PETRONAS TECHNICAL STANDARDS DESIGN AND ENGINEERING PRACTICE (CORE)
MANUAL
RISER DESIGN
PTS 31.40.10.10 DECEMBER 1999
PREFACE
PETRONAS Technical Standards (PTS) publications reflect the views, at the time of publication, of PETRONAS OPUs/Divisions. They are based on the experience acquired during the involvement with the design, construction, operation and maintenance of processing units and facilities. Where appropriate they are based on, or reference is made to, national and international standards and codes of practice. The objective is to set the recommended standard for good technical practice to be applied by PETRONAS' OPUs in oil and gas production facilities, refineries, gas processing plants, chemical plants, marketing facilities or any other such facility, and thereby to achieve maximum technical and economic benefit from standardisation. The information set forth in these publications is provided to users for their consideration and decision to implement. This is of particular importance where PTS may not cover every requirement or diversity of condition at each locality. The system of PTS is expected to be sufficiently flexible to allow individual operating units to adapt the information set forth in PTS to their own environment and requirements. When Contractors or Manufacturers/Suppliers use PTS they shall be solely responsible for the quality of work and the attainment of the required design and engineering standards. In particular, for those requirements not specifically covered, the Principal will expect them to follow those design and engineering practices which will achieve the same level of integrity as reflected in the PTS. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting from his own responsibility, consult the Principal or its technical advisor. The right to use PTS rests with three categories of users : 1) 2) 3)
PETRONAS and its affiliates. Other parties who are authorised to use PTS subject to appropriate contractual arrangements. Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) and 2) which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said users comply with the relevant standards.
Subject to any particular terms and conditions as may be set forth in specific agreements with users, PETRONAS disclaims any liability of whatsoever nature for any damage (including injury or death) suffered by any company or person whomsoever as a result of or in connection with the use, application or implementation of any PTS, combination of PTS or any part thereof. The benefit of this disclaimer shall inure in all respects to PETRONAS and/or any company affiliated to PETRONAS that may issue PTS or require the use of PTS. Without prejudice to any specific terms in respect of confidentiality under relevant contractual arrangements, PTS shall not, without the prior written consent of PETRONAS, be disclosed by users to any company or person whomsoever and the PTS shall be used exclusively for the purpose they have been provided to the user. They shall be returned after use, including any copies which shall only be made by users with the express prior written consent of PETRONAS. The copyright of PTS vests in PETRONAS. Users shall arrange for PTS to be held in safe custody and PETRONAS may at any time require information satisfactory to PETRONAS in order to ascertain how users implement this requirement.
TABLE OF CONTENTS 1. 1.1 1.2 1.3
INTRODUCTION SCOPE DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS DEFINITION
2. 2.1 2.2 2.3 2.4
DESIGN INTERFACES GENERAL TOPSIDE INTERFACE JACKET INTERFACE PIPELINE/EXPANSION SPOOL INTERFACE
3. 3.1 3.2 3.3 3.4 3.5 3.6
RISER/TIE-IN CONCEPTS SUMMARY OF MAIN RISER TYPES RISER INSTALLATION METHODS SUBSEA TIE-IN METHODS FLEXIBLE SPOOLS SELECTION OF RISER/PIPELINE TIE-IN METHOD AVAILABLE CONSTRUCTION METHODS
4. 4.1 4.2 4.3
RISER ROUTING AND LOCATION BASIC ROUTING REQUIREMENTS APPROACH TO PLATFORMS SAFETY
5. 5.1 5.2 5.3 5.4 5.5 5.6 5.7
DESIGN DATA RISER SYSTEM/PLATFORM DATA SOIL DATA METOCEAN DATA ATMOSPHERIC CONDITIONS EARTHQUAKE RETURN PERIODS DIRECTIONALITY
6. 6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9 6.10 6.11 6.12 6.13
RISER AND TIE-IN SPOOL ANALYSIS FAILURE MODES DESIGN LOADS LOAD CASES WALL THICKNESS DETERMINATION PIPELINE EXPANSION EXPANSION LOOP RISER STRUCTURAL ANALYSIS ALLOWABLE STRESSES ALLOWABLE STRAINS OVALISATION COLLAPSE VORTEX SHEDDING FATIGUE
7. 7.1 7.2 7.3 7.4
RISER SUPPORT DESIGN RISER SUPPORT TYPES DESIGN CONSIDERATIONS LOADING CONDITIONS CORROSION PROTECTION
8. 8.1 8.2 8.3 8.4 8.5
J-TUBE DESIGN DESIGN DATA J-TUBE ROUTING J-TUBE SIZING AND RADIUS OF CURVATURE PULL-IN LOADS STRUCTURAL DESIGN OF J-TUBE AND SUPPORTS
8.6 8.7
APPURTENANCES CORROSION PROTECTION
9. 9.1 9.2 9.3 9.4 9.5
FITTINGS FLANGES GASKETS BOLTING VALVES BENDS
10. 10.1 10.2 10.3 10.4
RISER MATERIALS AND CORROSION PROTECTION GENERAL LINEPIPE EXTERNAL COATING CATHODIC PROTECTION
11. 11.1 11.2 11.3
MECHANICAL PROTECTION PROTECTION FROM BOAT IMPACT PROTECTION FROM DROPPED OBJECTS PROTECTION FROM SNAGGING LOADS
12. 12.1 12.2 12.3 12.4 12.5
INSTALLATION REQUIREMENTS RISER INSTALLATION TOLERANCES INSTALLATION FEASIBILITY CLEARANCE FOR HYPERBARIC WELDING CONSTRUCTION AIDS TEMPORARY CONSIDERATIONS
13.
REQUIREMENTS FOR OPERATIONS AND MAINTENANCE
14. 14.1 14.2 14.3
DESIGN OUTPUT GENERAL DESIGN DOCUMENTATION AS-BUILT DOCUMENTATION
15.
REFERENCES
APPENDICES APPENDIX 1
FIGURES
1.
INTRODUCTION
1.1
SCOPE This new PTS specifies requirements and gives recommendations for the design of offshore pipeline riser systems, which include the piping, riser clamp supports and any expansion spool or anchoring system at the base of the platform. This PTS identifies a broad approach to the design including: • • • • • • •
definition of riser system and interfaces; potential riser concepts; riser routing; analysis requirements; support design; J-tube design; fittings and materials.
This PTS does not present a methodology, but is intended to act as a checklist of design activities for consideration by an experienced engineer. For the purpose of this PTS, it is assumed that the riser design is based on PTS 31.40.00.10 The scope of this PTS includes only rigid metallic risers; flexible risers and non-metallic risers are excluded from the scope. 1.2
DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS Unless otherwise authorised by PETRONAS, the distribution of this PTS is confined to companies forming part of the PETRONAS or managed by a Group company, and to Contractors and Manufacturers/Suppliers nominated by them. This PTS is intended for use in offshore exploration and production facilities. If national and/or local regulations exist in which some of the requirements may be more stringent than in this PTS, the Contractor shall determine by careful scrutiny which of the requirements are the more stringent and which combination of requirements will be acceptable as regards safety, environmental, economic and legal aspects. In all cases, the Contractor shall inform the Principal of any deviation from the requirements of this PTS which is considered to be necessary in order to comply with national and/or local regulations. The Principal may then negotiate with the Authorities concerned with the object of obtaining agreement to follow this PTS as closely as possible.
1.3
DEFINITION
1.3.1
General definitions The Contractor is the party which carries out all or part of the design, engineering, procurement, construction, commissioning or management of a project, or operation or maintenance of a facility. The Principal may undertake all or part of the duties of the Contractor. The Manufacturer/Supplier is the party which manufactures or supplies equipment and services to perform the duties specified by the Contractor. The Principal is the party which initiates the project and ultimately pays for its design and construction. The Principal will generally specify the technical requirements. The Principal may also include an agent or consultant authorised to act for, and on behalf of, the Principal. The word shall indicates a requirement. The word should indicates a recommendation.
1.3.2
1.4
1.5
Specific definitions J-Tube
J-shaped tube installed on a platform, through which a pipeline can be pulled to form a riser.
Piping components
items integrated in the pipeline/riser such as flanges, tees, bends, reducers and valves.
Riser support
structure intended for fixing the riser to the platform or for local or continuous guidance of the riser assembly.
Riser system
riser pipe, supports, integrated piping components and corrosion prevention system.
ABBREVIATIONS ASCE
American Society of Civil Engineers
EPDM
Ethylene Propylene Diene Monomer
ESD
Emergency Shut Down
HAT
Highest Astronomical Tide
QRA
Quantitative Risk Assessment
LAT
Lowest Astronomical Tide
RTJ
Ring Type Joint
SMYS
Specified Minimum Yield Stress
CROSS-REFERENCES Where cross-references to other parts of this PTS are made, the referenced section number is shown in brackets. Other documents referenced in this PTS are listed in (15).
2.
DESIGN INTERFACES
2.1
GENERAL The riser system shall be designed as a part of the total offshore pipeline system. For design purposes, it is necessary to define the extent of the riser assembly and to establish the interfaces between the riser system and adjacent systems. The interfaces provide a point where loading and/or displacement, and the requirements of the various systems can be defined and reconciled. The riser interface points can be summarised as follows: • topside and supports; • jacket and supports; • pipeline/tie-in spool. The riser analysis model shall take into account the effects of the interface points as further detailed below.
2.2
TOPSIDE INTERFACE The design of the riser system requires detailed interfacing with the platform topsides. The code break for the riser system shall extend up to and include the pig trap (including associated pipework and valves) or, if no pig trap is fitted, to the first isolation valve off the riser. The riser supports fall outside the code break. The following design issues shall be addressed: • • • • • • • • • •
2.3
design responsibility; exact location of code breaks marked on process engineering flow schemes (PEFS); piping layouts; structural layouts; instrument connections; electrical isolation; overlap of riser and piping analyses; support locations; access for pigging operations; access for valve overhaul.
JACKET INTERFACE The design of the riser system requires detailed interfacing with the jacket structure. The riser supports fall outside the code break. The following design issues shall be addressed: • • • • • • • • • • •
design responsibility; code breaks; details of the structural layout and dimensions of the jacket members; platform deflections; riser routing; riser support locations and type; electrical isolation; riser loadings on riser supports; ESD valve location; structural protection; hook-up to top section of riser.
2.4
PIPELINE/EXPANSION SPOOL INTERFACE The design of the riser system requires detailed interfacing with the pipeline/expansion spool. The interface between the riser and the submarine pipeline depends on the method of connection, geometry and type of riser and should be agreed in each case. The following design issues shall be addressed: • • • • • •
design responsibility; location of code breaks; riser routing; pipeline approach; expansion spool layout; overlap of riser and expansion spool structural analysis (often performed in one analysis from pipeline to pig trap); • the tie-in method.
3.
RISER/TIE-IN CONCEPTS
3.1
SUMMARY OF MAIN RISER TYPES Risers for platforms may be broadly grouped into the following categories: • • • •
riser for steel jacket platform; riser for gravity base structure (concrete); J-tube riser - this category is further discussed in (8); caisson riser system; consists of a caisson which forms a structural encasement and a number of riser pipes which are installed in the caisson. Caissons are protective devices to eliminate environmental loading on the riser pipes. Caisson riser systems may reduce the number of riser supports which otherwise would be required for conventional risers; • flexible riser for a floating facility (outside the scope of this PTS). 3.2
RISER INSTALLATION METHODS
3.2.1
General Risers are usually pre-installed with the jacket structure. Otherwise they can be retrofitted onto existing platforms. This may be by the conventional method of lift, set and subsea tiein. Alternatively, one of the following methods may be used without the need for subsea tieins: • • • •
3.2.2
stalk-on method; bending shoe riser method; barefoot riser; J-tube installation (8).
Conventional method Retrofitted risers are fabricated in sections, lifted from a barge and lowered into suitable riser supports which may also be retrofitted onto the jacket. The number of riser sections depends on the water depth and the length of the barge. The riser normally consists of an upper section behind the jacket bracing (to provide safety against boat impact) which is connected to lower sections positioned on the outside of the jacket. After installation, a subsea tie-in is made to the pipeline. A form of retrofit riser clamp may be installed after a jacket has been in service for some time. In this case, provision shall be made for aligning the clamps/guides. This is achieved by connecting the riser clamp/guide which is also clamped to a structural jacket member or stub, depending on the size of riser. Retrofitting of these clamps/guides involves considerable diver time. Alternatively, a riser ladder, or more simply riser support stubs, may have been installed on the jacket in the fabrication yard for future retrofitting of risers. Retrofitting methods without the need for subsea tie-ins are described below.
3.2.3
Stalk-on riser method For shallow water, this is the most commonly used riser installation method. After the pipeline has been laid with its end on the sea bottom and close to the platform, the lay barge is moored in position. The riser bend which will eventually connect the horizontal pipeline to the platform deck is measured and the location at which the pipeline will be cut for connection to the bend is marked. The pipeline is then lifted from the seabed by applying tension to the pipe. In very shallow water with small diameter pipelines, this is not a problem; however, larger lines in deeper water require a substantial length of pipe to be supported off the bottom to avoid overstressing the pipe. The pipe is then cut at the mark, the bend is welded onto the free end of the pipe and the pipe and bend are lowered down. This process of adding pipe is continued until the pipe reaches the bottom. The riser is then secured to the platform using diver-operated clamps. Expansion spools can be set simultaneously with this method.
In deeper waters, the handling of the pipe and riser becomes increasingly difficult and even hazardous to both pipe, equipment and personnel. The main advantages of this technique are: • weld connections are made above surface and can be fully inspected, ensuring weld quality; • diver activities are relatively simple, requiring only a normally-skilled team using standard tools. The expense and time delay involved in mobilising specialised contractor personnel are avoided; • there is no requirement for underwater welding. The disadvantages of this technique are: • the lifting, welding and lowering operation is vulnerable to environmental conditions; • careful planning and strict compliance with the predetermined lifting and lowering procedures are vital to avoid overstressing the pipeline and riser; • greater adjustability in the riser clamps is required because the riser cannot be moved fore and aft once it is welded to the pipeline. 3.2.4
Bending shoe riser method This method, which was developed by Shell Oil Company, consists of installing a curvature limiting shoe on the platform during onshore fabrication. The pipeline is then laid to the structure and positioned under the bending shoe either by manoeuvring the barge or attaching cables to the line as it is laid and pulling it under the shoe. Once the line is in the correct orientation with respect to the centreline of the bending shoe, specially designed hydraulic clamps on the platform capture and secure the riser. These clamps may be installed either during onshore fabrication or immediately before the riser is installed offshore. In very deep water or for pipe with low stiffness, it may be necessary to install auxiliary cables on the riser to assist with the installation. Other than inspection, this method of riser installation requires a minimal amount of underwater work.
3.2.5
Barefoot riser method This method has been used successfully in the Gulf of Mexico. The method is simple and should find many applications, especially for deepwater platforms. The pipe weight and wall thickness are selected such that the pipe can be lifted vertically at the water surface without exceeding a specified, non-buckling, bend in the sag portion of the line. The method consists of approaching the platform with the pipe suspended vertically at the water surface. The pipe is then positioned at a tangent to and in contact with the upper end of a series of pipeline clamps on the platform. The lifting load is decreased according to a prescribed schedule which forces the riser pipe into each successive clamp and puts the bottom span into compression. The riser is then clamped to the platform once the desired curvature in the sag-bend is achieved. The necessary hydraulic or electrically operated riser clamps can be installed offshore using a rail guidance system to land each clamp at a predetermined elevation. Diver time, other than for inspection, would be minimal for this method of riser installation. One other version of this approach to riser installation is called the Guide Rail method. This type varies from the previously described method primarily in the clamp used to attach the riser to the guide rail. The guide rail is a continuous “T” section or “H” beam welded to the platform side or jacket leg during shore fabrication. The installation sequence requires the lay barge to lay away from the platform while a riser barge attaches the riser clamp to the rail and continues to add pipe as the riser is lowered. The lay barge continues to move away from the platform during this operation. After the riser is in position, it is secured to the platform by welding the clamps located above the water line to the rail and by having divers attach the submersed clamps with set screws.
3.3
SUBSEA TIE-IN METHODS
3.3.1
General In most cases, tie-in of the pipeline to the offshore facility is achieved by inserting an expansion spoolpiece. The purpose of the spoolpiece is to absorb expansion loadings, and accommodate the installation tolerance on the pipeline. The spoolpiece connections may be made up using one or a combination of the following methods: • mechanical connectors; • flanged tie-in using RTJ swivel ring flanges; or • hyperbaric welding. These tie-in methods are further described below.
3.3.2
Mechanical connectors A variety of mechanical connectors are available and they generally consist of two components: • a gripping system, to anchor the connector onto the pipe; • a sealing system, using either metallic or elastomeric seals. Mechanical connectors are alternatives or supplements to flanges and can offer certain advantages depending on their design, e.g.: • • • •
some are easier to install (boltless flanges); some can accommodate a degree of misalignment (ball joints); some can be installed directly onto the bare pipe end; some are suitable for diverless application.
Mechanical connector systems are not yet as reliable as welded or flanged connections, hence they are mainly used for emergency repairs to pipelines where speed of repair is essential and the equipment for other repair methods is not available. Mechanical connectors have been developed that can be activated from the surface by hydraulics and without direct diver intervention. To achieve this type of connection, accurate positioning of the end of the pipeline is essential. Once positioned, the pipeline is pulled into the connector which is then activated and clamps around a special hub fitted to the end of the pipeline. 3.3.3
Flanged tie-ins Flanged tie-ins performed by divers on the seabed are effected by installing a flanged make-up spool between the flanged ends of the lines to be connected. The spool is fabricated at the surface to the exact dimensions required, using a template which has been made up on the seabed and retrieved at the surface. Due consideration should be given to the location of the flanges and, where possible, they should be located to minimise bending loads in the flanged joint. The integrity of flanges when subjected to high bending loads shall be confirmed by analysis. The following recommendations apply to flanged tie-ins: • • • • •
the flange shall be of the ring joint type; one of the flanges shall be of the swivel ring type, to facilitate alignment of bolt holes; the specified internal bore of the flange shall be the same as that of the pipeline; the gaskets shall be made of an alloy which is softer than the flange material; wall thickness differences between the flange body and the pipeline shall be accommodated by specifying a tapered slope of not less than 1:5; • all bolts shall be tightened using hydraulic tensioning equipment.
Subsea flanges and fittings should be bolted together using hydraulic tensioning equipment. Hydraulic bolt tensioning equipment is used on either side of a flange to stretch the bolts to a predetermined tension. With the tension maintained on the bolt, the nuts are turned down onto the flange, to bar tight, prior to relaxation of the equipment. In this way the flange can be tensioned to meet the service load. Washers are not used on subsea pipe-to-pipe joints as these are prone to contact corrosion, which causes the bolts to slacken with time. 3.3.4
Hyperbaric welding Sub-surface or hyperbaric welding is performed with the pipeline on the seabed. Special frames are required to align the pipeline ends to be welded, and the welding itself is performed in a special habitat. The systems presently available are operated from a barge or a diving support vessel. This method requires extensive diving capability and special welding procedures. As an alternative to hyperbaric welding, the weld can be performed inside an atmospheric chamber into which the pipeline is pulled. However, this method requires further development to be fully operational and is not presently recommended.
3.4
FLEXIBLE SPOOLS Flexible spools can be installed directly without the necessity of preparing a template, and can considerably speed up the tie-in work. Flexible spools also have the ability to accommodate thermal expansion/contraction. The extra cost of the flexible spools should be weighed against the diving time savings on a project-by-project basis.
3.5
SELECTION OF RISER/PIPELINE TIE-IN METHOD In general, welding is the preferred method for permanent tie-ins as far as this is practical and economic. The welding may be performed at the surface or on the seabed. The disadvantage of the hyperbaric welding technique is that it is a specialised activity, requiring dedicated spreads and a high level of training of the operational personnel. Alternatives shall be subjected to a cost/risk justification.
3.6
AVAILABLE CONSTRUCTION METHODS Depending on the conditions at the intended location, such as weather, current velocity, wave heights, tidal effects, seabed conditions, water depth etc., there may be a preference for one of the possible construction methods. This in turn could put certain limitations on the selection of line sizes. The preferred construction method will also be dependent on the available construction equipment and on the cost of mobilising the required spreads with dedicated equipment and handling capability. The type of riser to suit a particular application depends largely on the pipe size, the platform type, the direction of approach of the pipeline and whether the riser is to be installed during platform fabrication or at some time after the platform is placed.
4.
RISER ROUTING AND LOCATION
4.1
BASIC ROUTING REQUIREMENTS Selection of riser routing and location on a platform shall meet the following requirements as far as practical: • the riser shall have the minimum exposure to damage; • the riser shall not be located below the accommodation or the helideck, or close to escape routes from the accommodation or the temporary safe refuge; • the riser shall be accessible for inspection and maintenance; • in meeting these requirements, gas risers shall have precedence over oil risers. The selection of riser routing and location shall also consider the following general factors: • • • • • • • •
safe and economical installation; supply boat mooring area locations; location of future risers; minimisation of risk of damage by vessel collisions, by positioning risers within the structure above a depth of 20 m below LAT; minimisation of risk of damage by dropped objects; location of ESD valves, and their maintenance and inspection; minimisation of risk of interference with future construction, drilling, workover or platform maintenance or repair operations; access for subsea and topsides hook-up.
Consideration should be given to environmental loading conditions, particularly in the splash zone (5.3.3), where riser lengths and horizontal routing should be minimised. Jacket bracing layout should be considered as this will determine the possible support locations and thus influence riser span lengths. 4.2
APPROACH TO PLATFORMS Detailed consideration shall be given to the approach routes to the platform. This will include consideration of: • • • • • • •
potential crossings; seabed obstruction; existing platforms/seabed facilities in close proximity; angle of pipeline approach; pipeline expansion requirements; routing to minimise risk of damage by dropped objects; accessibility for future positioning of jack-up rig.
When pipelines have to approach the jacket with angles greater than 30° from the perpendicular to the jacket face, the spacing between the risers should be increased to allow more space between the lines on the sea bottom. If the direct approach of a pipeline would be hampered by the future position of a jack-up rig, doglegs can be installed. Doglegs should also be used in preference to tight curved approaches to jackets and provide a means of allowing for pipeline expansion. Consideration should be given to the routing from the bottom riser clamp to the seabed as this section is particularly susceptible to riser expansion, platform movement and scourinduced spans. Where several platforms together form a complex, they should have a staggered layout along a straight line (spine) in order to: • free as much of the jacket faces as possible for risers; • allow easy barge access;
• position different production functions along the spine, so that future extension of any function is perpendicular to the spine; • allow for new functions to be installed along the spine. A dedicated riser platform may be installed to supply additional riser capacity (with scraper barrels and manifolds) and/or to improve safety and reduce the overall risk levels on production facilities. For new developments and extensions of existing complexes a careful study of the new layout should be made in conjunction with anchor patterns (especially the drilling rigs), pipeline approaches, approach path for jack-up rigs and supply boat mooring. 4.3
SAFETY The design shall include a safety assessment which shall quantify the effect of the risers on platform safety and may include the use of risk analysis to determine the need for additional protective measures. Consideration should be given to the use of cost-benefit analysis to assess the relative merits of different protective measures. The requirement for and location of ESD valves should be addressed as part of the development of the platform specific safety case. Any risk analysis performed shall take into account analysis of the risk from both natural and man-made hazards. Natural hazards shall include but not be limited to corrosion attack, marine life attack, extremes of temperature and environmental conditions. Manmade hazards shall include but not be limited to platform loading and off-loading operations, vessel activities, dragged anchors, trawl gear, abrasion by cables and chains, impact by vessels and dropped objects.
5.
DESIGN DATA
5.1
RISER SYSTEM/PLATFORM DATA
5.1.1
Process data The following data are common to all elements of the riser: • • • • • • • • •
5.1.2
minimum bore requirement to meet throughput requirements; fluid type and density - maximum and minimum; design life; design pressure; maximum allowable operating pressure; hydrostatic test pressure for testing in fabrication yard and for system test; design temperature - maximum and minimum; normal operating temperature - maximum and minimum; internal corrosion allowance (if appropriate).
Riser data The following data are required, as a minimum, for the riser design: • riser type - whether a conventional riser for steel platform, for gravity base structure, J-tube riser or caisson riser; • installation philosophy - whether pre-installed or retrofit; • method of tie-in; • steel grade; • outside diameter; • wall thickness; • internal/external coating - type, thickness and density; • insulation - type, thickness and density; • field joint material - type, thickness and density; • valve, fitting and pig trap weight, rating and location; • bend radii, and thinning; • mechanical protection requirements.
5.1.3
Pipeline data • • • • • • • •
5.1.4
steel grade; outside diameter; wall thickness; internal/external coating - type, thickness and density; insulation - type, thickness and density; field joint material - type, thickness and density; expansion movements at free end; degree of trenching, self-burial and/or rock dump.
Expansion tie-in spool data • • • • • • • •
steel grade; outside diameter; wall thickness; internal/external coating - type, thickness and density; riser/spool connection type; geometry of expansion spool; mechanical protection requirements; bend radii and thinning.
5.1.5
Platform data • • • • • • •
5.2
substructure type and dimensions; details of other risers, caissons and/or J-tubes; possible support locations and load restrictions; immediate substructure settlement into seabed; long-term substructure settlement into seabed; anode locations and details; platform displacements under 100-year design condition.
SOIL DATA Soil data provide information regarding resistance of the soil to pipeline movement (lateral and longitudinal friction coefficients), soil strength deterioration due to cyclic wave loading, load bearing capacity of the soil and susceptibility of soil to scour. • • • • •
ASCE classification of soils and grain-size; specific gravity of the soils; soil friction angle for sands; undisturbed shear strength of clay soils; remoulded (disturbed) shear strength or sensitivity.
5.3
METOCEAN DATA
5.3.1
Seawater • water density; • water kinematic viscosity; • marine growth elevations, thickness and density.
5.3.2
Water depth and tides • • • •
5.3.3
water depth, referred to a consistent datum (e.g. LAT) lowest astronomical tide (LAT); highest astronomical tide (HAT); storm surge, i.e. maximum tide level for a specified average return period.
Splash zone The splash zone range is defined as the astronomical tidal range plus the wave height having a probability of exceedance of 0.01. The upper limit of the splash zone is determined by assuming 65% of this wave height above HAT and lower limit by assuming 35% below LAT.
5.3.4
Currents • maximum current velocity for a range of current directions (usually 8), heights above seabed (usually every 10 m) and return period (usually 1 and 100 years); • relationship between the occurrence of wave-induced currents and the steady currents; • the number of hours of occurrence per year for the ranges of steady current from zero to the maximum steady current. These data are used for riser span fatigue calculations.
5.3.5
Waves • maximum wave height for a range of directions (usually 8) and a range of return periods (usually 1 and 100 years); • the most probable wave period associated with each maximum wave height; • the number of waves per year for ranges of wave height from zero to the maximum wave height.
5.4
ATMOSPHERIC CONDITIONS
5.4.1
Wind • maximum wind velocity for return periods of 1 and 100 years; • maximum and minimum ambient air temperatures.
5.4.2
Ice • the maximum thickness of icing on risers; • the maximum thickness and occurrence of permanent ice; • the maximum velocity and occurrence of pack ice.
5.5
EARTHQUAKE In regions of the world prone to earthquakes, the response of the platform under the 100-year seismic event is required.
5.6
RETURN PERIODS The riser system should be designed to withstand loadings resulting from the 100-year return period storm conditions during the operating design condition. The one-year return period storm condition should be used for analysis during the installation and hydrostatic testing design conditions. Where the design life of the pipeline is very short (typically less than 10 years), consideration may be given to reducing the design storm return period to less than 100 years, based on a suitable risk evaluation. If suitable seasonal data are available, seasonal one-year return period storm conditions may be used for the installation and hydrostatic testing design conditions. Such data should not be used if there is a possibility of the relevant construction activity being performed outside the season to which the data relate.
5.7
DIRECTIONALITY Given sufficient hydrographic data, it is acceptable to account for the incident angle of wave and current attack on the pipeline/riser system. Tidal currents are strongly directional. If the wave and current data can be represented as a rosette, giving variation of wave height (or current value) with direction for a given return period, then the resulting flow velocities may be resolved perpendicular to the pipeline axis to give the (most critical) design loading condition.
6.
RISER AND TIE-IN SPOOL ANALYSIS
6.1
FAILURE MODES The riser analysis shall consider the following failure modes: • excessive yielding; • buckling; • fatigue.
6.2
DESIGN LOADS The riser analysis shall consider the following design loads:
6.2.1
Weight loads Static loads due to weight shall include the following: • • • • • •
pipeline/riser material; coatings; attachments such as anodes, flanges, buckle arrestors, couplings etc.; transported fluids; marine growth; buoyancy.
The weight loads shall be determined based on the nominal dimensions of the pipeline system components, except for fluid where maximum values shall be used. Concrete weight coatings may absorb water, and this shall be considered. 6.2.2
Pressure loads The riser pressure design shall be based on the internal design pressure. Cyclic variations in pressure may induce fatigue, and this shall be considered.
6.2.3
Thermal loads Thermal expansion or contraction loads induced in the pipeline/riser system by virtue of full or partial restraint of pipeline/riser movement shall be considered during the analysis.
6.2.4
Residual loads Residual loads are loads left in the pipeline system after installation, and include: • residual axial loads (such as lay tension); • loads due to curvature at direction changes in the pipeline route; and • loads induced by vertical curvature due to the seabed undulations along the pipeline route. Any permanent curvature or elongation produced during installation that results in residual loads should be taken into account.
6.2.5
Dynamic loads Dynamic loads induced as a direct result of the operation of the pipeline system may have an effect on the structural strength of the pipe and its supports. The riser analysis shall include dynamic loads resulting from slugging and pigging operations. Surge pressures occur when liquid flow is suddenly stopped or slowed, for example by the sudden closure of a valve.
6.2.6
Support reaction loads Shear forces, axial forces and bending moments will be introduced into the pipeline system by supports which displace or constrain the riser, and shall be included in the riser analysis. Substructure displacements as the result of storm loading and settlement fall into this category of loading. Possible scouring underneath the bottom riser bend and tie-in spool should also be considered as well as any ESD valves and associated pipework when determining the deadweight support loading.
6.2.7
Hydrodynamic loads Hydrodynamic loads are caused by the movement of water particles past and around a submerged object. The water particle movement is caused by currents and wave action. Consideration should be taken of the following factors when determining the hydrodynamic loads: • selection and applicability of wave theories with regard to water depth; • selection of the appropriate steady current profile for combination with the wave current profile; • breaking waves in shallow water; • storm surges in steady currents; • selection of appropriate drag, lift and inertia coefficients; • determination of combined drag, lift and inertia forces with regard to phase angle; • velocity amplification around jacket members; • the use of maximum wave data, not significant wave data; • the use of irregular sea-state data.
6.2.8
Wind loads Wind loading on sections of a riser above sea level shall be considered. The effects on wind load due to the proximity of other risers or structural members shall be considered. Vortex shedding excitation of the riser from wind loading and disturbances to the flow field from change in wind speed or dynamic excitation of members adjacent to the riser shall also be considered.
6.2.9
Seismic load If seismic loads are taken into account in the platform design, they should be taken into account in the riser design.
6.2.10
Ice loads The loads associated with the formation of ice on the riser or the passage of pack ice past the riser shall be considered, if appropriate.
6.3
LOAD CASES The riser analysis shall consider at least three load cases, as follows:
6.3.1
Load case 1 - Installation loads This load case shall consider the entire installation sequence, namely: • onshore riser handling; • load-out; • jacket upending, stalking-on or retrofitting. Loads considered shall be combined as appropriate and include: • weight and buoyancy loads; • hydrodynamic loads appropriate to the phase of work; • dynamic loads due to vessel motions.
6.3.2
Load case 2 - Hydrotest This load case covers the onshore and offshore hydrotests and includes loads due to: • • • • •
6.3.3
weight; pressure; thermal effects (if any); residual loads (if any); support reactions, and hydrodynamic loads appropriate to the period of the test.
Load case 3 - Operational This load case covers the operation of the riser and includes the following types of load: • • • • • • • • • •
weight and buoyancy; pressure; thermal; residual; dynamic; support reaction; hydrodynamic; wind; seismic; ice.
NOTE:
The combination of loads that produces the highest stresses at one point may not be the same combination that produces the highest stresses at another point (e.g. different wave directions and phase).
6.4
WALL THICKNESS DETERMINATION The riser wall thickness required for pressure containment shall be determined in accordance with PTS 31.40.00.10 An internal and external corrosion allowance shall be determined and added to the wall thickness required for pressure containment. An allowance for thinning during the bending process shall be added to the riser bend wall thickness. The wall thickness may not be governed by pressure containment and consideration shall be given to the following: • adoption of a single wall thickness for riser bends and straights; • the use of a non-standard outside diameter, in order to achieve a constant internal diameter along the pipeline system; • the addition of an allowance for mechanical damage to the riser such as gouging by cables; • the increase of the wall thickness for ease of installation and to increase the spacing between supports.
6.5
PIPELINE EXPANSION
6.5.1
General The design of the pipeline and riser system shall consider the pipeline expansion due to the effects of temperature and pressure. If pipeline expansion results in loads and stresses that exceed acceptable limits, an expansion loop or other method of reducing the expansion effects shall be provided.
6.5.2
Expansion analysis considerations The pipeline expansion due to temperature and pressure shall be determined for the following phases: • operation; • hydrotest. The pipeline expansion analysis shall consider both the functional loading and the resulting loads due to restraint. The functional loading should consider the loads due to the following: • temperature; • pressure; • self weight (including weight of steel, coating, attachments, components, contents and marine growth); • configuration. The restraining loads should consider the reactions due to the following: • • • • •
pipe seabed friction; trenching and backfilling; riser or platform tie-in spoolpiece; subsea facilities such as subsea safety valves; anchors (such as rock dumping).
The expansion analysis should consider the maximum expansion mechanism resulting from the minimum friction coefficient. Pipeline expansions derived for both maximum operational conditions and hydrotest conditions shall be based upon an appropriate pipe soil friction coefficient to determine the critical design loading. Where a thin layer of soil with a high friction coefficient overlays one
with a much lower coefficient, consideration should be given to possible pipeline settlement into the seabed from repeated expansion and contraction movements. For a buried pipeline, the frictional restraint of the soil overburden may be included as part of the restraining seabed resistance. The design should give consideration of the uncertainties inherent in this method of placement. The pipe soil friction coefficients normally include a range of coefficients for various pipe roughness and soil properties. The design shall include the effects of potential seabed scour on pipeline expansion. Changes in pipe wall thickness and/or weight coating thickness, and any discontinuities in pressure or temperature such as may be found at a valve station, shall be taken into consideration together with the pipeline length when determining the pipeline expansion. 6.5.3
Expansion control methods Pipelines at platforms have the potential to expand towards the platform. When the amount of pipeline expansion and the corresponding load on the riser exceeds the allowable riser loading, then some form of pipeline expansion control shall be incorporated in the design. In general, the control of pipeline expansion on the riser is achieved by either restraining the pipeline and forcing expansion away from the platform or by incorporating an expansion-absorbing mechanism. The restraining of pipelines near the riser may be achieved by the following methods: • • • • •
rock dumping; trenching and backfilling; increasing the pipeline submerged weight; axial anchoring; apply high-friction coating to low-friction-coated flowlines.
Pipeline expansion-absorbing mechanisms may include the following: • provision for riser flexibility; • expansion loop; • flexible pipe. 6.6
EXPANSION LOOP Pipeline expansion should be accommodated by flexibility in the bottom of the riser. If the pipeline expansion is such that the pipe and riser termination cannot accommodate the expansion load, an expansion loop shall be provided. The spool shall be made as compact as possible for ease of installation. The expansion loop shall be designed to accommodate the maximum pipeline expansion from either operation or hydrotest conditions, without applying unacceptable loads or stresses to the pipeline, riser or subsea structure. Flanges shall avoid locations subject to high bending loads. The maximum stress in the expansion loop and the maximum loads on the riser or subsea structure shall be determined using conservative values of lateral friction coefficients at the expansion loop. The environmental loads shall be applied to the expansion loop design in combination with maximum operational and hydrotest functional loading conditions. The wave crest shall be positioned to give maximum loading on the expansion loop and four wave directions shall be considered. Considerations shall be given to potential scour around a platform or subsea structure and the effect on the expansion loop design.
Consideration shall also be given to vortex shedding criteria for any pipe span between the bottom riser support and the pipe touchdown point on the seabed. As it is necessary for the spool to move relatively freely, local lateral stability under environmental loading may not be achieved. If the spool is unstable, the maximum lift force acting on the spool should be less than the submerged weight of the spool. A spool which is either trenched or partially buried will experience a lower hydrodynamic force than when exposed on the seabed. The design shall consider the effect of this shielding. The stability of a subsea pipeline is dependent on the stability of the soil on which it is placed. If the seabed is unstable then the pipeline will become unstable with it. The stability of the seabed shall therefore be considered in addition to the stability of the pipeline. If there is evidence that the seabed becomes mobile in storm conditions, the depth of the unstable soil below the seabed should be determined. The stability design should assume that the pipeline is only buried to the depth by which the pipeline embeds in stable soil, and not the embedment depth of the original undisturbed seabed. A more extreme possibility in sandy soils of low density is that the soil near the seabed may liquefy under extreme storm conditions. The excess pore pressures within the soil may become equal to the confining pressures on the soil, resulting in zero effective stress and zero soil strength. If this occurs, there is the possibility of severe instability coupled with settlement of the pipeline. The possibility of soil liquefaction shall be assessed where appropriate, or where there is evidence of the phenomenon occurring. 6.7
RISER STRUCTURAL ANALYSIS Detailed strength analysis of risers shall be carried out using a validated finite-element computer program. The computer model shall include the expansion offset, the riser up the jacket and riser-associated piping on the deck, up to and including the pig traps. The pipe system shall be modelled using pipe and elbow elements. Node spacing shall be carefully selected to provide adequate stress output summaries of critical locations (i.e. pipeline elbow). The riser guides and supports shall be modelled by applying restraints to the model with the required degrees of freedom. The thermal offset/soil friction interaction is complex and will be modelled by springs for small movements of the spool, or forces for larger movements of the spool. If overstressing due to hydrodynamic loads is predicted, then one or more of the following should be adopted: • • • •
6.8
relocation of clamps; use of additional clamps; increase in riser pipe material grade and/or wall thickness; use of anti-fouling coating and/or cleaning systems to reduce marine growth.
ALLOWABLE STRESSES Stresses shall be evaluated in accordance with PTS 31.40.00.10
6.9
ALLOWABLE STRAINS A riser shall be so designed that it remains elastic under any combination of functional and environmental loads. Allowable strain design is not allowed for risers, except for allowable bending strain during the installation of a J-tube riser.
6.10
OVALISATION The riser design shall ensure that pipe ovalisation, F, does not exceed 2.5%. where: F=
(D max − D min ) x (D max + D min )
100
and: F
=
Ovalisation
Dmax
=
maximum OD
Dmin
=
minimum OD
The design shall consider ovalisation that results from pipe manufacture, external pressure and pipe bending. 6.11
COLLAPSE The riser design shall ensure the pipe is not subject to collapse/local buckling under any of the load cases. Collapse results from excessive external pressure and/or pipe bending. Appropriate safety factors against collapse are given in DnV Rules for Submarine Pipelines. Note:
6.12
Specialist advice should be sought when using cold-expanded linepipe as the DnV Rules underestimate the effect of residual stresses.
VORTEX SHEDDING The riser and clamping/support arrangement shall be designed so that significant crossflow vortex-induced vibrations do not occur. Analysis of vortex-induced vibration shall be based on natural frequencies calculated in the course of the structural analysis of the riser as a whole. The analysis shall take account of interaction with nearby structural elements and other risers. If it is not possible to eliminate in-line vortex-induced vibration by design, then a fatigue analysis shall be performed to demonstrate an acceptable fatigue life.
6.13
FATIGUE The fatigue analysis shall consider fatigue damage from cyclic loadings due to pressure, temperature, waves and vortex-induced vibration. The riser pipe shall have a fatigue life of at least 10 (ten) times the intended service life. Conservatively, six shutdown and start-up cycles per year shall be assumed when assessing the fatigue life of risers.
7.
RISER SUPPORT DESIGN
7.1
RISER SUPPORT TYPES Riser supports are normally one of the following types: Guide clamp This type of riser clamp restrains the riser from movements perpendicular to its axis whilst allowing rotation and axial movement (see Figure 1). Deadweight support clamp This type of clamp supports the deadweight of the riser whilst allowing rotational and axial movement depending on its detailed design. Axial movement of the riser is restricted downwards only (see Figure 2). Anchor clamp An anchor clamp fixes the riser at the location of the support in all directions and prevents rotation, including torque (see Figure 3). Anchor clamps can either be fabricated from steel plate and welded to the riser by means of a doubler plate and circumferential fillet welds, or they can be manufactured as a fitting similar to a flange and welded into the riser string by means of full penetration welds. The former type of anchor clamp is most common due to its ease of fabrication. The latter integral type of anchor clamp is used where riser loads are particularly high. Topsides support The topsides supports are designed by others and fall outside the scope of this PTS. Special support Other types of support are used in cases where the required riser restraints differ from those indicated above. A riser guide permitting the movement of the riser in the direction of the pipeline expansion is an example of a special clamp.
7.2
DESIGN CONSIDERATIONS Riser support types shall be selected and the supports designed to provide the riser restraint and movement requirements determined from the riser strength analysis. Where possible, riser supports shall not be located in the splash zone. Except for the integral riser anchor flange, riser supports shall be designed and fabricated in accordance with the structural design rules for the structure. The integral anchor flange shall be in accordance with ASME VIII. The fabricated anchor flange shall make use of doubler plates welded to the riser with circumferential fillet welds. Riser supports shall be designed without large stress concentrations particularly when subjected to fluctuating loading. The possibility of fatigue damage of supports shall be examined and, if necessary, a fatigue analysis carried out to confirm adequate fatigue life and possible requirements for inspection for fatigue damage. Combined stresses should not exceed 0.6 SMYS. Bolts shall be designed for pre-tensioning to give a maximum allowable stress of 50% of SMYS. Access shall be provided for the use of hydraulic bolt-tensioning equipment. Bolts shall be of sufficient length for the use of hydraulic bolt-tensioning equipment and nuts shall be provided with pre-drilled holes for the use of a “Tommy bar” for bolt rotation. All bolts of a support should have the same diameter. Correctly tensioned bolts minimise fluctuating stresses under cyclic loading and therefore improve fatigue performance and reduce the de-stressing tendency of the bolt. Supports shall be designed to facilitate their installation and that of the risers.
For retrofit risers, specific attention shall be given to the requirement for position adjustment of supports to enable a stress-free riser installation. The required adjustment shall be determined taking into account the following tolerances and accuracies: • • • • • • •
dimensional accuracy of as-built drawings; dimensional accuracy of measurements by divers; alignment accuracy of installed clamps; clamp closure tolerance; misalignment adjustment tolerance; riser fabrication dimensional control accuracy; riser transport and handling effect on dimensional variation.
At least 250 mm of adjustment should be provided in the riser clamp design in order to accommodate the stack-up of tolerances. See (Figure 4) for configuration of clamp with complete freedom of adjustment. The design of riser guides shall also comply with the following requirements: -
7.3
the inside of the guide shall be provided with a ribbed polychloroprene liner vulcanised to the guide body; the inside diameter of the lined riser guide shall be determined such that the riser can move in its axial direction without significant restraint; risers coated with a polychloroprene coating at the location of riser guides shall be provided with external Monel sheeting vulcanised to the riser coating over the length of the riser guide and 250 mm at both sides in the installed condition. The length of the Monel sheeting shall be sufficient to accommodate the requirement for adjustment of vertical riser position during installation.
LOADING CONDITIONS Supports shall be designed to resist the maximum loads from the risers, the support weight and environmental loads on the support. Riser loads on the supports during hydrotesting of the riser shall be taken into account when determining the support design loads. The supports and supporting structures shall be designed to resist the combined loads from the riser, environmental loads acting directly on the clamping structure and its weight for all riser design conditions.
7.4
CORROSION PROTECTION The corrosion protection of riser supports shall be in accordance with the substructure requirements, and is a function of the support location, namely, either above the splash zone, or in the splash zone or in the submerged zone. Riser supports above, or in, the splash zone shall be protected by a coating system in accordance with substructure specifications. The design of riser supports in the splash zone shall include a corrosion allowance based on the design life of the structure. Riser supports beneath the splash zone shall be protected by the substructure cathodic protection system and shall be coated in accordance with substructure requirements. Ribbed linings on the riser clamps shall be used to prevent shielding of the cathodic protection system. Electrical continuity straps between the substructure and retrofitted riser supports shall be used.
8.
J-TUBE DESIGN
8.1
DESIGN DATA The following data shall be provided in addition to the requirements of (5): -
8.2
pullhead weight, diameter and length; pull-in cable weight, diameter and maximum tension capacity; back-tension during pull-in of the riser.
J-TUBE ROUTING Routing of J-tubes shall take into account the following requirements and considerations: -
alignment tolerances of J-tube and the pull-in cable or riser; space and support need to be available above the J-tube for the riser hanger clamp; space and supports are required for the riser pull-in winch and routing of pull-in cable; the number of bends should be minimised; bend angles should be kept as small as is possible; for steel risers the bend radius shall be as large as possible. Radii should be typically 100 times the diameter and radii of less than 50 times the diameter shall not be used.
NOTE:
8.3
Reducing the number of bends and bend angle and increasing the bend radii will reduce the friction forces between riser and J-tube during pull-in and will lead to minimum pull-in and J-tube design loads.
J-TUBE SIZING AND RADIUS OF CURVATURE The internal diameter of the J-tube for steel risers should not be less than twice the diameter of the riser. The riser shall be capable of negotiating J-tube bends without exceeding maximum permissible strains or without collapsing, buckling or wrinkling. The combination of internal J-tube diameter, bend radius and bend angle shall be sufficient to accommodate the pull-head. NOTE:
8.4
Minimum values for J-tube wall thickness and radius may be governed by the allowable span requirement to prevent vortex-induced vibrations.
PULL-IN LOADS The pull-in of the riser up the J-tube shall be analysed step-by-step from entry of the pullhead into the bellmouth all the way up the J-tube using a validated riser pull-in program. This analysis shall provide the required pull-in loads, point loads on the J-tube and bending moments/strains induced in the riser. The following forces shall be taken into account when calculating required pull-in loads: -
back-tension during pull-in of the riser; forces necessary for the elastoplastic bending of a rigid riser; friction forces between the riser and the J-tube and friction forces between the pull-in cable and the J-tube; radial forces in the bend due to loss in tension force around the bend; bellmouth jamming forces; J-tube jamming forces, i.e. the load on the J-tube that would result if a pull-head got stuck, prior to the pull winch stopping.
Back-tension shall include the tension or residual tension in the riser from the laying operation and friction with the seabed. Predictions of the contribution of friction forces to the required pull-in loads shall be conservative. NOTE:
Frequently used coefficients of friction are as follows:
Coefficient of friction
8.5
riser and seabed
0.4 to 0.6
riser and inside of the J-tube wall
0.3 to 0.65
pull cable and the inside of the J-tube wall
0.2 to 0.4
STRUCTURAL DESIGN OF J-TUBE AND SUPPORTS J-tubes and their supports shall be designed and fabricated in accordance with the requirements for the platform structure. Particular attention shall be paid to the modelling of the loads at the contact points between the J-tube and the riser/pull-in cable. Supports shall be designed without large stress concentrations particularly when subjected to fluctuating loading. The possibility of fatigue damage of J-tube and riser shall be examined and, if necessary, a fatigue analysis carried out to confirm adequate fatigue life and possible requirements for inspection for fatigue damage. Buckling analysis shall be performed to investigate any possibility of buckling/collapse of the J-tube. Bar buckling of the J-tube compression shall also be prevented. Checks shall be performed on the buckling stability of the J-tube bends, both in-plane and out-of-plane, for the pull-in load case and for local buckling at the worst loaded area of the J-tube. J-tubes shall be designed and supported so that vortex-induced vibrations cannot occur.
8.6
APPURTENANCES
8.6.1
Bellmouth design The purpose of attaching a bellmouth to the J-tube bottom end is to ease the pull-in operation. The bellmouth acts as a guide for the pull-head into the J-tube, and should have an entry angle and height above the seabed (if any at all) which accommodate pull-in and lead to acceptable span lengths with respect to vortex shedding and column buckling criteria (if applicable). The bellmouth may also serve to reduce the stresses resulting from a minor change in orientation of pull-head and riser as they enter a J-tube. In case a seal bung (8.6.2) is to be used, the bellmouth design needs to be suitable for seal bung installation and operation. The bellmouth might also need J-tube flushing facilities for J-tube installation and/or for flushing the J-tube of seawater/inhibitor for corrosion protection purposes. The loading that the bellmouth may experience can be divided into two load cases, namely installation (pull-in) load case and the operational load case. a)
During installation, the bellmouth shall be able to sustain the reaction forces induced on the bellmouth from the pull force required to free a jammed pull-head. Bellmouths which are close to the J-tube bottom bend may form a contact point on the riser as it progresses around the bend. In these cases the bellmouth shall be designed to sustain these loads.
b)
During operation the loading on the bellmouth is very dependent on what type of restraints the seal bung (if any) puts on the pipeline riser. However, the following loading might have to be considered: -
-
-
Pipeline expansion: When the bellmouth structure acts as a clamp fixing the riser to the end of the J-tube, expansion movement of a pipeline on the seabed imposes a bending moment, axial loading and shear force at the bellmouth. Gravity: When the bellmouth acts as a fixed support for the pipeline as it spans the seabed or to a support structure, the submerged weight of the line causes bending and shear at the bellmouth. Environmental: Wave and current loading acting on the suspended section may induce shear and bending at the bellmouth.
-
Settlement: Differential settlement between platform and seabed may induce bending and shear at the bellmouth.
There are many bellmouth designs in existence and it is difficult to categorise them. The bellmouth layout is very much dependent on whether a seal bung for prevention of inhibited water diffusing into the seawater is going to be used or not, and if so, what type of seal bung. In some cases a seal bung is not required, and the messenger wire, preinstalled in the Jtube for installation purposes, needs only to be attached to the pull-head padeye outside the bellmouth to commence the pull-in operation. When installing a jacket structure it might be impractical to have heavy and long bellmouths attached to the J-tubes. In this case, the J-tube may end in a blind flange with the messenger wire attached to its inside. The bellmouth must then be flanged to the J-tube before the pull-in operation can start. (Figures 5A and 5B) illustrate these bellmouth concepts. 8.6.2
Seal design The primary objective of the seal bung is to isolate the void between the inside of the J-tube and the outside of the riser/pipeline from seawater. The riser/pipeline within the J-tube would experience accelerated corrosion if the line was open to the sea. To prevent this accelerated corrosion, this void is filled with inhibited seawater, or other suitable noncorrosive medium. Secondary considerations are the degree of restraint the bung applies to the riser/pipeline and the ability to flush the J-tube of seawater/inhibitor. The flushing consideration may not form part of the seal design. The seal is designed to prevent diffusion of the contents of the J-tube into the sea. In satisfying this task the seal must accommodate the following load conditions: a)
Pipeline axial movement The pipeline usually experiences high axial loads during operation which, if the line is unrestrained, will translate into axial movement. Should pipeline axial movement be experienced, then the seal can either permit the line to expand or prevent it from expanding. Should the seal permit line expansion, then it will prove difficult to provide a watertight seal suitable for a long design life. However, should the seal prevent line expansion, the seal will experience high axial loads.
b)
Hydrostatic pressure The seal may experience a pressure differential between the inside of the J-tube and outside of the tube. This differential pressure can be either positive or negative depending on the design. If the J-tube is filled with inhibited seawater up to the topsides, the pressure differential at the seal will be the hydrostatic head due to the height of water from sea level to the topsides. However, if the J-tube is gas filled, the pressure differential will be dependent on the pressure of the gas in the J-tube. If the gas pressure is topsides ambient pressure, the maximum differential pressure at the seal will be the hydrostatic pressure at the seal due to water depth. These scenarios are clearly illustrated in (Figure 6).
c)
Design life The seal should maintain its integrity over the design life of the J-tube, which can typically be 20 years. The seal material should not degrade due to seawater, J-tube fluid content or extended durations of high temperature (from the riser/pipeline).
There are many J-tube seal designs in existence, most of which can be placed into 5 different categories. These categories are: -
conical seals; inflatable seals;
-
rubber boot seals; bellow seals; integral plug/anchor seal.
Each type of seal is discussed with respect to their advantages and disadvantages during installation and operation. a)
Conical rubber seals Conical rubber seals are suitable for small-diameter lines where the expansion movement is low. The seal consists of a rubber sheath of varying cross-section which is bonded to the riser. This is usually fabricated on a short pup piece which is then added in place offshore. The riser shall be installed carefully so that the conical seal section is accurately positioned in the J-tube bellmouth. In some cases, an anchor flange is fitted to restrict the movement of the riser within the J-tube and to prevent damage to the seal. The limits of axial movement and misalignment during installation with which the seal can cope will depend upon the contact length of the seal. Typically, the maximum permissible misalignment or movement is ± 50 mm. The principal advantages of this type of seal are its low cost and ease of installation.
b)
Inflatable seals This type of seal consists of two toroidal inflatable seals. The seals are installed on the inner surface of the J-tube bellmouth. After the riser is pulled in, the seals can be inflated from the surface to close the annulus between the outside diameter of the riser and the inside diameter of the J-tube. The seals can provide a sufficient seal to withstand a differential pressure of typically 5 bar. Axial movement of the riser within the J-tube is accommodated by shearing of the toroidal seals. With larger expansions the riser may slip through the seals and cause damage to the elastomeric seal components. Therefore this system is typically limited to axial movement of ± 30 mm.
c)
Rubber boot seals One of the simplest methods of sealing a J-tube is using a rubber boot, which is installed in the J-tube bellmouth. Since the sheath is designed to fit the riser a tight fit should be achievable. However, the seal is susceptible to mechanical damage during installation and pull-in. The wear caused by the riser during pull-in can be uneven and render the seal useless. Once the riser is installed, it is not possible to replace these seals. If this type of seal can be installed correctly without suffering damage during installation the seals can withstand differential pressures up to 2 bar and an axial movement of up to 30 mm. This method lends itself to the use of a rubber sealing diaphragm, which permits the J-tube to be filled with corrosion inhibitor before the riser is pulled through. To pull the riser through, the diaphragm is punctured to allow the riser to pass into the J-tube. The ruptured diaphragm can form a seal, however an effective seal cannot be guaranteed.
d)
Bellow seals This is another simple method of sealing a J-tube by means of a rubber diaphragm. These seals come in two forms, integral diaphragms and zipped types. The integral diaphragms must be installed on the riser before the pull-in operation, hence a protective cover is usually required to ensure no damage occurs to it during pull-in. Should the diaphragm be damaged then it cannot be replaced with a similar seal. However, the zipper diaphragm is installed by use of a waterproof zip. This will allow installation subsequent to the riser pull-in and replacement of the whole seal if necessary. The seal between the riser/diaphragm and J-tube/diaphragm can be made in a number of ways. The simplest method is to use banding straps, however split flanges can also be used.
These seals allow greater axial movement compared to simple diaphragm seals and, by increasing the length of the sleeves, can cope with axial movement over half a metre. These types of seal are suitable for differential pressures of up to 2 bar. e)
Anchor type seal This type of seal is based on the same principle as the conical rubber seal, with the difference that the seal is kept in constant compression irrespective of the movements/loads in the riser. This is achieved by an anchor flange which is attached to the riser behind the conical seal. Two split flanges are attached behind the anchor and tightened to the bellmouth. This prevents the riser from moving at the bellmouth, so ensuring the integrity of the seal. As discussed, this system does not permit any axial movement of the riser, but can accommodate relatively high differential pressures.
8.6.3
Pull-head design The pull-head is an item which is attached to the end of the riser on one side and to the pull-wire on the other. The pull-head shall be designed to facilitate the pull-in operation and not cause damage to the J-tube or the riser. It must withstand the tension caused by the pull-wire and distribute the load to the riser so that these will not get damaged. It must be small enough to pass through the J-tube bends without any danger of its getting jammed, and incorporate any feature which results in a reduction in riser stresses and pull-in loads. These features are often incorporated by designing a curved pull-head body of hardened steel, see (Figure 7). The danger of the pull-head getting stuck in the J-tube bend may be easily checked by sketching to scale the J-tube bend with the pull-head inside it. The pull-head needs to be designed for the highest pull-load the system will experience during pull-in plus the additional safety factor required. This load may either come from the pull-in analysis or from a pull-head snagging analysis. Two pull-head designs are illustrated in (Figures 7A and 7B) and they are used for small (50 mm to 150 mm) and medium (150 mm to 500 mm) diameter rigid pipelines, respectively.
8.7
CORROSION PROTECTION The internal surface of the J-tube shall be protected against exposure to untreated seawater prior to riser pull-in by means of a blind flange that prevents the ingress of seawater. At the time of the riser pull-in the blind flange is removed and replaced with a bellmouth. A seal is fitted to the riser that blocks to the bottom of the J-tube. The J-tube is then filled with inhibited seawater to prevent corrosion of the internal surface of the J-tube or the riser. Provision for sampling the annular water shall be provided. The external surface of the J-tube shall be protected against corrosion in the same manner as a riser, see (10).
9.
FITTINGS
9.1
FLANGES Flanges shall comply with PTS 31.40.21.34 If bending moments, additional axial forces or shear forces occur at the location of the flange connection, a behaviour (including the gasket with regard to leaking), stress and bolting force analysis according to ASME VIII shall be carried out, taking into account all relevant loading situations for the flanged connection. For maintenance purposes, the operating manual for the pipeline system shall detail the flange installation procedures used including the equipment required, the bolt pre-tension forces to be applied and measurements to be made. Consideration shall be made for the provision of profiled flange protectors to prevent snagging by cables.
9.2
GASKETS The gasket shall be a ring type gasket in accordance with ASME B16.20 and shall be made of a material softer than the flange ring groove. The gasket material shall be chosen for compatibility with the flange material and for the service conditions. Consideration should be given to the use of ring joint inlays and corrosion-resistant materials for the gaskets. Consideration should also be given to the use of coatings on the gaskets to improve corrosion resistance.
9.3
BOLTING Bolting shall comply with PTS 30.10.02.11 Note:
The preferred materials for standard applications are ASTM A 193-B7 and ASTM A 194-2H for non-sour service conditions, and ASTM A 193-B7M and ASTM A194-2HM for sour service conditions. For special applications, e.g. low temperature, other materials may be required.
The bolt tension shall be calculated on the following basis: • the bolt tension shall not cause a stress in the bolt greater than 50% SMYS; • the relaxation of the bolt is a function of the method of tensioning and the coating on the bolt; • the bolt tension shall not lead to excessive yielding of the gasket; • the bolt tension shall be sufficient to ensure the gasket remains seated under the worst combination of tension, bending and bolt relaxation. The use of a low-friction coating for ease of tightening shall be considered. 9.4
VALVES Valves for offshore pipelines shall comply with API 6D. Submarine valves should not be included in offshore pipeline systems because of the difficulty of inspection and maintenance. To facilitate maintenance, valves shall be either flanged both ends or be of the top-entry type and be suitably mounted for ease of access. Piggability requirements shall be taken into account in the selection of valves.
9.5
BENDS All long-radius riser bends shall comply with PTS 31.40.20.33 Consideration should be given to the use of long tangents to provide cut material for fit-up offshore.
10.
RISER MATERIALS AND CORROSION PROTECTION
10.1
GENERAL The service conditions throughout the design life of the pipeline shall be established to permit the selection of suitable materials based on a technical and economical evaluation. The requirements for pipeline materials shall comply with PTS 31.40.00.10
10.2
LINEPIPE
Amended per Circular 16/02
Carbon steel linepipe shall comply with PTS 31.40.20.37 10.3
EXTERNAL COATING All risers including Duplex or austenitic steel pipelines shall be coated externally by a suitable anti-corrosion coating, supplemented by cathodic protection for the part of the system below the water level. The sections located within the spash zone shall be externally coated with a vulcanised polychloroprene (neoprene). Consideration should also be given to PE coating and Monel cladding. The section above the splash zone and the riser bends shall be coated with a glassflake epoxy coating system. Recent QRA studies have demonstrated the benefits of providing passive fire protection around the above-sea section of the riser, to prevent escalation due to flame impingement. This aspect should be considered during the design of new risers. External coating selection shall take account of the following proven temperature limitations of the available coating systems, unless otherwise agreed with the Principal: Table 10.1
Coating temperature limits
Coating System
Maximum continuous operating temperature (°C)
Maximum excursion temperature (°C)
Specification
Asphalt enamel
60
70
To be agreed with Principal
Fusion bonded epoxy
70
85
PTS 31.40.30.32
Polychloroprene
100
100
To be agreed with Principal
EPDM
105
105
To be agreed with Principal
Polyethylene and polypropylene
100
120
PTS 31.40.30.31
Coal tar enamel or coal tar epoxy coating systems shall not be used. Corrosion coating systems shall be in accordance with the PTSs listed in the above table or project-specific specifications. Field joint coating systems shall be compatible with and have good adhesion to the millapplied coating, and shall be stored and applied in accordance with the Manufacturer’s recommendations.
Thermal insulation materials and their properties shall only be selected in full consultation with the Principal, taking into account the long-term degradation of mechanical and thermal properties at operating conditions, such as service temperatures and (external hydrostatic) pressures. 10.4
CATHODIC PROTECTION Cathodic protection design and sacrificial anodes shall comply with PTS 30.10.73.32 Zinc anodes shall be specified and the system shall be designed such that operational temperatures of the anodes do not exceed 50 °C. Impressed current systems should not be used. To allow effective monitoring of the cathodic protection of risers and to minimise the risk of current drain from pipeline cathodic protection systems, submarine pipelines and risers shall be electrically isolated from platforms and onshore installations. For offshore pipelines isolating flanges are not acceptable and use shall be made of an appropriate type of prefabricated isolating joint, see PTS 31.40.21.31 Electrical isolation shall be ensured at all points of potential electrical contact, between the riser and the structure, below the isolating joint.
11.
MECHANICAL PROTECTION
11.1
PROTECTION FROM BOAT IMPACT To prevent boat impact, the locating of the riser on the inside of the jacket structure adjacent to a leg should be considered. Alternatively, a boat fender should be provided.
11.2
PROTECTION FROM DROPPED OBJECTS The frequency of damage caused by dropped objects shall be assessed, by means of specific drop zones and the probabilities of an object being dropped, of the object hitting the pipeline and of the pipeline sustaining damage. A consequence analysis shall be carried out and the results of this analysis shall be assessed against accepted risks. For any risks exceeding allowable levels, protection measures shall be designed. If the expansion loop configuration cannot avoid the platform loading areas or other potential dropped-object areas, consideration shall be given to the provision of protection covers to the expansion loop. The protection cover shall be designed to withstand the impact from the heaviest item transferred between the platform and supply vessels. Protection covers shall allow free movement of the expansion loop for maximum pipeline expansion. Consideration should be given to the method of installation of the protection covers to ensure that they are not a potential hazard to the expansion loop or to adjacent pipelines and structures. The covers should be designed to allow easy access and removal if required. Consideration shall be given to ensuring that the cathodic protection system provided for the expansion loop remains unaffected by the protection covers. Alternatively, where this is impractical or excessively costly, the hazard and risk should be evaluated on a quantitative basis as part of the overall risk to the installation. Appropriate action should be taken where necessary to reduce the risk to an acceptable level.
11.3
PROTECTION FROM SNAGGING LOADS Consideration should be given to preventing accidental snagging of the pipeline/tie-in spool and avoiding transfer of such loads to the riser system. The possibility of snagging may be mitigated by avoiding spanning in the pipeline and tiein/expansion spool and protecting the tie-in spool and pipeline end close to the platform by means of burial, rock dumping or covering with mattresses. This is particularly important if, for example, anchor cables are frequently deployed in the vicinity of the platform.
12.
INSTALLATION REQUIREMENTS
12.1
RISER INSTALLATION TOLERANCES The alignment of all the riser clamps shall be verified before riser installation. In cases where the riser is stalked into position, the position of the clamp shall be adjustable by approximately 250 mm in all directions.
12.2
INSTALLATION FEASIBILITY A procedure demonstrating the feasibility of the riser installation shall be prepared. The procedure shall demonstrate the following: • the riser installation vessel’s capacity is adequate (e.g. deck space, lift capacity, etc); • sufficient clearances are provided for the installation vessel; • flexibility is provided in the design to make allowance for possible seabed level variations; • clearance is provided to adjacent structures for the tie-in operations; • installation sequence is established including riser handling, up-ending, positioning and placing of the riser in the clamps; • the riser will not be overstressed during any stage of load-out and installation, including static and dynamic loadings; • minimised interference to platform operations.
12.3
CLEARANCE FOR HYPERBARIC WELDING If the expansion loop is to be connected to the riser by hyperbaric welding, sufficient clearance shall be maintained from any adjacent pipeline or structure (including the platform jacket and appurtenances e.g. mudmats and pile guides) to allow positioning of the hyperbaric welding chamber and associated handling frames.
12.4
CONSTRUCTION AIDS Consideration should be given to the installation of construction aids at the time of the jacket design. Construction aids for the installation of future risers, subsea tie-in to expansion loops, and hook-up to the topsides section of the riser should all be considered.
12.5
TEMPORARY CONSIDERATIONS Temporary protection and seafastening requirements should be considered for pre-installed risers in order to prevent damage during load-out, transportation, installation and setting of the platform. Temporary supports/fixings should also be considered for the installation operation. In order to minimise installation stresses within the riser, it may be necessary to provide knee bracing on the riser, usually at the bottom bend in order to support the protruding riser. After installation the knee bracing shall be completely removed in order to minimise operational stress levels. Consideration should be given to the temporary requirements for hydrotesting and precommissioning equipment.
13.
REQUIREMENTS FOR OPERATIONS AND MAINTENANCE The riser system should be designed with regard to future inspection, maintenance and repair. If intelligent pigs are to be used for internal inspection, bend radii shall meet the following requirements: Nominal pipe diameter, D, (mm)
Minimum bend radius
≤ 100
10 D
150 to 250
5D
≥ 300
3D
Additionally, if intelligent pigs are to be used, the pipeline internal diameter should ideally be constant throughout, including valves, flanges, tees and other fittings. Variations in internal diameter (Di) cannot always be avoided in local areas of limited length, e.g. pipeline equipment such as valves. If changes in Di occur at the location of equipment, pup pieces shall be used with a Di of the equipment. These pup pieces shall have tapers to the pipeline Di with at least a 14 degree transition angle, measured from the axis of the pipe (i.e. a taper of 1:4). Consideration should be given to the requirement for possible riser replacement, in the event this becomes necessary at some time during the life of the structure. If replacement is not possible, as for example with a gravity based structure, consideration should be given to the provision of a spare riser. As far as practicable, the risers should be located to enable easy access for inspection, maintenance and repair purposes. Consideration should be given to diver and remote operated vehicle access throughout the length of the riser. Riser supports should be avoided in the splash zone since they hinder inspection and may result in additional corrosion.
14.
DESIGN OUTPUT
14.1
GENERAL Documentation is produced at all stages during the life of a pipeline, from design to abandonment. All essential documentation should be retained, be accessible and be regularly updated, as required, throughout the life of the riser system.
14.2
DESIGN DOCUMENTATION On completion of the design activity, a detailed design report shall be issued. All tables, graphs, drawings and any references used during the design should be included within the report. Back-up calculations, though not necessarily included in the report, should be retained for reference and clarifications. The drawings prepared during the detailed design should be retained to form the basis for as-built documentation. The drawings should include, but not necessarily be limited to, the following: • Key plan of field arrangement; • Platform layout including: • • • •
platform crane locations and radii; loading areas; areas at risk from dropped objects; pipe supports.
Tie-ins and expansion spools - general arrangement and isometric drawings; Designated anchor areas; Platform approach details; Riser details including: - size (diameter, wall thickness); - coatings; - clamp details; - location and routing; - general arrangement and isometric drawings.
14.3
AS-BUILT DOCUMENTATION Upon completion of pipeline construction activities an as-built record of the riser system shall be made. The as-built record provides an official record of the installed riser system and includes such information as: • • • •
precise routing of the riser; riser details, i.e. material grade, wall thickness, coating, etc.; fittings installed on the riser, i.e. ESD valves, anodes, bends, etc.; clamp details.
The as-built records are essential information required by the riser system operator for future inspection and maintenance of the riser system.
15.
REFERENCES In this PTS reference is made to the following publications: NOTE:
Unless specifically designated by date, the latest edition of each publication shall be used together with any amendments/supplements/revisions thereto.
PETROANS STANDARDS Index to PTS publications and standard specifications
PTS 00.00.05.05
Metallic materials – selected standards
PTS 30.10.02.11
Design of CP systems for offshore pipelines
PTS 30.10.73.32
Pipeline engineering
PTS 31.40.00.10
Amended per Circular 16/02
Linepipe induction bends
PTS 31.40.20.33
Welded and seamless duplex and super duplex stainless steel linepipe
PTS 31.40.20.34
Linepipe for critical service (amendments/supplements to ISO 3183-3)
PTS 31.40.20.37
Pipeline isolating joints
PTS 31.40.21.31
Carbon and low alloy steel pipeline flanges for use in oil and gas operations
PTS 31.40.21.34
External polyethylene and polypropylene coating for linepipe
PTS 31.40.30.31
External fusion-bonded epoxy powder coating for linepipe
PTS 31.40.30.32
AMERICAN STANDARDS Pipeline valves
API 6D
Issued by: American Petroleum Institute Publications and Distribution Section 1220 L Street Northwest Washington DC. 20005 USA
ASME Boiler And Pressure Vessel Code: Section VIII: Rules for construction of pressure vessels
ASME VIII
Metallic gaskets for pipe flanges
ASME B16.20
Issued by: American Society of Mechanical Engineers 345 East 47th Street New York NY 10017 USA
Alloy-steel and stainless steel bolting materials for high-temperature service
ASTM A 193
Carbon and alloy-steel nuts for bolts for high-pressure and high-temperature service Issued by: American Society for Testing and Materials 1916 Race street Philadelphia PA 19103 USA
NORWEGIAN STANDARDS DnV rules for submarine pipeline systems Issued by: Det Norske Veritas P.O. Box 300 N-1322 Høvik Norway
ASTM A 194
APPENDIX 1
FIGURES
FIGURE 1
TYPICAL GUIDE CLAMP
Riser clamp
Jacket leg
Riser Hinge pin
Jacket sleeve
Bolts
FIGURE 2
TYPICAL DEADWEIGHT SUPPORT CLAMP
Sleeve welded to riser Anchor flange
Riser clamp
Jacket leg
Riser Hinge pin
Neoprene lining
Jacket sleeve
Bolts
Lifting lug
FIGURE 3
TYPICAL ANCHOR CLAMP
Circumferential fillet weld top and bottom
Doubler plate
Jacket leg
Jacket sleeve
Riser
FIGURE 4
TYPICAL CLAMP WITH COMPLETE FREEDOM FOR ADJUSTMENTS Adjustable stub piece
Riser
Jacket bracing
FIGURE 5
A:
B:
J-TUBE BELLMOUTHS
FIGURE 6
J-TUBE SEAL PRESSURE Hanger support
Pj
ρ
j
Hj Hs
Seal
Flowline
Bellmouth
PRESSURE OF SEAL
(
)
Ps = Pj + ρ j gH j − (ρ s gHs )
WHERE: Ps = Differential pressure at seal Pj = Gauge pressure at top of J-tube fluid ρj = Density of fluid in J-tube ρs = Density of sea water Hj = Height of top of J-tube fluid above seal Hs = Water depth of seal below mean sea level
FIGURE 7
TYPICAL PULL-HEADS
Lifting lug, to be connected to a shackle
Circular plate bevelled to give smooth profile
Reducer
Riser/pipeline
A:
Side elevation of typical pull-head for small diameter pipelines (50 mm to 150 mm)
To spelter socket
Pull-head
To pull-head
Spelter socket B:
Pull-head for medium size pipelines (150 mm to 500 mm)
