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Materials and Design of High Strength Pipelines

Yong Bai

Stavanger University College, Stavanger, NorwayGerhard Knauf

MFI (Mannesmann Forschungsinstitut), Duisburg, Germany Hans-Georg Hillenbrand Europipe, Ratingen, Germany

ABSTRACT

The demand for high-strength linepipe for offshore applications hasincreased considerably because of the challenges that the offshorepipelines should be contracted in ever-deeper waters and that forreasons of reducing operational costs pipelines should be operatedat increased pressures. The development of new steels andimproved pipe manufacturing capabilities enable high strengthlinepipe with appropriate toughness to be supplied.

In this paper, the following subjects related to the use of highstrength linepipe are discussed:

• Materials properties

• Evaluation of the use of high strength steel from design

viewpoints;• Assessment of loading conditions for installation and in-

service conditions;

• Development of additional design criteria for the subjectsnot covered by codes, e.g. strength design of linepipes withyield anisotropy.

The paper describes practical considerations on material properties,design loads, code requirements and concludes with thedevelopments in design criteria for strength design of high strengthpipes with yield anisotropy.

KEYWORDS: Linepipe, Materials, Design, High Strength,

Pipeline

INTRODUCTION

The demand for high-strength linepipe for offshore applications hasincreased considerably because of the challenges that the offshorepipelines should be constructed in ever-deeper waters and that forreasons of reducing operational costs pipelines should be operatedat increased pressures. The development of new steels and

improved pipe manufacturing capabilities enable high strengthlinepipe with appropriate toughness to be supplied.

These developments cover linepipe for both sour and non-sourservice. The materials under consideration are grades X70 and X80for non-sour service and grades X65 and X70 with a wall thicknessof up to 40 mm for sour service.

Apart from structural strength, key considerations are:

• Toughness of parent linepipe material and all welded joints;

• Corrosion performance of lines that operate ‘wet’;

• Weldability, including repairs and hyperbaric requirements;

• Compatibility with external environment;

• Availability of bends and fittings required to complete apiping system;

• Suitability for operational modifications repairs and hot taps;

• Cost.

In this paper, materials properties and practical designconsiderations will be given. The anisotropy with respect to tensileproperties of linepipe and longitudinal and hoop design loads willbe discussed for S- and J-laid pipelines. Existing codes have beenevaluated and areas of improvement have been identified. Finally,an analytical capacity equation is outlined to design pipe with yieldanisotropy.

MATERIAL PROPERTIES OF HIGH STRENGTH

LINEPIPE

The desire to increase the through-put by increasing the operatingpressure or by increasing the usage factor has led to ever increasingdemands for large-diameter steel pipe. These requirements refer inparticular to strength properties and tolerances on dimensions. Atthe same time, it is endeavored not to compromise on operationalsafety and even to improve it, where possible.

Thanks to the intensive research and development work carried outand the quality assurance measures consistently implemented inpipe production, it has been possible so far to meet therequirements placed by the market.


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However, the limits of physical and technical feasibility havealmost been reached when producing high strength pipe that canmeet the ever-increasing requirements. As the strength increases, itbecomes extremely difficult, if not impossible to achieve thespecified limits for the yield-to-tensile ratio or to fulfill increasedtoughness requirements.

In addition to the tensile properties in the transverse direction, thetensile properties in the longitudinal direction of the pipe play a

crucial role in the context of offshore pipelines. This fact has beentaken into account in the usual offshore pipeline codes in that thevalues specified for yield and tensile strength for the longitudinaldirection are the same as those specified for the transversedirection. So far, the anisotropy with respect to the strengthproperties of the pipe produced by the UOE method has not beentaken into account adequately in the codes.

Figure 1 shows schematically the yield and tensile strengthfrequency distribution curves for the transverse and longitudinaldirections for plate and pipe. Because of the elongation of themicrostructure in the rolling direction, the yield and tensile strengthvalues for the longitudinal direction are lower than those for thetransverse direction.

Figure 1. Comparison of strength distributions for plate and pipespecimens in transverse and longitudinal direction.

As a result of the pipe forming and subsequent cold expanding,there is a marginal increase in the tensile strength for bothdirections and in yield strength for the longitudinal direction. Incontrast, the yield strength of the transverse, flattened stripspecimen is reduced. Comparison of these data with those for theround bar specimen indicates that the reduction of the yieldstrength in the case of the strip specimen can be attributed to theBauschinger effect resulting from the flattening operation of the

specimen prior to the tensile test.

The anisotropy described and its development in the course of pipeforming is typical of standard pipe and depends on the materialgrade, chemical composition and pipe geometry. This dependencyis readily seen in the case of low carbon sour service grades.

Figure 2 shows, by way of example, the distribution curvesdetermined on a production lot of grade X65 pipe intended for sourservice. As can be seen, the distributions for the transversespecimens are shifted to the right relative to those for the

longitudinal specimens. It had been necessary to optimize therolling process to raise the strength values for the transversespecimens so that the tensile requirements specified for thetransverse specimens are also met by the longitudinal specimens.

Figure 2. Results on 610 mm OD x 14.3 mm W.T. X65

production linepipe for sour service (PH3).

Such measures adopted to compensate for the anisotropy result inpipe with transverse strength properties corresponding to those of anext higher material grade. Of course, these measures are costintensive and may have an unfavorable effect on other materialproperties (toughness, Y/T, corrosion resistance).

It is therefore prudent to check whether the pipeline design cantolerate the anisotropy in that it can accept reduced yield andtensile strength values for the longitudinal direction.

DESIGN EVALUATION OF HIGH STRENGTH STEEL

Review of the Usage of High Strength Steel Linepipes in

Offshore Pipelines

For offshore pipelines, the current trend is towards linepipe ingrade X70 with a wall thickness up to 40 mm. Fulfillment of therequirements for DWTT transition temperature will beprogressively difficult as the wall thickness increases. For wallthickness in excess of 30 mm, low transition temperatures can onlybe achieved by means of highly expensive rolling processes.

Until now, there has been only limited offshore use of X70material. The main installation contractors have completed threeprojects with X70 and have two planned until 1997. Again, these

references are only indicative and not comprehensive.

One example use of X70 linepipe in offshore applications is theBritannia pipeline for which Europipe supplied the linepipe. TheBritannia field is a gas condense reservoir in the Central North Seaapproximately 200 km northeast of Aberdeen and 45 km north of Forties.

The Gas Export Pipeline, 682.4 mm OD ×15.9 mm WT, is 186 kmlong. The pipeline design pressure is 179.3 barg and the design lifeof the pipeline is 30 years. The pipe grade is X70. The mechanical

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properties of the pipe used are given in Figure 3. The pipeline wassubject to reliability-based limit state design techniques in order to

justify a wall-thickness thinner than that permitted by BS8010. TheBritannia pipelines were completed in 1997.

Figure 3. Production results on 682.4 mm OD x 15.9 mm W.T.,API grade X70 linepipe.

Another large offshore project in grade X70 is the pipeline in theNorth Sea operated by Statoil, connecting Karstø, Norway, togetherwith Dornum, Germany. This pipeline has a length of 600 km andis built of pipe 42” x 25 to 30 mm WT.

Europipe completed in the 1990's the development of grade X80

pipe 48" in OD and 18.3 to 19.4 mm in wall thickness for onshorepipelines. It has been demonstrated that it is feasible tomanufacture commercially large diameter X80 pipe consistently forlong transmission pipelines, see Gräf and Hillenbrand (1995).

As regards offshore applications, a series of pipes have beensupplied for qualification testing with respect to pipelaying. Use of X80 linepipe for offshore field development is being qualified by a

joint industry project EXPIPE.

For low-alloy steel pipelines operating in sour service, X65 iscurrently the established material. Special treatment in thesteelmaking shop and fulfillment of special requirements forchemical composition help prevent the formation of nucleation

sites for HIC. Production trials show big potential for thedevelopment of higher grades up to X80 for slightly sourconditions, see Gräf and Hillenbrand (2000).

Potential Benefits of Using High Strength Steel

It is clear that the obvious advantage for using higher strengthsteels is cost saving. However, new approaches to design,manufacture and construction and the use of high-grade materialswill expose potential pipeline projects to increased levels of technical and commercial risks. This section of the paper identifies

the benefits and disadvantages associated with the use of highstrength steels.

Potential Cost Reduction

Increasing the grade of linepipe used for construction of a pipelineprovides the opportunity to reduce overall material costs. The costreduction is based on the premise that increasing material yieldstrength reduces the wall thickness required for internal pressurecontainment and hence the overall quantity of steel required. Theimplications of using high-grade material are considered in relation

to linepipe manufacturing and pipeline construction.

A published study (Price (1993)), which considered both direct andindirect consequences of using a high strength steel, suggested a7.5% overall project saving for a 42-inch offshore line laid withX80 instead of X65. Although the X80 pipe cost 10% more perton, it was 6% less per meter. Further savings were identified fortransportation, welding consumables, welding equipment rental andoverall lay time.

On the recently completed Britannia gas pipeline, cost studiesduring detailed engineering showed that by increasing the linepipematerial grade from X65 to X70, an approximate cost reduction of US$ 3.5 million could be achieved. The project CAPEX is

approximately US$ 225 million.

Although not directly related to the use of high strength material,other potential cost savings identified in the same study include:

• Tighter than normal (API 5L) definition of dimensions.Consideration should be given to reducing linepipetolerances on ovality and wall thickness from API 5Lrequirements. The actual tolerances required will bedetermined by evaluating potential cost reductionsanticipated during pipeline construction and mechanicaldesign, compared to the expected increase in linepipemanufacturing.

• Use of fracture mechanics acceptance criteria fordetermination of maximum allowable defect sizes in

pipeline girth welds. Traditionally, the acceptance criteriafor weld defects are based on workmanship standards.More recently, alternative criteria such as EngineeringCriticality Assessment (ECA) have been used to determinethe acceptability of defects, see Knauf and Hopkins (1996).

• Non-standard pipeline diameters should be considered.Optimization of the pipe ID based on modeling of thepipelines in detailed design may demonstrate that thelinepipe cost can be reduced by procuring pipe of the exactID required as opposed to selecting the larger standard size,for examples on the Britannia gas pipeline. Conversely, itmay be of benefit to modify the design flowrates to enableselection of a more economical size of pipe.

A quick and reliable inspection of girth welds is required in thecontext of pipelaying, especially of high strength pipe. There havebeen considerable advancements in recent years in this field.Starting from conventional radiography, the NDT equipment usedfor pipeline inspection has been improved. Radiography systemsare available which produce a real-time image of the weld beinginspected. Such systems can also be used for the quality control of production welds in pipe manufacture, followed by automatedevaluation of the data. As an alternative to radiography, high-speedultrasonic inspection is available. The radiographic images and alsothe ultrasonic indications are stored electronically and offer instant



retrieval. The time to inspect each weld is reduced compared totraditional methods, and thereby significantly reducing constructioncosts.

Wall Thickness and Construction

Given two similar design conditions, increasing the grade of linepipe in simplistic terms will correspondingly decrease the wallthickness and therefore provide cost benefits. In addition to this, athinner wall thickness will also have various impacts onconstruction activities. A thinner wall thickness will require less

field welding and therefore, in theory, has the potential to reduceconstruction/lay time.

Increasing the material grade and strength of linepipe is beneficialto laying pipe in deeper waters. Furthermore, certain projects canonly be implemented with pipe having reduced weight andoptimized strength and toughness.

The maximum water depth by conventional S-lay method is beingstretched to the extent that ALLSEAS have installed a 12-inchpipeline using X70 steel in 1600 m water depth in the Gulf of Mexico. However, it is questionable that the same lay method canbe used for a larger pipe diameter in the same water depth. It iswidely acknowledged that the J-lay method is the most suitable for

laying pipe in waters beyond 1000 m. A thinner wall thickness hasa direct impact on this installation method since the requirementsfor lay barge tensioners is related to the water depth and weight of pipe.

Pigging Requirements

The thicker walled sections of the pipeline in deeper waters mayrestrict the full capabilities of intelligent pigging. There is alimitation on the wall thickness depending on the type of piggingtool used, which can be overcome by the use of high-strength steels

Potential Disadvantages of Using High Strength Steels

Limited Suppliers

The worldwide availability of proven suppliers for material grades

above X70 is relatively limited.

Welding Restrictions

With regards to the weldability of X80 steel, there is a medium risk of schedule extension and cost increase since it has only been usedon a small number of onshore projects and there is no experienceoffshore. Welding to the required quality may be slowed by moreprocess restrictions and more complex controls. Due to the limitedworldwide experience of welding X80 linepipe, certain keywelding issues will have to be addressed in further studies,particularly that of welding consumables.

Limited Offshore Installation Capabilities

The number of offshore pipelay contractors with proven experience

of welding X70 steel linepipe is limited. Additionally, theexperience of laying deepwater pipelines by the J-lay method islimited to relatively small diameter pipelines.

Fatigue and Fracture of High Strength Steel

While an onshore pipeline is essential subjected to fatigueessentially due to internal pressure fluctuations, an offshorepipeline experiences fatigue stresses in the form of longitudinaltension and bending. Fatigue life under offshore conditions is usedas the basis for many of the limits placed on pipeline strengthdesign. These limits have often been established based on empirical

data from tests on low strength steels, with a safety margin applied.In general, the ability of steels to resist fatigue failure increaseswith increasing strength. But, the notch severity increases withincreasing strength, a finding that is of significance to theconfiguration of the girth weld in the context of the fatigue life of offshore pipelines.

Pipe materials, as a rule, should possess adequate toughness toprevent the initiation and the propagation of long-running fracturesin the pipeline, see Re et al (1995), ISO 3138 and DNV OS F101

(2000). For pipes with increasing strength also an increasingtoughness level is required. This relationship is also valid for girthwelds, i.e. with increasing strength of linepipe, weld metals of increased strength and sufficient toughness are required to ensureovermatching behavior of girth welds.

LONGITUDINAL LOADS DURING INSTALLATION

AND IN-SERVICE

General

The objectives of this chapter are to describe the longitudinal loadsacting on pipelines as below:

• S-lay installation loads;

• J-lay installation loads;

• Reeling installation loads;

• In-service loads for cold pipelines;

• In-service loads for HP/HT (high pressure high temperature)pipelines.

For large diameter pipelines, the preferred installation method is S-lay when water depth is shallower than e.g. 500 m. For deepwaterinstallation, J-lay is considered more suitable because it demandsless laying tension. The lay rate for S-lay is 2-3 times faster than J-lay. Typically a lay rate for S-lay is 3 km per day and a day rate isapproximately 3 millions NOK (0.4 millions USD) for both S-layand J-lay.

Unless specifically defined, “strain” is meant to be total strain.

Installation Loads for S-laid Pipelines

For deep water pipe lay with S-lay method, the pipe’s departureangle on the stinger has to be increased to minimize tensionrequirements and provide seabed maneuverability. The requirementof stinger departure angle is linked to the minimum curvatureradius, or laying strain criterion. Less conservative laying straincriterion, is being developed by Deepipe JIP, Expipe JIP anddesign projects by operators and engineering companies.

Recent research projects document that allowable static strain may

be 0.28%. Due to a reduction of strain hardening for high strengthsteel, the allowable laying strain for high strength pipe is lowerthan that for X65 pipes. Further research is therefore required tostudy the feasibility of relaxing strain criterion for high strengthpipe in deep water.

High strength steels are beneficial both with respect to wall-thickness sizing and less tension requirements resulting fromsmaller weight during installation. The limiting failure modes withrespect to pipeline installation are considered to be



• Girth weld fracture from weld defects;

• Concrete tensile failure due to over-stressing;

• Low cycle fatigue due to installation and in-service loadCycling;

• Buckling as a result of external-over pressure in sagbend;

• Collapse due to bending moment and internal pressure duringOperation.

The girth welds are the potential “week” section if one of thefollowing situations is presented during installation:

• Strain concentration due to heavy concrete coating or use of thick buckle arrestors;

• Fracture due to less strict requirements of weld defectinspection and repair;

• Fatigue due to long holding period in a rough wave conditionduring installation.

The assessment of acceptable defect depth and length represents akey element evaluating the strain level that can be accepted on thestinger and during in-service condition. The acceptable defect sizesdepend heavily on the material strength and fracture toughness.These material properties are associated with significant statisticalscatter and systematic variations around the girth weld. Two kinds

of laboratory tests can be useful to justify an increase of allowabletensile strain:

• Ductile fracture tests for improved fracture resistanceassessment;

• Low-cycle fatigue tests.

Installation Loads for J-laid Pipelines

The J-lay method involves installing pipeline in a vertical modefrom a dynamically positioned vessel and therefore allowsinstallation in water depth beyond the limits of the S-lay andReeling methods.

The feasibility of vertical J-pipelay, in particular from smallervessels, was examined by DeepStar JIP (Ekvall et al, 1994) fordeepwater installation. The pipe diameter for such deepwaterpipelines is typically 10” to 20” while that in the case of the currentBlue stream project in the Black Sea is 24”. The major technicaldifficulties are e.g. strength against collapse under combined loads,vessel positioning, stinger integrity, and pipe handling. For verticalJ-lay, the vessel can be oriented arbitrarily with respect to thepipeline route to minimize the wind and wave forces acting on thevessel, allowing J-lay installation to continue under a wider rangeof weather conditions. For offshore pipeline installation, regardlessof the pipelay method, a stinger is normally used to control thedeflection of the suspended pipe span and to keep the bendingstrains within an acceptable limit. A shorter and less curved stingeris required for J-laying (compared to S-laying) pipelines in deep

waters, since the pipe span lifts off at a less steep angle.

The maximum bending stress along the suspended span occurs inthe sagbend or around the stinger.

A major design concern is that pipe strength in the sagbend is verysensitive to collapse during a vertical J-lay installation, since thepipe in this region is subjected to very high stresses due tocombined bending and external pressure.

At the touchdown point, the stress due to change of theconfiguration as well as contact force from the seabed, can be veryhigh. This may induce some cross-sectional ovalisation that mayfurther reduce pipe collapse strength. At the touchdown point, thebending collapse is a displacement-controlled situation. The layingstrain-limit may be determined using external pressure – curvatureinteraction equations. Typical strain is 0.2% during J-installationof pipelines.

Fatigue loads should also be included to design for an abnormal

weather situation, where cyclic loads may be repeated if the pipe ison-hold for a long period, due to e.g. repair needs. The calculationof fatigue loads may be conducted using dynamic installationanalysis.

The methods of strength design for S-laying installation, asdiscussed earlier, are generally applicable to J-laying situations.

Installation Loads for Reeled Flowlines

Strain Level During Reeling

The different stages of the reeling process are:

• Reeling on;

• Reeling off;• Pipe passing the entry guide and ;

• Bending at pipe straightener.

Strain as Pipe is Lowered to the Seabed

As in traditional S-lay, the reeled pipe may be bent as it passes overa stinger leaving the vessel, and bent in the opposite direction as itmeets the seabed. These bending scenarios are often referred to asoverbend and sagbend, respectively.

Strain During Pressure Testing

Prior to putting a pipeline into operation the pipe will behydrotested to a test pressure higher than normal operatingpressure. The procedure and the test pressure depend on the

pipeline code used for design. The longitudinal strain at a hydrotest is about 0.2% and the equivalent stress is close to SMYS(Specified Minimum Yield Stress) at critical locations (e.g. spans)in a hydro test.

In-service Loads for Cold Pipelines

For cold pipelines, the in-service loads are:

• Fatigue due to extensive repair period or rough waveconditions during installations;

• Functional loads (e.g. pressure, temperature, weight andsupport reaction);

• Environmental loads (e.g. wave and current loads);

• Accidental loads (e.g. impacts, dropped objects, explosion,fire and anchoring);

• Trawling loads (fishing gear loads during impact, pull-overand hooking process).

The internal pressure may be reversibly estimated from wall-thickness and material grade using (pressure containment) hoopstress criterion. Typically internal pressure is 200 barg for gasexport lines and 350 barg for infield flowlines, although the exactvalue is to be given case by case. The intention to list the above



values is to show that high pressure in offshore pipelines is farhigher than that experienced in onshore pipelines.

The weight is to be estimated considering the volume of steel, pipecontents density, coating thickness and density. The contact forcebetween a cold pipeline and the seabed may be simply calculatedbased on force equilibrium.

The wave and current loads on pipeline are estimated usingMorisson’s equations given by design codes. The wave and current

velocities are calculated based on water depth and the gap distancebetween the pipe and the seabed. Again, equations are availablefrom the codes to calculate wave and current velocities. Statisticalvalues are used to estimate leads:

• For ultimate strength analysis, the extreme valuescorresponding to n years return period are used;

• For fatigue strength analysis, characteristic values are used;

• For design against accidental loads, normal operating loadsare to be used;

• For design against fishing gear pull-over loads, loadscorresponding to the specific span heights are to be used.

The characteristic fatigue loads for cold pipelines are:

• Cyclic loads during installation phase, e.g. induced by waveloads or reeling loads;

• Cyclic loads due to free-spans, e.g. due to vortex-inducedvibrations or caused by cyclic wave force in a shallowwater.

For cold pipelines, the temperature induced axial displacement isnegligible. It is perhaps correct to assume that the typical normaloperating loads are internal pressure. However, global buckling(e.g. upheaval buckling & lateral buckling) should not be excludedfrom design if operating pressure is high and soil friction is low.

Unless fishing gear loads are large, longitudinal loads are not ademanding requirement. Normally very little seabed intervention isrequired for the safety of a pipeline in operating conditions.Unfortunately for design of pipelines in the North Sea, pull-overloads are governing design parameter where fishing activities arefrequent and water depth is less than 350 m. The pull-over loadsconsist of vertical (downward) component and horizontalcomponent. Both are functions of span height, and trawlingvelocity. The time-history of the pull-over loads are available fromdesign guidelines made by the pipeline industry.

As daily practice in design offices, finite element in-place analysisis conducted to estimate the structural response due to fishing gearpull-over loads, and comparisons with limit-state design criteria arecarried out to ensure the structural response is acceptable.

In-service Loads for HP/HT Pipelines

General

HP/HT (High Pressure High Temperature) pipelines are defined as

• Design internal-over pressure is typicallyt D

t −

28.0 SMYS

• Operating temperature is 130ºC and above.

The HP/HT pipelines are typically infield flowlines where oil andgas are transported without expensive cooling process.

Seawater is a good cooling system. At a distance of a couple of kilometers from a platform or a template, the temperature of thepipe containment becomes lower than 10 ºC.

As for cold pipelines, the in-service loads for HP/HT pipelines are:

• Functional loads (e.g. pressure, temperature, weight andsupport reaction);

• Environmental loads (e.g. wave and current loads);

• Accidental loads (e.g. impacts, dropped objects, explosion,

fire and anchoring);

• Trawling loads (fishing gear loads during impact, pull-overand hooking process).

Differences between Cold Lines and HP/HT lines

In the following, the difference between HP/HT pipelines and coldpipelines are described:

• The major difference is temperature-induced strain andthermal buckling. As known by pipeline industry for manyyears, a HP/HT pipeline may experience upheaval bucklingif the pipeline is rock-covered. Lateral buckling (snaking)may occur if the line is free on the seabed.

• Design of HP/HT pipeline against fishing gear loads

becomes a crucial issue since large stress and moment maybe observed under pull-over loading and the pipelineindustry does not allow strain-based design for pull-overloads yet. The moment criteria for load-controlledsituations from design codes are rather conservative.

• Seabed intervention cost for protection of in-servicepipeline is governed by pull-over loads.

Strain level in operating flowlines

The main source of cyclic loading during operation is repeatedheating-up and cooling-down due to shut-downs/start-ups. For apipe laying on the seabed with no rock cover, the thermalexpansion may cause the pipe to deform laterally or feed pipe intofree-spans, resulting in bending strain. Similarly, for a fully

constrained buried pipeline there will be radial and hoop strainvariations resulting from the start-up/shut-down cycles.



Summary of Loads and Load Combinations

Actuallongitudinalloads

Hoop loads CodeRequirements

Remarks

Reeling Maximum 2%logitudinal strain

Nohoop loads

Fracture &localbucklingchecks

For smalldiameterflowlines

S-Lay Maximum 0.3 %strain

Externalpressure forsag-bend

Fracture,Rotation,Collapse in

sag-bend

For shallowwater, largediameter

J-lay Maximum 0.3 %strain

Externalpressure forsag-bend

Fracture,Collapse insag-bend

For deepwater, large &small pipe

Coldoperation

pull-overinduced strain of 0.3% or stress of 0.9 SMYS

Hoop stress of 0.8SMYS

Limit statebased designcriteria

Crucial forseabedinterventiondesign

HP/HToperation

pull-overinduced strain of 0.3% or stress of 0.9 SMYS

Hoop stress of 0.8SMYS

Limit statebased designcriteria

Crucial forseabedinterventiondesign

Table 1. Summary of Installation and Operation Loads.

DESIGN EXPERIENCE ON LOADS AND STRENGTH

Limit-state Design of Offshore Pipelines

Limit state based strength criteria may be developed for pipelinescovering the potential failure modes: • Out of roundness for serviceability;

• Bursting due to internal pressure, longitudinal force andbending;

• Buckling/collapse due to pressure, longitudinal force andbending;

• Fracture of welds due to bending/tension;

• Low-cycle fatigue due to shut-downs;

• Ratcheting due to reeling and shut-downs;

• Accumulated plastic strain.

The limit-states are to be defined for the following load situations:

• Installation condition;

• Empty condition;

• Water filled condition;

• Pressure test condition;

• Operational conditions;

• Shut-down conditions.

The strength criteria are to be defined for the following designsituations:

• Static and dynamic installation criteria;• In-place behavior;

• Trawl pull-over response;

• Static free-spans;

• Dynamic free-spans.

It should be documented that adequate structural safety ismaintained against the potential failure modes for the given designsituations when the strength criteria developed are satisfied.

Pipe dimensions, operating conditions and material dictate theallowable moments, stresses and strains.

The experience from design of North Sea pipelines is summarizedin the following sections.

Experience from Design of Large Diameter Export Pipelines

The following is a summary of design experience on loads andstrength:

• When water depth is less than 350 m, the wall-thicknessdesign is normally governed by internal pressurecontainment requirement, e.g. hoop stress criterion. In orderto achieve cost saving, it is necessary to use high strengthsteel pipe.

• When water depth is greater than 350 m, a study is requiredto investigate the nonlinear relation between the costs andsteel grade for different water depths. Higher yield strengthalso helps increase the pipe buckling/collapse capacity forexternal-over pressure situations, however, this relationshipis no longer linear.

• As long as strain-based design can be applied for operatingconditions, the longitudinal loads are far below the

capacity. Therefore, the required longitudinal yield strengthis not so high – leading to a potential use of pipes whosehoop yield strength is far higher than longitudinal yieldstrength.

• When a pipe is under a load-controlled situation, thebuckling/collapse capacity of the pipe may be assessedusing moment criteria.

Experience from Design of Infield Flowlines

The following is a summary of design experience on loads andstrength:

• Flowlines are typically installed using reeling methods. Adetailed welding qualification program is required to ensurethat no fracture or local buckling occurs during the reelingprocess and there is no threat to the fatigue strength afterline installations.

• For small diameter flowlines in the North Sea, the governingdesign loads are the trawling loads. In this instance,buckling/collapse criteria (moment criteria) are governingdesign parameter.

MATERIAL PROPERTY REQUIREMENTS

General

The purpose of this chapter is to describe the materialrequirements, and compare the requirements for longitudinal

direction and circumferential direction. Typically, the materialproperties requirement in hoop direction are related to pressurecontainment hoop stress criterion and buckling/collapse underexternal pressure, while longitudinal properties are directlyspecified for buckling/collapse under bending and tension, andweldability.

It is beneficial from the viewpoint of manufacturing to allow hoopyield strength higher than longitudinal yield strength. In thefollowing, requirements will be described regarding CTOD, yield



stress, ratio of SMYS and SMTS, fatigue properties and wall-thickness tolerances.

Material Property Requirement in Hoop Direction

Necessary CTOD value requirements for HAZ and weld metal areto be established that are relevant for the specific design conditionswith regard to type and extent of longitudinal weld defects likely toexist. Typically, the required CTOD value is established throughECA (Engineering Criticality Assessment) using British Standard

PD 6493.

The extent of longitudinal weld defects that likely to exist, isdefined in the operators’ welding qualification specifications.Typical values are: depth 3 mm and width minimum of 25 mm andpipe wall-thickness.

The required CTOD value, as calculated based on codes, is ratherstringent, due to large scatters in the CTOD values from tests.Practical experience from field use of the line pipes have,demonstrated that there has been very little structural failure due tolack of CTOD value in hoop direction for line pipes. It is thereforesuggested to closely evaluate the following:

• CTOD testing methods, scatters and statistical evaluation of scatters;

• Possibility to reduce the number of CTOD tests;

• Safety factors used in ECA determination of CTODrequirements;

• ECA design equations and analysis methods.

Similar observations may be made on the CTOD requirements forthe longitudinal direction.

It is likely that fracture occurs in the weldment. Then the CTODrequirements made to pipe base material are not relevant. However,the CTOD value for HAZ (Heat Affect Zone) may be relevant forfracture in HAZ. Weldability of the pipe is a more importantparameter than CTOD value.

Material Property Requirement in Longitudinal Direction

The CTOD value for line pipes in longitudinal direction isinfluential for fracture limit-state when ECA such as PD6493 isapplied to calculate the limiting loading condition to avoid fracture.

The CTOD value needed to avoid fracture depends on the extent of girth weld defects likely to exist and the applied load. For a defectdepth of 3 mm, a wall thickness of 25.4 mm and loading up to0.5% total strain a defect length of 177 mm (7 x wall thickness)was shown to be safe when CTOD is minimum 0.10 mm, see Knauf and Hopkins (1996).

The discussions on unstable fracture and CTOD for hoop directionare also valid for longitudinal direction.

The fact is that the yield stress in longitudinal direction does notsignificantly affect pipe strength as long as strain-based design isapplicable to the design situation. The reasoning for this statementis that strain acting on pipelines in operating condition is typicallyas low as 0.2% unless the pipeline is under a high pull-over load.

With exception of some special material problems, the Y/T(SMYS/SMTS) ratio requirements can be replaced by introducing

strain-hardening parameters such as σR and n used in a Ramberg-Osgood equation. In Bai et al (1994), a set of equations are given to

relate SMYS and SMTS with strain-hardening parameters σR andn.

The material strain-hardening effect may be accounted for infracture mechanics assessment and local buckling/collapse checksthrough use of the stress-strain curves. In fact, a set of designequations was given by Bai et al (1997) and Bai et al (1999) forlocal buckling/collapse. In the papers by Bai et al. (1997, 1999),

the effect of material strain hardening parameter onbuckling/collapse have been discussed in detail.

The level-2 and level-3 failure assessment diagrams in PD6493 doalso account for strain-hardening effects.

Comparisons of Material Property Requirements

Which material properties are dominant in local buckling/collapse?The answer is dependent on loads as the following:

• For internal pressure containment, hoop SMTS;

• For external-pressure induced buckling, hoop SMYS;

• For bending collapse, longitudinal SMYS;

• For combined internal pressure and bending, hoop SMTS;Longitudinal SMYS & SMTS;

• For combined external pressure and bending, hoop SMYS;Longitudinal SMYS & SMTS.

Pipe strength under combined internal pressure and bending is animportant design case, if fishing activities are frequent.

It is difficult to compare the requirements of the material propertyin hoop and longitudinal directions. Rather the following is adiscussion on cost-effectiveness of raising material’s performancein hoop and longitudinal directions.

Raising hoop SMYS will directly result in a proportional reduction

of the required wall-thickness of the line pipe for water depthshallower than 350 mm. However, if the design codes, onbuckling/collapse for external-over pressure case, are furtherupgraded, this water depth may be extended from 350 m to 450 m.It is the authors' opinion that the existing design equations forexternal-over pressure situations are rather conservative. Toachieve yield and tensile strength values that conform to therequirements, as specified for the transverse direction, acorresponding increase in the strength in the longitudinal directionis needed. This in turn leads to increased production costs and maylead to difficulties in meeting the requirements for yield-to-tensileratio, toughness and sour service suitability, etc..

As a conclusive remark on materials property requirements, it isbelieved that:

• The minimum CTOD values in both hoop and longitudinaldirections typically should be 0.1mm; the applicability of lower CTOD values can be validated by ECA methods.

• It is economically beneficial and technically justifiable thatfor pipe grades X60 to X80 yield and tensile strength inlongitudinal direction can be lower by up to 10% than thosein the transverse direction for water depths shallower than450 m.



• For fracture and local/buckling failure modes, the Y/T valuerequirement can be removed if the strength analysisexplicitly account for the difference of strain-hardening

whose parameters (σR and n) are a function of SMYS andSMTS as the equations given in Bai et al(1997).

As a further study, it is proposed to compare the Y/T ratiorequirements from alternative codes (e.g. 0.93 from API foronshore pipelines, 0.85 from EPRG and 0.87 from DNV’96guideline). It is perhaps possible to find some other rational

criteria that can replace the Y/T ratio requirement in strengthdesign. In order to develop alternative criteria, it is necessary tounderstand the reasoning of using Y/T ratio as a design parameter.

STRENGTH DESIGN OF LINEPIPES WITH YIELD

ANISOTROPY

Anisotropy has been taken into account for the first time in therecently established DNV offshore standard F101 in that theminimum tensile strength required in the longitudinal direction hasbeen reduced by 5%, compared to that in the transverse direction. Itshould be endeavoured to pursue other codes to adopt thisapproach and to apply this approach also to yield strength.

Reduction of the strength levels in the order of 10% for thelongitudinal direction is technically justified.

An analytical solution may be derived for the calculation of themoment capacity of a pipe with a corrosion defect subjected tointernal pressure, axial force and bending moment. The maximumcapacity is defined in the solution as the moment at which theentire cross section yields. The corrosion defect is conservativelyassumed to be symmetrical to the bending plan.

Criteria for buckling/collapse calculations of corroded pipes withyield anisotropy were derived by Bai et al (1999).

The moment criteria were re-visited and extended for design of high strength steel pipes with yield anisotropy.

CONCLUSIONS

The paper provides technical information from linepipemanufacturing and design viewpoints to promote use of highstrength linepipes. The following is conclusive remarks:1. Material properties are given for high strength linepipe.2. Practical considerations on use of high strength steel have

been given, focusing on cost impact, welding, material andcorrosion aspects.

3. Pipeline design loads have been summarized for S-laid largediameter export lines and small diameter infield flowlines.

4. The requirements of material properties have been discussed

to justify use of yield anisotropy linepipe.5. Strength design equations have been developed for high

strength linepipes that have yield anisotropy.6. Regulatory bodies, specifications and design codes should pay

more attention to the technical feasibility of pipe properties.Close co-operation among designers, pipelaying contractors,pipeline operators and pipe manufacturers should beintensified.

REFERENCES

1. API 5L (1995): “Specification for Line Pipe”, 41st Edition.

2. Bai, Y. Igland, R. and Moan, T. (1994): “Ultimate Limit Statesfor Pipes under Combined Tension and Bending”, InternationalJournal of Offshore and Polar Engineering, pp.312-319.

3. Bai, Y. Igland, R. and Moan, T. (1997): “Tube Collapse underCombined External Pressure, Tension and Bending”, Journal of Marine Structures, Vol. 10, No.5, pp.389-410.

4. Bai, Y., Jensen, J.C. and Hauch, S. (1999): “Capacity of Pipeswith Yield Anisotropy”, Proc. of ISOPE’99.

5. DNV (2000): “DNV OS-F101, Submarine Pipeline Systems”,Det Norske Veritas.

6. Ekvall, A.G.C., Ju, G.T., Langner, C.G., McClure, S.C.,Salzer, J.R., and Welsman, B.D. (1994): “Evaluation of Deepwater J-pipelay”, DeepStar Phase II, CTR 610, March1994.

7. Graf, M.K. and Hillenbrand, H.G. (1997): “Grade X80Linepipe and Pipeline Construction”.

8. Graf, M.K., Hillenbrand, H.G. and Niederhoff K.A. (1993):“Production of Large-diameter Line Pipe and Bends for theWorld’s First Long Range pipeline in Grade X80 (GRS 550)”

PRC/EPRG Ninth Biennial Joint Technical Meeting on Line

Pipe Research, Houston, Texas, May 11-14th.9. Graf, M. K. and Hillenbrand, H. G. (1995): “Production of

Large Diameter Line Pipe - State of The Art and FutureDevelopment Trends” Europipe GmbH.

10. Gräf, M.K. and Hillenbrand, H.G. (2000): “Development of larger-diameter linepipe for offshore applications”, 3rd

International Pipeline Technology Conference, 22-24 May2000, Brugge, Belgium.

11. Hillenbrand, H.G., Niederhoff, K.A., Amoris, E., Perdrix, C.,Streisselberger, A. and Zeislmair, U. (1997): “Development of Line Pipe in Grades up to X 100”, PRCI-EPRG 11th Biennial

Technical Meeting, Arlington Virginia, April.12. Hillenbrand et al. (1995): “Manufacturability of Line Pipe in

Grades up to X100”, TM Processed Plate HG Pipeline

Technology, Volume II.13. ISO 3138-2 (1996): “Petroleum and natural gas industries -

Steel pipe for pipelines - Technical delivery conditions - Part2: Pipes of requirement class B”.

14. Knauf, G. and Hopkins, P. (1996): “The EPRG Guidelines on

the Assessment of Defects in Transmission Pipeline GirthWelds”, 3R international (35), heft 10-11/1996, pp. 620-624.

15. Pistone, G. R., Vogt, G., Demofonti, G. and Jones D.G.(1995): “EPRG Recommendations for Crack ArrestToughness for High Strength Line Pipe Steels” , 3R

International, Vol. 34 November 10, pp 606 - 611.16. Re, G., Pistone, V., Vogt, G., Demofonti, G. and Jones, D.G.

(1995): “EPRG Recommendation for crack arrest toughnessfor high strength line pipe steels”, 3R International (34), Heft10-11, pp607-611.

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