Design Priciples Concept Selection Barltrop

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CONCEPT SELECTION AND DESIGN PRINCIPLES

Based on:

Floating Structures: a guide for design and analysis,

(chapter 1)

ISBN 1 870553 357

Editor: N.D.P. Barltrop

MT 411 Floating Offshore Structures



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1 Concept selection and design principles

1.1 Introduction

The first practical application of a floating platform was a pivotal event in the development of human civilisation.

It lead to two-thirds of the earth becoming navigable and the resources of the ocean exploitable. Exploration and

Harvesting / production has continued through the ages and is presently being pursued in search of hydrocarbons

and other mineral resources.

The prime potential locations of petroleum reserves will have had a plentiful supply of organically rich

sedimentary material, often deposited in confined basins with restricted circulation. However, the phenomena of

continental drift, major climatic changes over the millennia and the migration of hydrocarbon fluids lead to the

discovery of petroleum deposits under areas that are now very different. Most offshore hydrocarbon deposits are

expected to be located under the continental shelf and on the slope from the shelf down to the deep ocean floor.

The bulk of today's offshore hydrocarbon reserves originate from developments on the continental shelf in relatively

shallow water. However as the size of discoveries in the mature basins diminishes, there is an increasing shift

towards exploration in deeper water. Typically the edge of the continental shelf is at about 200 metres water depthand the slope extends to 2500 -3000 in. Therefore future exploration of the continental margins, down to about

3,000 m may be expected but there will be little justification for prospecting for oil in the deep oceans.

1.1.1 Use of floating structures

The development of the offshore industry commenced with the use of fixed structures. As development

accelerated with the discovery of oil and gas in deeper waters, the use of floating structures became commonplace.

Once preliminary geophysical investigations indicate the potential for hydrocarbons several major activities,

which may overlap, are required to recover these hydrocarbons from below the seabed, namely:

• exploration drilling,

well testing,

• pre-production drilling,

• early production,

• production

• export,

• storage,

• work-over.

Exploration drilling, to find oil, is performed offshore using three main classes of drilling platforms: self-

elevating platforms (jack-ups), semi-submersibles and drill ships. Some drilling is also undertaken from barges.

Well testing, to determine production rates and field life, may initially be performed using the drilling platform

but only short (and therefore often unreliable) tests are practical, during which the oil is burnt, owin g to the lack

of oil storage. Therefore extended well testing may be carried out using a production tanker (such as Petrojarl 1 ).

Pre-production drilling, of the large number of wells required to produce the oil, and the 'completion'

(installation of tubing, filters, valves etc.) will be undertaken from a semi -submersible or monohull vessel before

the main production platform is installed. This allows oil production to start soon after the production platform

arrives on the field.



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Figure 1.2 Floating platforms used by the offshore oil industry (OPL)

Production platforms receive the oil from the well and separate out water, hydrocarbon and other gases to make

the products of interest suitable for export via pipeline or tanker, They will also typically inject water or gas to maintain

the pressure required for the oil to flow. They have, in the past, typically had a single location design life of about 20

years and thus have not required mobility. Now shorter life fields are being developed where the opportunity for

redeployment is possible. Many deep water fields are likely to have significant volumes of associated gas, which adds

substantially to the difficulty and cost of installing a production facility to tap the oil reserves. The flaring of large

volumes of gas is becoming increasingly unacceptable on environmental grounds and to conserve non - renewable

hydrocarbon resources, and is prohibited in some offshore areas. In some fields gas flaring may be necessary if oil is to

be produced economically but in the majority of cases gas must be, exported for sale or disposed of by re -injection intothe reservoir or an adjacent formation. Simplistically, Figure 1.1 shows the key features of a floating production

platform. Figure 1.2 shows various proposed and actual practical arrangements of floating production platforms.

Early production is simply producing oil soon after it is discovered, in order to improve cash flow. This early

production might be combined with extended well testing described above.

Export: As developments move further offshore or as field sizes become smaller, it may not be cost effective to

construct a pipeline export system. Instead shuttle tankers may be used to transport the product to shore.





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If the motion is sometimes large, and the number of risers small, it is practical to put the tree system on the seabed and

to disconnect the risers when the weather deteriorates. It is not practica1 to disconnect a large number of rigid risers.

The 1imitations on the above two cases may be overcome by placing the trees on the seabed and using either

permanently connected flexible risers or several wells manifolded on the sea bed with the oil co-mingled and producedthrough a disconnectable single riser. In either case drilling and work-over would be performed with a separate

temporary rigid riser.

If the motion is often high then the platform may on1y be suitable for use with flexible risers and seabed trees.

The Spar concept (see Section 1.2.4) and mid-depth completions (see Section 1.1.3) use a mixture of rigid riser and

flexible hose or riser to obtain some of the benefits of a rigid riser whilst allowing larger relative radial motions.

The rapid growth in demand for flexible pipe riser and flowline systems has been associated with significant increases

in understanding and design capability. However, the complexity of this product still leaves substantial areas of

uncertainty in applying flexible pipe in deep water fields and a lower than desirable reliability .The suitability of

flexible pipe for application in water depths greater than 1,000 m and in sour reservoirs has still to be demonstrated.

Temperature limitations continue to be a source of concern in some applications. The current pressure and diameter

capability provides constraints in many deep-water applications. Some integrated service umbi1ica1s and all multi-borerisers require further development work to confirm their suitability for deep water application.

The use of steel catenary risers has been demonstrated on the Auger TLP where they provide an attractive and

cost effective alternative to flexibles. These are now being studied for use with other floating systems such as

semi-submersibles, moored barges and FPSO's in both steel and titanium alloys.

1.1.3 Well completion

The characteristics of the reservoir and the well fluids need to be accounted for in the design of the production

facilities but for some field developments this may result in the need for frequent intervention in the well. Well

intervention may be necessary to maintain optimum performance due to mechanical failure, build up of sand, the

effects of corrosion and wear or the need to open or close production from different levels.

Well intervention capability is linked to the well configuration which in turn is linked to specific development

concepts. Three generic well configurations can be identified (Holmes and Verghese, 1995) with the 'trees' (well top

valve systems) at different levels. These are:

surface well completion,

mid depth well completion,

seabed well completion tied back to: -adjacent surface facility

-remote surface facility.

Surface well completion

This configuration has the tree at the surface and is used on TLP's, Compliant Towers and some types of Spar (see

Section 1.2). Its principle attraction is that the completion is accessible from the drill floor and well re-entry for

both 1ight and heavy work-over is feasible at the surface faci1ity. The main limitation is that it on1y a1lows a single

drilling centre.

Mid depth well completion

This completion has the trees located on a self-buoyant structure below sea level with seabed wells tied back

individua11y via rigid risers to the buoyant structure. Co-mingled well fluids are transferred to a surface facility



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via flexible risers. Potentially it could be used with semi-submersibles or FP's as (see Section 1.2). The idea of

this configuration is to have the trees accessible by divers for maintenance, to facilitate well work-over with a

dynamically positioned (DP) workboat and to simplify the surface facility. So far this completion has not been

used in practice.

Seabed completionThe conventional sub-sea completion has the tree on the seabed either in a template or as an individual cluster well.

This can be tied back by flowlines and risers to a surface facility in two ways:

Adjacent surface facility: Here the wells are located under the surface facility which is configured for drilling

and/or well intervention.

Remote surface facility: Here the wells are located some distance from the surface facility; this could be only a

few kilometres in the case of a typical floating platform development or a much greater distance in the case of

sub-sea tie back from deep water to a shallow water platform.

Typically sub-sea wells in the North Sea are entered every 4-5 years whereas surface completed wells in the Gulf

of Mexico are of ten entered more than twice per year. To enter a sub-sea well requires a mobile drilling rig or a

coil tubing work-over vessel which is a relatively expensive operation. For a surface completed well, interventionis more straightforward and less costly. This means that where a relatively high well intervention frequency is

anticipated, there is a strong incentive to have surface completed wells. In deep water this may lead to the selection

of a field development concept that has surface completed wells, and involves increasing Capex (Capital

expenditure) to reduce apex (operating expenditure) so as to improve overall field economics.

1.2 Types of compliant structure

The pioneering nature of the search for hydrocarbons from beneath the ocean has resulted in many innovative

engineering solutions. As confidence has grown in the successful application of engineering solutions to the

development of offshore oilfields so the industry has required:

• searching for oil in ever increasing water depths,

• producing oil in areas that do not have a pipeline infrastructure for exporting the oil,• economic oil production from small 'marginal' fields, with field lives of only a few years (that do not justify the

expense of a permanent platform),

• production very soon after discovery (oil exploration is expensive so oil companies can be more profitable by

producing oil quickly in order to improve cash flow).

All these pressures have lead to an increase in numbers and diversity of floating structures used for oil field

development throughout the 1980's and 90's. The focus of this book is the engineering design and analysis of

these floating structures used in the exploration and production of hydrocarbons. Figure 1.2 illustrates the

immense variety of floating structures available to the industry. These include ship shaped vessels, column

stabilised semi-submersible platforms, Spars and tension leg platforms. The principles and techniques described

in relation to these four major classes of floating structures should provide guidance for the design and analysis

of more novel concepts than are currently being proposed but which will no doubt be developed in the future.

The primary concepts considered for floating oil production are FP's as, semi -submersibles, TLP's and Spars.

other concepts which may be used as alternatives or in conjunction with floating systems are jackets, compliant

towers and sub-sea tie backs. New concepts are always being evolved and proposed with attempt to optimise

the capabilities of the concept from experience obtained so far with 'classical' designs (see for example, Madsen

and Gallimore, 1993). Figure 1.3 (Brown and Root, 1994) is a simplified indication of the relative capital costs

of the different concepts when used West of Shetland. Note that cost comparisons are area specific because not

all platforms are suitable for storage or drilling and these have different costs/benefits in different locations.

Presently used concepts are discussed below.



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1.2.1 Ship-shaped structures

Drillships

Drillships form a significant part of the total mobile drilling unit population of the world but are used predominantly in

areas with long periods of calm weather due to their poor heave response characteristics.

Floating storage units (FSU's)

Floating storage units, converted tankers, have been used for many years in conjunction with both fixed and floating

production platforms (Steeves, 1989) when economics dictate that the use of shuttle tankers is most economic or when

pipelines have yet to be completed.

Floating production storage and offloading units (FPSO's)

For the combined production, storage and offloading to a shuttle tanker, the ship -shaped floating structures (Figure 1.4)

are often cost effective. This is demonstrated by Figure 1.3 and the present proliferation of single point moored FPSO

systems. Note however that the FPSO is not direct I y comparable with the other platform types because it has storage

but no drilling capability.

The ship-shaped structure provides ample work area, deck load and storage capacity, structural strength, mobility (if

desired) and relatively cheap construction. However, as a result of its large displaced volume close to the waterline, thewave induced response of these structures is quite significant. Therefore, the station keeping systems and dependent

systems such as risers must be designed to accommodate these motions. The riser systems therefore need to be flexible.

However, the recent advances in flexible riser technology have permitted ship-shaped vessels to be used as production

platforms even in harsh environments in recent years (e.g. Foinaven and Schiehallion). In shallow waters, tanker based

production systems have been cost competitive against fixed structures and increasingly they are now being extended

into deep water with relatively easy changes to the mooring and riser system (Inglis, 1993; Henery and Inglis, 1995).

They are well suited for production duties in oil fields which do not require frequent work-over (well maintenance)

because in most environments the horizontal and vertical motions are too great to allow this.

Both new-build FPSO’s and tanker conversions have a role to play, with selection being based on the particular field

requirements. More hostile environments and longer field lives favour the new-build but milder environment and

shorter field lives are ideal for conversions, which can be executed very quickly. The important step is to





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One of the complexities associated with ship-shaped structures is station keeping. Excessive environmental forces

result when waves are incident on the beam of such a structure. Thus a number of alternative methods of mooring

these vessels such as CALM, SALM, articulated towers and soft yoke systems (see Chapter 9) have been developed

with the ultimate objective of permitting the ship to weathervane: i.e. rotate according to the direction of the extern al

forces. Thruster assistance may also be provided to reduce force and motions. In recent years, integral turret moorings

have been developed to allow weather-vaning, provide higher levels of structural safety, and provide opportunities for

more flow and control lines to be utilised.

The mooring systems for catenary anchored floaters still offer scope for improved reliability and cost effectiveness,

both in shallow and deep water. Some specific areas for further development are the simplification of the FPSO turret

mooring system, both in its configuration and mechanical! design, greater use of reliability techniques in the design of

catenary moorings together with improved understanding of component behaviour, and development of the taut leg

polyester mooring system for deep water.

In extremely mild and or directional environments (e.g. West Africa), spread-moored barges and ships have been

used as floating production facilities as the weather from the beam is sufficiently small to allow the moorings to

withstand these without having to weathervane. It may also be possible to use rigid steel risers and even surface trees in

conjunction with a ship/barge shaped structure in very mild conditions.

Semi-submersibles are a common type of floating structure used in the exploration and production of offshore

hydrocarbons. Figure 1.6 identifies the main features of a typical semi-submersible. These structures often comprise

two submerged horizontal pontoons which provide the main buoyancy for the platform but act as catamaran hulls when

moving location at low draft. Alternatively (as shown) a ring pontoon may be used for a



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fixed location. Typically, four to eight vertical, surface piercing columns are connected to these pontoons. The columns

themselves may have cross and horizontal bracing to provide structural strength and triangulated rigidity for the

platform. The deck of the platform is located at the top of the columns. The minimal water plane area contributed by

the vertical columns results in long heave, pitch and roll natural periods (with heave natural period being a critical

parameter for drilling units) and the heave, pitch and roll hydrodynamic loading can be minimised at the dominantwave period by careful selection of pontoon volume and water plane area. These features lead to

good response characteristics in typical operating weather conditions.

The good response characteristics provide an excellent platform for both drilling and production uses. However the

improved motion compared with ship -shaped vessels is achieved at the expense of increased structural complexity and

sensitivity of stability and draught to payload and position. Owing to this sensitivity, and because they have mainly

been designed as drilling units, they do not normally have any oil storage capacity.

The two main attractions of semi-submersibles are:

• Owing to their good motion response, they can be positioned over a well template to provide work over or possibly

drilling capability.

• Because they do not need to weathervane like a ship, they can support a large number of flexible risers.

Petrobras, who operate the most semi-submersible FPS, have units with more than 50 risers tied in from remote wells.

A good example of a semi-submersible being positioned over a template is the Liuhua FPS which provides a means to

recover and change out down -hole electrical submersible pumps. However if the floater only has a work-over

capability, wells must be pre-drilled and adding new wells later requires an additional semi-submersible to be brought

onto the field to drill those wells.

The main disadvantages of a semi -submersible are that:

• Unless pipeline export is possible, a FSU or direct shuttle loading system is required. The investment in a deep

water FSU goes much of the way towards the cost of a FPSO, so, providing only limited workover is required, the

FPSO will be a cheaper solution.

• The motions, whilst considerably smaller than those of a ship-shaped structure, are still too large to permit rigid

risers to be continuously connected in all weather conditions.

• Only a limited number of rigid risers can be supported because of the bulk of the tensioner systems required.

• Conversions only have a limited topside weight capacity.

• Sub-sea well re-entry from a semi-submersible is not as convenient as surface well re -entry from a TLP.

• Build schedules for semi -submersibles are generally longer than those of FPSO’s.

Deep draught semi-submersible shaped floaters will further reduce motion and may allow oil storage.

Station keeping is achieved primarily by chain/wire mooring systems. A number of rigs are also fitted with azimuthing

thruster capacity to relieve loads in the mooring system and assist in transit. A number of semi -submersibles also have

dynamic positioning systems (with computer controlled thrusters which respond to displacement or acceleration) which

permit their operation in deeper waters where moorings may be impractical.

Most semi-submersible floating production systems are based on converted dril ling rigs. For larger fields in deeper

water the topside payloads become larger so that only the larger drilling rigs are suitable for conversion to FPS unless

very substantial conversions (providing extra buoyancy and stability) are undertaken. However, the increasing demand

for drilling deep-water wells is forcing up day rates of the limited number of large deep-water rigs. In this situation it is

counter productive for oil companies to convert large drilling rigs and building new semi-submersible floating

production systems is preferred.



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1.2.3 Tension leg platforms

The heave, roll and pitch motion of a floating structure is often a controlling factor in its operability .The high strength

tethers of a TLP (Figure 1.7), whilst allowing surge, sway and yaw, limit the important motions and allow

uninterrupted drilling and the use of surface trees. The vertical tethers are designed to try and avoid resonance by

putting the natural periods in heave, pitch and roll below the wave periods and those in surge, sway and yaw well above

the wave period range.

Tension leg platforms typically have 3 to 6 vertical surface piercing columns with a complete ring of pontoons

because this is structurally more efficient and the TLP is not moved from location to location. TLP’s have a

sensitivity to payload through its effect on tether tensions. Excessive deck load may result in slack tether

conditions in large waves. They are therefore not used for oil storage.

The installation, in the Hutton field in 1984, and the success ful performance of the world's first tension leg oil

production platform has spawned others. Several, very different TLP’s have been installed to date. Of these all have

pipeline export except Heidrun which has direct shuttle loading.



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One of the main thrusts for future TLP projects is to reduce the long cycle time from start of design to first oil,

which is currently some 4 years. One possible way of doing this is to de-couple the deck design from the sub-

structure and accept a less optimised solution.

There is also interest in mini- TLP’s, supporting just the well system with minimum facilities. Several designs have been made in recent years offering an alternative to sub-sea templates with the intervention advantages of surface

completed wells.

TLP’s are in principle capable of being reinstalled at a different location when production at the initial field comes

to an end. However, no experience of reinstallation of a TLP at a different location has been gained to date.

1.2.4 Spars

The use of a Spar, as a storage unit, was pioneered in the Brent Field in 1976 and more recently for the floating

loading platform for the Draugen field offshore Norway. Over the last decade there have been numerous design

studies for production Spars and one is now in place on Oryx's Neptune field in the Gulf of Mexico.

Spars (with vertical circular cylindrical geometry as shown in Figure 1.8), by virtue of the large draught, havesignificantly reduced heave response and the possibility of oil storage. The reduced heave response permits the

use of surface trees and rigid risers, thus allowing drilling and work-over without the need for an extra drilling

rig. Indeed, this concept is only one of two designs (the other being the T LP) of floating production facilities

where surface trees have so far been used. Furthermore, rigid vertical risers can be used in greater water depths

and with higher temperature/pressure fluids than presently possible with the flexible risers commonly used with

FPSO and semi-submersible floating structure concepts. The rigid risers are self buoyant and are only guided by

the platform so no tensioning mechanisms are required.

The Spars installed to date have been compliantly moored to allow motion in all six degrees of freedom. However

a tether mooring, making them into a single column TLP, is a possible alternative.

A production Spar may be configured in a number of different ways, either with or without oil storage and with

surface or sub-sea completed wells. These options are shown in Table 1.1.

No oil storage Integral oil storage

Surface completion Oryx 'Neptune' Spar Best characteristics of TLP

Competitor for TLP and FPSO?

Sub-sea wells Mini-Spar or 'Nomad' Competitor for FPSO

Table 1.1 Spar options

Configured with oil storage and surface completed wells, a Spar may be able to combine the best characteristics

of the TLP and FPSO for fields where the reservoir can be reached from one drilling centre.

In the Gulf of Mexico, where the large infrastructure p rovides oil export routes with pipelines, it is natural that

the Neptune Spar is configured without oil storage. By supporting surface completed wells with buoyancy applied

to the risers, the Neptune Spar is acting as a direct competitor to a TLP.

Configured without oil storage and connected to sub-sea wens, the Spar can provide a low cost platform for a light

weight topsides. This topside may contain pumps for multi-phase pressure boosting, and in this form is currently

marketed as the 'Nomad' concept. It could also provide a means of dehydration for a remote satellite field.

Provided with oil storage and sub-sea (rather than surface) wells, the Spar is a competitor for the FPSO, but in

general it is expected that the FPSO will be cheaper when sub-sea wells are acceptable.



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1.2.5 Other concepts

A number of other concepts may be used in conjunction with or may be in competition with floating platforms.

these include fixed platforms, compliant towers and sub-sea completions.

Fixed platforms

Fixed platforms are preferable to floating production systems for large fields in small-medium water depths. The

long term lower operating costs and probably better reliability compensate for the possibly greater initial costs and time

to first oil. However for deep water (greater than about 150 m) or more marginal fields (field life less than perhaps 10years) the fixed platform is not economic.



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Where no oil storage is required then the fixed platform may be a jacket type. When oil storage is required then

a gravity platform or jacket plus FSU may be used.

As the water depth increases so a stiff jacket structure with natural surge periods less than 3-4 seconds becomes

difficult to design and it becomes better to place the surge periods at greater than about 30 seconds to avoid thelarge amounts of wave energy between 10 and 25 seconds. This leads to a compliant tower or a floating structure.

Owing to non-linear wave forces the 10 to 20 second waves will result in longer period ' slow drift ' loading and

an even longer surge period, up to about 200 seconds, may be selected, depending on the environment and

platform.

Compliant towers

There are numerous different configurations of compliant tower, but the best ones are those that have no moving

parts and achieve compliancy (i.e. long natural period) by careful design of the mass and stiffness (particularly

pile stiffness) distribution. The most attractive aspect of a compliant tower is that once installed it has the

capabilities of a fixed jacket with respect to supporting surface completed wells and having a high topside load

capacity. It is most suited to a field requiring a high number of wells drilled from one location. However , due to

its long development schedule and the fact that the wells must be drilled sequentially from the compliant tower

to capitalise on its capabilities, there tends to be a long period between the capital investment and the revenuewhich may hurt the field economics.

Compliant towers tend to work best at intermediate water depths, say 400 -700 metres where the steel weight

is still not too high and installation is somewhat easier. Since they have no storage capability , they are most likely

to be economic when a relatively short pipeline connection to au export route is possible.

Sub-sea

Sub-sea developments are a natural way to produce fields where nearby infrastructure can serve as a hub or host

platform. This implies more sub-sea developments as a deep-water area matures and acquires infrastructure.

Development schedules are short. The challenges are primarily focussed on hydraulics and flow in long pipelines,

issues of sub -sea facilities control and deep-water installation. Technology development is continually increasing

the industries capabilities in this respect and sub-sea developments are certain to play a large role in producing oil

and gas from deep water. Frequently sub-sea developments are used in conjunction with floating platforms.

1.3 Concept selection

1.3.1 Development strategy

In the life cycle of a project, it is in the development planning stage that there is the greatest potential to impact

the earning power, see Figure 1.9. Once a project moves into au execution phase, the project team has somewhat

limited impact on earning power through budget and overall schedule controls. It is natural then to focus attention

on the early field development planning stage to improve the profitability of deep-water offshore fields. At this

early stage of the field development, decision making is made difficult by very large uncertainties. Managing this

uncertainty, to make the right decision with limited knowledge is one of the keys to successful field development

planning.

To form a field development strategy, the following steps are taken:

• create sub-surface (reservoir) models,

• select sub-surface development concepts,

• select surface development concepts,

• perform safety evaluation,

• perform economic evaluation.



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These steps are used to choose a promising strategy and then again, iteratively, until an optimum field

development strategy is achieved. The following mainly addresses the third step above.

The greatest economic risks lie in the sub-surface modelling and it is essential that surface facilities are planned

taking account of this uncertainty. If the final development strategy is to be robust in most situations, surface

facilities should be selected based on a wide range of probability weighted sub-surface models. This involves

determination of the expected monetary value of different development scenarios across the probability weighted

range of sub-surface outcomes. Advances in risk modelling and the use of highly efficient field development

costing tools makes the use of such techniques possible in a routine and structured way.

One specific use of probability techniques in field development planning is the assessment of the impact, or value,

of information. For example the options of proceeding with the development of a discovery, drilling another

appraisal well or possibly carrying out an extended production test can be assessed in terms of how much the

expenditure to acquire the 'information' impacts the 'value' of the field. If the extra well significantly improvesthe return on the field, by for example allowing more optimum facilities, then the well is justified.

When d etermining the economic return from the field, the costs and revenues over the whole field life are

important; in many situations the total operating cost (Opex) is similar to the capital expenditure (Capex). Thus

cost saving ideas which save Capex must be evaluated taking account of their operating costs through the life and

any impact they may have on revenue, by for example changing availability. It must be realised, however, that

there is always an optimum availability and chasing the last few per cent of downtime may involve

disproportionate cost and have a negative impact on revenue. For example a FPSO with disconnectable mooring

may be shut down for some periods, but can have a cheaper mooring system which is not designed for severe

storms.

Safety evaluation is a key part of the concept selection process. Some concepts may be significantly less safe than

others owing to for instance:

• diving requirements,

• limitations of deck size and layout that puts accommodation at risk from fire and blast,

• excessive motion of a small floating platform that could make helicopter access difficult,

• dependence on non-redundant structural components,

• use of key components that are difficult or impossible to inspect.

The UK HSE would expect the ALARP principle (maintaining risk to personnel to be As Low As Reasonably

Practical) to be applied. In other countries the authorities may require the risk level to be demonstrably lower than

some prescribed level.





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Of the a wide range of mature and novel production system concepts in the industry those most commonly considered

have been discussed in Section 1.2 and are summarised in Figure 1.11.





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Structure (GES) is probably somewhat less. Floating structures all have minimum water depth limits but as yet

undetermined maximum water depth limits. Existing and planned facilities include Auger TLP (872 m); Mars

TLP (894 in), Ursa TLP (1200 in); Petrobras XVII1 semi -submersible (910 in); Mensa sub-sea (1675 in).

The increases in water depth for exploration drilling and production over time are shown in Figure 1.12. This

suggests that the water depth limit for production simply lags that for drilling by 10 -15 years. Alternatively theremay be little point in drilling prospects which cannot be brought into production within 10 -15 years.

Distance to shore or an oil terminal has a major impact on the most economical crude export option. A pipeline

is generally the preferred solution but if the distance to shore is large, off shore loading to tankers is more cost

effective. It is economics based on life-cycle cost that ultimately determines the choice between a pipeline or

offshore loading system, and here capital cost, operating cost and tariffs must all be considered.

In most situations in- field oil storage is required to make the offshore loading efficient and avoid repeated

production shutdowns. In-field storage may be integral to the production facility (e.g. FPSO, Spar) or stand-alone

(e.g. FSU- Floating Storage Unit). The offshore loading facilities may also be integral to the production facility

(e.g. FPSO) or stand alone (e.g. OLS .Offshore Loading System). The strategy of retaining a shuttle tanker in-field to provide temporary storage, possibly using twin-loading systems, looks increasing1y attractive and is

threatening the traditional role of the FSU.

The main oil export options, illustrated in Figure 1.13, are:

• production facility without storage + pipeline,

• production facility without storage + direct shuttle tanker loading, ,

• production facility without storage + Floating Storage & Off-Loading Unit (FSU),

• production facility with integral storage plus stand alone Off-Loading System (e.g. Spar + OLS),

• production facility with integral storage & off -loading (e.g. FPSO).

The storage capacity provided on an FPSO is a function of the number of shuttle tankers used, the shuttle tanker

size, the maximum amount of estimated shuttle tanker waiting time due to weather conditions and distance to

nearest port.



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The FPSO may return to port for cargo discharge as does the 'SWOPS' vessel. This option is in general valid onlyfor marginal fields with low production rates and a small number of risers. This solution is perhaps most suited

for well testing and early production type of vessels producing through a single riser.



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The other aspect of proximity to shore or other existing infrastructure is the potential for a sub-sea tie-back

development. Here sub-sea wells are located in deep water and tied-back to a shallow platform via individual

flowlines from separate satellite wells or through a single co-mingled export flowline from a sub-sea manifold.

The tie-back distance record of Togi at 48 km was doubled to 109 km by the 1997 Mensa development.

The number of drilling centres and the number of wells required at each centre to adequately drain the reservoiris dependent on the field architecture. Advances in extended reach drilling technology have increased the along-

hole depth of wells to almost 10 km, with horizontal to vertical depth ratios of up to 3 being possible. However ,

in many situations it is still not possible to efficiently drain the reservoir from one drilling centre. This is often

the case when the reservoir is relatively shallow and has a large area, see Figure 1.14. Multiple drilling centres

are certainly required where it is planned to have satellite fields tied back to a central production facility .If there

are only a small number of drilling centres and frequent drilling or workover is required through the life of the

platform then there is some advantage in having a platform with a drilling and work-over capability. Otherwise an

additional vessel will be required for these purposes.

Reservoir fluid parameters, production chemistry and hydraulics must all be considered in selecting the optimum

development concept. This must encompass the implications of:

• CO2• H2S (naturally occurring as well as from reservoir souring),

• asphaltene deposition,

• wax deposition,

• scale precipitation,

• hydrate formation,

• sand production,

• slugging flow in multiphase flowlines,

• reservoir pressure and drive mechanisms.

The parameters affect the well intervention (work over) frequency as well as the design of the production facilities.

Well intervention may be necessary to maintain optimum performance due to mechanical failure, the effects of

corrosion and wear or the need to open or close production from different levels.

The risk to personnel will vary with the concept. There will be some variation in risk caused by the different

hydrostatic, dynamic and structural behaviour of the different concepts but, for well designed platforms with:

• adequate reserves of intact and damaged stability ,

• adequate ultimate and fatigue strength, and

• constructed from good toughness steel.

these risks should be small.

The variability in risk will be much more associated with:

• oil and gas import and export,

• the process system,

• the layout of the topside equipment,

• the position of the accommodation,

• collision with errant vessels (trading vessels, shuttle tanker, supply boat, safety boat),

• the provision of adequate evacuation systems (free fall lifeboats or other systems),

• preparations for inclement weather (riser/turret disconnect etc.).

Clearly the platform concept affects these risks but they need to be considered in conjunction by the range of

disciplines, not just the naval architects and structural engineers.



22



23

1.3.4 Performance requirements

A floating structure for hydrocarbon drilling, production or export typically has the following performance

require ments:

• sufficient work area, deck load capacity and perhaps storage capacity ,

• acceptable response to environmental loads,

• adequate stability ,

• strength to resist extreme conditions,

• durability to resist fatigue loading,

• may require a combined function (e.g. drilling and production),

• may be transportable.

No one structure type can provide optimum performance with regard to each of the above requirements. Thus,

any field development or exploration activity should identify the optimal structure type for the particular task from a

number of classes of floating offshore structures. For example, excellent stability characteristics may lead to

excessive motions in waves. In response to these conflicting requirements, the offshore industry has developed

a wide variety of platforms.

1.3.5 Concept selection

The development concepts identified in Section 1.3.2 above must be matched to the field requirements discussed in

Section 1.3.3 to identify likely field development schemes. This has been done for deep water in Table 1.3

based on combinations of: distance to shore, number of drilling centres and well intervention frequency. Whilst

there are certainly other factors that may influence concept selection in a particular situation, Table 1.3 appears

to be a reasonable predictor of concepts selected in reality.

The logic used in Table 1.3 is as follows.

The concept selection is based primarily on an oil field with associated gas which may be exported, re-injectedor possibly flared. For a gas field, possibly with associated liquids, different criteria will apply.

When the distance to shore is short, pipeline export is assumed unless a FPSO is used since this already has an

integral export system. Where the distance to shore is long, offshore loading is assumed.

Where the well entry frequency is low, it is asSW11ed that sub-sea wells will be the cheapest and only concepts with

sub-sea wells are proposed for both single and multiple drilling centres.

For single drilling centres and high well entry frequency, surface t rees are preferred. These require TLP’s,

Compliant Towers or Spars. A semi-submersible with work-over capability is also a candidate.

The combination of multiple drilling centres with wells that need frequent intervention, is accommodated in

shallow water by using a well head jacket. In deep water this would require multiple TLP’s or Compliant Towerswhich is not economically viable. No deep water field has yet been developed which combines multiple drilling

centres and frequent well intervention but the currently favoured solution is a small unmanned TLP, or mini- TLP,

which only supports the wells and provides a capability for drilling and work-over. The mini- TLP has no

processing facilities as these are provided by another central facility such as a semi-submersible or FPSD moored close

by. It is important to recognise that the mini- TLP is providing an alternative well system to sub-sea wells and flow

lines and that the same production facility can be used in either case.

Another important situation in deep water in which surface completed wells are potentially attractive is where the

combination of extended reach drilling from one or more mini- TLP’s is simply cheaper or technically more robust

than sub-sea wells, flow-lines and risers. With the recent significant increases in the cost of deep water drilling



24

units and the potential for relatively cheap mini- TLP’s this is becoming a realistic possibility .Again such a system

would fit wel1 with the processing, storage and off -loading capability of a FPSO moored close by.

ln shallow water (say less than 150 m) fixed structures may be expected to be chosen. They are clearly favoured

if the field characteristics include:

• single drilling centre,• local pipeline infrastructure,

• long field life (greater than 10 years),

• frequent workover requirements.

However even in shallow water an FPSO, in conjunction with sub-sea wellheads, may become the optimum

solution. It would be favoured by:

• multiple drilling centres,

• no pipelines,

• short field life,

• infrequent workover requirements.

Distance to Number of Well Entry Development Concept

shore/Infra- Drilling Frequency

structure Centres

Semi+Subsea+Pipeline

Low SWP+Subsea+Pipeline

One FPSO+Subsea

TLP+Pipeline

Compliant Tower+Pipeline

Spar Pipeline

High Semi+Mini-TLP+Pipeline

Semi+Subsea(adjacent)+Pipeline

SWP+Mini-TLP+PipelineFPSO+Mini-TLP

Short

Semi+Subsea+Pipeline

Low SWP+Subsea+Pipeline

FPSO+Subsea

Semi+Mini-TLP+Pipeline

High SWP+Mini-TLP+Pipeline

FPSO+Mini-TLP

FPSO+Subsea

Low Spar+Subsea+OLS

One Semi+Subsea+FSU or DTL

TLP+FSU or DTL

Spar+OLSHigh Compliant Tower+ FSU or DTL

FSPO+Mini-TLP

Semi+Subsea(adjacent)+FSU or DTL

Long

FPSO+Subsea

Low Semi+Subsea+FSU or DTL

Multiple Spar+Subsea+OLS

High FPSO+Mini-TLP

Spar+Mini-TLP+OLS

Key: OLS=Offshore Loading System, DTL-direct Tanker Loading, FSU=Floating Storage Unit,

SWP=Shallow Water Platform

Table 1.3 Deep water field development concept selection guide (Inglis, 1996)



25





27

uncertainties.) These methods are known as load and resistance factor design (LRFD) or partial safety factor

methods (PSF). It is still generally impossible to precisely quantify reliability so it is usual to calibrate the safety

factors against experience with existing designs. It is argued that this leads to LRFD/PSF designs having a more

uniform level of reliability across structure types and loading regimes than would be obtained from a structure

designed using WSD allowable stresses.

Most calibration studies performed to date have been on fixed structures. It should not be assumed that the safety

factors determined for fixed structures are also applicable to floating structures. They have different response

characteristics and different design methodologies that may require different factors to be used.

The offshore impact of these developments gathered momentum with the move by the American Petroleum

Institute to put its recommended practice for fixed structures, RP2A, on an LRFD basis (Moses, 1989). These

techniques have recently been applied to the development of acceptance criteria for jack-ups (Ahilan, Baker and

Snell, 1993) and work is currently in progress for its application to Tension Leg Platforms. Therefore, the process of

rationalisation of the design integrity of floating structures via the explicit consideration of uncertainties is well under

way. Current designs still tend to use the traditional WSD or LRFD approaches but with additional probabilistic

analysis techniques to assist in optimisation and to achieve uniform safety levels.

The Piper Alpha disaster and the resulting loss of 167 lives in July 1988 changed the approach to safety in the

UK offshore oil industry. Rather than simply designing to codes of practice it was realised that it was necessary

to consider the overall safety of the installation, to identify hazards and to, if necessary, modify the structure or

procedures until it can be demonstrated that the risk to life is sufficiently small. This is often referred to as a change

from prescriptive to goal setting regulation. Often the structural engineering is still performed to codes because a

structure properly designed and built to these codes is considered to provide an acceptably low risk.

However certain decisions may have much broader effects on the risk levels so minimisation of risk must be a key

consideration in concept and detail design. Sometimes probabilistic risk analyses are undertaken in order to

quantify the risk. Such approaches (probabilistic and risk analyses) require a good understanding as to the

acceptable risks, because without this knowledge, the work based on probabilistic/risk analyses cannot be used

within the project decision process. However, definition of acceptable risks is generally complex (for example how

does one value the human consequences in order to assign the acceptable probability?) and varies according

to each particular situation because of the specific human, economic, political and environmental consequences.A concept for determining this acceptable risk has been introduced by the UK Health and Safety Executive which

suggests that the risks of any venture shall be kept As Low As Reasonably Practicable (ALARP). This formally

requires that if a risk reduction measure is practicable, it should be carried out whether the venture already

satisfies some 'absolute' risk measure. Others have argued that the acceptability or otherwise must be based upon

industry consensus, historical practice and consequences, so that once a venture risk is shown to be equal to or below

some target based upon these parameters, any further ris k reduction measure is superfluous. This remains an area of

discussion and legal interpretation.

This book deals with the design integrity of floating structures and dependent systems such as moorings and risers. It

describes the analysis methods which are applied and considers the interaction between various issues, in so far as they

affect analysis but the complete systems and safety issues are beyond the scope of this book. It provides all the

individual building blocks, which are needed in the analysis relating to the integrity of floating offshore structures.

These can be divided into five main areas:

• environment and loading,

• stability,

• station keeping,

• motion response,

• structural integrity .

The last four areas are taken in turn and discussed below.



28

1.4.2 Stability

A design requirement that is unique to floating structures is that of hydrostatic and dynamic stability. The work

platform should be able to remain floating upright in the extreme environmental conditions. Thus the design for

stability is a critical part of the floating structure design. It is important to have strict procedures for weight controlduring construction or upgrade and through the life of the structure. The platforms must also have adequate reserves of

stability when certain damage scenarios have occurred, as specified in the rules and regulations. Ibis is to prevent the

loss of the platform arising from flooding caused by limited damage to the shell plating. Guidance on this topic is given

in Chapter 4.

1.4.3 Station keeping

The floating structure experiences both steady and unsteady loads which cause large displacements from the

original target position. The structure is usually held in position using moorings, tethers, dynamic positioning

thrusters or a combination of these. The integrity of a number of systems such as risers and gangway bridges

depends on the station keeping ability and the limitations of the station keeping systems dictate the limitations

in the operability of the floating unit. Thus, the integrity of the station keeping system is a critical facet in the

successful design of floating structures. Guidance on analysis of station keeping ( taut and catenary moorings,dynamic positioning systems and tethers) and risers is given in Chapters 9, 10 and 11.

1 .4.4 Motion response

In contrast with fixed structures, all floating structures are compliant to varying degrees. Thus their response

under the influence of extreme environmental loading is significant and successful floating structure design

requires the optimisation of these responses by judicious selection of dynamic characteristics of the floating structure.

For example, water plane area to displacement ratios may be selected to minimise pitch and heave responses at the

predominant wave periods and natural period is often engineered to either push it above the wave period range (thus

making it truly compliant as for catenary moored semi-submersible) or bring it below (as for TLP heave). Designing to

control the motions therefore requires a general unders tanding of wave loading and its interaction with the structural

geometry. Guidance on this is given in Chapters 3 and 5.

1.4.5 Structural integrity

It is a requirement of any structure that it has sufficient strength to withstand operational, extreme and accidental loads.

This issue is fundamental because failure can result in catastrophic consequences. Indeed, the capsize of the semi-

submersible Alexander Kielland, with the loss of 123 lives, in 1980 was initiated by the cracking in a brace.

The structural integrity of a platform may be built in and maintained in a number of ways. Firstly, the structure

should be designed to withstand the static and environmental loads. This implies that gravity, buoyancy, wind,

wave and current loading should be addressed as well as intermittent but extreme impact loads due to slamming.

For instance, the air gap -which on semi-submersibles and TLP platforms is the distance between the deepest

draught operational waterline and the bottom of the deck- should be chosen to prevent any slamming in extreme

seas as platforms are usually not designed to withstand such large impact loads. Secondly, fatigue should be

considered, as the predominant loading mechanism on these structures is due to waves and is thus cyclic. Thirdly,

the structural members are prone to damage from accidental loads such as ship impact and dropped objects. They

must be capable of absorbing the energy, albeit with large deformation, from likely impacts. Finally, any

degradation in the construction material with age, through fatigue and corrosion, must be taken into account at

the design stage and the material used should be sufficiently tough for any likely fatigue cracks not to reach a

critical size and cause a fast fracture and for large deformations to be acceptable without rupture under accidental

loading. Guidance on designing to resist these various structural failure mechanisms is given in Chapters 7- 8.



29

To maintain safety, some structural inspection will probably be required through the life of the structure. The

interaction between design, construction and practical levels of inspection should be considered during design.

1.4.6 Instrumentation

Improved understanding of the above four areas -stability, station keeping, motion response and structural

integrity -can be obtained from full-scale instrumentation. This greater knowledge can improve safety and also

reduce casts as already shown by indus1Iy's experience with fixed structures. Thus, in any innovative application,

instrumentation of the deployed structure should be seriously considered.

1.5 Regulations

Floating structures are subject to the regulations of the state in whose waters they operate. There may be many

sets of regulations, ship regulations may be in force when a floating structure is on its way to an oil field, oil

production regulations when the structure is installed at the field. Furthermore the regulations may change over time, as

in the UK with the change from prescriptive to goal setting requirements. This section only provides an indication of

the types of regulations that may affect a floating platform. The naval architect/engineer must determine and apply the

regulations that are appropriate for the particular countries where a platform is built and operated. Increasinglyreliability and risk analysis is used both within prescribed codes and within the justification of particular platforms to

the regulatory authorities.

The regulatory authority requirements can typically be:

• national statutory (legal) requirements,

• certifying Authority requirements,

• international regulatory authority requirements,

• flag state requirements,

• classification society requirements,

• requirements of specified national and international standards and codes.

To aid the engineers who wil1 later be involved in the design or identification of the candidate vessels and the

development of the technical! solutions, it is often prudent to clearly identify and detail the main regulatory

authority requirements in the Design Basis document rather than just identify or refer to the applicable regulation or

code. Ibis helps to ensure that all project personnel are fully aware of the requirements and their impact on the design or

vessel selection and subsequent conversion work. Where conflicting requirements occur, the most stringent one or the

most stringent set of criteria should be clearly identified in the Design Basis document.

1.5.1 Classification

Classification societies have a long history in connection with the shipping industry. Most mobile floating structures,

including those which are not ship shaped, also obtain classification from one of the classification societies.

Classification society rules have evolved over the years and simply provide a basic design standard for mobile

structures. Most mobile drilling units are classified by one of the members of the International Association ofClassification Societies (IACS) along with ships, barges, cranes and other support vessels.

1.5.2 Government regulations

Along with fixed offshore structures, all floating structures used for the exploitation of hydrocarbons must satisfy the

ratification requirements of the country in which the field is located. This certification often imposes more



30

stringent requirements than those of classification. To operate in the UK continental shelf, every installation must

satisfy the Health and Safety Executive (HSE). All floating structures directly involved in exploration, exploitation or

storage of hydrocarbons on the Norwegian continental shelf must satisfy the regulations of the Norwegian Petroleum

Directorate.

1.5.3 Recommended practices

A significant contributor to technical! standards associated with offshore exploration and production has been the

American Petroleum Institute (API). The API recommended practice for fixed structures, RP2A, is universally

recognised and often adopted by the offshore industry in preference to country specific requirements. For instance,

the UK Statutory Instrument SI 289 (now superseded) required the use of at least the individual 50-year return

conditions in the evaluation of environmental loads on a UK installation but many structures in the UK sector have

been designed according to the loo-year return condition requirements of API. Note however due to the permissibility

of joint probability effects in the latter, the API loads may well be less than the collinear, concurrent summation

required of the SI 289.

API has already published recommended practices for the design of TLP’s and for the moorings of floating drilling and

productio n systems. API has continued its pioneering work with a reliability based model code for Tension LegPlatforms which may be extended to other floating structures.

1.5.4 Unification

The proliferation of national and international codes and classification society rules result inevitably in conflicting

requirements for the design of floating structures. This has engendered moves towards the unification of standards.

Through the International Standards Organisation (lSO) and the International Maritime Organisation (IMO), unified

codes are currently under development for various facets of floating structure design and operation.

lSO is developing, with close co-operation from existing code generators and industry, codes which will encompass

both fixed and floating structures. IMO is taking charge of the unification of ship related requirements.

At present the fixed structure lSO is expected to be a largely self contained document whereas the floating structure

lSO is expected to refer to many other codes and standards such as API RP2V and RP2U for the design of flat plate andcurved shell structures.

1.6 Project strategy

This section identifies the main components or 'building blocks' for a floating structure build or conversion

project strategy and for a typical floating structure project these are:

• establishment of the project specific commercial constraints,

• identification of the project specific functional requirements,

• identification of the applicable Regulatory Authority requirements,

• concept definition,

• identification of suitable concepts or candidate vessel(s),

• development of the technical detail solutions,

• identification of the scope of work,

• development of realistic project schedule and budget.

The above proposed main components for the strategy are listed in the order they are normally dealt with during a

project. However, it should be noted that a number of the above components are dealt with to a certain extent



31

in parallel and that there also exists a certain amount of 'feed-back' between the components. As an example the

identification of the commercial constraints, the functional requirements and the applicable Regulatory Authority

requirements can be carried out in parallel but the final selected field development concept and any vessel selected

for conversion will also to a certain extent determine what rules and regulations will apply.

1.6.1 Commercial constraints

Before any project can proceed a careful commercial evaluation of the project economic feasibility has to be carried

out. Ve ry simply, the revenue the project has to generate (e.g. through the recovery of hydrocarbon reserves at a certain

estimated daily production rate) in a particular tax regime has to be sufficient to allow profits to be made and to cover

all capital costs, other development costs, the costs of operating the facility and finally the costs associated with the

removal and disposal of the facility in an environmentally acceptable manner. The main impact this has on the

technical work is that it limits the available technical solutions to those which have estimated capital, operating and

removal expenditures within sufficiently low limits to still allow an acceptable profit to be made. It is essential that

these limits are clearly defined before any significant technical development work commences.

1.6.2 Functional requirements

The first technical items to be dealt with are the project specific functional requirements. Here it should be immediately

noted that the project specific functional requirements may not be synonymous with the field specific requirements as

many vessels operate on marginal fields with relatively short field lives and hence may be designed to be re -located

onto other fields in similar environments. The project specific functional or performance requirements concerning the

floating structure or system are usually summarised in the ' Functional Specification'.

The main project specific functional requirements to be identified are:

• environmental criteria,

• operating requirements,

• import requirements,

• production requirements,

• export requirements,

• manning requirements,

• replenishment requirements,

• removal requirements.

Environmental criteria

In general the first criteria to be identified are the environmental criteria in which the vessel has to o perate and survive.

If the field life is long then the field specific environmental conditions may be used, otherwise a market location e.g.

West Coast of Africa, may be selected and environmental conditions selected which allow the vessel to be used

anywhere in the specified market location.

The criteria of interest include:

• water depth including storm surge and tidal information, ,

• water data (e.g. salinity, temperature profiles and extremes, pollutants),

• wave data,

• current data,

• wind data,

• ambient air temperature and humidity data,

• sea bed soil data.



32

For certain specific geographic locations additional information may have to be added such as sea ice data, ice load

data, earthquake data, etc.

It is important that all relevant environmental data must be clearly identified in the Design Basis document.

Operating requirements

The main operating requirement is usually the limiting environmental conditions in which the platform or system

has to be capable of operation.

This may cover the extreme environment al conditions in which the platform has to survive on the field location,

the environmental conditions in which the platform has to carry on producing hydrocarbons, the maximum

environmental conditions in which any shuttle tanker must stay connected and the worst environmental conditions in

which the vessel has to be able to connect up to a shuttle tanker.

For vessels with drilling equipment, the required limiting environmental conditions for the various drilling operations

would be specified.

For some vessels this may also include maximum cruising speeds, fuel consumption limits, manoeuvrabilityrequirements, DP system station keeping requirements, limiting environment al criteria for heavy lift operations etc.

Import requirements

The methods of treatment and the quantities of untreated crude oil or natural gas to be imported have to be identified

and specified as this determines the type, number and size of import risers.

Production requirements

The main characteristics of the field and the process equipment packages should be clearly detailed and identified:

• field life,

• product production rates,

• process equipment deck area requirements,

• process equipment weight, centre of gravity and mass distribution data,• process equipment arrangements,

• process hazard data.

For systems involving tanker export, the production rates together with shuttle tanker size, off loading frequency

and estimated shuttle tanker waiting time due to the environment al conditions determine the product storage

requirements for the production vessel. However, if the product export is via a pipeline then the production rates

may be limited by the size of the process equipment and the size of the export riser.

The minimum required process deck area will have to be established and specified relatively early. However, this

is seldom a problem for large vessels such as tankers but if the platform is a relatively small semi-submersible,

jack-up or smaller ship then the area requirement and the location of the process deck are usually critical.

The process equipment dry and operating weights and their mass distributions are required for lightship, stability and

vessel motion calculation purposes.

The process equipment arrangements will be required in order to allow wind loading calculations to be performed

mainly as input into stability and mooring analysis calculations.

The hazards imposed by the proposed process equipment must be clearly defined as they determine the hazardous

area zones, the rating of the deck equipment, the design criteria for any blast walls, passive fire protection

requirement, water for fire fighting, etc..



33

Manning requirements

These will determine the amount of accommodation etc. required.

Replenishment requirements

Consideration should be given to the provis ion of regular supplies for operational purposes and the crew members.Adequate handling facilities (generally offshore cranes) should be provided to off-load provisions from supply boats.

Lay-down platforms should also be provided for the supplies and for any other service and maintenance requirement.

ldeally, handling facilities should be provided over the entire deck area.

Removal requirements

Currently the removal requirements vary significantly between geographic regions from various levels of partial

removal (to allow unrestricted shipping over the field location) to complete removal down to seabed level.

However, it is generally accepted that as the concern for the environment increases the removal requirements will

become increasingly more comprehensive and stringent. This increases the pressure on the designers to design the

facilities and equipment to be removable. Increased international competition and consequent commercial pressures in

combination with an ever increasing number of small hydrocarbon finds with short production lives being declared as

commercially viable have also lead to the need to design the facilities and equipment to be not only removable but also

reusable. The reusability requirement also demands that the facilities and system design have to have a significantamount of flexibility to allow reuse in different environments, water depths and on fields with different reservoir

characteristics and sub-sea equipment layouts.

As there are definitive needs to design for removal and reusability the criteria and requirements should be clearly

established and it should ensured that the subsequently proposed engineering solutions meet the agreed criteria and

requirement.

1.6.3 Concept definition

During this phase (which may be part of the concept selection stage described in Section 1.3, or may follow on from it)

the field hardware main 'building blocks' or main components are defined Typically these comprise the following main

systems:

• type of support vessel (i.e. TLP, semi-sub, / jac k-up, mono-hull),

• marine system (ballast system, hull ventilation system, thruster system, where applicable, etc.),

• sub-sea system,

• mooring system,

• riser system,

• turret system (if required),

• production system,

• drilling facilities (if required),

• export system,

• accommodation unit.

1.6.4 Technical solution

Once the candidate design or vessel is known and, for a conversion, the vessel technical documentation is available, the

engineering of the technical solution can commence. It is often beneficial to divide the engineering process into a

number of distinct phases, each phase having its own objectives and deliverables. For a typical conversion project the

engineering work may be divided into the following three phases:

• front end engineering and design,

• detail engineering and design,

• construction/ conversion support engineering.



34

The first two phases are described below:

Front end engineering and design

During this phase the technical concept is outlined on the global rather than detail level. All the technical solution

main 'building blocks' are identified, defined and located on the vessel. Solutions are also identified for all the

vessel main systems and components requiring modification, upgrading or replacement.

At this stage the team should not be t oo large and should work as an integrated team with no discipline barriers.

For the work to be carried out successfully the team must be high I y experienced and have a sufficient range of

specialist technical and financial skills. It should consist of an appropriate mix of marine engineers, electrical

engineers, instrument engineers and naval architects working closely with the reservoir, drilling sub-sea, topsides

process and cost engineers. Personal experience is backed up with in -house and openly publis hed information.

Previously analysed data, e.g. MacGregor and Smith (1994) for FPSO hulls, can be particularly useful at this stage.

Projects are often structured in a manner which allows the project to be terminated at the end of the front end

engineering and design phase, showed the project capital expenditure estimates based on the budget costs enquiries be

too high. If budget cost and schedule estimates in combination with the satisfactory development of a technically

acceptable front-end engineering solution is acceptable then the project can proceed to detailed engineering. If

conversion is selected, at this stage the commercial arrangements can be concluded to reserve the preferred candidatevessel for the project.

Detail engineering and design

During this phase the detail engineering of all 'building blocks' commences to transform the concept into detailed

design and working drawings. Since the design of every unit has an impact on other disciplines, the importance of

inter-discipline communication during this stage cannot be over-emphasised. All package specifications and enquiry

packages are issued as soon as possible in this phase to obtain a realistic price, weight and delivery schedule of every

component from the vendors.

Particular attention should be paid to the topside/vessel deck interface details where large concentrated forces are

delivered to the vessel deck. Deck deflections due to environmental forces must be considered in the design of these

areas. Interface details should allow for misalignment tolerances between platform structure and topsides support

structures.

Fatigue life usually constitutes a critical design consideration. All structural details should be developed to

minimise local stress concentrations.

It is important that the warranty surveyor is involved with transportation and installation aspects from the early stages

of the project because late modification may be expensive and cause delay.

During this phase the construction/conversion yard is selected and the remaining work is transferred to the yard.

This usually consists of the preparation of fabrication drawings and the engineering of secondary and outfit steel.

1.6.5 Schedule

The schedule must be drawn very carefully to achieve the planned 'first oil' date within the budget cost for thesuccess of the project. Project targets should be monitored regularly following the schedule critical path. Due to

the multi-disciplinary nature of these projects, any delay in one area will always have implication in other disciplines.

Particular attention should be paid to long lead delivery items.

The schedule should include all construction, facilities installation, commissioning, tow-out to installation site,

laying of mooring lines and hook-up of the sub-sea flow lines. Where the concept requires the use of shuttle tanker for

export, the client should ensure availability of the tanker.



35

1.6.6 Weight control and payload estimate

Weight control and payload estimates are always a critical feature of floating structures. This is especially true for

weight sensitive structures such as semi-submersibles and tension leg platforms. The main purpose of weight control

and payload estimates are to ensure that the vessel:

• has adequate stability at all operating and temporary draughts,

• floats on even keel,

• does not have excessive draught at 'float out',

• is capable of carrying the intended payload.

Floating structure weight control is not merely a summation of weights. The addition or removal of a weight usually

also causes trim and heel angle changes, which have to be corrected by the removal or addition of ballast.

In extreme cases the addition of a weight requires the same weight of ballast to be added in order to maintain even keel

thus having a double effect on the payload.

For practical reasons, in the marine industry the vessel weight is divided into the lightship weight and dead weight,

and it is proposed that this weight breakdown approach is maintained throughout the conversion phase and subsequentoperation phases. The lightship weight is the weight of the vessel complete including hull, machinery, outfit items,

equipment, and any other permanently fixed items (including process equipment). The accurate calculation of the

lightship weight allows precise estimation of the float-out draught and the determination of the actual light ship centre

of gravity position during the inclining test. The deadweight is the carrying capacity of the vessel at a particular draught

and includes weight of cargo, fuel, any liquids in any process systems, ballast water, fresh water, stores, crew and their

effects. For a vessel with drilling facilities this would also include drill string stored on the pipe rack, drilling mud and

other drilling liquids, chemicals and loose items.

1.7.1 Extreme environmental data required for analysis

Return period criteria

The simplest environmental data to use for design are the combined individual e.g. 100-year return period values

(see Section 2.8 and Figure 1.21). These are the individual most probable maximum values in that period. The precise return period chosen largely depends on the regulatory authority and the Oil Company. The level of safety

is not solely dependent on the return period, safety factors, for instance, will also have a large effect and overall

it is anticipated that the strength of the structure should only be exceeded by conditions which would be expected

to occur once in about 104

to 106 years. It is sometimes argued that a better approach is to design for a 10

4-10

6

year event and, for instance, the NPD regulations do require additional checks with these higher return period loads.

If the response is dominated by one environmental parameter e.g. wave loading then combining the separate 100-

year return period responses is satisfactory. The environmental data might provide information about directional

maxima so different values may be appropriate for different directions. This may be allowed for in mooring and

flexible riser design.

Commonly several metocean parameters will be important. This leads to three problems:

• The assumption that all the individual maxima occur at the same time may be too onerous and result in an

excessively expensive design.

• For some types of structure the maximum wave force occurs with the largest waves, however, for a ship or barge

the largest forces may occur with moderately large waves having a lower period than the largest waves.



36

• The assumption that the worst conditions are when the directions of sea, swell, current and wind are all aligned

will usually be conservative for semi's, TLP’s, spars and conventionally moored ships and barges. The co-linearity

assumption may be conservative or un-conservative for a ship or barge on a single point mooring. (As discussed

above.)

Response based environmental design criteria

To avoid excessive conservatism, to allow for the likelihood of largest ship response in moderate but not the largest

waves and to rationally design for non-optimum heading angles of a single point moored tanker the industry is starting

10 use a response based criterion for the assessment of extreme loading design combinations

(Marshall and Rezvan, 1995). An overall flow diagram for response based design is shown in Figure 1.21. Using

this method the response of the platform is estimated and extrapolated to e.g. 100-year values using extreme value

statistical methods (as opposed to extrapolating the individual environmental effects to the e.g. 100-year values or

attempting to construct an extreme joint probability description of the environment). The method usually relies on

hindcasting sea, swell and wave driven current from atmospheric pressure data (which unlike wave and current data is

available for a long period of time); A time history of environmental conditions (Hs sea, Tzsea, Hsswell, Tzswell, mean wind

speed and wind driven current) is obtained, typically at 3 to 6 hourly intervals. In addition to these tidal currents, other

(non wind driven) currents and sea level variation are estimated. The overall environment can then be applied to asimplified mathematical model ( or polynomial equation fitted to represent the behaviour) of key rigid body and

structural responses. A time history of the peak responses to the combination of all these environmental loads is then

generated for each hour of s imulation. Many of the loads may be regarded as quasi static over each 1 hour period,

however the wave frequency and slow drift frequency parts of wave and wind loading will need some non-linear rule

for their combination which will depend on the assessment of likely correlation.

The storm by storm time history of response over many years is then subject to extreme value analysis in order to

determine the extreme values of each of the responses as predicted by the simplified model. Because the calculated

responses are obtained from a simp1ified model and because they are only a limited number of the many responses and

internal stresses that need to be considered for design, these responses are not used directly for design. Instead they are

used, in conjunction with the simplified model, to determine a range of simple loading conditions which duplicate the

extreme conditions found from the extreme value analyses. These loading conditions are then applied to a detailed

model of the platform. The accuracy of the overall approach, including the simple model needs to be determined. Itmay be that the safety factors determined by code calibrations for existing techniques applied to fixed structures may

not be appropriate for these response based methods.

Environmental loads typically considered for design

The types of environmental data required for extreme value analysis are:

Wind A gust speed and its variation with height or a mean hourly wind speed and a wind spectrum may be

used (Section 2.5). The traditional approach has been to use a one-minute average gust applied as a

static load. Occasionally the mean plus turbulence spectral analysis method is used to obtain a more

accurate assessment of response both for extreme and fatigue loading. The turbulence may be

described at a single point in one or all three directions. More accurate analysis is possible with cross-

spectral models defining the coherence between the wind turbulence at different points.

Current Currents may have many components as described in Section 2.6. In some enclosed areas, such as the

North Sea, the tidal and wind driven currents are dominant. However in other areas, such as West of

Shetland, many other currents become important. Currents are usually considered to have long

periods in comp arison with any natural frequencies of the platforms, so they can be considered as

steady during the one-hour periods. Their effect on fatigue is usually to determine the mean position

about which the structure oscillates under the effect of waves and wind. Current will also affect

damping: increased current will lead to higher levels of form drag on hull and moorings and therefore

higher damping of slow drift motion.



37

Currents will generate vortices as they interact with the platform and these might result in vortex

induced vibration. This is considered for steel risers and Spar platforms. Semi's and

TLP’s whilst theoretically susceptible to vortex induced vibration do not seem to have been so in

practice, perhaps owing to the multiple relatively short columns and flow interference from pontoons.

Water level Changes of water level {Section 2.6) in deep water are usually quite small. Even a 1 to 2 in change in

water level has a relatively small effect on a conventionally moored platform but this change would be significant for a TLP.

Wave Waves (Section 2.7) result in a steady drift force, a slowly varying drift force (and response at the

natural frequency of the platform on its mooring) and a wave frequency force. Wave period is as

important as wave height in determining the wave force.



38

1 .7.2 Hydrostatics

Stabil it y assessment

Clearly an assessment of intact and damaged hydrostatic stability is a critical part of the design and analysis of

any floating structure. Small angle stability / metacentric height. Large angle stabilitycalculations require computer simulation. Often it is necessary to solve for displacement, heel and trim at the same

time. Practical methodology is given in Sections 4.7 and 4.9.

In general the following can cause difficulties and need special care:

• Longitudinal compartmentalisation of double skinned ships: It is cheapest to avoid longitudinal subdivision of the

large central oil tanks. To reduce longitudinal bending moments it can be advantageous to have s everal slack tanks.

However this can result in unsatisfactory transverse stability as well as increasing structural bending moments.

• Semi-submersibles, owing to their small water plane area and inertia are sensitive both to total weight and its

position. If a large weight is placed away from the centre of gravity then another large weight of ballast will need

to be applied to avoid heeling the vessel. Both the weight and the ballast will increase the draught. Weight applied

above the metacentre will reduce the stability.

• TLP’s are primarily sensitive to weight because, once all ballast has been discharged, any increase in weightimmediately leads to a drop in tether tension and this will make slack tether conditions in large waves more likely

to occur.

As well as traditional naval architecture stability analysis it is important to apply hazard analysis and risk

assessment principles to the design and operation of the ballast system. This is described in Sections 4.16 and

4.17.

Hydrostatic properti es for hydrodynamic and structur al anal ysis

Typically the hydrodynamic model for platform motion calculation is a rigid body model. For linear calculations all

that is required is a stiffness matrix to represent the hydrostatics. For the calculation of the behaviour in large waves a

program which estimates static plus dynamic pressures over the instantaneously wetted surface is preferable.

For structural analysis, a quasi-static model (Section 1.7 above) with directly applied gravity, acceleration and

pressure loads will usually be satisfactory.

In some circumstances, when a non-linear dynamic analysis of a ship hull is undertaken, a dynamic hull model is used

with hydrostatic stiffness distributed over the hull. Care has to be taken to distinguish between, but to allow for, both

the true hydrostatic stiffness and the reduced roll and pitch stiffness that results from the centre of gravity being higher

than the centre of buoyancy and resulting in an additional roll moment. For the quasi-static hull strength and fatigue

analyses an equivalent spring system or a calculated pressure distribution (as described in Sections 3.6.5,4.13 and 6.2)

may be applied. Care needs to be taken to properly include the effect of roll angle on the gravity force, either through

GM or as a directly applied force.

1.7.3 Hydrodynamic loading and response models

The appropriate model depends on the type of structure and the type of analysis being performed.

For a semi-submersible a Morison model (Section 3.6.4) is likely to be good in extre me waves because diffraction

effects are small and the wave loading is dominated by drag and inertia forces. A time domain calculation in

irregular waves will give the best response estimates although a frequency domain calculation with linearised drag

should give reasonable estimates of response away from the heave and pitch natural frequencies. In smaller waves,

appropriate to fatigue analysis, diffraction (modification to the waves caused by the structure) becomes important



39

and so a linear diffraction analysis will commonly replace the Morison inertia loading. The drag is linearised and has a

loading component but it also makes an important contribution to damping resonant responses. Frequency domain

spectral techniques are generally applicable for fatigue calculations, however the size of the predicted resonant

responses needs to be checked to make sure that the drag force and drag damping linearisation are consistent with the

predicted response. A Morison inertia force based semi-submersible respons e calculation is undertaken in Section 5C.Steady and slowly varying drift forces are not usually very important for a semi-submersible but they may be calculated

using results from a linear diffraction model. Current and wind loading are calculated using a drag coefficient

approach.

For a TLP the wave frequency loads may be handled as for a semi-submersible. However the high frequency springing

forces (Section 3.8) are also important as these can cause resonant heave and pitch motion at natural frequencies that

are higher than the wave frequencies. These require a non-linear diffraction analysis. Even a second order analysis is

time consuming and difficult to perform and at present it is not clear whether a second order analysis is sufficient or

whether even higher orders are required. It is therefore usual to supplement any high order diffraction calculations with

model tests. Ringing (Section 3.9.7) is another high order hydrodynamic loading effect that can generate episodic

transient pitch responses. Its importance can be estimated by calculation but again model tests are usually used to gain

confidence in the likely level of response.

The analysis required for a Spar is similar to that required for a semi-submersible. However it will typically have

a larger diameter so diffraction effects are likely to be more important and the long single tubular column type

may be prone to vortex induced vibration in currents, so a vortex shedding response analysis (Section 3.10) is required.

The response of a ship to wave loading is usually analysed using either a linear 3-0 diffraction analysis (Section 3.6.5)

or a linear 2-0 strip method analysis (Section 3.6.6). The 2-0 method applies, to any cross section of the ship, the results

of a diffraction analysis of a long prismatic shape of approximately the same cross section. 2-D analysis should

preferably be used in conjunction with a correction for axial pressures. 8oth analyses require the empirical assessment

of roll damping but then provide good estimates of the response of a ship in small waves and are directly useful for

fatigue analysis. A simplified strip theory analysis of a ship, which demonstrates some of the basic principles whilst

using approximate hydrodynamic coefficients, is given in Annex 58.

In large waves linear diffraction results are only a first approximation to the response particularly because they do notallow for the effects of intermittent wetting of the hull surface. There are several effects some of which reduce the hull

girder loading (Section 3.6) but some of which (particularly bottom and flare slamming) make the loading worse

(Section 3.9). The effect of non-linearity on the response is usually quite small although it can affect the calculated

intensity of slamming. Slamming itself is accounted for either by a slamming pressure integration or by a rate of change

of momentum calculation. The latter may conveniently be linked with the rate of change of added mass as calculated

from (usually 2-D) diffraction theory analyses at different draughts .

In addition to the wave frequency and impulsive loading a ship is also subject to steady (Section 3.2) and (in a sea)

slowly varying drift forces (Section 3.7). These drift forces, although non-linear, may be calculated by post processing

the results of linear diffraction analysis.

Wind forces acting on a ship superstructure and transverse current forces are calculated using drag force equations.

Longitudinal current forces are calculated using equations developed for ship resistance estimation (Sect ion 3.2).

1.7.4 Mooring / DP models

Moorings and tethers

The moorings may be accounted for in the analysis by either:

• coupling a detailed mooring model to the hydrodynamic loading and response model, or



40

• simplifying the moorings to either a linear stiffness matrix or a quasi-static catenary model, coupling this to the

overall hydrodynamic analysis and solving for the platform response. The detailed behaviour of the mooring lines

may then be obtained by applying the calculated top of mooring deflections to the detailed dynamic mooring

model so obtaining the forces in individual lines/tethers etc.

For fatigue analysis of all types of floating structure the linear stiffness matrix method of representing moorings or

tethers, is usually the most convenient because it is consistent with frequency domain analysis of rigid body response,

stress transfer functions and spectral fatigue calculation of the response to wave frequency, drift frequency and wind

gust motions.

Vortex induced vibration is also conveniently analysed in the frequency domain.

For extreme response calculation of catenary moored platforms the usual method is to use quasi-static catenary

models for the global analysis with dynamic analysis of individual lines. This avoids highly

complex full time dynamic global analyses on the assumption that line dynamics may be important for individual lines

but it should not significantly affect the overall response.

For extreme response of a TLP a fully coupled analysis is preferable owing to the inherent coupling of hull and tether

dynamics (Section 11.4).

DPFor structural design purposes it is usual to discuss the DP system characteristics with the DP designer and to

allow for its characteristics approximately, for example by a representative mass-spring damping system.

1.7.5 Riser models

For global platform analysis 'rigid' and flexible risers are usually modelled as a simple system with mass, damping,

stiffness and loading effects on the hull (see Sections 12.3 and 13.8 to 13.9).

As in dynamic mo oring line analysis the individual riser would be checked with a detailed model subject to distributed

hydrodynamic loading and top deflections obtained from the global platform analysis.

1.7.6 Global structural models

The global structural model may be a stick model, a shell element or a brick element model (See Section 6.5).

Opinions differ as to which are the most appropriate. The Editor prefers stick models at the early stages of design,

because these models are relatively quick to run and engender an understanding of the structural response and overall

forces to be taken: a ship or Spar model would essentially be a line of elements; a semi or TLP model would be line

beams for the pontoons, columns and bull braces with a deck probably modelled as a gri llage filled in with plate

elements to obtain the correct in plane shear properties.

The disadvantage of a line beam model is that it does not give information on the distribution of forces inside the

section. For instance the 'shear lag' effect which makes a wide flanged cross section less efficient when subject to a

changing bending moment along its length or the distribution of stresses in a double hull tanker have to be estimated

separately.

A coarse mesh finite element model of a complete platform can be set up to provide this information. It is likely to be

made from a large number of substructures or super elements (groups of elements representing e.g. a length of

pontoon). However the large amount of data generated tends to obscure the basic overall force and moment pattern in

the structure, so it should be run in addition to the stick model, not in place of it. The results of the two analyses should

be cross-checked.



The global, structural analysis model will be subject to static (weight, buoyancy, ballast and mean mooring forces),

modification to static loads caused by roll and pitch angles and heave displacement, acceleration forces on the structure

and ballast, and the hydrodynamic pressures on the hull. The dynamic loading may be represented as a set of quasi-

static load cases in dynamic equilibrium. Alternatively the dynamic effects of hydrodynamic loading, mooring forces,

accelerations, roll etc may be represented by a pairs of load cases each regarded as a complex pair. For extreme loadingcalculations and structural checks it is necessary to obtain specific, quasi-static, loading combinations. The analyst may

set these up manually, however it is often not straightforward to select the worst cases. Alternatively therefore the

analyst may define the loading rules to an enveloping program which will select worst loading cases and possibly wave

phase angles for each component being checked.

For fatigue analysis the dynamic pressures on the hull, mooring, acceleration, roll and pitch forces etc. will be obtained

from the global platform analysis. Complex pairs of load cases will represent the amplitude and phase of each loading

component and the output win represent the real and imaginary parts of the response to each wave frequency. Spectral

analysis techniques may then be used for the fatigue calculations (Section 7.5). A similar approach may be used to

represent the gust and possibly the drift frequency response. The latter are mainly of interest in the immediate area of

the mooring connections.

References

Ahilan, R.V., Baker, M.J. and Snell, R.O., 1993, Development of Jack -up Assessment Criteria using Probabilistic

Methods, OTC 7305, Houston.

API: see Annex lB.

Barltrop N.D.P. and Rainey RC.T., 1985, Floating and compliant platforms: response to environmental loads.

E&P Forum, Workshop on uncertainties in the design process, U.K.

Brown and Root, 1994, AFP concept option study, private communication , with permission of Shell and BP.

Hamilton, J. and Perrett, G.R., 1986, Deep water tension leg platform designs, Proc. RINA Int. Symp.Deve1opments in Deeper Waters, 6-7 October.

HeneryD. andInglis RB, 1995, Prospects and Challenges for the FPSO, OTC 7695, 27th Offshore Techno1ogy

Conference, Houston.

Holmes J. and Verghese J., 1995, Sub-sea Developments in Very Deep Water , 8th Deep Offshore Technology

Conference, Rio De Janeiro, November.

HSE: see Annex 1 C.

Inglis R.B., 1993, The Role of the Production Ship In Deep Water Field Development , 7th Deep Offshore

Technology Conference, Monaco, November.

Inglis RB, 1996, Production facilities selection for deep water oil and gas field development , IESIS, (Instn.

Engnrs. and Shipbuilders in Scotland), vol; 139.

Madsen, A. and Gallimore, D., 1993, Offshore Production Concepts, Oilfield Publications, U.K.

Moses, F., 1989, Tutorial on LRFD lor FixedOffshore Platforms,. API PRAC 88-22 Report.

Ocean Industry, 1992,1992 Guide to Marine Drilling Rigs, Gulf Publishing, Houston. ,

OPL, 1997, Single point moorings, wall chart, Oilfield Publications Ltd., Ledbwy, U.K.

Steeves M 1989 The Halyard Guide to Single Point Moorings of the World Oilfield Publications Ltd UK

Documents

Design Priciples Concept Selection Barltrop