DESIGN OF OFFSHORE OFFSHORE PIPELINES PIPEL INES Mec h an i c al Des i g n
Presentation Reference Number Here
PIPE PIPEL L INE INE MECH MECHA A NICA NICAL L DESI DESIGN GN
Topics Pipeline Design •
Code compliance
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Desi esign to resi esist inte intern rnal al pres pressu sure re
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Long Longit itud udin inal al,, ben bendi ding ng & com combi bine ned d str stres esse ses s
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Desi esign to resis esistt ext exter erna nall pr pressu essurre
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Buckling
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Fittings
Riser Desi Design gn •
Types of riser
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Pipeline to to ri riser tie-ins
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Riser iser and and exp expan ansi sion on spool pool mode modellling ling
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Load co conditions ons & combinations
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Fatigue
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Riser supports
Cod ode e Com ompl pliance iance • DnV OS F101: Rule ul es for fo r Subma ub mari rine ne Pipe ip eline li nes s • AS A S 2885 : Pip Pi p eli el i n es - Gas and an d L i q u i d Petr Pet r o l eum eu m • ANSI/A A NSI/ASME SME B 31.4 : A SME Cod Co d e f o r Pres Pr ess sure (Liqui uid d Petr Petrol oleu eum m Tran Transp spor orta tati tion on)) Piping iping Systems ystems (Liq • ANSI/A A NSI/ASME SME B 31.8 : A SME Cod Co d e f o r Pres Pr ess sure Transm smis issi sion on & Dist Distri ribu buti tion on)) Piping ip ing Sys yste tems ms (Gas Tran • B S 8010 : Co d e o f Pr ac t i c e f o r Pi p el i n es Par t 3 • API A PI RP1111 : Reco Rec o m m end en d ed Prac Pr actt i c e f o r Desi Des i g n , Construction, Operation & Maintenance of Offshore Hydr Hydroc ocar arbo bon n Pi Pipe peliline nes s
Types of Loads • functional loads (actions resulting from the operation of the pipeline); e.g. internal and external pressure, invariant loads. • environmental loads (normal actions from the natural environment); e.g. hydrodynamic forces from currents and waves – variable forces. • accidental loads (infrequent actions due to natural hazards or third party influence); e.g. dropped objects, fishing interaction. • installation loads (actions incurred during construction of the pipeline); e.g. pipelay stresses.
ASD vs LRFD •
ASD = Allowable Stress Design – generally based on limiting stresses in a pipeline to less than a prescribed limit.
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LRFD = Load and Resistance Factor Design – determine loads on pipeline and factor, and ability of pipeline to resist those loads without failing and factor. Factors dependant on risk and confidence of load / resistance prediction.
Limit States •
Serviceability Limit State • ovalisation/ ratcheting limit state • accumulated plastic strain and strain ageing • large displacements • damage due to, or loss of, weight coating.
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Ultimate Limit State • bursting limit state • ovalisation/ratcheting limit state (if causing total failure) • local buckling limit state (pipe wall buckling limit state) • global buckling limit state (normally for load-controlled condition)
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Fatigue • unstable fracture and plastic collapse limit state
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Accidental • Impact.
Risk Approach – OS F101
Pressure Containment • In essence, all variations on Barlow’s formula • Diameter based on hydraulic analysis • Minimum external pressure • Safety factor based on code • Maximum internal pressure
Pressure Containment Additional Considerations • Material grade • Wall thickness tolerance • corrosion allowance • temperature derating factors
Pipeline Stress – Simple Approach
Pipeline stress considered biaxial • hoop stress around circumference (as used for wall thickness sizing • longitudinal stress along axis
Longitudinal Pipeline Stresses • Pressure • Temperature • Bending • Residual tension (difficult to quantify and often ignored)
Longitudinal Stress • Pressure Stress • Two effects dependent on pipeline axial restraint • Full axial restraint gives poissons effect of hoop stress • Completely unrestrained gives “end cap” effect
• Poissons effect • Hoop stress creates circumferential (lateral) strain • Poissons ratio = lateral strain/longitudinal strain = 0.3 for steel • lf restrained pipe cannot contract - tensile stress developed • Poissons longitudinal stress = 0.3 x Hoop Stress
Pressure Stress
Endcap Pressure Stress • unrestrained (near expansion spool) • pressure differential acting over internal CSA or equivalent pipe end (hence “end cap”) • longitudinal tensile stress = 0.5 x Hoop Stress
Temperature Stress • Dependent upon axial pipeline restraint • Stresses developed when expansion or contraction are prevented • 3 cases : unrestrained, partially restrained, fully restrained • unrestrained - no stress due to temperature • partially restrained - equilibrium between expansion and friction restraint (section of pipe which expands) • fully restrained when friction force = fully restrained force ie no movement
Temperature Stress • Longitudinal stress is as follows :
• e.g 6-inch x 14.3mm wt 60 degrees above ambient results in a stress of 145 N/mm2 • full restraint force = 1017 kN or 100 tonnes • to prevent expansion this restraining force would be required • Generally better to avoid restraining pipe if possible
Bending Stress • Lay radius curvature • Resting on irregular seabed • Spanning (includes environmental loads) • Bending within elastic range, formulae as follows :
• Bending is tensile and compressive about neutral axis - important to remember when calculating combined stress ie 2 possible values of longitudinal stress
Combined Stresses
• Von Mises ( maximum distortion energy theory) • design factor for combined equivalent pipeline stress can be as high as 0.96 for functional and environmental loads • Von Mises Stress,
given by:
LC and DC Conditions •
Load controlled - additional load results in additional displacement – e.g. cantilever.
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Displacement controlled – curvature is imposed on the pipe rather than a load – e.g. pipe on a reel. Considers non-linear material properties.
Local Buckling •
LRFD equivalent to combined stress limit approach.
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Alternatives for load and displacement controlled conditions.
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Alternatives also for internal or external overpressure.
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Highly dependant on bending load.
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More likely during installation when no internal pressure.
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For thick wall pipes, strains in excess of yield may be demonstrated to be acceptable in displacement controlled situations.
Collapse and Propagation Two other buckling scenarios to consider : • collapse - water depth where collapse can occur with negligible bending load. • propagation - water depth where a previously initiated buckle would propagate to. • Pipelines always sized for collapse (Bluestream). • Buckle propagation can be prevented by buckle arrestors (thicker section of pipe) at regular spacing (e.g. 200m). Collapse pressure (pressure required to collapse a pipeline) Is greater than
Initiation pressure (pressure required to start a propagating buckle from a given buckle) Is greater than
Propagating pressure (pressure required to continue a propagating buckle).
Buckling & Collapse
Pipeline Fittings Typical pipe fittings : • Flanges • Bends • Tees • Wye piece
Flanges •
Subsea use high integrity ring type joints (RTJ)
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Pipelines usually use standard ASME/ANSI B16.5
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Wellhead equipment use standard API
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For subsea use swivel ring and possibly misalignment flanges required
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Subsea flanges are critical link - if leakage occurs very expensive to rectify
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Code does not allow for external moment loads ie if design pressure = flange allowable pressure no moment capacity exists. Often need to go up a class to cater for moments.
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Bolting normally performed using accurate hydraulic tensioning tool. Bolt load critical - too little and leakage may occur too much and flange overstress/distortion problems.
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Many compact flange and other connector designs available.
Flanges, Cont
Bends • Elbows generally to ANSI/ASME 16.9 • Pipelines usually require pigging - elbows not suitable • Bend radius = 3D or 5D • Utilise bends at expansion loops between pipeline and facility • Ability to deform and flatten - curved pipe is more flexible & has higher bending stresses • Addressed by flexibility & stress intensification factors (SIF) - ANSI B31.3 • Flexibility and SIF depends on pipe id. & wt and bend radius - can be very significant
Tees Tees • Standard branch tees to ANSI B16.9 • Barred tees for pigging implications • Flexibility and SIF implications as per bends (ANSI B31.3) - can have high stress at branch connections • Not suitable for inspection pigs •
increase flowline flexibility (future tie-ins)
• Valve skid & protection structure required etc. • CAPEX implications may be high for hot-tap tees reduced if installed in the mainline during pipelay
Wye Pieces Wye Pieces • Allows pigging of mainline and branch - correct geometry is critical • Typically a symmetrical branch arrangement with 30 degrees between branches • Large radius of curvature (greater than 3D) between branch and main line • Non standard items ie no standard specifications • Complex 3D geometry - pipe codes not applicable • Design to pressure vessel code using 3 dimensional solid model finite element techniques
Wye Pieces Wyes • Design in accordance with pressure vessel code • Typically BS 5500 or ANSI/ASME VIII • Complexity due to code break at interface with pipe • Pressure vessel codes deal with discontinuity's and stress concentrations - pipeline codes inadequate in this respect.
Pipeline Expansion Analysis
Expansion Governed by • Temperature • Pressure • Pipe weight • Friction (coefficient assumed conservatively low, say 0.3, in analysis)
Expansion loops generally provided at hot end of pipeline to allow for expansion.
Pipeline Expansion Movement
RISER MECHANICAL DESIGN
Risers Risers connect topsides facility with pipeline expansion spool (where required). Pipeline to riser tie-ins: • deal with pipeline expansion. • allow practical pipeline approaches. • Generally a rigid steel ‘L’ or ‘Z’ spool. • some smaller diameter flowlines use flexible pipe.
Analysis of Tie-in Spool & Riser • Computer model used for accurate assessment • Tie-in spool and riser should be modelled as one item from pipeline end to top of riser • Pipeline expansion applied to spoolpiece end • Dropped object protection may be required (concrete mattresses) consider in computer model
Riser Design Major location requirements (Routing) • pipeline approach • topside layout • minimise number of risers (weak link) • locate for least exposure to potential damage (e.g. preferably inboard at water level and away from boat landing) • locate as far as practical from living quarters • provide access for inspection & maintenance • gas risers have location preference over oil risers • installation philosophy - pre-installed or retrofitted
Specific Design Loading Conditions Basic Loads for load combinations • loads imposed on riser via supports from platform • loads due to interaction with topsides piping • loads due to interaction with pipeline • loads due to weight and buoyancy effects • loads due to environmental conditions • loads due to pressure of contents • loads due to thermal effects • loads during transient operation - slugging, pigging. • Loads from vortex shedding (fatigue)
Typical Load Combinations • Refer to codes for guidance • Analysis performed using computer models • LC1- functional loads only • LC2- maximum storm and functional loads as they occur during storm • LC3- as LC2 with loads during installation and/ or test • LC4- wave loading for fatigue life evaluation may include vortex shedding induced vibrations • LC5- accidental loading (may be in conjunction with other loads, generally higher allowable stress)
Riser Fatigue Riser should be analysed to determine fatigue life. Variations in stress level may occur due to : • load cycles • wind & wave action • platform movements • vortex induced vibration • fatigue life should be 3.3 times design life or, if inspection is not possible, 10 times design life
Riser Guide & Clamp Design •
provide support and transfer riser load to platform
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critical to the safe working of the system
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guides allow axial movement through the support
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clamps restrain laterally and axially
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deadload clamp used to support weight of riser
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dimensional control critical for retrofitted risers
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designed in accordance with structural codes
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similar load cases and combinations to risers
FREE-SPANNING
Introduction
• Spans arise from rough seabed or scour • Long lengths may cause unacceptable pipe loads at support locations, particularly for hard seabed conditions • Fatigue from movement under environmental and operating loads • Snagging by trawlers/anchors • Buckling from inline and pressure loads (can be beneficial if self limiting)
Prediction of Spanning • From route survey - prediction of pipeline profile on seabed – Packages available to predict pipe loads • Span acceptance limits for VIV calculated separately • After installation / during operation – Surveys
Route Preparation • Pre-sweeping - capping the height of sandwaves • use of hydraulic tools is effective
• Blasting rock peaks • interbedded calcarenite is energy absorbent • difficult to shatter more than a few layers at a time
• Pre-lay supports • Wide enough to allow for pipelay tolerance • Can provide issues following lay for trenching etc.
Route Preparation cont. •
Predumping of rock in rough areas • controlled rock dumping in rough areas • stability issue must still be addressed
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Pretrenching - normally in shore approaches • cutter suction dredge or backhoe most common • weather sensitive and depth dependent
Pre-sweeping
Span Rectification – Post-lay • Supports • Grout bag: should be tailor made, coat sack types tend not to last • Scour around grout bag type supports may undermine them • Adjustable mechanical: for rocky areas - long term performance
