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. .,. DET NORSKE VERITAS ClASSIFICATION AS

5.81.3000 9.82.2000 7.85. 300 9.86. 300

APPROVED BY THE BOARD OF DIRECfORS

APRIL 30. 1981

co Det norske Veritas 19 81.

Printed by Del norskc V critas. Oslo.

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PREFACE

VERIT AS has published Rules for offshore structures. off· shore loading systems. process equipment. submarine pipe1i· nes etc .. and is prepared to issue a Certificate of Approval for such installations when found to be designed and constructed in accordance with the appropriate Rules.

The procedure for obtaining and retaining a Certificate of Approval is defined in these Rules.

The purpose of the Rules is to'

Serve as basic philosophy and rule requirements when applying for certification by VERIT AS. Recommend an international acceptable level of safety and reliability by defining minimum requirements re­garding strength. serviceability and maintenance. Serve as a technical reference document in contractual matters between Owner and Contractor.

The Rules open for a freedom in choice of technical solutions to obtain an acceptable safety level. More detailed description of possible methods satisfying the Rule's requirements. are gi· ven in the Appendices to the Rules. Other methods will be ac· cepted provided the same safety level is obtained.

In addition to the Rules and Appendices, VERIT AS also is· sues Technical Notes. which give further guidelines on speci· fie problems related to the fulfilment of the Rule's require­ments.

Where VERITAS is recognized as a Certifying Agent by Na· tional Authorities, the Rules may serve as a supplement to any National Regulations which are mandatory.

Although the Rules. the Appendices and the Technical Notes. are all prepared with VERITAS' Certificate of Approval in mind, the publications may be used as guidelines for desig· ners. owners and others not directly involved in the certifica· tion process. Where parts of the Rules are copied or applied. proper reference to the source should be made.

. .'

• 1.1

1.2

1.3 1.3.1 1.3.2 1.3.3 1.3.4 1.3.5 1.3.6 1.3.7 1.3.8 1.3.9 1.3.10 1.3.11 1.3.12 1.3.13 1.3.14 1.3.15 1.3.16 1.3.17 1.3.18 1.3.19 1.3.20 1.3.21 1.3.22

1.4 1.4.1

• . 2 ... 3 1.4.4

1.5 1.5.1 1.5.2 1.5.3 1.5.4

1.6 1.6.1

1.7

1.7.1. 1.8 1.8.1 1.8.2 1.8.3 1.8.4 1.8.5

2.1 2.1.1 2.1.2

••. 1 2.2.2 2.2.3 2.2.4

2.3 2.3.1 2.3.2 2.3.3

CONTENTS Section 1

General regulations

Symbols ................................. 9

Technical terms .......................... I 0

Definitions .............................. I 0 Pipeline system .......................... I 0 Submarine pipeline ....................... I 0 Riser system ............................ I 0 Pipeline riser ............................ I I External riser ........................... II Internal riser ............................ II Riser support ........................... ·. II Piping components ....................... II Splash zone ............................. II Submerged zone ......................... II Atmospheric zone ........................ II Platform ................................ II Zone I .................................. II Zone2 .............. · ......... c ••••.••••• ll Surveillance ............................. II Inspection .............................. II To survey .............................. II A survey ............................... II Surveyor ........................•...... II Liquid hydrocarbons ...................... II Gaseous hydrocarbons .................... II Fluid .................................. II

The Rules .............................. II Application ............................. II Amendments ............................ II Alternative methods and procedures ......... II Assumptions ............................ II

Certificate of Approval. ................... 12 Issuance of the Certificate ................. 12 Recommendations ........................ 12 Memoranda to Owner .................... 12 Withdrawal of Certificate .................. 12

Concept evaluation ....................... 12 General ................................ 12

Instrumentation for monitoring of the pipeline system .......................... 12 General ................................ 12

Documentation .......................... 13 Submission of documentation .............. 13 Design phase ............................ I 3 Fabrication phase ........................ 13 Installation phase ........................ 13 Filing of documentation ................... 13 ,,, •.•

Section 2 Environment

General ................................ 14 Environmental phenomena ................ 14 Acceptable environmental data ............. 14

Pipeline route ........................... 14 Location ............................... 14 Route survey ............................ 14 Bottom topography ....................... 14 Seabed properties ........................ 14

Environmental conditions ................. 14 General ................................ 14 Tide ................................... 14 Wind .................................. 14

2.3.4 2.3.5 2.3.6 2.3.7 2.3.8 2.3.9

2.4 2.4.1 2.4.2

2.5 2.5.1 2.5.2

3.1 3.1.1 3.1.2 3.1.3

3.2 3.2.1 3.2.2 3.2.3

3.3 3.3.1 3.3.2 3.3.3 3.3.4 3.3.5 3.3.6 3.3.7 3.3.8

4.1 4.1.1 4.1.2 4.1.3

4.2 4.2.1 4.2.2 4.2.3 4.2.4 4.2.5 4.2.6 4.2.7 4.2.8

Waves ................................. 15 Current ................................ 15 Corrosivity ............................. 15 Ice ..............................•..... IS Air and sea temperatures .................. 15 Marine growth .......................... IS

Internal pipe conditions ................... 15 Installation conditions ..................... IS Operational conditions .................... 15

Design temperature ....................... 16 General ................................ 16 Differentiated design temperatures ........... 16

Section 3 Loads

Loading conditions and design conditions ..... 17 General ................................ 17 Loading conditions ....................... 17 Design conditions ........................ 17

Functional loads ......................... 17 General ................................ 17 Functional loads during operation ........... 17 Functional loads during installation .......... 17

Environmental loads ...................... !7 General ................................ 17 Wind loads ............................. 18 Hydrodynamic loads. general. .............. 18 Wave loads ............................. 18 Current loads ....................... · .... 18 «Indirect» environmental loads ............. I 9 Ice loads ............................... 19 Accidental loads . . . . . . . . . . . . . . . . . . . . . . . . . I 9

Section 4 Strength and inplace stability

General ................................ 20 Design analyses .......................... 20 Design criteria ........................... 20 Design conditions ........................ 20 ·

Pipeline/ riser during operation ............. 20 General ................................ 20 Yielding ................................ 20 Buckling ............................... 21 Fatigue ................................. 21 On-bottom stability ....................... 22 Propagating ductile fractures ............... 23 Riser supports ........................... 23 Spans .................................. 23

4.3 Pipeline/risers during installation ........... 23 4.3.1 General ................................ 23 4.3 .2 Yielding ................................ 23 4.3.3 Buckling ............................... 24 4.3.4 Fatigue ................................. 24

4.4 Pipjpg components and accessories .......... 24 4.4.1 General ................................ 24

Section 5 Material requirements for pipes and piping components

5.1 General ................................ 25 5.1.1 Validity .............................. ·. 25 S .1.2 Selection of materials ..................... 25 5.1.3 Material specification ..................... 25

5.1.4

5.2 5.2.1 5.2.2 5.2.3 5.2.4 5.2.5 5.2.6 5.2.7 5.2.8 5.2.9 5.2.10

5.2.11

5.2.12

5.2.13

5.3 5.3.1

5.4 5.4.1

5.5 5.5.1 5.5.2 5.5.3 5.5.4

5.6 5.6.1

5.7 5.7 .]

6.1 6.1.1 6.1.2 6.1.3

6.2 6.2.1 6.2.2 6.2.3 6.2.4

6~ 6.3.1 6.3.2 6.3.3 6.3.4 6.3.5

6.4 6.4.1 6.4.2 6.4.3 6.4.4

6.4.5

6.5

6.5.1 6.5.2 6.5.3 6.5.4

6.6 6.6.1 6.6.2 6.6.3 6.6.4

Documentation and identification . . . . . 25

Steel for line-pipes. . . . . . ... 25 Steel making . . . . . . . 25 Supply condition. . . . . . 25 Heat treatment . . . . . .. 25 Chemical composition. . 25 Mechanical testing ....................... 25 Tensile properties . . . . . ........ 26 Brittle fracture resistance .................. 26 Resistance against propagating ductile fractures 26 Supplementary fracture toughness testing ..... 27 Resistance against hydrogen induced cracking in welded joints .......................... 27 Resistance against environmental induced blistering . . . . . . . . . . . . . . . . . . . . . . 27 Resistance against sulphide stress corrosion cracking (SSC) ........................... 27 Resistance against chloride stress corrosion cracking..... . .. 27

Soundness .............................. 27 General ................................ 27

Steel for piping components ................ 27 General ................................ 27

Welding consumables ..................... 27 General........................ . .. 27 Chemical compcsition ..................... 28 Mechanical properties ..................... 28 Handling and storage of welding consumables. 28

Bolt assemblies .......................... 28 General ................................ 28

Materials for support structures ............. 28 General ................................ 28

Section 6 Corrosion protection and weight coatiiJg

Corrosion protection. general . .............. 29 validity . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Definitions .............................. 29 General requirements to corrosion protection systems ................................ 29

External coating ............ - ............ 29 General ................................ 29 Coating materials ........................ 29 Coating application ....................... 30 Field joint coating. . . . . . . . . . . . . . . . . . . .. 30

Cathodic protection ....................... 30 General . . . . . . . . . . . . ........... 30 Design of system ......................... 30 Anode materials and fabrication . . . . . . . . . 31 Installation of anodes . . . . . . . . . . . . . . . 31 Testing of system . . . . . . . . . . . . . . . . .. ~.L.

Internal corrosion control. ................. 31 General ................................ 31 Internal corrosion control by inhibitors . ...... 32 Internal corrosion control by coating ........ 32 Internal corrosion control by corrosion resistant alloys ........................... 32 Internal corrosion monitoring .............. 32

Protection of risers and pipelines in 'critical areas .......... :· .... : .................. 32 Splash zone protection .................... 32 Protection of risers in J-tubes. tunnels etc ..... 33 Protection of risers in internal transition zones. 33 Pipeline shore-approach ................... 33

Weight coating .......................... 3 3 General ................................ 33 Weight coating specification ................ 33 Concrete constituents ..................... 3 3 Properties of concrete ..................... 33

6.6.5 6.6.6 6.6.7

7.1 7 .I. I

7.2 7.2.1 7.2.2 7.2.3

7 .2.4 7.2.5 7.2.6 7.2.7 7.2.8 7.2.9

7.3 7.3.1 7 .3.2 7.3.3 7.3.4 7.3.5

7.4 7.4.1

8.1 8.1.1

8.2 8.2.1 8.2.2

8.3 8.3.1 8.3.2 8.3.3 8.3.4 8.3.5

8.4 8.4.1

8.5 8.5.1 8.5.2 8.5.3

8.5.4 8.5.5 8.5.6 8.5.7 8.5.8

8.6

8.6.1 8.6.2 8.6.3

8.7 8.7.1 8.7 .2 8.7 .3 8.7.4

8.8 8.8.1 8.8.2 8.8.3

Reinforcement.... . .............. 33 Application and curing of concrete coating . ... 34 Testing and inspection . .- ................. 34

Section 7 Fabrication of pipes and piping components

General ............ . Validity ..

.... 35 . 35

Pipe fabrication. . . . . . . . .............. 35 General ................................ 35 Fabrication procedure specification .......... 35 Qualitification of welding operators. welders and arc- air gougers .............. ] 5 Qualification of pipe fabrication procedure .... .35 Hydrostatic testing ..................... :. 36 Dimensions and workmanship .............. 37 Visual examination and non-destructive testing 38 Production testing ........................ 38 Repairs ................................ 38

Fabrication of. piping components ........... 39 General .........................•...... 39 Fabrication procedure specification .......... 39 Qualification of fabrication procedures ...... . 39 Production testing. . ................ 39 Repair welding of piping components, . ·., .. · .• •39

Post weld heat treatment .................. ·39 General ................................ 39

Section 8 Installation

General . . . . . . . . . . . . . ..... ·.·. 4 .. I "·. . Specifications. . . . . . . . . ..... ·. 41 \.

Pipeline route .. , ........................ 41 Route survey. . .................... 41 Seabed preparation .............. , ..•. : . .. : .. : .. :::.: .. ::;;.;."~"

Construction ............................ , Qualification ................... ,. , ... ···' Handling and storing .................... ,. Installation operations. . . . . . . . . ..... 41 Pipeline and cable crossings. . ........ 42 Buckle detection ........................• 42

Anchoring and protection of pipeline systems : 42 General ................................ 42

Installation welding ...................... 42 General ................................ 42 Welding procedure specification ......•..... 42 Qualification of the welding equipment and welding procedure ...................... :' 42 Essential parameters for welding procedures .. 43 Qualification of welders and welding operators 43 Welding and workmanship ................ 43 Production test .......................... 44 Repair of field joints. . . . . . . . . . ......... 44

Visual examination and non-destrUctive testing of installation welds ...................... 45 General ............................... , 45 Visual examination ........ , . , ............. 45 ~on-destructive testing .................... 45

~::.~i : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : :~ ' Mechanical connectors .................... 45 -, Welded tie-in on the lay vessel ............. 45 Tie-in by underwater welding .............. 45

Final surveys and tests . ................... 46 General ................................ 46 Survey of installed pipeline system .......... 46 Survey of corrosion protection system ..... ~ . 46

Pressure test ............................ 46 Buckle detection ......................... 47 Testing of alarm and shutdown systems ...... 47

Section 9 Operation and maintenance

General .... , ........................... 48 Owners duty ............................ 48 Retension of Certificate of Approval ......... 48

Operation and maintenance of the pipeline. system ................................. 48 Operation. inspection and maintenance manual 48 Operation ............................... 48

In-service inspection ...................... 48 General ....... , ........................ 48 Start up inspection ....................... 48 Periodical inspection ...................... 48 Frequency of periodical inspection ........... 48 Extent of periodical inspection - pipeline .... 48 Extent of periodical inspection - riser ....... 4 9 Special inspection ................ , ....... 49

Repairs ................................ 49 General ................................ 49 Grooves. gouges and notches .•............. 4 9 Dents .............. , ................... 49 Leaks .................................. 49 Repair by welding ....................... 49 Temporary repairs ....................... 50

Section 10 Non-destructive testing

General ................................ 51 Selection of method ...................... 5 I

Radiographic examination of welds .......... 51 Radiographic procedure specification ......... 51 Radiographic procedure qualification ......... 51 Qualification of radiographers .............. 52 Production radiography ................... 52 Evaluation of .welds and standards of acceptability .. : . . . . . . . . . . . . . . . . . . . . . . . . . 52

Ultrasonic examination of welds with stationary equipment ..................... 52 Equipment .............................. 52 Ultrasonic procedure specification ........... 52 Ultrasonic procedure qualification ........... 52 Calibration of equipment .................. 52 Qualifications of operators . . . . . . . . . . .... 52 Production ultrasonic examination .......... 52 Evaluation of welds and standards of acceptability ............................. 52

Ultrasonic examination of welds with pcrtable equipment. ...................... 52 Equipment.., ........................... 52 Ultrasonic procedure specification ........... 53 Ultrasonic procedure qualification ........... 53 Calibration of equipment .................. 53 Qualifications of operators •... , .... , . , ..... 53 Production ultrasonic examination .......... 53 Evaluation of welds and standards of acceptability . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Magnetic particle examination of welds ...... 55 Magnetic particle procedure specification ..... 55 Magnetic particle procedure qualification ..... 55 Qualilic:ations of operators ................. 55 Produ~tion magnetic particle testing ......... 55 Evaluation of welds and standards of acceptability . . . . . . . . . . . . . • . . . . . . . . . . . . . . 55

Liquid penetrant examination of welds . ...... 55

10.6.1 10.6.2 10.6.3 10.6.4 10.6.5

A.l A.l.l A.l.2 A.l.3

A.2 A.2.1 A.2.2 A.2.3

A.3

A.3.1 A.3.2 A.3.3 A.3.4

A.4 A.4.1 A.4.2

Liquid penetrant procedure specification ...... 55 Liquid penetrant procedure qualification ...... 56 Qualifications of operators ................. 56 Production liquid penetrant testing .......... 56 Evaluation of welds and standards of acceptability. . . . . . . . . . . . . . ....... 56

Appendix A Environmental loads

Wind loads ............................. 63 General ................................ 63 Static wind loads ......................... 63 Vortex shedding due to wind ............... 63

Vortex shedding due to current ............. 63 General ................................ 63 In-line oscillations ........................ 64 Cross-flow oscillations .................... 64

Recommended values of hydrodynamic coefficients .............................. 64 General ................................ 64 Added mass coefficient. ................... 64 Drag coefficient. ................. ; ....... 64 Lift coefficient. .... , ..................... 64

Wave slamming ......................... 64 Wave slamming loads .................... 64 Fatigue due to wave slamming ............. 6 5

Appendix B Buckling calculations

B.l Local buckling ........................... 6 8

B.2 Propagation buckling . . . . . . . . . . . . ... 68

B.3 Buckling of the pipe as a <<bam ............. 69

Appendix C Quality control of materials.

Qualification of welding procedures and welding per­sonnel

C. I General. .. , . . . . . . . . . . . .......... 7 0 C.l.l Scope. . . . . . . . . . ....... 7 0 C.l.2 Defmitions .............................. 70 C.I.3 Testing equipment ................... , .... 70

C.2 Steel making . . . . . . . . . . . . . . . . . . . ........ 70 C.2.1 General . . . . . . ...................... 70

C.3 Steel casting. . . . ........... , ......... 70 C.3.1 General . . . . . . . . . . . .............. 70

C.4 C.4.1

C.5 C.5.1

C.6 C.6.1

C.7 C.7.1 C.7.2 C.7.3 C.7.4 C.7.5 C.7.6 C.7.7 C.7.8

C.8 C.8.1 C.8.2 C.8.3

Chemical analyses . .... . . .......... 70 General ............ . . .............. 70

Heat treatment ............ 7 0 General ................................ 70

Surface defects in base material ............. 70 General ................................ 70

Mechanical testing ....................... 71 General ................................ 71 Tensile testing ........................... 7 ]. Benct'testing ............................. 71 Nick break testing ....•...... ' ............ 71 Charpy V -notch impact testing ............. 71 Macrosection of welded joints .............. 71 Hardness testing of welded joints ............ 71 Strain ageing testing ...................... 71

Sampling of test specimens . ................ 7 2 Seamless pipes. . . . . . . . . ............... 72 Welded pipe ............................ 72 Cold formed or forged bends ............... 72

C.8.4

C.8.5

C.9 C.9.1

C.IO C.IO.l C.l0.2 C.I0.3 C.I0.4 C.l 0.5

C.I0.6

C.l0.7

Forged seamless piping components other than bends ................... - - - - - . · · · · · 72 Cast piping components . - .. · - - - · · · · · - · · · · · 72

Welding procedure qualification - - - .... · · · · · 72 General ..................... --.---··-·· 72 Qualification of welding personnel .......... 72

~;.~e~~ldl~~ : : : : : : : : : : : : : : : : : : : : : : : : : : : : ; ~ Inspection and testing of qualification test welds 7 3 Welder qualification ..................... - 7 3 Welding operator qualification for mechanized welding ...................... 7 3 Qualification of welding personnel for underwater welding ...................... 7 3 Extraordinary requalification of welding personnel ............................... 74

Appendix D Guidelines on corrosion control

D. I Design of cathodic protection systems ........ 82 D. I.! General ................................ 82 D.l.2 Design basis ............................ 82

0.1.3 D.J.4 D.I.S D.I.6 0.1.7 D.I.8

0.2 D.2.1 D.2.2

D.2.3

Current demands - - . - - - - .......•. 82 Anode materials ... - - . - -- · ... - - .... : ... : . 83 Current output capacity of anodes ........... 84 Calculation of anode life ................... 84 Current distribution - 84 Fabrication of anodes ..................... 84

Standards for coating . . . . . . . . . . . . . . . . _._·'84 General .......... -- ... -- .... - .......... 84 Acceptable standards for coating properties . and test methods referring to generic type .. , . 84 Application and inspection of coatings. general standards · · · · · · · · · · · · · · · · · · · · · · · ·8?

Appendix E . _ . Pressure testing of pipelines and pipeline sections

E.l General ... · · - - - · - · · · · · · - · · · · · · • · · · · · · · 8? E.2 Pressure test method no. 1 ........... - .... _- 87 E.J Pressure test method no. 2 ........... : . . . . 87

E.4 Acceptance criteria ..................... :. 8] E.S Witnessing ................. · - . · ... · · ... · 88

E.6 Hydrostatic test report . . . . . . . . . . . . . . . . . . 88

a a, B B b,

c Co (::L Cm c. d <i D D, E g F•

SECTION 1 GENERAL REGULATIONS

1.1 Symbols

cross sectional area of pipe. also:

(n). p

exposed area of anode . . Per parameter used in wave analyses. (Defined m F1g. A2). also: acceleration relative acceleration ·

= buoyant force per unit length of pipe, also: = width of reference block

p, P; Ppr

:'!T> = parameter used in wave analyses. (Given in Table Q

AI) Q shape(drag) coefficient used in wind force formula drag C9"fficient lift coefficient ·added mass coefficient slamming coeffiCient water. depth.ll)so:

= di'lffiO(er = nominal outside diameter of pipe = total outside diameter of pipe (including coating) oc m<>Qulus of elasticity, also: = . col)Sumption rate of anode "= iota! horizontal (Ja\erall force per unit length of a pi-

pe due to drag and inertia = dragforce

tift force

q

R, r s s &":,> ·s p

T T T, T,

mass<inerpal force Tv wave slamming force 1 total vertical force per unit length of a pipe due to U dn!g and inertia coefr!cient offriction, also: vortex shedding frequency natural frequency for cross-flow excitation naturll) frequency for inline excitation clearance between pipe and fixed boundary, also: wave height significant wave height

u u /u/

~yi,slljll wave height» v, the most "probable largest" wave height out of 10" v. waves encountered w referencevalueofH •• i.e. for n = r IDeal! <;Um;nt requirement per anode d.iam~~r factor, also: slope of the S·N curve Keu10gan-Qu-penter number stability parameter roughness parameter in wave analyses (Table AI) ~mperature derating factor length of reference block, also: effective life of anode Sll$peDded length, span width bending moment in pipe critical bending moment

"'_ to~onll) moment in pipe . . = parapteter used in wave analyses. <Defmed m F18-

A.2l · effeCtive mass per unit length of pipe

axial force in a pipe. also: number of years in a probability consideration critical axial force in a pipe

w w X y y a a a

y

«eqlJivaleJ)I>> axial force in a pipe subjected to inter· nlll ;llld/ or external pressure nUmber of constant amplitude stress cycles «u )) to ~: failure criticlll number of stress cycles exponent when number of waves is expressed as a power of 10 . actual number of stress cycles of a gtven stress ran· 8!'<..), . number of waves within block j

a, a,. Of o, (u);

= perrnissJ.ble value of n1 = pressure. difference between two absolute pres-

sures. external over·pressure :: critical external over~pressure = external pressure = internal pressure = propagation pressure

initiatioJl pressure frequency distribution of average apparent wave periods shear force nominal to pipe axis, also:

= probability level = lateral force per unit length of pipe = wind force per unit length of pipe

reduction factor on number of waves = Reynold'snumber = reference value of n = safety factor in on-bottom stability analysis, also: = Stroubal' s number = Miner's sum = permissible value of Miner's sum = number of stress blocks = . thickness of reference block, also: = average zerc>-upcrossing period = pipe material temperature at time of installation = pipe material temperature under considered condi-

tion = «visual)> wave period = nominal wall thickness of pipe = flow velocity for anodes = utilization factor, also: = liquid particle velocity noma! to pipe axis = absolute (positive> value of u = current velocity = resulting «design» velocity due to wave and current = maximum orbital particle velocity = particle velocity due to «design>> wave = ·flow velocity for anodes = relative water particle velocity = component of wind velocity_ no~al-to pipe axis . = weight per unit length of ptpe m aJT, ~eluding PIJ'C'

contents and water absorbed by the coattng, also: section modulus of pipe cross section, also:

= netweigbtofanodes = longitudinal position_of a point on a pipe.

circumferential position of a pomt on a pipe, also: modesbape · . linear coeffiCient of thermal expanSion, also: symbol used in buckling formula logarithmic decrement of structural damping usage factor usage factor for equivalent stress usage factor for hoop stress permissible usage factor _ . permissible usage factor when a,IS acting alone permissible usage factor when u,is acting alon_e angular position of a point on a ptpe relative to a defmed radius e = 0 mode shape parameter Poisson's ratio, also: kinematic viscocity of a liquid IDa:~' density. also: resistivity element stress due to net buoyancy force critical one dimensional compressive stress for com­pletely elastic buckling (a,E or a,.> equivalent stress according to von Mises permissible equivalent stress specified (nominal) yield strength stress range stress range for stress <<block» no i

Cixcr

a~

r,, i'xz

element stress due to vertical wave force element stress due to net buoyancy force longitudinal stress critical longitudinal (compressive) stress longitudinal stress due to pipe bending, defined as M/W longitudinal stress due to axial force = N I A critical ax when M is acting alone critical r7x when N is acting alone permissible ax

longitudinal stress due to shell bending hoop stress critical compressive hoop stress permissible hoop stress (in tensionl critical compressive hoop stress for completely elast­ic buckling when rr, is acting alone tangential shear stress radial shear stress

1-2 Technical terms

Longitudinal stress = normal stress acting parallel to pipe axis.

Hoop stress = normal stress acting in the circumferential di­rection.

10

Maximum operating pressure = maximum pressure to which a piping system will be subjected in operation. which should include static pressure and pressure required to over~ come friction.

Surge pressure = total pressure caused by a change in ve­locity of flow within a pipeline system. '

Test pressure = pressure specified to be applied to a vesset pipe. component. etc .. on completion of manufacture and/ or on completion of construction. It may also Pe the pressure specified to be applied to a vessel. etc., after appropriate per­iods in operation.

Strength test pressure = pressure of a higher magnitude than test pressure and with short duration.

Leak test pressure = pressure normally of a lower magnl· · tude than test pressure and with at least the same duration.

Minimum design temperature = lowest possible steady state temperature which the pipeline system experiences during installation and operation. Environmental as well liS opera­tional temperatures are to be considered. "I

Maximum design temperature = highest possible steady sta~ temperature which the pipeline system may be exposed to during installation and operation. Environmental as well liS · operational temperatures are to be considered.

Tangemial shear stress = shear stress which in a cross sec- Restrained lines = pipelines which cannot expand Of coq: tion of the pipe acts in the tangential (circumferential) direc- tract in the longitudinal direction due to flxed supports or tion. friction between pipe and soil. ' · ''

Radial shear stress = shear stress which in a cross section of Understrained lines = pipelines without substential aJI:ial r"'i: the pipe acts in the radial direction. traint (Maximum one flxed support and no substential fric­

tionl. Pipe bending moment = bending moment (M) in the pipe cross section as a whole.

Shell bending moment = bending moment (m,or m,) in the pipe wall per unit length.

Suspended length = length of a pipeline without contaci with the sea bottom or other supports ( = unsupported length). .. ,'.: , ... ,~'c·"'-"'-"'·""'?

Pipe bending stresses bending moment. .

Laying parameters = essential parameters affecting the stres'­Iongitudinal stresses due to pipe ses in a pipeline during laying. such as applied tension. stin-"

ger curvature, etc.

Shell bending stresses = stresses due to shell bending mo- Nominal wall thickness = the pipe wall thickness that is sp~ ment. cified for supply of pipes.

Longitudinal shell bending stresses = · longitudinal stresses Nominal pipe diameter = the outside pipe diameter to be u~-(a, ~due to longitudinal shell bending moment(m). ed in the design calculation.

Hoop bending stresses = hoop stresses (a/l due to circum-ferential shell bending moment (hoop· bending· moment -m,J

Direct stresses :;;; stresses of which the resultant acts in ~ middle surface of the pipe wall ( = membrane stresses>.

Internal pressure = pressure inside the pipe. May be given as absolute pressure or gauge pr~ure.

External pressure = pressure (immediately) outside the pipe. May be given as absolute pressure or gauge pressure.

Overpressure = difference between two absolute pressures.

Initiation pressure = external overpressure required to initi­ate a propagaiing buckle from an existing , local buckle or dent. ·

1.3 Definitions

1.3.1 Pipeline system

By a pipeline system is meant an interconnected system of submarine pipelines, pipeline risers. their supports. all in­tegrated piping components. the corrosion protection system and weight coating. '

1.3.2 Submarine pipeline

A submarine pipeline. later referred to as pipelin~- is defin~ as that part of a pipeline which is located below the water surface at maximum tide- except pipeline risers (see 1.3 .•f). The pipeline may. wholly or in part be suspended above th~ sea floor, rest on the sea floor or be buriecl below the s""· floor. . ' Propagation pressure = external overpressure required to

propagate a buckle that has been initiated ( at ~ higher pres-sure). 1.3.3 Riser system

Design pressure :;;; maximum internal operatina pressure. By riser system is meant the riser. its suppol't$. all integraied piping components and corrosion protection system.

1.3.4 Pipeline riser

A pi~line riser, later referred to as riser. is defmed _as th_e connecting piping or flexible hose between a submarme pl­

. pellne on the sea floor and the processing equipment on a ~tform. Exact points of riser termination are to be agreed ·ron in eash case.

1.3.5 External riser

·By external risers is meant risers which are mounted in such a ·way that no effective shelter against the action of wind. wa­Y~· and currents is provided.

1.3.6 Internal riser

'By iilternal risers is meant risers which are effectively shelter­e4 against the action of wind. waves and currents.

1.3.7 Riser support

II

1.3.17 To survey

By to survey is normally meant to carry out surveillance on behalf of Veritas.

1.3.18 A survey

By a survey is meant the general inspection carried out by the Owner, by his ·contractor or by Veritas.

1.3.19 Surveyor

By a Surveyor is meant a person carrying out surveillance on behalf of V eritas.

1.3.20 Liquid hydrocarbons

By liquid hydrocarbons is meant crude oil, condensate. natu­ral gasoline. natural gas liquids. liquefied petroleum gas, pet­roleum products and their fractions in their liquid phase.

By riser supports is meant structures intended for fiXing the 1.3.21 Gaseous hydrocarbons riser to the platform or for local or continuous guidance of By gaseous hydrocarbons is meant hydrocarbons in a vapor the riser. · phase from wells drilled· Tor the purpose of producing liquid

hydrocarbons or natural. gas. 1.3.8 Pipiog components

· BY piping components is meant items integrated in the pipeli­ne/ li,ser such as flanges. 1ee1;, bends. reducers and valves.

1.3.9 Splash zone

By the splash zone range is meant the astronomical tidal ran­ge plus the wave height having a probability of exceedance of O.Q 1. The upper limit of the splash zone is determined by as­suming 65 96 of this wave height above HAT and the lower limit by assuming 35 96 below LAT.

\,-3-10 Submernd zone

. Jy the submerged zone is meant the region be_Iow the splash zone including sea water, sea bottom, and buned or mud zo-

By the atmospheric zone is meant the region above the splash zone.

1.3.12 Platform

By a platform is meant a flxed or permanently anchored off­shore installation onto which the riser is mounted.

1.3•13 Zone 1

By Zone I is meant the part of the seabed located more than a certain distance away from any platform or building, nor­mally to be taken as 500 m.

1.3.14 Zone 2 -By Zone 2 is meant the part of the seabed located close to any platfor111 or building. and normally to be taken as a distance of 500 m.

1.3.15 Surv!:~Jiance

By surveillance is meant the work carried out by V eritas in order to assure that the pipeline or riser is built and operated in accordance with the Rules. This work comprises approval of d!'awiflss. procedures and specifications an<l inspection Ed <Xl!itrol during prefabrication and installation. It also in­. des the work carried out by Veritas in order to assure that

e in•service inspection and maintenance are carried out ac­cording to these Rules. This surveillance is not meant to re­PliiCe the quality control program of th~ contractor/ operator.

1 ,.U ~ I!IS!'ection

· By insPection is meant the quality control carried out by the Owner or his contractors.

1.3.22 Fluid

By fluid is meant a gas. liquid or slurry that is transported through the pipeline system.

1.4 The Rules

1-4.1 Application

1.4.1.1 These Rules apply to submarine pipeline systems as defmed in 1 .3 .1 intended for the transportation or transporting liquid and gaseous hydrocarbons as defined in 1.3.20 and 1.3.21. The Rules may also be applied. wholly or'in part. to pipeline systems carrying other products. This is to be decided by V eritas in each separate case.

1.4.2 Amendments

1.4.2.1 Amendments to the Rules may be undertaken at any time and may also be applicable for pipelines or risers which have already been approved by Veritas.

Unless otherwise decided. the amendments are to come into force 6 months after the date of issurance.

1.4.2.2 Application of amendments to pipelines or risers al­ready approved. or in the process of approval. will be limited to cases where it is judged essential to the structural integrity. If amended requirements to construction, materials, dimensi­ons. etc. are to be made applicable to pipelines or risers al­ready approved, necessitating re-analysis and re-evaluation of strength 'requirements, this will be clearly stated in the amendments.

1.4.3 Alternative methods and procedures

1.4 .3 .1 V eritas is prepared to consider alternative methods and procedures found to represent overall safety and strength standards equivalent to those of the Rules.

1.4.4 Assumptions

1.4.4.1 These Rules are based on the assumption that pipe­line or riser in question is designed, constructed and operated by adequately skilled personel according to sound engineer­ing practice.

I .4 .4 .2 The Owner and or his contractors are to establish and implement a detailed. independent q~ali~ control system covering all phases involved by the Certification. The quality control functions are to be directed and performed by compe­tent persons.

1 .4.4.3 It is assumed in these Rules that external risers on platforms and similar structure:' are ad7quately pro~ted from impacts from vessels and sunilar acc1den~ mechamcal influence. Hence it is assumed that the protectmg structure. and not the riser, is designed for such loads.

1.5 Certificate of Compliance

1.5.1 .Issuance of the Certificate

1 .5 .I. I Upon request Veritas is prepared to issue a Certifi­cate of Compliance for pipeline systems when found to be de­signed and constructed in accordance with these Rules.

1 .5 .I .2 The client requesting certification is to'

12

submit required documentation with complete and correct information of significance for certification. see 1.8 .I . pay all expenses which arise in connection with the sub­mitted request.

1.5 .1.3 The Certificate of Compliance will be issued after V eritas consideration of all relevant documents and declara­tions of survey concerning the pipeline system in question. The Certificate will contain'

a description of the pipeline system and its function. . . a specification of the operational limitations for the p1peh· ne system. . . . . a specification of the geographical Jocat1on of the p1pelme system. a statement that the pipeline system is designed and con­structed in accordance with these Rules and under the sur­veillance of Veritas.

(.5.1.4 Individual Statement of Compliance may upon re­quest be issued for design, fabrication, installation or testing.

1.5.2 Recommendations

1.5.2.1 On matters considered to represent a possible safety hazard Veritas will issue separate recOmmendations.

1.5.2.2 Recommendations may be issued to the effect that specified actions (e.g. repa.ir$) or specified surveys are to be carried out within· specified time limits. Recommendations may also be given regarding reduction of permissible loading.

1 .5.2.3 Once a recommendation is formally issued the validi­ty of the Certificate of Compliance is conditional upon com­pletjon of the required work before the expiry date. The Ow· ner is expected to take the necessary steps to fulfil the cond1· lion without further action from Veritas. Should circumstan­ces occur that make the fulfilment of the recommendation im­practical before the expiry date. or that requires the recom­mendation to be altered. the Owner"s r~quest for a change of extention of the recommendation should be made in g~ time before the expiry date.

1 .5.2.4 The Owner sllould notify V~r!tas when a recom­mendation has "been completed so that a completion survey may be carried out before expfry of the time limit.

1.5.2.5 Updated lists of recommendations will be forward­ed regularly to the Owner and to the Surveyor carrying out the surveillance.

1.5.3 Memoranda for Ow11ers

1 .5.3.1 Memoranda for Owners are information to the Ow­ners regarding observed damage. deterioration or other sig­nificant change in a structure which does not justify the issu­ance of a recommendation at the present time.

1.5.3.2 Updated lists of these memoranda will be forward­ed regularly to the Owner and to the Surveyor carrying out the surveillance.

1.5.4 Withdrawal of Certificate

1.5 .4.1 Veritas reserves the right to withdraw the Certificate of Approval if the Owner fails to comply with_ the directives of operating the system within the spec1fied hm1ts.

1.5.4.2 Withdrawal may also take place when the Owner fails to carry out regular in-service inspection and mainten• ance according to the specifications for such inspection ~n9 maintenance. Such work is to be survey~d by Veritas. see Section 9.

1 .5 .4 .3 Any of the events mentioned below may lead to withdrawal'

The pipeline system is damaged. or is suspected of having been damaged. in a manner likely to impair its safety. strength or stability. · The pipeline system demonstrates signs of deterioration likely to impair its safety. strength or stability. The pipeline system is subjected to any alteration. repair or replacement which will impair the operational safety.

1 .5.4.4 The withdrawal may be made conditional, in that it will be executed only if the Owner has failed to carry out his obligations within a stipulated time period.

1.5.4.5 If the situation leading to withdrawal of the Certifi­_cate of Compliance no longer exists. the Certificate may be reinstated. As a condition hereto. Veritas can requir-e that th~; pipeline system will be subjected to certain specified surveys tests or imp~ovements..

1.6 Concept evaluation

1.6.1 General

1.6.1.1 Prior to the detailed design. the overall concept of the pipeline system is to be checked in order to identify pos­sible weal( points or unacceptable desJgns. Th1s applies to such as:

selection of pipeline route and protection methods location and protection of riser location and protection of landfall possibilities for pigging. inspection and monitoring of the pipeline choice of Codes.

1.6.1.2 Accidental situations should be taken into account in the detailed design.

1 .6.1 .3 Special attention should be paid to protection of and to the possibilities for inspection and maintenance of gas r~­sers inside waterfilled or closed companments. and to gas li­nes near platforms and populated areas.

1 .6.1.4 For systems that involve new technology _it may be recommended to carry out an overall safety analysis.

1.7 Instrumentation for monitoring o~ the pipeline system condition

1.7.1 General 1.7.1.1 By instrumentation is meant special devices foro~ servation and monitoring of the loading. response and cond1· tions of the pipeline system during fabrication. installation or operation.

J .7. J .2 Instrumentation may be required when visual . in­spection or simple m~uremen~ are not considered ~racuca­ble or reliable. and available desogn methods and prevtous ex­perience are l)ot sulfJCient for a reliable prediction of the per­formance of the pipeline system ..

(

1.8 Documentation

1.8.1 Submission of documentation

(.8.1,1 This section outlines the documentation required in order to obtain a Certificate of Compliance. Detailed require-

I 3

1.8.2.6 Materials and fabrication of pipes and components. The following is to be submitted for approval'

Material specifications for pipes. piping components, sup­ports, bolts. nuts and welding consumable.

- Fabrication specification of pipes. piping components and supports. l"~ts to the documentation is described in the respective main

k:t10ns. 1.8.1.2 Documentation essential for ·the understanding of 1.8.2.7 Corrosion protection. The following information is

to be submitted for approval' the pipeline system and necessary to prove its safety is to be Specification for coating and coating application. includ-submitted Veritas. ing field joint coating

Specification for anodes 1.8.2 Design phase

1.8.2.1 The Owner is normally to submit to Veritas the de­~ign documentation before fabrication and installation com· me~e-

1.8.2.2 Concept evaluation. The following is to be submit!· ed for information' ' w aier depth along the pipeline route ...,. Pipe dimensions

Fl\Jid to be tnansported Pesi&n life Maximum and minimum design temperature Design pressure Project schedules

. , plans for known future developments along the pipeline route

'Type and grade of material Corrosion protection system

The following is to be submitted for approval: · '" . Overall drawing(sl showing location of the pipelines rela­

tive to platforms. buildings, populated areas, ship lanes and harbours and other items or activities essential for the safety of the pipeline.

·): Platform layout with risers, riser protection system. cra­nes. ·living ·quarters. boat landing area as well as rescue area clearly marked.

Specification of cathodic protection system including de­sign calculations Description of anode location Drawing of anode. including rebar and earthing connec­tion Specification for protection of risers and pipelines in criti­cal areas such as in splash zone, J-tubes. tunnels. Specification for internal corrosion control .

I .8.2.8 Construction. The following information is to be submitted prior to start of construction.

Construction procedure specifications including installa­tion. tie-ins and protection Description of construction vessels and equipment Specification for installation welding Description of quality control system including speciflca· tion for non-destructive testing Specification for fmal surveys and tests

1.8.3 Fabrication phase

I .8.3.1 During and/or after fabrication the following doc­umentation is to be submitted:

Material certificates for pipes. piping components. riser supports and anodes Fabrication procedure qualification report including welding procedure qualification record

....... ,..;;"':"'l"'"·'·i:" . .,:.cc: h8::! . .J .::Environment. The following is to be presented for Qualification record for welders and welding operators Hydrostapc testing reports Production test records (visual. NDT. dimensional) Reports on coating

information and evaluation: SoU properties relevant for foundation evaluation Bottom topography Wind and wave conditions . Current and tide conditions Maximum and minimum seawater and air temperatures

. .. Corrosivity Ice conditions Seismic activity Marine growth

J .8.2.4 Loads. The following is to be presented for in­formation: ~ Any loads during fabrication. installation and operation

which may govern the design.

The following is to be presented for approval: - Calculation of functional loads - Calculation of environmental loads

1.8.2.5. Strer~gth and inplace stability. The following is to be submitted for approval: -, SIJ'uctural drawings of risers and riser supports.

Structural drawings of special pipeline geometries such as expansion loops. crossings and laterals. Structural drawings of non-stan~dized piping compo­~ents such as tees. reducers. connectors etc.

·) On bottom stability analysis. Structural analysis. including control against excessive yielding. fatigue failure. propagating ductile fracture and brittle fracture as applicable. Structural stability analysis. including control against buckling and excessive displacements. PYnl!llliC analysis. including vibration analysis. if rel-'evarit. ·

' Foundation analysis. including sea bottom stability.

1.8.3.2 Material test certificates for pressurized parts are normally to be endorsed by V eritas.

1.8.4 Installation phase

I .8 .4.1 During and/ or after construction the following doc­umentation is to be submitted:

As-laid alignment sheets As-built drawings of special pipeline geometries such as expansion loops and crossings As-built drawings of riser systems As-built isometric drawings of risers showing the location of each item and weld and with reference to their item/ heat/ number/ certificate and heat treatment report num­ber if relevant Non-destructive testing records As-built drawings of non-standardized piping compo­nents such as tees and reducers Post weld heat treatment report Dimensional control report if relevant Final inspection report Hydrostatic test report Report on pigging and drying (if relevantl Report on performance of the cathodic protection system Report on trenching/ protection

1.8.5 FUlng of documentation

1.8.5.1 It is the Owners responsibility to keep complete fi­les on all relevant documentation during the life of the pipeli­ne system. Documentation to be med is at least as defined in 1.8.2-1.8.4. The me should include the necessary reports from operation. in-service inspection and maintenance.

14

SECTION 2 ENVIRONMENT

2.1 General

2.1.1 Environmental phenomena

2. i .1 .l All environmental phenomena which may impair the proper function of the system or cause a reduction of the system reliability are to be considered. Such phenomena in· ch.:d~ wind, waves. currents. ice, seismic. geological, and geo­technical conditions. temperature. fouling. biological activit· ies. chemical components of water. and transported fluid etc.

2.1.2 Acceptable environmental data

2.! .2.1 The environmental conditions are to be described using adequate data for the areas in which the system is to be installed.

2.1.2.2 Data supplied by generally recognized consultants will normallY be accepted as a basis for design. Background information on data collection and derivation is to be sub­mitted on Veritas" request. -

2.1.2.3 The various environmental factors are to be describ­ed by characteristic parameters based !=m statistical d~ta or long term observations. If sufficient data directly applicable for location in question are not available. reasonably conserv­ative estimates based on relevant data for other relevant loca­tions may be used.

2.1.2.4 Statistical data are to be utilized in describing en­vironmental parameters of a rand~m natur~ (e.~. waves. wind}. Proper care is to be exercised in deriving such par­ameters in a statistically valid manner. and geJ;l~rally accepted methods are to be used. ' ,

2.2 Pipeline route

2.2.1 Location

1.2 1.1 The route should be selected with due regard to the probability of damages to tbe pipe and. the consequences of a possible pipe rupture. Factors to take into consideration are: - population density - location of living quarters - ship traffic -.-fishing activity - o!Tshore operations - unstable seabed - corrosivity of the environment Known future operations in the vicinity of f.he route is to be tak~n into consideration.

2.2.2 Route suney

2-2.2.1 A detailed route survey is to be performed to pro­vide sufficient data for design and construction.

2.2.2.2 The route survey is to cover sufficient width and ac­curacy to permit the safe and proper installtion and operation of ihe pipeline. '

2.2 .2 .3 The accuracy needed may vary along the proposed route. A higher degree of accuracy is required in areas where other activities. obstructions or highly varied seabed topogra· phy or subsurface conditions may dictate more detailed in· vestigations.

2.2.2.4 A proper investigation to reveal pQssigle conflicts with existing or planQed ipstallations ~ t<? be perfoqned. Ex­amples of such installations are other submarine pipelines and communication cables.

2.2.2.5 The intended pipeline route is to be surveyed for wrecks and obstructions down to a depth exceeding that reached by the pipeline during installation. burial or opera· tion.

2.2.2.6 The results of the survey are to be presented in an accurate route map indicating the location of the pipeline and related facilities and the seabed properties. See 2.2.4. ·

2.2.3 Bottom topography

2.2 .3 .I All topographical features influencing the stability and installation of the pipeline are to be covered by the route survey. The survey is at least to define' ,

obstructions in the form of rock outcrops. large boulders etc. that could require levelling or removal· op~r~tiQn$: prior to pipeline installation . '·_, topographical features that contains potentially unstable slopes. sand waves. deep valleys and erosion in fopri of scour patterns or material deposits. ·

2.2.4 Seabed properties

2.2 .4.1 All the geotechnical properti~;>. . ~~~~slu:y ~ fqr . evaluating the effects of relevant loading conditions are to be determined for the subfloor deposits. This should include possible unstable deposits in tbe vicinity of the pipeJjne. '

2.2 .4 .2 The geotechnical properties may be ol;>taiped through a combination of seismic $UrYey. coring. in s.itti tes~ and borings with sampling. · ··

Supplementary informations may be obtained from gwlogi· cal surveys. sea bottom topographicid SUrveys~, visl,l31 'sur veys. biological investigations. chemical examinations and la-boratory testing on samples from borings. ,,

Guidelines for site and laboratory ,.testing maY· be f'!"'n<J,:i"'~""-::;:. Veritas" Technical Note TNA 302. ·

2.2.4.3 Special investigations of the subfloor deposits may be required to evaluate specific problems. Examples of such problems are:

ease of excavation and/ or burial operations. possibilities of flow slides or liquefaction as the result of repeated loadings.

2.3 Environmental conditions

2.3.1 General

2.3 .I . I Possible effects of the various environmental actions are to be taken into account to the extent relevant to the si­tuation considered.

2.3.2 Tide

2.3.2.1 Tides are to be taken into consideration when the water depth is a significant parameter. such as when deter .. mining wave loads on a riser. planning laying- operation~. de­termining maximum or minimum water pressures etc.

2.3.2.2 The- assumed maximum tide is to include both as­tronomical tide and storm surge. Minimum tide estimat~ should be based on the astronomical tide and possible 11ega· live storm surge. · ,,

2.3.3 Wind

2.3.3.1 Direct actio!! of wind is to be taken into co~sidera· tion for slender risers. The possibility of vibrations of such ri­sers excited by winQ is to be considered. Special atten~ion ~s

to be paid to wind loads in the construction and transporta­ti0!1 phases.

2.3.3.2 For risers the wind data used are in principle to be tile same as those used for the design of the platform.

}.3.3 If the riser is positioned adjacent to other structural parts. possible effects due to disturbance in the flow field should be considered when determining the wind loads. Such erf~ts may either be caused by an increase or reduction of t~e wi~d speed. or by dynamic excitations caused by vortexes Sh~d from the adjacent structural parts.

2.3-4.1 The effect of waves is to be taken into consideration for both pipeline and riser. Examples of·such effects are the aGli9P' of wave forces on riser or on pipeline during installa· tion or when resting on bottom (not buriedl. Examples of indi· f~t effeCts ·are deformation of riser due to wave forces acting

lh¢ platform. and deformation of pipeline due to Jay barge rrtQtions in waves. P=ible Jiquifaction and transportation of sea bed material is ~lsO tQ be considered.

2.3.4.2 If the riser is positioned adjacent to other structural partS. possible effects due to disturbance of the flow field

,·.sh9uld be considered when determining the wave loads. Such effects may either be caused by changes in the wave pa~icle kinematics. or by dynamic excitation caused by vor· tex~s shed from the adjacent structufal pans. '

' 2.~ .4.3 For riser the wave data to be used are in principle to be the same as those used for the design of the platform.

2).4.4 For the assessment of wave conditions along the pi· ''-"'"·''··"· .: :·,··~Nn~line route a limited number of intervals may be assumed.

1': tn of which being characterized by water depth. bottom to­pography and ?ther factors affecting the wave conditions.

2.3.5.1 The effect of current is to be taken into considera­tiO!J for both pipeline and riser.

2.3.5.2 The assumed current velocities are to include pos­sibi~ contributions from tidal current. wind induced currents. sto'rm surge current. density current and possible other cur­

,_ rent phenomena. For near shore regions longshore current dl.le to wave breaking should also be considered.

2.3.5 . .Jr. The tidal current may normally be determined from harmonic analyses of recorded data. while wind induced-. storm surge and density currents may be determined either from statistical analyses of recorded data. or from numerical simulations.

15

salinity oxygen content pH-value resistivity current biological activity (sulfate reducing bacteria etc.)

2.3.7 Ice

2.3.7.1 In case the installation is to be located in an area where ice may develope or drift. proper consideration of ice conditions and their possible effects on riser or pipeline is to be made. The ice conditions should be studied with particular attention to possible:

ice forces on riser and on pipeline potential scour at pipeline location and contact with pipe­line by floating ice ice problems during the installation operations

2.3.7 .2 The description of ice conditons should preferably be in accordance with the cc\'\.:orld Meterorological Organiza­tion Sea-Ice Nomenclature>).

2.3.8 Air and sea temperatures

2.3.8.1 Reasonably accurate air and sea temperature statist­ics are to be provided. These data are important for proper determination of design temperatures. possible thermal stres­ses. deformations. displacements. etc.

2.3.8.2 The period of observations on which tbe maximum and minimum air and sea temperature statistics are based. should preferably be several years.

2.3.9 Marine growth

2.3.9.1 The effect of marine growth on riser and pipeline loads is to be considered. taking into account all biological and environmental factors relevant to the site in ques;tion.

2.3.9.2 For determination of the hydrodynamic loads spe­cial attention is to be paid to the effective diameter increase arid the equivalent roughness of accumulated marine growth when determining the hydrodynamic coefficients.

2.4 Internal pipe conditions

2.4.1 Installation conditions

2.4.1.1 A description of the internal conditions during stor­age. installation. and pressure testing is to be prepared. Of

. . special concern is the duration of exposure to sea water and !'Jormally a wmd mduced surface curre~t speed cor~espond-,.:...·~,..moist air. and whether inhibitors are 10 be used. tng to 2 per cent of the I hour mean wmd speed will be ac- See section 4. 5 and 6. 10epted.

2.3.5.4 In regions where bottom material may erode. spe­cial studies of the current conditions near the bottom includ­ing boundary layer effects may be required for onbottom stability calculations of pipelines.

For risers and for pipelines during laying reasonable a~umptions should be made as to current velocity distribu-

1' over the depth. For risers this is normally to be the same !use(! for the platform.

2.3.6 Corrosivity

l~l.6,1 For the evaluation of the corrosion protection sys­tem the following properties. with seasonal variations of the

water ami soil along the route are to be considered' tc;m~rature

2.4.2 Operational conditions

2.4.2.1 The physical and chemical composition of the pro· duct and the pressures and temperatures along the pipeline are lo be specified.

2.4.2.2 Limits of :emperatures and pressures. and allowed concentrations oi corrosive components for the product to be transported are to be specified. Of special concern is the con· tent of

sulphur compounds water chlorides oxygen carbon dioxide hydrogen sulphide.

16

2.5 Design temperature

2.5.1 General

2.5.1.1 Minimum and maximum design temperatures for pipeline system is to be established for selection of adequate materials for pipes and coating. See section 4. 5 and 6.

2.5.2 Differentiated design temperatures

2.5.2.1 When estimated operational and environmental temperatures vary significantly along the pipeline. a differ­entiated design temperature for different intervals or sections of the pipeline system may be specified.

17

SECTION 3 LOADS

3.1 Loading conditions and design conditions

3.1.1 General

\ .1.1 In order to relate permissible stresses or strains to the probability of the loading and the risks involved these Ru· les define two loading conditions and tV{O design conditions.

3.1.2 Loading conditions

3.1.2.1 Any part of the pipeline system is to be designed for the most unfavorable of the following loading conditions:

al Functional loads b) Design environmental loads and simultaneously acting

functional loads

Functional loads and design environmental loads are defined in 3.2 l'nd 3.3

3.1.2.2 For each of the above loading conditions and for each member or cross section to be considered. the most un· fav9urable relevant combination. position and direction of forces which may act simultaneously are to be used in the an· !j,lni~.

3,1 .2J All direction of wind. waves and current are to be ~umed equally probable. unless statistics show clearly that wind. waves and current of the prescribed probability are dif· ferent for different directions.

3:1.3 Design conditions

3 .. 1.3.1 )loth loading conditions defined in 3.1.2.1 are to be considered for all different conditions or phases relevant to ~:Je pipeline ·or ris~r in question.

3.1 .3 .2 With respect to levels of permissible stresses _ccc . ..:c.cc::::c:::c""' a,ny situation or phase is to be referred to one of the

design conditions:

3.2 Functional loads

3.:~:\. General

3,2.).1 · Functional loads are loads which are necessary con­Sequences.of the system"s existence~ use and treatment in the Various situations under ideal conditions. Ideal conditions

no wind. waves etc .. i.e. no environmental loads act-_. :1.2.1.2 Functional loads which normally are to.be consid· ~red for the operation and installation phases are given in 3.2.2 and 3.2.3.

-· ~·~:l : .. Functional loads during operation

·3:2.2.1 Functional loads during operation will normally be those (!ue to

)"•igpl pr~ure

. ~hermal expansion and contraction prestressing.

Weight is to includ"' of pipe. including coating and all attachments to

Note that weight of transported contents and buoyancy will not have the sam~ effect on stresses as weight of pipe if the p1pe IS vertical or mclined. See also 3.2.3.2.

3.2.2.3 Pressure is to includ"' internal fluid pressure.

-- external hydrostatic pressure. - soil pressure for buried pipes.

3 .2.2 .4 Thermal expansion and contraction loads are pri· marily to include the effect of product temperature on mate­rial temperature. Possible other causes of changes in material temperature are also 'to be considered. The temperature dif· fere.nce to be c:onsidered is that between material temperature ~unng operatiOn and material temperature during installa· uon. (Loads due to thermal expansion of an enclosed fluid are to be included in ~<internal fluid pressure>~ mentioned in 3.2.2.3)

3.2.2.5 Thermal expansion or contraction loads do not ha· ve to be taken into account when they do not influence the capacity to carry other loads. Fluctuation in temperature may cause fatigue and be taken into account when checking fati· gue strength.

3.2.2.6 Prestressing. such as permanent curvature or a per· manent elongation introouced during installation. is to be ta­ken into account to the eXtent the capacitY to carry other loads is affected by the prestressing.

3.2.2.1 The functional loads are mainly static. Exception may be internal fluid pressure. which may change with time rapid enough to cause dynamic effects. Under normal condi· lions this effect may be considered allowed for by the per· missible hoop stress in the sl<jtic condition. ·

3.2.3 Functional loads during installation

3.2.3.1 'J.:he functional loads during installation may be grouped as·

weight - pressure - installation forces.

3.2.3.2 If the buoyancy of the pipe is included in the term c<weighb>. the longitudinal force due to pressure is ·to be add­ed. If weight in air is used together with .the actual pressure normal to the surface. the effect of pressure on the longitudi· nal force is automatically included in the result.

3.2.3.3 Installation forces are to-include all forces acting on the pipe due to the installation operations. Typical installation forces are applied tension during laying and forces from the trenching machine if trenching is carried out after laying.

3.3 Environmental loads

3.3.1 General

3.3.1.1 Environmental loads are loads due to wind. waves. current and other environmental phenomena. Loads due to hum?on activities independent of the pipeline system are also included. e.g. impact from trawl boards .

3.3.1.2 The environmental loads are random in nature and should in principle be evaluated by means of probabilistic methods. Natural. simultaneous occurence of different en· vironmental phenomena is to be determined by proper super· postition of their individual effects. taking into account the probability of their simultaneous occurence.

18

3 .3 .I .3 The environmental loads during normal operation a are not to be taken Jess than the most probable severest load

liquid particle acceleration normal to the pipe axis (wave induced particle accelerationl. relative acceleration between water particle and pi­pe normal to the pipe axis.

in a time period of I 00 years. a,

3.3.1.4 For temporary phases the design period is to beta· Cm ken as three times the expected duration of the phase. but not

added mass coefficient. In general Cm is a function of Reynolds number. Keulegan-Carpenter number. pipe roughness. and the distance between the pipe and a fiXed boundary. This boundary may f.inst. be the seabottom for a pipeline on or close to the sea· bottom. or the caisson wall for the outside riser on ·a gravity strUcture. Proposed values of Cm giye~ ~n

less than 3 months. See also 3.3.1.5.

3.3.1.5 The environmental parameters for determination of environmental loads in temporary phases lasting 5 days or less. and which can be interrupted on a 48 hours warning. can be based on reliable weather forecasts.

3.3.2 Wind loads

3.3.2.1 Wind loads. based on given wind data. may be de­termined in accordance with a recognized code or in accord­ance with Appendix A. Direct application of data from ade­quate tests may also be used.

3.3.2.2 The wind data assumed for the determination of loads are to ·be based on statiStical information. See also 2.3.3.2. When combined with maximum wave loads the one minute sustained wind speed is to be used. If gust wind only is more unfavourable than sustained wind in conjunction with wave loads. the 3 seconds gust wind speed is to be used.

D, Appendix A may be used. · · · · · total outside diameter of the pipe !including coating. marine growth etc.l.

3.3.4.3 The drag force per unit length of the pipe is to be calculated as: '

F0 = 112 pC0 V,IV,ID,

drag force per unit length normal to the pipe axis. drag coefficient for the flow normal to the pipe axis. In general C0 is a function of Reynolds number.

· Keulegan-Carpenter number. pipe roughness "an<! the distimce between the pipe and a fiXed boundary.

IV,!

Proposed values ofC0 are given in Appendix A. water particle velocity relative to the pipe. normal to the pipe axis. absolute value of V, introduced to obtain proper sign ofF0 •

3.3.2.3 In addition to the determination of maximum static V' (or quasistatic> wind loads. the possibility of vibrations due to windinduced cyclic loads is to be considered. Guidelines per· taining in particular to the vortex shedding phenomena are pand D, see 3.3.4.2. given in Appendix A.

3.3.3 lclydrodynamic loads, general

3.3.3.1 Hydrodynamic loads are flow induced loads caused by the relative motions betweep the pipe and the surrounding liquid. When determining the hydrodynamic loads. the rela· tive liquid particle velocities and accelerations used in the cal· culations are to be established taking into account contribu­tions from waves. current and pipe motions if significant.

3.3.3.2 The hydrodynamic loads on a pipe may be divided into the following five categories:

Drag and lift forces which are in phase with the absolute or relative wat~::;r particle velocity. Inertia forces which are in phase with the absolute or relative water particle acceleration. Flow induced cyclic loads due to vortex shedding and other instability phenomena. Impact loads due to wave slamming.

- .J3uoyancy variations dUe to wave action.

Flow induced cyclic loads and wave slamming loads are dell with in Appendix A.

3.3.4 Wave loads ..a>··

3.3.4.1 Wave-induced loads acting on a submerged pipe are to be calculated according to recognized methods. In the de­termination of the hydrodynamic coefficients involved. rel­evant model test data and published data may be used.

Forces obtained directly· by reliable and adequate model tests may alternatively be used in the prediction of wave loads.

3.3.4.2 The inertia force per unit length of the pipe is to be calculated as:

where

F - _;;QL C •D? a m-e 4a+em 4 r

the inertia force per unit length acting normal to the pipe axis. the mass density ofthe surrounding water.

3.3.4.4 If the riser is built up of a number of closely spaced pipes. interaction and solidification effects are to be taken into account when determining the mass and drag coefficient for each individual pipe or for the whole bundle of pipes. If suf­ficient data is not available large scale model tests may be re­quired.

3.3.4.5 For pipes on or close to a fiXed boundary lift forces perpendict~lar to the axis of the pipe. and perpendicular to the · velocity vector are to be taken into account. These forces are to be calculated as:

where

F L lift force per unit length acting normal to the axis of the pipe. and normal to the velocity vector.

CL the lift force coefficient. In general CLis a function of Reynolds number. Keulegan-Carpenter number. pipe roughness and the distance between the pipe and a fiXed boundary. Proposed values of Ctare gi­ven in Appendix A.

•· VrD1 see3.3.4.2 .

3.3.4.6 To obtain the combined effect of simultaneous drag. lift and inertia forces. these are to be added vectorially. taking the phase angles between them into account.

3.3.4.7 Possible influence of adjacent structual parts should be taken into account when determining the wave loads as described in 2.3.4.2.

3.3.4.8 For exposed risers and suspended spans of pipeli· nes. the possibility of vibrations due to vortex sheddin"g and other instability phenomena due to wave action should be considered.

3.3.5 Current loads

3 .3 .5 .I The current induced drag and lift forces on a pipeli· ne or riser are to be determined in combination with t~~ wa-

ve forces. This may be done by a vector additon of the wave and current induced water particle velocities. If available. computations of the total particle velocities and accelerations based on more exact theories of wave - current interaction. will be preferred.

~-3 .5 .2 Special attention is to be paid to possible current in· duced vibrations of exposed risers and free spans of pipelines due to vortex shedding or other instability phenomena. For guidance see Appendix A.

, 3.3.6 .Indirect» environmental loads

3.3.6.1 For a riser during operation possible significant soil qeformation. displacement of the platform due to soil de­formation. and signiflcantplatform deformation are to be ta­~en into account. Some portion of the connected pipeline

, p1a)' ;>!so l>e considered for such effect.

· 3.3.6.2 For a pipeline during laying. the effect of lay-vessel ·:p1ovements due to waves are to be considered. For a riser be­ing installed from a vessel a similar effect may be considered.

3.3.7 Ice loads

3.3.7 .I In areas where ice may develop or drift. the possi· , .!?il.ity of !'1~~ on _the pipeline system is to be considered. Such · forces may partly be due to ice frozen on the pipeline system itself. and partly due to floating ice. For shore approaches o;nd '!fea5 of shallow water the possibility of ice scouring and

Irrpat;ts from drifting ice is to be considered.

· 3.3.7 .2, In case of ice frozen to above-water parts of the sys­tem (e.g. due to sea spray) the following forces are to be con·

· sidered:

19

Weight of the ice. Impact forces due to thaw of the ice. Forces due to expansion of the ice. Increased wind- and wave-forces due to increased expos· ed area or volume.

3.3.7 .3 Forces from floating ice are to be calculated accord· ing to the best ·available theory. Due attention is to be paid to the mechanical properties of the ice. contact area. shape of structure. direction of ice movements etc. The oscillating na­ture of the ice forces (build-up of lateral force and fracture of moving ice) is to be taken into account in the structoral ana· lysis. When forces due to lateral ice motion will govern struc-­tural dimensions. model testing of the ice-structure intera~ tion may be required.

3.3.8 Accidental loads.

3.3.8.1 Accidental loads are to be classified as environ­mental loads. and they are to be taken into consideration for those parts Qf the system where such loads are likely to oc­cur. Examples of accidenllll _loads are impact from vessels. trawlboards and dropped object as well as fire.

3.3.8.2 The pipeline and its accessories are to be protected against accidental loads which are likely to occur. Such loads are - impacts from vessels - impat;ts from trawlboards - impacts from dropped objects See also 1.4.4.3.

20

SECTION 4 STRENGTH AND INPLACE STABILITY

4.1 General

4 .1.1 Design analyses

4 .I .1.1 The design analyses are to be based on accepted principles of statics. dynamics, strength of materials. and soil mechanics. and are to be in accordance with these Rules. See also 4.1.2.3.

4. 1. 1.2 Simplified methods of analysis may be used if these are reasonably conservative. Model tests may be used in combination with or instead of theoretical calculations. Iri ca­ses where theoretical methods are inadequate. model or full scale tests may be required.

4.1.1.3 When determining responses to dynamic loads. the dynamic effect is to be taken into aC~;ount if deemed signi· licant. Dynamic analyses or reasonably conservative qua-sistatic considerations may be used. ·

4.!.1 .4 All forq:s and support displacements which may influence the safety, are to be taken into accounL For each cross section or part of the system to be considered. and for each possible form of failure to be analysed, the relevant combination of forces which may act simultaneously are to be considered.

4.1 .1 .5 These Rules do not include the problem of optimum design. which would involve repeated design analyses. Pipe diameter. operating pressure and other vital parametl'lS are assumed to be known.

4.1.2 Design criteria

4.1.2.1 Pipelines and risers are to be designed against the following possible modes of failure,

4.1.3.2 fined'

In these Rules two main design conditions are d~

- Pipeline systems during operation - Pipeline systems during installation

4.1.3.3 The term (<during operatiom) refers to normal $itua':' tions after completed installation whether the system is. in operation or not. Shutdown conditions and conditions dur\ng maintenance operations are included. Repair situations, ~e normally not included.

4.1.3.4 The term «during installation» referst\) ~y siwa­tion (construction. installation. laying. buriall before'comple(­ed installation of the system. Repair situations will noqnally also be included. ·

4.2 Pipeline/ riser during operation

4-2.1 General

4.2.1.1 The pipeline/riser is to have a lllinimum against the modes of failure mentioned in 4 .).2 .1 c

4.2.1.2 I~ order to avoid damage to the pipeline/risers ffi~y should not be located too close to foreign structures. pipeli­nes. wrecks boulders etc. If. however. this is unavoidable ~e pipeline/ riser should be kept in posi\ion 1:>)' cJart!P5· supP9fts etc. When one pipeline is' crossing another the recommeq<!ed minimum clearance between the two pipelines is 0.3 m.

4.2.1 .3 External risers are to be adequately protected agaipst impact loads from vessels and other mechanical influence .. , The protection may be obtained by:

(

Excessive yielding Buckling

- suitable lQI:~tism wi!.!l r~&~!f! 1\! , !i!','J;!L!.!!!.!l'!!!!Qi>,. ~,'~"'~"-""''"'~·'=

Fatigue failure Brittle fracture Excessive damage to or loss of weight coating (see Sec­tion 6) Loss of inplace stability (external equilibrium) Propagating ductile fracture

For design against corrosion. see Section 6.

4.1~.2 These Rules do not specify any limitations regard­ing elastic deformations or vibrations. provided the effect of large deformations and the effect of dynamic behavior. in­cluding fatigue effect of vibrations. are taken into account in the strength analyses.

4. 1.2.3 Strength criteria are here primarily based on ·rt;;, method of permissible stresses. The limit sta,te method may also be used. provided the load- and material factors used for the ultimate limit state will represent the safety required in these Rules. See also 1 .4 .3.

4.1.2.4 The safety against brittle fracture is normally con­sidered satisfactory if the materials are in accordance with Section 5 and the workmanship. welding. and testing are in accordance with Section 7.8 and 10.

4.1.3 Design conditions

4.1.3.1 The safety against the modes of failure mentioned in 4.1 .2.1 is to be checked for the design conditions in which the mode of failure in question is possible - with due regard

to permissible stress (or strain> levels in the considered condi­tion. A general definition of «design conditiom• is given in 3. 1.3. A more precise defmition of the design conditions. to which different stress levels are connected. is given in 4.1.3.2.

- instaU3.tion or renctering structures-- location of the risers within the platform structure itself: The protection system is subject to approval. See 3.3.8.

4.2. 1.4 In zone 2 and where found necessary pipelines ar~ to be protected against unacceptable mechanical influence. Protection may be achieved by one or a combination of th.e following means:

Concrete coating Burial

- Backfilling - Other ·mechanical protection.

4.2.2 Yielding

4.2.2.1 For pipelines the tensile hoop stress (ay) due to a pre, ssure differential between internal and extern~l pressur~~~- 1S not to exceed the permissible value u)-p given below,.

usage factor<See Table 4.1) permissible hoop stress specified minimum yield strength temperature derating factor. For material temperatures below 1 20°C, may normally be usf!l. For higher ternn<,raltur'es reduction of k,. depending on type be considered.

21

Usage factor

Zone Loading condition

a b

0.72 0.50

0.96 0.67

If not a more accurate method is used. the tensile stress, to be compared with a,, of 4.2.2. 1. is to be deter­

by the following formula'

D .,.,(p;-p)· 21 lnteinal pressure extern~l p·ressure nominal outside diameter of pipe nOininal wall thickness of pipe (see 7 .2.6.5)

(p;'~ p,) is to be the maximum of the difference (p;,.,- p, ;n' ~long the portion of the ptpehne mtended to have constant r!: t ;ti!d material properties. and which is to be pressure tested m Qne ~od the ~llle operation. Pi is not to be taken less than th' highest of the following pre~tres at the considered point'

maximlJm st~dy state operatmg pressure ~J~~iS p~aq pf~~.re ~~th the ·line ~~- a static condition

, p . is not to be taken higher than the water pressure at the ~ ~~"idered _point corresponding to low tide.

4.2;2.3 For risers and for pipeline sections where longitudi­stresses- are F;SSential for equilibrium. the equivalent stres~

to be used as a criterion for safety against ex­The criteria for equivalent stresses are given

er>r n<inelline.r.' and risers the permissible longitudinal ( r .,l depend on the consequences of

possible strain (displacementl does not ~""""""'"''i:Jioee<Fthte·•i>ertrli~"'ib'le strain (see 4.2,2.5). stresses need not to

as a criterion for safety against excessive yielding. In S\fain ~xceeds the permissible strain (dis­

equivalent stress (a,} is to be used as the criteri-

The permissible strain depends on the ductility of the and on previously experienced plastic strain. The pi~

is to have acceptable fracture toughness after deforri,ttio·n. For D/ t ratios above a certain value. flatten~

&!'vern. see 4.2.2.6.

flattening due to bending together with the out tolerance from fabrication of the pipe (see

to exceed 2 % '

2 ..;100

req11irements of 4.2.2.5 and 4.2.2.6 apply to ·. strain. such as th~ permanent curva~

Th~y also apply to exposed pipelines

¢~?~':~~~~:.:~~ with the bottom. For exposed 01 contact with the bottom the re-

i Qi\iu·ealents <and 4.2.2.6 will apply provided yield-tO" Such contact that the strain would be

exc~ng the permissible value.

for risers and in cases where possible permissib.le strain. e.g. suspended spans with the bottom is not obtained before

p~rin~ible strain is exceeded, the equivalent stress. defm-

is not to exceed the permissible value Gcp given below.

O"cp 71cpO'F·k, ~'P usage factor as defined in Table 4.1 Gx longitudinal stress ay hoop stress T xy tangential shear stress

"F and k, are defined in 4.2.2.1.

4.2.2.9 For suspended spans in axially restrained lines the axial force developed due to the sag may be taken into ac­count If this effect will stop the bending strain (or flattening) within the limit given in 4.2.2.5 and 4.2.2.6. the value of a, to be inserted in the formula of 4.2.2.8 may be determined as if the span acts as a cable. In such a case stresses due to ther­mal expansion will only be those corresponding to the chan­ge in sag caused by the thermal expansion.

4.2.2.10 Corrosion and erosion allowances are not to be included in the nominal thickness used for the determination of stresses. ·

4.2.2.1 1 Possible strengthening effect of weight coating on a steel pipe is normally not to be taken into account in the design against yielding. Coating which adds significant stiff­ness to the pipe may increase the stresses in the pipe at dis­continuities in the coating. When appropriate this effect is to be taken into account.

4-2.3 Buckling

4.2.3.1 The possibility of buckling is to be considered. De­pending upon the load and support conditions of the pipe. one or more of the following three buckling modes may be possible

Local buckling of the pipe wall due to extemal pressure, axial force and bending moment. See 4.2.3.2 through 4.2.3.4. Propagation buckling due to external pressure - when frrst j!.- local buckle or similar damage has occured. See 4.2.3S. Buckling of the pipe as a bar in compression. See 4.2 .3 .6.

4.2.3.2 The pipeline is to have adequate safety against local buckling under . the most unfavourable combination of ex­ternal overpressure. axial force and bending moment. The applied combination of stresses is to be compared with the critical combinations. The critical combinations may be de­termined .from available relevant test results. The empirical formulas. methods and corresponding criteria given in Ap­pendix B may be used-

4.2.3.3 Bending moment due to a curvature which cannot change. ·e.g. a riser in a J~tube needs not be taken into ac­count in the buckling analysis.

4.2.3.4 The effect of weight coating on pipe wall buckling may be taken into account if satisfactory analytical or ex~ perimental documentation is provided.

4.2.3.5 Since propagation buckling cannot be initiated be­fore a local buckle has occured. no additional safety against propagation buckling is required. For guidance see Appendix B.

4.2.3.6 It has to be documented either that the safety against barbuckling is not less than what is normally accept­ed or. if barbuckling is unavoidable. that the pipeline/ riser will not suffer any damage in the postbuckled mode. For a nonburried pipeline such proof will normally not be requ'r­ed.

4.2.4 Fatigue

4.2.4.1 All stress fluctuations of magnitude and number

large enough to have a significant fatigue effect on the pipeli­ne system are to be investigated.

4.2.4.2 Typical causes of stress fluctuations in a pipeline

22

system are: where - Direct action of waves. --Vibrations of the pipeline system, e.g. due to vortex s number of stress blocks

shedding caused by current. waves. or wind. n1 - Platform movements (displacements or deformationsl. N,

number of stress cycles in stress block i

- Fluctuations in operating pressure and temperature.

The above phenomena, together with possible other causes of

number of cycles to failure at constant stress range (a); usage factor

stress fluctuations, are to be considered to the extent relevant The number of stress blocks. s, is to be large enough to ensu-in each case. re reasonaJbe numerical accuracy.

4.2.4.3 Fatigue analyses are in particular to be made for construction~ details likely to cause stress consentrations. The aim of fatigue design is to ensure adequate safety against fatigue failures within the planned life of the structure. The specific criteria will depend on method of analysis. of which two different categories exist:

al Methods based on fracture mechanics. See 4.2.4.4. b) Methoqs ba5ed on fatigu.e tests. See 4.2.4.5.

The limit damage ration ., will depend on the maintainability, i.e. possibility for inspection and repair. Recommended values of., are given in Table 4.3.

Methods. other than Miner's rule. for accessing cumulative damage will be considered in each separate case.

4.2.4.4 Where appropriate. a calculation procedure based Table 4.3 Usage factor on fracture mechanics may be usecl The specific criteria will .-------------.....--------,-----~ be considered in each separate case. Access for inspection

4.2.4.5 The methods based on fatigue tests consists general­ly of the following three main steps:

Determination of long term distribution of stress range. see 4.2.4.6. Selection of appropriate S-N curve (characteristic resist­ance!, see 4.2.4.7. Determination of the accumulated dantage. see 4.2.4.8.

4 .2.4.6 All stress fluctuations imposed during the entire life. included the installation phase of the pipeline system which have magnitude and number large enougb to cause fatigue effects are to be taken into account when determining the long term distribution" of stress range. .. - . . .

As most of the loads which contribute to fatigue are of ran­dom nature statisti\'aJ considerations will normally be requir­ed for determination of the long term distribution of fatigue loading effects. Deierministic or spectrai analysis may be us­ed. The method of analysis used is subject to acceptance.

The effect of dynamic respo~e are to be properly accounted fo{· when determining the ~e:;s' i-anges unless it can be shown that the dynamic effects are neglil;ible. Special care is to be taken to determine the stress ranges adequately in pipe­lines or risers excited in the resonan~e range. The amount of damping assumed in the analysis is to be conservatively esti­mated.

4.2.4.7 Characteristic resistances are normally given as S·N curves. i.e. stress versus nu~ber of cycles to failure.

The S·N curve used is to be applicable for the material, con­struction detail and state of stress considered as well as to the surrounding environment.

The 1;-N curve is normally tq )le !>O>ed Rn a 95% c;onfidence limit.

4.2.4.8 In the general case where stress fluctuations occur with varyi~g arriPHn.ide in random ~rder. the linear damage hypothesis (Miner's rule) may be used.' Application of Miner's rule implies that the long term dis­tribution of stress range is replaced by a stress histogram, consisting of a convenient number of constant amplitude stress range blocks (a~; and a number of repe~tiors n;. The fa­tigue criteria then reads:

Usage factor

4.2.5 On-bottom stability

4.2.5.1 The pipeline is to be supported. anchored or buried in such a way that under the assumed conditions it will not move from its as-installed position, apart from movements ( corresponding to permissible deformation, thermal expan­sion. and a limited amount of settlement alter installation.

Criteria which will limit permissible deformations are: yiefdiiig: ouckiing""and faugue of pipe • . - . - .. deterioration/ wear of coating geometrical limitations of supports distance to other pipelines. structures or obstacles

The requirement to permissible deformation may thus vary along the pipeline.

4.2.5.2 If the pipeline at any location along its route is on or near slopes. the risk of slope failure is to be analy~. Regard­ing precautions against slides. reference is made to 8.2 .2.

4-.2.5.3 Buried lines are to be checked for possible sinking or floatation. For both liquid and gas lines sinking is to be considered assuming the pipe is waterfllled, and floatation is to be considered assuming the pipe is gas· or ajr-ftlled.

4.2.5.4 If the specific weight of the waterfilled pipe is less than that of the soil (including water contentsl. no further analyses are needed to document the safety against sinking. For lines to be placed .in soils having low shear strength. a consideration of soil stresses may be required. If the soil is. or is likely to be liquefied. it is to be shown that the depth of sinking will be satisfactorily limited. either by the depth of li­quefaction or by build-up of resistance ~uring sinking.

4.2 .5 .5 If the specific weight of the gas- or air-filled pipe is ( less than that of the soil. it is to be proven that the shear strength of the soil is sufficient to prevent floatation. Con­sequently. in soils which are or may be liquefied, the specific weight of the gas- or air-filled pipe is not to be less that that of the soil (if burial is requiredl.

4.2.5.6 Exposed lines resting directly on the bottom withoUl any special supporting elements or anchoring devices. except

possible weight coating. are to be checked for sinking in the same manner as explained above for buried lines. Further. such lines are to have the below required safety against being lifted off the bottom or moved horizontally.

~.5. 7 Liquid lines as well as gas lines are. in the air- or -filled condition. to have a specific gravity higher than that

f ~ea water. (((Negative buoyancyn). Required minimum va­lues will depend on pipe size.

4.2.5.8 Horizontal (transverse) stability is to be checked for wave and current conditions according io 3.3.1.3 and 3.3.1.4.

The most unfavourable combination of simultaneously acting venical and horizontal forces on the pipeline is to be consid­ered. When determining this unfavourable combination, it maY Qe taken ·into account e.g. that the forces will vary along the line, and directional distribution of waves and currents.

4 .2.5 .9 If the motions of the pipeline is to be restrained eith­er by friction force between the pipe and the sea bottom or by forces _mobilized through plastic deformation of the sup­portmg soil, a factor of safety of minimum 1.1 is to be includ·

, ed when establishing the restraining force.

4-Z-5.10 The coefficient of friction may vary(within a wide r~ge) with Ix>tt~m material and surface roughness of the 'pi­pehne. The apphed values are to be based on relevant in· formation from the actual location.

4.2 .5 .I I Axial (longitudinal) stability should be checked. Especially. near platforms and/ or places where the pipeline c~arges dlfectJon, sufficient flexibility and space for expan· s1on should be allowed for. The expansion calculation should Qe, based on conservative values for the axial friction between pip!:ljne and soil.

'~-5-12 _In shallqw water repeated loading effects due to :Jave :>cllo~ '!lay lead to a reduction of the shear strength of

s9il. ThiS s]jould be considered in the analysis, especially '"·'""-t:==-'-'''·"'""''"!!l!U:>l!.<;!\(1)1 .consists of loose sands which is more sus·

, . to liq!lefaction tl)an looser graded deposits and clays.

·4::1::6·'''-PrOJ>ag:;ting'dl\ctile fractures

4 .~ ,6-1 . P i~lines transporting gas or mixed gas and liquids under h1~h pressure are to have reasonable resistance against propagatJng (fast running) ductile fractures.

This may be obtained by using steel with a itigb upper shelf Cll'llpY V-notJ::h toughness, lowering the stress level. me­ella~ crack. arrestors. changing the fracture direction or by ~ompmauon of these solutions.

23

Fatigue (due to possible vortex shedding) see 4.2.4. Interference with human activiteis e.g. fiShing

Free spans are not acceptable if they may lead to failure of the pipeline or put restrictions to human activities.

4.3 Pipeline/riser ,during installation

4.3.1 General

4.3. ~ .I Strength considerations for the pipeline/risers dur­mg mstallation are to be made in order to determine how the pipeline/ riser may be installed without suffering· any damage which may _impair th~ function or the safety of the completed • line, or which may mvolve hazardous installation or repair work. See also Section 8.

4.-3 .I .2 If the installation analyses for a proposed pipeline/ nser show that an acceptable set of installation parameters cannot be obtained with the installation equipment to be us­ed, the pipeline/ riser is to be modified.

4.3.1.3 The requirements of 4.3 apply also, as far as applic­able. to repair operations.

4.3.1.4 Only those sections under 4.3.2, 4.3.3 and 4.3.4 found pertinent to the various installation techniques/ phases should be considered.

43.!.5 Any installation phase/technique is to be checked Such phases and techniques are: - Stan of laying operation - Normal continous laying

Pipe abandon and retrieval Termination of laying operation Tow out Bottom tow Bottom pull Spool on Tie-in Straighfening Trenching Back fill

4_.3.1.6 ~or any of the phases mentioned in 4.3.1.5 the pipe­hoe/ nser IS to have the below required safety against the fol­lowing modes of failure and damage

Yielding. see 4.3.2. Local buckling. see 4.3.3.

- Fatigue effect. see 4.3.4. - Excessive damage to weight coating.

The <;lesign solution is to be supported by calculations based 4.3.2 Yielding 0 Q relevant. experience and/or suitable tests. See also 5.2.8. 4.3.2.1 The primary requirement as to yielding during in-

R" s~la_t.J.on IS that the residual longitudinal strain after installa· •~ers supports .,,.., t10n IS not to exceed 0.002 (0.2 per centl.

4.2.7.1·_ Riser supports are to be so designed that a smooth Theabov~ strain limitation does not apply to the bending and tr~quss~on ~f forces between riser and support is obtained. strrughtemng mvolve~ 1~ the reel barge method or the pulling As (ar as _POSSible. introduction of bending in the pipe wall is through a J-tube or surular. see 4.3.2.3-4.3.2.5. When a pipe

, t<;>, ~~ ayqJded. has vanable suffness e.g. due to concrete coating, this will lo-cally give high strain. Such local strain are no to exceed 0.02 (2.0 per centl. ~-l-1 .2 The ri~er supports are normally to be designed

~Saillst the possJble forms of failure with. at least the same lle$ree of safety as that of the riser they support. However. if

'1:V~all safery consideration indicates that the overall sa­IS m~ed by a reduction of the failure load of cenain

may govern the support design.

here there is no contact between the bottom and (free spansl the following problem areas are to be

4.3.2.2 \\'hen the pipe is to be given a permanent curvature (e.g. by the «bepding shoen or the «J-tube>, method). strain and· flattening. are to be used as criteria in accordance with 4.3.2.3 and 4.3.2.4.

4.3.2.3 The permissible permanent strain depends on the ducility of the pipe material. A total. permanent. bending strain of 0.02 (2 per centl is acceptable. If the bending pro­cedure involves successive bending and straightening of a portion of the pipe, the maximum plastic strain is not to exce­ed I % . (The corresponding radii of curvature are 250 and 500.) See also Section 5.

24

4.3 .2 .4 The flattening due to a permanent curvature togeth· er with the out of roundness tolerances from fabrication of the pipe shall not exceed 2 % .

Dmu- Dmjn

Dmax- + Dmin

2.0 "'100

4.3.2.5 The requirement of 4.3.2.1 apply to the assumed most unfavourable condition during installation. i.e. assumed maximum wind. waves and current acting. (Loading condi­tion b). see 3 .I .2 .I). This requirement applies also to portions of the pipeline where the strains are completely controlled and cannot change. e.g. where the curvature is controlled by the curvature of a rigid ramp. wp.ether or not environmental loads are acting.

4.3.2.6 Instead of a direct consideration of residual strain as explained in 4.3.2.1 and 4.3.2.5. the following criterion may be appliedo

I (N 0 .. 85M )2 2 . (.!::! + 0.85M) "' V A + -v:;- + ~ y - A --,;;;;-- ay ~·f

where the usage factor 11 is 0.72 for loading condition al and 0.96 for the loading condition b) and portions of controlled strain in condition a) (see 4.3 .2 .5). · Other symbolso

N axial force (including effect of water pressure). A = crosS s·ectional area of pipe. M = bending moment W = section modulus of pipe. a y = hOop stress. · •r = specified minimum yield strength. It is to be noted that if M is determined on the basis of a given curvature. the nonlinear relationship between moment and curvature is· to be taken into account.

4.3.2.7 For installation methods involving a J or S shaped curve of the pipeline N and M are to be determined by an ap­propriate method. suitable for the water depth: pipe stiffness and weight in question. Since the effect pf the enviro11me11t~l loads is difficult to determine. the J;Tlin~mum required analyses are as follows: A) Loading condition a) is to be analyzed in detail. and the

formula of 4.3.2.6 is to be applied with a usage factor >i pf maximum 0.72.

B) Loading condition bl is to be co!lsidered by evaluating the' increase of M due to environ men~! lqads on the basis of the assumed environmental conditions. the rele-­vant characteristics of the installation equipment (parti· cularly the laying vessel). and an' available relevant ex·

• perience. If there is reason to expect that the increase of

M will exceed 33 ex,. the assumed maximum M is to be inserted in the formula of 4.3.2.6. applying a usage fac· tor of maximum 0..96.

Cl The particular effect of transverse forces acting on the pipe during laying. namely the change in direction of the pipe axis in the horizontal plane near the lift-off points. is to be specially considered.

4.3.3 Buckling

4.3.3.1 Local buckling of the pipe wall is to be considered in accordance with the applicable clauses from 4.2.3. Guidelines is found in Appendix B.

4.3.4 Fatigue

4.3.4.1 When checking the fatigue life according to 4.2.4. possible fatigue effects in the installation phases are to be add· ed.

4.3.4.2 When the bQttom tow. bottom pull or the floatation methode is used for installqtion of a pipeline. fatigue is consid· ered to. be a majpr effect and this effect should be paid special attention both through theoretical calculation and tests. 4.3.4.3 Wind induoed cyclicOioads on risers during constru"' lion and transportation is to be considered and taken into ac­count when found relevant.

4.4 Piping components and accessories

4.4.1 General

4.4.1.1 All pressure-containing piping components and a"' cessories are generally to represent the same safety as that re­quired above for plain. straight pipe.

4.4.1.2 For all components. for which detailed design pro­cedures and criteria are not. given in these Rules. sufficient strength is to be documented in at least one of the following way~ _:-· ~

Equal' or similar components hav~ been proven satisfacto­ry by previqu~ ~uccessful perfo.rmance under co01parable conditions. By proof tests. By experimental stress analyses. By engineering calculations.

4.4.1.3 If components designed according to a recognized Code pr Standard has proven satisfactory performance. design according to that Code or Standard may be generally accepted.

(

25

SECTION 5 MATERIAL REQUIREMENTS

FOR PIPES AND PIPING COMPONENTS

5.1 General 5.2.2 Supply condition

. : ~-H Validity

_?.,1-1 .. !: This ~tion specifies requirements to characteristic " .. ~atepal pro,l'7rtles for design and quality control of steel line­

. Pipes and p1pmg components. The requirements are applica· ble to. C·Mn steels. C·Mn·fine grain treated steels and low al·

. ,Joyed steels having a specified minimum yield strength up to -500 Mpa. and consumables for welding.

5.2.2.1 The supply condition is to be specified taking into ~count possible adverse effects as a result of forming. weld­mg :an~ heat tr~trnent operations which will occur during fabncauon and Installation.

5.2.2.2 Steel to be used for general service may be supplied as ~oiled. controiJed rolled. thermomechanical treated. nor­maltzed. quenched and tempered or subcritical age--hardened.

of higher strength. other alloys and other materials used subject to special approval. 5.2.3 Heat treatment

Materials for corrosion protection and weight coat· covere<) by Section 6.

5.2.3.1 . Steel castings and forgings are to be normalized. normalized and tempered or quenched and tempered.

The manufacture is to be capable o.f producing rna· ' of required quality. Relevant documentation is to be "'Ya,i!ll\)le on request.

5.2.3.2 Rolled steel for low temperature service (i.e. mirii· ~urn desJgn temperature below 0°C) is either to be normal· ~~· quenched and tempered or thermomechancicaJiy treat·

l'requ~lifl""!iion t.Sii11g or an extended quality contro.l sche­m~ ~ reql:ltred_ for manufacturers having limited experience. .. nd IIJ ~.where new production methods are introduced.

~el~_ctioo of materials

,2.1 ... Materials are to be selected with due consideration ~e commodity. to be transported. loads. temperature. cor·

' ~!')n a11d ?Onsequences of a possible failure during installa· . _ .. ·.·. _opera.uon and mamtenance of the pipeline system.

·-_ ~a~fial specificatioD

specification is to be prepared giving the . ···'···""'"f3cr7'.:.7"'-''o/_elclirli~C:>f~,·~i~i';~~;'~r~~· for line-pipes. piping components.

. ' bQits ·:'nd nuts and any other impor· specifi~~tJon IS to cover manufacturing meth­

····-~·· ... --·~····~"' wmp~tion. heat treatment. mechanical pro-s~:umdnc;ss. 'quality control testing. documentation

mark mg.

}'h~ tP"7ificaqon is to be submitted for approval.

~.j.,f PCIC~01en~tlon and Identification , $j .4,1 All materials are to be delivered with test certificates ~tat!~g the !teat number. manufacturing methods. test results. ldentifiC!ltiOn etc. Material test certificates for pressurized parts are I'Pf!Jlally to be endorsed by Veritas.

' '

~-IA-2 ·AU materials are to be traceable and suitably mark· eg fo~:CIISY JdentJficauon of manufacturer. grade. heat num· ber: S!Ze an(! application. "'''~

~-1 ,4.'3 M at_erials · of uncertain origin or uncertain quality are to ~ reJected. or a special identification and test pro­gramme IS ro be agreed upon.

'5.2 Steel for line-pipes

The steel is to processed and cast in a manner ensur· composition. properties and soundness. Jmpurit-

elements are to be kept at a level consistent property and service requirements.

steel is normally to be fully killed. Steels for li· may. however. be semi·killed when the specif· rield strength is less than 300 MPa.

5.2.4 Chemical composition

S-?.4.1 The ~I is to have a chemical composition which With the S!"7'fied manufacturing. fabrication and welding procedures will ensure sufliCJent strength. ductility. toughness and corrosion resistance.

5.2:4.2 The chemical composition of C·Mn and C·Mn. fine gram tr~lel! 5te:"ls I~ be welded is to be specified within the analysiS hml!" gtven tn Table 5.1. Modifications may be agre­ed ul'on subject to the application of suitable fabrication and weldtng procedures.

·5.2.4:3 If the hardenability of a steel may be better predict· e~ wllh •!!other carbon equivalent formula. this may be con· stdered together with a revised CE·Iimit.

5.2 .4 .4 The chemical composition is to be determined both tn the ladle and the product. Ladle analyses are to be taken for every heat A check analysis is to be taken for each batch of 50 finished products. but at least once every heat

5.2.4.5 The elements listed in Table 5.1 are to. be determin· ed and reported. Other remaining elements added on purpose to control the material properties are also to be checked. and to be reponed.

Procedures for chemical analyses are described in Appendix c. .

5.2.4.6 The chemical composition of low-alloy and alloyed steels will be considered in each case.

5.2.4.7 Tbe impu~ity level and inclusion contents are to be k_ept spec1ally low tn steel to be used in pipeline systems de­Slgne.d. to transport commodities which under unfavourable condltlons may cause blistering. also called stepwise cracking. <see 5.2.11 and 6.4.)

5.2.4.8 The chemical composition is to be specially consid· ered for steel to be used in pipelines where underwater weld· ing is planned for tie-in operations or should be anticipated in case of repair situations.

5.2.5 Mechanical testing

5.2.5.1 The following mechanical properties are essential and are to be determined and reported as part of the quality control: - Yield strength

26

u Jtimate tensile strength Elongation Reduction of area fracture toughness Hardness of welded joints

The reduction of area is normally to be measured only for cast and forged steels.

5.2 .5 .2 The mect>anical properties of the base_ material is. when practically posSJble. to be tested w1th spec1mens onen­tated transverse to the principal rolling/ working direction.

5.2.5.3 Procedures for mechanical testing are described in Appendix C. Alternative standarized methods jl1ay be used subject to agreement.

Table 5.1 Chemical composition of C-steel, C-Mn steel and · C-Mn fine-grain treated steel for general service.

c Mn Si p s Cu % % % % 96 %

5.2. 7 Brittle fracture resistance

5.2.7.1 Base materials and weldments are to be reasonable resistant against initiation of brittle fractures. This is to be en­sured by keeping the transition temperature from brittle to ductile behaviour sufficiently below the minimum design temperature.

Charpy V-notch transition curve is to be established for in­formation for the base material of line-pipes. (See Table 7. I J 5.2.7 .2 Base materials and welded joints are normally \P meet the average Charpy V -notch energy values given bY Fi­gure 5.1. Single values are to be at least 75% of the sp<;eified minimum average. Where standard specimens can not be made, subsize specimens may be used with en~rS;y co-nv~r­tion factors as given in Figure 5. I.

Ni Mo Cr AI OtherS Carbon % % % (total) % equivalentl1 Analysis

max. max. max. max. max. max. tnilX. max. max. 96 max.

Ladle 0.18 1.60 0.55 0.025 0.020 0.35 0.40 0.25 0.20 0.08 J) 0.40 Check 0.20 1.70 0.60 0.030 0.025 0.35 0.40 0.25 0.20 0.08 J) 0.43

J) Vmax. 0.10 (V+NblmaxO.l2 Nb max. 0.05

2) CE=C+ ~n +~+ CulsNi

Ti max. o.os N max. 0.009 (0.015 when AI fme grain treated)

Residuals(Cr+Mo+Cu) max 0.50 .

5.2.6 Tensile properties

5.2.6.1 The yield strength and ultimate tensile strength are to meet the specified values for the actUal grade. Downgrad­ing of high strength steejs is normally not acceptable.

5 .2 .6 .2 The ratio of yield to ultimate t"'nsile strength is nor­mally to be maximum 0.85. A ratio up to 0.90 may be ac­cepted for cold expanded pip~s having ~ctu.U yie!cl stren~th proportion~lly hi~her than the specified minimum.

5.2.6.3 Stress-strain curve typical for the specified line-pipe material is to be recorde!'l. (See 4.3.2.1 and Table 7 .1).

5.2.6.4 The elongation of the base J11ateria:Is is to comply with Table 5.2.

Table 5.2: Minimum elongation for base materials (Based on flat specimens 38 mm wide.}

Specified Minimum percent elongation in 50 mm minimum yield gage length for wall thickness. t mm' strength MPa t .. 12.5 12.5 < t .. 25.5 t > 25.5

200-295 27 29 30 295-340 23 25 26 340-390 22 24 25 390-440 21 23 24 440-500 20 22 23

5.2.6.5 The reduction of area of cast and forged steels C-. C-Mn and C-Mn grain treated is to be at least 35 per cent. for heavy wall components or higher strength steel a higher ductility level may ~e required.

5.2.6.6 The ductility in the thickness direction is to be ade­quate for the pan in question. In special cas~ through thick~ ness tensile testing may be required.

5.2.7 .3 The impact testing temperature is to be selected in accordance with Table 5.3. Maximum testing temperature is. however. not to be taken higher than + 20°C.

Joule Kpm

47 ll v 4.8

,/ ....

v 43 4.4

v v 39 4.0

L v 35 3.6

/ ll

31 3.2

27 / 2.8

11 235 275 315 355 390 430 470

Specified minimum yield strength (MPal

Specimen Energy section factor <mm1)

IO x IO I 10 X 7.5 5/6 10x5 2/3

Fig. 5.1 Average Charpy V-notch energy values

5.2.8 Resistance against propagating ductile fractures

5.2.8.I Pipelines transporting gas or mixed gas and liquids are to ~ 4t;:signe~ irl a manner preventing propagaun~ duculc fractures (see 4.2.(;). When the design is based on the mstalla­tion of line-pipe materials with arrest propenies H. e. a high up-

27

Charpy V-notch impact testing temperature (°C).

induced cracking in

.TOT''· "Tit;;•;n,.x1miiim hardness is to be kept at a level safe­hydrogen induced cracking during

After welding the hardness is not to at any part of the weld unless otherwise re-

2} ..

against sulphide stress corrosion crack·

M~terials and welding consumables for use in pi­systems required designed against sulphide stress cor­¢racking <see 6.4). are to have a chemical composi\ipl'l

level suitable for such service. Selection is to be on documented experience. e.g. NACE Standard -7 ~ {Rev 1980).

final hardness of the base material and any part is to be kept in the range of 260 HV5 or Io­systems required designed against sulphide

.•; . · ' :I;!Te~ •cor·ro:"on cracking. The actual limit is to be agreed upon J . . , , 0 .,. ~., ~onsiderations to operational conditions, corrosivity

coxnrr1oauy. material properties. fabrication and weld­'"'x;cuu•res. corrosion contro! and monitoring systems etc.

. · Suitable heat treatment may be required for high stee~ arid weJds to ensure adequate resistance

formed C-Mn and C·Mn fine grain treated heat treated and meet the applicable hardness

limit for sse resistance. when the accumulated plastic strain exceeds 5 96 . •

Cold formed and/ or welded low alloy steels are normally to be heat treated and meet the applicable hardness limit when sse resistance is required.

5.2.13 Resistance against chloride stress corrosion crack­ing

5.2.13.1 Materials which are to be used in seawater en­vironment are to ·be resistant against chloride stress corrosion crackrting.

5.2.13.2 Application of alloyed steels and/or extra high strength steels (specified min yield strength above 500 MPal is to be specially considered when the pipeline will be operat­ing at higher temperature (above 70°C). or the oil and gas contain significant amounts of chloride components. V ~rifi­cation by relevant experience or suitable laboratory tests may be required.

5.3 Soundness

5.3.1 . General

5.3.1.1 The material is to be free from any defects which may ma:I<e the material unsuitable for intended service. Cracks. notches. gouges and tears are not acceptable. Over­laps_ slivers. impressed mill scale etc. are to be removed by grinding unless proved to be of a superficial nature (see 7.2.6.12).

5.3.1.2 The material is to be free from gross laminations. gross inclusions. segregations. shrinkages and porosity. The soundness of rolled. forged and cast material is to be verified by non-destructive testing according to agreed procedures and standards (see 7 .2.7 .3).

5.4 Steel for piping components

5.4.1 General

5.4.1.1 Piping components such as bends. valves. flanges. tees. mechanical couplings etc. are in general to fullfiU the sa­me material requirements as specified for line-pipes of the sa­me grade and thickness.

5.4.1.2 Modification in chemical composition may be agreed provided special pr,.,autions like preheating and post weld heat treatment are included in the welding procedure.

5.5 Welding consumables

5.5.1 General

5.5.1.1 Welding consumables are to be suitable for the in­tended application giving a weld with required properties. soundness and corrosion resistance in the finally installed condition.

5.5.1 .2 Welding consumables are to have classification ac­cording to recognized classification schemes. Low hydrogen consumables are normally to be used for welding of high strength steels. Cellulosic electrodes may, however. be used provided it is es· tablished special welding procedures preventing hydrogen in­duced cracking.

5.5.1.3 Hydrogen controlled consumables are to give a dif­fusible hydrogen content of max Sml/ I 00 g weld metal (when determined with the glycerin method). and are to be type approved.

5.5.2 Chemical compositon

5.5.2.1 The chemical composition of the weld deposit is to be compatible with the base metal to prevent general and lo­calized corrosion. Content of alloying elements is to be kept at a ~fe level consistent with documented experience. Pre­cipitation effects due to intended heat treatments are to be considered. ·

5.5.3 Mechanical properties

5.5.3.1 The mechanical properties of the weld metal are to meet the base mate-rial require11Jents. Exessively overmatch­ing yield and tensile strengths are. however. to be avoided.

5.5.3.2 Impairment of tensile and toughness properties due to intended heat treatments is to be considered.

5.5.4 Handling and storage of welding consumables

5 .5 .4 .I Welding consumables are to he treated with care to avoid contamination. moisture pick-up and rusting. and are to be stored under dry conditions.

5.5.4.2 The relative humidity is to be kept at max 40% in stores for low hydrogen consumables unless supporting evid· ence confirm a somewhat higher humidity to be tolerable.

5.5.4.3 Table 5.4 shows generally recommended storage and handling routines. Recycling and rebaking is to be strict· ly in accordance with the manufacturers· instructions.

Table 5.4 Storage and handling of welding consumables

Type of Storage of Storage of Storage of consumable hermetically opened consumables

sealed containers withdrawn containers for use

Covered electrodes - low hydrogen

type 20-30°C" 150°C 70°C" - cellulosic type 20-30°C" 20 30oCil Flux for submerg· ed arc welding 20-30°C" 70°C ]) 4>'"i"

Notes:

I) The temperature should exceed ambient by + 5°C. 2) When withdrawn (or use. low hydrogen consumables arc to be kept in

heated containers and normally to be used within 4 hours. 3) To be handled according to good workshop practice.

28

5.6 Bolt assemblies

5.6.1 General

5.6 .1.1 Bolts and nuts are to be made of steel having chemi· cal composition and mechanical properties in accordance with. and are to be manufactured and tested to relevant. re- • cognized standards. '

5.6.1.2 Bolts to be exposed to or immersed in sea water are to be of property class 8.8 HSO R8Q8) or of a equivalent strength level. The strength level is not to exceed property class I 0.9 for bolts to be installed above the splash ~ne. c~ •

5.6.1.3 When bolt assemblies are to be used in low tempe­rature service. or having large diameters. fracture toughness testing may be required.

5.6.1.4 Bolts. nuts and other fastening elements are to be protected against corrosion by suitable. durable c9atingi When bolts assemblies are part of or will join components Which are required designed against stress corrosion q-~ck­ing. the. applicable conditions to materials. manufacturin~ and testing would also apply to these connections. (See 5.2.12.) c

5. 7 Materials for support structures

5.7.1 General

5.7.1.1 When support structures are welded directly to. or act as a pressurized pan of the pipeline system. the material re­quirement for the pipeline part in question are to be mel·

5.7.1.2 Support structures which are not directly welded to pressurized parts are considered as structural members. The material requirements specified for primary structural melll· hers according to Veritas. «Rules for the design, contructi~n and inspection of offshore structures» - latest issue will n~r-mally apply. c

29

SECTION 6 CORROSION PROTECTION AND WEIGHT COATING

6.1 Corrosion protection, general

Validity

6.1.1.1 Pipeline systems are to be adequately protec.ted from corrosion. 6.1 through 6.5 cover nummum requ~re­rnents to corrosion protection systems. 6.6 covers the require­mems to weight coating.

6.1.1 .2 Requirements to pipe materials and welds with res· : pect to enviroqmentally induced cracking such as hydrogen ·induced pressure cracking (hydrogen blistering) and sulphide stress corrosion cracking are given in Section 5.

'' §,L2 De'finitions

6.1.2.1 Splash zone: The splash zone is defined as the as· tronomical tidal range plus the wave height having a proba· bdity of exceedance of 0.0 1. The upper hmit of the .splash zo­ne is determined by assummg 65% of thts wave height above HAT and the lower limit by assuming 35% below LAT.

Stray currents may be avoided by means of a metallic con· ductor connected to the return (negative) side of the stray cur­rent source. Counteraction of the effect of stray current may be obtained by means of cathodic protection or removal relo­cation of the stray current source.

6.2 External coating

6.2.1 General

6.2.1.1 The external coating is to provide adequate corro­sion protection in the actual environment.

.6.2.1.2 Different parts of the pipeline system such as

pipe coating field joint coating coating of supports

are to be adequately covered by the coatings specifications.

, q.l.:i.2 Submerged zone: The submerged zone is defined as 6.2.2 Coating materials the region below the splash zone including sea water and sea bottom zone. 6.2.2.1 The following generic types of external coating may

6.1.2.3 Atmospheric zone: The atmospheric zone is defined !'5 the region above the splash zone.

6.1.2.4 External coating: External coating is organic. in­organic or metallic materials applied to the external metal

;.~·, · S~rface to pfev~nt cor~osion.

i! J1 .2.5 Cathodic protection: Cathodic protection is a tech· c nique toe c corrosion of a metal surface by making the

c;:.:;:=:cccc:::::":.~::::c-~~-~ cathqde of an electrochemical cell.

'v, 6.1 .2.6 Internal prOJection: lnternal protection is differe~t ;_-;:-· :.·:~'::~~ys~ems to reduce corrosion attacks of internal surfaces of pl­

.. PrJines and risers.

,. -6~l .. 3 General req~irements to corrosion protection sys­t~!DS

· 6. L3 .I The pipeline system is normally to be protected by '• external coating in the submerged zone as well as the at·

m_osRheric zone.

6.1.3.2 In the submerged zone the pipeline system is nor· mally 10 be cathodically protected by sacriflcal anodes.

li .3.3 In the splash zone the riser is to be protected by < .. ~peci_al means of corrosion protection normally in combma­

,tiOq ...;hh corrosion allowance. ~·

(i.t . .JA For pipeline systems transporting corrosive com· rnodities internal protection is required.

Fgr pipeline systems which are exposed to intern":! or ex· \ernar erosion wall thickness allowance may be requued.

6.r3s ··For risers which 3fe installed in Hubes. tunnels etc. $pecial ~eans of corrosion protection are normally required.

.) .6 The possibilities of stray currents in connection n~rt>y strUctures are to be evaluated and in areas where ,rC~rren_~ ar~ suspected. appropriate tests are lO be :on­

Detrimental effects of stray currents are to be avOided !!Y-llPlPIYIJng ~eneral preventive methods.

~~ial importance is proper grounding of the welding sys· for barge welding during pipelaying.

be used for corrosion protection:

Coal tar and asphalt enamels and asphalt mastic. normal· Jy in combination with concrete weight coating for s·ub­merged pipelines/ risers. Epoxy. on conditions of compatibility with any weight coating. Epoxy and coal tar epoxy for the submerged part of ri· sers. . Epoxy. vinyl and coal tar epoxy for atmospheric pan of risers. Asphalt ..mastic or epoxy for field joint coating. Rubber lining for risers.

Other generic types of coatings may be used if satisfactory long term performance under similar exposure conditions is documented. Relevant laboratory data and field testing may be satisfactory documentation. This will be considered in each case. (See 6.2.2.3)

6.2.2.2 Asphalt or coal tar based coatings should have a softening point not less than 30°C above the maximum de­sign operating temperature of the pipeline system.

6.2.2.3 When selecting an external coating for a pipeline system the following properties are to be taken into account:

Adhesion or resistance to disbanding Durability or resistance to chemical. physical and biologi· cal deterioration Service temperature range Tensile elongation or flexibility Strength and impact resistance Compatibility with concrete weight coating Repair of damaged coating

The relation between adhesion and strength properties with time should be fairly constant so that underrusting or shield· ing of cathodic protection in case of disbanded coating is avoided.

The above properties are to be documented by relevant tests or by reference to earlier successful application.

6.2.2.4 In addition to the p"roperties given in 6.2.2.3 the coating specification is to include information on

generic type and composition coating thickness primer binder reinforcement fillers

6.2.3 Coating application

6.2.3.1 The external coating is to be applied according to an approved procedure. The procedure is normally to include!

handling and treatment of coating materials surface preparation temperatures. air humidity and time lags between steps in the coating process testing methods. with reference to generally recognized standards or a correspondingly detailed description acceptance criteria repair procedure following attachmein of cathodic pro· tection cables. padeyes. etc. handling. transport of coated pipes quality control and inspection reporting procedure

6.2 .3 .2 The minimum requirement to pipe surface treat· ment before application of coating is generally bl.St cleaning to min. SIS 055900 C Sa 2.5 or equivalent standard.

6.2.3.3 The quality control reports are generally to include:

acceptance criteria according to the coating specification surface preparation data temperature and humidity measurements number of coats and total dry film thickness adhesion data .. · · · holiday detection information on the location of reinforcement in the coat~ ing.

6.2.3.4 A preproduction ~is to ~ ~ried out at the coat· ing yard in order to demonstrate that the coating can be ade­quately applied under the prevailing conditions.

6.2.4 Field joint coating

6.2.4.1 Field joiiit coating should be applied according to an approved procedure of similar nature as described in 6.2.3. The field joint coating shoulcl be compatible with the pipe coating.

Cri1eria for acceptance, repair and rejc;ction of coating before final submersion of pipe are to be stated. Repair methods for damaged coating under field conditions are to be described in the procedure for field joint coating.

6.2.4.2 Surface preparation by power tool brushing to a uniform near·white metal finish may be accepted for aspmut or coal tar based field joint coating. ·

6.2.4.3 When mastic is used for field joint coating. it is of special importance to keep the temperature of the mastic within acceptable limits.

The mastic should be adequately cooled by continuous wa· tercooling before the pipes passes over the stinger during lay· ing operations. · · · · · ·

6.3 Cathodic proteetion

6.3.1 General

6.3 .1 .1 The cathodic protection system is normally to be based on sacrifiCial anodes.

Impressed current may be used upon special consideration

30

and approval. If an impressed current system is to be used. due consideration is to be paid to avoid overprotection and to design a system with sufficient mechanical strength.

6.3 .1.2 Cathodic proteCtion by sacrificial anodes is to be designed to provide adequate protection during the design life of the pipeline system. '

The design may be based on a shorter period if reinStallation of anodes is arranged for.

6.3 .1.3 Potentials for cathodic protection are given in table 6.1. These potentials apply to sea water and saline mud at ambient temperatures-(S- 25°C) and normal sea water com· position (salinity 32-38%ol.

Table 6.1 Potential (in volts) for cathodic protection of steel

Metal Reference electrode

Cu/CuS04 Ag/AgCI Zn

Steel in aerobic envirOnment al positive limit . -0.85 -0.80 +0.25 b) negative limit -1.10 -1.05 +0.00

Steel in anaerobic environment al positive limit -0.95 -0.90 +0.15 b) negative limit -1.10 -1.05 +0.00

Very high strength steel (yield strength >700 MPal

al positive limit -0.85 -0.80 +0.25 b) negative limit -1.00 -0.95 +0.10

In brackish water the potential of the Ag/ AgCI electrode f must be corrected by the actllal chloride composition.

The zin~ . .reference electrodes is only reliable in· open ·sea, , water.

At temperatures other than ambient the potential given in table 6.1 may not apply. Protective potentials which are I mV /°C more negative may be used for steel surfaces ope­rating at temperatures between 25 and I 00°C.

6.3.1 Design of system

6.3.2.1 The cathodic protection system is to be designed so that it is able to deliver sufficient current and distribute this current so that the criteria for cathodic protection is obtained (Table 6.1).

The current density requirement is to be selected on the basis of the environmental conditions either by experience from si­milar conditions or from direct measurements along the rou­te.

Guidance on the design of cathodic protection systems is gi­ven in Appendix D.

6.3.2.2 Cathodic protection design specification should in· elude:

calculation of area to be protected influence"t>n/from electrically connected systems current density requirement coaling breakdown criterion anode material and manufacturer anode weight. design. distribution and total number calculation of the effectiveness of the system.

6.3.2.3 The anode core is to be designed to support the an­ode during all constrUctional and operational phases. e.g. transportation. installation etc.

31

Anode materials and fabrication

. Sacrifical anodes may be alloys of aluminium or

· ,, potential and electrochemical effiCiency of tbe ' are to be documented by appropriate tests. The

The test welds are to be sectioned and examined for bonding and possible excessive Cu-penetration using a microscope with magnification of at least I OOx. The Cu·penetration is normally to be less than OJ mm for procedures to be used on risers. while maximum 0.8 mm for procedures to be used on pipelines.

be based on long term freerunning tests under The hardness in the heat affected zone is to be determined· on

be furnished with a test certifx:ate at least i~',~oufacturer. the specified alloy composition. an­

the chll)"ge number. the chemical analysis. the method of analysis. and other relevant

anodes are to be examined 100% vi­is to be free from coating and

efficiency.

are to be fastened securely on the may bi, welded together with steel

, , ·satisfactory mechanical connection ;pel$i\l,oniin~ Each anode is to be electrically con­

least two attachments.

. co,nnection between anode and pipe is manual welding or !hermite weld­

:hrne.lt 11t'eldirog arc to be placed at least 1 SO mm off

the macrosections and is to be within the normal liinit specif~ ied for the pipeline system.

6.3.4.7 The welds and electrical connection between anode and pipe is to be checked before pipe installation. Pipes with metallic connection between anode and reinforcement in weight coating are to be rejected. . '

6.3.5 Testing of system

6.3.5.1 Potential measurements are to be carried out to en· sure that the pipeline system is adequately polarized. This testing is to be carried out within one year after installation.

6.3.5.2 A program for the tes~ing including test equipment. procedure for and extent of potential measurements are to be submitted for approval.

The reference electrode is to be loCated as close as possible to the se.lected surface point to be measured.

6.4 Internal corrosion control

6.4.1 General

6.4.1.1 Internal corrosion control is to be provided for pi· peline systems transporting corrosive hydrocarbons.

Internal corrosion control may be achieved by one or more of the following methods:

Application of corrosion inhibitors Corrosion allowance Internal co"ating Application of corrosion resistant alloys or linings Drying

6.4.1.2 The following properties of the commodity to be transported should be taken into account in the establishment of a program for internal corrosion control:

Oil/ gas/ water ratios Salinity. bacteria content. pH of water phase Content of corrosive gases such as C02• H-;> and 0 2 Solids content and Dow characteristics Temperature and pressure

fnr· eJ.ect·riclll connections are to be made on an A,~iacJ)ffi'ent plates welded directly onto the

orientated circumferentially. and per­welding procedure. See 8. 7. Regarding see 5.7. Expected time dependance and variations due to .operational

•'""'Conditions should be indicated. The possibility of changing is used for attachment of anode conditions by seawater injection (secondary recovery) should

is to include: be considered at the design stage.

the surface is to be dry. clean and

. of electrical connections by !hermite with a qualified procedure proved to an<!. negligible Cu-penetration along

and shape of the mold is to suit the the anode cable size.

welding procedure is l!a!··~~:llnlin:atic>n and mechanical testing of

6.4.1.3 Internal corrosion control is normally required when the commodity is containing water or has a relative humidity of more than SO% and when the partial pressure of corrosive gases is above the following limits:

oxygen ~

- hydrogen sulphide - carbon dioxide

:0.001 MPa : O.Dl MPa :0.01 MPa

(0.014 psi (1.4 psil (1.4 psil

Combination of these corrosive gases may be more agressive. especially the combination of H2S and 0 2. The corrosivity will also generally increase by increasing temperature.

6.4.1.4 The H,S values listed in 6.4.1.3 are to be considered for general corrOsion. Regarding limits of hydrogen sulphide

for sulphide stress corrosion cracking reference is made to NACE-Standard MR-01-75 (latest revision).

6.4.2 Internal corrosion control by inhibitors

6.4.2.1 When inhibitors are used for internal corrosion control the following conditions are to be taken into account:

General philosophy for the inhibitor selection Trade name Chemical typjl and mechanism for inhibition Solubility and despersibility Ecological effects Recommended inhibitor concentrations Pressure. flow rate and temperature limitations Compatibility if more than one inhibitor is used A reference list of previous applications

6.4 .2 .2 The protective properties of th!> selected inhibitor are to be properly documented by appropriate laboratory and/ or field tests. Laboratory tests should include exposure testing in a relevant fluid with respect to composition. flow. temperature. etc.

The testing should normally be carried out by an independant body.

6.4.2.3 The inhibitors are to be injected into the system ac­

31

Exposure to corrosion Consequences of a corrosion failure Accessibility

6.4 .5 .3 Thickness measurements at selected reference points on risers are to be carried out prior· to installation and in con­nection with periodical inspection (See 9.4 .4 .3). The measure­ments are to be carried out according to an approved pro­cedure which should include information on:

type of equipment type of probe recording and evaluation procedure location of reference points

6.4.5.4 fluid analysis may provide valuable information on the corrosion behaviour of a pipeline system. A specification on sampling procedure. types. methods. frequency and evaluation of fluid analysis should be submitted for approval.

The following analysis may be carried out:

pH Iron content Bacteria Salinity Inhibitor

cording to an approved procedure. The procedure is to in- Flow. temperature. pressure. dew point and other operational elude information on characteristics should be recorded as well.

principles of inhibitor application general arrangement system dosage control system

6.4.3 Internal corrosion control by coating

6.4.3.1 Internatcorrosion control may be achieved by app­lication of a suitable coating system. Regarding properties of coating materials and application procedures reference is ma­de to 6.2.2.3-4 and 6.2.3.).

If the coating is applied after the pipeline has been installed. due consideration should be given to proper surface prepara­tion and quality control after application.

If the coating is applied before the pipeline is installed. due consideration should be given to internal coating of field joints.

6.~3.2 Internal coating which only is applied to increase the capacity of the pipeline system is not subject to approval. Due consideration is to be given to the possibilities of increas­ed localized corrosion at imperfections in the internal coating.

6.4.4 Internal corrosion control by corrosion resistant .. ~­loys

6.4-4.1 Corrosion resistant alloys may be used for corrosion control. The alloy may be used as solid pipe or as a lining in­side the pipeline.

6.4.4.2 The corrosion resistance of the alloy should be doc­umented by reference to previous su~ful ~pplication in si­milar enviroments or laboratory tes~n~. The lab~nt~ory test­ing should include tests for resistance against stress corrosion cracking, pitting, crevic~ corrosion and erosion corrosion.

6.4.5 lntefllal ~rrosion monitoring

6.4.5.1 Internal corrosion monitoring is normally to in­clude different procedures such as thickness measurements. fluid analysis. electrochemical probes. electrical resistance probes and different types of weight loss coupons. The pro­gramme should be based on !be following:

6.4 .5 .5 Properly installed electrochemical probes and weight loss coupons may provide valuable informati<:m in systems containing sufficient water. A specification on design installation and operation of the probes should be submitted for approval.

6.5 Protection of risers and pipelines in critical areas

6.5.1 Splash zone protection

6.5.1.1 In the design of corrosion protection system for ri­sers in the splash zone. due consideration is to be give11 to:

temperatures of hydrocarbons intermittent wetting and drying wave forces resistance to ageing by seawater and sunlight ease of repair and maintenance compability of different materials when such are combin­ed.

6.5 .1 .2 The riser is to have a corrosion allowance in addi­tion to other means of corrosion protection as described in 6.5.1.3.

The corrosion allowance is to provide protection for 2 years. Table 6.2 gives guidelines on determination of the corrosion allowance as function of operating temperatures of the riser.

Table 6.2 Corrosion allowance of risers as function of operating temperature

Temperature~ ~C Corrosion allowance. mm

< 20 2 20 - 40 4 40 - 60 6 60 - 80 8 80 - 100 10

6.5.1.3 Acceptable !DeanS of corrosion protection in the splash zone ar~ application of a corrosion resistant met;lllic sheating or vulcanised rubber. ,

33

6.5.1.4 If metallic sheating is used. the alloy should have adequate corrosion resistance and_ su~cient _thickness and stren~th to withstand the loads dunng Installation a?d opera­tic;>ri. The welding is to be carried out to a quahfied pro­cedure. All welds are to be examined I 00 per cent by suitable "\PT·methods. A sacrificial anode is to be located below the

,;, ; Jta:UiC sheating to compensate for galvanic effects.

caused by the contact between the bottom and the pipeline during the towing operation. This is normally to be proved through tests. Such tests should be carried out with relevant diameters. submerged weigh~ concrete quality. jointing methods and along a similar route as the actual towing.

6.6.2 Weight coating specification.

6.6.2.1 The following items are normally to be covered by shielding should be of a type that can be completely weight coating specification:

to itself and to the steel doubler plate. No me-L'H::;;_:,:,;,,,,,,.., • .,, type sealing should be permitted.

·of inhibitors are to be adequately. documented.

A ~ing pltlg should be fitted to the drawn in section of the ri.0-'S9 that it seals the J-tube at the bellmouth. when the line i$pulleP m. A-~cition for installation of sealing plug and application of W.hibitors should include a description of provisions for Sl!JilPlinl! and chemical analysis of the inhibited fluid.

1.2.2 Pr;Otection by sacrificial anodes may be used as an ~ precaution if technically feasible. Monitoring of the

~\~!odic protection system should be specially considered.

·---':::~"''f""l""'"'""''6iJ;c1_::::..,.,.,.t;;<,Htin Of-ii5efs- in ·interila1 transition zones

of risers in internal transition zones (air I for instance in shafts of concrete structures may be

anq corrosion allowance. Acceptable corro­may be as given in Table 6.2.

Ptle i;9rlsicler••ticm should be given to the possibilities of in­repair for transition zones.

The pipeline shore approach are to be specially in !be design of the corrosion protection system. area the pipeline may be treated as risers corrosi-

Thickness and strength Materials to be used Method of application Curing method Inspection and tests Requirements on storage and handling of coated pipe.

6.6.3 Concrete constituents

6.6.3.1 General. It is to be documented that the properties of the materials under consideration are adequate for the in­tended purpose.

6.6.3.2 Cement. Cement is to be equivalent to ASTM Port­land Cement type ·1. II. III IS. or 1!'-

The tricalciU!)l aluininate ~;Qntent of the cement is to be such as to enhance the corrosion protection of steel without impar­ing the durability of concrete.

6.6.3.3 Water. Water is to be free from contamination in amounts likely to harm the concrete or the reinforcemenL

6.6.3.4 Aggregates. Aggregates are to have suflicient strength and durability. Aggregate containing potentially reactive or deterious constituents is not to be used Aggrega­tes are to be properly graded.

6.6.3.5 Admixtures. Admixtures are to meet requirements of a recognized standard and are normally to be verified by trial mixes.

6.6.4 Properties of concrete

6.6.4.1 General. Concrete for weight coating is to have suf­ficient strength and durability.

6.6.4.2 Strength. The concrete is to have a minimum char­acteristic strength of 30 N/ mm2 found from 150 x 300 mm cylindrical speciments tested in accordance with ASTM C39.

When test specimens of different shape or dimensions are u.s­ed. an appropriate correction factor is to be applied to convert the compressive strength determined to the standard cylinder strength.

QiiE{coortsicler••*!n is to be given to possible interaction with''" 6.6.4.3 Durability. Permeability is the most unportant pro­systems for land based structures and pi- perty determining the long-term durability of concrete expos·

insulating devices may be used above the ed to sea water. Low permeability may normally be obtained

6.6 Weight coating

sectio<n deals with concrete weight coating. anchoring systems will be subject to special

9f concrete weight coating are to provide neg­to submarine pipeline throughout its service

corrosion protection coating against me­during pipeline installation and service.

whc:re the bottom tow methods is used for ,.,."~~····••:.- co~uing must withstand the abrasion

by use of:

high cement content low water-cement ratio preferably below 0.40. however not greater than 0.45. sound and dense ag~regates. proper grading of fine and coarse aggregates. . good concreting practice and good workmanship ensur­ing adequate workability .thorough compaction. proper curing and handling.

6.6.5 Reinforcement

6.6.5.1 Material properties: Reinforcing steel is to satisfy the chemical and physical requirements of a recogniZed standard.

34

6 .6.5 .2 Types' Reinforcement may be in the form of steel wi­re fabric or welded cages fabricated of plain or deformed bars. The type and amount of reinforcement is to be selected in due account of the anticipated pipeline loading and service condi­tions and so as to control the crack pattern of the concrete coating.

6.6.5.3. Splices' Reinforcement type ~d application method are to msure continuity of the hoop reinforcement

6.6.5.4 Placing' Reinforcing steel is to be accurately placed and adequately supported. · · .. ·· · · · ·

Reinforcing steel is not to make electrical contact with the pi­pe or anodes.

6.6.6 Application and curing of concrete coating

6.~.6.1 Applicatio_n. Concrete is to be applied to pipe joint usmg su1table equ1pmo:nt and procedures tllat will result in adequately COilS()Iidate concrete coining of uniform thickness. density and strength. The conCrete is to be plai:Cd as socin as possible after mixing and in any case weU before ihe ·initiai set.

6.6.6.2 Curing. The selected method of curing and its dura­ti?!l is to be such as to ensure satisfactory strength_ and dura­bility of concrete. and to prevent undue cracking of concrete coating. ·· ·

Documentation of the adequacy of the proposed curing method may be required. particularly for adverse climatic conditions. · ' · ·

6.6.7 Testi!!g al!~ i11spect1on

6.6.7 .I General. Methods for testing of materials are to be in accordance with a recognized siaildard. The organization

plan for testing. inspection. reporting of results etc. at coating yard is subject to acceptance. ·

6.6.-7.2. Concrete ~nstituems. Testing of the individual ma­terials~ to be earned out at regular intervals during conci'ete producuon. The frequency of testing is to be determined tak­:~~~e quality and uniformity of material supply into ac-

6.6.? .3 Concrete. Prior to start of concreting the mix pro­poruons. concrete strength and weight are to be documented by tests. · · ..•. ··

During production concrete is to be tested regularly for thick­ness. Strength and density. The frequency is 10 be minimum one sample per IS pipes coated and minimum one per shifL.

In addition to molded test s~ens the s~ngtjl ~ !Ire to be SUJ?plemented by control of the in-place strength P!~Ured on drilled-out cores. The minimum diameter of the co~· iS to be at least 3 tilpes the ®~ maximum aggrcopl!' s~ anc;l !he lengt~ to d1ameter !'"uo IS to be not less than 1.0. Sa!rii>l­mg. stonng an!! . tesun.s are to be in accordance with ASTM-c42 or equivalent. The core strength is to be coi!Vert' ed to the stt;ength of standard cylinders I SO. x 300 mm· in ac­C?rdance ~1th ASTM-?'2. The strength requirement is con­Sidered sa~fied pro~ded the mean converte!:! $\!:cngth gf three. "?res IS at least 8 S % of the specified minimum char­acteriStic Strength and no single core is ~ow 7 ~ 11\J •

6.6.7 .4 Electrical insulation measurements by ~pproved proc~ure to Prove no contact between weisht coatiiJe; rei~-forcement and pipeline steel are to be earned ouC" · · ·

35

SECTION 7 FABRICATION OF PIPES AND PIPING COMPONENTS

7.1 General

This section specifies requirements for fabrication control of pipes and piping components. Material

~re to wmply with Sectiop S.

fabricator is to be capable of fabricating .line pi· components of the required quality. Relevant

::!!l:x;\lmentatio" is to be made available on reque5L

teSting or an extended quality control pro­for fabricators having limited experience.

'iR~~f~;~~;;;~ .. ~pipes and components to the actual or similar

is to establish and implement a de­control system covering all succes· qualjzy conirol functions are to be

by competent persons. ·

SCillemes ·IOf qJ!II)ifJcation and quality c:Ontrol been based on current rec:oSn­

methods may alsO be used. ~, '''"'" ·~u'"'"' tO ~ approval.

·Pipe fabrication

recognized classifies-

7 .2.2.4 Previously qualified fabrication procedure may be transferred to a new production when the fabricator has used it recently for production of pipes to the same or more strin­gent requirements under the surveillance of V eritas or an in· spection agency accepted by Veritas.

1.2.2.5 Jointers may be produced in limited numbers using sound sections of pipes. The girth welding procedure is to be qualified prior to or during initial production as given in 7.2.4 and Table 7 .(.

7 .2.2.6 All welding is to be carried out strictly in accord­ance with the qualified procedure. If any parameter is chang­ed outside the acceptable limits. the welding procedure is to be respecified and requalified. Essential parameters and va­riation limits are specified in 8.5.4.

7 .2.3 Quallfieatlon of weldlnc operators, welders and arc-air cougers .

7.2.3.1 Welding perSonnel is to have reasonable under­standing of fundamental welding techniques. welding pro­cedure specifications. relevant methods of non-destructive testing and acceptance criteria. obtained .through training and pniCiise prior to qualifJcation testing. see Appendix C.

7 .2.3 .2 Qualifu:ation testing is required for welding opera­tors when their tasks are to preset. acljusL start. guide and stOp the welding operation. and thereby may influence lhe quality of the weld. Qualification testing may be exempted for welding operators whose tasks have no influence on the weld quality provided they have been given adequate training on the actual welding equipment.

7.2.3.3 Welden are normally to be qualified for single side buUwelding of pipes in the required principal positions. Un­der special circumstances qualification may be carried out on plates. . Repair welders may be qualified for partial thickness repair on a representative devised test set up if only such weld re­pairs will be made.

7 .2.3 .4 The qualifJcation test is to be carried out with the same or equivalent equipment such as to be used during pro­duction welding. and normally at the actual premises. e.g. work shop. yard. vessel. The test is to be witnessed by Veri­laS or an inspection agency recognized by V eritas.

7 .2.3 .S Qualification testing is normally to be based on vi­sual inspection and radiographic examination. When the sas metal arc process is used. mechanical testing is also to be per­formed. normally using side bend and nick br.eak test speci­mens.

Qualification schemes are described in Appendix C.

7.2.3.6 The qualification expires when the welder and welding operator have not been welding regularly within the qualified range during a period of more than 6 months.

7.2.3.7 A welder or a welding machine operator who has produced a complete and acceptable welding procedure qua­lifx:ation test lS thereby qllalified.

7 .2.3.8 Personnel to perform arc-air gouging is to be train­ed and experienced with the actual equipment. Qualification testing may be required.

7.2.4 Qualification of the pipe fabrication procedure

7 .2.4.1 From the flfSt production batch of maximum SO pi­pes. two pipes selected by V eritas are to be used for qualifi­cation testing.

36

Type and number of tests to be made for each pipe are given 7 .2.4.3 Failure of a test specimen due to defective prepara· in Table 7.1. tion m~y be disregarded and is I? be replaced by a new test

specimen. Dimensions of test specimeru; and testing procedure are given in Appendix C.

7 .2.4.2 The quaiification of the fabric;l.tion procedure is to be based on the following requirements:

Hydrostatic testing to the specified test pressure (see 7.2.5). Dimensional tole~ces and workmanship to the specified limits !see 7 .2.6).

7 .1.5 Hydrostatic testing

7 .2.5.1 Every pipe is to be hydrostatically tested and with· stand without any sign of leakage or sweats a test pressure (p) determined by the following formula for at least I 0 seconds:

2t p = u,·K 0 (Mpa)

Soundness of base material and welds within the specif· "• ied acceptance limits (see 7.2.6 and 7.2.7). ' t Check analyses within the specified composition limits D (see 5.2.4). K TensDe properties of~~~ qwerial at least equal to the specifted mlniliiUlJl ValUeS (see 5.2.6). .

specified minimum yield strength (MPal. nominal wall thickness (mml. . nominal outside diameter (mml. factor determined by pipe diameter.

Notch tol!ghness Of base materi<ll at least equal to the miilimllt'll Specified values for resistance against l>riWe fracture: and propagating ductile fractures when so re­quired (see 5.2.7 and 5.2.8). Transverse weld tensile strength at least equal to the sp~ cilied minimum tensile strength. Bendhig duCtility to specified deformation without ap­pearimi:e of imy defect greater than 3 mm. however. max. 6 rnm at the specimen edges. BriWe fracture resistilnee of weld metal and beat affected zone at least equal to the required average and minimum single values (see 5.2.7). Macrosections with a sound weld merging smoothly into ihe pipe. Acceptance criteria as per Table I 0.1. Maxirninri ·hardneSs equal to or below the specified limit (see 5.2.10 and 5.2.12}." ·

Outside diameter j{ ·.

(nominal)

00<200 0.15 200<00<500 0.85 00>500 0.90

f9.r pydrostatic testers equipped with end sealing devices. tile applied sealing" force for'endsealing resulting in an ac:!ditional longitudinal siress has to be considered. Supporting calcula· tions to achieve the required stress intensity for computins of tests pressure is to be submitted by the pipe manufacture.·

7 .2.5.2 Pressure test records showing test pressure and. du­ration are to be available for each pipe.

7 .2.5.3 Pipes which have failed on pressure testing. are to be rejected.

Table 7.1 Qu3ilficatii!JI or PiPe r~brication procedure , Type and number of tests for .each pipe •v~•"' ••vH••, ~ '"'~' o

Pipe sil:e. FULL LENGTH BASE MATERIAL TESTS outside PIPE TESTS diameter (mml Hydi-o- Oimcn· Non- Chock TcnsiletcstU Charpy T..wle Guided Charpy Macro,

&tatic sional deolru<- analysis V·notch .... bend V·notch sec:tjo,>/ u:sts inspc:c- livet<SIS Lonai· Trans- transi- uans- .... tough· ""* lion tudinal ..... lion verse to Sl . ... •1"5

CU!Ye weld 61

llll .. Seamless Ace. Ace. Ace. 00<300 to to to OD> 300 7.2.5 7.2.6 7.2.7

Welded Ace. Ace. Ace. ..... 00<300 to to to j1l 2 4 4 samples 00>300 1.2.5 1.2.6 7.2.7 2 4 4 samples

Noles: 1. Yield strcnglh. ultimate tensile SU"cngth and cJona:ation to be c1ctermincd with recording of the stress-strain curve (only for line-pipes). 2. Charpy V~notch transitioo curve is lO t?e estab~ usina transverse ~ samples whctc so is possible. Acceptance testing temperature is to be as spcciftcd

iu S.2.7. t W~ resisranc:c to propq.a~a ductile f~rc is to be evaJualed by other testS than Charpy testing. the specified te$ts are 10 be; perform~ ~~idonally

(see a&o "$.2.91. · • ·· "' ..... '·. ·•· · .. , · •· ·•·· - .. · · 4. The Ultimate tensile strenath of the weld is 10 be detenQined. . S. Guided bend tests to be either 2 face bend plus 2 root bend specimens. or 4 side bend specimens for lhickncss less and greate:r than 12.S rn~ ~ivcly. 6. Charpy V-im~ les1ini 4 to be perfonne~ at~ spec;ifie4 remperowre iu the wei~ metal and the heal affected zone at sufficient posilions .0 ~the

overall ~ io briu1c f~ (~ S.2.7l. Cbarpy ~ is normally to be performed with the noach positioned ln: Center of weld. on f~!1l~. 2 mm from f\lsion line and S mm from fusioa line (Each sample ~ prov!de J lCS\ specimens). -· · ~

7. Longitudinal tensile 1es1 is to be taken 1800 opposite to the weld.

37

Table 7.2 Frequency and extent of pipe production tests

Mechanical testing21 Hydrostatic test Non-destructive tests

Each SO pipe. mini· mum once each heat (Ace. to Table 7 .3)

Each pipe (Ace. to 7 .2.5)

Each pipe (Ace. to 7 .2.6)

Each pipe (Ace. to 7 .2.7)

is not ·ri;Qllired if this has already been performed during an intermcdialc s&age.

more 1han SO pipes manuracu.ued from each SO tons. mechanical ~ting is only required for cacb 50 tons.

Table 7.3 Number and type of mechanical tests on pipe production tests

verse

Charpy2131 . T ensile41 lest V -notch transverse to

toughness weld

I sample I sample

I sample I sample

Guided'1

bend test

2 2

u!rimate tensile strength and elonplion 10 ~ determined. ' RS:isu.nce: to be determined by Charpy V·nocch testing at the specifted testing ~empcrature (see: S.J,.7l.

Cbarpy61

V-notch toughness

2 samples 2 samples

Macro­section/ hardness

if«';,laUrial bn .. •ulred to be rcsislant ap.in$l propaplins duaile fractUres. production testS arc also to include the specified type and number of

Table 7.4 Mechanical testing or weld repair procedures

TensDe test transverse toweldll

ultimate tensile strength of the joint

Guided bend testZl

4

Charpy V·notch toughness31

4

bends plus two face bends. or four side bends for thickness less and greater than 12.5 mm respectively.

Macro-section/ hard· ness

, be:. c;arried out with the notch positioned in centre of weld. fusion line. 2 mm from U. and .S mm from f.l. This teSting may be exempted • • :

0 -~~urc provided same weldina consumable. ~itJd heat input ts applied.

.. ,-,,,.,.;,.'"_ op <,limensions and workmanship for li­. 7 .2.6.2 through 7 .2.6.12. When pipes . ends are to be rechecked. Tighter toler·

if installation welding is to be equipment demanding ~w line-

7.2.6.3 The inside diameter at the ends is to be measured over a length of I 00 mm from the end and is to comply with the following limits:

Inside diameter (nominal) Tolerances

10<300 mm +1.6mm -0.4 mm

10>300 mm +2.4 mm -0.8 mm

38

7.2 .6 .4 The out-of-roundness is to be limited and measured inside pipe over a length J 00 mm from each end. is to comp­ly with th~ following limits:

Inside diameter (nominal) Tolerances

ID<SOO mm ±I per cent. max. 3 mm

!D>SOO mm ± 0.5 per cent. max. 5 mm

7.2 .6 .5 The wall thickness at any point of the pipe material is not to deviate from the nominal thickness by more than plus 15 per cent and minus 12.5 per cent. For welded pipes having 00 > 500 mm. the minus tolerance is not to exceed 8 per cent.

7.2 .6 .6 The variation in pipe weight is to be within minus 3.5 per cent and plus I 0 per cent of nominal weight of a sin· gle length pipe.

7.2.6.7 Offset: The radial offset is to be within the following limits:

Wall thickness Offset (nomina!l

t<l2.5 mm Max. 1.5 mm t> 12.5 mm 12.5 per cent.

max. 3 mm

7.2.6.8 The straightness of the pipe measured as the gap be­tween the straight line between the ends and the lowest point of the pipe surface is to be maximum 2.0 mm per meter length.

7.2 .6 .9 The pipe is to contain no dents deeper than 6 mm. being measured as the gap between the prolongation of the original contour of the pipe and the lowest point of the dent. The length of a dent in any direction is not to exceed half the pipe diameter.

Any cold formed gouges and notches in dented areas are to be removed by grinding (see also 7.2.9.3).

7.2.6.10 The reinforcement of the weld seam is to be kept within the following limits:

Wall thickness Reinforcement of weld (nominal) Inside pipe Outsid!" pipe

Max. I Min. Max. Min.

t,;:l2.5 mm 2 mm I 0 3 mm I 0 t> 12.5 mm 3 mm 0 4 mm 0

The weld seam inside the pipe is to be ground flush over a length of I 00 mm from each end.

7.2.6.11 The weld is to have an even surface finish~~ merge smoothly into the base material. Minor undercutting may be tolerable without repairs provided the depth and length comply with Table I 0.1. ·

7 .2.6.12 The pipe surface is to be free from any defects which may make the pipe unsuitable for intended service. Cracks. arc burns. notches and gouges· are not acceptable. Overlaps. slivers, impressed mill scale etc. which do not comply with a workmanlike finish are to be removed. Lami~ nations and incl~s,!ons extending to the surface or the bevel face and having a transverse dimension above 6 mm are to be removed by grinding (see also 5.3 and 7 .2.9 .3).

7.2.7 Visual examination and non-destructive testing

7 .2.7 .I Each pipe is to be visually examined and non-des· tructive tested after pressure testing. If a pipe is cut back. the new pipe end is also to be inspected.

NOT-records of each pipe are to be identified and traceable (see 8.6.1.3).

7 .2.7 .2 Visual examination is to be performed at outside. and also inside if access allows. The surface finish of the base material and the welded seams is to comply with 7.2 .6 .12 and Table 10.1.

7.2. 7.3 Welded and seamless pipes are to be ultrasonic test­ed full length. or by other suitable: agreed methods. for !ami· nations and cluster inclusions. Procedures and acceptance cri­teria are to be in accordance with agreed. recognized stand­ards.

Plates and strips may optionally be tested prior to pipe fabri· cation. but after quenching and tempering if this has been applied. ·

7.2. 7.4 Longitudinal welds and spiral welds are to be ultra' sonic tested full length. The testing procedure is to be capable of detecting two-dimensional. and three-dimensional defects located in any direction and position. Additionally such welds are to be radiographed over a length of 200 mm from each pipe end.

Circumferential welds are to be radiographed full length. Ul­trasonic testing may also be required in spec~al c~e~.

Weld repairs are to be radiographed full length.

Non-destructive testing is to be in accordance with Section 10. Weld seams are to meet the acceptance limits of Table 10.1. .

7 .2.8 Production testing

7.2.8.1 Production testing is to be carried out to verify that ( the pipes are fabricated to the composition. mechanical pro· perties. soundness and dimen~ions specified. Production tests are to be performed as directed in Tables 7.2 and 7.3.

Testing iS. io be witnessed by Veritas or an inspection agency·~ recognized by V eritas.

7 .2.8.2 If any of the selected test specimens do not fulfil the requirements. the corresponding pipe is to be rejected. In or· der that the remaining pipes from the same batch of maxi­mum 50 pipes (or 50 tons. see note in Table 7 .2) may be ac­cepted. two similar tests are to be repeated on two different pipes. and both tests are to be satisfactory. Should one of the­se tests fail. individual testing of the remaining pipes of the batch is to be carried out.

7 .2.8.3 Failure of a test specimen due to defective prepara· tion may be disregarded and replaced by a new test speci· men.

7 .2.8.4 If the failure rate exceeds 5 per <:;ent. the quality control program is to be increased to an appropriate level and maintained until the failure cause is identified and eliminated. Retesting of supplied material and requalification of the fabri­cation procedure may also be required.

7.2.8.5 When pipes have failed by mechanical testing. and acceptable properties are intended restored by a controlled heat treatment. individual retesting is to be performed.

7 .2.9 Repai;s

7 .2.9.1 Pipes containing defects may be repaired. or the t;le· ( fective sections cut off. Weld deposits having unacceptable mechanical properties are to be completely removed b~fore rewelding. ·

7 .2.9 .2 Surface defects in pipe material inside the pipe. on the outside of the pipe and less than I 00 mm from the pipe end are to be repaired by grinding only.

In other areas. surface defects may be weld repaired once. provided the depth of the defect is maximum 1/3 of the wall thickness. The length of that part of a defect which has depth more than 1/8 of wall thickness is to be no longer than 1/4 of the outsjde pipe diameter.

'"\2.9.3 Where defects are eliminated by grinding. the re­... ~aining wall thickness is to be within the minimum specified limit. Grinding is to be performed in a workmanlike manner.

7.2.9.4 A local weld repair is to be at least 100 mm long. '--Weld repairs in pipe material are to be orientated circum· ferential if so is possible. Weld seams may be repaired full length. however. not more than twice in the same area. Weld repairs are to be ground to merge smoothly into the original J>ipe contour.

'1 .2.9.5 When a heat treated pipe is repaired by welding. a -new suitable heat treatment may be required depending on the .~ffect Of the weld repair on the properties and microstruc· 111re of the pipe.

7-2.9.6 Repair welding specifications are to be prepared co· verirlg repair of the pipe material and of the weld. The fol­lowing information in addition to that mentioned in 7 .2.2 is to be included in the specifications:

Method of removal of defect. preparation of weld area and subsequent non-destructive testing. see Section I 0. M~imUfrl and maximum repair depths and lengths.

Repair welding is to be performed with a low hydrogen w~ldi!lg process using appropriate preheating/ interpass tem­peratures.

7 .2.9.7 Unless the production welding procedure can be ¥Plied. !he_ repair welding procedure is to be qualified. e.g. [.Jartual repairs of submerged arc welds of pipe material. The ~ualificatioQ test wclds are to be made on pipe nipples in a manner f"ealistically simulating the repair situations to be

The length of the pipe nipple is to be sufficient to give realis· tic restraint. Pipe material is to be on the high side of the chemiC'!! composition.

7.2.9.'8 Qualification testing is to be based on visual inspec· tion, r'ldiography and mechanical testing. Mechanical testing is lO be performed according to Table 7 .4. Repair welding procedu7~ ~r~ ~o meet the pipe requirements.

7.3 Fabrication of piping components

(ieneral

Piping components such as bends. valves. flanges. tees. Intersections etc. may be forged. cast or welded. The CO!llposition. mechanical properties. heat· treatment and soupdness. of piping components are generally to comply wit!J Section 5 in their final installed condition. Dimensional

, ~~)~~~?~·are to comply with recognized standards.

, J,~-1.2 The material flow direction of a forged component l$ to follow the main stress flow pattern. Where

components like flanges. tees. intersections etc. are other methods than shape or die forging. e.g. being out of bars or plates. materials without significant

,, w"~·"v""' dependent propenies are to be used and verified !lppropriate mechanical tests.

;; The effect of forming and heat treatment operations properties. microstructure and corrosion re-­~en into account.

39

7 .3.!.4 When cold forming of pipes to bends or other com· ponents introduces a permanent deformation more than 3 per cent. the mechanical properties ofC·Mn and C·Mn fine grain treated steel are to be retested in the affected region. When such materials are cold deformed more than 5 96 . stress re­lieving is to be performed. When the deformation exceeds I 0%. hot forming is normally to be performed followed by a controlled heat treatment. restoring a uniform microstructure and mechanical properties (e.g. normalizing. quenching and tempering).

Low alloy steels are normally to be suitably heat treated after any cold and hot forming operation.

7 .3.2 Fabrication procedure specification

7 .3.2.1 A fabrication procedure specification describing the sequences of manufacturing is to be established. When piping components are to be produced by welding. a detailed weld· ing procedure specification is to be prepared. see 7 .2.2.

7 .3.3 Qualification of fabrication procedures

7 .3 .3 .I The fabrication procedure is to be qualified by test­ing the first components being produced. A qualification test is to be performed for each group (based on grade of mate­rial. thickness. bending ratio. fabrication method. as applica­ble). Number and type of tests are to follow the requirements given for pipes. see 7 .2.4 through 7 .2.7. as applicable.

Previous qualification tests may be accepted when the com· ponent tested meets the specified requirements and the tests have been witnessed by Veritas or an inspection agency re­cognized by Veritas.

7 .3.4 Production testing

7.3.4.1 Production testing of fabricated piping components is to be performed according to the methods stated in Table 7.2 and 7.3.

Check analysis is to be carried out for each heat. Mechanical testing is .. normally to be carried out for each cast component. and once ·every tenth forged or welded component of each lot. If more than one heat is used for fabrication of a lot of components. each heat is to be tested.

Dimensional inspection and non-destructive testing as specif· ied in 7 .2.6 and 7 .2.7 are to be carried out for each fabricated piping component. Hydrostatic testing is to be performed by the manufacturer or on site with the piping components as built-in section. see 8.8.4. If the latter is agreed. non-destruc­tive testing may be required after the pressure test of the built·in section.

7 .3.5 Repair welding of piping components

7.3 .5 .I Repair welding of piping components is to be carr· ied out by qualified welders using a qualified repair welding procedure as allowed by and according to 7 .2.9. After repair welding. casted and forged piping components are to be post weld heat treated. visually examined and non-destructive tes­ted.

7.4 rost weld heat treatment

7.4.1 General

7 .4.1.1 Post weld heat treatment is generally to be perform­ed for welded joints of C-Mn and C-Mn fine grain treated steels having nominal wall thickness (see Appendix C) more than 49 mm.

\\'hen the minimum design temperature is less than - l0°C. the thickness limit is to be specially decided.

40

The thickness limit for post weld heat treatment of low alloy­ed steels is to be considered in each case.

7 .4.1.2 When post weld heat treatment is used to ensure adequate resistance of welded joints against sulphide stress corrosion. this is normally to be perfonned far all thjcknes­ses.

7 .4 .1.3 Post weld heat treatment is to be carried out at 575-600°C for C-Mn and C-Mn fme grain treated steels. while low alloyed steels are to be post weld heat treated at 600-625°C unless otherwise recommended by the steel ma­ker.

If the steel has been quenched and tempered. the post weld heat treatment temperature is. however. not to be higher than 30°C below the tempering temperature.

7.4.1 .4 Heating, soaking and cooling is to be performed in a controlled manner. The soaking time is to be 2 min/ mm. however. minimum l hour. Where local heat treatment is performed. the specified temperature is to be maintained in a band extending at least 3 times the wall thickness on each side of the weld. The temperature at the edge of the insula­tion bend is to be maximum half the soaking temperature. When the temperature at all parts has fallen to 300°C. the joint may be cooled freely.

41

SECTION 8 INSTALLATION

8.1 General

Speelfications

8-1 .].1 Installation of a pipeline system is to be carried out . ill ~~rdance with written specifications. plans and drawings which are satisfying these Rules. The specifications are sub­Ject to approval by Veritas.

f I , 1.2 . Welding procedures are to be specified as described in8,5.2.

8.2.2 Seabed preparation

8.2.2.1 Seabed preparation is to carried out in acoordanoe with an approved specification. The specification is to include information such as

extent of preparation preparation methods and equipment

- inspection methods and equipment

8.3 Construction

;L(.3 Field coating procedure is to be specified as describ- 8.3.1 Qualification

ed in 6·2·4• 8.3.1.1 Construction has to be carried out by means of g .f.L4 . NOT procedures are to be specified as described in qualified personnel, procedures and equipment The quali-S~f)n 1 o. fications are to be proved prior to start of construction.

8 :lX.S · · A detailed quality control system has to be specified 8.3 .I .2 Welders and welding operators are to be qualified for 1.11 Installation activities. see 1.4.4.2. in accordance with 8.5.5.

l!'~U ,6 The instailation specification is to give detailed in­formaticm on parameters which have to be controlled in or­. ll.er 'to o~tain ihe correct configuration ofand stress levels in the i!4f<>:;!e4 poJlion of the pipeline. The range within which the ~ers ~e allowed to vary is to be clearly stated. see 4.3. .

811..1.7. i!IStrumentation systems used for measuring or con­trolling essential pa;.ometers during the installation operation are to !>e specifted.

~ .'J.S 'Fo~ ~ layvessel the following should be included in J~ sPf9.fication: ·

· "-- general lay-out drawings showing location of working '"'"'on<. '"''""'" devices. stinger. supports. guides etc.

~-=,L::='"'t>r<ifile·••er•oam" ·and· stinger showing proposed pipeline

brief ,descri•oticm of the ~nsion devj~ with information holdiqg force and squ= pressure

support and guides on layvessel and infiorn>ation on possible horizontal and

8.3.1.3 Welding procedures are to be qualified in acoord­ance with 8.5.3 and 8.5.8.

8 .3 .I .4 NOT procedures and operators are to be qualified in accordance with Section I 0.

8.3.).5 It may be required that installation vessels are sur­veyed prior to start of installation. This may include testing and calibration of equipment and instrumentation such as

tension machines winches load cells depth gauges welding equipment

8.3.2 ~.a.ndling and storing

8.3.2.1 Pipes. fabricated sections and accesories are to be handled in a safe manner to prevent damage, and are to ·be adequately supported and protected during storage and trans­portation.

8.3.2.2 Pipes. prefabricated sections and accessories are to be inspected before installation. Damaged items are to be re­paired to the satisfaction of the Surveyor or clearly marked and deplaced, see 6.3.4 and 8.5.8.

8.3.2.3 Storing of pipes has to be carried out in such a way that the pipe is not being permanently deformed by its own

installation the specification should in- weight or the weight of above layers of pipes. Special care inforrclltion such as: should be taken for storing heavy coated anode joints.

general layout drawings of the riser of supports. bends. flanges. etc. '""" · 8.3.3 Installation operations

of riser supports. !>ends. flanges. spoolpie-

,, •.•. ··.·• 4f.fi::S~::;;:~:~J:, systemS used for measuring or contrail-parameters during the installation operation

specification covering all installation opera-

8.2 Pipeline route

8.3.3.1 The installation of the pipeline system is to be car­ried out in acoordance with approved procedures and in such a way that the pipe and coating will not be exposed to un­acceptable strains/ stresses or be damaged.

8 .3.3.2 Mounting and application or riser supports are to be carried out so as to obtain the support conditions upon which the design ""'!,culations have been based.

8.3.3.3 Instrumentation systems used for measuring or con­trolling essential parameters are to be accessible for the Sur­veyor at any time.

8.3.3.4 Joining of pipes and subsequent non-destrUctive testing are to be carried out in accordance with 8.5 and 8.6 respectively. Tie-ins of pipeline sections are to be carried out in acoordance with 8.7.

42

8.3.3.5 Corrosion coating of field joints is to be carried out 8.4.1.3 Measures for obtaining protection of risers and pi-in accordance with 6.2.4. pelines are outlined in 4.2.1.3 and 4.2.1.4.

8.3.3.6 Pipes which have suffered damage during abandon or retrieval operations are to be replaced or repaired to the satisfaction of the. Surveyor. Aoceptance criteria for coating damages are to be worked out prior to stan of laying.

8.3.3.7 Survey of the installed pipeline is required when there is reason to believe that damage has occurred. and that further laying may render later surveys and repairs difficult or impossible.

8.3.4 Pipeline and cable crossings

8.3 .4.1 Crossing of pipeline and cables is to be carried out in accordance with an approved specification. Safety measures. adopted to avoid damage on foreign installations or by other installation~ ar~ to be specified.

8.3.4.2 The specification is to include information such as layout and profile of crossing auxiliary constructions or components including layers of separation methods and equipment adopted for installation inspection methods.

8.3.4.3 Normally a minimum clearance distance of 0.3 m is to be maintained between the pipeline and other pipelines or cables.

8.3.5 Buci<Je de~oo

8.3.5.1 In connection with pipelaying from vessel where pi­pe sections are joined onboard the vessel it may be required that continuous buckle detection is carried out during laying. In such cases the method of buckle detection is subject to ap­proval. Normally a rigid disc is to be located withing the pipe at a suitable distance behind the touch down point.

8.3 .5 .2 The diameter of the detector is to be chosen with due regard to pipeline inside diameter and tolerances on ovality. wall thickness. misalignment a11d· heisht of internal weld bead. The following fcirrr~ula may be used.

where s d "' D

d = D-2t-S

0.01 D + 0.4 t + 5 I diameter of detector nominal outer diameter of pipe nominal wall thickness of pipe 20% oft. max. 5 mm

8.4 Anchoring and protection of pipeline systems

8.4.1 General

8.4.1.1 The pipeline system is to be protected and/or an­chored against unacceptable loads and incidents such as'

lateral axial movements - iQlp~IS - corrosiOn

8.4.1.2 1\ncboring/protection of a pipeline sy$1em is to be carried out in accordance with an approved specifiCiltion. The specification is at least to include

defmition of the fmal conditions description of methods and equipment

- description of means and instrUmentation for control and inspection

Provisions for corrosion protection are covered in Section 6.

8.5 Installation welding

8.5.1 General

8.5 .I. I The schemes for installation welding described in this section have been baSed on current recognized practice. Other methods may also be used. but are lhen subject to spe­cial approval.

8.5 .1.2 All installation welding is to be performed with equipment which has been proved reliable and suitable for field applications. PrequalifiCiltion testing is to be performed for welding systems where previous field experience is limit­ed. or the system will be used under new conditions.

8.5.1.3 Welding may be performed with the manual metal arc. the flux-cored arc. !he gas metal arc or the tungsten inert gas metal arc process. Higher strength steels are to be welded with low hydrogen consumables unless special welding techniques are used ensuring an equal Safety against cold cracking. ·

8.5.2 Welding procedure speelfication

8.5.2.1 A welding procedure specifiCOtiOn is to lie prepared for each procedure giving the following information: - Pipe material. stan~ grade and project specification.

Diameter and wall thickness. Groove preparation and design. Clamping device and line-up tolerances. Welding process. Welding cons!lmablasl. trade name and recognized clas­sification. Electrode/wire diameter. Shielding gas. mixture and flow rates. w~~ P"~~ ~T'!'t: ~?1~_8._e. tyJ,>e ofcurren~ ~n_d . polaritY< trave~ ..,.,...... etc. Welding position. Welding direction. Temporary backing and type (if any}. Number of passes. Time lapse between passes. Preheating and interpasS temperatures. Post weld heat treatment.

8.5.3 Qualification or the welding equipment and welding procedure

8.5.3.1 The selected type of welding equipment and the specified welding procedure is to be qualified prior to instal­lation welding. The qualification test is to be carried out with the same or equivalent equipment as that to be used during installation. The test is normally to be performed on the yard or the vessel where the installation welding is to_ take place. and be conducted under representative conditions.

The test joints to be used for qualifiCiltion testing are to be of sufficient length to give realistic restraint during welding. Pi­pes on the high side of the specified chemical composition are to be selected.

8.5.3.2 When manual welding is to be used. one complete test joint is to "be made. For mechanized welding equipment. three consecutive complete test joints are to be made.

Each test joint is to be subject to visual examination. non­destructive tests and mechanical testing.

8.5 .3 .3 Non-destructive testing is normally to be radio­graphy tested using X-rays. When the ga$ metal arc process is used. the test joints are also to be ultrasonic tested. Magnet­ic panicle testing may be required in special cases.

t

43

Qn:jlelitnlctJIVe testirig is to be performed in accordance with and the soundness of the test welds is to meet the limits given in this section.

The !Ype and number of mechanical tests for each given in Table 8.1. Sampling of test speciQlens. di­and method of testing are described in Appendix C.

tensile strength of the joint is to be at least specified ultimate tensile strength of the pipe

When different steel grades are joined. the ulti­strength of the joint is to be at least equal to

specified ultimate tensile strength of the lo-

bend tests are to disclose no defects exceeding cracks. less than 6 mm. originaling at the

~yJg~··4ef~i$.may be disregarded if not associated with

"'" ·.1

· · 11!1'1 siJ!gl~ Charpy V -notclt toughness at to be less than specified according to m...... ''""·-··• steel grades are joined. a series of performed in the lteat affected woe

· weld The weld metal is then to meet en~gy requirement

?~;!~!~{~~;I;;r~~;~~i~~;;:~ remains valid as ~ within I!CCOPtable li-regulariy. When one

limits occur. the invalid. and is to be re-

from a lower strength grade to a in type. composition and proces­weldability and the 'mechanical

the weld. The C-content. alloy content 'and supply condition is to be specially

in diameter from one to another of 00 .. I 00 mm. I 00 < OD ""301)

ration. dilution and solidifiCiltion pattern. i.e. groove type (V, U. Y. X} angles. root gap and root face are to be spe­cially considered.

Welding process: Any change.

Welding consumables: Any change of type, classifiCation. diameter and brand as well as additions/ omissions of powders. bot and cold wires./

Gas shielding: Any change of specified mixture. compo­sition and flow rate range;/

Welding position: A change to a principal position not be­ing qualified according to Table 8.2.

Welding direction: A change from vertical down to verti-cal up or vice versa. ·

Current: Any change beyond ± IS% and from AC to DC.

Polllrity: Any change.

Yohage: Any change beyond ;1: 10% except ± 596 for gas metal arc welding.

Travel speed: Any change beyond ± I 0 96 .

r~me lapse between root pass and first filler pass: Any de­lay signif1C8Ittly increasing the cold cracking risk.

Prehe4ting: ,o\ny decrease.

lnterpass tempertlture: Any signifiCant change in the mi· nimu!ll and maxb!lu!ll interpass te!llperature limits.

Post weld heat treatment: Any change signifiCantly affect­ing mechanical properties. !he residual stress level. the corrosion resistance. i.e. the beating rate. cooling rate. temperature level and periOd; heating band and insulation width to be specially considered.

8.5.5 Qualification of welders and welding operators

8.5.5.1 QualifiCiltiO!l of welders and w~lding operators are generally to be as described in 7 .2.3. For underwater welding additional conditions apply. see 8.7.4.10.

The fractured surface is to show complete. penetration and fusion. There is to be maximum one - I - gas pocket per cm1• being less tl)an I .5 mm in extension. On­ly mirior slag inclusioni with maximum depth 0.8 mm and with maximum length 3 mm spaced at least 12 mm. may be accepted. «Fish eyes>• may be disregarded unless not associated with significant number of slag inclusions and cluster porosity.

8.5.6 Welding and workmanship

8.5.6.1 AU installation welding is to be performed with qualified welding equipment. qualified welding procedures and type of equipment and by qualified welders/ operators. The back lead of the welding equipment is to be correctly connected to avoid straY current giving arise to corrosion. see also 6.3.2.3. Identical welding units. either additional or re­placement units. may be qualified by non-destructive testing of production welds.'

44

Table 8.1 Qualification of glrthwelding procedure. Type and number of mechanical tests for each joint.

TEST JOINT NUMBER OF EACH SPECIFIED TEST

Wall Outside Transverse Root bend Face bend Side bend Nick break21 CharpyV· Hardness thickness diameter weld tensile notch sam- and macro (mml (mml ples3)4 15 l6•

<;300 2 2 2 0 2 4 2 <12.5

> 300 4 4 0 4" 4 4 2

.;;300 2 0 0 4 2 4 2 > 12.5

> 300 4 0 0 8 4 4 2

Notes: I) Roo~ and face bend tests may be used instead of side bends. 2) Nick break_~ may be omitted for manual metal arc: welding to be performed above water. 3) Impact testmg IS not required for t <5 mm. 4) Each Charpy·V-notch saniple consists of 3 specimens. · · S) ~i~:.act testing is to be carried out with the V·notch positioned in the weld metal. on the fusion line. 2 mm from tbe fusion line and 5 mm from the fusion

6) ~~~~~ = ~!~~~ ::e:d ~:;;~~:~e c~r;s~~!':P~~;e u:e~d.impact testing is nonnaJiy to be carried out in the corresponding weld regions if the

8.5.6.2 The bevelled pipe ends are to be free from con· lamination by moisture. oil, grease. rust etc. which might af· feet the weld quality.

8.5.6.3 Internal or external line-up cliiillPS 1'-te normallY not to be removed before the first two passes are completed. When tack ~elds are n~ for ali!lJlment, these are oJ1]y to be made m the weld groove using a qualified welding pro­cedure. Defective tack welds are to be completely removed.

8.5.6.4 Welding is not W be discontinued before the joint has. sufficient strength to avoid plastic yielding and cracking dunng pullmg and haJ1dfulg. Prior to r!'starting after inter· rupuons. preheating to the minimum specified preheating temperature is to be applied.

8.5.6.5 Suppa~. attachments. lifting devices etc. used for permanent positioning of risers and pipelines are normally to be welded to a doubler ring. Doubler rings for temporary use are to be clamped. ' ·

8.5.6.6 Permanent doubler rings are to be 111ade as fully enc.;rcbng sleeves and of materials satisfying the requirements fo~ pressure_parts. see 5.7. Longitudinal welds are to be made w1th -~ backing st;ip. avoiding penetration into the main pipe. The :-lrcumf~r~nt.Jal welds "!"e to be continuous, and made io a m.3..:-mer nummiZtng the nsk of root cracking and lamellar tearmg.

Table 8.2 Qualified principal welding positions

Test pOsition Applicable welding positions

IG IG 2G IG.2G 5G IG.5G

2G + 5G All or 6G All

8.5.7 Production test

8_.5.7.1 Prod~ction tests may be required during installa­I.Jon. The test IS to be performed in a manner which. as far as possible. repr~uces the actual welding. and is to cover weld­mg of a suffiCiently large pipe sector in a relevant position.

Wh~n pr~uction testing is required. half the number of tests specified m Table 8.1 are to be carried out- Impact test sam·

pies are to be located in the weldmetal. and in the heat affect· ed zone at th~ positi<:>n which showed the lowest average energy absorption dunng the procedure qualification test. see 8.5.1.

8.5.8 Repair of field joints

8.5.8.1 Pipes and welds containing defects are to be repair· ed as described in 8.5.8.2 through 8.5.8.9.

8.5.8.2 Defects outside the weld are to be repaired by grind· mg only. If grmding reduces remaining wall thickness below the minimum speci~ed ~hickness. the defective pipe sectior is to be cut <>UL Gnndmg IS to be performed in a workman-like manner. and with smooth transition into the pipe surface.

8.5 .8 3 Defects in the weld ~ay be repaired by grinding or weldmg. Reparr weldmg specifications are to be prepared. and are to g1ve the following information in addition to that relevant of 8.5.2.1.

Method for removal of defecL Preparation of weld area.

- Non-~~tructivetests for confirmation of defect removal. - Perrmssible mmunum and maximum weld repair sizes.

8 .5 .8 .4 The _repair welding procedures are to be qualified. The q~ahficauon tests are to be made in a realistic manner si­rnulatmg repair situations likely to occur. e.g. - Through thickness repair.

Ex~ernal repairs or undercuts with one stringer pass. Inside root repair with one pass only. Repeated weld repairs in same area.

The repair ~ests welds are to be made in the overhead t~~ough verucal position. using pipe with a chemical compo­Sition m the upper range of the specification.

8.5.8.5. The_ test weld covering through thickness repair is to be VISUally inspected. non-destructive tested and mechani· cal tested as re<_~uired for the installation welding procedure. see 8.5.3. T~e sm~le pass test welds are to be visually inspect· ed. magnettc parucle exammed and mechanical tested with two macro/ hardness tests provided there is used the same weldmg consumables and parameters as for the major re· pairS.

8.5.8.6 Pre.h:ating is to be performed prior to repair weld­ing. The mt~umum specified preheating/ i~terp~ tempera-

45

ture is lO '''! maintained until the repair has been completed.

8.$.8.7 Long defects may require repair in several steps to avoid yielding and cracking. The maximum length <>f allowa· bl~ 'repair step is to be calculated based on the maximum wesses in the joint during the repair operation. The repair :'fngth is •o be at least approximately 100 mm even if the de­f~~ i~ .of Jess extension.

8.5.8.8 Grinding is to be performed after arc air gouging to r~m4;)v~ ;;;ny carbon pick-up.

$.5'.8.9 .-\ joint may be repair welded twice io the same aiea. If the joint stili contain defects. the complete joint is to 1M; 'cl!t · o:.n unless special repair welding procedures simulat­Ing actual number of weld repairs have been qualified.

8.6 Visual examination and non-destructive testing of installation welds

8.6.1 General 8,6.J.I , ln~Datj<ln welds including repairs made by grind· ing and welding are to be visual examined and non-destruc­tive tested.

~.§. 1.2 NoncdestrUctive testing is to be performed in ac· <;~>nlance with qualified procedures and qualified NPT·opera· tQl"li· ~ SectiOIJ 1 0.

~.6.1.3 'Inspection and NOT-records are to be made for each weld including any repair actions. The records are to be 111arked an>! ideqtified in a suitable manner enabling tracebili· \y til locatio!) of welds and the welding procedure!sl being us· O<J.

Visu~l ~xamination

is to be carried out for all

The finished welds and the pipe surfaces are to ¢amply with the acceptance criteria specified in Table I 0. I.

3:~:2:3 Welds whi!;:h do not comply with Table 10.1 are to ,ber~paired according to 8.5.8 or cut out.

, '~:6~3 No'l-~estructive testing

8.6.3.1 All installation welds are to be radiographed full leiw!th· Ultrasonic testing and magnetic particle testing may

; be required depending on the applied welding method.

8.6.3.2 Defects which exceed the acceptance limits in Table ::JO.I ,are to be completely removed and repaired in accord· ,~nee with 8.5.8. Magnetic particle testing is normally to be \lSed ~o ~nsure complete removal of defects prior to rei~jr

'"Welding. ·

Weld repairs are to be radiographed. This examina· tion is to cover the repaired area and an additional length of

, 50 mm at each end of the repair weld.

8.6.3.4 Magnetic particle testing may replace radiography when the defect is located at the outside of the pipe. and is re­

'-'lloved by grinding only.

8.7 Tie-ins

~~!)•r'll Tie-ins between different ponions of a pipeline. or

v \:'::~J!I~i;,'\;:~pipeline and riser. mav be carried out by one of the ·,. 'methods. .

connectors.

W eided connection on the Jay vessel and subsequent lo­wering. Underwater welding.

The choice of method is to be based on an evaluation of the conditions under which the tie-in is to be carried out and the service conditions under which the tie-in is to operate.

8.7.1.2 The tie-in operation is to be carried out in accord· ance with an approved tie-in specification.

8.7.1.3 Tie-in specification is to include: description and specification of components which will be introduced as permanent pans of the pipeline. calculation of stresses occurring .during installation and operation. · procedure specifications covering all tie-in operations. description and specification of equipment and instru· mentation essential for the installation. description and specification of methods of inspection and testing.

8.7.2 Mechanical connectors

8.7 .2.1 Mechanical connectors include flanges. couplings or other components adapting similar mechanical principles of obtaining strength and tightness.

8.7 .2.2 An evaluation is to be carried out for loads and re­sulting stresses to which the components are subjected during installation and operation. Safety factors to be included to en· sure an equivalent overall safety to that adopted for the ad· jacent pipeline.

8.7.3 Welded tie-in on the lay vessel

8. 7.3 .1 Lifting and lowering of the pipeline during the tie-in operation are to be carried out so that induced stresses are within the allowable limits for pipeline or riser respectively during installation.

8.7.3.2 .. Suitable means for monitoring the configuration of the pipeline section are to be used.

8.7.3.3 Welding and inspection of the tie-in is to be carried out in accordance with approved specifications. see 8 .S and 8.6.

8. 7.4 Tie-in by underwater welding

8.7.4.1 Welding is to be carried out with a low hydrogen process in a chamber (habitatl from which the water has been displaced.

Other methods are subject to special approval.

8.7 .4.2 Sealing devices are to be of a proven design and rna· nufacture. Sealing pigs are to be pressure tested prior to in­stallation into the pipeline sections unless this has been carr· ied out at an earlier stage.

8.7.4.3 A detailed welding procedure specification is to be established. and is in addition to that specified in 8.5.2.1 to contain:

water depth. pressure inside the chamber. gas composition inside the chamber. humidity level. temperature fluctuations inside the chamber.

8 .7 .4 .4 Storage and handling routines of welding con· sumables on the support vessel and in the welding chamber as well as the sealing and the transfer procedures to the weld· ing chamber are to be specified.

8.7.4.5 The welding procedure is to be qualified under re­presentative conditions in a suitable testing facility. The qua·

46

Jification test is to consist of minimum one complete joint for manual welding and minimum three joints for mechanized welding system.

The qualification program may be increased when the under­water welding will occur under conditions where previous experience is limited. or will be undenaken by a company with limited experience in this field.

8.7.4.6 The qualification test welds are to be inspected and tested as per 8.5.3 and comply with the requirements specif­ied for the pipeline section in question.

8. 7.4. 7 Preheating to a suitable temperature is to be applied for moisture removal and hydrogen diffusion.

8.7 .4.8 The essential parameters for underwater welding are those specified in 8.5.4.1 plus those given in 8.7.4.3. The accep4tble variation limits are normally those specified in 8. 5 .4 plus the following,

Pressure inside chamber: Gas composition inside chamber: Humidity,

any increase any change any increase beyond specified range may be required

8.7 .4.9 A confirmation test weld may be required made on location prior to starting the tie-in welding. The test weld is to be made on pipe coupons in the habitat under actual con­ditions. The coupons are to cover welding from the 6 o'clock to 9 o'cJock region. Subject to acceptable visual inspection and radiography in accordance with 8.6 the tie-in welding may commence. Mechanical testing is to be performed as soon as possible. The number of mechanical tests is half that required for welding procedure qualification.

When the same welding habitat. equipment and welding pro­cedure are used for consecutive tie-ins on the same pipeline under comparable conditions further confrrmation test welds are not required.

8. 7.4 .I 0 The tie-in weld is to be non-destructive examined full length. as per 8.6 and comply with the applicable accept­ance standard in S<;ction I 0.

8.7 .4.1 I Prior to qualification testing for underwater weld· ing. the welder is to have passed a surface welding tests (see 7 .2.3) and have relevant training for welding under pressure.

Qu~ification for underwater welding is to consist of at least one test weld made in a testing facility under representative conditions in accordance with the qualified underwater weld­ing procedure. The test weld is to be visually inspected. radio­graphed and mechanically tested. see 7 .2.3 and Appendix C.

8.8 Final surveys and tests

8.8.1 General

8.8.1.1 A final survey of the installed pipeline system is to be q:trried out in order to verify that the condition of the pi­peline sys~~~ satisfi~ ~~ ~PPf9Y~~ §P.~illg~1J9P and the re­quirements of these Rules.

8.8.1.2 If the pipeline is to be buried or covered by other protection stabilization methods. surveys are normally requir­ed both before and after burial (covering) operations.

8.8.2 Survey of installed pipeline system

8.8.2.1 The fmal survey on the pipeline system is at least to provide the following information' - Detailed plot of the pipeline position

Thickness of cover or depth of trench lif applicable) and description of the state of rest along the route Verification that the condition of weight coating or the anchoring system which provides· for on-bottom stability is in accordance with the approved specification Description of wreckage. debris or other objects which may affect the cathodic protection system or otherwise impair the pipeline Description and location of damages to the pipeline. its coating or cathodic protection system

8. 8 .2 .2 The final survey report of the installed riser is to verify that the riser. including supports. clamps. anchors. pro­tection devices (e.g. fenders. casings. etc.) and corrosion pro­tection system. are installed in accordance with approved drawings and specifications.

8.8.3 Survey of corrosion protection system

8.8.3.1 Inspection of the external coating of the pipeline system is required. Special attention should be given to the ri­ser in the splash zone.

8.8.3.2 Spot measurements of the polarization along the pi­peline may be required in areas with damaged coating. Spe­cial attention is to be paid to areas far from sacrificial anodes and areas with stress concentrations.

8.8 .3 .3 In areas where measurements indicate that cathodic protection has not been attained. some cOrrective action is to be arranged. e.g. mounting of additional sacrificial anodes. increasing current output from rectifiers. or application of protective coating.

8.8.3.4 The possibility of over-protection is to be investigat­ed at locations where detrimental effects of over·Protedion may be suspected.

8 .8 .3 .5 The possibility of stray currents are to be investigated by measurements and visual· observations by qualified per­sonnel. Pr'!visions accordin~ to 6.1.3.6 are to be co'!'pli"~ with wher~ detrimental effects may be suspected.

8.8.4 Pressure test

8.8.4.1 The pipeline system is to be pressure tested after in­stallation. The testing is to be carried ~ut in accordance with an approved procedure. A pipeline system may be tested in sections. e.g. between top of risers or betwe~n ~op of the riser and shore. When a pipeline is to be buried or covered. the pre-ssure test i~ to be performed after such operation. ·

8 .8 .4.2 The test is normally to be carried out with liquid test medium.

8.8.4.3 The pressure test is to prove the strength and the tightness of the tested section. The minimum test pressure is to be 1.25 times the design pressure. Hoop stress in the pipe dur­ing testing is normally not to exceed 90 per cent of the mini­mum specified yield strength. Higher stresses will be consider­ed in each case.

8 .8.4.4 During pressurizing. added test liquid versus pre­ssure is to be recorded in order to evaluate the amount of resi­dual air in the test section.

8 .8.4.5 Afte~ pressurizing sufficient time has to be allowed for stabilization of the pressure in the pipe section.

8.8 .4 .6 The holding time for pipeline sections is normally to be minimum 24 hours. after the pressure has stabilized. For short lines and risers 8 hours holding time may be accepted. For pipesections that can be 10096 visually inspected the hold­in~ period is normally to be at Jeast 2 hours.

8.8.4.7 Alternative pressure testing procedure$ may also be accepted. For guidance see Appendix E.

47

8.8.4.8 If the tested section bursts or leaks. the failure is to be co·rrected and the section retested.

'. 8.8.4.9 Pressure testing of tie-in welds between already test­~d sections may in special cases be exempted provided the re­,1,..-UU!lar.ra_ diqgraphic examination is extended with ultrasonic ex·

··,:_fnination or other suitable methods. Monitoring may be re-­<!Uired .. The NDT procedures and operators are to be qualified f<>r this testing; see Section I 0.

:.,,.8.11,5, Buckle detection

8 .8 5.1 Buckle detection is to be carried out by running a ~~J.lge pig (caliper pig) through each pipeline section after in­

.'.stallation. When the pipeline is to be buried. the final buckle ; detection is to be performed after trenching.

8.8.6 Testing or alarm and shutdown systems

8.8.6.1 It is the Owner's responsibility to protect the pipeli· ne system against operational conditions for which the sys­tem is not designed.

8.8.6.2 Instrumentation for the safe operation of the pipeli­ne system is to be tested according to generaJly recognized co­des and the manufacturer's recommendations prior· to start of operation.

8.8.6.3 Emergency shutdown systems are to be tested ac­cording to generally recognized codes prior to start of opera­tion.

48

SECTION 9 OPERATION AND MAINTENANCE

9.1 General

9.1.1 Owner's duty

9.1.1.1 The Owner is to inform Veritas when inspections re· quired to retain the certificate is to be carried out.

9 .I .I .2 The Owner is to retain files of the running ins~on and the remedial measures taken and make these files avalla· ble upon request.

9.1.1.3 The Owner is forthwith to notify Veritas if any of the events occur as given below. so that the need for surveys can be determined:

the pipeline sYstelll is damaged. or is s.usp<7te~ of having been damaged. in a manner likely to 1mpa1r 1ts safety or

strength ·. · l'k the pipeline system demonstrate signs of deteno~uon 1 e-ly to impair its safety or strength . · . the pipeline system is subjected to any alteration. repa1r or replacement transportation of new fluids.

9.1.2 Retension of Certificate of Compliance

9.1.2.1 The Certificate of Compliance will be retained in the

9.3 In-service inspection

9.3.1 General

9.3.1.1 In-service inspection is to be carried out according to an acceptable program. see 9.2 .I .2. .

9.3.1.2 Veritas may have free access to

scrutinize in-service inspection reports carry out ~urvey in connection with in-service ~nspection· made by the Owner or his contractors carry out survey.

whenever found necessary in order to retain the Certificate of Compliance.

9.3.2 Start up inspecti~n

9.3.2.1 The objective of the start up inspection is to observe during and immediately after start up any movements or be­haviour of the pipeline system. This may include inspection and measurement of the f;iistance between the bend connect­ing the pipeline and the riser. and the installation in order to detect lateral or axial movement. If necessary these measure­ments are to be continued until such movements have stabil­ized.

operating phase provided the requirements in these Rules are 9 .3.2.2 Mechanical couplings including flanges may require satisfied. See also I .5 .2 · visual inspection during start up. Leak detection is to be car-

9.2 Operation and maintenance of the pipeline system

9.2.1 Operalion, inspe~tion and Dlaiote_oance manual

9.2.1.1 The Owner is to prepare a manual for this opera­tion. inspection and maintenance of the pipeline $Ystem-

9.2.1.2 The operation. inspection and maintenance manual is to:

describe organization and management of the mainten­ance and in-service inspection identify all items to be monitored. inspected and main­tained

- JPecify the monitoring equipment. inspection method and Trequency for each item to be inspected

- specify operation limitations - specify start up/ shut down procedures

9 .2.2 Operation

9.2.2.1 Pressure at delivery and receiving stations alonl! ttit' pipeline is to be contrOlled and recorded. It may also be re­quired that the temperature and dew point of the product is measured and recorded at various points in the pipeline sys­tem at regular intervals.

9.2.2.2 Automatic shut down valves and other safety devi­ces in the pipeline system is to be tested and inspected. The inspection Shoidd verify that the deVices are in ·good condi­tion and properly performs the safety function.

9.2.2.3 It is assumed that regulators and pressure relief val­ves not part of the pipeline system are subject to regular test­ing and inspection.

9.2.2.4 Surge pressure is not to exceed 1.1 times the inter­nal design pressure.

9.2.2.5 The concentration of aggressive and toxic compo· nents in the product is to be monitored.

ried out when found necessary. ·

9.3.3 Periodical inspection

9.3.3.1 The frequency and extent of each periodical inspec­tion are to be based on factors such as

type of inspection design and function of the pipeline SYStem seabed· conditions and protection enviro~mental conditions corrosion/ erosion conditions traffic density condition of the pipeline system as installed and as per earlier inspections PQ$Sible conseque'lces of failure

9.3.3.2 Pipeline systems that are not in operation are also t? be subject to periodical inspection if the Certificate of Comph­ance is to be retained.

9.3.4 Frequency of periodical inspection

9.3.4.1 A periodical inspection is normally to be carried out annually if not otherwise agreed upon. The time for annual inspection may. under normal circumstances. be selected with due regard to factors such as weather conditions and operation of the pipeline system.

9.3.4.2 Veritas may. upon request. accept a continuous in­spection in lieu of regular periodical inspection. Each pan of the system is to be controlled as frequently as in the case of regular periodical inspection.

9.3.4.3 The..Owner is tc notify Veritas on occasions when such pans of the pipeline system. which are not normally ac­cessible for inspection. may be examined.

9.3.5 Extent of periodical inspection - pipeline

9.3 .5 .1 The pipeline is to be surveyed to detect free spans. and. if specified to be buried. to detect e/<posed sections. Length of free spans and exposed sections and degree of ex­posure is to be quantified.

49

Visual inspection of exposed parts of the pipeline is out to determine the general conditions of the

locate areas that may be subjected to close visual and testing. This is to include detection and mapp-

l!I"!X'essiible ·parts of the pipeline system are to be re­by suitable equipment.

.~.:o.;;.·;,dnx:r>ness measurements may be required where to believe that 'the pipe wall thickness may be

to external/ internal corrosion or erosion (e.g. sand content in the flow). · ·

the below specified inspection is to be to the inspection specified for the pi-

':l~·;j'~Ftii~ifei~iteiiiii\i~iiniiS··a.r·jirli'Selected reference out on a regular basis. see 6.4.5.3. be carried out according to an ap­

should include information on:

9.4 Repairs

9 .4.1 General

9.4. I. I All repairs are to be carried out by qualified per­sonnel in accordance with approved specifications and pro­cedures. and up to the standard defined for the pipeline.

9.4.1.2 Repairs of parts that are subject to certification are to be surveyed and approved by Veritas.

9.4.1.3 The Owner is to notify Veritas in advance of any such action and to submit the necessary plans and specifica· lions for approval. The exact documentation that is to be sub­mitted for approval or information purposes is to be decided in each particular case.

9.4. 1.4 Pipeline systems with defects may be operated tem­porarily at a reduced pressure until the defect has been re­moved.

9.4.1 Grooves, gouges an- notches

9 .4.2.1 Sharp defects !ike grooves. gouges and notches are to be removed by grinding or by other approved repair metl!­od. The remaining wall thickness is to meet the minimum re­quired for the particular location. see 4.2.2. Deeper defects are to be removed by cutti11g out the damaged portion of the pipe as a cylinder. ·

!1.4.3 Dents

9.4.3.1 A dent is defmed as a depression which produces a gross disturbance in the curvature of the pipe wall.

9.4.3.2 A dent affecting the longitudinal or circu;ruerential weld is to be removed by cutting out the damaged portion of the pipe as a cylinder. or by installing a fUll encirclement welded split sleeve. see 9.4.5. 9.4.6 and 9.4.7.

9.4.3.3 The acceptability of dents are to be evaluated in each case. !;actors to be ~en into consideration are:

size and ·shape of dent properties of pipe material oil or gas pressure possible consequences of pipe rupture pigging possibilities

!1.4.4 Leaks

9.4.4.1 Prior to permanent repair of any leak. the mecha­nisms causing the leak are to be established.

9.4.4.2 Permanent repair of a leak in pipe body or weld may be carried out by cutting out the damaged portion of the pipe as a cylinder or by installing a full encirclement welded split sleeve. see 9.4.5. 9.4.6 and 9.4.7.

For low pressure oil lines repair by properly designed leak clamps may be accepted.

apy c;v~ts occur which impair the safety. 9.4.4.3 Leaking flanges and couplings are to be sealed if 11tabiiity of tite pipeline system. the Owner is found satisfactory by torquing the bolts or by replacing at · pl)\ify V eritas and a special inspection is to be least the sealing devices such as gaskets and seals.

9.4.5 Repair by weldiDg

. is damaged or suspected of having be- 9.4.5.1 Repair welding procedures and welders are to be qualified as described in 8.5.3 and 8.5.5.

: SJrS!i:m ·dernoJrrs~ratc:s signs of deterioration· is subjected to alteration. repair or re- 9.4.5.2 Repair welding above water is to be carried out as

described in 8.5.

is normally to be carried out in 9.4.5.3 Underwater repair welding is to be carried out in a The Surveyor is to be provided dry habitat. see 8.7 .4.

for flfSI band evaluation of the the inspection. 9.4.5.4 Repair welding may in special cases be carried out

50

on pipelines under pressure. Acceptable repair conditions are to depend on:

actual wall thickness pressure flow rate oil or gas welding procedure safety procedures

9.4 .5 .5 All repair welds are to be visually examined and non-destructive tested. see 8.6. When relevant. pressure test­ing is to be carried out as described in 8.8.4.

9.4.6 Temporary repairs 9.4.6.1 If not possible to take the pipeline out of operation.

· repairs may be made by installing properly designed leak clamp over the defect. The strength of the sleeve is to be as required in 4.2.2.

(

51

SECTION 10 NON-DESTRUCTIVE TESTING

10.1 General

Selection of method

Methods for non-destructive testing are to be cho­~n with due regards to the conditions influencing the sensivi­tY. of the methods.

Appropriate methods will be evaluated in each case.

10.2 Radiographic examination of welds

Radiographic procedure specification

I O,l;l.l ;A p~<J!'edure specification for the radiographic ex­a!Dini\tion is to be established and is at least to include the fol­lowing information:

Materia,! qu;ilitY and dimensions Welding process and groove geometrY Racliation source (X -rays or gamma rays. If gamma rays. ty~ of isotop). Teclmique. (Equipment rating in voltage or curie. ex­ternal or internal equipmentl. .Geoll1etric relationships. (Source focal spot size. film­focus distan~ object~film distance. radiation angle with respect to weld and mml .

. Film type. (Trade name and designationl. lntensUYing screens. (Front and/or back. material. thick­

'. nessl. : ' · · Ex~ure conditions. (kV. rnAmin. Cimin.l PrOC<;SSing. (Developing time/temperature. stop-bath. fi­x~tion: 'washing. drying. etcl.

Image quality indicator sensitivities in per cent of the wall th1c~ness based on source and fllm side indicators res· pecuvely. Density. (The density of the radiographs measured on the sound weld metal imagel. Film Coverage.

10.2.2 Radiographic procedure qualification

10.2.2.1 Two radiographic exposures are to be made of a welded joint using pipe of the same diameter and wall thick­ness and of material equal to or similar to that which is to be used in the pipeline system.

I 0:2-2.2 Image quality indicators of the wire type and of re­QUITed number (according to the recommendations of docu­ment JIW /115·62-60) are to be placed on both the mm side and the source side. The image quality indicators are to be clearly identified. and the sensivity of the source side indi­cator is to be equal to or better than the requirements given in Fig. I O.J.

1 0.2.2.3 Exposed radiographs are lo have an average H&D density at the sound weld metal image of 1.8-2.5. High in­tensity illuminators are to be available for radiographs with density in the upper density range.

rar sensitivity = diameter of the smallest wire .still visible •100 "/. thickness of tne weld

5 10 15 20 25 Material thickness, mm

For piodu~tion radiography; sensitivity · b"*d. !>n film side penetrameters

judged as per results from the qualification.

35 40

Fig. 10.1 Required IQI sensitivity. Source side parameter.

45 50

10.2.3 Qualifications of radiographers

10.2.3.1 Radiographers are to be fully capable of perform· ing an operational test using the qualified radiographic pro­cedure.

10.2.4 Production radiography

I 0.2.4.1 Only approved radiographic procedures are to be used. If the panorama technique is used to include I 00 per cent of a girth weld in one exposure. a minimum of three pe­netrameters are to be equally spacea around the circumfer~ ence.

52

Surface requirements Type of couplant<sl Scanning techniques Reporting and identification system

10.3.3 Ultrasonic procedure qualification

10.3.3.1 The ultrasonic examination procedure is to be qualified through a procedure qualification test.

The test is to be performed under normal working conditions -in the presence of a Surveyor.

If the multiple exposure technique is used. at least two penet- The test pieces are to be available as reference during the in­rameters are to be recorded on each fllm and located near spection work. each end of the fllm.

For testing of the ends oflongitudinal or spiral welded seams. one p~~etrameter may be used.

I 0.2 .4 .2 The maximum acceptable fllm lengths are limited by a 6 per cent increase of the wall thickness in the beam di­rection.

10.3.3.2 The procedure qualification is to be performed on a sample pipe containing artificial defects made as drilled ho­les or machined notches. The defects are to be placed both on the outside and inside of the sample. orientated parallel. transverse and through the weld and in base material .. The .. ' defect dimensions and locations are subject to agreement.

10.2.4.3 All fllms are to be clearly marked to identify the 10.3.4 Calibration of equipment proper weld and to locate any discontinuities quickly and ac-curately. Veritas may specify the identification system. 10.3.4.1 Calibration of the ultrasonic equipment is t!l be

Processing and storage is to be in a way that enables the fllms to maintain their quality throughout the design life of the in­stallation.

10.2.5 Evaluation of welds and standards of acceptability

10.2.5.1 The radiographs are to be interpreted by qualified personnel. The report is to show if the weld quality meets the requirements of Table I 0.1. which defects have been judged unacceptable. and the number of repairs made.

10.2.5.2 Since radiography gives two dimensional results only. welds which meet the acceptance criteria may be reject­ed if the density indicates the depth of the defect to be detri­mental to the integrity of the weld.

10.2.5.3 The SurVeyor is to have the right of being final judge in assessment of weld quality.

10.3 Ultrasonic examination of Welds with stationary • equipment

10.3.1 Equipment

carried out whenever it bas been out of function for any rea­son including on/off. and whenever there is any doubt con­cerning proper functioning of the equipment.

10.3.4.2 Calibration is to be performed with the Sllmple pi­pe described in 10.3.3.2. The equipment is to be set to prO-· duce maximum signal amplitude from the artificial defects. The trigger level is then to be reduced to an agreed level. Cali­bration is to be performed at the production speed.

10.3.5 Qualifications of operators

10.3.5.1 Tile operators are upon request to be able to de-'·''-"o-""""'"'1· :c•;, monstrate the following capabilities;

Calibrating the equipment Performing an operational test under production condi­tions Evaluating size and location of reflectors.

10.3.6 Production ultrasonic examination

10.3.6.1 The contact surface is to be clean and smooth. i.e. free from dirt. scale. rust. welding spatter. etc. which may influence the results of the testing.

10.3.!.1 The equipment is to 10.3.7 Evaluation of welds and standards of acceptability be applicable for the pulse echo technique or the double- 10.3.7.1 For stationary equipment the purpose of the test-,; probe technique 4;!oto ing is normally to detect defects which are to be further use a frequency of 4 MHz unless otherwise agreed upon evaluated by radiography. have a sufficient number of fixed. guided probes ensuring examination of the complete seam for longitudinal and Indications giving signals below the agreed trigger level are transverse defects and for detection of possible lamination acceptable. interfering the testing have a trigger system alerting indications of defects and a system alarming malfunctioning of the equipment have a system automatically locating the defect area have a continuous monitoring of weld seam centering

I 0.3.2 Ultrasonic procedure specification

10.3.2.1 A procedure specification is to be established and is at least to include the following information;

Material quality and dimensions Welding process and groove geometry Type of instrument Typasl of transducers Frequencies Calibration details

Indications giving signals above the trigger level are to be considered injurious unless further investigations by radio­graphy show that the weld meets the acceptance cfiteria in Ta­ble 10.1.

10.3.7.2 The Surveyor is to have the right of being final judge in assessment of weld quality.

10.4 Ultrasonic examination of welds with portable equipment

I 0.4.1 Equipment

10.4.1.1 The equipment is to

be applicable for the pulse echo technique and for the double-probe technique cover as a minimum the frequency range from 2-6

~!~:a calibrated gain regulator with ·max. 2 dB per step have a flat screen accessible from the front for d~rect f plottirig of reference cur:ves

- allow echoes with amplttudes of 5 per cent of full screen height to be clearly detectable under test conditions include straight beam transducers and angle beam trans­ducers of45°. 70° and goo.

r-PROBE CONlo>.CT SURFACE

~OIAMETER

__£__:~ L

0 T

B

1.0-lJOnm

L Length of reference block given by probe angle and materia! range to be covered. Thickness of reference block.

..,. D p

Width of reference block. minimum 40 mm. Diameter of drilled hole. Position of drilled hole. ... . ..

Actual wall Thickness of Position of Diameter of thickness ref. block drilled hole drilled hole tinmm Tin mm Pinmm D inmm

t.;;25 20 or t T/2 2.4 25 .;;t<50 38 or t T/4 3.2 50< t .. IOO 75 or t T/4 4.8

Fig~ 10.2 Reference block for constr~ction of reference curve for portable equipment.

1 0.4.2 Ultrasonic procedure specification

1 0.4.2.1 A procedure specific.ation is to be established alit! is at least to include the followmg mformat1on:

Material quality and dimensions Welding process and groove geometry Type of instrument Type(s) of transducers Frequencies Calibration det;lils Surface requirements Type of couplannsl

- Scanning techniques U Reporting and identification system

10.4.3 Ultrasonic procedure qualification

10.4.3.1 The ultrasonic examination procedure is to be qualified through a procedure qualification test.

The test ·is to be performed under normal working conditions in the presence of a Surveyor.

53

The test pieces are to be available as reference during the in­spection work.

1 0.4.3.2 Reference blocks as described u~der I 0.4.4 will normally be considered satisfactory as test p1eces. Whenever groove geometry. welding methods .or other _factors may e3:u· se special problems in flaw detecuon. Yentas may requtre special test pieces to be prepared.

1 0.4.4 Calibration of equipment

1 0.4.4.1 Calibration of the ultrasonic equipment is to be carried out whenever it has been out of fun.cuon for any rea­son inducting on/ off. and whenever ~ere ts any doubt con· cerning proper functioning of the equipment.

1 0.4.4.2 The IJW /ISO calibration block is to be used for calibration of range and for angle determination. The V2 cah­bration block according to DIN 54122 may be used for cah­bration of range only.

10.4.4.3 For evaluation of flaw indications a reference. curve is to be established. The curve is to be plotted on the mstru­ment screen.

1 0.4 .4 .4 A reference block is to be used for gain calibration and construction of the reference curves. The referenc: block is normally to be manufactured from the actual matenal and have dimensions according to Fig. 10.2.

1 0.4.4.5 The sound path from the probe in position A to the reflector. Fig. 10.3 is not to be less than 60 per cent of the nearfield length of the probe. ·

10.4.4.6 The echo height from position A is to be maxin;­ized and the gain control regulated so that the echo he1ght IS

7 5 per cent offull screen heighL Th1s gam settmg .IS called the P.rimary gain and is to be recorded. W1thou~ altenng thiS gam setting the maximized echo he1ghts from pomt Band C are to be plotted on the screen. The reference curve IS now to be drawn as a-smooth line through the three pomts. Two curv­es. 20 and 50 per cent of the reference curve are also to be constructed.

1 0.4.4.7 The primary gain is to be corrected for difference in surface character and attenuation between the reference block and the actual pipe by means of the double probe technique. Two identical angle probes. facing each other one skip distance apart as shown in Fig. I 0.4. are to be used. The primary gain is to be corrected accordingly and then becomes the corrected primary gain.

10.4.5 Qualifications of operators

10.4.5.1 The operators performing ultrasonic examination are to be certified and upon request to be able to demonstrate the following capabilities'

Calibrating the equipment . . Performing an operational test under production condl­tions Interpreting the screen display Evaluating size and locatiOn of reflectors.

10.4.6 Production ultrasonic examination

10.4.6.1 Tlfe contact surface is to be clean and sm~th. i.e. free from dirt. scale. rust. welding spatter. etc. wh1ch may innuence the results of the testing.

10.4.6.2 The weld is to be examined from both sides as shown in Fig. 10.5 and 10.6.

10.4.6.3 For defect detection. the correctedprimary gain is to be increased by 6 dB. Defect size evaluauon IS not to be performed at this increased gain level.

100'/o

a

b A

100'/,

c

I I

--REFERENCE CURVE

FOR THICKNESSES

-10mm

--REFERENCE CURVE

FOR THlCKNFSSFS BETWEEN IOANQ 2Smm

--... _

\ --REFERENCE CURVE

FOR THICKNESSES - 25mm

Fig. 10.3 Construction of reference curves for portable equipment.

54

REFERENCE BLOCK:

TRAHSHITTER RECEIY£R

DIFR.~NCE lxdBI C1Wit«i TO DffEREKE IN SlRFACE AM) ATTENJATION.

r.l r..

1~/1

HATERIAL TO BE TESTED:

FIB. 10.4 Attenuation and surface correction for portable equipment. Double probe technique.

,- -===-f-) ::::-f::~-- _) "- ---- -, ,- --- _, "- --- - ... ,- --- _.,'

... _ --- -., ,- --- _ .. ,_ ---

SCANNtNG AREA

Fig. 10.5 Probe movement for testing butt welds, portable equipment.

10.4.6.4 The defects are to be investigated by maximizing the echoes with different angle probes and by rotating the probes.

10.4.6.5 For dimensional evaluation. either the «20 dB·drop• method or the «half·value-drop» method is to be used.

b

. J:)etection of transverse cracks.

£valuation of welds and standards of acceptability

55

I 0.5.2 Magnetic particle procedure qualification

10.5.2.1 No special procedure qualification test is required. The procedure is considered qualified based on approval of the testing procedure specification.

1 0.5.3 Qualifications of operators

10.5.3.1 Operators' performing magnetic particle examina· lion are to be capable of performing and operational test. us· ing the test method and technique which is to be applied in production.

10.5.4 Production magnetic particle testing

I 0.5 .4.1 The testing equif:ment is to establish a field strength between 2.4 kA/m 30 Oel and 4.0 kA <so Oe).

I 0.5.4.2 Use of permanent magnetic yokes is not permitted.

10.5.4.3 The pipe surface is to be clean and dry. free from any dirt i.e. grease. oil. lint. scale. welding flux etc. which may interfere with the examination.

10.5.4.4 To ensure detection of discontinuities having axes in any direction. the examination is on each area to be per­famed with the magnetic field shifted in at least two direc­tions approximately perpendicular to each other .

10.5.4.5 Non-fluorescent wet or dry particles are to provide adequate contrast with the background of the surface being examined.

10.5.4.6 Examination with flourescent magnetic particles is to be conducted in a darkened area using filtered ultraviolet

is .to show if the weld quality meets the require- light with wave lengths within the range of 3200-3800 A. defects have been judged unacceptable and the

As ultrasonic examination is principle detects «re­in the material. all indications are to be considered

. m9\il. Q!!!!gerollS type of defect until otherwise proven.

=;o ''~!If""''~ of n:pail"!i made..

'tn general all defect indications exceeding the re­!.~l!l;n~e·~'"'e !!fe to be repaired and reexamined.

~~:C:;7""';c.;;;c.;defect'"in<iicitloi1S wiih length .. t exceeding

•·•'·''· .. ,,_ .. ,,~=: .. ,_. the reference curve are to be repaired and ree-

. All defects indications exceeding 20 per cent of the curve are to be investigated to the extent that the can <:valuate the shape. identity and location in lbe-=piance criteria in Table 10.1.

If only one side of the weld is accessible for test· !)efect indications exceeding 50 per cent of the refer­

with length ;>t and all defect indications exceed· cent of the reference curve with length ;a. 2t are to

.... -··· •··-' and ree~Camined.

Surveyor is to have the right of being fi9jl fir• ·Sl>Sel>Sm:ent of weld quality.

panicle and contrast paint

10.5.4.7 Magnetic particle examination is not to be per­formed on parts with surface temeratures exceeding 300°C (570°Fl Between 6o•c (J40°Fl and 3oo•c. only dcy magnetic particle examination is to be used.

10.5.4.8 -C:are is to be taken to avoid local heating of the test surface. PrOds tipped with lead. or «soft prods» are recom· mended. Arc strikes and burn marks are to be ground out and reinspected with a suitable method .

10.5.4.9 Demagnetization is required if the material due to the magnetic panicle testing bas become permanently mag· netized and this may interfere with the servicability of the part or installation.

10.5.5 Evaluation of welds and standards of acceptability

I 0.5 .S .) The magnetic particle examination operators are to report all surface defects detected. The report is to show if the weld quality meet the requirements of Table. I 0.1. and the number of repairs made.

10.5.5.2 Surface which are shown to have defects exceed· ing the limits given in Table 10.1 are to be repaired and re­examined.

I 0.5.5.3 The Surveyor is to have the right of being final judge in assessment of weld quality.

10.6 Liquid penetrant examination of welds

10.6.1 Liquid penetrant procedure specification

I 0.6 .1.1 A procedure specifiCation is to be established and is at least to include the following information:

Material quality and dimensions Welding process and groove geometry Surface preparation Brand name and specifiC type (number of letter designa·

tion if availablel of penetranL remover emulsifier and developer. Details of the method of pre-examination cleaning and drying. including cleaning materials used and time allow· ed for drying. Details of the method of penetrant application• the length of time that the penetrant remains on tpe surface. and the temperature of the surface and penetrant during the ex· amination if not within the 15"C-35"C range Details of the method of removing excess penetrant from the surface and of drying the surface before applying the developer. Details of the method of applying the developer. and length of developing time before examination Method of postexamination cleaning.

10.6.2. Liquid penetrant procedure qualification

10.6.2.1 When the temperature of the surface and the pe­netrant is within I 5°C-35"C range. no' special procedure qualifiCation. test is required. The procedure is considered qualified based on approval of the testing procedure specifi-cation. ·· ·

Outside the temperature range 15"C-35"C a suitable com­parator block is to be used to compare indications from sur· face defects examined within and outside the range.

56

I 0.6.3 Qualifications of operators

I 0.6.3 .I Operators performing liquid penetrant examina· tion are to be capable of performing an operational test. using the test method or technique which is to be applied in pro­duction.

10.6.4 Production liquid penetrant testing

10.6.4.1 Liquid penetrant examination is only to be used on nonferromagnetic materials and materials with great varia­tion in magnetic permeability.

10.6.5 Evaluation of welds and standards of acceptability

I 0.6.5.1 The liquid penetrant examination operators are to report all surface defects detected. The report is to show if the surface meets the requirements of Table I 0.1 and the number of repairs made.

10.6.5.2 Surfaces which are shown to have defects exoeed· ing the limits given in in Table I 0.1 are to be repaired i;,nd re­examined.

10.6.5.3 The Surveyor is-to have the right of being fmal jud­ge i~ assessment oi' weld quality.

57

Pipeline systems. Acceptance limits for visual inspection and radiographic examination.

~\'~i\~,·c

! t:ACK OF FUSION OR rcoMPLETE PENETRATION

tdiSAUGNMENT OF ADJOINING f,IPEENDS

bENTS ·:<-COLD FORMED GOUGES. GROOVES. NOTCHES AND All,CBURNS

Scattered porosity is to be max. 3 per cent by projected area. Largest pore dim. t/4. max. 4 mm.

Cl~ porosity is not to exoeed an area of 12 mm in diameter in any conunuous 300 mm of weld length. Max. dim. of any individual pore is not to exoeed t/8. max. 2 mm.

Porosity on line is not to penetrate weld surface. largest pore dim. t/8. max. 2 mm.

Isolated sl!lg• Length <t/2. width <t/4, max. 4 mm.

Slag lines• Lei!~ <;2t. max. 50 mm. width <;2 mm.

For «wagon trackS» width of each parallel slag line is not to exoeed I.S nun.

Length <;2L max. 50 mm.

Max. 6 mm. Lengtho Max. OD/2.

Not acceptable. May be removed by grinding.

For t<;l2.5 mm: Max. 3 and 2 mm respectively. Fort> 12.5 mm• Max. 4 and 3 mm respectively.

ExlefDal concavity not acceptable.

fntei-nai concavity acceptable provided that the density of the radio­graphic image of the concavity does not exoeed that of the adjacent base metal.

Depth <;tit 0. max. 0.8 mm.

For girth welds the length of an undercut in any continuous 300 mm of weld length is not to be more than•

Max. 50 mm for depth <;t/10. max. 0.8 mm Max. 100 mm for depth <;t/20. max. 0.4 mm

For longitudinal or spiral welds the length is not to be more than max. 1/ S of the above limits for girth welds.

For depth <;0.3 mm. undercut may be accepted regardiess of length

2. 3. 4

2. 3. 4

provided its shape and notch effect is not considered detrimental. 2. 3. 6. 7

2. 3. 7

3. 4

continUous tenich of weld whicb equals five times the lenath o( tbc defect ..... Sl Observed cracks should initiate more cxlenSivc non--dc5trUc:tivc testing or

the joint and revision of the welding procedure. 6) The dcplll to be mcasuRd by mcd1anical means.

sla& ~usions. incomplcle pcnetralion. misalia:n­lhi'<M:llh Qr undercut are to be judJCCI as lhe in queslion..

7) Severe corrosive cnvironmenl may no:essilale more strinaent require­mans to be adopted.

8) The \Olal lcnalh of hollow bead in any COilliDuous 300 mm len&:th o( weld mct.al shall not cxc:ccd SO mm. Individual adjacent hollow bead dis-­continuities. each exceeding 6 mm in length. are to be scparaled by a1 least SO mm of sound meW. time lllc defect timiiS as per ootcs 2 and 3 within any

58

Table 10.2 Pipeline and pipeline risers Definitions and radiographic characterization.

POROSITY'

Definition: Voids due to entrapped gas.

Radiographic characterization:. Sharply defined dark shadows of rounded or elongated sha· pe.

HOLLOW BEAD'

Definition: Elongated voids in the root pass.

Radiographic characterization: Sharply defined dark shadows in line of elongated shape.

SLAG INCLUSIONS'

Definition: Slag entrapped during welding.

Radiographic characterization: Dark shadows of irregular shape.

SLAG LINES'

Definition: Elongated cavities containing slag.

Radiographic characterization: Dark lines parallel to the weld edges.

LACK OF FUSION'

Definition: Plane defect due to incomplete fusion between beads or be­tween metal and parent metal.

Radiographic characterization: Thin dark line with sharply defined edges. The line may tend to be diffuse and wavy depending upon the orientation of the defect with respect to the x·raybeam.

INCOMPLETE PENETRATION'

Definition: Gap left by incomplete filling of the weld root with weld me­tal.

Radiographic characterization: Dark continuous or intermittent line following the weld root

Definition: Fracture in the weld metal or in the heat affected zone.

Radiographic characterization: Fine dark line. The line may terid to diffuse and wandering in direction. ~»>·•

UNDERCUT,

Definition: A groove in the surface of the pipe following the edge of the weld.

Radiographic characterization: Dark line along the edge of the weld. The line may be more or less diffuse dependent on the shape of the undercut.

-........ , . . - ,;:::­''' . ,, -:/''''"' ,,,,.~ ~.... . . ,, ~I I IIIII I\$ ...~ . . ,,

-

--~---~------~~--"'''' tl I ~ 111111111 """''~' ;..-,., ~~" ''Jh,, ..... ,,,~

, " , ' ._ _____ ..;· .......... ,-'.;... ____ ...,.._,

1/jll1111111 lriJ 111111 ,,_ 111111') _' .

"''''" VII'"' '"""'''~.- -.... ,, ~-------------~~~~ ~~·~~-------------'

10 PER CENT ........ ........ . ...... . ........ .. •·• .. ,... . ...... . . . . . . . . . . . . . . . . . ........ ........ ........ ........ . . . . . . . . . . . . . .. . . ...... . . . . . . . . .

59

lmm PORE DIAMETER

3 PER CENT 1 PER CENT

• •

•

2mm PORE DIAMETER

10 PER CENT 3 PER CENT

• • • • • • • • • • • • • • •

.. ·. • • • • • • • • • • • • • • • • • • • • • • • • •

• •

4mm PORE DIAMETER J!)W

10 PER CENT

• • • • • • • •

Fig.10.7 Typical distribution of porosity by proje<:ted area.

61

APPENDICES

The purpose of the appendices to the Veritas Rules·for sub­marine pipelines is to provide recommended practice. meth­ods and procedures for design, construction and inspection of submarine pipelines.

The appendices give guidance, methods and procedures satis­fying the Rules' requirements. The engineer is free to use oth­er methods and procedures than those recommended, provid­ed an equivalent standard of quality and safety is obtained.

Each appendix is self-contained and the procedures and methods given may be used independent of the Rules alt­hough the content of the appendices is directly related to the Rules.

In the appendices text reference to specific paragraphs in the Rules is made by giving the paragraph number marked with the letter(R), see 5.4.2 (R).

63

APPENDIX A ENVIRONMENTAL LOADS

A.l Wind loads A.l.3.2 In-line excitations may occur when

1.7 <V,<3.2

where

Static (constant~ quasistatid wind forces. which are as· y r sUmed to be constant as long as the wind is· constant. These forces are assumed to act normal to the pipe axis in V the plane defined by the pipe axis and the wind direction. fi See A.l-2. D

v f,.o wind velocity normal to the pipe axis natural frequency of the pipe pipe diameter

.. . Cy,iic wind forces due to vortex shedding. Also these forces are assumed to act normal to the pipe axis. They !nay act in two planes - «parallel» and (tnormal)) to the i.vind direction. See A.l.3.

qw = 0.613CV/D,

Wind force per· unit length of the pipe. acting normal topjpeaxis in N/m Shape coefficient according to A.l.2.2 CompPnent of \he wind velocity normal to the pipe axjs ill rill sec:, Total outer diameter of pipe. i.e. including coating etc... in metres.

k (meters> 5 ·10 _,

5 ·10 -· 3 ·IO-l 3 ·I0-·1

5·IO-L5·I0·2

A.l.3.3 Cross-flow excitations may occur when 4.7 < V, < 8.0. V,asdefinedinA.I.3.2.

A.I.J .4 The amplitudes of the vortex shedding induced mo­tipns due to wind may be derived according to the simplified approach for vortex shedding in steady current given in A.2.

~·substituting· the mass density of the water with the mass density of the air. · ·

A.2 Vortex shedding due to current

A.2.1 General

A.2.1.1 Fluid flow past a riser or a free span on a pipeline may cause unsteady flow patterns due to vortex shedding. This may lead to oscillations of the pipe normal to its axis.

A.2.1.2 Normally two types of oscillations may be encoun· tered: oscillations in Jine with the velocity vector <in-line mo­tionl. and 9scillations perpendicular to the velocity vector (cross-flow. motionsl. Such .oscillations may be investigated according to A.2.2 and A.2.3.

A.2.1.3 For certain critical flow velocities. the vortex shed· ding frequency may coincide with or be a multiple of the na· tural frequency of the pipe. resulting in harmonic or sub­harmonic excitations.

A.2.1.4 The vortex shedding frequency may be obtained as'

where

f = s,.v D

Fotr sevcoral pipes (relatively) close together. group w;,.. into account. However~ if no adequate ~

effects for the specific case is avail· cDI~ffic:ien•ts given in A.l.2.2 may be used for D

vortex shedding frequency (Hzl Strouha!'s number flow velocitY normal to the pipe axis pipe diamter

.l!l1! .. \111~,inllltykluai pipes in the group.

sens1uve to dynamic construction. transportation or opera~

of the wind is to be taken into det.ernninin• the wind loads. This may either

Sllst loading factors. or by use for the wind loading.

il)duced cyclic excitations of pipes may occur

For pipes. Strouha!'s number is a function of the Reynold's number. see Fig. A.2.

A.2.1.5 For determination of the velocity ranges where vor· tex shedding induced oscillations rna~· occur. a parameter. Vr called the redut:ed velocity. is used. V, is defined as

where

v v, = f,.o

with or perpendicular to the wind di· V a closer description of the vortex f,

phc.-.ornena. see A.2. D

flow velocity normal to the pipe axis natural frequency of the pipe pipe diameter

64

A.2.1.6 An other parameter controlling the motions is the A.3 Recommended values of hydrodynamic coefficients stability parameter. K5. defined as

where

0 e D

where

m =

y(x)= L d

logarithmic decrement of structural damping mass density of surrounding water pipe diameter effective mass per unit length of the pipe. defmed as

mass per unit length. including structural mass. add· ed mass and the mass of any fluid contained within the pipe mode shape of the actual pipe span length of the pipe submerged length of pipe

A.3.1 General

A.J.l.l The proper hydrodynamic coefficients to use in each case will depend on the flow and pipe conditions character­ized by

Reynold's numbedR, = U D/v) Keulegan-Carpenter number (Kc = U m • T /D) pipe roughness (k/D) distance between the pipe and a fixed boundary (H/ D)

where

D pipe di3.meter H clearance between the pipe and a fixed boundary T wave period k roughness height U flow velocity U m maximum orbital particle velocity

kinematic viscosity of the water

A.J .1.2 The hydrodynamic coefficients should preferably be obtained from relevant model test. taking into account the ac­tual values of the different parameters specified in A.J.I. In the following some proposed values of the hydrodynamic coefficients are given.

A.3.2 Added mass coefficient

A.3 .2.1 The added mass coefficient for a circular cylinder as A.2.2 In-line oscillations function of the distance from a fiXed boundary is given in

A.2.2.1 Resonant in-line vortex shedding induced oscillations Fig. A.?. may occur when 1 .0 < V, < 3.5 and Ks < 1 .8. For definition ofV,and K5• seeA.2.1.5 and.A.2.1.6.

A.2 .2.2 Depending on the flow velocity. the vortices will eith· er be shed symmetrically or alternatively from .either side of the pipe.

For V, < 2.2. the shedding will be antisymmetrical. and the necessary flow velocity for onset of motion may be d.etermin· ed from Fig. A.J.

ForV,> 2.2. the shedding will beantisymmetrical.

A.2.2.3 The maximum amplitude of the motions due to in· line vortex shedding may be detennined from Fig. A.4.

A.~.3 Cross-flow oscillations

A.2.3.1 Cross-flow oscillations may occur forKs< 16 and values ofV, as determined from Fig. A.5.

A.2.3.2 The maximum amplitude of the cross-flow oscilla­tions may be de~ermined from Fig. A.6. The mode shape par­ameter. y, used m thiS figure is defined as .,,_

L 1/2

J [y'<xl]dx

Y = Ymu 0

L

J [>"(xl]dx

0

where

y (xl= mode shape Y max= maximum value of the mode shape

For a sim~ly supported beam in first mode. y is equal to 1.16. For a cantilever beam in ftrst and second mode. the rvalue is equal to 1.31 and 1.50 respectively.

The fJgUre may be used for both smooth and rough pipe sur­faces. For a pipe which is not influenced by any fiXed bound· ary. the recommended added mass coefficient is 1 .0.

A.3.3 Drag coefficient

A.3.3.1 Tpe d!1lg coefficient as function of the Keulegan­Carpenter. number for smooth and marine growth covered pipes for supercritical Reynold's numbers is given in Fig. A.B. The figure is valid for free field flow without any influ­ence of a fiXed boundary.

A.3.3.2 The drag coefficient for steady current is equal to the asymptotic value for Kc equal to infmity. For combined wa­ve and current action. the increase of Kc due to the current may be taken into account.

A.3.3.3 To determine the drag coefficients for pipes close to a fixed boundary. the drag coefficients given in A.3.3.1 may be multiplied by a correction factor obtained from Fig. A.9.

A.3.4 Lift coefficients

A.3.4.1 The lift coefficient for a pipe at a fiXed boundary in oscillatory flow is given in Fig. A.IO. The figure may be used both for smooth and rough pipe surfaces. In steady flow. the lift coefficient may be taken equal to 1.0. For combined wave and current action the increase of Kc due to the current may be taken into account .when determining the lift coefficient from Fig. A.lO.

A.3.4.2 To determine the lift coefficient for pipes at a certain distance from a fiXed boundary. the lift coefticients given in A.J .4 .1 may be multiplied by a correction factor obtained from Fig. A.ll.

A.4 Wave slamming

A.4.1 Wave slamming loads

A.4.1.1 Horizontal pipes in the wave zone may be subjected to forces caused by wave slammin_g. The dynamic response of the pipe should be accounted for.

65

The wave slamming force per unit length of the pipe maY be calculated as

Fs = l/2eCsV2 D

slamming force per unit length in the direction of the velocity mass density of the surrounding water slatp.ming coefficient member diameter velqcity of the water surface normal to the surface of the pipe. Normally the vertical water surface velocity will apply

slamming coeffiCient Cs may be determined us­and/ or experimental methods. For smooth.

cylinderS the value of Cs should not be taken less

The contribution to fatigue from each wave block is gi­ven as:

~j n;

R

K

n •= 20 ( i )K Y· = R .!!L l: -J Nj i""20-nj 20

nt~mber of waves within block j critical number of stress cycles (from relevant S-N curvel associated with !> o;

number of stress ranges in excess of the limiting stress range associated with the cut off level of the S-N curve reduction factor on number of waves. For a gi­ven element only waves within a sector of I 0 degrees to each side of the perpendicular to the member have to be accounted for. In case of an undirectional wave distribution, R equalsO.II. slope of the S·N curveHn log-log scalel

A.4.2.2 The calculated contribution to fatigue due to slamm-. ing bas to be added to the fatigue contribution from other

As the slamming force is impulsive. dynamic amplifJ- variable loads. w~st b~ considered when calculating the response.

pip<; section fixed at both ends. dynamic amplification of 1 .5 and 2.0 are recommended for the end moments A I.

the midspan moment. respectively. A2.

Th~ fatigue damage due to wave slamming may be rc·:·~iet(:rrrdn!:d "!'COrding to the following procedure: AJ.

''Determi,ne minimum wave height, Hmin' which can cau· se slalnming Divide the long term distribution of wave heights. in ex·

-'··c~ ofHm;,. into a reasonable number of blocks Fq(.each block the stress range may be taken as'

l> o;= 2 [ao;...,-<ob + crwll

·-'··-'-'·f'"~::::.::;:-tcc.C;cc_.c. .. a,o>m.,; _.str:ess in ... the element.due to the slam load given inA.4.1.2 stress due to the net buoyancy force on the ele­nierit ' stress due to vertical wave forces on the element factor actounting for dynamic amplifications. see A,4.j.4

Each slam is associated with 20 approximate linear deca­yin~ stress ranges

-

A4.

A5.

A6.

A7.

A8.

References to Appendix A

BSI Code of Practice No.3. Chapter 5. Part 2' «Wind LO'lds>>. September 1972. CIRIA Underwater Engineering Group.· Report UR8' «Dynamics of Marine Structures>>, London. Ju­ne 1977. Blevins. R.D., «Flow-induced Vibration•. Van Nos­trand Reinhold Company. New York. 1977. Heideman. Olsen and Johansson: «Local Wave Force Coefficients>>, ASCE Civil Engineering in the Oceans N. September 1978. Sarpkaya. T.: «Vortex Shedding and Resistance in Harmonic Flow about Rough Circular Cylinders>>. BOSS 76-conference. Trondheim. Norway. August 1976. Sarpkaya. T., <<In-line and Transverse Forces on Cy­li!?ders near a Wall in Oscillatory Flow at High Re­ynold"s Numbers». OTC Paper No. OTC 2980. May 1977. Sarpkaya, T.: «Hydrodynamic Drag on Bottom­mounted Smooth and Rough Cylinder in Periodic Flow». OTC Paper No. OTC 3761. May 1979. King. R .. Prosser. MJ .• John. DJ., «On Vortex Ex· citation of Model Piles in Water>>, Journal of Sound and Vibrations. Vol. 29. No.2. pp. 169-180. 1973.

c

' ''" ~ ''f~hf=---- \ g;;--­~ ' ,.,;,J

\~u I ~~;-.,~ \\.1 ~,-• .---I • -;r I ' ' I \KS&'f~oo'"

0~--~-T-T~~~--~~~~~~+---~-T-T~~~ 104 105 105 107

'? Re

Fig. A.l. Shape coefficient for circular cylinders. Ref. A.l.

66

LAMINAR SUBCRITICAL jt:Hm-

CAL I SUPEf CRITICAL·

0.4

s 0.3

0.2

0.1

0.1 1.0

-, !"

10 102 103 104

hi J ~ ~ I

I

.,0, 106 107 Re

Fig. A.2. Strouhals number for circular cylinders as function of reynolds number. Ref. A.8.

... 2.5

FIRST 11NSTABILITY 1 SECO~D INSTAB. REGION

I REGION v,

/ !" I !

/ I •Jt-

MOTION

2.0

I

I NO MOTION

1.5

1.

---- - ··- ·--------- ------

0 0.5 l.O 1.5 2.0 Ks

Fig. A.3. Flow velocity for onset of in-line motion. Ref. A.2.

AMPL. OIAM.

0.20 -r-----r------,------r----,

0 .15-r---"\-t----f----+------l

IN -LINE MOTION

0. 10-f------+~..::----+------J.------1

v, > 2.2

0.054---------+-----~T-t-~~----t--------;

0 0.5 1.0 1.5 2.0 Ks

Fig. A.4. Amplitude of in-line motion as a function of K5 Ref. A.2.

6.0

v,

5.

4.0

3.

0.0

104 ,as 106 . 1C Re

Fig. A.S. Flow speed for onset of cross flow motion. Ref. A.2.

AMPL. '(·DIAM.

1. 2 CROSS FLOW

1.0~,---+-----+-----_J

0.8

0.6

0.2

2 4 6 s 10 i2 14 Ks

Fig. A.6. Amplitude of crossflow motion as a function of K 5 Ref. A.3.

• • • • • • • • • • • I I

-·-~

~

3.0

Cm .9 ~

~ r---1.0

oo 0.~ 1.0 I S. 2.D

~

2.S J.O M ..,.

1S

Fig. A. 7. Recommended value of the added mass coefficient, Cm for a circular cylinder.

CD - ,...___

" v ~ARINE GROW H

\ ROUGH., ess

2.0

'·- \ .......... -........._ \ -- • nn

.......... - , 0.70

1.0

ST EEL RC f.JGHNES s.r

0.0 --

0 10 20 30 40 50 60 K.,

Fig. A.8. Drag coefficient for a circular cylinder in oscillatory flow. Ref. A.4.

i

70

67

2.0 I ,-,.:•.-..

Co/co.,..

! 1. 5

I j I

1.0 -' .t

___ _l -- I J 0.0 0.2 0.4 0.6 0.8 1.0

H/0

Fig. A.9. Influence of a fixed boundary on the drag coefficient of a circular cylinder in oscillatory supercritical flow,K.>20,R~= 105 -2·106•

Ref. A.S, A.6 and A.7.

s. ~

CLO \ 1\..

I

""'" ~ ~ ---1-----

•-

3 ..

2.0

--- --1.0

0.0

0 10 20 30 40 so 60 10

Kc

Fig. A.lO. Lift coefficient for a circular cylinder at a fixed boundary in oscillatory flow. Ref. A.S, A.6 and A.7.

1 . 0

CL/ Clo

1\

\ 0.8

0.6

0. 4

0.2

..

0. 0 0.0

\ \

·-

0.2

-.......__

0.4

~-I fH

/////// -

- I ----

0.6 0.8 1.0 H/0

Fig. A.ll. Variation of lift force coefficient as a function of the distance from a fixed boundary. Ref. A.S, A.6 and A.7.

~

68

APPENDIX B BUCKLING CALCULATIONS

B.l Local buckling

B.l.l In the absence of more accurate information (or methods} the critical combina.tion of longitudinal and hoop stresses may be expressed as follows:

(...£&_)a+~ -I Uxcr aycr

(Compressive stress is positive in this formula.)

a,

N A M

w D

a,.N + r1xM

~ (Compression positivel

M w (Compression positivel

aXial force. " (D - tl t = cross sectional area bending moment.

f (D- tl2 t = (elasticl section modulus.

nominal outer diameter of pipe. nominal wall thickness of pipe.

a~cr == critical longitudinal stress when N is acting aJone <M= o. P; ol.

a•

p, P; p r1ycr

Uycr

Of

"F[t-ri.oot( ¥ -2o)]

forD/t<;20

for20 < Q < 100 t

specified yield strength (corresponding to 0.2 96 resi­dual strainl.

critical (maximurnllongitudinal stress (when deter­mined as·M/W) when M is acting alone (N= 0. p= O).

"F ( 1.35-0.0045 -T) 1 + lQQ_ _!!:,_

D/t D rJycr

= (p,- p) 2t = hoop stress to be considered in buckling analyses.

<Not necessarily equal to actual hoop stress.) external pressure. internal pressure. Pe- Pi= external <(overpressure>>. critical hoop stress when p is acting alone (N = 0. M=O).

a,E =E( 0 ~t)'

B. I .2 The permissible combination of a, and "• should be defined by inserting permissible usage factors in ihe formula of 8.1.1 for critical combination. The permissible combina­tion may then be expressed as

where llxp permissible usage factor (i.e. permissible value of

~)whenay= 0.

""" lJyp permissible usage factor (i.e. permissible value of

..E.Y..) when Ox::: 0. Gycr

Other symbols are defined in B.l I .

The usage factors should depend on whether the critical stress is in the elastic or in the plastic range. Therefore nor­mally ~,.. will be smaller than >Jxp.Recommended usage factor are given in 8.1.3.

B. 1.3 . A reco~me_nded dependence ':'" the degree of plas­ticity mvoJved ts gtven for nsers dunng operation in Table B.l. For pipelines during operation the factors in Table B.l ;na~ be multiplied by 1.2. For both pipelines and risers dur­mg mstallauon. the factors in Table B. I may be multiplied by maximum 1.44. However. no usage factor should exceed 1.0. See also 8.1.4.

Table B. I Permissible usage factors - general case

Loading .£.E <; I 1<~ <3 _.£.E_ Condition >3

aF "F ar

a) ~.= 0.52 ~.= 0.48 + o.o4.£.E ~.= 0.60 "F

b) ~.= 0.68 ~.= 0.62 + 0.06 :~ ~.= 0.80

aE = critical stress if completely elastic material. (uxE or ayE)

a,.E is defjned in B. 1.1. . E ·t

"•E "= 0.42-o--

8.) .4 For most pipes buckling due to a, alone will be nearly plastic. an~ buckling due to a,. alone will be nearly elastic. For such ptpes the recommendations of B.J.3 will lead to the usage factors given in Table B.2.

Table B.2 Permissible usage factors- typical D/t

Installation Operation

Loading Pipelines Pipelines Pipelines

condition and Zone I Zone 2 and risers risers

~ .. 1/yp 1}xp 1Jyp ~ .. 1}yp

a) 0.86 0.75 0.72 0.62 0.50 0.43 b) 1.00 0.98 0.96 0.82 0.67 0.56

Empty (airfilledl liquid pipes during «Operation» may be considered as during <<installation•).

B·2 Propagation buckling

8.2.1 Theoretically. the probability that a propagating buck­le will be initiated is not higher (but may be lower) than the probability that a local buckle will occur. However. due to the great economic ri$k involved in propagation b!Jckling.· in­creased safety. or at least a closer investigation. may be ad­viceable. For such investigation the available results from the later research work sbould be V;tilized.

8.2.2 A propagation buck!~ cannot be initiated in. ()r pr()pa­gate mto. a portion. of the pipe where the maximum externaJ

69

overpressure is Jess than the propagation. pressure_ (pp) of the pipe. A simplified consideration of plasttc work mvolved m total collapse gives

'fr•'"'J.JS;,ar( D~t )'

wpjch may be considered a lower bound. p., will most prob­ably be somewhat higher than give~ by the above formula. further. the initiation pressure (p;,) ts somewhat htgher than

·. PB.f ·B-2:3 A propagation buckle cannot be initiated in. but may p,ropa~ate into. a portion of the pipe where the maximum ex­iernal 9verpressure is between P..- and P;.<p.,< p < p,.,). If 9uckle arr!'Stors are installated where P >Pin· there is no need in~U,IIing sue~\ arrestors where Pp< < P < P;n·

~.3 J;Juik)ing of the pipe as a .. bar~ ·B.J.l . If there is doubt about the stability of a span against

' <<b<!rbuckling». the stability may be checked according to the

roitowini-

,, 'il-f. Tbl: effect of internal ;tnd external pressures may be ·· taken into 'account by introducing an <<effective>> axial force.

s. whiclj in effect is equivalent to the real axial force in an «ordinary>> compression member in air. Otherwise the pro­cedure is as for <<ordinary)) compression members in air.

8.3 .3 For a pipe subjected to an axial force N in the pipe it­self. an internal pressure Pi and an external pressure Pe- the «<effective>) axial force with respect to ccbar buckling•) is:

S = N + ~ (D- 2tl2 P;- ~ D2 p,

(Compression positive in this formula.l

The formula applies to any type of axial restraint. since the restraint is reflected in N.

8.3.4 lfS is positive. S should be compared with the critical axial force with respect to «bar buckling» of the considered span. If S is zero or negative. buckling is not possible. (Nega­tive S has a similar effect as tension in an «ordinary» mem­ber. even if the real axial force N is compressive.)

B.3 .5 The required minimum critical axial force Scr in rela­tion to S should depend on axial restraint If both ends of the considere\1 span are ftxed against axial displacement. S need not be Jess than Scr Even with S exceeding Scr the pipe may find a new eqilibrium position after a limited lateral deflec­tion. The possible bending stresses should in such cases 0. checked. If the considered span is free to contract axially. the safety against buckling should be as commonly used in steel construction.

70

APPENDIX C QUALITY CONTROL OF MATERIALS.

QUALIFICATION OF WELDING PROCEDURES AND WELDING PERSONNEL

C.l General

C.l.l Scope

C.l .1.1 This appendix is a guidance to quality control of rna· terials and defines methods for determination of chemical composition. mechanical testing of materials and welds ~nd schemes for qualification of welding personnel.

C.4.1.2 Wet analyses and. spectrochemical analyses are to be made on materials sampled by e.g. drilling or milling and be representative for the material composition.

C.4 .I .3 Spectrographical analyses are to be made on a clean. bright metal surface after grinding to a depth at least 2 mm below the surface. Analyses of semi-killed steel are. however. to be taken at approximately one quarter thickn~ position.

Other standardized testing methods. test specimens and C.4.1.4 Ladle analyses are to be taken prior to <tnd during combination of tests may be used subject to agreement. steel casting to ensure a uniform composition of Cl!Ch l!~L

C.1.2 Definitions

C.t.n Test sample The part of the material (pipe. plate. sec­tion. east-on bar; pi«:!'C cut from forgings etc.) which is select· ed for testing.

c.1.2.2 Test specimen' Tbe part of !he test sample which is prepared by mac:1lining etc. for carrying out the various lest$.

C.I.J Testing equipment

Testing equipment is to be of ~roven ~esign with. adequ~te capacity and accuracy. Tbe equtpment IS to be satisfact?rilY maintained and kept in accurate condition by regular calibra· lion and check routines. Endorsed calibration records are to be kept available in the testing facility.

Only competent and trained personnel is to carry out testing.

C.2 Steel making

C.2.1 General

C.4.1.5 Check analyses are to be taken on the fmal products. The check analyses may. however. optionally be determ,ined at an intermedi<tte stage. e.g. on plates. provided th~ results are stated on the certiftcates. ·

C.4.1.6 Determination or"chemical composition is" to include all eleme!ll$ listed in Table 5 .I (R) and o!be~ rS!JWning :Je­ments intentionally •deled to control the material properues. When the steel is imdc from ~p. the !lliDluf~.'!r~ ~ !'Is<> to check the content of other residual elements which may impair the quality of the product. e.g. Sn. A~ Sb.

C.4.1.7 The chemical composition is to be stated on the certi· licate by the elements listed in Table 5.1 (R) apd al!y other elements intentionally added to control the material propert· ies. Trace elements need. however. not be reported.

C.4.1.8 Recheck analysis Should a check analysis fail to meet the specified composition limits. all other heats within tl!e sa· me batch are to be subject to a complete chemical analfsis­Only those heats which are -,vithin the specification. may be accep~d.

C.2.1.1 Steel may be made from pig iron. sponge iron or re­cycled scrap. Residual elements are to be kept at a level C.4.1.9 Requirements are given in 5.2.4 (R). which will not impair

hot working ability C.S Heat treatment weldability · mechanical properties C.S.l General

soundness c.S.I.I Heat treatment is to be carried out in a controlled surface fmish manner using calibrated equipment. Accuracy of temperature

C.~ .I .2 Ladle treatment is to be performed in a controlled measurement is to be within S"C. manner taking appropriate precautions to prevent humidity increasement and contamination.

C.J Steel casting

C.3.1 General

C.3 .1.1 Steel may be ingot cast. continuous cast or mould cast. Sequence casting is subject to agreement.

C.5.1.2 Temperature fluctuations during austenizing are to be within ± 1 0°C. During tempering. stresS relieving or post· weld heat treatment carried out within the range 500-650°C. the fluctuations are to be within ± 15°C.

C.6 Surface defects in base material

C.3.1.2 The cast ingot. item or slab is to be inspected for sur· C.6.1 General face defects. Defects are to be removed prior to subsequent wor)<.ing.

C.3.1.3 Spun cast products are to be machined to a depth en· suring removal of impurities and surface defects.

C.4 Chemical analyses

C.4.1 General

C.4.1.1 The chemical composition is to be determined by

C.6 .1.1 The steel manufacturer or any other works perform· ing operations which m!lY influence the surface finish of the material. ar~ to take precautions oand make regular checks with suitable equipment to ensure that the final surface finish is acceptable.

C.6 .1.2 Surface defects are to be removed. Superfteial indica­tions formed at high temperature and without a sharp tip. may be accepted if their maximum depth is less than 5% of the nominal wall thickness. however. maximum I mm.

either wet analyses. spectrochemical or spectrograpbical C.6.1.3 Local surface defects may be ground out provided the methods. remaining thickness is within the minimum specined.

C. 7 Mechanical testing

~e~eral

"1 The. material properties are to be determined on the . in its final condition.

· Samples for testing are normally to be cut from the ·or provided as integrally attached coupons. or ex· pif;CCS-

are to be prepared in a manner which mechanical properties and \he testing.

tensile and bend test specimens from roll· are to retain the as·roUed surface fmisb. ·

. Tensile test specimens from a product· of· uniform to have a rectangular cross section be-.

and with the dimensions as given in Fig. specimens from castings ancl forgings of va·

to have a round cross section.

Sirenliih- Is to ·tie· ialien as the lOwer yield resulting in 0.2% permanent strain (offsetl

· O.S% total elongation during testing.

71

C.7.5 Cbarpy V-notch impact testing

C.7.5.1 Charpy V-notch specimens are to have dimensions as given in Fig. C.4. The provisions ofiSO R 148 «Beam impact test (V-notchl». are to be applied. When using subsize speci· mens (Le. I 0 x 7.5 and I 0 x 5 mml. all the dimensions except the height are to be in accordance with the said document. Full size specimens are to be used unless they can not be rea· sonably provided. The impact toughness is the absorbed ener­gy expressed in Joule (or kpml. and the symbol being KV T for specimens orientated transverse to the principal rolling/ working direction.

C.7 .5.2 Charpy V·notch specimens sampled from the base material are normally to have their longitudinal axis transver­se to the principal rolling/ working direction. The notch is to be perpendicular to the rolled surface.

When the wall thickness exceeds 50 mm. the Charpy V -notch specimens are to be sampled at approximately t/4 position below the outside surface.

c. 7.5 .3. Tbe scale of the llUIChine is to be calibrated to a~ ac: curacy of ± 0.5% of the machines maximum striking ener­gy.

C.7 .5.4 Wilen imPact testing is specified to be carried out at a iemperature lower than the room tempciature. !be test speci· men is to be cooled down by immersion for I 0 minutes or more in a bath of a suitable temperature (e.g. methyl alcohol cooled by solidified carbon dioxidel. When withdrawing the test specimen from the bath. the bath temperature is not to be higher. and not more than 2°C lower. than the required test temperature. The specimen is to be inserted in the machine and tested within 5 seconds.

C.1.5.S Requirements are given in 5.2.7 (R). 5.2.8 (R). 7.2.4.2 (R) and 8.5.3.4 (R). .

_R~qui~ern«•ts are given in 5.2.6 (R). 7.2.4.2 (R) and C.?.6 Macrosectiqn of welcled joints

be tensile tested by the ring expansion ,,~~-,..~''"'~'" ••M"·'"'"''. w .a&re:llment.

:test· specimens are to have full wall thickness. root and face bend specimens are to be approxi-

The width of side bend specimens are to be niay be rounded off to a radius of 1/1 0 weld reinforcement on both faces is to

· with the original surfaces (Fig. C.2). j!!e located symmetrically on each specimen. ·

are given in 7.4.2 (R) and 8.5.3.4 (R).

!lick break test specimens are to have full thick· reinforcement retained on both faces and

in Fig. C.3. The specimens are to the thickness from both sides at

niay be fractured either by pulling. . or by striking one end while the other is

C.7.6.1 Tile width of the macrosection is to be minimum three tinies the width of the weld. The section is to be prepar­ed by grinding and polishing. and etched to clearly reveal the weld metal and the heat affected zone. The macrosection is to be examined using a magniftcation of at least Sx.

C.7.7 Hardness testing of welded joints

C. 7. 7 .I The prepared macrosection is to be used for hardness testing using the Vickers method with 5() N (S kp) load. In· dentations are to be made along mtverses. each approximate­ly I mm below the surface at either side of the weld. In the weld metal minimum 6 indentations equally spaced along the traverses are to be made. In the HAZ indentlltions are to be made along the traverses for approximately each 0 .S mm into unaffected material. and starting as close to the fusion line as possible. Reference is made to Fig. C.S.

C.1.1.2 In case of a.single reading slightly higher than the specified limit funher indentations should be made to check if the «high» value Wll$ an isolated case. Then indentations are to be made in the adjacent region as well as on the opposite side of the macrosection along the specified traverses. If these additional tests give a hardness within the speciftcation limit. the slightly high value may be accepted.

C.7 .7 ,3 The.. accuracy of hardness testing with the actual equipment and method is to be taken into account in the evaluation of the readings.

C.7.7.4 Requirements are given in 5.2.10 (R). 5.2.12 (R). 7.2.4.2 (R) and 8.5.3.4 (R).

C. 7.8 Straht ageiDg testing

C.7.8.1 The specified mechanical properties of a product is R!'!~l,lirenti:Qts are given in 8.5.3.4 (R) and &.S.S.2 (Rl. guaranteed in its final supply condition. In special situations

72

subsequent operations may still affect the material properties. e.g. by field bending of pipes to bends. pulling of pipes through J-tubes or pipelaying of reeled pipestrings. The frac­ture toughness is particularly sensitive to cold deformation. Strain ageing testing may then be a suitable method to asses whether adequate notch toughness does remain.

C.7.8.2 When the material is deformed to a fibre strain more than 3%. strain ageing testing is considered appropriate for pipeline systems required to have high resistance against brit­tle fracture. Base material and weld metal are then to be test­ed.

C.7 .8.3 Procedure: The material is to be cold strained by eith­er uniform compression or tensioning to a deformation of 5%. or to the actual deformation if this is greater. The mate­rial is to be artifically aged for 1 hour. The ageing tempera­ture is to be I 00°C, or 250°C for pipeline systems having ma­ximuiJl design temperature above 100°C.

The deformed and aged material is to be Cbarpy V-notch tes­ted at the irnpa~t testing temperature and meet the same re­quirements as specified for the pipeline system.

C.8 Sampling of test specimens

C.8.1 Seamless pipes

C.8.1.1 Tensile test specimens (transverse and longitudinaO and Charpy V-notch specimens (transverse> may be sampled from any location within the pipe material. However. if the pipe has been spun cast. the test specimens are to be taken at the inside surface of the pipe.

C.8.2 Welded pipe

C.8.2.1 Pipe material: Tensile test specimens (transverse and longitudinaO and Charpy V-notch specimens (transversel. are to be sampled 180~ from the weld.

C.8.2.2 Weld seam: The test specimens are to be sampled transverse to the weld. with the weld deposit at the center. as shown in Fig. C.6. The same applies for jointers which are produced in the I G· principal position (pipes horizontal while rotating).

C.8.3 Cold formed or forged bends

C.8.3.1 The test specimens are to be cut from an overlength behd section having received the same deformation and heat treatments as applied for the bends. Base material test speci­mens are to be sampled from the area of maximum tensional deformation. The longitudinal axis of the specimen is to be orientated transverse to the Qirection of the principal wor­king/ grain flow. When a bend contains longitudinal weld seam<sl. test specimens are also to be selected as described' ror welded pipe (C.8 .2).

C.8.4 Forged seamless piping components other than bends

C.8 .4 .I The test specimens are to be taken from a portion of the forging which has received a deformation representative for the working ratio of the most highly stressed cross sec­tion. For components with greatly varying working ratios and sectio11 thjcknesses. more test samples may be nec;essary.

Separately forged test blanks may be used when integrally forged extension samples can not be reasonably provided.

C.8.4.2 The test specimens are to be ~ed with their principal axis transverse to the direction of principle grain flow. and be at least 0.11 from the as-forged surface. Where transverse testing can not reasonably be performed due to the small size of the component. the test specimens may have longitudinal orientation.

C.8.5 Cast piping components

C.8 .5 .I Cast coupons are to be of a size and located in a man­ner realistically predicting the properties of the casting. The coupons are to be heat treated with the casting. and are not to be detached before completion of all heat treatments.

C.9 Welding procedure qualification

C.9.1 General

C.9. I. I The position for sampling of test specimens in con· nection with welding procedures for fabrication and installa­tion welding are shown by Figs. C.6 and C.7 respectively.

The welding procedure specification and the test results are to be presented on suitable forms including references to pro­ject. application. fabrication. installation company and eQdor· sement of witnessing.

C.lO Qualification of welding personnel

C.lO.l General

C.IO.l.l The purpose of qualification testing of welding per· sonnel is to verify that the welder or welding operator have the necessary training. skill and understanding to produce sound welds according to a qualified welding procedure.

C. I 0.1.2 In order to be qualified. welders and welding opera· tors are to be at least 18 years of age. and are to have passed a relevant theoretical and practical training program. ... ·

C.lO.LJ The company responsible for the welding opera· tions is prior tu qualification t.Sting. to confmn thllt each welder and welding operator have obtained adequate under' standing of

fundamental weldi!lg techniques signitlcance of welding parameters relevant materials response to welding operation of the welding equipment to be used welding procedure specifications handling of welding consumables relevant methods of non-destructive testing relevant acceptance criteria for weld defects

C. I 0 .I .4 Welding personnel to make buttwelds and fillet welds is to have passed qualification testing for single side. full section buttwelding of pipes in the principal position(sl required.

C.IO.I.S Welding personnel satisfying the above general con­ditions and having performed an acceptable test weld accord­ing to C. I 0.2 is thereby qualified.

C. I 0.1.6 For underwater welding additional conditions will apply. see C.I0.4.

C.IO.I.7 An endorsed qualification test record is to be ~ued after completion of an acceptable test weld. The record is to be of a suitable form containing information sufficien~ tO describe applied welding procedure. testing set up. evaluation methods and conclusions. ~t;ope of application and date of testing. ....

C.IO.I.8 Where a qualification of recent date is allowed transferred to a new project. the welding personnel is to be, informed about pllf(icular project requirements for which their welding performance will be specially important.

C.IO.I.9 Requalification is to be performed if the welding personnel has not regularly performed qualified welding within a period of more than six months.

73

doubled. and both the new welds are to be acceptable. No 'C, 0· 2· 1· p · further retests are permitted until the welder/operator has ... 1 . . nor to starting the test welding. reasonable time is passed acceptable additional training. !O be permitted to adjust the welding equipment.

lf the welding procedure involves more than one · .. :.,,.1"1f""'"' or more welding units. test welding is to include all

. Jl:""'ltic>ns and units necessary to complete the weld. Con­the performance test may require welding with dif-

\Vel~l)g units and welding parameters.

·Two pipe nipples of sufficient length to introduce are to be joined according to the qualified

The pipe diameter. wall thickness and the are to be selected in accordance with the

qualified.

installation of transmission pipelines the actual line shol,lld be US!'d for qualification testing.

Fpr welding of pipes with t < 5 mm or OD < I 00 mm. the test pipe dimensions are to be agreed upon.

C.l 0.2.4 For pipe diameters less than 300 mm. the complete joint ls to ·be welded. For testing on significantly greater dia· n>eter. the welding length is to be at leaSt half the circumfer­:~ce ~uch that. typical flat. vertical and overhead welds are made without interruption.

C.! 0.2.5 Minimum one stop and start is to be made during welding of the root and cap pass. Electrodes are to be com­pletely consumed. Light mechanical treatment is permitted for removal of scale. debris and minor local irregularities. however. not for the intent of removing weld defects due to unsatisfactory performance of welding. Welding is to proce­ed ,\Vith a speed representative for regular production.

0.2.6 Test material may be of semikilled or killed C-Mn steel for welding on pipeline system designed with unalloyed. mlcroalloyed or low alloyed steels with ultimate tensile

' ·620 MPa. Qualification for welding of strength grades or alloyed steel may require additional

''""'·'· ,,,,. ·-·"-"'!!'·'¥- ()!'_the actual material tYPe.

C.l0.3 Inspection and testing of qualification test welds

C.IO.J.l Each test weld is to be visually inspected and show .aworl<manlike appearance satisfying Table 10.1 (R). If found ~cceptable, the test weld is to be radiographed using a qualif· led p~dure based on X-rays. see section 10 (R). and comp­ly• with Table 10.2 (R).

C.I0.3.2 The test weld is also to be destructively tested if it lias been made with a welding procedure involving the gas metal arc welding process or other processes of high potential for non-fusion defects. Type and number of mechanical tests !U'e given in Table C. I.

Nick Face Root Side break bend bend bend test test test test

2 0 2 0 t..:12.5 4 0 2 0

8 2 2 0

0 0 2 0 0 2 0 0 4

If a_ failure occurred due to conditions beyond the welders/ operator's control. this failure may be disregarded. and a new opportunity to qualify given.

C.l0.4 Welder qualification

C.I0.4.1 A welder is qualified for welding when the condi­tions given in C.IO.I. C.I0.2 and C.l0.3 have been fulfilled. Qualified welding positions are given in Table C.2.

C.I0.4.2 A welder qualification is valid within the limits of essential variables as described below. If any of the following essential variables are changed, a new qualification test is re­quired

A change of welding process A change of welding direction A change of welding consumables from basic coated to cellulosic coated or vice versa A change of pipe diameter-from one to another of the fol­lowing diameter groupings: OD ..:100 mm. 100 < OD ..; 300 mm. and OD > 300 nun A change of wall thickness from t > 5 riun to t < 5 mm A change in principal welding position other than already qualified. see table C.2 A significant change of joint design e.g. V-groove to Y·groove

Table C.l

Principal test position Qualified welding positions

IG IG 2G IG.2G SG I G. SG

2G + 5G All 6G All

C.lO.S Welding operator qualification (or mechanized weld­ing

C.l0.5.1 A welding operator is qualified for welding when the conditions given in C.IO.I. C.l0.2 and C.I0.3 have been fulfllled.

C.I0.5.2 An operator's qualification is valid within the limits of essential variables as described for welders. see C.I0.4.2. Additionally the qualification is limited to the type of welding equipment qualified for the actual installation welding. Re­qualification is further to be initiated if there is made a chan· ge in the welding procedure which itself requires requalifica­tion. and this change is depending on the operator's control and skill. and necessitate a different operating technique.

C.l0.6 Qualification of welding personnel ·for underwater welding

C. I 0.6.1 Qualification of welding personnel working under· water is to be based on the scheme given in C. I 0 with the ad· ditional conditions specified herein.

C.I0.6.2 The test welds are to be produced under actual or si­mulated conditions for the work in question.

C.l 0.6 .3 In ~addition to the requirements given in C. I 0.1.3. underwater welding personnel is initially to have passed a relevant welding test above water before beeing pennitted to qualify for welding underwater. Prior to the tests. the wel­ders are to be given sufficient training to get familiar with the influence of pressure. temperature. atmosphere etc. on weld· in g.

If~ test weld fails to meet the specified require­. w~der or welding operator may be permitted im- C.I0.6.4 Approval of welders/operators are to be based on retesting. Tben the number of test welds are to be visual. mechanical and radiographic testing.

74

Type and number of mechanical tests are given in Table C. I. is to be examined visually and by radiography. If interrupted period exceeds 6 months. the performance test is to be as specified for initial qualification. C.J0.6.5 The applicability of a welder's certificate is given in

Table C.2 as regards welding positions. Applicability for welding at greater water depths or other pressure or diving modes will be decided in each case.

C. I 0.6.6 For underwater welders any change of coated elec· trades will normally require requalification.

C.l0.6.7 Renewal of the certificate for underwater welders may be required if welding has been interrupted for a period of more than 3 months. The retest is then to consist of rriak· ing minimum one test coupon of length approximately 300-400 mm in an agreed welding position. and the coupon

For underwater welders who are on stand·by and without necessarily doing regular underwater welding. the conditions for maintenance of the qualification is to be ··specially agreed , upon.

C.I0.7 Extraordinary requalification of welding personnel

C.I0.1.1 Welding personnel may be required to reQualifyjn case of negligence or questionable welding performance. In such cases the welder/ operator in question shall present evid· ence of further acceptable training. and are to be requalified as for initial qualification.

75

SOmm.

HansYIH5t, Of longitudinal. base material tensile te.st specimen·

REDUCED SECTION

r--6Dmm -1 : II t·~-11

25mmRmin. t

Weld tensile test- fabticati on of pipes/piping c.omponents.

SPECIMEN MAY BE MACHINE OR OXYGEN CUT. I EDGES SHALL BE PARALLEL AND SMOOTH.

r--1 -----r:;;;l=r-/_,________,~PPROXIMATELY 25mm

,,. APPROiflMATELY 225 MM -----~~ i . ... WELO REINFORCEMENT SHOULD NOT BE

. ,· .'T(1~VED ON EITHER SIDE ?'?¥··-·'';>:O:.:.F_ . ..:S:.:.P.::E.::C.:.;IM::.:E:.:N;_ _____ _,..i_ L...-- =s . . I. WALL THICKNESS

T Wei d len$ile test for field weld procedure qualification test.

Fig. C.l. Tensile test specimens

76

t/10 MAX. SPECIMEN MAY BE MACHINE OR OXYGEN C7UT.

\\lRAO. ALL CORNE

IL___ _..L/~·~-----~ DIWROX.25mm

r•--------200mm !minimum l

I ~~WEW l_

i:. ===========J""ff:ii~~c===========~l :=- WALL THICHNESS

' WELD REINFORCEMENT IS TO BE REMOVED" FROM BOTH FACES FLUSH WITH THE SURFACE OF THE SPECI­MEN. SPECIMEN SHALL NOT BE FLATTENED PRIOR TO TESTING. CUT SURFACES SHALL BE SMOOTH AND PARALLEL

FACEBEND/ROOT BEND SPECIMEN

WELD REINFORCEMENT SHALL BE REMOVED FROM BOTH FACES FLUSH WITH THE SURFACE OF THE SPECfMEN

1------- 200mm !minimum l

J I

WALL ~ THICKNESS ,---

\ t /10 RADIUS MAX. _j_ \ CORNERS

12.5mm c=::J/ T I _j1WIDTH

1-- t SPEC! ME

/WALL THICI<NES~ SPECIMENS MAY BE MACHINE CUT TO 12,6 MM WIDTH OR THEY MAY BE OXYGEN CUT TO APPROXIMATi L Y 20 MM WIDE AND THEN MACHINED OR GROUND SMOOTH TO 12.5 MM WIDTH. CUT SURFACES SHALl BE SMOOTH AND PARALLEL.

SIDE BEND SPECIMEN

Fig. C.l. Bend test spedmens

77

3mm

20mm

NOTCH CUT BY HACK SAW. SPECIMEN MAY BE MACHINE OR OXYGEN CUT. FACE 5 SHALL BE REASONABLE PARALLEL

I 3mm ~-o._,.__ __________ APPROX.225mm ---------.,j

l.. DO NOT REMOVE REINFORCEMENT OF WELD OF EITHER S.IDE OF SPECrME:N.~·'------------.,._.__

~ -~-:.u::.. I 0

WALL THICKNESS

T T

Fig. C.3 Nick break test specimen

NOTCH POSITIONS.

CENTER OF WELD

FUSION LINE II.IJ

2mm FROM 1.1.

Smm FROM 1.1.

location of Charpy V-notch samples of welded joints. (Each sample consists of three spedmens.)

Fig. C.4. Cbarpy V -notch impact testing.

78

O.Smm

I DETAIL A MAGNIFIED I

HARDNESS TESTING MULTIPLE PASS WELD REPAIR

Fig. C.S. Hardness testing welded joints - schematic.

HARDNESS TESTING SINGLE BEAD REPAIR INSIDE OR OUTSIDE

79

(Z//2i'i///JZ/6Jscfd 5a;m/21 I C b] I Tensile test spec.imens. .

. c ~ '} I 1

L Q I Bend test specimens.

!. ~ } IMPACT TESTING: I Center of weld metal specimens.

I ; A : } Fusion line I 1 @ specimens.

I ~} 2 mm from fusion line I ~ specimens,

I ~:::u. 'r I · ~ Smm from fusion line

f ;f{j : : specimens. .

5 } Bend test :specimens. I

Fig. C.6. Welding procedure qulaification - fabrication of pipes/ piping components: sampling of test specimens.

80

TOP OF PIPE

. .r-'----- Hardness /macrosection

Face or side bend ----+:A:--"9''"'--..i'tt-..~----Tensile Root or side bend Nick break

Nick break -----.... ~;::>.

Tensile

}if Ec - Smm from f.l. -"'

..._--'-_"<!.,S.>",._ ___ Root or 5ide bend "'-----Face or 5ide bene!

'------- Hardness I macrosect ion

r---------- Hardness/ macr osectio;

Root or 5ide bend Nick break --------+:Ar.it» Tensile ---------.,,c::;:y Face or 5ide bend--___,.,..AI

Outer diameter

f'l...-o------Tensile ~::....------Root or side bend

11.•--- Nick break

00 > 300mm ...--Weld metal --~---·---#'.!i--Fusion line [f.l)

I - 2mm from f. I.

- Smm from f. I.

} u: c!

.a. I E' -·

L Root or sicfe bend ___ _.,.".I<!!>.

Nick break --------I~"'VI'l'h Tensile ---------~tt"'~?!--~~....--Sidebend _________ __,.

~7 ... t----Nick break v ... t-----Teosile

v..------ Root or side bend

Note: The indicated locations of the test specimens are to be used for welding positions 2G. 5G and 6G. For qualification of welding in I G position. sampling positions are optional.

Fig. C.7 Welding procedure qualification test-field joints. Sampling of test specimens

Root bend

Root bend or side bend

Root bend or 5ide bend Nick break

Nick break

8 I

TOP OF PIPE

break

bend or side bend

TOP OF PIPE

Root bend or side bend

side bend

bend

becottttllrn"''~' option. the locations may be rotated 45 degrees counterclockwise or they may around the pipe except specimens shall not include the longitudinal weld. Also,

LCC'IllllaiiY·s option, additional specimens may be takell.

Fig. C.S Welder and welding operator performance test­fieJ~ joints, Sam!'ii11g of test specimens

82

APPENDIX D GUIDELINES ON CORROSION CONTROL

D. I Design of cathodic protection systems

D.J.J General

0.1.1.1 The purpose ofO.l is to provide some general guide­lines to the design of cathodic protection systems for sub­marine pipeline systems.

Veritas will be open to evaluate cathodic protection systems based on alternative design methods.

0.1.1.2 Cathodic protection for submarine pipelines and ri· sers is generally by sacrificial anodes.

The cathodic protection system is generally applied in com· binatlon with a suitable coating system. The coating will re­duce the initial current requirement and improve the current distribution.

D .1.2 Design basis

For coated pipeline systems. however. the current demand may increase with time as the coating deteriorates.

Table 0.1 presents a general guide for selection of design cur­rent densities. Three minimum design current densities are listed for some major offshore areas and special environ­ments.

The initial current density is used to determine the necessary current output capaciry of new anodes. The final current density is used to determine the necessary current output ca· pacity of anodes when the anodes are consumed to the utili· zation factor. The mean current density is used to determine the weight of the anodes. ·

Tallie" D.l Guidance on minimum design current densities 0.1.2.1 Design life: Normally the design life of the cathodic (mA/m'lforcathodicprotectionofbaresteel protection system should be taken as the design life of the pi· peline system.

0.1.2.2 Environmental conditions: The following parameters should be taken into account in the design of the cathodic protection system:

Temperature of pipeline system Temperature of seawater/ sea bed Oxygen content of seawater/ sea bed Chemical composition of seawater I sea bed Resistivity of seawater/ sea bed Current velocity of seawater Biological activity

If relevant parameters from the same area on these are not available. measurements along the route may be required.

The current output of anodes is dependent on the resistivity. For seawater the resistivity in tropical waters (t == 25°C) may be taken as 20 ohmcm while in colder waters (t==S-I0°C) it may be taken as 33 oluncrii.

The resistivity of the 1m upper layer of the sea bed may be ta­ken as I 00 ohmcm if no measurements have been carried ou•

0.1.2.3 Potential criteria: The potential criteria for cathodic protection are given in 6.3.1.3 of the Rules.

D.J.3 Current demands

0.1.3.1 The total current demand is given by the current density and the area of exposed steel surfaces. The following areas should be considered:

areas in seawater areas below mudline

Initial Mean Final value value value

North Sea (northern) 160 120 100 North Sea <southern) 130 100 90 Arabiati Gulf 120 90 80 India 120 90 so· Australia 120 90 80 Brazil 120 90 80 Gulf of Mexico 100 80 70 West Africa 120 90 80 Indonesia 100 80 70 Pipelines (burial specified)-~-· -' "' 50 40 30 Risers in ·shafts with flowing seawater 180 140 120 Risers in shafts with stagnant seawater 120 90 80 Sea bed (ambient temperature>· · 25 20 IS

For buried pipelines. higher values are used than for bare steel in seabed. This is due to that a higher safety margin is necessary and the fact that complete burial may not be ob­tained.

0.1.3.2 The current density for a coated steel surface is high· ly dependent on the quality of the coating materials and the

unprotected foreign structures in the pipeline system

electrical contact with coatin~ application.

The current density is determined by the environmental conditions. The selection of design current densities may be based on experiences from similar pipeline systems in the sa­me environment or measurements.

The current density is normally not constant with time. For bare steel surfaces in seawater the current density may dec­rease due to the formation of calcareous deposit caused by the cathodic curren~

Table 0.2 gives guidelines on the selection of coating break· down criteria for coated structl!res. The coating breakdown criterion is defined as the ratio:

Current density coated steel • 1 00 % Current density bare steel

The presented values are based on satisfactory coating appli· cation. If the coating is particularly exposed to wear and me· chanica! damage. higher values must be used.

83

the current density requirement for coated steel. D. 1.4 Anode materials Table 0.1 should be multiplied by the percenta· 0.1.4.1 Zinc anodes should conform to the following compo-0.2. sition in order to reduce the susceptibility to intergranular

criteria (X) for

pipeline systems in contact with the reinforce­structures. allowance should be made for to the reinforcement. An average current mAl m2 for the outer reinforcement layer is

Initial values may be somewhat higher !ijgnificantly lower. The area of the outer

may ·be taken as the area of the concrete sur-

. ~ 2SOC to Joo•c an increase in the order of I mAl m2 per OC as compared Table D. I may be used. The tempera­

be:co:nsio1e~lld is the temperature differem;e between byc;lfow!txlnl!lld seawater/ sea bed.

seawater seawater <s-3o•c>

saline mud (S-30°Cl saline mud (30-90°Cl

seawater saline mud (O-60"Cl

corrosion.

max% min%

Aluminium 0.2 0.1 Cadmium 0.06 0.03 Iron 0.002 Copper 0.005 Silicon 0.125 Lead 0.006 Zinc remainder

0.1.4.2 The following electrochemical properties of alloys other than given in D.l.4.1 should be documented by ap-propriate tests: .

- Driving potential (mV) to polarized steeL i.e. the differ­ence between closed circuit anQde potential and the po­tentials siven by Tl!l!le ~.I.

- Current capacity (IIIJIWC • hours/ kg). - Susceptibility to passivity. - Susceptibility to intergranul;u- corrosion.

The testing of the a.l:!ove-~tioned properties may be ~ out by long tetm f~111nning (i.e. without external power source> laboratory testing. or field testing of full scale anQdes.

Table 0.3 gives some g\lidelines on typical values for es­sential parameters for 5ome technical anodes alloys.

Consumption rate kg/ A year

3.1-3.2 - 3.5 3.85- 6.7 6.7 -22

11.2 -11.5 11.2 -ll.S

84

D.1.5 Current output capacity of anodes

0.1.5.1 The current output capacity(),) is given by Ohm's law.

!'J.V R {O.J)

!'J. V Driving potential R Circuit resistance {usually taken as the anodic resist·

ancel

The anodic resistance is determined by the resistivity of the surrounding environment and the geometric conditions of the anodes. Empirical formulae as shown in Fig. D. I may be used.

If the anodes are grouped closely in array. interference be­tween the anodes must be taken into account when calculat­ing the anodic resistance.

0.1.5.2 For bare steel surfaces the anode current output ca­pacity should be calculated in the initial stage when the cur­rent demand is greatest and at the end ofthe lifetime when the anode is consumed to the utiliziltion factor and the anode has the lowest current oUtput..

0.1.5 .3 Installation of additional anodes with smaller dimen­sions for the initial stage {for instance 3 years) to meet the high initial current requirements may be more economical than to find a single anode shape which meets both initial and final current demand.

For coated structures where an increase in the current density may be observed the current output capacity should be checked at the end of the lifetime when the anode is consum­ed to the utilization factor.

The total current output capacity should be greater than the total current demand.

D.1.6 Calculation of anode life

0.1.6.1 The anode life L may be determined as follows:

W·U L= -­

E·I

effective life of the anodes net mass of the anodes

{0.5)

L w. u utilization factor determined by the amount of anode

material consumed when the remaining anode mate­rial cannot deliver the current required

E I

consumption rate of the anode mean current requirement per anode during the life­time

The following values for utilization factor may be usedo

Slender anodes: 0.90-0.95 Bracelet anodeso 0.75-0.80 Other shapeso 0.75-0.85

D.l.7 Cur;ent distribution

0.1.7.1 The anodes should be evenly distributed over the steel surface to achieve a uniform current distribution.

For systems with complex geometry model testing may be necessary.

It is recommended that the distance between anodes on a coated pipeline does not exceed 150 m. Close to platforms and pipe crossings additional anodes should be installed.

D.1.8 Fabrication of anodes

0.1.8.1 The electrochemical properties are highly dependent on the content or alloying elements and impurity elements. The anode manufacturer should thus prove his capability of delivering anodes which satisfy the specification.

0.1.8.2 The quality control at the anode manufacturing plant should include control systems on the following:

Raw materials. i.e. chet:king of documentation. Production equipment and process. Testing during and after production. Identification of products. Chemical analysis of produCts. Weight and dimensional tolerances. Visual check of any surface defects. Documentation (test certificates>.

D.2 Standards for coating

0.2.1 General

0.2.1.1 Standards or recommendations for coatipg mat~rials. application and testing are listed below. Most test methods will be found under the frrst group referring to the most com­mon generic types of pipeline coatings·. :Yhe second group contains more general guidelines for coating application and inspection.

D.2.2 Acceptable standards for coating properties and test methods referring to generic type

0.2.2.1 Coal tar based coatings:

British Standard BS 4164. Specification for Coal Tar Based Hot Applied Coating Materials for Protection of! ron & Steel.

t . . . .. . ....... . Americah Water Works Association. AWW A C 203. Stand· ard for Coal Tar Protective Coatings and Linings for Steel Water Pipelines- Enamel and Tape- Hot- Applied.

National Association of Corrosion Engineers NACE 2G 156. Coal Tar Coatings for Underground Use.

0.2.2.2 Asphalt based coating:

British Standard BS 4147. Specification for Hot Applied Bitu­men Based Coating for Ferrous Products.

Netherlands Corrosion Committee II. Communication 13. published by T.N.O.

NACE Publication 2H 157. Asphalt Protective Coatings for Underground Pipelines - Wrapped Systems.

The Asphalt Institute. Asphalt Protective Coatings for Pipeli­nes - Construction Series No. 96 - Wrapped and Mastic Systems.

NACE Standard RP-02-76. Extruded Asphalt Mastic Type Protective Coatings for Underground Pipelines.

0.2.2.3 Reinforcing materials for coal tar and asphalt based coatings:

Netherlands Corrosion Committee II. Communication 13.

NACE Publication 2J 262. Specifications for Fil)rous Glass. Reinforced Type Underground Pipe Wrap.

NACE Publication 21 162. Specifications for Bitumous Satu· rated Glass Pipe Wrap.

85

Standard for Coal Tar Protective Coatings Water Pipelines - Enamel and Tape -

All surface preparation of pipes for pipelines or risers is nor· many to be in accordance with:

Swedish Standard SIS 055900. Pictorial Surface Preparation Pul>li•::atiion 21 362. Specifications for Asbestos Pipeli- Standards Grade Sa 2 I /2. or better (Sa 3).

Code of Practice CP 3003: Part I. Rubber.

good bonding the rubber coating should be applied ~ of a c;ontinuous rubber stripe under controlled

rotating pipe.

and inspection of coatings, general

are listed $Ptpe recognized general standards for coat­including pipe metal surface preparation. in·

The following standards for surface preparation are consider­ed to be equivalent:

British Standard BS 4232. Surface Finish of Blast-cleaned Steel for Painting. Second Quality. or better< First Quality).

U.S. Steel Structures Painting Council SSPC. Grade SSPC-SP I 0. Near-White Blast Cleaning. or better (Grade SSPC·SP 5),

NACE No. 2. Near-White Blast Cleaned Surface Finish. or better {NACE No. J).

For field joint coating of weld areas on lay barge or similar. for coal tar or asphalt based coatings. surface preparation by wire brushing. to remove all weld spatter rust dirt and dust until a clean uniform grey-white metallic finish is obtained.

0.2.3.3 Application and inspection of coating:

NACE Standard RP-Q6-7S. Recommended Practice. Control of Corrosion on Offshore Steel Pipelines.

and testing of final coatings. For application of pipe- U.S. Steel Structure Painting Council SSPC. Steel StrUctures coatings. the standard listed under 0.2.2 are of primary ·Painting Manual.

ip.terest. The below requirement to surface preparation of mi- · . nimum SIS grade Sa 2.5 or equivalent should always be gov­erning for yard coating of pipes.

SLENDER ANODES

British Standard BS 54 9 3. Code of practice for protective coating of iron and steel structures against corrosion.

References is also made to the standards given in 0.2.2.

2 .:. 1 (1n_±f-1)

resistivity {ohm cml le)"lgth of anode {em) equivalent radius of anode {cml

f; a cross section ofanode{cm2)

Stand off core greater than 30 em

R,

s s

R,

A

_e_ 2·S

mean length of anode side {cml b + c - 2- b;;>2c

0.315 .•

V"A exposed surface area of anode

{0.2)

{0.3)

{0.4)

Fig. D.l Anodic resistance formulae (R,.)

86

APPENDIX E PRESSURE TESTING OF PIPELINES AND PIPELINE SECTIONS

E.l General

E.J .I This appendix covers Veritas' guidelines with respect to pressure testing of pipelines and pipeline sections.

The purpose of the pressure testing is to verify that the tested sections are leakproof and have the required structural strength to withstand the design pressure with the anticipated level of safety.

It is assumed that the separate pipes have been individually pressure tested in the pipe mill.

E. I .2 The Owner is to establish specifications for hydrostatic testing describiilg procedures and equipmf;nt.

The procedure speciiication is to cover at least the following,

Pressure test specification designation and revision num­ber Description of the sections to be tested (defining lengths. elevations. in-line valves and connectors. branches. con­nection for test equipment. e.g. isometric drawings. flow­sheets and alignment sheetsl Test medium (including additives) Mixing oftest medium and additives Test pressures Test holding time Description of all testing equipment Description of all testing instruments Method for cleaning and removing of air from the test section Sequence of pressurizing Monitoring and recording of test pressure Depressurizing and discharge of test medium

E.l.3 Instruments and equipment for measuring pressure. vo­lume and/ or temperature is to have an appropriate measur~ ing range with sufficient accuracy verified by a recognized test laboratory. The verification should normally not be older than one year.

Pressure measuring equipment is to have an accuracy and re­peatability of ± 0 .I 96 .

If temperatures are measured during the pressure test. the ac­CUW'CY of temperature testing equipment is to be 0.1 °C.

The volume measurement equipment. if used. is to have a sensitivity of 0.1 96 of the added volume of liquid necessary to produce a hoop stress equal to SMYS.

E.l.4 Below are described two alternative methods of.pres­sure testing.

E.2 Pressure test method no. I

E.2.1 The testing sequence will be as follows'

Caliper pigging (normally included) Filling of test liquid Stabilization (long sectionsl Pressurizing to test pressure Stabilization Holding Pressure release Reporting

E.2.2 Filling of test liquid should be carried out in due time prior to the actual pressure testing (several days). During flll­ing. steps should be taken to ensure that the volume of air re­maining in the test section is minimized.

E.2.3 The minimum test pressure is to be at least 1.25 times the design pressure. The hoop stress during pressure testing is normally not to exceed 90% of SMYS. Higher stresses will be considered in each case. During pressurizing. added test li­quid versus pressure should be recorded in order to evaluate the amount of residual air in the test section.

E.2.4 After pressurizing sufficient time for stabilization must be allowed having in mind that a temperature change during the pressure test wil1 greatly influence on the pressure. Signi­ficant temperature differences between added test liquid and surrounding .environment might lead to a long stabilization time (several daysl.

E.2.5 The holding period should normally be 24 hours. If. however. a I 00 96 visual inspection of the tested section is carried out. the holding period could be limited to the time necessary to carry out this inspeetion. but not less than 2 hours. For short sections as for instance risers 8 hours hold­ing penod inay be acceptable. During the holding period the pressure is to be recorded every ·I I 2 hours.

E.J Pressure test method no. 2

E.3 .I The testing sequence will be as follows'

Caliper pigging (normally included) Filling of test liquid Stabilization (long sectionsl Pressurizing to strength test pressure Stabilization Holding Reduction to leak test pressure Stabilization Holding Pressure- release Reporting

E.3.2 With respect to fllling of test liquid and stabilization. re­ference is made to E.2.2 and E.2.4.

E.3 .3 The minimum strength test pressure is I .4 times the design pressllre. The maximum equivalent stress during pres­sure testing is normally not to exceed the von Mises equiva­lent stress during pressure testing in the pipe mill or 0.96 times SMYS. whatever is the largest. Higher stresses will be considered in each case. The holding period for this strength test should not be shorter than I hour and not longer than 3 hours. The pressure is to be recorded every I 0 minutes.

E.3 .4 The leakproof test pressure is to be I .I times the design pressure. For a leakproof test the holding period should nor· mally be 24 hours. For test sections where I 00% visual in· spection is carried out. the holding period could be limited to the time necessary to carry out this inspection. but not less than 2 hours. During this holding period. the pressure is to be recorded every I /2 hours. For shorter sections. for instance risers. 8 hours holding period may be acceptable.

E.4 AcceptaDH criteria

E.4.1 The test will be accepted if during the test all pressure containing components in the tested section maintain their in­tegrity and no leaks are found. Since it is difficult to judge if certain small pressure changes could be caused by for inst­ance temperature changes. a pressure change of ± 0.2% of the test pressure could be accepted. If greater pressure· drops occur the test will not be accepted or the holding period should be extended until a 24 hour period with acceptable pressure change has occurred.

87

E.4.2 If the temperature is taken into account when interpret- cations along the section to be tested (e.g. one in each end of a ing the test results. then the Owner has. prior to the test. to long section). · present calculations clearly showing the effect on the pressure from variations in the following variables' E.6 Hydrostatic test report

- Temperature of test liquid when filling .• Tem~rature of environment

Restramts

During the actual test. the temperature of the environment has to be recorded at several relevant positions along the line. The readings to be made every hour.

E.5 Witnessing

E.S.I The pressure testing shall be witnessed by Veritas. If found necessary. Veritas may have surveyors at relevant lo-

E.6.1 The Owner is to provide a test report for each section tested.

The report is at least to comprise

test report as per attached form pressure time diagrams actual pressure volume diagrams plotted versus theoreti­cal pressure volume diagram if relevant. all temperatures versus time is to be plotted and included certificate of pressure measuring equipment

88

HYDROSTATIC TEST REPORT REPORT NO ........ .

Owner.: .............................................................................................. .

Pipeline Description: .................................................................................... .

Testing Contractor: ..................................................................................... .

Construction Contractor:

Testing Specification: ................................................................................... .

Section Tested From: ................................. To: ............................................... .

Pump Location: ................................ · · · · · · · · · · · · · · · ... · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · Pressure Recorder Location (Elevation): ...................................................... .

Length of Section: ................... · ................ Volume of Section: .................................. .

Pipe Tested (Size, W.T .. Grade, Type and Manufacturer): ............. , ........................................ .

Type and Source of Test Medium: ......................................................................... .

Additive: ............................................................. Quantity:

Dye: ................................................................ Quantity:

Inhibitor: ............................................................ Quantity:

Dead Weight Tester No.: ............................................................................... ..

Strength Test Pressure: ..................... bar Start of Test: ...... bar End of Test: ....... bar

Leakproof Test Pressure: ... · ................. bar Start ofT est: ...... bar End of Test: ....... bar

Time and Date St~ength Test Started: ...................................... Ended: . , ........................ .

Time and Date Leakproof Test Started: .................................... Ended: .......................... .

Remarks: ............................................................................................. .

Company Representative: ............................................... Date:

Colttractor Representative: .............................................. Date:

VERITAS Representative: ............................................... Date:

Attachments:

Pressure--time diagrams

Pressure-volume diagrams .................. .

Temperature-time diagrams ..... .

Instrumentation calibration sheet ............ .