Alternatively, the use of a semisubmersible drilling vessel may be considered. The first worldwide production facility of this type was used by Hamilton for their Argyll Field in the North Sea (1975). This converted mobile offshore drilling unit (MODU), the North Sea Pioneer, was subsequently used for a number of other field applications.

Finally, these systems also required the development of subsea wells, the first of which (West Cameron 192, No. 7) was successfully completed in 1961 in the Gulf of Mexico in 17 meters of water. Subsequently improved and multiwell designs (manifolds) have been employed for increased applications.

Floating production

Less conventional offshore platforms are those that are not fixed, such as mobile offshore production units. Provided a platform includes major processing equipment, in the broadest sense such categorization may include ship-based FPSO vessels, semisubmersible floating production units (FPUs), jackup production units and tension leg platforms (TLPs).

The application of jackup rigs is more limited to shallower waters (realistically < 100 meters) and there are very few of such facilities in permanent use worldwide. on the other end of the scale, tlps are only applicable for deep water (> 300 m). FPSOs and FPUs, on the other hand, have much more versatility and hence wider application and are further discussed below.

Ship-based FPSOs

To date, there have been some 34 vessels of this type deployed with at least another 10 vessels forecast to come an stream during 1995/96. There were two distinct periods of development: the early experimental period (1976-82) and the more recent period (1985 onward).

Initial developments tended to deploy more simple mooring designs: SALS and CALM (also SBS or single buoy storage) in predominantly shallower and calmer waters. The second period includes a wider range of designs and is particularly marked by different turret designs. Most notably central turret designs are very popular of late and are suitable for deep water situations ( 300 m) in remote areas.

Semisubmersible FPUs

Some 32 vessels of this type have been in use over the past 20 years with possibly another five facilities to come onstream over the next two years. In addition, there are two speculative vessels which were listed in 1993.

By far most of the facilities are in use offshore Brazil, in the Campos Basin. The only other major region is currently the North Sea. Considerable infrastructure exists in both regions, hence the predominant use of FPUs in these more mature areas. The US Gulf of Mexico is conspicuously absent in terms of this type of facility. The main reason is cost. Conventional design substructure (jacket) costs for these tropical waters is significantly less than for the much heavier North Sea platforms. The statistics also show that by far most applications are in moderate water depth below 300 meters (most prevalent in 101-150 meters) but that more recently this type of facility is being used in much deeper waters ( 500 meters). While semisubmersibles may be more advantageous at greater water depth, when compared to FPSOs, ship-based facilities with more rigid moorings definitely have the edge in shallower waters. The latter have, of course, also an advantage for remote fields in that they have in-built storage.

Remote developments

Remote or isolated developments are those which have no nearby infrastructure; this means no other existing offshore developments or pipeline are in the vicinity (< 20 km) or the distance to shore/nearby island is considerable. however, even if the latter is not too far, it may still be more cost effective to store/offload the crude offshore.

Remote fields, also in combination with deeper water and or limited reserves size, are prime candidates for fpsos. in some cases, the combination of fpu/fso has also been used (depending most often on the availability of existing vessels).

Early developments using fpsos were in the mediterranean, asia, and offshore brazil. more recently offshore central and southern africa, and australia have also seen such developments. most notably, the north sea is a latecomer where the first more permanent facility came on stream only in 1993 for the gryphon field. however, over the next two years, there are several substantial north sea developments to come on stream.

Small, marginal fields

There are no precise definitions when considering small and marginal offshore fields. the author feels that in terms of reserves, a marginal offshore field may be defined as one with less than 20 million bbl, and a small field as one with less than 100 million bbl (based on estimates at the time of the development decision). in more general terms, marginality relates to economics.

Even a field with reserves greater than 100 million bbl, particularly if in a remote location and/or in deep water, may be marginally in economic terms. other physical or commercial aspects may also be contributing to the adverse situation: geological complexity (compartmentalization due to sealing shales or faults), large areal extend, heavy crude - all requiring an increased number of wells and hence cost.

Early production systems

Early production systems (epss) are attractive for two reasons:

  1. They generate early cash flow, being implemented much more quickly than full scale field development (using more elaborate facilities).

  2. They minimize up-front financial exposure in more uncertain situations in which additional reservoir data may be required before final full field development decisions can be confidently made.

    In many instances, very large fields may be targeted (for example, offshore brazil) where technology is being further developed to handle the deeper water. other examples can be found in the north sea and in vietnam.

Extended well testing

With the advent of floating production facilities, long term testing became economically viable for offshore fields. oil produced during testing could be conserved and sold to pay for the rather large expense of extended offshore testing.

Extended well tests typically last from several month to more than a year and are usually intended to gather more detailed reservoir information, often in conjunction with decisions leading up to development. particularly in case of marginal fields, extended well tests may be necessary to reduce geological uncertainties and financial risks sufficiently to bring about such developments.

However, it should be noted that the first floating facilities of the mid and late seventies were essentially test situations, not so much for reservoir purposes but to prove up new development concepts, including subsea technology (enchova and garoupa off brazil).

The real advent of testing for reservoir information was the deployment of a specialized charter vessel (september 1986) in the north sea, the petrojarl i. this vessel was used for extended well testing in four fields (oseberg, lyle, troll, and balder).

Other test situations have utilized completely different vessel arrangements. of particular note are the more recent tests in deeper waters (liuhua off china and aquila off italy). an alternative to testing in shallower water is a jackup modu in combination with an fso, as was used in case of agip's emilio field, for example.

This article was originally presented as spe 30147 at the spe-sponsored petrovietnam conference held in ho chi minh city, vietnam earlier this year. it has been updated by the author expressly for offshore magazine. a lengthy list of references are available from the author.

Copyright 1995 Offshore. All Rights Reserved.

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