Offshore Structures: General Introduction
OBJECTIVE/SCOPETo identify the basic vocabulary, to introduce the major concepts for offshore platform structures, and to explain where the basic structural requirements for design are generated. PREREQUISITES
None. SUMMARY
The lecture starts with a presentation of the importance of offshore hydro-carbon exploitation, the basic steps in the development process (from seismic exploration to platform removal) and the introduction of the major structural concepts (jacket-based, GBS-based, TLP, floating). The major codes are identified.
For the fixed platform concepts (jacket and GBS), the different execution phases are briefly explained: design, fabrication and installation. Special attention is given to some principles of topside design.
A basic introduction to cost aspects is presented. Finally terms are introduced through a glossary.
1. INTRODUCTION
Offshore platforms are constructed to produce the hydrocarbons oil and gas. The contribution of offshore oil production in the year 1988 to the world energy consumption was 9% and is estimated to be 24% in 2000.
The investment (CAPEX) required at present to produce one barrel of oil per day ($/B/D) and the production costs (OPEX) per barrel are depicted in the table below.
Condition CAPEX $/B/D OPEX $/B
Conventional Average 4000 - 8000 5 Middle East 500 - 3000 1 Non-Opec 3000 - 12000 8 Offshore North Sea 10000 - 25000 5 - 10 Deepwater 15000 - 35000 10 - 15
World oil production in 1988 was 63 million barrel/day. These figures clearly indicate the challenge for the offshore designer: a growing contribution is required from offshore exploitation, a very capital intensive activity.
Figure 1 shows the distribution of the oil and gas fields in the North Sea, a major contribution to the world offshore hydrocarbons. It also indicates the onshore fields in England, the Netherlands and Germany.
2. OFFSHORE PLATFORMS 2.1 Introduction of Basic Types
The overwhelming majority of platforms are piled-jacket with deck structures, all built in steel (see Slides 1 and 2).
Slide 1: Jacket based platform - Southern sector North Sea
A second major type is the gravity concrete structure (see Figure 2), which is employed in the North Sea in the Norwegian and British sectors.
A third type is the floating production unit. 2.2 Environment
The offshore environment can be characterized by: • water depth at location
• soil, at seabottom and in-depth • wind speed, air temperature • waves, tide and storm surge, current • ice (fixed, floes, icebergs)
• earthquakes (if necessary)
The topside structure also must be kept clear of the wave crest. The clearance (airgap) usually is taken at approximately 1,50 m, but should be increased if reservoir depletion will create significant subsidence.
2.3 Construction
The environment as well as financial aspects require that a high degree of prefabrication must be performed onshore. It is necessary to design to limit offshore work to a minimum. The overall cost of a man-hour offshore is approximately five times that of an onshore man-hour. The cost of construction equipment required to handle loads, and the cost for logistics are also a magnitude higher offshore.
These factors combined with the size and weight of the items, require that a designer must carefully consider all construction activities between shop fabrication and offshore installation. 2.4 Codes
Structural design has to comply with specific offshore structural codes. The worldwide leading structural code is the API-RP2A [1]. The recently issued Lloyds rules [2] and the DnV rules [3] are also important.
Specific government requirements have to be complied with, e.g. in the rules of Department of Energy (DoE), Norwegian Petroleum Direktorate (NPD). For the detail design of the topside structure the AISC-code [4] is frequently used, and the AWS-code [5] is used for welding. In the UK the Piper alpha diaster has led to a completely new approach to regulation offshore. The responsibility for regulatory control has been moved to the Health and Safety Executive (HSE) and the operator has to produce a formal safety assessment (TSA) himself instead of complying with detailed regulations.
2.5 Certification and Warranty Survey
Government authorities require that recognized bodies appraise the aspects of structural integrity and issue a certificate to that purpose.
The major certification bodies are: • Det norske Veritas (DnV) • Lloyds Register of Shipping (LRS) • American Bureau of Shipping (ABS) • Bureau Veritas (BV)
• Germanischer Lloyd (GL)
Insurance companies covering transport and installation require the structures to be reviewed by warranty surveyors before acceptance. The warranty surveyors apply standards, if available, on a confidential basis.
3. OFFSHORE DEVELOPMENT OF AN OIL/GAS FIELD 3.1 Introduction
The different requirements of an offshore platform and the typical phases of an offshore development are summarized in [9]. After several initial phases which include seismic field surveying, one or more exploration wells are drilled. Jack-up drilling rigs are used for this purpose for water depths up to 100 - 120 m; for deeper water floating rigs are used. The results are studied and the economics and risks of different development plans are evaluated. Factors involved in the evaluation may include number of wells required, fixed or floated production facilities, number of such facilities, and pipeline or tanker off-loading.
As soon as exploitation is decided and approved, there are four main technical activities, prior to production:
• engineering and design
• fabrication and installation of the production facility • drilling of production wells, taking 2 - 3 months/well • providing the off loading system (pipelines, tankers, etc.).
The drilling and construction interaction is described below for two typical fixed platform concepts.
3.2 Jacket Based Platform for Shallow Water
First the jacket is installed. The wells are then drilled by a jack-up drilling unit standing close by with a cantilever rig extending over the jacket. Slide 3 shows a jack-up drilling unit with a cantilever rig. (In this instance it is engaged in exploratory drilling and is therefore working in isolation.)
Slide 3 : Cantilevered drilling rig: Self-elevating (jack-up) exploration drilling platform. Design and construction of the topside are progressed parallel to the drilling, allowing production to start soon after deck installation. For further wells, the jack-up drilling unit will be called once again and will reach over the well area of the production deck.
As an alternative to this concept the wells are often accommodated in a separate wellhead platform, linked by a bridge to the production platform (see Slide 1).
3.3 Jacket and Gravity Based Platform for Deep Water
The wells are drilled from a drilling rig on the permanent platform (see Slide 2). Drilling starts after the platform is built and completely installed. Consequently production starts between one and two years after platform installation.
In recent years pre-drilled wells have been used to allow an earlier start of the production. In this case the platform has to be installed exactly above the pre-drilled wells.
4. JACKETS AND PILE FOUNDATION 4.1 Introduction
Jackets, the tower-like braced tubular structures, generally perform two functions:
• They provide the substructure for the production facility (topside), keeping it stable above the waves.
• They support laterally and protect the 26-30 inch well conductors and the pipeline riser.
4.2 Pile Foundation
The jacket foundation is provided by open-ended tubular steel piles, with diameters up to 2m. The piles are driven approximately 40 - 80 m, and in some cases 120 m deep into the seabed.
There are basically three types of pile/jacket arrangement (see Figure 3):
Pile-through-leg concept, where the pile is installed in the corner legs of the jacket.
Skirt piles through pile sleeves at the jacket-base, where the pile is installed in guides attached to the jacket leg. Skirt piles can be grouped in clusters around each of the jacket legs.
Vertical skirt piles are directly installed in the pile sleeve at the jacket base; all other guides are deleted. This arrangement results in reduced structural weight and easier pile driving. In contrast inclined piles enlarge the foundation at the bottom, thus providing a stiffer structure. 4.3 Pile Bearing Resistance
Axial load resistance is required for bearing as well as for tension. The pile accumulates both skin friction as well as end bearing resistance.
Lateral load resistance of the pile is required for restraint of the horizontal forces. These forces lead to significant bending of the pile near to the seabed.
Number, arrangement, diameter and penetration of the piles depend on the environmental loads and the soil conditions at the location.
4.4 Corrosion Protection
The most usual form of corrosion protection of the bare underwater part of the jacket as well as the upper part of the piles in soil is by cathodic protection using sacrificial anodes. A sacrificial anode (approximate 3 kN each) consists of a zinc/aluminium bar cast about a steel tube and welded on to the structures. Typically approximately 5% of the jacket weight is applied as anodes.
The steelwork in the splash zone is usually protected by a sacrificial wall thickness of 12 mm to the members.
5. TOPSIDES 5.1 Introduction
The major functions on the deck of an offshore platform are: • well control
• support for well work-over equipment
• separation of gas, oil and non-transportable components in the raw product, e.g. water, parafines/waxes and sand
• support for pumps/compressors required to transport the product ashore • power generation
• accommodation for operating and maintenance staff.
There are basically two structural types of topside, the integrated and modularized topside which are positioned either on a jacket or on a concrete gravity substructure.
5.2 Jacket-based Topsides 5.2.1 Concepts
There are four structural concepts in practice. They result from the lifting capacity of crane vessels and the load-out capacity at the yards:
• the single integrated deck (up to approx 100 MN) • the split deck in two four-leg units
• the integrated deck with living quarter module
• the modularized topside consisting of module support frame (MSF) carrying a series of modules.
Slide 4 shows an integrated deck (though excluding the living quarters and helideck) being moved from its assembly building.
Slide 4 : Integrated topside during load out 5.2.2 Structural Design for Integrated Topsides
For the smaller decks, up to approximately 100 MN weight, the support structure consists of trusses or portal frames with deletion of diagonals.
The moderate vertical load and shear per column allows the topside to be supported by vertical columns (deck legs) only, down to the top of the piles (situated at approximately +4 m to +6 m L.A.T. (Low Astronomic Tide).
5.2.3 Structural Design for Modularized Jacket-based Topsides
A major modularized topside weighs 200 to 400 MN. In this case the MSF is a heavy tubular structure (Figure 4), with lateral bracing down to the top of jacket.
5.3 Structural Design for Modularized Gravity-based Topsides
The topsides to be supported by a gravity-based substructure (see Figure 2) are in a weight range of 200 MN up to 500 MN.
The backbone of the structure is a system of heavy box-girders with a height of approximately 10 m and a width of approximately 12 - 15 m (see Figure 5).
The substructure of the deck is rigidly connected to the concrete column and acts as a beam supporting the deck modules. This connection introduces wave-induced fatigue in the deck structure. A recent development, foreseen for the Norwegian Troll platform, is to provide a flexible connection between the deck and concrete column, thus eliminating fatigue in the deck [10].
6. EQUIPMENT AND LIVING QUARTER MODULES
Equipment modules (20-75 MN) have the form of rectangular boxes with one or two intermediate floors.
The floors are steel plate (6, 8 or 10 mm thick) for roof and lower floor, and grating for intermediate floors.
In living quarter modules (5-25 MN) all sleeping rooms require windows and several doors must be provided in the outer walls. This requirement can interfere seriously with truss arrangements. Floors are flat or stiffened plate.
Three types of structural concepts, all avoiding interior columns, can be distinguished: • conventional trusses in the walls.
• stiffened plate walls (so called stressed skin or deck house type). • heavy base frame (with wind bracings in the walls).
7. CONSTRUCTION 7.1 Introduction
The design of offshore structures has to consider various requirements of construction relating to: 1. fabrication. 2. weight. 3. load-out. 4. sea transport. 5. offshore installation. 6. module installation. 7. hook-up. 8. commissioning.
A documented construction strategy should be available during all phases of the design and the actual design development should be monitored against the construction strategy. Construction is illustrated below by four examples.
7.2 Construction of Jackets and Topsides 7.2.1 Lift Installed Jackets
The jacket is built in the vertical (smaller jackets) or horizontal position (bigger jackets) on a quay of a fabrication site.
The jacket is loaded-out and seafastened aboard a barge. At the offshore location the barge is moored alongside an offshore crane vessel.
The jacket is lifted off the barge, upended from the horizontal, and carefully set down onto the seabed.
After setting down the jacket, the piles are installed into the sleeves and, driven into the seabed. Fixing the piles to the jacket completes the installation.
7.2.2 Launch Installed Jackets The jacket is built in horizontal position.
For load-out to the transport barge, the jacket is put on skids sliding on a straight track of steel beams, and pulled onto the barge (Slide 5).
Slide 5 : Jacket being loaded onto barge by skidding
At the offshore location the jacket is slid off the barge. It immerses deeply into the water and assumes a floating position afterwards (see Figure 6).
Two parallel heavy vertical trusses in the jacket structure are required, capable of taking the support reactions during launching. To reduce forces and moments in the jacket, rocker arms are attached to the stern of the barge.
The next phase is to upright the jacket by means of controlled flooding of the buoyancy tanks and then set down onto the seabed. Self-upending jackets obtain a vertical position after the launch on their own. Piling and pile/jacket fixing completes the installation.
7.2.3 Topsides for a Gravity-Based Structure (GBS)
The topside is assembled above the sea on a temporary support near a yard. It is then taken by a barge of such dimensions as to fit between the columns of the temporary support and between the columns of the GBS. The GBS is brought in a deep floating condition in a sheltered site, e.g. a Norwegian fjord. The barge is positioned between the columns and the GBS is then deballasted to mate with and to take over the deck from the barge. The floating GBS with deck is then towed to the offshore site and set down onto the seabed.
7.2.4 Jacket Topsides
For topsides up to approximately 120 MN, the topside may be installed in one lift. Slide 6 shows a 60 MN topside being installed by floating cranes.
Slide 6 : Installation of 60MN K12-BP topside by floating crane
For the modularized topside, first the MSF will be installed, immediately followed by the modules.
7.3 Offshore Lifting
Lifting of heavy loads from barges (Slide 6) is one of the very important and spectacular construction activities requiring a focus on the problem when concepts are developed. Weather windows, i.e. periods of suitable weather conditions, are required for these operations.
7.3.1 Crane Vessel
Lifting of heavy loads offshore requires use of specialized crane vessels. Figure 7 provides information on a typical big, dual crane vessel. Table 1 (page 16) lists some of the major offshore crane vessels.
7.3.2 Sling-arrangement, Slings and Shackles
For lifting, steel wire ropes in a sling arrangement are used which directly rest in the four-point hook of the crane vessel, (see Figure 8). The heaviest sling available now has a diameter of approximately 350 mm, a breaking load of approximately 48 MN, and a safe working load (SWL) of 16 MN. Shackles are available up to 10 MN SWL to connect the padeyes installed at the module's columns. Due to the space required, connecting more than one shackle to the same column is not very attractive. So when the sling load exceeds 10 MN, padears become an option.
Table 1 Major Offshore Crane Vessels
Operator Name Mode Type Lifting capacity (Tonnes)
Fix 2720 Thor Monohull Rev 1820 Fix 2720 Odin Monohull Rev 2450 Fix 4536 + 3628 = 8164 Hermod Semisub Rev 3630 + 2720 = 6350 Fix 3630 + 2720 = 6350 Heerema Balder Semisub Rev 3000 + 2000 = 5000 Fix 4000 DB50 Monohull Rev 3800 Fix 1820 DB100 Semisub Rev 1450 Fix 3360 DB101 Semisub Rev 2450 McDermott DB102 Semisub Rev 6000 + 6000 = 12000
Micoperi M7000 Semisub Rev 7000 + 7000 = 14000
ETPM DLB1601 Monohull Rev. 1600
Notes:
1. Rated lifting capacity in metric tonnes.
2. When the crane vessels are provided with two cranes, these cranes are situated at the vessels stern or bow at approximately 60 m distance c.t.c.
1. 3. Rev = Load capability with fully revolving crane. Fix = Load capability with crane fixed.
7.4 Sea Transport and Sea Fastening
Transportation is performed aboard a flat-top barge or, if possible, on the deck of the crane vessel.
The module requires fixing to the barge (see Figure 9) to withstand barge motions in rough seas. The sea fastening concept is determined by the positions of the framing in the module as well as of the "hard points" in the barge.
7.5 Load-out 7.5.1 Introduction
For load-out three basic methods are applied: • skidding
• platform trailers • shearlegs. 7.5.2 Skidding
Skidding is a method feasible for items of any weight. The system consists of a series of steel beams, acting as track, on which a group of skids with each approximately 6 MN load capacity is arranged. Each skid is provided with a hydraulic jack to control the reaction. 7.5.3 Platform Trailers
Specialized trailer units (see Figure 10) can be combined to act as one unit for loads up to 60 - 75 MN. The wheels are individually suspended and integrated jacks allow adjustment up to 300 mm.
The load capacity over the projected ground area varies from approximately 55 to 85 kN/sq.m.
The units can drive in all directions and negotiate curves.
7.5.4 Shearlegs
Load-out by shearlegs is attractive for small jackets built on the quay. Smaller decks (up to 10 - 12 MN) can be loaded out on the decklegs pre-positioned on the barge, thus allowing deck and deckleg to be installed in one lift offshore.
7.6 Platform Removal
In recent years platform removal has become common. The mode of removal depends strongly on the regulations of the local authorities. Provision for removal should be considered in the design phase.
8. STRUCTURAL ANALYSIS 8.1 Introduction
The majority of structural analyses are based on the linear theory of elasticity for total system behaviour. Dynamic analysis is performed for the system behaviour under wave-attack if the natural period exceeds 3 seconds. Many elements can exhibit local dynamic behaviour, e.g. compressor foundations, flare-stacks, crane-pedestals, slender jacket members, conductors. 8.2 In-place Phase
Three types of analysis are performed:
• Survival state, under wave/current/wind attack with 50 or 100 years recurrence period.
• Operational state, under wave/current/wind attack with 1 or 5 years recurrence period, under full operation.
• Fatigue assessment. • Accidental.
All these analyses are performed on the complete and intact structure. Assessments at damaged structures, e.g. with one member deleted, and assessments of collision situations are occasionally performed.
8.3 Construction Phase
The major phases of construction when structural integrity may be endangered are: • Load-out
• Upending of jackets • Lifting.
9. COST ASPECTS 9.1 Introduction
The economic feasibility of an offshore project depends on many aspects: capital expenditure (CAPEX), tax, royalties, operational expenditure (OPEX).
In a typical offshore field development, one third of the CAPEX is spent on the platform, one third on the drilling of wells and one third on the pipelines.
Cost estimates are usually prepared in a deterministic approach. Recently cost-estimating using a probabilistic approach has been developed and adopted in major offshore projects. The CAPEX of an installed offshore platform topside amounts to approximately 20 ECU/kg. 9.2 Capital Expenditure (CAPEX)
The major elements in the CAPEX for an offshore platform are: • project management and design
• material and equipment procurement • fabrication
• transport and installation • hook-up and commissioning. 9.3 Operational Expenditure (OPEX)
In the North Sea approximately 20 percent of OPEX are required for offshore inspection, maintenance and repair (IMR).
The amount to be spent on IMR over the project life can add up to approximately half the original investment.
IMR is the area in which the structural engineer makes a contribution by effort in design, selection of material, improved corrosion protection, accessibility, basic provisions for scaffolding, avoiding jacket attachments dangerous to divers, etc.
10. DEEP WATER DEVELOPMENTS
Deep water introduces a wide range of extra difficulties for the operator, the designer and constructor of offshore platforms.
Fixed platforms have recently been installed in water of 410 m. depth, i.e. "Bullwinkle" developed by Shell Oil for a Gulf of Mexico location. The jacket weighed nearly 500 MN. The maximum depth of water at platform sites in the North Sea is approximately 220 m at present. The development of the Troll field situated in approximately 305 m deep water is planned for 1993.
In the Gulf of Mexico and offshore California several fixed platforms in water depths of 250 - 350 m are in operation (Cerveza, Cognac). Exxon has a guyed tower platform (Lena) in operation in 300 m deep water.
An option for deeper locations is to use subsea wells with flowlines to a nearby (approximately maximum 10 km) fixed platform at a smaller water depth. Alternatively subsea wells may be used with flexible risers to a floating production unit. Subsea wells are now feasible for 300 - 900 m deep water. The deepest wells have been developed off Brasil in moderate weather conditions.
The tension leg platform (TLP) seems to be the most promising deepwater production unit (Figure 11). It consists of a semi-submersible pontoon, tied to the seabed by vertical prestressed tethers. The first TLP was Hutton in the North Sea and recently TLP-Jolliet was installed at a 530 m deep location in the Gulf of Mexico. Norwegian Snorre and Heidrun fields have been developed with TLPs as well.
11. CONCLUDING SUMMARY
• The lecture starts with the presentation of the importance of offshore hydro-carbon exploitation, the basic steps in the development process (from seismic exploration to platform removal) and the introduction of the major structural concepts (jacket-based, GBS-based, TLP, floating).
• The major codes are identified.
• For the fixed platform concepts (jacket and GBS), the different execution phases are briefly explained: design, fabrication and installation. Special attention is given to the principles of topside design.
• A basic introduction to cost aspects is presented. • Finally terms are introduced within a glossary.
12. GLOSSARY OF TERMS
AIR GAP Clearance between the top of maximum wave and underside of the topside. CAISSONS See SUMPS
CONDUCTORS The tubular protecting and guiding the drill string from the topside down to 40 to 100m under the sea bottom. After drilling it protects the well casing.
G.B.S. Gravity based structure, sitting flatly on the sea bottom, stable through its weight. HOOK-UP Connecting components or systems, after installation offshore.
JACKET Tubular sub-structure under a topside, standing in the water and pile founded. LOAD-OUT The operation of bringing the object (module, jacket, deck) from the quay onto the transportation barge.
PADEARS (TRUNNIONS) Thick-walled tubular stubs, directly receiving slings and transversely welded to the main structure.
PADEYES Thick-walled plate with hole, receiving the pin of the shackle, welded to the main structure.
PIPELINE RISER The piping section which rises from the sea bed to topside level.
SEA-FASTENING The structure to keep the object rigidly connected to the barge during transport.
SHACKLES Connecting element (bow + pin) between slings and padeyes.
SLINGS Cables with spliced eyed at both ends, for offshore lifting, the upper end resting in the crane hook.
SPREADER Tubular frame, used in lifting operation.
SUBSEA TEMPLATE Structure at seabottom, to guide conductors prior to jacket installation. SUMPS Vertical pipes from topside down to 5-10 m below water level for intake or discharge.
TOPSIDE Topside, the compact offshore process plant, with all auxiliaries, positioned above the waves.
UP ENDING Bringing the jacket in vertical position, prior to set down on the sea bottom. WEATHER WINDOW
A period of calm weather, defined on basis of operational limits for the offshore marine operation.
WELLHEAD AREA Area in topside where the wellheads are positioned including the valves mounted on its top.
13. REFERENCES
[1] API-RP2A: Recommended practice for planning, designing and constructing fixed offshore platforms.
American Petroleum Institute 18th ed. 1989.
The structural offshore code, governs the majority of platforms. [2] LRS Code for offshore platforms.
Lloyds Register of Shipping. London (UK) 1988.
Regulations of a major certifying authority.
[3] DnV: Rules for the classification of fixed offshore installations. Det Norske Veritas 1989.
Important set of rules.
[4] AISC: Specification for the design, fabrication and erection of structural steel for buildings. American Institute of Steel Construction 1989.
Widely used structural code for topsides. [5] AWS D1.1-90: Structural Welding Code - Steel.
American Welding Society 1990. The structural offshore welding code.
[6] DnV/Marine Operations: Standard for insurance warranty surveys in marine operations. Det norske Veritas June 1985.
Regulations of a major certifying authority.
[7] ABS: Rules for building and classing offshore installations, Part 1 Structures. American Bureau of Shipping 1983.
Regulations of a major certifying authority.
[8] BV: Rules and regulations for the construction and classification of offshore platforms. Bureau Veritas, Paris 1975.
Regulations of a major certifying authority. [9] ANON: A primer of offshore operations. Petex Publ. Austin U.S.A 2nd ed. 1985.
Fundamental information about offshore oil and gas operations. [10] AGJ Berkelder et al: Flexible deck joints.
ASME/OMAE-conference The Hague 1989 Vol.II pp. 753-760. Presents interesting new concept in GBS design.
14. ADDITIONAL READING
1. BS 6235: Code of practice for fixed offshore structures. British Standards Institution 1982.
Important code, mainly for the British offshore sector.
2. DoE Offshore installations: Guidance on design and construction, U.K. Department of Energy 1990.
Governmental regulations for British offshore sector only. 3. UEG: Design of tubular joints (3 volumes).
UEG Offshore Research Publ. U.R.33 1985. Important theoretical and practical book. 4. J. Wardenier: Hollow section joints.
Delft University Press 1981.
Theoretical publication on tubular design including practical design formulae. 5. ARSEM: Design guides for offshore structures welded tubular joints.
Edition Technip, Paris (France), 1987. Important theoretical and practical book. 6. D. Johnston: Field development options.
Oil & Gas Journal, May 5 1986, pp 132 - 142. Good presentation on development options.
7. G. I. Claum et al: Offshore Structures: Vol 1: Conceptual Design and Hydri-mechanics; Vol 2 - Strength and Safety for Structural design.
Springer Verlag, London 1992.
Fundamental publication on structural behaviour. 8. W.J. Graff: Introduction to offshore structures.
Gulf Publishing Company, Houston 1981. Good general introduction to offshore structures. 9. B.C. Gerwick: Construction of offshore structures.
John Wiley & Sons, New York 1986.
Up to date presentation of offshore design and construction.
10. T.A. Doody et al: Important considerations for successful fabrication of offshore structures.
OTC paper 5348, Houston 1986, pp 531-539. Valuable paper on fabrication aspects.
11. D.I. Karsan et al: An economic study on parameters influencing the cost of fixed platforms.
OTC paper 5301, Houston 1986, pp 79-93. Good presentation on offshore CAPEX assessment.
Loads (I): Introduction and Environmental Loads
OBJECTIVE/SCOPETo introduce the types of loads for which a fixed steel offshore structure must be designed. To present briefly the loads generated by environmental factors.
PREREQUISITES
A basic knowledge of structural analysis for static and dynamic loadings. SUMMARY
The categories of load for which a pile supported steel offshore platform must be designed are introduced and then the different types of environmental loads are presented. The loads include: wind, wave, current, earthquake, ice and snow, temperature, sea bed movement, marine growth and tide generated loads. Loads due to wind, waves and earthquake are discussed in more detail together with their idealizations for the various types of analyses. Frequent references are made to the codes of practice recommended by the American Petroleum Institute, Det Norske Veritas, the British Standards Institution and the British Department of Energy, as well as to the relevant regulations of the Norwegian Petroleum Directorate.
1. INTRODUCTION
The loads for which an offshore structure must be designed can be classified into the following categories:
1. Permanent (dead) loads. 2. Operating (live) loads.
3. Environmental loads including earthquakes. 4. Construction - installation loads.
5. Accidental loads.
Whilst the design of buildings onshore is usually influenced mainly by the permanent and operating loads, the design of offshore structures is dominated by environmental loads, especially waves, and the loads arising in the various stages of construction and installation. This lecture deals with environmental loads, whilst the other loadings are treated in Lecture 15A.3.
In civil engineering, earthquakes are normally regarded as accidental loads (see Eurocode 8 [1]), but in offshore engineering they are treated as environmental loads. This practice is followed in the two lectures dealing with loads, Lecture 15A.2 and 15A.3.
2. ENVIRONMENTAL LOADS
Environmental loads are those caused by environmental phenomena such as wind, waves, current, tides, earthquakes, temperature, ice, sea bed movement, and marine growth. Their characteristic parameters, defining design load values, are determined in special studies on the basis of available data. According to US and Norwegian regulations (or codes of practice), the mean recurrence interval for the corresponding design event must be 100 years, while according to the British rules it should be 50 years or greater. Details of design criteria, simplifying assumptions, required data, etc., can be found in the regulations and codes of practice listed in [1] - [8].
2.1 Wind Loads
Wind loads act on the portion of a platform above the water level, as well as on any equipment, housing, derrick, etc. located on the deck. An important parameter pertaining to wind data is the time interval over which wind speeds are averaged. For averaging intervals less than one minute, wind speeds are classified as gusts. For averaging intervals of one minute or longer they are classified as sustained wind speeds.
The wind velocity profile may be taken from API-RP2A [2]: Vh/VH = (h/H)1/n ………..(1)
where:
Vh is the wind velocity at height h,
VH is the wind velocity at reference height H, typically 10m above mean water level, 1/n is 1/13 to 1/7, depending on the sea state, the distance from land and the averaging time interval. It is approximately equal to 1/13 for gusts and 1/8 for sustained winds in the open ocean.
From the design wind velocity V(m/s), the static wind force Fw(N) acting perpendicular to an exposed area A(m2) can be computed as follows:
where:
ρ is the wind density (ρ ≈ 1.225 Kg/m3)
Cs is the shape coefficient (Cs = 1,5 for beams and sides of buildings, Cs = 0,5 for cylindrical sections and Cs = 1,0 for total projected area of platform).
Shielding and solidity effects can be accounted for, in the judgment of the designer, using appropriate coefficients.
For combination with wave loads, the DNV [4] and DOE-OG [7] rules recommend the most unfavorable of the following two loadings:
a. 1-minute sustained wind speeds combined with extreme waves. b. 3-second gusts.
API-RP2A [2] distinguishes between global and local wind load effects. For the first case it gives guideline values of mean 1-hour average wind speeds to be combined with extreme waves and current. For the second case it gives values of extreme wind speeds to be used without regard to waves.
Wind loads are generally taken as static. When, however, the ratio of height to the least horizontal dimension of the wind exposed object (or structure) is greater than 5, then this object (or structure) could be wind sensitive. API-RP2A requires the dynamic effects of the wind to be taken into account in this case and the flow induced cyclic wind loads due to vortex shedding must be investigated.
2.2 Wave Loads
The wave loading of an offshore structure is usually the most important of all environmental loadings for which the structure must be designed. The forces on the structure are caused by the motion of the water due to the waves which are generated by the action of the wind on the surface of the sea. Determination of these forces requires the solution of two separate, though interrelated problems. The first is the sea state computed using an idealization of the wave surface profile and the wave kinematics given by an appropriate wave theory. The second is the computation of the wave forces on individual members and on the total structure, from the fluid motion.
Two different analysis concepts are used:
• The design wave concept, where a regular wave of given height and period is defined and the forces due to this wave are calculated using a high-order wave theory. Usually the 100-year wave, i.e. the maximum wave with a return period of 100 years, is chosen. No dynamic behavior of the structure is considered. This static analysis is appropriate when the dominant wave periods are well above the period of the structure. This is the case of extreme storm waves acting on shallow water structures. • Statistical analysis on the basis of a wave scatter diagram for the location of the
structure. Appropriate wave spectra are defined to perform the analysis in the frequency domain and to generate random waves, if dynamic analyses for extreme wave loadings are required for deepwater structures. With statistical methods, the most probable maximum force during the lifetime of the structure is calculated using linear wave theory. The statistical approach has to be chosen to analyze the fatigue strength and the dynamic behavior of the structure.
2.2.1 Wave theories
Wave theories describe the kinematics of waves of water on the basis of potential theory. In particular, they serve to calculate the particle velocities and accelerations and the dynamic pressure as functions of the surface elevation of the waves. The waves are assumed to be long-crested, i.e. they can be described by a two-dimensional flow field, and are characterized by the parameters: wave height (H), period (T) and water depth (d) as shown in Figure 1.
Different wave theories of varying complexity, developed on the basis of simplifying assumptions, are appropriate for different ranges of the wave parameters. Among the most common theories are: the linear Airy theory, the Stokes fifth-order theory, the solitary wave theory, the cnoidal theory, Dean's stream function theory and the numerical theory by Chappelear. For the selection of the most appropriate theory, the graph shown in Figure 2 may be consulted. As an example, Table 1 presents results of the linear wave theory for finite
depth and deep water conditions. Corresponding particle paths are illustrated in Figures 3 and 4. Note the strong influence of the water depth on the wave kinematics. Results from high-order wave theories can be found in the literature, e.g. see [9].
2.2.2 Wave Statistics
In reality waves do not occur as regular waves, but as irregular sea states. The irregular appearance results from the linear superposition of an infinite number of regular waves with varying frequency (Figure 5). The best means to describe a random sea state is using the wave energy density spectrum S(f), usually called the wave spectrum for simplicity. It is formulated as a function of the wave frequency f using the parameters: significant wave height Hs (i.e. the mean of the highest third of all waves present in a wave train) and mean wave period (zero-upcrossing period) To. As an additional parameter the spectral width can be taken into account.
Wave directionality can be introduced by means of a directional spreading function D(f, ), where σ is the angle of the wave approach direction (Figure 6). A directional wave spectrum S (f,σ) can then be defined as:
S (f,σ ) = S(f).D (f,σ ) ………...….(3)
The response of the structure, i.e. forces, motions, is calculated by multiplication of the wave energy spectrum with the square of a linear transfer function. From the resulting response spectrum the significant and the maximum expected response in a given time interval can be easily deduced.
For long-term statistics, a wave scatter diagram for the location of the structure is needed. It can be obtained from measurements over a long period or be deduced from weather observations in the region (the so-called hindcast method). The scatter diagram contains the joint probability of occurrence of pairs of significant wave height and mean wave period. For every pair of parameters the wave spectrum is calculated by a standard formula, e.g. Pierson-Moskowitz (Figure 6), yielding finally the desired response spectrum. For fatigue analysis the total number and amplitude of load cycles during the life-time of the structure can be derived in this way. For structures with substantial dynamic response to the wave excitation, the
maximum forces and motions have to be calculated by statistical methods or a time-domain analysis.
2.2.3 Wave forces on structural members
Structures exposed to waves experience substantial forces much higher than wind loadings. The forces result from the dynamic pressure and the water particle motions. Two different cases can be distinguished:
• Large volume bodies, termed hydrodynamic compact structures, influence the wave field by diffraction and reflection. The forces on these bodies have to be determined by costly numerical calculations based on diffraction theory.
• Slender, hydrodynamically transparent structures have no significant influence on the wave field. The forces can be calculated in a straight-forward manner with Morison's equation. As a rule, Morison's equation may be applied when D/L 0.2, where D is the member diameter and L is the wave length.
The steel jackets of offshore structures can usually be regarded as hydrodynamically transparent. The wave forces on the submerged members can therefore be calculated by Morison's equation, which expresses the wave force as the sum of an inertia force proportional to the particle acceleration and a non-linear drag force proportional to the square of the particle velocity:
... (4) Where,
F is the wave force per unit length on a circular cylinder (N)
v, |v| are water particle velocity normal to the cylinder, calculated with the selected wave theory at the cylinder axis (m/s)
are water particle acceleration normal to the cylinder, calculated with the selected wave theory at the cylinder axis (m/s2)
ρ is the water density (kg/m3)
D is the member diameter, including marine growth (m) CD, CM are drag and inertia coefficients, respectively.
In this form the equation is valid for fixed tubular cylinders. For the analysis of the motion response of a structure it has to be modified to account for the motion of the cylinder [10]. The values of CD and CM depend on the wave theory used, surface roughness and the flow parameters. According to API-RP2A, CD ≈ 0,6 to 1,2 and CM ≈ 1,3 to 2,0. Additional information can be found in the DNV rules [4].
The total wave force on each member is obtained by numerical integration over the length of the member. The fluid velocities and accelerations at the integration points are found by direct application of the selected wave theory.
According to Morison's equation the drag force is non-linear. This non-linear formulation is used in the design wave concept. However, for the determination of a transfer function needed for frequency domain calculations, the drag force has to be linearized in a suitable way [9]. Thus, frequency domain solutions are appropriate for fatigue life calculations, for which the forces due to the operational level waves are dominated by the linear inertia term. The nonlinear formulation and hence time domain solutions are required for dynamic analyses of deepwater structures under extreme, storm waves, for which the drag portion of the force is the dominant part [10].
In addition to the forces given by Morison's equation, the lift forces FD and the slamming forces FS, typically neglected in global response computations, can be important for local member design. For a member section of unit length, these forces can be estimated as follows:
FL = (1/2) ρ CL Dv2 ... (5) FS = (1/2) ρ Cs Dv2 ... (6)
where CL, CS are the lift and slamming coefficients respectively, and the rest of the symbols are as defined in Morison's equation. Lift forces are perpendicular to the member axis and the fluid velocity v and are related to the vortex shedding frequency. Slamming forces acting on the underside of horizontal members near the mean water level are impulsive and nearly vertical. Lift forces can be estimated by taking CL ≈ 1,3 CD. For tubular members Cs ≈ π. 2.3 Current Loads
There are tidal, circulation and storm generated currents. Figure 7 shows a wind and tidal current profile typical of the Gulf of Mexico. When insufficient field measurements are available, current velocities may be obtained from various sources, e.g. Appendix A of DNV [4]. In platform design, the effects of current superimposed on waves are taken into account by adding the corresponding fluid velocities vectorially. Since the drag force varies with the
square of the velocity, this addition can greatly increase the forces on a platform. For slender members, cyclic loads induced by vortex shedding may also be important and should be examined.
2.4 Earthquake Loads
Offshore structures in seismic regions are typically designed for two levels of earthquake intensity: the strength level and the ductility level earthquake. For the strength level earthquake, defined as having a "reasonable likelihood of not being exceeded during the platform's life" (mean recurrence interval ~ 200 - 500 years), the structure is designed to respond elastically. For the ductility level earthquake, defined as close to the "maximum credible earthquake" at the site, the structure is designed for inelastic response and to have adequate reserve strength to avoid collapse.
For strength level design, the seismic loading may be specified either by sets of accelerograms (Figure 8) or by means of design response spectra (Figure 9). Use of design spectra has a number of advantages over time history solutions (base acceleration input). For this reason design response spectra are the preferable approach for strength level designs. If the design spectral intensity, characteristic of the seismic hazard at the site, is denoted by amax, then API-RP2A recommends using amax for the two principal horizontal directions and 0,5amax for the vertical direction. The DNV rules, on the other hand, recommend amax and 0,7 amax for the two horizontal directions (two different combinations) and 0,5 amax for the vertical. The value of amax and often the spectral shapes are determined by site specific seismological studies.
Designs for ductility level earthquakes will normally require inelastic analyses for which the seismic input must be specified by sets of 3-component accelerograms, real or artificial, representative of the extreme ground motions that could shake the platform site. The characteristics of such motions, however, may still be prescribed by means of design spectra,
which are usually the result of a site specific seismotectonic study. More detail of the analysis of earthquakes is given in the Lectures 17: Seismic Design.
2.5 Ice and Snow Loads
Ice is a primary problem for marine structures in the arctic and sub-arctic zones. Ice formation and expansion can generate large pressures that give rise to horizontal as well as vertical forces. In addition, large blocks of ice driven by current, winds and waves with speeds that can approach 0,5 to 1,0 m/s, may hit the structure and produce impact loads.
As a first approximation, statically applied, horizontal ice forces may be estimated as follows: Fi = CifcA ... (7)
Where,
A is the exposed area of structure, fc is the compressive strength of ice,
Ci is the coefficient accounting for shape, rate of load application and other factors, with usual values between 0,3 and 0,7.
Generally, detailed studies based on field measurements, laboratory tests and analytical work are required to develop reliable design ice forces for a given geographical location.
In addition to these forces, ice formation and snow accumulations increase gravity and wind loads, the latter by increasing areas exposed to the action of wind. More detailed information on snow loads may be found in Eurocode 1 [8].
2.6 Loads due to Temperature Variations
Offshore structures can be subjected to temperature gradients which produce thermal stresses. To take account of such stresses, extreme values of sea and air temperatures which are likely to occur during the life of the structure must be estimated. Relevant data for the North Sea are given in BS6235 [6]. In addition to the environmental sources, human factors can also generate thermal loads, e.g. through accidental release of cryogenic material, which must be taken into account in design as accidental loads. The temperature of the oil and gas produced must also be considered.
2.7 Marine Growth
Marine growth is accumulated on submerged members. Its main effect is to increase the wave forces on the members by increasing not only exposed areas and volumes, but also the drag coefficient due to higher surface roughness. In addition, it increases the unit mass of the member, resulting in higher gravity loads and in lower member frequencies. Depending upon geographic location, the thickness of marine growth can reach 0,3m or more. It is accounted for in design through appropriate increases in the diameters and masses of the submerged members.
2.8 Tides
Tides affect the wave and current loads indirectly, i.e. through the variation of the level of the sea surface. The tides are classified as: (a) astronomical tides - caused essentially from the gravitational pull of the moon and the sun and (b) storm surges - caused by the combined action of wind and barometric pressure differentials during a storm. The combined effect of the two types of tide is called the storm tide. Tide dependent water levels and the associated definitions, as used in platform design, are shown in Figure 10. The astronomical tide range depends on the geographic location and the phase of the moon. Its maximum, the spring tide, occurs at new moon. The range varies from centimeters to several meters and may be obtained from special maps. Storm surges depend upon the return period considered and their range is on the order of 1,0 to 3,0m. When designing a platform, extreme storm waves are superimposed on the still water level (see Figure 10), while for design considerations such as levels for boat landing places, barge fenders, upper limits of marine growth, etc., the daily variations of the astronomical tide are used.
2.9 Sea Floor Movements
Movement of the sea floor can occur as a result of active geologic processes, storm wave pressures, earthquakes, pressure reduction in the producing reservoir, etc. The loads generated by such movements affect, not only the design of the piles, but the jacket as well. Such forces are determined by special geotechnical studies and investigations.
3. CONCLUDING SUMMARY
• Environmental loads form a major category of loads which control many aspects of platform design.
• The main environmental loads are due to wind, waves, current, earthquakes, ice and snow, temperature variations, marine growth, tides and seafloor movements. • Widely accepted rules of practice, listed as [1] - [13], provide guideline values for
most environmental loads.
• For major structures, specification of environmental design loads requires specific studies.
• Some environmental loads can be highly uncertain.
• The definition of certain environmental loads depends upon the type of analysis used in the design.
4. REFERENCES
[1] Eurocode 8: "Structures in Seismic Regions - Design", CEN (in preparation).
[2] API-RP2A, "Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms", American Petroleum Institute, Washington, D.C., 18th ed., 1989. [3] OCS, "Requirements for Verifying the Structural Integrity of OCS Platforms"., United States Geologic Survey, National Centre, Reston, Virginia, 1980.
[4] DNV, "Rules for the Design, Construction and Inspection of Offshore Structures", Det Norske Veritas, Oslo, 1977 (with corrections 1982).
[5] NPD, "Regulation for Structural Design of Load-bearing Structures Intended for Exploitation of Petroleum Resources", Norwegian Petroleum Directorate, 1985.
[6] BS6235, "Code of Practice for Fixed Offshore Structures", British Standards Institution, London, 1982.
[7] DOE-OG, "Offshore Installation: Guidance on Design and Construction", U.K., Dept. of Energy, London 1985.
[8] Eurocode 1: "Basis of Design and Actions on Structures", CEN (in preparation).
[9] Clauss, G. T. et al: "Offshore Structures, Vol 1 - Conceptual Design and Hydromechanics", Springer, London 1992.
[10] Anagnostopoulos, S.A., "Dynamic Response of Offshore Structures to Extreme Waves including Fluid - Structure Interaction", Engr. Structures, Vol. 4, pp.179-185, 1982.
[11] Hsu, H.T., "Applied Offshore Structural Engineering", Gulf Publishing Co., Houston, 1981. [12] Graff, W.J., "Introduction to Offshore Structures", Gulf Publishing Co., Houston, 1981. [13] Gerwick, B.C. Jr., "Construction of Offshore Structures", John Wiley, New York, 1986.
Table 1 Results of Linear Airy Theory [11] Phase θ = kx - ω t
Relative water depth d/L
Deep water d/L ≥ 0,5
Finite water depth d/L < 0,5 Velocity potential θ
Surface elevation z
Dynamic pressure pdyn =
ζa cos θ ρ gζa ekz cos θ
ζa cos θ
Water particle velocities
horizontal u =
vertical w =
ζa ω ekz cos θ
ζa ω ekz sin θ Water particle accelerations
horizontal u' = vertical w' = ζa ω2 ekz sin θ -ζa ω2 ekz cos θ Wave celerity c = Group velocity cgr = Circular frequency ω = Wave length L = Wave number k = co = cgr = ω = Lo = ko = c = cgr = ω = L = kd tanh kd = Water particle displacements
horizontal ξ vertical ζ Particle trajectories -ζa ekz sin θ ζa ekz cos θ Circular orbits Elliptical orbits Where ζ a =
Loads (II): Other Loads
OBJECTIVE/SCOPETo present and briefly describe all loads, except environmental loads, and the load combinations for which a fixed offshore structure must be designed.
PREREQUISITES
A basic knowledge of structural analysis for static and dynamic loadings. SUMMARY
The various categories of loads, except environmental, for which a pile-supported steel offshore platform must be designed are presented. These categories include permanent (dead) loads, operating (live) loads, loads generated during fabrication and installation (due to lifts, loadout, transportation, launching and upending) and accidental loads. In addition, the different load combinations for all types of loads, including environmental, as required (or suggested) by applicable regulations (or codes of practice) are given.
The categories of loads described herein are the following: 1. Permanent (dead) loads
2. Operating (live) loads
3. Fabrication and installation loads 4. Accidental loads
The major categories of environmental loads are not included. They are dealt with in Lecture 15A.2.
1. PERMANENT (DEAD) LOADS Permanent loads include the following:
a. Weight of the structure in air, including the weight of grout and ballast, if necessary. b. Weights of equipment, attachments or associated structures which are permanently mounted on the platform.
c. Hydrostatic forces on the various members below the waterline. These forces include buoyancy and hydrostatic pressures.
Sealed tubular members must be designed for the worst condition when flooded or non-flooded.
2. OPERATING (LIVE) LOADS
Operating loads arise from the operations on the platform and include the weight of all non-permanent equipment or material, as well as forces generated during operation of equipment. More specifically, operating loads include the following:
a. The weight of all non-permanent equipment (e.g. drilling, production), facilities (e.g. living quarters, furniture, life support systems, heliport, etc), consumable supplies, liquids, etc. b. Forces generated during operations, e.g. drilling, vessel mooring, helicopter landing, crane operations, etc.
The necessary data for computation of all operating loads are provided by the operator and the equipment manufacturers. The data need to be critically evaluated by the designer. An example of detailed live load specification is given in Table 1 where the values in the first and second columns are for design of the portions of the structure directly affected by the loads and the reduced values in the last column are for the structure as a whole. In the absence of such data, the following values are recommended in BS6235 [1]:
a. crew quarters and passageways: 3,2 KN/m2 b. working areas: 8,5 KN/m2
c. storage areas: γH KN/m2 where,
γ is the specific weight of stored materials, not to be taken less than 6,87KN/m3, H is the storage height (m).
Forces generated during operations are often dynamic or impulsive in nature and must be treated as such. For example, according to the BS6235 rules, two types of helicopter landing should be considered, heavy and emergency landing. The impact load in the first case is to be taken as 1,5 times the maximum take-off weight, while in the second case this factor becomes 2,5. In addition, a horizontal load applied at the points of impact and taken equal to half the maximum take-off weight must be considered. Loads from rotating machinery, drilling equipment, etc. may normally be treated as harmonic forces. For vessel mooring, design
forces are computed for the largest ship likely to approach at operational speeds. According to BS6235, the minimum impact to be considered is of a vessel of 2500 tonnes at 0,5 m/s. 3. FABRICATION AND INSTALLATION LOADS
These loads are temporary and arise during fabrication and installation of the platform or its components. During fabrication, erection lifts of various structural components generate lifting forces, while in the installation phase forces are generated during platform loadout, transportation to the site, launching and upending, as well as during lifts related to installation. According to the DNV rules [2], the return period for computing design environmental conditions for installation as well as fabrication should normally be three times the duration of the corresponding phase. API-RP2A, on the other hand [3], leaves this design return period up to the owner, while the BS6235 rules [1] recommend a minimum recurrence interval of 10 years for the design environmental loads associated with transportation of the structure to the offshore site.
3.1 Lifting Forces
Lifting forces are functions of the weight of the structural component being lifted, the number and location of lifting eyes used for the lift, the angle between each sling and the vertical axis and the conditions under which the lift is performed (Figure 1). All members and connections of a lifted component must be designed for the forces resulting from static equilibrium of the lifted weight and the sling tensions. Moreover, API-RP2A recommends that in order to compensate for any side movements, lifting eyes and the connections to the supporting structural members should be designed for the combined action of the static sling load and a horizontal force equal to 5% this load, applied perpendicular to the padeye at the centre of the pin hole. All these design forces are applied as static loads if the lifts are performed in the fabrication yard. If, however, the lifting derrick or the structure to be lifted is on a floating vessel, then dynamic load factors should be applied to the static lifting forces. In particular, for lifts made offshore API-RP2A recommends two minimum values of dynamic load factors: 2,0 and 1,35. The first is for designing the padeyes as well as all members and their end connections framing the joint where the padeye is attached, while the second is for all other members transmitting lifting forces. For loadout at sheltered locations, the corresponding minimum load factors for the two groups of structural components become, according to API-RP2A, 1,5 and 1,15, respectively.
3.2 Loadout Forces
These are forces generated when the jacket is loaded from the fabrication yard onto the barge. If the loadout is carried out by direct lift, then, unless the lifting arrangement is different from that to be used for installation, lifting forces need not be computed, because lifting in the open sea creates a more severe loading condition which requires higher dynamic load factors. If loadout is done by skidding the structure onto the barge, a number of static loading conditions must be considered, with the jacket supported on its side. Such loading conditions arise from the different positions of the jacket during the loadout phases, (as shown in Figure 2), from movement of the barge due to tidal fluctuations, marine traffic or change of draft, and from possible support settlements. Since movement of the jacket is slow, all loading
conditions can be taken as static. Typical values of friction coefficients for calculation of skidding forces are the following:
• steel on steel without lubrication... 0,25 • steel on steel with lubrication...0,15 • steel on teflon... 0,10 • teflon on teflon... 0,08
3.3 Transportation Forces
These forces are generated when platform components (jacket, deck) are transported offshore on barges or self-floating. They depend upon the weight, geometry and support
conditions of the structure (by barge or by buoyancy) and also on the environmental conditions (waves, winds and currents) that are encountered during transportation. The types of motion that a floating structure may experience are shown schematically in Figure 3.
In order to minimize the associated risks and secure safe transport from the fabrication yard to the platform site, it is important to plan the operation carefully by considering, according to API-RP2A [3], the following:
1. Previous experience along the tow route
2. Exposure time and reliability of predicted "weather windows" 3. Accessibility of safe havens
4. Seasonal weather system
5. Appropriate return period for determining design wind, wave and current conditions, taking into account characteristics of the tow such as size, structure, sensitivity and cost.
Transportation forces are generated by the motion of the tow, i.e. the structure and supporting barge. They are determined from the design winds, waves and currents. If the structure is self-floating, the loads can be calculated directly. According to API-RP2A [3], towing analyses must be based on the results of model basin tests or appropriate analytical methods and must consider wind and wave directions parallel, perpendicular and at 45 to the tow axis. Inertial loads may be computed from a rigid body analysis of the tow by combining roll and pitch with heave motions, when the size of the tow, magnitude of the sea state and experience make such assumptions reasonable. For open sea conditions, the following may be considered as typical design values:
1. Single - amplitude roll: 20° 2. Single - amplitude pitch: 10° 3. Period of roll or pitch: 10 second 4. Heave acceleration: 0,2 g
When transporting a large jacket by barge, stability against capsizing is a primary design consideration because of the high centre of gravity of the jacket. Moreover, the relative stiffness of jacket and barge may need to be taken into account together with the wave slamming forces that could result during a heavy roll motion of the tow (Figure 4) when structural analyses are carried out for designing the tie-down braces and the jacket members affected by the induced loads. Special computer programs are available to compute the transportation loads in the structure-barge system and the resulting stresses for any specified environmental condition.
3.4 Launching and Upending Forces
These forces are generated during the launch of a jacket from the barge into the sea and during the subsequent upending into its proper vertical position to rest on the seabed. A schematic view of these operations can be seen in Figure 5.
There are five stages in a launch-upending operation: 1. Jacket slides along the skid beams 2. Jacket rotates on the rocker arms 3. Jacket rotates and slides simultaneously
4. Jacket detaches completely and comes to its floating equilibrium position
5. Jacket is upended by a combination of controlled flooding and simultaneous lifting by a derrick barge.
The loads, static as well as dynamic, induced during each of these stages and the force required to set the jacket into motion can be evaluated by appropriate analyses, which also consider the action of wind, waves and currents expected during the operation.
To start the launch, the barge must be ballasted to an appropriate draft and trim angle and subsequently the jacket must be pulled towards the stern by a winch. Sliding of the jacket starts as soon as the downward force (gravity component and winch pull) exceeds the friction force. As the jacket slides, its weight is supported on the two legs that are part of the launch trusses. The support length keeps decreasing and reaches a minimum, equal to the length of the rocker beams, when rotation starts. It is generally at this instant that the most severe launching forces develop as reactions to the weight of the jacket. During stages (d) and (e),
variable hydrostatic forces arise which have to be considered at all members affected. Buoyancy calculations are required for every stage of the operation to ensure fully controlled, stable motion. Computer programs are available to perform the stress analyses required for launching and upending and also to portray the whole operation graphically.
4. ACCIDENTAL LOADS
According to the DNV rules [2], accidental loads are loads, ill-defined with respect to intensity and frequency, which may occur as a result of accident or exceptional circumstances. Accidental loads are also specified as a separate category in the NPD regulations [4], but not in API-RP2A [3], BS6235 [1] or the DOE-OG rules [5]. Examples of accidental loads are loads due to collision with vessels, fire or explosion, dropped objects, and unintended flooding of buoyancy tanks. Special measures are normally taken to reduce the risk from accidental loads. For example, protection of wellheads or other critical equipment from a dropped object can be provided by specially designed, impact resistant covers. According to the NPD regulations [4], an accidental load can be disregarded if its annual probability of occurrence is less than 10-4. This number is meant as an order of magnitude estimate and is extremely difficult to compute. Earthquakes are treated as an environmental load in offshore structure design.
5. LOAD COMBINATIONS
The load combinations used for designing fixed offshore structures depend upon the design method used, i.e. whether limit state or allowable stress design is employed. The load combinations recommended for use with allowable stress procedures are:
a. Dead loads plus operating environmental loads plus maximum live loads, appropriate to normal operations of the platform.
b. Dead loads plus operating environmental loads plus minimum live loads, appropriate to normal operations of the platform.
c. Dead loads plus extreme (design) environmental loads plus maximum live loads, appropriate for combining with extreme conditions.
d. Dead loads plus extreme (design) environmental loads plus minimum live loads, appropriate for combining with extreme conditions.
Moreover, environmental loads, with the exception of earthquake loads, should be combined in a manner consistent with their joint probability of occurrence during the loading condition considered. Earthquake loads, if applicable, are to be imposed as a separate environmental load, i.e., not to be combined with waves, wind, etc. Operating environmental conditions are defined as representative of severe but not necessarily limiting conditions that, if exceeded, would require cessation of platform operations.
The DNV rules [2] permit allowable stress design but recommend the semi-probabilistic limit state design method, which the NPD rules also require [4]. BS6235 permits both methods but the design equations it gives are for the allowable stress method [1]. API-RP2A is very specific in recommending not to apply limit state methods. According to the DNV and the NPD rules for limit state design, four limit states must be checked:
1. Ultimate limit state
For this limit state the following two loading combinations must be used: Ordinary: 1,3 P + 1,3 L + 1,0 D + 0,7 E, and
Extreme : 1,0 P + 1,0 L + 1,0 D + 1,3 E
where P, L, D and E stand for Permanent (dead), Operating (live), Deformation (e.g., temperature, differential settlement) and Environmental loads respectively. For well controlled dead and live loads during fabrication and installation, the load factor 1,3 may be reduced to 1,2. Furthermore, for structures that are unmanned during storm conditions and which are not used for storage of oil and gas, the 1,3 load factor for environmental loads - except earthquakes - may be reduced to 1,15.
2. Fatigue limit state
All load factors are to be taken as 1,0. 3. Progressive Collapse limit state
All load factors are to be taken as 1,0. 4. Serviceability limit state
All load factors are to be taken as 1,0.
The so-called characteristic values of the loads used in the above combinations and limit states are summarized in Table 2, taken from the NPD rules.
6. CONCLUDING SUMMARY
• In addition to environmental loads, an offshore structure must be designed for dead and live loads, fabrication and installation loads as well as accidental loads. • Widely accepted rules of practice, listed in the references, are usually followed for