Api rp 572 3rd ed. nov. 2009
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  • 1. Inspection Practices forPressure VesselsRECOMMENDED PRACTICE 572THIRD EDITION, NOVEMBER 2009
  • 2. Inspection Practices forPressure VesselsDownstream SegmentRECOMMENDED PRACTICE 572THIRD EDITION, NOVEMBER 2009 1
  • 3. Special NotesAPI publications necessarily address problems of a general nature. With respect to particular circtJmstances, local,state, and federal laws and regulations should be reviewed.NeIther API nor any of APIs employees, subcontractors, consultants, commIttees, or oltler assignees make anywarranty or representation, either express or implied, with respect to the accuracy, completeness, or usefulness of theinformation contained herein, or assume any liability or responsibility for any use, or the results of such use, of anyinformation or process disclosed in this publication. Neither API nor any of APIs employees, subcontractors,consultants, or other assignees represent that use of this publication would not infringe upon privately owned rights.Classified areas may vary depending on the location, conditions, equipment, and substances involved In any givensituation. Users of this recommended practice (RP) should consult with the appropriate authorities having jurisdiction.Users of thIs RP should not rely exclusively on the Infonnation contained In this document Sound business, scientific,engIneering, and safety Judgment should be used In employing the Infonnation contained herein.API is not undertaking to meet the duties of employers, manufacturers, or suppliers to warn and properly train andequip their employees, and others exposed, conceming health and safety risks and precautions, nor undertaking theirobligations to comply with authorities having jurisdiction.Information concerning safety and health risks and proper precautions with respect to part/cular materials andconditions should be obtained from the employer. the manufacturer or supplier of that material, or the material safetydatasheet.API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to assure theaccuracy and reliability of the data contained In them; however, the Institute makes no representation, warranty. orguarantee In connection with this publication and hereby expressly disclaims any liability or responsibility fur loss ordamage resulting from its use or for the violation of any authorities having jurisdiction with which this publication mayconflictAPI publications are published to facilitate the broad availability of proven. sound engineering and operatingpractices. These publications are not Intended to obviate the need for applying sound engineering judgmentregarding when and where these publications should be utilized. The formUlation and publication of API publicationsIs not intended In any way to inhibit anyone from using any other practices.Arty manufacturer marl!.ing equipment or materials in conformance with the marking requirements of an API standardis solely responsible for complying with all the applicable requirements of that standard. API does not represent,warrant, or guarantee that such products do In fact conform to the applicable API standard.All rights reselVed. No part of this woric may be reproduced. translated, stored in a retrieval system, or transmitted by any means, eleclronlc. mechanical, photocopying. recording. or othefwise. wi1hoot prior written permission from the publisher. Contact the Publisher, API Publishing Services, 1220 L street. NW, Washington. DC 20005. Copyright e 2009 AmeriClJn Petroleum Institute
  • 4. ForewordNothing contained in any API publication is to be construed as granting any right, by Implication or otherwise, for themanufacture, sale, or use of any method, apparatus, or product covered by letters patent Neither should anythingcontained in the publication be construed as insuring anyone against liability for infringement of letters patent.Shall: As used in a standard, ·shall" denotes a minimum requirement In order to confoon to the specification.Should: As used in a standard, "should" denotes a recommendation or that which is advised but not required in orderto conform to the specification.This document was produced under API standardization procedures that ensure appropriate notification andparticipation in the developmental process and is deSignated as an API standard. Questlons concerning theinterpretatlon of the content of this publication or comments and questions conceming the procedures under whichthis publication was developed shOUld be directed In writing to the Director of Standards, American PetroleumInstitute, 1220 L Street, NW, Washington, DC 20005. Requests for permission to reproduce or translate all or any partof the material published herein should also be addressed to the director.Generally, API standards are reviewed and revised. reaffirmed, or wtthdrawn at least every five years. A one-timeextension of up to two years may be added to this review cycle. Status of the publication can be ascertained from theAPI Standards Department, telephone (202) 682-8000. A catalog of API publications and materials is publishedannually by API, 1220 L street. NW. Washington, DC 20005.Suggested revisions are invited and should be submitted to the Standards Department. API. 1220 L Street, NW.Washington, DC 20005. standards@api.org. "
  • 5. Contents Page1 Scope .... . .... .. ... . ... . .... . ... . ......... . ....... . ............ . ....•....... . . . .... . ... 12 Nonnative References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Terms and Deftnitions ........ . . . . .. ........ . .. . ..... . ..... . .... .. ......... . ............... 23.1 Deftnitlons . . . . . . . . . . . . . . . . . . . . . • . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . • 23.2 Acronyms and Abbreviations . .. . . ........ . .. . ..... .. ..... " . ....... . . . .. . ........ . .. . ..... 64 Introduction to P...ssure Vessels . . ...... • .......•..... . . . ...... . . . ... . .................... . 54.1 General.. . . • . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . • 64.2 Methods of ConstrucUon .. . . . .................. . . .. . .... . ... . ............ . ... . . . ...... . .• . 64.3 Materials of Construction . . . . .... . ....... .. .... . .. .. . . .. . ... . ... . ..... . ............... • .. . . 84.4 Internal Components and equipment .. . . ......... . .... .. . • ..... . ...... . • . . ...... . . . ......... 74.5 Uses of Pressure Vessels • .. •.. . . ...•.. .. •. . . . .. . .. . . . . ... • . ... . .. • . .• .. . .. . . . ............. 84.6 Design and Construction Standards ... . ... . . ......... . ..... . . .. ..... . ......... . ..... . .... : . . 96 Re sons for Inspection .........•...... . .. . . . .... • . . ............... . . . ... .. ......... . . • ... 125.1 General .. . . ....... .. . .. ....... .. ....... .. .......... . ...... . .......•... . .......... . .... . 126.2 Safety.. . . ... .. .. .. . ..... . .. ......... . ....... . ........ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 166.3 Reliability and Efficient Operation . . .. . .. . ..... ... ........ . .. . . . .... . ... . . . .. . ............ . . 166.4 Regulatory Requirements . ... . ............. . .. . . . ... . ... . ....... . ... . . .. .. . .. . .... .. .. .. .. 166 Inspection Plans ... . ........ . .. .. .... . .. . ... . . • .. . .... . ..................... . . ... .. . .... 166.1 General .... . .... . ...... .. ... .. ... . . . ... .. ...... . .............. . .... . .... . .... . ..... . ... 168.2 Inspection for Speolftc Types of Damage . .. . . ......... . ... .. ........ .. ............ . ...... . .. 168.3 Developing Inspection pr.ns . .. . ............... . .. . ..... .. ..... .. .. . ......... .. . ......... . 186.4 RBI . ..... . ......... . ....... . . .. . ..... .. .. . . . .. . .. . ... . .. . . . ....... .. . ... .... .. ......... 177 Frequenoy and Extent of Inspection . .. • .................. . ........ .. ....... . ............ . .. 177.1 General ..... . .. ...... .... ... . . ... . .... . ........ . ....................... .. ...... . ... .. .. 177.2 Opportunities for Inspection . . .. . ... . ......... . .... . .. . ... .. ........ . .... . .... . .. . ........ 188 Safety Precautions and Preparatory Work .... . . . ......... . ..... . ..... . ....... .. ............. 188.1 Safety Pr808utions . • . . . . . ... ..... ..... . ...... . .................... . ... . .......... . ... . .. 188.2 Preparatory Work... .. . .....• . . . ........ . . . ........ . ..... . ... . .... . ......... . ....... . ... . 199 Inapectlon Methods and Limitations . ................. . .... . . . . .. . . . . ........ . ... . ....... . .. 219.1 General. . . ..... . . .. .... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219.2 Thickness Measurements....... • ... . .... . ........ . ... . .. . .... . ..... . . ..... . ... . . . ........ 229.3 Externallnspeotion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249.4 Internallnspec;tion . •. ..... . .. .. •. ....... . . ...... .• . .. . ..... . .. . . . . .. .. ................... 339.6 Special Methods of DeteotIng Mechanical Damage .. ..... . .......... . ............... .. .. . .. .. 469.6 Metallurgical Changes and In.sltu Analysis of Metals ...... ... .. ........................... . .. 468.7 Testing . . .. •. . .. ........ . ...... . ... . . . ..... . .. . .... . . . ...... .. .. . ......... . ........ . ... 4710 Condition Assessment and Repair . .. ... . .... . ............. . ...... . ...... . ... .. . ... ..... . .. 6010.1 General .. .. .• . . ................... . ... .. .. . ........ .. ...... . . . ............ . ... . .. . ... . 6010.2 VlsuallnspectJon . .. . . . . .. ............ . .... . ........... . ................ . ....... . ....... 6010.3 Thickness Measurements . . ..... . ...... . ........ . • . . .... . ........ .. . . ......... .. ... . ..... 6110.4 Remaining LW. . ... . ... .. .... . .... . ......... . . . .......... . ... .... .. ......• . . . . . .. .. .. . .. 6110.6 Methods of Repair ... ... .... . .. •.. ..... .. .. . ... . ... . ..... .. .... . . .. ..... . . . .... . ... . .... 6110.6 Repair of Supporttng Vessel Equipment. ... . ........................... . .. .. .. . ...... . .. .. . 63 v
  • 6. Page11 Records and Reports • .... .. .. . .... ... ..... ...... ...... .......... ... ........ .. ........... 6311.1 Records ... .....• ........................... . ......... . ....... . .......... .... . ...... .• . 5311.2 Reports ...... ..... . ...... ... .. .. ...... ... .... .. .................... . . . ................ 63Annex A (informative) Exchangers ..... .. .. . ....... .. .... . ......... ... ...... . ............. . . . . .. 64Annex B (infonnatlve) Towers .......................... . . .... .......... .. ....... .... ........... 71Annex C (informative) Sample Record Fonns ................................... . . . .. . .. . . .. .. ... 12.Figures1 TYpe 316 Stainless-clad Vessel .............................. . .......•.. . ................... 72 Weld Me1a1 Surfacing ...• • . . . .................•....... . ............. .. .. . .... . .. .. ........ 83 Strip-llned Vessel .. . ....•.. .... ..... ......... . ........ . ...... .. ..... .... ............. .. ... 8.. Prlnclpal Strip-llnlng Methods. . . . . . . • . . . . . . . . . . . . . . . . . • . . . . . . . • . . . . . . . . . . . . . . • . • . . . . . . . . . . . 96 Hex Mesh Installation for Refractory Lining .................... . •• . .. ..... . ........... . .. . .. . 96 Reinforced Refractory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 107 Vertical Heat Exchanger . . . . . . . • . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 118 HOrizontal Vessel. ............ . •.. . ... . ............ .... ... . .......... . ... .. ......... ..... 129 Spheres ..... .• . . . .......................... . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1310 Horton Spheroid (Noded) ... ...... . . . ........ . ...... . ....... ... ..... .. ...... . ............ . 1311 ProcH_ Tower ...... . ........ . ......•.. . .. . . ...... ... . ............. .... ........... . ..... 1412 Exchangers ....... .. . .. . . ...... . .. .. ... . .. .. . ...... .. ...... .... . . .......... .... ...... .. 1413 Exchanger Installation and Foundation ....... .. .... ..... .. .. . .. ........ . .............. . .... 2614 Severe Detllrloratton of Anchor Bolts .... . .. . . . . ..•.... . ....... .. ... . ......... ....... ... . ... Z716 Method of Obtaining Vessel Profile Measurements .... .. . ....... .......... ...... . ... . . ....... 3216 . COlTOslon In Channe .. . . ............... . .... • . • . . . ..... .. ......•............ . .•......... 3511 Crack In Weld Seen by PT ... " ................ . ... • .. . ................ . ................. 3718 Hydrogen Blistering ... . . . . .. ........... . ...... . ..................................... . ... 3819 Self-vented Hydrogen Blisters . . . . . . . . . . . . . . . . . . . . . . • . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 3920 Radiograph of S If-vented Hydrogen BUsters In Carbon Steel ...... . .... ........ ..... ..... . .... 3921 Cafalytic.....ctor Intemals--Cyclones . .. . . .. . ..... . . . .. ..... . .. . ... .. ... . .................. 4122 Corrosion Tab Method of Determining Metal Loss on Vessel LInings •. . ......... . .. .. . . ........ • 4323 Strtp-tlner Deterioration .... ... . . ...... . . .• . . ..... .. ..... .. ... .................. . ........ . 4424 Detertorated Refractory-tile Lining ... •. .. . .... . .. . •.. . • . .................... . .............. 4526 Steps In Using Special Equipment to Test Individual Tubes . ....... ... .... ... ......... ...... .. . 49A.1 Properly Rolled Tube . ....... . . . . ....... ... ... .. ... . ............. . . .............. . ....... . 56A.2 Tube-bundle Type of Tank Heater . ............. . .......... . ..... ..... .... . ................ . 57A.3 Air-cooled Exchangers . . .•. .. . . ...... .... ............ ... ....... . .. . ...... .. .. . .. . ....... . 68AA Clean-servlce Double-plpe Colis .. .............. .. ...... . . ... . . ... • ................... . ... . 69A.S Tank Suction Heater with Everything but Forward End Enclosed; Shell Suction Nozzle Enclosed In Far End . ... .. ... . .. . . . .. . .. ...... .. ... .. ... ... ... ........ ..... ... . ... ...... . 60A.6 Fln-ty~ Tubes In Double-plpe Coli . .......... . . . ... . .. .. ...... .. .. ........ ........ . ...... . . 60A.7 Plate-type Exchanger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61A.8 Tubes Thinned at Bafftes ..... . .. • . ..•.. .. ........ • ......... . ..•... .. ... . ... ... . . ... .. .... 61A.& Tubes Fretting at Bam . ..... ... ... •••.• ...................... • ..•.... .... . . .... . ... ... . . 82A.10 Eroslon-corroslon Attack at Tube Ends • ..............•. . ....... •• ... .. . .. ............. . .... 83A.11 Heat Exchanger Parts ... •. .. . ....... • .•................. . ............... • ................ 66A.12 Heat Exohanger Types .. ..... ... ........ .. .. .. ... . .. . . . .......................... . .....•. 708 .1 Typical Trays In a T0N8r . . .. .. . ....... .. • ...... . ....... • ......... .. ............ . .......... 71B.2 Random Packing In a Tower. .. . ................ .. ...... • ... ..... ... . . ..................... 71B.3 Tnays with Downcomers . . .. ........................ . .. . .... ....... ... .... .... .. . .. . . . . . .. 72B.. Bubble Cap Flow Path . . . . . . ........ .. . .. ..... . ....... . ...... .. . .. ........................ 72B.5 Tow.r Stripping and RecttftcatJon Section ............. . ....... .... ..... ..... ... . ............ 73
  • 7. p.ageB.6 DlskJDonut Tray . •..... ....... .. .......... . ............•................ ....... . ..... .... 74B.7 Ba.... Tray Arran{lement . . . .. .. ... ......... .• •. .. ..... .. .. ....... ......... . , ... . ......•. .. 76B.8 Sieve Tray ..... .. ..... • . ... .•. ................ ..... ... ... .... ..... . ... . ................. nB.9 SI ve Tray Dlstortlon • . . . .....•...........•............................................... 78B.10 Typical Trayed Tower. ... ..... ..... .. ............... .... . .. ....... .. ....... . .. ......... .. . 79B.11 Float Valves with Two Weights ...... ...... .. .. . .... . ....................................... 80B.12 Fixed V.tves •.. •• . .. ... •••• • • ... . ...................... . ....••.......................... 80B.13 Bubble Cap Vatves .................................................. . ........... " ...... 81B.14 Extruded Vatves ....• . •. .... .. ..... . .. ...• .. .... .... . .• .. .. .. . ... . ... .......... .... ... ... 81B.16 New Floating Valve Tray .... ..... ..... ..... ... ... • .. ... .......... .. .. . .... ... ..... . • ... • .. 82B.18 Caged Valves ..• . . ... ..•...... . .. ... ...... .. ..... .. ..... .. . ........... . .. .. ... . . . . .. .. . . 82B.17 Typloal Packed Tower Drawing . . . . ... ... ... .... ....... .. . .. ... ... . ...... . .. .... ........ •• . 83B.18 Random Packing, Pall Rings ....•. •. .... .. . •... ..... . .... . .. ... .. ... .. ...... . .. ........... 84B.19 Structured Packing . •. . ... . • . . .• " . • ....•................. . .............................. 84B.20 Grid-style Packing. . . . . • . . . • . . . . . . . • . . . . . . • . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . • . • . . . . . . • . . • . . 85B.21 Diagram of Required Scaffolding ............... . .......................................... 87B.22 Hexagonal Manways .. . . . .. ......... ... . . ...• . .. . .... . ... ... .. ...... . . .... . ......• ..... •. 88B.23 Standing all and Water .. . .. ....... .. .. ... . . .......................................•.. ..•. 88B.24 Trays Collapsed. . . . . . . . . . . . . . • . . . . . . . . . . . . . . . . . . . . . . . • . . . . . . . . . . . . . . . . . . . . . • . . . . . . . . . . . . 89B.25 Corroded Anchor Bolting . ................•...........................•............ .. . •.• . 89B.26 Corroded Anchor Bolting ... . .. .. .. ... . . .................. . ... . ... . .... . ... ... .. ... .. .. .. . 90B.27 Cracked and Bulged Fireproofing ....... .... . .. .. . ................. . . . ....... ..... .. ...... . 90B.28 Debris In Skirt .. .•.•• . .• .. . •. . .. • .......................... . ... . . .. . ... . . .. ... .. . ...... . 91B.29 Preliminary InspecUon . .. ... ........ • . ... . . ..... ...........•... . . ... .. ....... . ....... . . .. 91B.30 Bed Dlmage t Preliminary Inspection .. ...•. . . . .. ... . .... • ... . ....... •. . ......... . .. ...... 92B.31 Manway Corrosion .• . . .. . .. •....... . . . . . . . . . . . . . . . . . . • . . . . . . . . . . . . . . . . . . . • . . . . . . • . . . . . • . 92B.32 Manway Uner Damag . ... .. . .. .• . ... .............................. " •........... ..... ..• 92B.33 Corrosion on Gask t SeaUng Surface • .. . ... . • .......................... . .................. 93B.34 Corrosion on Gasket Seatfng Surface ...... . ............................................... 93B.36 Surface Corrosion of Shell ....... . ..... .. .. • . .......•..... .. ............ . . . ........ .. .... 94B.38 Inspection From the Bottom Head ...•..................................................... 96B.37 InspecUon of Packing via Riser ........................ .•. . .. . . ....... ... . . . • . . . . .. ..... • .. 96B.38 Dernister Bypass Deposits .. .. .. ... ......•.. . ................................ • . . ... . . ..... 95B.39 Fouled Demtster Pads ... •..• . ..... . ...................................................... 96B.4O Faulty Deml$ter InstallaUon .... • ....... . . ............. .• . •. ........ ... .. . . .......... . • .... 988 .•1 Preferential Corrosion of the Head to Shell Weld ......... .. . .. .. .. ... .. ..... .......... . .... .. 97B.42 Head Seam prer.rential Corrosion . ... .. .••. .. .. .. ••• ................ . ...............•..... 97B.43 Preferential Corrosion of the Sh II .. .......... • ... • ...... ... ...... ............ . ... .. ... . . .. 98B.44 Perforation Degradation . ..... • .. .. . ..... .•. ............ • .. ... ....... . ............. . ...... 98B.46 Chimney Tray Deformation at Draw Sump ... . ... . . ....... .. • ... .. ...... ....... .. . ........ .. . 98B.46 Fouled Troughs on Box and Trough Distributor ................. . ........ . . . • ...... . ...•... . . 99B.47 Obstructed Pipe Dlstrtbutor Perforations . ....... . .................................•.. .. ..... 998.48 Box and Troughs . ... • .. . . . . . ..... .......... ... .. .. ... . .................................. 99B.49 Hit the Washers, Not the Bolts . .•..........•...... . ... .. . " ............................... 100B.5O Random Packing on Valve Tray . . .. ............ . . ...... .. ....... . ........ .. .. .. ..... . . .... 100B.S1 Bed Limiter Above Random Packing . .... . .• •...... ... ..... .. ........ . .. . .....•..• . •. .. . .. 101B.152 Dislodged Packing ... . . ... .. . .... ... ..... .... ......• .... ....... . .. .. . .............•.... 101B.63 Damaged Packing Support Grid .......................................................... 102B.64 Support Grid from Below . .. . . ...• • .. .. ....• . . ..... .................. .. . . . ............... 102B.65 Corrosion Inside Sightglass Nozzle .. • ................ . ..... ...... ....... ..... . . .. . . ...... 103B.56 Bottom Head, Vortex Breaker, and Debris .................. .. ... . ................ .... ...... 103B.67 Fouled Grid-type Packing .. . . ............................................................ 104 vii
  • 8. PageB.68 Cracked Plug Weld .. ... . • . .. .. .. .. .... . • . . .. .. . " . . . .. • . .. . .. . . .. . • .. .. .. ... . .. .• . .... . 104B.69 Stainless Steel Donut CladdIng Breech . . . . ..• ..... • . .. . ... .•.. .. .. .. . ... .. . . .• . .. .... .. .. . 106B.60 Cladding Bl88Ch at Gouges In 8ottom Head .• .. . .. . . .. . .. . .. ..... .... .. . . .. . ... ..• .. . . .. . . 105B.61 410 Stainless Steel Clad to Carbon Steel Interface W.,d . ... .. ... . .. . . . .... . . .. . .. ... . .. ... ... 106B.62 Suppl mental UT Martdngs ... . .. •.. . • . . . . . . .. . .. . .... . . .....•... . .. .. .. . ... . . . .. .. . . . . . . 106B.63 Cracking at Tray Support Ring Weld .. . .... . ... . . . . .... . . .. .... . . .. . . . .. ... .. . . ... ..• . .. . . . 107B.64 WFMPT Dlscovered Cracking .. .. . .. . ...• ..... . . . . .. .. .... .. . ...... . . ... .. .. . • .•.... • ... • 108B.65 Supplemental NOE May be Needed . ... ... .. ... . .. ... .. ... .. ... . ... .. .... .. . .. ..... . ... . . . . 1088.66 Areas of Chemical Activity . . •.. . • .. . . . . .. ....... .. . .. ..•. . ..... . .. . . ..•....... . .......... 109B.87 Areas of Activity .. ... . ... . .............. . ..... . . . . .. ... . .. • .. . . .. .. .. . . . . . . .. . .. . .. .. .. 109B.68 Hardware COfToslon ........ .• ... . .... ...... .. . ... . . . .... • . . . . .. .•. . .. .. . . .. .. . . . . .. .... 1108 .69 Stuok Valves Always Open .. . .. • . ... .... . .. .. ... . . .. . .. • . . ....... .. .... .. . . . . . .. .... . ... 110B.70 Clean Square-edged Perforation .. .... ..... ... ..... ... .......... . ... ..... .. . , ....... . . .... 1118.71 Valye Fretting . . • . . ... . ..... . . . . . . . .... . . . ...... .. ... .. . . ..... .. . . • • .... . ........ .. .. . . . 111B.72 Slotting from Below. . . . . . . . .. .. .. .. . . . . .. . . .. .. . . . . . ... . ... . . . . .•• . .. . . . ... ...... . ... . .. 1118.73 Valye Leg and Perforation Inspection . . . . . ... ..... . . . . ... .. .......... . . .... .. . .. ... . ... . . .. 112 08.74 Indentation Valves • . •.. . .•. . . .. .. . . . ... . . . . .. .... . ........ . .... •• . . . . . . ... . . .... .•.... 1128 .76 New Caged Valves with Dimples . ... .. .. .. ... . ..... . .. . .. . . . .. . ...... ... . ..... . ... . " . .. . • 113B .76 New Caged Vatv Cage Tabs ... . ....... . .. . .. . . .. .... . .. . .... .... . . .. . . . .... . .. . ......... 113B.77 Small Fixed Valves ••.•• . . .. .. . .. .. . . . ... • •. . .. .. . . . •... ... .. ... . . . . .. . .. . ... . ... ..• .. . . 114B.78 Fixed Vatves Lateral Vapor Directional Flow . . .. . . . . .. " . . . ... . ........ . , .... ...... ..... .. .. 114B.79 Removabl. Fixed Valves Reduce Fouling ...... ... . . . . . . . ..... ... .... . .... ... .. . ... ..... . .. 116B.80 Removable Fixed Valves Tray Damage • . .. ...... . . .. . . . .... .. .. . .... . ... . . . . .. . ... .... . ... . 1158.81 Bubble Caps on Stepped Trays . .. . .. .. ... . .. ... .. ... . ......... • . • . ... . .. .. . • ...... . .... . . 116B.82 Fibrous Deposits and Fouling Under Bubble Caps .. .. .... . ....... .. ...... . ... .. .. . ...... . . .. 116B.83 Tray Deck Should be Scraped Clean ..... . . . . ... .. . . .. .... .. .. ... .. .. .. . ..... • .. . ... . .. . .. . 117B.84 Tray Fatigue Cracking ... . . . .. . .. . .. . . . . . ..... . .. .. ....•. . .... . .. . . ...... . . .. ...... .. . ••. 11 7B.86 Llght-to-moderate Well CorrosIon . .. ... .. .. .. . . . .. .. ... .. . .. . .. .. . .... . .. . ... . .. .... . .. . .. 118B.86 Loose and MissIng Hardware Fallur. . .. .... . ..... ... . . . ... .. .. .. ... .. .... .... .... . .. . . . . . . 1188.87 Oowncomer and Seal Pan Clamps Loose .. ..... .• .. .. ... . ... . . ... . .. . .. . . • . . . .• .... . ... • .• 119B.88 DowncOiner Clamp Loose . .. . . . . . . . ..• . .. . . . . ... . .. ... ... .... ..... ... .. ........ . . .. . . . . . 119B.89 Tray Support Ring Corroded to Failure. .. .. . . .. ... .. .. .... . . .. ...... ... . . ... . .. . ... . ... .. .. 120B.90 Depostts Adjacent to Shell are on Ring . . ...... .. .. .. . . . . ..... ...... ... ......... ... .. ...... 120B.91 Shell Corroded to Half Will Adjacent Top Three Rings . . ... ... .. .. .... ..... ... ..... . . . . •.. . .. 121B.92 Support Ring Grooving •.• • . .. ... .•• .. ... ...... .... . .. ..... ... ... . . . ......• . ... . . . . . • . . .• 121B.93 Cracking of Ring Attachment Weld . ........ . . ..... .. ..... .. .. .. . .... . . .. ... .. . . . .. .. .... .. 1218.94 Tray Support Ring Butt Weld Cracking .......... . . .. ..... . . . .. .. .... . .... . .. . ....... .. . .... 1228.96 Breechlng of the S al Wold . . •. • ... ... . . .. . .. . . ... . ... .. ... ... .... . ....... ... .... .. • .. . . .. 122B .96 Shadowfng Inside the Downcomer . • . . . ...... • ... .. ... . . .. . .. ... . . ..... . .. . . •. .. . .... • . .. . 1230 .97 Shadow the Downcomer Shell Every Tray . ...... . ..... . ...... ... ..... . . . ... .. .. .. .. . . . . ... . 123
  • 9. Inspection Practices for Pressure Vessels1 ScopeThis recommended practice (RP) covers the inspection of pressure vessels. It includes a description of the varioustypes of pressure vessels (including pressure vessels wittl a design pressure below 15 psi g) and the standards fortheir cons1ruction and maintenance. This RP also Includes reasons for Inspectlon. causes of deterioration, frequencyand methods of inspection, methods of repair, and preparation of records and reports. Safe operation is emphasizedwithin this RP.2 Nonnative ReferencesThe following referenced documents are indispensable for the application of this document For dated references,only the edition cited applies. For undated references, the latest edition of the referenced document (including anyamendments) applies.API 510, Pressure Vessel Inspection Code: In-service Inspection, Rating, Repair. and AlterationAPI Recommended Practice 571. Damage Mechanisms Affecting Fixed Equipment in the Refining industryAPI Reoommended Practice 574, Inspection Practices for PipIng System ComponentsAPI Recommended Practice ST5,Guidelines and Methods for Inspection of Exisling Atmospheric and Low-pressureStorage TanksAPI Recommended Practice 576, Inspection of Pressure-Relieving DevicesAPI Recommended Practice 577, Welding Inspection and MetallurgyAPI 579-1/ASME FF5-1 , Fitness-For-Service API Standard 660, Shell-and-Tube Heat ExchangersAPI Standard 661, Air-Cooled Heat Exchangers (or General Refinery ServiceAPI Recommended Practice 945, AvoIdIng Environmental CrackJng In Amine UnitsAPi Publication 2214, Spark Ignition Properties of Hand ToolsAPI Publication 221 7A, Guidelines for Safe Worle in Inert Confined Spaces In the Petroleum and PetrochemicalIndustriesASME Boiler and Pressure Vessel Code (BPVC) , Section VIII; Pressure VesselsASME PCC-2, Repair of Pressure Equipment and PipingNB-23 2, National Board Inspection CodeTEMA 3, Standards of Tubular Exchanger Manufacturers Associationt ASME International, 3 Pari< Avenue, New York, New York 10016, www.asme.org.2 National Board of Boiler and Pressure Vessel Inspectors, NBBI. 1055 Crupper Avenue, Columbus, Ohio 43229, www.nationalboard.org.3 Tubular Exchanger Manufacturers Association, 25 North Broadway, Tarrytown, New Vorl< 10591, www.tema.org.
  • 10. 2 API REcOMMENDED PRACTICE 5723 Tenns and Definitions3.1 DefinitionsFor the purposes of this document, the following definitions apply.3.1.1alterationA physical change in any component that has design implications that affect the pressure-contalnlng capability of apressure vessel beyond the scope descnbed in existing data reports. The following should not be consideredalterations: any comparable or duplicate replacement, the addition of any reinforced nozzle less than or equal to thesize of existing reinforced nozzles, and the addition of nozzles not requiring reinforcement3.1.2claddingA metal Integrally bonded onto another metal under high pressure and temperature whose properties are bettersuited to resist damage from the process than the substrate materfal.3.1.3condition monitoring locationeMuDesignated areas on pressure vessels where periodic inspections and thickness measurements are conducted.Previously, they were normally referred to as "thickness monitoring locations (TMLs)."3.1.4corrosion specialistA person, acceptable to the owner/user, who has knowledge and experience in corrosion damage mechanisms,metallurgy, materials selection, and corrosion monitoring techniques.3.1.5corrosion under InsulationCUICorrosion that occurs under insulation, including stress corrosion cracking under insulation.3.1.6damage (or deterioration/degradation) mec:hanlsmA process that Induces deleterious micro and/or macro material changes over time that is harmful to the materialcondition or mechanical properties. Damage mechanisms are usually incremental, cumulative, and unre<:overable.Common damage mechanisms Include corrosion, stress corrosion cracking, creep, erosion, fatigue, fracture, andthermal aging.3.1.7defectAn imperfection. whose type or size, exceeds the applicable acceptance criteria.3.1 .8design temperatureThe temperature used In the design of the pressure vessel per the applicable constructioo code.3.1.9examination pointAn area defined by a circle having a diameter not greater than 2 in. Thickness readings may be averaged within thisarea. A CMl may contain examination points.
  • 11. INSPECTlON PRACncES FOR PRESSURE VEssas 33.1.10extemallnspectlonA visual Inspection performed from the outside of a pressure vessel to find conditions that could Impact the vesselsability to maintain pressure integrity or conditions that compromise the Integrity of the supporting structures, e.g.ladders, platfonns, etc. This inspection may be done either while the vessel Is operating or while the vessel is out ofservice.3.1.11ImperfectionFlaws or other discontinuities noted during inspection that mayor may not exceed the applicable acceptance criteria.3.1.12In serviceDesignates vessels that have been placed in operation as opposed to new construction prior to being placed inservice. A vessel not In operation due to an outage Is stJlI considered an in...service vessel.3.1 .13Inspection planA strategy defining how and when a pressure vessel will be inspected, repaired, and/or maintained.3.1.14InspectorA shortened title for an authorized pressure vessel Inspector.3.1.15Integrity operating windowEstablished limits for process variables that can affect the integrity of the equipment If the process operation deviatesfrom the established limits for a predetermined amount of time.3.1.16JurisdIctionA legally constituted govemment administration that may adopt rules relating to pressure vessels.3.1.17liningA nonmetallic or metallic material installed on the Interior of a vessel whose properties are better suited to resistdamage from the process than the substrate material.3.1 .18maximum allowable woritlng pressureMAWPThe maximum gauge pressure permitted at the top of a pressure vessel in its operating position for a designatedtemperature. This pressure is based on calculations using the minimum (or average pitted) thickness for all critlcalvessel elements, (exclusive of thlcl<ness designated for corrosion) and adjusted for applicable static head pressureand nonpressure loads (e.g. wind, earthquake, etc.).3.1.19mInimum design metal temperatureMDMTThe lowest temperature at which a Significant load can be applied to a pressure vessel as defined in the applicableconstruction code [e.g. ASME BPVC Sadion VIII. Division 1, Paragraph UG-20(b)].
  • 12. 4 API RECOMMENDED PRACllCE 5723.1.20on-streamA condition whereby a pressure vessel has not been prepared for Internal inspection and may be in service.3.1.21owner-US8rAn owner or user of pressure vessels who exercises control over the operation, engineering, inspection, repair,alteration, testing, and rerating of those pressure vessels.3.1.22pressure design thicknessMinimum wall thickness needed to hold design pressure at the design temperature as determined using the ratingcode formula. It does not Include thicKness for structural loads, corrosion allowance or mill tolerances.3.1.23pressure vesselA container designed to withstand intemal or extemal pressure. This preS5.lre may be Imposed by an externalsource. by the application of heat from a direct or Indirect source, or by any combination thereof. This definitionIndudes heat exchangers, aJr-coolers, unfired steam generators and other vapor-generating vessels which use heatfrom the operation of a processing system or other Indirect heat source.3.1.24pressure vessel engineerOne or more persons or organizations acceptable to the owner-user that are knowledgeable and experienced In theenglneertng disciplines associated with evaluating mechanical and material characteristics that affect the Integrtty andreliability of pressure vessels. The pressure vessel engineer, by consulting with appropriate spedallsls, should beregarded as a compoSite of aU entities necessary to property address a technical requirement3.1.25repairThe work necessary to restore a vessel to a condition suitable for safe operation at the design conditions. If any of therestorative work results In a change to the design temperature, MDMT, or MAWP, the wor1c shall be considered analteration and the requirements for reratlng shall be satisfied. Any welding. cutting, or grinding operation on apressure-contalning component not specifically considered an alteration is considered a repair.3.1.26rerattngA change In either the design temperature rating, the MDMT. or the MAWP rating of a vessel. The design temperatureand MAWP of a vessel may be increased or decreased because of a reratlng. Derating below Original designOOf1<Iitions is a permissible way to provide for additional corrosion allowance.3.1.27risk-based InspectionRBIA risk assessment and management process that is focused on inspection planning for loss of con1alnment ofpressurized equipment in processing facilities, due to material deterioration. These risks are managed primarilythrough inspection In order to Influence the probability of failure.3.1.28.trip liningStrips of metal plates or sheets that are welded to the inside of a vessel wall. Normally, the strips are of a morecorrosion--resistant or erosion-resistant alloy than the vessel wall and provide additional corrosion/erosion reSistance.
  • 13. INSPECTION PRACTICES FOR PREssURE VEssas 53.1.29temper embrittlementThe reduction In toughness due to a metallurgical change that can occur in some low alloy steels, e.g. 2 1/4Cr-1Mo,as a result of long term exposure In the temperature range of about 650 of to 1100 OF (345 °C to 595°C).3,1.30testingWithin this document, testing generally refers to either pressure testing whether performed hydrostatically,pneumatically or a combination hydrostatlclpneumatc, or mechanical testing to determine such data as materialhardness, strength, and notch toughness. Testing, however, does not refer to NDE techniques such as PT, MT. etc.3.1.31weld overtayA lining applied by welding of a metal to the surface. The filler metal typically has better corrosion and/or erosionreslstance to the environment than the underlying metal.3.2 Acronyms and AbbreviationsFor the purposes of this document, the following acronyms and abbreviations apply. AUT automated ultrasonic technique CUF corrosion under fireproofing ET eddy current technique FRI fractJonation research incorporated FRP fiber reinforced plastic H2S hydrogen sulfide MT magnetJc particle technique NDE nondestructive examination PSCC polythlonic stress corrosion cracklng PSV pressure safety valve PT liquid penetrant technique UT ultrasonic technique WFMPT wet fluorescent magnetic particle technique4 Introduction to Pressure Vessels4.1 GeneralA pressure vessel is a container designed to withstand internal or external pressure. The pressure vessels may havebeen constructed in accordance with ASME BPVC Section VIII, other recognized pressure vessel codes, or asapproved by the jurisdiction. These codes typically limit design basis to an external or intemal operating pressure noless than 15 Ibffin.2 (103 kPa). However, this RP also includes vessels that operate at lower pressures. Externalpmssure on a vessel can be caused by an internal vacuum or by fluid pressure between an outer jacket and thevessel wall . Vessels subject to external pressure are usually inspected in the same manner as those subject toIntemal pressure. Columns, towers, drums, reactors, heat exchangers, condensers, air coolers, bullets, spheres,and accumulators are common types of Industry pressure vessels. [See Annex A for an Introduction to exchangers.Storage vessels subject to internal pressures up to 151bf IIn.2 (103 kPa) are covered in API 575.)Pressure vessels are designed in various shapes. They may be cylindrical (with flat, conical, toriconical, torispherical,semi-elllpsoidal, or hemispherical heads), spherical. spheroidal. boxed (with flat rectangular or square plate heads,such as those used for the headers of air-cooled exchangers), or lobed. They may be of modular construction.Cylindrical vessels, including exchangers and condensers, may be either vertical or horizontal and may be supportedby steel columns, cylindrical plate skirts, or plate lugs attached to the shell. Spherical vessels are usually supported bysteel columns attached to the shell or by skirts. Spheroidal vessels are partially or completely supported by resting on
  • 14. 6 API RECOMMENDED PRACTICE 672the ground. Jacketed vessels are those built with a casing or outer shell that fonns a space between itself and themain shell.4.2 Methods of ConstructionPrior to the development of welding, riveting was the most common method of construction. Seams were eltherlapped and riveted, or butted with butt straps and then riveted. To prevent leakage. the edges of the seams and rivetheads were caUlked. At high temperatures, It was difficult to keep this caulking tight. After the tecllnlque of weldingwas developed, a light bead of weld waS applied to the caulking edges. Although some vessels of this type can still befound in older refineries, this method of construction Is seldom used today.Today, several different methods are used to construct pressure vessels. Most pressure vessels are constructed withwelded Joints.Shell rings are usually made by roiling plate at either elevated or ambient temperature. The cylinder Is fonned bywelding the ends of the rolled plate together. this yields a cylinder with a longItudinal weld.Hot forging is another method of making cylindrical vessels. Some vessel manufacturers hot forge cylindrical shellrings for high-pressure, heavy-wall vessels such as those used for hydrotrealer or hydrocracker reactors. Thismethod does not produce a longitudinal seam in the cylinder.In the multilayer method. the cylindrical section Is made up of a number of thin concentric cylinders fabricat.edtogether, one over the other, until the desired thickness Is obtained. Multilayer construction is sometimes used forheavy-wall reactors and vessels subject to high pressure.4.3 Materials of ConstructionCarbon steel is the most common material used to construct pressure vessels. For special purposes, a suitableausteniUc or fenitlc alloy, Alloy 400, nicKel. titanium, high-nickel alloys or aluminum may be used. Copper and copperalloys (except AJloy 400) are seldom used in refinery ....essels but are common with heat exchanger tubes and may befound in petrochemical plant vessels.Materials used to construct the ....arlous parts of heat exchangers are selected to safe4y handle !he service and theheat load required. Materials that will most economically resist the type of corrosion expected are selected.Exchanger shells are usually made of carbon steel but may be made of a corrosion-resistant alloy or clad with aCOfTOslon-reslstant material. Exchanger channels and baffles are made of carbon steel or a suitable corrosion-resistant alloy material, usually similar to the material of the tubes.Tubes for exchanger bundles may be a variety of materials. Where water is used as a cooling or condensing medium,they are generally made of copper based alloys or steel. In water applications where copper alloys at steels will notprovide sufficient corrosion protection, higher alloy materials may be used such as duplex stainless steel, or the rube10 may be coated (baked epoxy or similar). Titanium may be used In seawater appllcatloos. Where the exchange isbetween two different hydrocarbons, the rubes may be made 01 steel or a suitable corrosion-resistant alloy. Tubes.COflslstlng of an inner layer of one material and an outer layer of a different material (bimetallic), may in some casesbe required to resist two different corrosive mediums.Tubesheets for exchanger bundles are made of a variety of materials. Where water is the cooling or condensingmedium, they are usually made of admiralty brass or steel, but may also be constructed of high-alloy steels (clad orsolid). TItanium may be used in seawater applications. Where the exchange of heat is between two hydrocarbons. thetubesheets may be composed of steel or a suitable corrosion-resistant alloy. In some cases it may be necessary to faceone side of the tubesheel with a material different from that facing the other to resist two different corrosive mediums.If carbon steel would not resist the corrosion or erosion expected or would cause contamination of the product,vessels may be lined with other metals or nonmetals. A lined vessel Is usually more economical than one built of a
  • 15. INSPECTION PRACnceS FOR PRESSURE VESSELS 7solid corrosion-resistant material. However, when the pressure vessel will operate at a high temperatura, a highpressure, or boItl, solid alloy steals may be both necessary and economical.Metallic liners are installed in various ways. They may be an integral part of the plate material rolled or explosionbonded before fabrication of the vessel. They may instead be separate sheets of metal fastened to the vessel bywelding. Corrosion-resistant metal can also be applied to the vessel surfaces by various weld overlay processes.Metallic liners may be made of a fenitic alloy, Alloy 400, nld<el, lead, or any other metal resistant to the corrosiveagent Figure 1 through Figure 4 show various methods of applying metallic linings. Figure 5 and Figure 6 show theHex mesh installation to support the refractory lining and the reinforced refractory lining.Nonmetalfic liners may be used to resist corrosion and erosion, reduce fouling potential (Le. exchanger tubes), or toinsulate and reduce the temperature on the walls of a pressure vessel. The most common nonmetallic lining materialsare reinforced concrete, acid brick, refractory material, Insulating material, carbon brick or block, rubber, phenoliC/epoxy coatings, glass, and plastic.Pressure vessels constructed out of nonmetallic materials are usually made from fiber reinforced plastic (FRP) andcan be more resistant to some corrosive services. FRP can be made with different resins as the matrix material andtypically use glass fiber as the reinforcement. Reinforced thermoset plastics are a type of FRP that Is more rigid dueto the use of a thermoset resin for the matrix rather than a thermoplastic. Both of these nonmetallic matenals havevarying strength due to the type of fiber used, fiber weave, and the lay-up of the fiber layers. Figure 1-Type 316 Stalnless-c/ad Vessel4.4 Internal Components and EquipmentMany pressure vessels have no internals. Others have Intema/s sucn as baffles. distribution piping, trays, mesh- orstJip-type packing grids, catalyst bed supports, cyclones, pipe coils, spray nozzles, demlster pads, and quench lines.Large spheroids may have Internal bracing and Iles and most vacuum vessels have either external or Internalstiffening rings. Some pressure vessels have heat exchangers or reboilers located In the lower shell area.Exchangers have Intemal tube bundles with baffles or support plates, which vary with the service and heat load theexcnanger is designed to handle. Pass partitions are usually Installed In the channels and sometimes Installed in thefloating tubesheet covers to provide multiple pass flow through the tubes. The flow through the shell may be singlepass, or longitudinal baffles may be Installed to provide multiple passes. The baffling used in the shell detennines thelocation and number of shell nozzles required. Figure A.. 11 and Figure A 12 of Annex A show various channel and
  • 16. 8 API RECOMMENOEO PRACllCE 572 FIgure 2-Wefd Metal Surfacing Figure 3-Strip-llned Vesselshell baffle arrangements. Frequently, an Impingement baffle or plate is placed below the shell intet noZZle to preventerosion damage of the tubes due to impingement of the incoming fluid.4.5 Uses of Pressure VesselsPressure ves. els are used in most processes In a refinery or petrochemical plant. They are used to contain process sfluids. A pressure vessel can be used as 8 thermal reactor or a catalytic reactor to contain the chemical changerequired by the process; as a fractionator to separate various constituents produced in the reaction; as a separator toseparate gases, chemicals, or catalyst from a product; as a surge drum for liquids; as a chemical treating unit; as asettling drum to permit separation of a chemical from a treated product; as a regenerator to restore a catalyst or
  • 17. INsPECTION PRAcnCES FOR PRESSURE VEssas 9 2 1/ (A) Fillet Butt I~ (B) Butt Strap (C) Cap or Joggle (0) Shingle Figure 4-Principal Strip..Jlnlng Methods Figure S-Hax Mesh InstallatIon for Refractory Unlngchemical to its original properties; or as a heat exchanger, condenser, cooler, or other type of vessel for any of variousother purposes. Figure 7 through Figure 12 illustrate various types of pressure vessels.4.6 Design and Construction StandardsPrior to the early 19305. most unflred pressure vessels for refineries were built to the design and specfflcations of theuser or manufacturer. Later. most pressure vessels in the U.S. were built to conform either to the APIIASME Code forUnfired Pressure Vessels for Petroleum Uqulds and Gases or to Section VIII of the ASME BPVC. Publication of theAPIIASME Code for Unfired Pressure Vessels for Petroleum Uqulds and Gases was discontinued as ofDecember 31. 1956. and it Is no longer used for new vessels.
  • 18. 10 API RECOMMENDED PRACTICE 572 Figure &-Reinforced RefractorySection VIII of the ASME BPVC Is divided Into three parts, Division 1, Division 2, and Division 3. Section VIII,Division 1, provides requirements applicable to the design, fabrication, inspection, testing, and certification ofpressure vessels operating at either Intemal or external pressures exceeding 15 psig. Section VIII, Division 2,provides ahemative and more stringent rules for the design, fabrication, and Inspection of vessels than those found InDiviSion 1. Most pressure vessels for U.S. refineries are now built to conform to the latest edition of Section VIII ,Division 1. Some high-pressure vessels are desIgned and built in accordance with the specifications of DiviSion 2.Section VIII, Division 3 provides alternative rules for construction of high-pressure vessels with design pressuregenerally above 10 ks j (70 MPa).In the U.S., heat exchangers and condensers are designed and built in accordance with ASME BPVC, TEMAStandards, API 660, and API 661. (Other countries may have eqUipment design requirements other than ASME,TEMA, and API. ) .Both DMslons 1 and 2 of Section Viii of the ASME BPVC require the manufacturer of a vessel to have a qualitycontrol system. Before the manufacturer can obtain a certificate of authorization from ASME, a written manual mustbe provided, and the system must be implemented. The quality control system requires detailed documentation ofexaminations, testing, and design data regarding the vessel and provides a history of the construction of the vessel.This documentation can be useful when evaluating vessels in service.The ASME BPVC lists materials that may be used for construction, gives fonnutas for calculating thickness, providesrules on methods of manufacture, and specifies the procedures for testing completed vessels. Inspection is requiredduring construction and testing of vessels . The code also prescribes the qualifications of the persons who perform theconstruction inspect/ons.After a qualified construction inspector certifies that a vessel has been bunt and tested as required by the ASMEBPVC, the manufacturer is empowered to stamp the vessel with the appropriate symbol of the ASME BPVC. The
  • 19. INSPECTION PRACTICES FOR PRESSURE VEssas 11 Figure 7-Verttcal Heat Exchangersymbol stamped on a pressure vessel is an assurance by the manufacturer that the vessel has been designed,constructed, tested, and inspected as required by the ASME BPVC.Some states and cities and many countries have laws other than the regulations of the ASME BPVC (and othercodes) that govern the design, construction, testing, installation, inspection, and repair of pressure vessels used intheir localities. These codes may supersede the ASME BPVCs (and other codes) minimum requirements.Construction codes are periodically revised as the designs of pressure vessels improve and as new constructionmaterials become available. A pressure vessel should be maintained according to the requirements of the code under
  • 20. 12 API ReCOMMENDEO PRAcTICe 572 Figure 8-Horizontal Vesselwhich it was designed and constructed. If rerated, it should be mainlained according to the requirements of the codeunder which it was rerated. A refinery or petrochemical facility inspector should be familiar not only with the latesteditions of codes but also with previous editions of the codes and with other specifications under which any vesselsthey inspect were built The inspector should be familiar with any regulations pncluding city, county, parish, provincial ,slate, or national (such as OSHA) regulations] governing inspection and maintenance of pressure vessels in therefinery. The Inspector should be familiar with the contents of API 510 and NB-23, where applicable.5 Reasons for Inspection5.1 GeneralThe basic reasons for inspection are to determine the physical condition of the vessel and to determine the type. rate,and causes of damage meenanisms and associated deterioration . This information should be carefully documentedafter each inspection. The Information gained from a general Inspection contributes to the planning of MuraInspections, repairs, replacement, and yields a history that may form the basis of a risk-based inspection (RBI)assessment
  • 21. INSPECTIOH PRAcnces FOR PRESSURE VESSElS 13 Figure 9-SpheresAgure 1O-Horton Spheroid (Noded)
  • 22. 14 API RECOMMENCED PRAcnce 572 Figure 11-Process Tower Figure 12-Exchangers
  • 23. INSPECllClN PRACTIces FOR PReSSURE VESSElS 155.2 SafetyOne of the primary reasons to conduct periodic scheduled inspections is to identify deficiencies that could result in aprocess safety Incident, such as loss of containment, that could lead to fire, toxic exposure, or other environmentalhazard. These deficiencies should be addressed immediately through evaluation, further inspection, or repair whenidentified.5.3 Reliability and Efficient OperationExternal Inspections performed while the equipment is in operation using nondestructive (NDE) techniques mayreveal important information without requiring entry inside of the equipment. With such data, mechanical Integrity ofpressurtzed equipment can be maintained and Fitness-For-Service or RBI evaluations can be performed. Therefore,this data can aid in maximizing the period of operation without an unplanned shutdown. In addition, repair andreplacement requirements can be planned and estimated in advance of a planned shutdown, to more effectivelyutilize downtime. These efforts can contribute to overall plant reliability by reducing the number or duration ofunplanned shutdowns.5.4 Regulatory RequirementsRegulatory requirements typically cover only those conditions that affect safety and environmen1a1 concerns. Ingeneral, these groups require the adherence to an Industry standard or code, such as ASME BPVC, API 510, or theNational Board Inspection Code (NBlC). In addition, OSHA 1910.119 requires refineries follow Recognized andGenerally Accepted Good Engineering Practice (RAGAGEP) when performing any Inspection and repair activitiesHowever Inspection groups in the petrochemical induslly familiar with the industrys problems often inspect for otherconditions that adve~ely affect plant operation. API 510 was developed to provide an induslly standard for theinspection of in-service pressure vessels. II has been adopted by a number of regulatory and jurisdictional authoritiesthat may require inspections In accordance with API 510.Intemal company procedures regarding inspections must be followed. OSHA and other regulatory groups require thatoperating companies follow internal procedures in addition to Industry codes and standards. Internal proceduresregarding Inspection of pressure vessels should encompass the requirements outlined in API 510 to help ensurecompliance with many of the regulatory and jurisdictional authorities.6 Inspection Plans6.1 GeneralSeveral criteria should be considered when developing an effective inspection plan. The primary goal of the plan Is toorganize inspectlons (and supporting activities) that enable the owner to assess the condition of the pressure vessel.Care should be taken to ensure that the inspections provide the infconation required to perfonn any applicableanalyses, In a timely fashion, without Imposing detrimental effects on the equipment For example, the rollowingfacto~ should be considered during the establishment of an inspection plan.a) Known or anticipated degradation modes.b) Primary areas of degradation.c) Expected degradation rate/susceptibility.d) Remaining useful life.e) Inspection technique(s) that can effectively target the degradation modes identified.
  • 24. 16 APt REcoMMENDED PRACTICE 572f) Safe accessibility of equipment or parts of the equipmentg) Potential negative Impacts of Inspection to integrity and deterioration, such as the removal of protective films or the stress on equipment due to start-up and shutdown.h) Possible rfsks to personnel Involved In Inspection activities.t) Will equipment be inspected extemally In lieu of conducting intemal inspection?j) On-stream monitoring requirements for known defects that are evaluated and found acceptable for continued servtce (without repairs). Examples include hydrogen blistering, locally thin areas due to erOSion/corrosion, etc.Complete inspection plans for pressure vessels should include the Inspection interval (or next date). the type ofinspection that should be performed, and the portion of the equipment to which the inspection should be applied.Most of the criteria above are considered In the Implementation of an RB I program, so this type of assessment can beused to build a complete plan.6.2 Inspection for Specific Types of DamageActive damage mechanisms and rates of degradation will vary markedly depending on the process stream and itscontaminants or corrodent levels, temperature of exposure, and materials of construction. Inspectors can utilizemultiple NDE tedlnlques and technologies in the jnspedion and evaluation of pressure vessels. Inspectors shouldconsider the type{s) of active degradation mechanisms and corresponding degradation modes active in the pressurevessel to determine the best technique(s) to use during the Inspection process. API 571 provides detailed guidance Inevaluating degradation mechanisms. In addition, common inspectlon techniques are identified that should allow foreffective Inspection and identification of flaws. Each damage medlanlsm, environment and equipment design mayhave unique characteristics, and the inspector should consider all parameters In determining the applicability of atechnique and its ability to produce accurate results.6.3 Developing Inspection PlansA service history record should be established after the first inspection by on-stream methods or internal examination.On the basis of this history, an inspectlon interval based on time, condition, or risk-based factors can be set inaccordance with API 510 or jurisdictional requirements. The period between inspections is normally plann9d so atleast half the remaIning life is remaining at the next scheduled inspection, or at a regular interval. The predeterminedfrequency of inspection should allow for unanticipated changes in corroSion rates where appropriate.Identifying all potential damage mechanisms is key in developing an effective Inspection plan. This can be doneutiUzlng API 571 in conjunction with process and equipmenllnformation. Once all potential mechanisms have beenestablished, the appropriate inspection tedlnique(s) should be aligned with the modes of deterioration expected.Understanding factors and conditions that affect the likelihood a damage mechanism will be active is important indeveloping a focused Inspection plan. Previous Inspection results can also be used to identify active mechanisms andbetter predict areas to be Inspected. Equipment susceptible to uniform deterioration can be inspected at anyoonvenlent location; however, it may be necessary to inspect larger areas or employ multiple techniques to ensurelocalized damage is detected.Selecting appropriate inspection locations for equipment subject to localiz9d deterioration is as critical as applying theappropriate technique. Predicting where localized damage will occur is difficult even when potential damagemechanism(s) are well understood.However, if sufficient levels of Inspection have been performed over time, then the results of those Inspections couldbe used to identify locations of applicable mechanisms. Once established, these mechanisms and their associated
  • 25. INSPECTION PRACTICES FOR PRESSURE VESSELS 17modes can be used in conjunction with equIpment availability (will equipment be shutdown or remain on-stream) toplan Inspection techniques.When changes in process operations are implemented, they should be reviewed to determine whether they mightaffect the deterioration rate or provide new damage mechanisms. When a change in !he deteriorallon rate occurs or Isanticipated, the recommended Inspection Interval should be changed accordingly.Visual checks of the external parts of a vessel should be made periodically. Such inspections can be made withoutremoving the vessel from service. These inspections rnay be made at comparatively short intervals, the intervaldepending on the service and previous condition of the particular equipment Involved. Thorough external inspectionof unfired pressure vessels should be conducted in accordance with API 510.Finally, the list of techniques identified for the pressure boundary should be compared against internal or processbased inspection and maintenance requirements (such as potential fouling or mechanical problems) to ensure allareas of the vessel are assessed as needed. All of these are combined into one set of complete Inspection activities.Then, basad on degradation rates and remaining life, appropriate timing should be identified (see Section 7).6.4 RBIRBI can be used to determine inspection intervals and the type and extent of future inspection/examinations. An RBIassessment determines risk by combining the probability and the consequence of equipment failure. When an ownerluser chooses to conduct an RBI assessment, it must include a systematic evaluation of both the probability of failureand the consequence of failure In accordance with API 580. API 581 details an RBI methodology that has all of thekey elements defined in API 580.Identifying and evaluating potential damage mechanisms, current equipment condition. and the effectiveness of thepast Inspections are important steps In assesslng the probability of a pressure vessel failure. Identifying andevaluating the process Iluld(s), potential injuries, environmental damage, equIpment damage, and equipmentdowntime are important steps in assessing the consequence of a pressure vessel failure. The consequence of afailure and the probability of a failure yields the risk associated with that pressure vessel and an appropriateInspection plan can be developed to mitigate the risk7 Frequency and Extent of Inspection7.1 GeneralThe frequency with which a pressure vessel should be inspected depends on several factors. The most Important are the rate of deterioration and the corresponding remaining usafullife (see API 510).factOIl)Maximum Intemal or external Inspection intervals should be in accordance with API 510 Of other jurisdictionalrequirements. Scheduling of shutdowns for maintenance or inspection is usually ananged through the collaboration ofprocess, maintenance, and inspection groups or as mandated by a jurisdiction. Where practical. efforts should bemade to schedule unit shutdowns evenly throughout the year to distribute the work/oad on the inspection andmaintenance groups. On most units, operational performance related to equipment cleanliness and internal foulingmay determine the length of a unit run: especially for towers, exchangers, and the maintenance of required heat-transfer rates for heat exchangers.Mechanical integrity, continued safe operations, and compliance with environmental regulations are the mostimportant considerations in scheduling units for Inspection. Occasionally. seasonal demands for certain products maymake some units available for inspection and maintenance WOfi( without serious interruption of supply. New vesselsshould be inspected at a reasonable time interval after being placed In service. This interval will depend on theequipment design, fabrication, and service conditions. The past records on vessels in similar units may be used as aguide.
  • 26. 18 API REcow.IeNoeo PRACTIce fil2Insurance and jurisdictional requirements may also affect the inspection of pressure vessels. Those responsible forInspection and maintenance of equipment should familiarize themselves with the applicable requirements.Recommendations In AP I 510. NB-23. and Jurisdictional requirements should be followed where appropriate.7.2 Opportunities for InspectionThe actual time for inspection wln usually be determined through the collaboration of process, mechanical, andInspection groups, or by the mandate of a jurisdiction.Unscheduled shutdowns due to mechanical or process difficulties sometimes present opportunities for intermediatechecks of vessel areas where rapid corrosion. erosion. or other deterioration Is known or suspected to occur. Partialshutdowns of units for process reasons also provide opportunities for making some Intemal inspections to determineconditions and verify on-stream inspection findings and for making needed repairs. However, internal inspectionsduring unscheduled shutdowns should be motivated by specific process or inspection observations.Inspections during the following opportunities are possible.a) Heat exchangers are normally taken out of service for cleaning at more frequent intervais than permitted by the normal run of the process unit, it Is beneficial to install spare exchangers, so that the heat exchanger can be bypassed and opened for cleaning. Advantage should be taken of the opportunity to inspect exchangers when removed for routine cleaning. to identify repair/replacement needs that can be scoped and scheduled for a Mure unit outage.b) When vessels or process towers are removed from service to clean trays and other Internals.c) Extemal inspections may be made while a vessel is In service. Inspection woft( performed while the equipment is in service will reduce the woft(load when it Is out of service. These inspections should oover the oondition of the foundation. supports, insulation, paint, ladders, platforms, and other structural elements. The existence and location of abnormally high metal temperatures or hot spots on intemally insulated units can also be detected. On- stream inspection methods may be used to detect defects and to measure wall thickness. For example, thickness can be determined by using ultrasonic equipment or profile radiography where applicable.d) An occasional check of the operating record while equipment is in service is sometimes helpful in determining and locating the cause of functional deterloration. An increased drop in pressure may indicate blockage from excessive oorroslon deposits. Reduced exchange of heat from exchangers or coolers may Indicate heavy oorrosion deposits on or in the bundle tubes. The inability to draw the product of fractionation or distillation from certain trays may IndIcate fouling or loss of tray parts In a process tower. Product deterioration may IndIcate loss of trays. tray par1s, or other Intemal equipment In process vessels. The inspector should always keep in dose touch with operations.e) On-sfream inspections can be planned and executed without shutting down equipment. This may require special provisions to access areas for inspection, such as scaffOlding, insulation removal, rope access provisions, and surface preparation (buffing to remove surface scale/deposits).8 Safety Precautions and Preparatory Work8.1 Safety PrecautionsSafety procautions must be taken before entering a vessel, including consulting and complying with all applicablesafety regulations. This Includes, but Is not limited to, "lockoutltagour and ~confined space- requirements. Because oflimited access and egress within confined spaces, safety precautions are critical for lntemal vessel inspection woft(.The vessel should be isolated from all sources of liquids, gases, or vapors. using blinds or blind flanges of suitablepressure and temperature rating. The vessel should be drained, purged. cleaned, and gas tested before it Is entered.This preparation will minimize danger from toxic gases. oxygen deficiency. explosive mixtures. and irritating
  • 27. INSPECTION PRACTlCES FOR PRESSURE VEssas 19chemicals. Clothing that will protect the body and eyes from the hazards existing in the vessel to be entered should beworn. Details of the precautions to be followed are covered in API 2217AOn occasion, it may be desirable to enter a vessel before it has been property cleaned to search for internal causes ofpoor operation. In this case, the inspector should exercise the special precautions and utilize additional personalprotec1lve equipment (I.e. breathing air) for such entry as given In API 221 7A.The use of NDE devices for Inspection Is subject to safety requirements customarily met in gaseous atmospheres,which are listed in API 2214. The use of hydrocarbon-based magnetic particle (MT) and/or liquid penetrant (PT) canchange the environment of a confined inspection space. Therefore, procedures should be in place that recognize thepotential change In the gaseous atmosphere. Such procedures may include periodic gas tests, limiting other activitiesin or near the subject vessel, and housekeeping requirements to minimize the accumulation of accelerants and rags.Before the inspection starts, all persons wor1<ing around a vessel should be informed that people will be workinginside the vessel. The posting of tags on the manways of tall towers is a worthwhile precaution. Usually, a safetyguard Is stationed at the manway nearest the area under Inspection. Workers inside a vessel should be informedwhen any work will be done on the exterior of the vessel to prevent their becoming alarmed by unexpected or unusualnoise.8.1.1 Precaut10ns Regarding the Use of Breathing AirFor many companies, confined entry into vessels containing unbrealhable atmospheres is not allowed. However, onoccasions, it may be desirable to enter a vessel before it has been properiy cleaned and prepare<! for enrry withoutthe need for breathing air. API 2217A offers several guidelines and precautions if this situation arises.Breathing air should be supplied from cylinders or a dedicated air compressor system that is certlfied for breathing air.At least two independent breathing-air sources shall be used. Breathing-air hose couplings shall be Incompatible withthe couplings for other utility gas systems or nonbreathlng plant air system In order to prevent the inadvertent crossconnection of breathing-air hoses with gases that should not be inhaled. Fatalities have occurred when crossconnections have been made, or when breathlng-alr cylinders did not contain the necessary oxygen levels. Refer toAPI 2217A for guidelines to follow for ensuring that breathing-alr supplies are safe for use.8.2 Preparatory WorkThe tools needed for vessel inspection, indudlng tools and equipment needed for personnel safety, should be to the Inspectlon. Any necessary safety signs should bechecked for availability and proper wort<lng condition priorinstalled prior to work in vessels.Some of the tools that should be available for pressure vessel Inspections follow: a) portable lights, including a flashlight; b) flashlight with bulb on flexible cable; c) thln-bladed knife; d) broad chisel or scraper; e) pointed scraper; f) mirrors; g) inside calipers:
  • 28. 20 API RECONME..a?EO PRACllCE fil2 h) outside calipers; I) pocket knife; 1) steel tape [50 ft (15 m)J; k) flange square; I) an inspectors hammer or ball peen hammer (4 oz or 8 oz); m) ultrasonic (UT) thickness measurement equipment; n) tube gauges (Inside diameter); 0) steel rule; p) pit depth gauge; q) paint or crayons; r) notebook and penells; s) straightedge; t) wire brush; ul plumb bob and line; v) magnet; w ) magnifying glass; x) hook gauge; y) plastic bags for corrosion product samples.The following tools should be available if required: a) surveyors level; b) carpenters or plumbers level; c) MT inspection equipment; d) micrometer, e) three-ball micrometer for tube 10 measurement; f) radiographic equipment; g) megger ground tester; h) sandblasting equipment; I) high-pressure water blasting equipment;
  • 29. INSPECTlON PRACTIC£S FOR PReSSURE Vessas 21 j} portable hardness-testing equipment~ k) eddy current (ET) testIng equIpment; 1) sonic and radiation-measuring equipment; m) fiber optic flexible scopes; n) surveyors transit; 0) temperature-indicating crayons; p) thermocouples; q) metal sample-cutting equipment; r) material identification kit or machine; s) camera; t) UT fiaw-detection equipment; u) PT inspection equipment; v) test-hole drilling equipment (drill, tap, and plugs); w) sand- or water-blasting equIpment; xl borescope; y) plumb lines and levels; z) spotting scope or binoculars; aa) neutron backscatter eqUipment for moisture detection; ab)magnetlc flux leakage equipmentOther related equipment that might be provided for Inspection includes planking. scaffolding. bosons chairs, chain orrope ladders, safety devices for climbing flares or ladders without cages. stages for lifting by cranes, radios, andportable ladders. If external scaffolding Is necessary, it may be possible to erect it before the inspection starts.The vessels should be cleaned prior to inspections. Cleaning can be performed with a wire brush or by abrasive-gritblasting. grinding, high-pressure water blasting [e.g. 8000 Ibtlin.2 to 20,000 Ibflin.2 (55.2 MPa to 137.9 MPa)]. orpower chipping when warranted by circumstances. These extra cieaning methods are necessary when stresscorrosion cracklng, wef sulfide cracking. hydrogen attack, or other metallurgical forms of degradation are suspected.9 Inspection Methods and Limitations9.1 GeneralBefore starting Itle Inspection of a pressure vessel, especially one In severe service, the inspector should determinethe pressure, temperature, and service conditions under which the vessel has been operated since the lastinspection. The Inspector should also be aware of eqUipment construction details including materials of construction,the presence of Internal attachments, and weld detaUs. They should also confer with operations to determine whetherthere have been any abnormal operating conditions or disturbances such as excessive pressures or temperatures.
  • 30. 22 API RECOMMENDED PRACTlCE 572This data may offer valuable clues to the type and location of corrosion and to other fonns of deterioration that mayhave occurred such as scaling, bulging, and warping. The inspector should develop and exerclse sound judgment onthe extent and kinds of inspection required for each vessel.Careful visual inspection of every vessel is of paramount importance to determine other forms of Inspection that mayneed to be made. Appropriate surface preparation Is essential to all Inspection methods. The extent to which specialsurface preparation may be required depends on the particular circumstances Invotved. Wire brushing, sandblasting,high-pressure water blasting, chipping, grinding, or a combination of these operations may be required In addition toroutine cleaning.If external or internal coverings such as insulation, refractory linings, or corrosion-resistant linings are In goodcondition and without evidence of an unsafe condition behind them, it may not be necessary to remove them forinspection of the vessel. However, it may sometimes be advisable to remove small portions to investigate theircondi1iOll and the condi1ion of the metal behind them, partJcularty If previous Inspections have Indicated corrosion or ifoperating conditions present the risk of corrosion under insulation (CUI). When any covering Is found to be defective,a sufficient amount of the covering in the vicinity of the defect should be removed to find out whether the base metal Isdeteriorating and to determine the extant of the deterioration.Where operating deposits such as coke are normally permitted to remain on a vessel surface, it is Important todetermine the conditioo of the vessel surface behind the deposits. This may require thorough removal of the depositin selected critical areas for spot-d1eck examination.Where vessels are equipped with removable intemals, the internals need not be completely removed, providedreasonable assurance exists that deterioration is not occurring beyOlld that found In more readUy accessible parts ofthe vessel. Condltlon monitoring locatlons (CMLs) can make areas of the pressure vessel more accessible. Cutouts Ina vessers insulation at the CML points allow for visual examination of the exterior of the vessel and allows forthickness measurements of the vessel wall to be taken.9.2 Thickness Measurements9.2.1 GeneralThere are many tools designed for measuring metal thickness. The selection of tools used will depend on severalfactors:a) the accessibility to both sldes of the area to be measured,b) the desire for NDE methods,c) the time available,d) the accuracy desired,e) the economy of the situation.UT instruments are now the primary means of obtaining thickness measurements on equipment Radiography andreal-time radiography may also be used in a limited way to determine thickness of vessel parts such as nozzles andconnecting piping. Methods sucl1 as depth drilling (Le. sentinel or tell-tale holes), the use of corrosion buttons, and theuse of test holes may be appUed at some special locations. However, these methods have generally been replacedby NDE methods of thickness gauging, such as UT. UT, both for thickness measurement and flaw detection,represents an important technique of NDE inspection.API 510 allows a statistical treatment of UT thickness data to assess corrosion rates and current thickness. It Isacceptable to average several individual thickness readings at an examinatioo point to determine the thickness at the
  • 31. INSPECTION PRACTlCES FOR PRESSURE VEssas 23test point. Moreover, the ensemble of examination point data may be statistically analyzed to assess corrosion ratesand actual minimum thickness. VVhen using such methods, it Is important that areas with distinct corrosionmechanisms be property identified and treated in the analysis process. Alternatively, scanning techniques provIde agreater data density which prollides better statistical information. Magnetic flux scanning techniques are alsoavailable which provide a fast qualitative technique fur the detection of corrosion losses on large surface areas forvessels up to 0.5 In. (1.3 cm) wall thickness.Radiographs are taken with a step gauge of known thickness thai will show on the developed film of the vessel part Inquestion. By comparing the thickness of the step gauge on the film to the thickness of the part on the film, the partthickness may be determined.API 510 permits an on--stream Inspection to be conducted in lieu of an intemallnspection under certain conditions.When this approach is used , a representative number of thIckness measurements must be conducted on the vesselto satisfy the requirements for an intemal Inspection. A dedsion on the number and location of thicknessmeasurements should consider results from previous inspectlons, if available, and the potential consequences of lossof containment. In general, vessels with low corrosion rates will require fewer thickness measurement locationscompared to vessels with higher corrosion rates. A possible strategy for vessels with general (I.e. uniform) corrosionis to divide the vessel into its major design sections (Le. shell. head, and nozzles) and identify at least onemeasurement location for each design item. The number of thickness measurement locations would progressivelyincrease for higher corrosion rates. The Inspector, in possible consultation with a pressure vessel engineer, woulddetermine the specific measurement strategy for the vessel.For pressure vessels susceptible to localized corrosion, additional thickness measurement locations will be required,or altemate techniques will be necessary p.e. manual or automated ultrasonic technique (AUT) scanning}. Theselection of these additional areas and/or methods should be made by personnel knowledgeable In localizedcorrosion mechanisms.9.2.2 LImits of ThicknessThe limits of wall loss, due to corrosion and other deterioration mechanisms, that may be tolerated must be known, oran Inspection wiIl lose much of its value. The two most important factors of this problem are the following:a) the retiring thickness of the part considered,b) the rate of deterioration.Before determining the limiting or retiring thickness of parts of any pressure vessel, the code and edition of the codethat the vessel will be rated under, and whether there are any regulations regarding limits and allowable repairs, mustbe determined.There are a great many variables, such as size, shape, material, and method of construction, that affect the minimumallowable thickness. API 510 recognizes that corrosion rate, corrosion allowances, rerating, and componentassessment by ASME BPVC Section VIII , Division 2, methodology may all be used to establish retirement and nextInspection ailena. For this reason, It Is not possible In this document to present a single set of minimum or retirementthicknesses. API 510 contains additional guidance on the rating of pressure vessels.When corrosion or erosion is causing deterioration, the rate of metal loss can usually be obtained by comparingconsecutive Inspection records. Data and graphs showing this information should be kept with the vessel records. Inmany cases, computerization of inspection data has been helpful in quickly determining corrosion rates and inestimating retirement dates. The ability to predict when a vessel will reach a retiring thickness is important.Scheduling of repairs and replacements will be greatly Influenced by such predictions.When the safe limit of thickness is approached or reached, decisive action Is necessary. In some cases decisions willhave to be made quickly without mum time for study or consideration and relliew by others. The minimum thickness
  • 32. 24 API R. COMMENOEO PRACTICE 572 Eor the methods of calculating the minimum thickness should be known in advance for each vessel. It should be notedthat different parts of a vessel may have different retirement thicknesses. A risk-based assessment of the data couldbe valuable.Most vessels are built with greater thickness in vessel walls and heads than what is required to withstand the intemaloperaUng pressures. This excess thickness may result from any of the following:a) deliberately adding it into the design as corrosion allowance;b) using a nominal plate thickness rather than the exact, smaller value calculated ;c) setting minimum plate thickness for construction purposes;d) change in vessel service: a reduction of the safety valve setting. the maximum metal temperature, or both.When this excess thickness and the corrosion rate are known, the date when repairs or replacement will be neededfor any vessel can be predicted with reasonable accuracy.Cautlon-ln some cases, the excess thIckness of the shell or head plates Is used by the designer as nozzlereinforcement.Since the ASME 8PVC is a design and construction standard for vessels, the methods for calculating the retirementthickness of many accessories of pressure vessels are not covered. Some of these parts are trays, Internal traysupports, valves, grids, baffles, ladders, and platfonns. For some of this equipment, there are generally acceptedmethods of setting the retiring thickness. Minimum thickness should be developed for all this equipment Theconsequence of possible failure of equipment should be considered when setting these limits. Safety is the primefactor affecting retiring thickness. After safety, continuous and efficient operations become a factor. (API 574 shouldbe consulted for Inspection of some of the parts mentioned in the preceding text. )Since they are not considered as part of the pressure-retaining boundary, no minimum thickness is set for appliedmetallic linings. As long as the lining remains free of leaks or does not require excessive repairs, it should besatisfactory for further service.In the case of exchangers, minimum thickness values should be developed for tubes, tubesheets, channels, covers,and other pressure retaining exchanger parts. The consequence of possible failure of such parts should beconsidered when setting these limits. Safety Is the prime factor affecting retiring thickness for this equipment.Nonnally, failure of Internal parts, such as the various components of the tube bundle, does not involve a hazard;hence, continuous, efficlent operation is the governing factor in establishing retirement limits of internal parts. Someparts, such as baffles, may be continued in service until failure, and tubes need not be plugged or replaced until actualperforation occurs.9.3 Extemallnspection9.3.1 GeneralAs indicated in Section 9, much of the external inspection can be made while the vessel Is in operation. Anyinspection made during vessel operation will reduce the period during which the vessel will be out of service.9.3.2 ladders, Stairways, Platforms, and WalkwaysThe extemal inspection of pressure /essels and exchangers should start with ladders, stairways, platforms, orwalkways connected to or bearing on the vessel.A careful visual inspection should be made for corroded or broken parts, cracks, the tightness of bolts, the condition ofpaint or galvanizing material, the wear of ladder rungs and stair treads, the security of handrails, and the condition of
  • 33. INSPECTION PRACTICES FOR PRESSURE VEssas 25flooring on platforms and walkways. VIsual inspection should be supplemented by hammering and scrapIng toremove oxide scales or other corrosion products; floor plates can be removed to check their supporting members.The tightness of bolts can be determined by tapping with an inspectors hammer or a small ball peen hammer or bytrying the nuts with a wrench. Wear on metal stair treads and flooring may not only weaken them but also make themslippery if worn smooth. Depressions In platforms should be closely checked, because water lying In depressions canaccelerate oorroslon. Crevices should be checked by picking at them with a pointed scraper. Loose or broken partsare easily found by tapping with a small ball peen hammer or an Inspectors hammer. If desired, thicknessmeasurements of the platforms and structural members can be made with transfer calipers.Corrosion Is most likely to occur where moisture can oolled. On ladders and stairs, oorrosion is likely to ooncentratewhere rungs or treads fit Into the runners or stringers. Crevice corrosion may eldst around the heads of bolts and nuts,at bracket connections between stair treads and angle supports, and at connections between Intermediate supportsand the vessel wall. Welded bracket oonnections are particularty susceptlble to oorrosion as the welds are usuallyrough, and it Is difficult to apply a good, void-free paint coating to them. CorrosIon may exist beneath a paint film andwill be Indicated by rust stains showing through the paint or by a blistering or a general lifting of the paint film.The oondltion of most paris can be determined by hammering. Where oorroslon appears to be severe, the actualthickness should be determined using a caliper or by other means.9.3.3 Foundations and SupportsFoundations for vessels are almost Invariably constructed of steel-reinforced concrete or structural steel fireproofedwith ooncrete. They should be inspected for deterioration such as spalllng, cracking, and settling.The foundations for exchangers usually oonslst of steel cradles on concrete piers. Occasionally, the supports aremade entirely of steel. Figure 13 shows a typical exchanger foundation.The crevice formed between an exchanger shall or a horizontal vessel and a cradle support should be carefullychecked. Moisture lying In the crevice can cause rapid attack on carbon steel and on low-chrome-molybdenumsteels. If the cradle is sealed with a mastic compound, this seal should be checked to make sure that it Is Intact.Cradles are often seal welded to vessel shells to prevent moisture from accumulating in the crevice and causingoorroslon. Figure 13-Exchanger Installation and Foundation
  • 34. 26 API RECOMMENDED PRACllCE 572Excessive heat, mechanical shock, corrosion of reinforcing steel, or the freezing of entrapped moisture can causecracking in and around supports. Inspection for this type of damage should consist of visual observation andscraping. Measurements of the depth of such damage can usually be made with a straightedge or a steel rule.Cracks in concrete or fireproofing may be caused by excessive heat, poor design or material, mechanical shock, orunequal settlement. Inspection for cracks should be mostly visual. Some plcklng with a pointed scraper may behelpful.Very small openings or cracks In concrete or fireproofing caused by high temperature or by temperature changes canusually be identified by their hair~lIke appearance. Such cracks are not usually serious unless they expose the steel tocorrosion.When major cracks appear and propagate, and measurements indicate that no settlement has taken place, thecracks are probably the result of fatigue (temperature cycling due to process or weather conditions), poor design, orpoor material. In such cases. a complete check or engineering study may be required. If such investigations show thatthe design is correct, then the cracks are most likely caused by fatigue, or the use of poor concrete material. Carefulvisual examination and minor chipping with a hammer will usually confirm the diagnosis, but removal of a core fortesting may be required.Some settling is expected In any foundation. When settlement is even and of a nominal amount, no trouble should beexperienced. However, if it is excessive or uneven, the settlement should be corrected before serious damageoccurs. When foundation or support settlement has occurred, the condition of connected pipe lines should bechecked.Records of settlement should be maintained on vessels known to be settling. A rough check for uneven settlIng canbe made with a plumb line and steel rule. When accurate measurements are desired, a surveyors level may be used.When settlement is appreciable, it can be observed by noting the misalignment of the foundation with the surroundingpaving or ground. The frequency with which settlement measurements should be taken depends on the rate and theseriousness of the settlement. Measurements should be tak. n until the settlement stops. Vessels supported on long econcrete slabs or on two or more separate foundations are more likely to undergo uneven settlement.9.3.4 Anchor BoltsAlthough the condition of anchor bolts cannot always be completely determined by visual Inspection, the area ofcontact between the bolts and any concrete or steel should be saaped and closely examined for corrosion. Althoughthis will not reveal the condition below the top surface of the base plate or lugs, a sidewise blow with a hammer mayreveal complete or nearty complete deterioration of the anchor bolt below the base plate (see Figure 14). Distortion ofanchor bolts may Indicate serious foundation settlement. The nuts on anchor bolts should be inspected to determinewhether they are property tightened. UT may also be used to test bolts.9.3.5 Concrete SupportsInspection of concrete supports is similar to inspection of concrete foundations. The opening between concretesupports and a vessel shell or head should be sealed to prevent water from seeping between the supports and thevessel. A visual inspection with some picking and scraping should discfose the condition of the seal. A concentrationcell could develop there and cause rapid corrosion.9.3.6 Steel SupportsSteel supports should be Inspected for corrosion, distortion. and cracking.The remaining thickness of corroded supporting elements (skirts, columns, and bracing) is of primary importance. Itcan usually be determined by taking readings with transfer or indicating calipers in the most severely corroded areas.The readings should be compared with the original thickness (if known) or with the thickness of uncorroded sections
  • 35. INSfECTlON PRACTICES FOR PRfSSURE VESSELS 21 .,t.r. t anchor bolt conditions saMceabie standlion appearance of boll leg (pipe) and nul above nange and severe corrosion below nul flange groove fonned by bolt template grade Figure 14-Severe Deterioration of Anchor Boltsto estabfish a corrosion rate. Visual examination of the support surfaces should be supplemented by wire brushing,picking, and tapping with a hammer. On large skirt supports, UT thickness measuring devices can be used. Often,corrosion of structural elements can be virtually eliminated simply by keeping the structural elements proper1ypainted. Galvanizing is one of the best methods of protecting steel structtJres from corrosion.Columns and load-carrylng beams should be inspected for buckling or excessive deflection. This can be Inspecte<lvisualty with the aid of a straightedge or plumb line. Taking diameter measurements at several points approximately60° (1.0 radian) apart can check distortion of cylindrical skirts.The inside surface of a skirt sheet Is often subject to attack by coodensed moisture, especially when the temperaturein the enclosed area Is less than approximately 100°F (38 0c) or when steam Is put in the skirt to warm the bottom ofthe vessel. Visual inspection will usually disclose the condition of the metal surface. If a scale or rust layer has builtup, it should be wire brushed or saaped off before the inspection Is made.Vessel support lugs should be Inspected to see that they are sound. Scraping will usually reveal corrosion. Tappingwith a hammer will disclose extreme thinning. Connecting fasteners should be checked for corrosion and generaltightness. Any crevices found should be examined for crevice corrosion by picking. Cracks can occur in aU types ofsupporting structures and lugs. However. they are most likely to appear in welded structures. The welds and theareas adjacent to the welds are the common locations of cracks. If the vessel is in service, the inspection will probablybe limited to visual methods of detecting cracks. MT (wet or dry), PT, or UT shear-wave methods may be used tosupplement visual examination. These methods will often require further surface preparation .
  • 36. 28 API REcot.HENDED PRACTICE 572If supporting skirts are insulated, the insulation should be inspected. VISual inspection will usually disclose anydeterioration of the Insulatlon. If there Is reason to suspect that water or moisture Is seeping through to the steel,enough Insulation should be removed to determine the extent of any corrosion.Inspect fixed and floating supports on horizontal vessels. Floatlng ends of vessels must be free to allow for thermalgrowth and contact any sort of stop. Air fan tubes will buckle If shipping ptns are not pulled from floatlng supports.Piping attachments to vessels (I.e. supports and guides) should be Inspected for evidence of distortion due to pipemovement.Fireproofing on support beams and skirts should be inspected. It is usually made of bricks or concrete. Visualexamination aided by scraping will disdose most defects. Very light taps with a hammer will disclose lack of bondbetween concrete fireproofing and the protected steel. If moisture can get behind the fireproofing. the steel maycorrode and may cause the fireproofing to bulge. The bulge In the fireproofing would indicate the corrosion. Ruststains on the surface of the fireproofing would indicate possible corrosion of the metal underneath.9.3.7 RivetsAlthough uncommon. riveted vessels may still be found In process facilities. Inspection should Indude examination ofthe rivet head, butt strap, plate, and caulk. If rivet-shank corrosion is suspected, hammer testing (9.8 describeshammer testing and other inspection test methods) or spot radiography at an angle to the shank axis may be useful.9.3.8 Guy WiresMost vessels are self-supportlng structures. Some towers or columns are guyed for support by steel cables. Thesecables radiate to the ground and terminate In the concrete deadman anchors benaath the ground surface.The coonectlons to the tower and to each ground anchor point should be Inspected for tJghlness and correct tension.Visual examination may be sufficient to check wire rope condition at grade and from accessible platfonns, but AUTinspection Is typically necessary to scan the entire length of guy wires for condition and proper loading. It is also oftennecessary to periodically lubricate guy wires to maintain COITOsion resistance (also done with automatic equipment). Ifthere is a question regarding the correct tension in the cables, a structural engineer should be consulted.The cable should be inspected for corrosion and broken strands. The threaded parts of any turnbuckles are subject tocrevice corrosion. Pidting with a pointed scraper will disclose this corrosion.The wire rope clips on the guy wire cable at the tower and at the ground anchor point should be checked for correctinstallation . The clips should be attached to the cable with the base against the live or long end and the U-bott againstthe dead or short end of the wire rope. The dips should be spaced at least six rope diameters apart to insuremaximum holding power. The number of dips necessary for each wire rope end depends upon the diameter of thewire rope. This number can be found in wire rope catalogs and In engineering handbool<s.9.3.9 NozzlesIf any settling of the vessel has occurred, nozzles and adjacent shell areas should be inspected for distortion andcracking. Excessive pipeline expansions, intemal explosions, earthquakes, and fires may also damage pipingcoonections. Flange faces may be checked with a flange square for distortion. If there Is any evidence of distortion orcrncks in the area around the nozzles, all seams and the shell in this area should be examined for cracks. The areashould be abrasive-grit blasted or wire brushed. MT (wet or dry), PT, angle beam UT, or replication techniques may beused to supplement visual examination. Catalytic reformer equipment operating at temperature more than 900 O F(482 0c) may experience creep embrlttJement damage during operation . Replication is a useful technique in detectingthis damage).
  • 37. INSPECIlON PRACTICES FOR PRESSURE VEssas 29Walllhickness of nozzles should be measured. Calipers, UT Ihickness instruments, or radiographic techniques maybe used. These measurements should be recorded and compared with previous or origInal thickness readings. Anylosses should be analyzed, and appropriate action should be taken, such as renewal if thickness is near or atminimum, Installing a lining if feasible. monitoring on shorter Intervals, and using corrosion inhibitors.Leaks are likely to occur at piping attachments to the vessel wall. Leaks can be located visually while the vessel Is Inservice or under test conditions. Evidence of a leak is usually left in the form of discoloration to the vessel, insulation,fireproofing, or paint, or damage to or wetting of the insulation.9.3.10 Grounding ConnecttonsGrounding connections should be visually examined to vertfy that good electrical contact is maintained. Theseconnections provide a path for the harmless discharge of lightning or static electricity Into the ground. The systemusually consiSts of a stranded copper conductor with one end bolted to Itle vessel and the oltler end brazed or boiledto an iron or copper rod placed deep in the ground. The cable connections should be checked for tightness, positivebonding to ltte vessels, and corrosion where It penetrates the foundation, slab or ground. The continuity of all groundwires should be checked. No break should exist In the grounding circuit Test the system to see that the resistance toground does not exceed the accepted values in the area. Recommended resistance is 5 ohms or less, and resistanceIs not to exceed 25 ohms. In some areas, jurisdictional requirements will differ from these values, will govem, andneed to be checked. Note that in some process systems, grounding of equipment is done through Interconnectingpiping to common ground locations. Consult with area electrical engineering regarding equipment without groundingconnections.9.3.11 Auxiliary EquipmentAuxiliary equipment, such as gauge connections, float wells, sight glasses, and safety valves, may be visuallyInspected while the unit Is in service. Undue vibration of these parts should be noted. The vibrations should bearrested by adding supports, or calculations should be performed by a qualified engineer to assure that the vibrationswill nol cause a fatigue failure. Also, check for proper construction of auxiliary equipment and connecting pipingbeyond vessel block valves as they can be improperly mcx:lified during unit operation for contingency reasons.9.3.12 Protective Coatlngs and InsulationThe condition of the protective coating or insulation on a vessel shell should be determined. Rust spots. blisters, andfilm IIftlng are the types of paint failures usually found. Rust spots and blisters are easily found by visual examination.FUm lifting is not easily seen unless the film has bulged appreciably or has broken. It can be found by picldng at thefilm with a saaper or knife In suspect areas. Scraping paint away from blisters and rust spots often reveals pits in thevessel walls. The depth of such pitting can be measured with a pit gauge or a depth gauge. The most likely spots tosearch for paint fallure are in crevices, in constantly moist areas, and at welded or riveted vessel seams. The bottomheads of vessels supported on skirts in humid locations are other likely points of paint failure.Visual examination of insulation is normally sufficlent to determine its condition. A few samples may be removed tobetter determine the condition of the insulation and the metal wall under it The supporting clips, angles, bands, andwires should all be examined visually for corrosion and breakage. Occasionally, spadal blocks of Insulation may beInstalled so that they are easily removable. These blocks are Installed where it Is desirable to make pericx:llcinspections, usually at welded seams.Inspectlon for CUI should be considered for externally insulated vessels subject to moisture ingress and whichoperate between 10 OF (-12°C) and 350 OF (175 0c) for carbon and low alloy steels, and 140 OF (60°C) and 400 OF(205°C) for austenitic stainless steels, or are in Intermittent service. This inspection may require removal of someInsulation. However. visual Inspection at ports used for thickness measurement locations may not adequately assessexternal corrosion at other locations. Often, moisture sealing and Insulation type/consistency at these thicknessmeasuring locations is not representative of the vessel Insulation in general. Neutron backscatter methcx:ls can
  • 38. 30 API RECOMMENDED PRACTICE 572provide an on-stream assessment of areas with high moisture and can provide a screening assessment for CUI.Thennography data may provide a similar on-stream screening assessment. Pulsed ET may be used to measuremetal thickness through insulation. Alternatively, shell thickness measurements done with UT at typical problemareas (e.g. stiffening rings, nozzles, and other locations which tend to trap moisture or allow moisture ingress) may beperformed during Internal Inspections.9.3.13 External Metal SurfacesThe extemal metal surfaces of a vessel may be inspected visually by picking, scraping, and limited hammering tolocate corroded areas.Cautlon-Extreme care should be used on operating equipment containing hot, harmful, or hlgh1)ressurematerial. to minimize the potential for creating a leak.If conditions warrant, scaffolding may be erected around a vessel to permit access to all surfaces.The degree of surface preparation required for external inspection will depend on the type and extent of deteriorationexpected. Under normal conditions, thorough cleaning to bare metal will be needed only at those points wtlere UTthickness measurements are taken. When cracking or extensive pitting is suspected, thorough cleaning of a largearea (possibly the entire vessel shell) may be required.Hand tools such as a pointed scraper, an Inspectors hammer, a wire brush, a scraper, and a file can be used to cleansmall spots. For larger areas, power wire brushing or abrasive blastlng will usually be cheaper and more effectivethan the use of hand tools.Any evidence of corrosion should be investigated and the depth and extent of the corrosion should be determined.ThIckness measurements of the vessel walls, heads, and nozzles are usually required at each complete vesselInspection. Whether these measurements are taken from the outside of a vessel or the Inside will depend on thelocation and accessibility of the corroded areas.Under normal conditions, at least one measurement in each shell ring and one measurement on each head should betaken. However, If much corrosion Is evident or If locaUzed erosIon/corrosion Is antiCipated In specific areas, severalreadings should be taken in the most corroded areas. AUT instruments may also be used to scan areas wtlen moredata points are needed. Also, if no history exists on a particular vessel, getting readings In each quadrant of eachshell ring and head should be considered. UT Instruments may be used for these measurements. Under abnormallyclean-service conditions, fewer readings may be taken.Inspect vessels in cyclic service at extemal supports using either PT or MT testing for fatigue cracking.9.3.1 4 External Evidence of CorrosionCertain types of corrosion may be found on external surfaces of a vessel. Among these are atmosphericcorrosion, caustJc embrittlement, hydrogen blistering, and soil corrosion. These types of corrosion are covered Indetail in API 571.The extent of atmospheric corrosion on the outside of a vessel will vary with local climatic, coating, and serviceconditions. In humid areas and in areas where corrosive chemical vapors are present in the air. corrosion of extemalshell surfaces may be a problem. Vessels operating in a temperature range that will permit moisture to condense aremost susceptible. Corrosion of this type Is usually found by visuallnspectlon (see 9.5.3).
  • 39. INSPECTION PRAcnCES FOR PRESSURE VESSElS 31If a caustic is stored or used In a vessel, the vessel should be checked for caustic embrittlement. This type of attack ismost likely to occur at connections for Internal heating units and in areas of residual or other high stress. The moresusceptible areas are around nozzles and in or next to welded seams. Frequently, visual inspection will disclose thistype of attack. The caustic material seeping through the cracks will often deposit white salts that are readily visible.MT (wet or dry), PT, and angle beam UT examinations may also be used to check for caustic embrittiementThose areas below the liquid level in vessels that contain acidic corrosion products are more likely to be subject tohydrogen blistering. Hydrogen blistering Is typically found on the Inside of a vessel. However, hydrogen blisters maybe found on either the 10 or 00 surface depending on the location of the void that causes the blistering. Blisters arefound most easily by visual examination. A flashlight beam directed parallel to the metal surface will sometimes revealblisters. When many small blistElfS occur, they can often be found by running the fingers over the metal surface.Attention should be given to metal surfaces in contact with concrete saddles. In humid atmospheres, severe attack atthe points of support may require weld repairs and subsequent application of protective coatings.Vessels that are partially or completely underground are subject to soli corrosion wherever they are in contact with theground. This COITOsion will be particular1y intense In areas where cinder fills were used or where acid splash-over hasoccurred. Inspection of the vessel surface will require thorough cleanIng. Abrasive blasting will usually provide thebest surface preparatlon. Visual examination, supplemented by picking and tapping, will dIsclose most faults. Thelocation of any deep pItting should be recorded. Good judgment should be used in determining how much of thesurface should be uncovered to permit this Inspection. The most severe corrosion will usually be found betweenground level and up to several inches below. Any vessel in contact with the ground Is a candidate for connection tocathodic protection, and if so designed, this should be inspected.The external surfaces of the vessels should be examined not only for corrosion but also for leaks, cracks, buckles,bulges, defects in the metal plates, and deformation and corrosion of any external stiffeners. If the vessel is insUlated,small sections of insulation should be removed, particularly where moisture might accumulate, to gain a general Ideaof whether external corrosion Is occurring.Unless readily visible, leaks are best found by pressure or vacuum testing the vessel. If there are visual or otherindications that a leak comes through a crack, more thorough methods of examination should be employed.In welded vessels, cracks are most commonly found at nozzle connections, in welded seams, and at bracket andsupport welds. In riveted vessels, the most common location is at metal ligaments between the rivets. Usually, closevisual Inspection with some picking or scrapping will disclose most cracks. When cracldng Is suspected in an area,the entire area should be cieaned by an appropriate method such as wire brushing, high-pressure water blasting, orabrasive-grtt blasting to facilitate Inspection. If visual Inspection is not sufficient (often the case In the detection ofamine and deaerator cracking), wet or dry MT, angle beam UT, PT, or acoustic emission analysis may be used tolocate and provide additional information on the structural significance of cracks or other discontinuities. The wetfluorescent magnetic particle technique (WFMPT) analysis is more sensitive than dry MT techniques.Buckles and bulges will normally be quite evident Small distortions can be found and measured by placing astraightedge against the shell of the vessel. While some distortion is normal, determining the cause of distortion isvery important. Causes of distortion such as Intemal vapor explosions or excesslve Internal corrosion will bedisclosed by the intemal inspection. Settlement, earthquakes, extensive distortion in connected piping, and othersources can often be determined by external inspection. The extent of bulging or buckling can be determined bymeasuring the changes In circumferences or by making profiles of the vessel wall. Profiles are made by takingmeasurements from a line parallel to the vessel wall (see Figure 15). A surveyors transit or a 180° optical plummetmay also be used.Hot spots that have developed on the shell or heads of vessels that are Intemally insulated should be inspected atfrequent Intervals while the vessel Is in service. Evidence of bulging should be noted and recorded. A check of theskin temperature of the metal In the hot-spot area can be made by using a portable thermocouple, infraredequipment, or temperature-indicating crayons or special paints. Infrared Imaging cameras are especially effective in
  • 40. 32 API RECOMMENDED PRAcnce 572 bracket attached to vessel ~ &.J-- -- - l - - - --l measurements taken al small equal Intervals v essel wall may be mar1<ed al equal intervals for convenience. vessel thin wire stretched taut between brackets and ~ parallel to vesselwaJl ! saw slot In bracket for wire bracket ~ Detail of Brackets Figure 1>-Method of Obtaining Veasel Profile Measurements
  • 41. INSPECTION PRACTICES FOR PRESSURE Vessas 33identifying and mapping local hot spots on in-service equipment A complete dimensional check in the hot-spot areashould be made when the vessel Is shut down. Using replication techniques or taking a material sample (a boat orother sample) should be considered if carbon steel temperatures were In the range of 750 of to 1000 of (399 °C to538 0C) for an extended period of time. Depending on operating oonditions and alloy (or if hydrogen attack ispossible), or if temperatures in the creep range are suspected, an experienced metallurgist or engineer should beoonsulted.The extemal surfaces should be checked for laminations and mechanical damage. Laminations that oome to thesurface can be detected by Yisuallnspection. Mechanical damage such as gouges and dents should be Inspected.The depth and extent of any surface gouge should be measured when the gouge seems large enough to affect thestrength of the vessel. All gouges should be reported.Usually, a certain amount of extemal auxiliary equipment Is attached to a pressure vessel. This equipment indudesitems such as the following:a) drain lines and other connected piping (see API 574);b) gauges for liquid level, pressure, and temperature and other instruments;c) safety and relief valves (see API 576);d) extemal water sprays and other fire-fighting equipment;e) instrument or utility stations;f) structural steel for platforms, supports, and lifting lugs.9.4 Intemallnspection9.4.1 GeneralAll necessary inspection equipment (Including tools, ladders, and lights) should be assembled in advance to minimizedowntime for the Vessel. Austenitic stainless steels are particularly susceptible to polythlonic stress corrosion cracking(PSCC) and chloride oorroslon. Local oonditions and materials should be assessed to determine satisfactoryprotection measures required during downtime. Not allintemal Inspections have to be carried out from the Inside ofthe vessel. Techniques are available to Inspect aspects of the vessel nonIntrusively using acoustic emission,magnetic scanning and AUT systems. If flaw mechanisms are well~efined, the techniques may frequenUy be appliedfrom the outside of the vessel, while the plant is In service. This on-stream Information can be used to extend therunning time of the plant or as a planning tool for Mure outages. A risk-based assessment should be used todetermine when extensions to the run time can be allowed and to define the additional volumetric Inspection appliedfrom the outside.9.4.2 Surface PreparationThe degree of surface preparation needed for intemal inspection will vary with several factors. Foremost amo,ng thesefactors are the following:a) the type of deterioratlon expected,b) the location of any deterioration.Usually, the deanliness required by the vessel operators will be sufficient for inspection purposes. This would entailthe usual cleaning methods of washing with hot water, steaming. using solvents, and ordinary scraping. Where bettercleaning is needed, the inspectors hand tools will sometimes be adequate.
  • 42. 34 API REcoMMENDED PRACTIce 512The cleaning methods mentioned should be supplemented by power wire brushing, abrasive-grit blasting, grinding,high-pressure water blasting [e.g. 8000 to 12,000 Ibflln.2 (55.2 MPa to 82.7 MPa)] or power chipping when warrantedby circumstances. These extra cleaning methods are necessary when stress corrosion cracking, wet sulfide cracking.hydrogen attack. or other metallurgical forms of degradation are suspected. Extensive cracking. deep pittlng, andextensive weld deterioration require thorough cleaning over wide areas. If the entire Inside of the vessel is notaccessible from one opening, the procedures discussed in 9.4.3 should be followed at each access opening.9.4.3 Preliminary VJsuallnspectJonIf this is not the first inspection. the Initial step In preparation for an Internal inspection Is to review the previous recordsof the vessel to be inspected.When possible, a preliminary general visual inspection is the next step. The type of corrosion (pitted or uniform), itslocation, and any other obvious data should be established. In refinery process vessels, certain areas corrode muchmore rapidly than others do. This unevenness of corrosion is covered in detail in API 571. Data collected for vesselsin similar service will aid in locating and analyzing corrosion in the vessel being inspected.The bottom head and shell of fractionators processing high-sulfur crude oils are susceptible to sulfide corrosion. Thiscorrosion will usually be most Intense around the inlet lines. In general, high-temperature sulfur corrosion tends to beuniform compared to more localized corrosion from high naphthenic adds.The upper shell and the top head of the fractionation and distillation towers are sometimes subject to chloride attack.The liquid level lines at trays In towers and in the bottom of overhead accumulators are points of concentrated attack..Corrosion in the form of grooving will often be found at these locations.Fractionation and distillation towers, knock out drums, reflux accumulatOffi, exchanger shells, and other relatedvessels that are subject to wet hydrogen sulfide (H~) or cyanide environments are susceptible to cracks in theirwelds and weld heat~affected zones.In vessels where sludge may settle out, concentration cell corrosion sometimes occurs. The areas contacted by thesludge are most susceptible to corrosion. This corrosion may be rapid if the sludge contains acidic components.If steam is injected Into a vessel. corrosion and erosion may occur at places directly opposite the steam Inlet Bottomheads and pockets that can collect condensate are also likely to be corroded.Often, a reboiler will be used at the bottom of a tower to maintain a desired temperature. The point where the hotprocess stream returns to the tower may be noticeably corroded. This is especially true if the process stream containscomponents that may decompose with heat and form acid compounds. as In alkylation units, solvent extractionprocesses, and soap or detergent plants.Because of metallurgical changes caused by the heat of welding at welded seams and adjacent areas, corrosionoften accelerates there. Most of the cracks that occur in pressure vessels will be found in these areas. Areas of thevessel opposite inlet nozzles maybe subject to impingement attack or erosion.Vessels In water service, such as exchangers or coolers, are subjected to maximum corrosion where the watertemperatures are highest. Thus, when water Is In the tubes of an exchanger. the outlet side of the channel will be themost corroded. Figure 16 shows pitting in a channel.In any type of vessel, corrosion may occur where dissImilar metals are in close contact. The less noble of the twometals will corrode. Carbon steel exchanger channels gasket surfaces near brass tubesheets will often corrode at ahigher rate than it would elsewhere.
  • 43. INSPECTION PRAC11CES FOR PRESSURE VEssas 35 Figure 16-Corroslon In ChannelCracks In vessels are most likely to occur Where there are sharp changes In shape or size or near welded seams,especially If a high stress is applied. Nozzles, exchanger channel and shell-cover flanges, baffles in exchangerchannels, floating tube-sheet covers, and the like should be checked for crncks.When materials flow at high velocities in exchanger units, an accelerated attack can be expected if changes are madeIn the direction of flow. Tube inlets in tubular units, retum bends in double-pipe units, and condenser box or air coolercoils are likely to be attacked.Shells of vessels adjacent to Inlet Impingement plates are susceptible to erosion. this is especially true wnenvelocities are hIgh.The preliminary Inspection of the vessel Interior may indicate that additional cleaning is needed. If large areas aredeeply corroded, abrasive blasting may be necessary. Normally, it is not necessary to remove light coatings of rust onmore than a spot basis with a wire brush.The preliminary inspection may reveal unsafe conditions. such as those due to loose internals that may fall or due tobadly corroded or broken lntemalladders or platfonns. These parts must be repaired or removed Immediately beforea more detailed inspection may proceed.
  • 44. 36 API RECOMNENOEO PRACTICE 5729.4.4 Inspection of DegradatfonInspectors should understand the function of the vessel, Internals, and each nozzle to assess findings. If access tothe inside of the vessel Is available. detailed Inspection should start at one end of the vessel and wor1< toward theother end. A systematic procedure should be followed to avoid overlooking obsrure but important items. Certain keyareas such as Internal attachment welds, seam welds and tray supports can be Inspected from the ou1slde of thevessel using manual and AUTs. This may be applied if acoess to the inside of the vessel is not available.All areas of the vessel should be Inspected for corrosion, erosion, hydrogen blistering, deformation, cracking. andlaminations. A careful reoord should be made of the types and locations of all deterioration found.9.4.4.1 Thinning and PittingThickness measurements should be taken at those locations that show the most deterioration. When deteriorationappears to be widespread, enough readings should be taken to assure an accurat. determination of the remaining ethickness. When deterioration is slight, one thickness measurement on each head and each shell course may besufficient on small vessels, but more measurements should be taken on large vessels. UT instruments can be usedto obtain the necessary measurements. Other special methods of measuring wall thickness are discussed in 9.1.Pitting corrosion can usually be found by scratching suspected areas with a pointed scraper. When extensive anddeep pitting or grooving Is found. and depth measurements are wanted, the areas may have to be abrasive blasted.The depths of pits or grooves can be measured with a depth gauge, a pit gauge, or (In the case of large pits or widegrooves) with a straightedge and a steel rule. A depth can be estimated by extending the lead of a mechanical pencilas a depth gauge. Depressions or pockets that can hold sludge or water should be scraped clean and carefullyexamined for evidence of corrosion.A hammer can be used to inspect for thin areas of vessel shells, nozzles, and parts. Naturally, experience Is neededbefore the hammer can be used effectively. When striking the shell, nozzle, or part, an experienced Inspector canoften find thin spots by listening to the resulting sound and by noting the feel of the hammer as it strikes.9.4.4.2 CrackingA careful Inspection should be made for evidence of cracking. A strong light and a magnifying glass will be helpfulwhen doing this work. visually. If crad<lng Is suspected or any evidence of cracking is found using visual means, amore thorough method of investigation must be used. When cracks are suspected or found. their extent can bechecked with PT or MT (wet or dry) techniques. Angle beam UT Inspection methods provide a volumetric Inspectionof potential flaw areas. To use any of these methods effectively, the suspected areas must be prepared by abrasiveblasting, grinding, or other methods acceptable to the Inspector. Figure 17 shows a crack in a shell weld. The mostsensitive method of locating surface cracking Is the WFMPT method. Other valuable methods are the dry Mr, PT, UT,or radiographic methods.Vessels containing amines (absorbers, accumulators. coalescers. condensers, coolers, contactors, extractors, filtervessels, flash drums, knockoot drums, reactivators, reboilers, reciaimer.>, regenerators, scrubbers, separators,settlers, skimmers, sour gas drums, stills, strippers, surge tanks, treating towers, treated fuel gas drums, etc.) aresubject to cracks In their welds and the heat-affected zones of the welds. WFMPT testing Is a very sensitiveInspection method for detecting surface cracks and discontinuities and is the primary recommended inspectionmethod. See API 945 for more detailed information. Also, ET, alternating current field measurement. and UT methodsare also available for the detection of surface breaking defects; these new techniques have an advantage ofincreased inspection speed. In addition, a number of the methods have a limited depth measuring capability. UTscanning techniques can also be used to scan from the outside surface to avoid entering the vessel.Oeaerators on boilers should have their welds and heat-affected zones checked for possible de aerator cracking.WFMPT testing is the primary recommended Inspection method. Care should be taken in deaning surfaces prior to
  • 45. INSPECTION PRACTIC€S FOR PRESSURE VEssas 37 Figure 17-Crack In Weld Seen by PTWFMPT testing because mechanical deanlng with grinders or wire brushes can hide fine cracks. UT scanningtechniques can also be used to scan from the outside surface to avoid entering the vessel.Supports are almost always welded to the shell. The point of attachment should be examined closely for cracking. Agood light and a scraper will usually be sufficient for this examination.The attachment points of baffles to exchanger channels and heads should also be checked closely for cracks.Usually, visual Inspection with the aid of a light, a magnifying glass, a scraper, and a brush is sufficientlaminations In vessel plates have an appearance similar to cracks, but they run at a slant to the plate surface, whilecracks run at right angles to the surface. If open sufficiently for a thin feeler to be Inserted, the angle of the laminationcan be observed. If a lamination is suspected but not open enough for a feeler to be inserted, heating toapproximately 200 OF (93 °C) with a torch will usually cause the edge of the lamination to lip upward. Manual andscanning UT may be used to trace the lamination.
  • 46. 38 API REcoMMENoeo PRACTlCE 5729.4.4.3 ErosionErosion usually differs In appearance from corrosion. Erosion Is characterized by a smooth, bright appearance,mar1<ed absence of the erosion product, and metal loss, usually confined to a clearty mafi(ed local area. On the otherhand, COIToded areas are not commonly smooth or bright See API 571 for more detailed Information on erosion.The shells of exchangers next to bundle baffles and inlet impingement plates should be checked for erosion.Turbulence near the Impingement plate and Increased velocity around exchanger bundle baffles sometimes causeerosion of the adjacent shell areas. Erosion or corrosion at the baffles of exchangers will often show up as a series ofregularty spaced rings when a flashlight beam is place parallel to the shell surface. Sometimes, a lack of scale wHiIndicate this type of erosion.Erosion occurs not only in exchangers but also in any vessel that has wear plates, baffles, or Impingement plates. Incatalytic reactors and regenerators, the catalyst and air distribution facilities are especially susceptible to erosion andshould be examined ciosely for this type of attack. These areas such as Intemal Impingement plates, attachmentwelds, seam welds and tray supports can be Inspected from the outside of the vessel using manual and AUTs. Thismay be applied if access to the inside of the vessel is not available.9.4.4.4 BlisteringAreas directly above and below the liquid level in vessels with a process containing acidic components may besubject to hydrogen blistering. Blisters are most easily found by visual examination. A flashlight beam directed acrossthe metal surface will sometimes reveal blisters; the shadows created by the blisters can be observed. When manysmall blisters occur, they can often be found by running the fingers over the metal surface. The metal thickness oflarge blisters should be measured so the remaining effective wall thickness can be determined. Usually, this can bedone by using an UT thickness instrument or by drilling a hole at the highest point of the blister and measuring thethickness with a hook scale. If an UT thickness instrument Is used, the blister size must allow a transducer to beplaced on to obtain a UT UTreadlng. When the blister is near a weld, UT readings may be difficult to obtain becauseof the weld surface roughness. Figure 18 through Rgure 20 illustrate hydrogen bHstering. Figure 18-Hydrogen Blistering
  • 47. INSPECTION PRACTICES FOR PRessuRE VESSELS 39 Figure 19--SeIf-vented Hydrogen Blisters Figure 21}-Radlograph of Self-vented Hydrogen Blisters In Carbon SteelBoth the shell and heads of vessels should be inspected for deformation. Normally, the shell is more likely to sufferdeformation than the heads. However, some older vessels have heads fonned with a small knuckle radius, whichmay be seriously deformed. Unless dimensions of head parts, such as crown radius or knuckle radius, are already onrecord, these dimensions should be taken and recorded at the time of the first inspection. If deformation Is suspectedor indicated later, these measurements should be repeated and compared with the original values.9.4.4.5 DefonnationExcessive deformation of the shell by either bulging or collapsing can usually be detected visually from the outside ofthe vessel. unless It is extemally insulated. Out-of-roundness or bulging may be evaluated by measuling the Insidediameter of the vessel at the cross section of maximum deformation and comparing it with the Inside diameter at thecross section of minimum deformation.
  • 48. 40 API RECOMMEHOEO PRAcnce 572Exchanger shells should be checked closely for any deformation . partlcular1y after repairs or alterations. Out-of-roundness caused by welding can make installation of wbe bundles extremely difficult, and extractions after difficultinstallations can be nearty impossible.If the out-of-roundness occtIrs at Intervals throughout the length of the vessel, measurements should be taken ateach interval to compare with the original shell dimensions Of measurements. In thIs case, the center wire method orthe plumb line (or optical plummet) method can be used to measure the defonnation. In the center wire method. asteel wire is positioned on the centerline of the vessel and stretched taut. If no manways or nozzles exist In thecenters of the heads, a plumb line or an optical plummet may be used. When the deformation is restricted to one sideof the vessel, It may be more convenient to measure offsets from a wire stretched parallel and adjacent to the wallrather than along the vessel axis (as in the method shawn in Figure 26 with the brackets and wire inside the shellinstead of outside). in horizontal vessels. some special method may have to be required to hold the wire in position.The wire furnishes a reference line from which to measure the deformation. Sufficient measurements can be taken atintervals arong the wire to permit drawing a prome view of the vessel wall. Local deformation can sometimes bemeasured by placing a straightedge parallel to the vessel axis against the vessel wall and using a steel ruler tomeasure the extent of bulging . One method for locatlng suspected deformation Is to direct a flashlight beam parallel tothe surface. Shadows will appear in depressions and on the unlighted side of internal bulges.9.4.5 Inspection of Components9.4.5.1 GeneralIn most instances, Inspection of intemal equipment should be made when adjacent shell areas are Inspected. Thismay be very difficult in some large vessels .The supports for trays, baffles, screens, grids, piping, Internal stiffeners, and other internal equipment should beinspected carefully. Most of this Inspection will be visual. Light tapping with a hammer can be used as a check forsoundness. If there appears to be any metal loss, the thickness of the support should be measured and checkedagainst the original thickness. Transfer or direct-reading calipers, micrometers, or UT thickness Instruments can beused for these measurements.9.4.5.2 TraysThe general condition of trays and related equipment should be noted. Shell and tray surfaces In contact with traypacking should be examined for possible loss of metal by corrosion. The condition of trays and related equipment willnot affect the strength of the vessel but will affect the efficiency and continuity of operation. Normally. only visualinspection will be required for such equipment. If measurements are required. they can be obtained with calipers orUT Instruments.The performance of some trays Is dependent upon the amount of leakage. If tray leakage is appreciable. thenefflclency Is lost, and the withdrawal of side streams from the tower or vessel may be almost Impossible. Therefore,tray leakage should be minimized. The process design will usually specify the amount of leakage that can betolerated. Tests for leakage may be made by filling the tray with water to the height of the overflow weir and observingthe time it takes for all of the water to leak through the gasket surfaces of the tray. Excessive leaks can be located byobservfng the underside of the tray during the test If difficulty is encountered in determining the location of leaks, plugthe weep or drain holes in the low sections of the tray prior to the test. Because of their design, ballast- and valve-typetrays cannot be checked for leakage.9.4.5.3 Internal ComponentsAll intemal piping should be thoroughly Inspected vlsually, especially at threaded connections. Hammer testing of thepipe by an experienced Inspector is a quick way to determine its condition . The sound, the feel, and any indentationwill Incllcate any thinness or cracking in the pipe. If excessive meta/loss Is Indicated, the remaining wall thickness maybe measured.The internals of vessels such as catalytic readors are very complicated. Figure 21 is an illustration of this internalequipment Inspection of this equipment may be mostly visual, although some scraping, picking, and tapping may be
  • 49. IKSPECTlOO PRAcnccs FOR PRESSURE VESSElS 41 Figure 21-Carafytlc.f8actor Intemals-Cyc:lonesnecessary. Thickness measurements and corrosion rate calculations may be required in some areas, althoughoperating efficiency rather than strength is the most Important consideration.9.4.5.4 NozzlesNozzles connected to the vessel should be visually examined for internal corrosIon. The wall thickness of nozzles canbest be obtained with UT instruments. In some cases, a record of Inside diameter measurements of nozzles may bedesirable. These measurements can be made with a pair of intemal, spring-type transfer calipers or with directreading, sclssors--type, Inside diameter calipers. When the piping Is disconnected, actual nozzle wall thickness can beobtained using a caliper around the flange. In this way, any eccentric corrosion of the nozzle will be revealed.Nozzles, especially pressure safety valve (PSV) Inlets, should be inspected for deposits.9 .... 5.5 liningsHeavy-wall hydroprocessing reactors operate at high pressure and have special inspection reqUirements. Usually,these vessels are constructed from e-1J2 Mo, 1 1;4 Cr-1J2 Mo, or 2 1;4 Cr-1 Mo steels. Experience has Identified thefollowing major areas of concern with respect to crack damage:a) attachment weId(s) of an internal component,b) main weld seams,c) gasket grooves (ring joint-flanges),d) nozzle attachment welds.Secondary areas of concern include base metal and overiay disbondlng and Integrity of the weld overiay. VTinspection perfonned from the outside of the vessel can be used to locate and measure the extent of dlsbood andcracked areas. If UT scanning techniques are used the defect areas can be recorded and assessed simultaneously.
  • 50. 42 API RECOMMENDED PRAC11CE 572Welded seams in vessel shells should be closely checked when the service is amine, wet H2S, caustic, ammonia,cyclic, high temperature, or other services that may promote cracking. In addition, welds in vessels constructed ofhigh-strength steels [(above 70,000 /bflln.2 tensile (483 MPa)] or coarse grain steels should be checked. Welds invessels constructed of the low-dlrome materials and In high-temperature service should receive careful inspection. Inall cases, cracks may occtJr in or adjacent to the welded seams. The WFMPT is considered the best means forlocaUng surface Indications. ET, alternating current field measurement., and UT methods are also available for thedetection of surface breaking defects; these new techniques have an advantage of Increased Impaction speed. Inaddition, a number of the methods have a limited depth measuring capablllty.9.4.6 Inspection of NozzlesWhen accessible, nozzles should be Intemally inspected for corrosion, cracking, and distortion. The Inspection can bevisual with a scraper and a flashlightExposed gasket surfaces should be checked for scoring and corrosion. The surfaces should be cleaned thoroughlyand carefully for a good visual inspection.The grooves of ring-joint flanges should be checked for cracks due to excessive bolt tightening. Also, stainless steelring jOint grooves should be checked for stress corrosion cracking. NDE testing methods such as MT (wet or dry), PT,or UT shear-wave techniques may be used to supplement visual examination.Lap joint flanges Of slip flanges such as Van Stone flanges should be checked for corrosion between the flange andthe pipe. The check can be made from inside the pipe by spada/ probes and UT thlck.ness-measuring devices. Theflanges can also be moved for Inspection after bolt removal, and the nozzle thickness checked with calipers.Internal diameter measurements may be taken with Inside calipers to monitor corrosion; the pipe does not have to beremoved fOfthis measurement, but the vessel must be open and approved for Intemal Inspection.9.4.7 Inspection of Metallic UnlngsMany vessels are provided wi1h metallic linings. The primary purpose of these linings is to protect the vessels from theeffects of corrosion or erosion. The most important conditions to check for when examining linings are the follov.ring:a) that there Is no corrosIon,b) that the linings are propet1y installed,c) that no holes or cracks exist.Special attention should be given to the I/oIelds at nozzles or other attachments.A careful visual examination is usually all that is required when checking a lining for corrosion. Ught hammer taps willoften disclose loose lining or heavily corroded sections. If corrosion has occurred, it may be necessary to obtainmeasurements of the remaining thickness. Unless the surface of the lining is relatively rough, these measurementscan be made with an UT thickness instrument Another method of checking the thIckness of the lining is to remove asmall section and check it with calipers. This method provides an opportunity to inspect the surface of the shell behIndthe lining. The application of either manual or scanning UT methods from the outside surface of the vessel can beused to detect thinning of the base material.Small 1 In. x 2 in. (2.5 em x 5.0 em) tabs of lining that form a right angle wi1h one leg extending into the vessel may bewelded on the lining. The thickness of the protruding leg should be measured at each inspection. Since both sides ofthe tab are exposed to corrosive action, the loss in thickness would be twice that of the shell lining where only oneside is exposed. This permits a fair1y accurate check of any general corrosion of the lining. Figure 22 Illustrates thislining inspection method.
  • 51. IItSPECTlON PRACTlCES FOR PRESSURE VESSElS 43 Key 1 corrosion lab 2 lining 3 inside surface 4 vessel wall Figure 22-COITOSion Tab Method of Detennlnlng Metal loss on Vessel UnlngsCracks in metallic linings sometimes can be located by visual Inspection. If cracking is suspected, the visualInspection should be augmented by using PT or other methods suitable for detection of surface cracks. A crackedsection of a liner or a loose liner may make a tinny sound when tapped with a hammer. With the exception of thestraight chrome steels, most of the materials used as linings are primarily nonmagnetic. MT Inspection cannot beused on austenitlc materials.If cracks are found In a clad liner or weld overlaid liner, the cracks should be investigated to ensure that they do notextend beyond the cladding and Into the base metal or parent metal.Bulges and buckling often occur in metallic linings and usually indicate that cracks or leaks exist In the bulged sectionof the lining or that pin holes exist in the adjacent welds. The bulges are formed either by the expansion or buildup ofa material that seeps behind the lining during operation or by differential thermal expansion. If material seeps behindthe lining during operation and cannot escape when the vessel pressure Is reduced for a shutdown, the lining maybulge. Caution should be exercised when dealing with process material that Is trapped behind strip lining or cladding.Releasing this malerial Into a confined space may create a hazardous environmenl In vacuum service, the liningmight bulge in service and depress when the vessel is shut down. This condition may actually wrinkle the lining.When bulges or wrinkling become excessive, it may be necessary to inspect the lining for cracks or pin holes. Thesecracks or pin holes may need to be repaired or the lining may need to be replaced. Figure 23 illustrates thedeterioration of strip-welded linings.NOTE Corrosion tab of same material and thickness as lining Is Installed as shown when vessel is lined.Where a lining leaks, It should be determined whether or not corrosion has taken place behind the linIng. In somecases, UT testing from the outside may be used. Removal of representative lining sections to pellTlit visualexamination of the vessel wall is always preferred if feasible. An AUT can provide the most reliable NDE of defectsdetected In the lining or base material. Although these techniques can be applied at ambient or elevated vesseltemperatures, defect sizing Is most accurate at or near ambient temperatures.Many reactors In hydrogen service, such as hydrocrackers and hydrotreaters, use complete weld overlay that usesstabilized austenitic stainless steel welding rods or wire as liners instead of plug- or strip-welded or dad plate.Disbanding from the parent metal can be a problem wtth this type of lining. UT tesUng, visual checking for bulges, andlight tapping with a hammer can reveal this problem.
  • 52. 44 API RECOMMENDED PRACTICE 572 Figure 23---StrIp-liner Deterioration9.4.8 Inspection of Nonmetallic LiningsThere are various kinds of nonmetallic linings: glass, plastic, rubber, ceramics, concrete, refractory, and carbon blockor brick linings. These materials are used most often for corrosion resistance. Some forms of refractory concrete areused as an internal insulation to keep down the shell temperatures of vessels operating at high temperatures.Refractory tile is also used for insulation.The effectiveness of these linings in lessening corrosion is appreciably reduced by breaks in the film or coatings. Forthe most part, inspection will consist of a visual examination for discontinuities in the coatings. These breaks aresometimes caned holidays. Bulging. blistering, and chipping are all Indications that openings exist In the lining. Thespar1< tester method of Inspection for leaks In paInt, glass, plastic, and rubber linings Is quite thorough. A high-voltage,low-current, brush-type electrode Is passed over the nonconductive lining. The other end of the circuit Is attached tothe shell of the vessel. An electric arc will fOJTn between the brush electrode and the vessel shell through any holes Inthe lining. This method cannot be used for concrete, brick, tile, or refractory linings.Caution-The voltage used In this Inspection method should not exceed the dielectric strength of thecoating. Damage to the lining may Nault.Considerable care should be exerdsed when working Inside vessels lined with glass, rubber, plastic sheets, or paintThese coatings are highly susceptible to mechanical damage. Glass lined vessels are especially susceptible todamage and they are costly and difficult to repair.Concrete and refractory linings may spall and crack in service. Inspection of such linings should be mostly visual.Mechanical damage, such as spalllng and large cracks, can readily be seen. Figure 24 Illustrates the deterioration ofa refractory-ti/e lining. Minor cracks and areas of porosity are more difficult to find. Light scraping will sometimesreveal such conditions. Bulging can be located visually and Is usually accompanied by crackIng. In most cases, Ifcorrosion occurs behind a concrete lining, the lining will lose its bond with the steel. The sound and feel of lighthammer tapping will usually make such looseness evident. If corrosion behind a lining Is suspected, small sections ofthe lining may be removed . This permits an inspection of the shell and a cross-sectional examination of the lining.
  • 53. INSPEcnON PRACilCES FOR PRESSURE VEssas 45 Figure 24--Oetertorated Refractory..tlle LiningSome refractory-tile linings are hung with a blanket of ceramic fiber or other insulation between the shell and the tile.Broken or miSSing tiles create lanes for the channeling of any fluid that gets behind the fining. This results in thewashIng away of some of the Insulation. Inspectlon of tile linings should Include a visual Inspection of the Insulation Inthe vicinity of broken or missing tile. This may be done by removing enough tiles to determine the extent of thedamaged areas.In all cases where bare metal has been exposed because of lining failures, a visual inspection should be made of theexposed metal. If corrosion has taken place, the remaining wall thickness should be measured. UT instruments arebest suited for this measurement.Durtng operation, intemally Insulated vessels are sometimes subject to severe corrosion due to condensation on theshell behind the insulation. If the shell-metal temperatures are near the calculated dew point of the process stream,shell corrosion should be suspected and the shell should be checked. A frequently used oorrective measure is toreduce the internal Insulation or to add extra extemal Insulation. Precautions should be taken to assure that designmetal temperatures are not exceeded when these measures are used.9 .... 9 Corrosion Beneath Unlng8 and DepositsIf external or internal coatings, refractory linings, and corrosion-resistant linings are In good condition , and there is noreason to suspect a detertorated condition behind them, it is usually not necessary to remove them for inspection ofthe vessel.
  • 54. 46 API RECOMMENDED PAACTlCE 572The effectiveness of corrosion-resistant linings is greatly reduced by breaks or holes in the lining. The linings shouldbe Inspected for separation, breaks, holes, and blisters. If any of these conditions are noted, it may be necessary toremove portions of the internal lining to investigate the effectiveness of the lining and the condition of the metalbeneath the lining. Alternatively, UT scanning examination from the extemal surface can be used on certain types oflinings, such as explosion bonded dad or WId overlaid dad, to measure wall thickness and to detect separation,holes, and blisters.RefractOlY linings may spall or crack in service with or without causing any significant problems. Corroslon beneathrefractory linings can result In separation and bulging of the refractory. If bulging or separation of the refractory liningIs detected, then portions of the refractory may be removed to permit inspection of the metal beneath the refractory.Alternatively, UT thickness scanning may be made from the external metal surface. Thermography may also beuseful in detecting refractory or lining deterioratJon.Where operating deposits, such as coke, are present on a vessel surface, it is particularfy important to determinewhether such deposits have active corrosion beneath them. This may require a thorough Inspection in selectedareas. Larger vessels should have the deposits removed In selected critical areas for spot examination. Smallervessels may require that NDE methods, such as radiography or external UT scanning examination be perfonned inselected areas.9.5 Special Methods of Detecting Mechanical DamageVisual examination will reveal most mechanical damage (dents, gouges, and Clacks). MT (wet or dry) and PTmethods may be useful and have been discussed in preceding text. Other methods, such as radiography, anglebeam UT, etching, and sample removal, are available and may be used when conditions warrant. Also, ET, alternatingcurrent field measurement. and UT methods are available for the detection of surface breaking defects. These newtechniques have an advantage of Increased Inspection speed.Radiography and angle beam UT are used to analyze defects, usually in welded seams, that are not visible on thesurface of the metal.Etching of small areas may sometimes be used to find small surface cracks. First, the surface must be abra sive-gritblasted clean. Etching solution, typically an add, is then used to wash the suspect area. Because of the nature of theresulting reaction, any cracks will stand out in contrast to the surrounding area.Sample removal can be used to spot-<:heck welds and to investigate cracks, laminations, and other flaws. Small metalsamples from the affected area are removed with a trepan or weld probe tools. The sample Is then analyzed under amicroscope or with an ordinary magnifying glass. If they can be adequately cleaned, the filings obtained during thecutting operation may be used in making a chemical analysis of the metal. The hole left in the vessel wall by sampleremoval must be evaluated by Fitness~For-service assessments and repaired if they may affect pressure equipmentintegrity. The decision to remove samples should be made by someone who knows how to analyze the problemsrelated to repair of the sample holes.9.6 Metallurgical Changes and n-situ Analysis of MetalsIn-situ metallography can be used to detect metallurgical changes with portable polishing equipment and using replicatransfer techniques. Hardness, chemical spot, and magnetic tests are three methods of detecting metallurgicalchanges.Portable hardness testers can be used to detect faulty heat-treating, carburization, nltriding, decarburization, andother processes that cause changes In hardness.Local chemical tests may be used to detect the installation of materials other than those specified . Chemicals such asnitric acid in varying concentrations are used. A spot is cleaned on the metal surface and a drop of a chemical isplaced on the surface. An experienced observer can observe the reactions to the acid of the metal being tested and
  • 55. INSPECTlON PRACncEs FOR PRESSURe VEssas 47Identify the metal. ET, X-ray fluorescence, radiation. and portable light emission spectroscope instruments are alsoused for material Identification.Because nonnalty nonmagnetic steel usually becomes magnetic when carburized. carburlzat/on of austeniticstainless steel can sometimes be detected by a magnet9.1 Testing9.7.1 HammerTestlngIn hammer testing. an Inspectors hammer Is used to supplement visual Inspectlon. The hammer Is used to do thefollowing Jobs:a) to locate thin sections in vessel walls. heads. etc.;b) to check tightness of rivets, bolts, brackets. etc.:c) to check for cracks in metallic linings;d} to check for lack of bond in concrete or refractory linings;e) to remove scale accumulations for spot Inspection.The hammer is used for these jobs by lightly striking or tapping the object being inspected and observing the sound.feel. and indentation resulting from the blow. The proper striking force to be used for the various jobs can be learnedonly through experience. Hammer testing is used much less today than previously. It is not recommended to hammertest objects under pressure. Also. piping upstream of a catalyst bed should not be hammered. as hammering coulddislodge scale or debris and cause plugging.9.7.2 Pressure and Vacuum TestingWhen a pressure vessel Is fabricated. it Is tested for Integrtty and tightness In accordance with the standard orconstruction code to which it was built. (In addition to Integrity and tightness, the pressure test can also result inbeneficial stress redistribution at defects.) These methods of testing may also be used to subsequently inspect forleaks and to check repair work. When major repair work such as replacing a head. a large nozzle. or a section of theshell plate Is performed, the vessel should be tested as if It were just installed. In certain circumstances. the applicableconstruction code requirements for Inspection of vessels in service also require periodic pressure testing. eventhough no repair work has been necessary. For code rules conceming tests of vessels in service. see API 51 0. TheASME BPVC. although a new vessel fabrication code, may be followed In principle in many cases.A large vessel and its structural supports may not necessarily be deSigned to support the weight of the vessel when itis filled wtth water. Whether it can support this weight should be determined before a hydrostatic test is made. If thevessel or its supports are inadequate for a hydrostatic test, then a pneumatic test may be considered. There Is a riskof explosion due to the release of highly stored energy if the pressure vessel fails during a pneumatic testing. this riskshould be considered and the appropriate precautions should be taken to minimize the potential for fallure,particularty brittle failure during pneumatic testing at lower temperatures.Pressure testing consists of filling a vessel with liquid or gas and building up an Internal pressure to a desired level.The pressure and procedures used should be in accordance with the applicable construction code requirementsconsistent with the existing thickness of the vessel and the appropriate joint efficiencies. (As noted In preceding text.sometimes the rules for Inspectjon in service also require periodic pressure testing. even though no repair worl< hasbeen necessary.) When pressure vessels form a component part of an operating unit, the entire unit Is sometimespressure tested. Water or 011 Is used as a testing medium and the charge pumps of the unit are used to provide thetest pressure. While the vessel or vessels are under pressure. the external surfaces are given a thorough visualexamination for leaks and signs of deformation.
  • 56. 48 API REc~NOED PRAC11CE 572In recent years, acoustic emission analysis has been developed for use In conjunction with pressure testing or duringequipment cool-down. When acoustic emission equipment is used on a vessel under pressure in a stressedcondition, II is possible to detennine the overall structural integrity of the vessel. This method can be especially usefulfor vessels of complex design or where the vessel contents cannot be easily removed to permit an Intemallnspection.When testing pneumatically, a UT leak detector or soap solution or both should be used to aid vlsual inspection. Thesoap solution Is brushed over the seams and Joints of the vessel. The vessel is then examined for evidence ofbubbles as an indication of leakage.A UT leak detector may be used to pick up leaks in joints and the like that cannot be reached with a soap solutionwithout scaffolds or similar equipment. Very small leaks may be detected and located with the leak detector.Often, a vessel that operates at a vacuum may be pressure tested. When feasible, pressure testing is the preferredtesting method as leaks from an internal pressure source are more easily located. When pressure testing is not feasible,a vacuum vessel can be tested for leaks with evacuators or vacuum pumps that are Installed in the unit and used tocreate a vacuum. f11tle vacuum can be held for a specified time after closing off the evacuators or vacuum pumps, it islikely that the vessel is free of leaks. If the vacuum cannot be held, leaks are present Hoviever, since this method givesno indication of the locations of leaks, a search, which may be difficult, must then be made to locate the leaks.Consideration should be given to the temperature at which testing Is done. Many of the common steels used infabrication exhibit severe reduction In impact resistance at low temperatures. API 510 recommends thai vesselsconstructed with these steels be tested either at temperatures not less than 30 O (15 °C) above the minimum design Fmetal temperature (MDMT) for vessels that are more than 2 In. (5 em) thick or 10 °F (5 °e) above for vessels thathave a thickness of 2 1 or less. The test temperature shOUld not exceed 120 O (49 O ), unless there Is Information n. F eon the brtttle characteristics of the vessel material to Indicate the acceptability of a lower test temperature or the needfor a higher test temperature (see API 579-1 fASME FF8-1).When conducting hydrostatic or pneumatic pressure tests, it Is a good safety practice for all personnel not connectedwith the test to remain away from the area until the test is completed and the pressure is released. The number ofinspection personnel in the area should be limited to the number necessary to run the test When making pneumaticpressure tests, the recommendations set forth in the ASME BPVC should be followed.9.7.3 Testing ExchangersWhen an exchanger Is removed from service, it is often desirable to apply a lest to either the shell side or the tubeside before dismantling. A leak may be detected by observation at a drain point, such as at a disconnected lowernozzle or an open bleeder. Usually, the test must be run for some time before a small leak wlll show up. If theexchanger leaks, It Is then partially dismantled and the test reapplied. For example, when testing a floating-headexchanger with the pressure in the tubes. removal of the shell cover will reveal the source if the leak Is In the gasket,stay bolts, or tube rolls at the floating head. This test will not normally distinguish between tube roll leaks at thestationary tubesheet and those at penetrated tube walls, as these parts are not visible w11ile the tube bundle Is In theshell. A shell test applied to a floating-head exchanger with the channel cover off will reveal leaking tube rolls at thestationary tubesheet, but will not dearly Identify the source of leakage at floating tubesheet rolls or floating headgasket leaks. In most cases, exchangers that do not use a floating head are so constructed that a shell side testapplied to the partially dismantled exchanger will enable individual detection of leaking tubes and thetr plugging. Also,leaking tube rolls at either end can be detected and rerolled. Exchangers with floating heads do not permit individualdetection of leaking tubes or access to both ends of tube during a shell side test. A test ring is sometimes used forthese exchangers. This is a device that temporarily converts the arrangement of the partially dlsmantted exchangerinto a dual fixed tube-sheet arrangementIn some cases, leak testing Is performed at each downtlme. Tube condition assessment can also be performed usingscanning detection tools. The range of tools available Indudes ET, remote field ET, magnetic flux, laser, and UT testequipment. These technologies can be used to detect erosion, corrosion, pitting. and cracking in tubes. If leakingtubes are found, the tubes are located and plugged, and the bundle is put back In service. This procedure should be
  • 57. PAAcnc£s FOR PRESSURE VESSELS " INsPECTIONrepeated until no new leaks are discovered: several repetitions may be required. If the number of tubes pluggedinterferes with the effident use of the exchanger, the bundle should be retubed. When leakage is enoountered for thefist time in a given servk:e, Inspection may be performed to determine the nature of the deterioration. After historicalrecords have been built up, inspection is performed onty when the number of plugged tubes indicates that thereplacement point may be approaching. When a decision Is made to retube, inspection is employed to determinewhich parts can be salvaged and reused and which require replacement.It is customary to test an exchanger at assembly. Where retubing has been performed, a test may be applied to thepertialy assembled exchanger to detect roll leaks Individually. In any case, a final test 00 both the sheg and tube sidesis normally applied to the asserntHed exchanger.frequently, a bundle will be tested while it is out of the shell. In this case, the channel and floating tube-sheet coversare left In place. This method makes observation for leaks easier but necessitates a separate shelt test.When any of the parts are under test pressure, the external surfaces. rolled joints, and gasketed joints are given athorough visual examination. Leaks and distortion of parts may be found by Pf8SSlK8 testing.Special equipment is available for testing exchanger tubes individually. All example of this equipment is shown InFlgure 25. Step 1 Step 2 Figura 2S-Steps In Using Special equipment to Te.t Individual Tubes
  • 58. 50 API RECOMMENDED PRACTlCE 572The pre ssures to be used when tesUng will depend on the operating and design pressures of the unit. Thesepressures should be determined locally in accordance with individual practice or jurisdictional requirements. Beforeapplying pressure to the shell side only of an exchanger, the inspector should be sure that tubes of the bundle are ofsufficient wall thickness to withstand the extemal pressure. In addition, the channel side test pressure and the shellside test pressure should be checked against one another and care should be laken that one side or the other of theexchanger Is not excessively pressured when testing. Particular care should be taken with any high-pressureexchangers where the tubesheets were designed on the basis of differential pressure vs the absolute MAWP of theeach side.When water is used to conduct a pressure test, care should be laken to remove all water from the equipment. Whenwater cannot be completely removed, it may be necessary to add chemical corrosion inhibitors to prevent thepotential for microbiological corrosion while the equipment is out of service.In some cases it may be preferred or desired to leak test the shell and tube exchanger while it is in service. Methodsfor conducting this testing include injection of a gas or liquid tracer material on the higher pressure side of theexchanger stream. If cooling water is the lower pressure stream, it may be possible to assess the hydrocarboncontent of the water upstream and downstream from the exchanger.10 Condition Assessment and Repair10.1 GeneralOne of !he primary focuses of the pressure vessel inspection is the establishment of a pressure vessels ability tosafely continue operation. There are a number of steps involved in performing a condition assessment, each requiringdifferent data, tools, and degrees of expertise. Condition assessment should be a formal part of every inspectlon, andthe determination of acceptable vessel condition should be formally documerrted. The condition will generally bedefined as: 1) "like new" condition, not requiring any additional actions before the next scheduled inspection; 2) requiring minor repairs such as repainting, cleaning, or minor surface work; 3) requiring major repair or replacement of all or a section of the vessel.10.1 .1 Derating and Fitness-For-ServlceThe vessel may be of solid structural integrity, but may nol meet the construction code requirements for the pressureand temperature of its current rating . Derating or Fitness-For-Service should be considered.10.2 VisuallnspectionA visual inspection , comparing design parameters and original conditions (or conditions at the time of the last formalassessment) of the pressure vessel to current conditions, is the most basic form of condition assessment. TheInspector should evaluate tf the vessel meets the anginal construction parameters by Inspecting the condition of thevessel walls, welds, intemals, supporting equipment, etc. If the inspector determines the vessel to meet the onginalspecifications, the vessel may be identified to be in satisfactory condition. However, any degradation, damage, oro!her potential issues should be noted.In cases where an inspedor locates degradation in a pressure vessel, care must be taken to ensure that thisdegradation either: 1) does not affect the ability of the vessel to continue safe operation, 2) Is removed by repair or replacement of the vessel component experiencing the degradation,
  • 59. INSPECTION PRAcnces FOR PRESSURE VESSELS 51 3) that the structural integrity and design parameters of the vessel are maintained or reevaluated to ensure the vessel meets the applicable code of construction.Degradation may be determined to be inconsequential if the effective wall beneath the defect is greater than requiredthickness, and the remaining life is determined to exceed the next scheduled inspection. The inspector shouldconsider both the nature and the ongoing susceptibility of the equipment item to this degradation. It should bedetennlned wheth er the degradation will continue in a consistent or inconsistent manner in order to predict theremaining life. API 571 provides guidelines on degradation mechanisms , causes, etc. In cases where the degradationor defects are severe enough, further evaluation Is required. API 579-1/ASME FFS-1 provides guidelines forevaluating degradation and associated remaining life.10.3 Thickness MeasurementsThickness measurements should be used to confirm thinning rates or lack of thinning when possible. Once thicknessmeasurements are obtained, the following sleps should be followed to assess the vessels condition . 1) Comparison of the current thickness against nominal, original, and required thicknesses may indicate the condition of the vessel. In cases where a corrosion allowance is included in the original or nominal thickness, this may be subtracted to determined an approximate N minimum thickness. n If the measured thickness is less that this then the following should be performed. 2) The required thickness of vessel components may be calculated utilizing the design code of construction (typically ASME BPVC Section VII I). This code should provide the guidelines for detennining the required thickness for the pressure vessel components, and will typically take Into account pressure, temperature, win d loads, seismic loads. and other parameters pertinent to the vessel design. If the measured thickness is less than this required thickness. than the following may be performed. 3) A Fitness-For-Service analysis utilizing API 579-1/ASME FFS-1, for general or local metal loss.10.4 Remaining UfeOnce the vessel condition has been identified as sufficient, the remaining life should be evaluated to ensure thevessel can safely continue operation at least until the next scheduled inspection . API 510, Section 7. includesguidelines for evaluating corrosion rales , remaining life, and maximum allowable working pressure (MAWP).10.5 Methods of RepairAlthough repair and maintenance are not parts of Inspection, repairs thai affect the pressure rating of a vessel andthat require reinspection for safety reasons are of concem.Before any repairs are made to a vessel, the applicable codes and standards under which it Is to be rated should bestudied to assure that the method of repair will not violate appropriate requirements. API 510 sets forth minimumpetroleum and chemical process industry repair requirements and is recognized by several jurisdictions as the propercode for repair or alteration of petroleum or chemical pressure vessels.NOTE Some jurisdictions require that welded repairs and alterations be done by certified organizations that possessappropriate National Board OR" stamp. usually In accordance with NB-23 and acoompaniecl by the completion and filing NationalBoard Fonn R-1 with he jurisdiction. Refer to ASME PCC-2 for repair methods.The defects requiring repair and the repair procedures employed should be recorded in the permanent recordsmaintained for the vessel (see A PI 51 0 for sample repair and alteration record sheets or refer to jurisdictionalrequirements).
  • 60. 52 AP I RecoMMENOED PRACTICE 572A common defect that typically requires repair is cracks. Cracks can be just suriace cracks where grinding out thecrack would not exceed the corrosion allowance or the excess wall of the vessel (greater than T-min). Cracks whichare deeper than the corrosion allowance or for which repairs are not made should be evaluated by an engineer Inaccordance with API 579-1/ASME FFS-1, Part 9.It is Important thaI the source of the problem requiring the repair is determined. Treating the source of the conditioncausing deterioration will, in many cases, prevent future problems.10.5.1 Welding Repairs10.5.1 .1 GeneralRepairs made by welding to the vessel should be inspected: the inspection should include a check for completion andquality. Normally, a visual examination will be sufficient for minor repairs; however, MT and PT methods should beused on major repairs, and if required by the applicable construction code, radiographic or angle beam UTexamination should also be performed. Refer to API 577 for guidance on welding inspection as encountered withfabricatJon and repair of refinery and chemical plant equipment.After repairs are completed, a pressure test should be applied if the API authorized pressure vessel inspectorbelieves that one is necessary. A pressure lest is normally required after an alteration. API 510 provides additionaldetails on pressure test reqUirements.The repair of sample holes left by a trepan or weld probe tool must be closely inspected. The weld quality in suchrepairs is likely to be poor unless carefully controlled. Therefore, the removal of samples for weld inspection should beavoided If possible.Sections of shell plates may be replaced to remove locally deteriorated areas. The joint efficiency of the patch shouldbe equal to or greater than the efficiency of the original joints in the shell.Cracks in vessel walls or heads may be repaired by chipping, by flame. arc, or mechanical gouging, or by grinding thecrack from end to end and then welding. Care should be used in flame and arc gouging, as heat may cause the crackto enlarge or lengthen. If a crack extends completely through the plate, It may be expedient to cut a groove from bothsides of the plate. In any evenl, complete removal of the crack is absolutely essential before welding is begun. MT orPT techniques should be employed to assure removal of the crack. If several cracks occur in anyone plate, it may bewise to replace the entire plate. Repairs of weld cracks should be checked carefully. 1 the remaining metal, after (defect removal, provides adequate strength and corrosion proteclion, the repair may be completed without welding bytapering and blending the edges of the cavity.Scattered pits in pressure vessels are best repaired by welding. As a means of temporary repair, proprietary epoxybase materials are available that can be packed into pits to prevent further corrosion . This material must be capableof resisting the service conditions. In all cases, pits should be well cleaned. preferably by abrasive grit-blasting, beforerepairs are made.NOTE When consldering the use of this method, the inspector must be satisfied that the pits are not large enough or closeenough together to represent a general thinning of the vessel component See the subsection on corrosion and minimum thicknessevaluation in API 510.Repairs of metallic linings require welding . Visual inspection of welding after thorough slag removal will normally besufficient to check weld quality, unless code requirements specify radiographic, PT. MT, or other examination of the weld.
  • 61. INSPECTION PRAcnces FOR PReSSURE VESSElS 5310.6 Repair of Supporting Vessel EquipmentRepair of appurtenances such as platforms, ladders, and stairways will usually consist of replacing excessively womparts. Stairway treads that have been wom smooth can be roughened by placing weld beads on the wom surfaces.Also, proprietary coatings containing a grit-type material are available.11 Records and Reports11 .1 RecordsInspection records are required by API 510, NB-23, and jurisdictions. These records fonn the basis of a scheduledmaintenance program, and are very Important. A complete record file should contain three types of information:a) basic data (I.e. permanent records per API 510).b} field notes,c) the data that accumulates in the continuous file" (I.e. progressive records per API 510).Basic data include the manufacturers drawings, data reports and specifications. design information, and the results ofany material tests and analyses.Field notes consist of notes and measurements recorded on site either on prepared forms (see Annex B) or in aneither written or electronic field notebook. These notes should include in rough form a record of the condition of allparts inspected and the repairs required.The continuous file includes all information on the vessels operating history, descriptions and measurements fromprevious Inspections, corroslon rate tables (If any), and records of repairs and replacements.As indicated earlier, some organizations have developed software for the computerized storage. calculation, andretrieval of inspection data. When the data is kept up-to-<late, these programs are very effective in establishingcorrosion rates, retirement dates, and schedules. The programs permit quick and comprehensive evaluation of allaccumulated inspection data.11.2 ReportsCopies of reports recommending repairs should be sent to appropriate management groups, which would normallyinclude engineering. operat.ng, and maintenance departments. General inspection reports (see Annex B) may be isent to Interested parties. such as the operating, maintenance, and engineering departments. These reports shouldinclude the location of the repairs, metal-thickness measurements, corrosion rates, descriptions of the conditionsfound, allowable operating conditions, estimation of remaining life, reasons for recommended repairs. and the date bywhich the repairs are to be completed. OccaSionally, speciaJ reports covering unusual conditions may be circulated.
  • 62. AnnexA (informative) ExchangersA.1 GeneralExchangers are used to reduce the temperature of one fluid by transferring heat to another fluid without mixing thefluids. Exchangers are called condensers when the temperature of a vapor is reduced to the point where some or allof the vapor becomes liquid by the transfer of heat to another fluid, usually water. When a hot fluid is cooled to a lowerdesired temperature by the transfer of heat to another fluid, usually water, the exchanger is usually referred to as acooler. When air is used to reduce the temperature of a hot liquid to a lower desired temperature, the exchanger isreferred to as an air cooler. Figure A. 11 and Figure A.12 illustrate heat exchanger parts and types.A.2 Shell and Tube-bundle ExchangersA.2.1 GeneralThere are several types of shell and tubErbundle exchangers. Usually, the tubes are attached to the tubesheet byroiling. A properly rolled tube is shown In Figure A.1. The tubes may be rolled and welded or attached by packingglands. The physical characteristics of the fluids such as the temperature determine the type of fluid used for apartirular service. A description of some of the types of exchangers commonly used and the factors influencing theirselection follow.A.2.2 One Fixed Tubesheet with a Floating HeadOne type of exchanger consists of a cylindrical shell flanged on both ends, a tube bundle with a tubesheet on bothends, a channel, a channel cover, a floating-head cover for one end of the tube bundle, and a shell cover. Thediameter of one tubesheet of the tube bundle is small enough to pass through the cylindrical shell. The diameter ofthe other tubesheet is large enough to bear on a gask. ted surface of one shell flange or may be an integral part of the echannel. The bundle Is inserted in the shell with the large tubesheet against one shell flange. The channel is boiled tothe shell fla nge that holds the tubesheet In place. The channel and floating heads may be divided so that Incomingliquid flows through some of the tubes and returns through other tubes to the channel. The number of divisions andthe number of tube flow passes will vary with the design. The flow through the shell is directed by baffles as desired.Since the floating tube end Is free to move in the shell, this type of construction permits free expansion andcontraction with changes in temperature. This is the type of heat exchanger most commonly used.A.2.3 Two Fixed TubesheetsThe construction details for an exchanger with two fixed tUbesheets are similar to those of the floating tube-sheettype; however, both tubesheets are fixed and the tubes are installed and rolled after the tubesheels are In place. Theshell side cannot be exposed for cleaning. Therefore, it is limited to either clean service or service susceptible tochemical cleaning. Because both tubesheets are Ilxed, the exchanger is limited to small expansion and contractionunless an expansion joint is provided in the shell.A.2.4 One Fixed Tubesheet with U-lubesA U-tube exchanger has one fixed tubesheet with the tubes benl in the form of a long U in place of the floating head.These exchangers have the same freedom of expansion and contraction as the floating-head type. Clean service isusually limited to the tube side because of the difficulty of mechanically cleaning the inside of the U-tubes. Chemicalcleaning, abraslve-grlt blasting, or hydroblasling can be used successfully if care is taken not to allow the tubes tobecome completely plugged. 54
  • 63. INSPECTION PRACTICES FOR PRESSURE VESSELS 55 Figure A.1-Property Rolled TubeA.2.5 Double-tube-sheet ExchangersIn certain services where even minute leakage of one fluid into another cannot be tolerated, double-lube-sheetconstruction of the exchanger is sometimes employed. As the name implies, two tubesheets ara used together withonly a small distance, usually 1 in. or less, between them. The tubes are rolled into both lubesheets. The outertubesheet is attached to the channel. and the Inner tubesheet is fixed to the shell. The purpose of this arrangement isto cause any leakage from the lube roll to bleed off into the space between the two sheets, thus, preventingcontamination of one fluid by the other. this construction is applicable only where there Is no floating lubesheet.Hence, It can be used only with a U-tube exchanger.A.2.6 Reboilers and EvaporatorsThe construction details of rebollers and evaporators are the same as those of any other exchanger with one fixedtubesheet, with the exception that horizontal reboilers have a large vapor space above the tube bundle. They areused 10 produce vapor from liquids by passing a hot fluid through the tubes.A.2.7 Water HeatersWater heaters may be the floating-head type. U-tube type, or the fixed tube-sheet type. They are used to heat waterfor boiler feed or for other purposes by exchanging heat from a hot fluid.
  • 64. 56 API RECOMMENDED PRACnCE 572A.2.S ConstructionExchangers are equipped with baffles or support plates, the type and design of which vary with the service and heatload the exchanger Is meant to handle. Pass partitions are usually installed in the channels and sometimes in thefloating tube-sheet covers to provide mUltiple flow through the tubes. The flow through the shell may be single pass,or longitudinal baffles may be installed to provide multiple passes. The baffling used in the shell will determine thelocation and number of shell nozzles required . Figure A.11 and Figure A.12 show various channel and shell bafflearrangernents. Frequenlly, an impingement baffle plate or rod baffle is located below the shell inlet nozzle to preven1impingement of the incoming fluid on the adjacent tubes.The tubes may be arranged In the tubesheet on either a square or a triangular pitch. When the fluid circulating aroundthe outside of the tubes may coke or form other dirty deposits on the tubes, the square pitch Is generally used. Thesquare pitch arrangement permils better access for cleaning between the tubes.A.3 Exposed Tube BundlesA.3.1 GeneralExposed tube bundles are used for condensing or cooling and may be located under spraying water or may becompletely submerg ed. They also may be used as heaters, particularly in tanks where they are submerged In theliquid.A.3.2 An Exposed Tube Bundle Under A Cooling TowerExposed tubes arranged in compact bundles can be placed under a cooling tower: In this arrangement, the waterfrom the tower flows over the tubes, and heated water is retumed to the top of the tower for cooling and reuse. Thisplacement of the tube bundles is most effective in a climate with a low relative humidity resulting in maximumevaporative effect.A.3.3 An Exposed Tube Bundle Under Spray HeadsSpray heads may be Installed above an exposed tube bundle to provide an even distribution of water over the tubes(this represents a modification of the method described in A.3.2). A receiving tank Is located below the tube bundle foruse mainly wnen the water Is naturally cool enough to permit recirculation without additional cooling. Where water isplentiful, this type of cooler may be used without a receiving tank, permitting the used water to drain Inlo a treatmenlsystem.A.3.4 Submerged Exposed Tube SectionsWhen exposed tube sections are submerged, the sections are mounted either vertically or horizontally within a box.The hot fluid enters the top of the headers in vertical installations and the top section In horizontal installations. Ineither installation, the cooled fluid leaves at the bottom. Cool water enters near the bottom of the box, and the warmedwater overflows a weir near the top of the box. This arrangement produces counter current flow resulting in maximumcooling with a minimum use of water.Submerged sections are used primarily when a hot fluid leaving the cooler might result in a dangerous condition if thewater supply should fail. The large volume of water in the cooler box would give partial cooling for an extended periodand allow time for an orderly shutdown of the operation if necessary.A.4 Storage Tank HeatersThe tube-bundle version of the tank heater is buitt in three general types for the following installations:a) installation outside the tank,b) installation partially within the tank,
  • 65. INSPECTlON PRACTlCCS FOR PRESSURE VEssas 57c) Installation entirely inside the tank.The first two are installations of suction line heaters, and the third (see Rgure A.2) heals the entire contents of thetank. Figure A.2-Tube-bundle Type of Tank HeaterA*5 Air--cooled ExchangersAn air-cooled unit is similar to an exposed tube bundle unit; however, air is used as the cooling medium. A bank oftubes is located in a steel framewor1< through which air is circulated by a fan placed either above or below the tubebank (a fan above the tube bank Is usually referred to as an induced draft. air cooler and a fan below the tube bank isusually referred to as a forced draft air cooler). These coolers may be used for the condensing or COOling of vaporsand liquids and are installed where water is scarce or for other reasons. Figure A.3 illustrates air-cooled exchangers.(API 661 covers the minimum requirements for design, materials, fabrication , Inspection, testing, and preparation forinitial delivery.)A.6 Pipe CoilsA.S.1 GeneralPipe coils are of two types:a) double-pipe coils,b) single-pipe coils.A.6.2 Double-plpe CallsA.6.2.1 GeneralDouble-pipe coils are used when the surface required is small, because they are more economical than the shell ortube type of exchanger In such service. They are also used where extremely high pressures are encountered,because their small diameter and cylindrical shape require a minimum wall thickness.
  • 66. 58 API R ECOMMEND ED P RACTICE 572 Figure A.3-Alr-cooled ExchangersA.6.2.2 Clean-servlce Double-plpe CoilsClean-service double-pipe coils consist of tubes within tubes (see Figure A.4). The intemal tubes are connected atone end by retum bends that are enclosed by retum bends connecting the extemal tubes of the same coil unit. At theopposite end, the Intemal tubes project beyond the outer tube and through a tight closure that prevents leakage.Intemal lubes terminate in piping or are connected to adjacent units with exposed retum bends. The extemal tubesare connected to piping or adjoining extemal tubes by branch-flanged nozzles.A.6.2.3 Dlrty-servlce Double-pipe ColisDirty-service double-pipe coils (scraper-type coils) are identical to clean-service double-pipe colis with the exceptionthat a scraper is added to the inside of the inner tube. Each intemal tube is equipped with scrapers mounted on a rodor shaft extending the full length of the tube. The rod projects through the retum bends at each end. To preventleakage, a bearing for the rod is capped at one end, and a bearing and a stuffing box are used at the other end. Therod extends through the stuffing box, and a sprocket is mounted on the end of the rod. The rods and scrapers arerotaled by a sprocket chain driven by some form of prime mover, usually an electric motor.A.S.3 Single-pipe CoilsA.6.3.1 GeneralSingle-pipe coils are used in several different ways, but essentially all are continuous runs of pipe through which flowsa medium to be cooled or heated.A.6.3.2 Condenser or Cooler ColisCondenser or cooler coils consist of a continuous pipe coil or a series of pipe coils Installed in a box through whichcold water flows. The pipe coil or coils rest on supports in the box and are free to move with any expansion orcontraction . Water enters near the bottom of the box and overflows a weir near the top.
  • 67. " Figure A.4-Clean...-v1ce Double1)lpe CollaA.6.3.3 Chilling CollaChitling coils are pipe coils InstaMed In cylindrical vessefs to 0001 a product below atmospheric temperature. Usually, arefrigerant Is drculaled through the coils to accomplish the cooling. The pipe may be coiled near the Internal peripheryof the vessel and extend from the bottom to the top or may be ammged as a flat, spiral coil near the bottom of thevessel.A.6.3.4 Flat-type Tank Heater Co ilsThe ftat-type coii extends over most of the bottom of a SI0fag8 tank and Is a conUnuous 0011 wtth retum bendsconnecting the straight runs of pipe. Steam enlefS one end of the coR, and condensate Is drained at the other endttYOugh a steam trap. The coil rests on ICM supports at the boUom of the tank and slopes gantty from the inlet to theoutiet to facilitate drainage of the condensate. The pipe is usually made of steel. and generally ell joints are welded tominimize the probability of leakage.A.6.3.5 8ox-type Tank Heater CollaThe box-type coil Is constructed In a rectangular shape, as shown n Figure A.5, and extends diametrically from thelank outlet to within a few feet of the opposite side of the tank. The coil Is enclosed in a box made of steel or wood.The end of the box opposite the tank outlet remains open to permit the entrance of 011. The oil nowsthrough the box,around the 0011, and to the tank outIel Steam enters the top of the coil and flows downward to the outlet wherecondensate is drained through a steam trap. The entire coil Is sloped gently from the Inlet to the outlet to facilitatedrainage of the oondensate.A.7 Extended Surface or Fin-type TubesExtended surfaoe or fln·type tubes are used quite extensively for more efficient heat exchange. especially when theexchange Is between two fluids having widely cifferent thennat conductivities. The addition of the extended surfacerequires less internal tube surface. Consequentty, an exchanger smalkH" than would be roquIrad if pkIin tubes wereused Is necessary. The use of fin-type tubes In 8 doubIe-pipe collis shown In Figure A.6.
  • 68. so Figure A.S-T.nk Sudion Heater with Everything but FOfWard End Enclosed; Shell SUction NozzItI Enclosed In F.r End FJgure A.6-Fln-type Tubes In Oouble-plpe ColiA.8 Plate-type ExchangersThe pIa1e-type exchanger is also constructed with an extended surface, making use of altemating layers of thin Patesand corrugated sections. Integral chaniltH and manifold sections enclose the open ends. The proc:ess material flowsinto the corrugated openings. Because the ftow opentngs are sman, they are easily dogged by dirt and products ofcorrosion. this is one of the reasons these units are constructed of materials that are highly resistant to corrosion, Aplate-type exchanger Installation for storage tank heating service is Illustrated In Figure A. 7.
  • 69. INSPECTION PAACTlCES FOR PRESSURE VESSELS 61 Figure A.7-Plate·type ExchangerA.9 Inspection of Exchanger BundlesA.9.1 GeneralThe first step in bundle Inspection is a general visual inspection that may establish general corrosion pattems. Ifpossible, bundles should be checked when they are first pulled from the shells, because the color. type, amount. andlocation of scales and deposits often help to pin point corrosion problems. An overall, heavy scale buildup on steeltubes may indicate general tube corrosion. The lack of any scale or deposit on tubes near the shell inlet may indicatean erosion problem. A green scale or deposit on copper base tubes indicates that these tubes are corroding. As anInspector gains experience. these scales and deposits will become a useful inspection guide.While visually inspecting a bundle, the Inspector should make use of a pointed scraper to pick at suspected areasnext to tubesheets and baffles. These areas may not have been deaned oompletely. PickIng in these areas willsometimes disclose grooving of tubes and enlargement of baffle holes. Figure AS shows tubes thinned at baffles. Figure A.&-Tubes Thinned at Baffles
  • 70. 62 API RECOMMENDED PRACTICE 572 Figure A.9-Tubes Fretting at BafflesTapping the tubes with a light [4 OZ to 8 OZ (115 9 to 225 g)] ball peen hammer or inspection hammer during the visualcheck will often help in locating thinned tubes. This method is especially useful when inspecting light-wail tubes ofsmall outside diameters. The amount of rebound and the sound of the blow give an indication of the tube wallthickness. This method will become more helpful as experience is gained in the use of the hammer.The inside of the tubes can be parti ally checked at the ends by use of flashlight extensions, fiber optic scopes,borescopes, and special probes. The special probes are slender 118-in. (3.2 em) rods with pointed tips bent at 90 0 tothe axis of the rod. With these tools, IT is possible to locate pitting and corrosion near the tube ends.Obviously, only the outer tubes of a bundle can be thoroughly inspected extem ally, and without a borescope or fiberoptic scope, only the ends of the tubes can be inspected Internally. If a complete inspection of the tubes for defects isrequired, it can be made by using ET methods or UT methods (for internal rotary, UT thickness measurements).Tubes may also be removed from the bundle and split for visual inspection. There are devices available for pulling asingle tube from a bundle.Removal of one or more tubes at random will permit sectioning and more thorough inspection for determining theprobable service life of the remainder of the bundle. Tube removal is also employed when special examinations, suchas metallurgical and chemical ones, are needed to check for dezinciflcation of brass tubes, the depth of etching or finecracks, or high-temperature metallurgical changes. When bundles are retubed, similar close inspection of tubesremoved will help to identify the causes of failure and improve future service.The baffles, tie rods, tubesheets, and floating-head cover should be visually inspected for corrosion and distortion.Gasket surfaces should be checked for gouge marks and corrosion. A scraper will be useful when making thisinspection. Sufficient gasketed surface should remain to make a tight seal possible when the joints are completed.Tubesheets and covers can be checked for distortion by placing a straight edge against them. Distortion oftubesheets can result from the overrolling or improper rolling of tubes, thermal expansion, explosions, rough handling,or overpressuring during a hydrates!.Tube-sheet and floating-head thickness can be measured with mechanical calipers. Except in critical locations,continuous records of such readings are not usually kept. However, the original thickness readings of these partsshould be recorded. Thickness readings of tie rods and baffles are not generally ta.ken. The condition of these parts isdetermined by a visual inspection.
  • 71. INSPECnON PRACllCES FOR PRESSURE VESSB..S 63Tube wall thickness should be measured and recorded at each inspection. It is sufficient to measure the inside andoutside diameters and to thus determine the wall thickness. Eccentric corrosion or wear noted during the visualinspection should be taken into account in determining the remaining life of the tubes.Several tools are available for the assessment of tube conditions. Long mechanical calipers can be used to detectgeneral or localized corrosion within 12 In. (30.5 em) of the tube ends. More detailed measurements along the entiretube length can be achieved with specialized tools such as laser optical devices, internal rotary UT tools, andelectromagnetic sensors. Generally, the laser optical and UT devices require a high degree of internal tubecleanliness compared to electromagnetic methods. Laser optical devices can only detect and measure intemaldeterioration. Electromagnetic methods can detect and provide semiquantitative information on both internal andexternal defects. Rotary UTs will generally provide the most quantitative information and can identify if defects are onthe internal or external surface of the tube.A.9.2 Likely Locations of CorrosionThe locations where corrosion should be expected depend on the service of the equipment. However, there arecertain locations that should be watched under most conditions of service.The outside surface of tubes opposite shell inlet nozzles may be subject to erosion or impingement corrosion. Whena mildly corrosive substance flows on the shell side of Ihe tube bundles, the maximum corroslon often occurs at theseinlet areas. The next most likely point of attack under the same conditions would be adjacent to the baffles andtUbesheets. Any deterioration here is probably erosion-corrosion (see Figure A.10). Figure A.1O-Eroslon-corroslon Attack at Tube Ends
  • 72. 64 API RECOMMENDED PRACTICE 572When a high-temperature malerial flows into the lube inlet pass, the backside of the stationalY tubesheets or tubesImmediately adjacent to it may suffer extensive corrosion.When process conditions allow a sludge or similar deposit to form, it will generally settle along the bottom of the shell.If the deposit contains a corrosive malerial, the maximum corrosion will occur along the bottom of the shell and thebottom tubes.In water service, the maximum corrosion will occur where the water temperature is highest. Thus, when the water is inthe tubes, the outlet side of the channel will be the location of maximum corrosion. Figure 27 shows pitting in achannel.Also in water service, when exchanger parts are made of gray cast iron, they should be checked for graphiticcorrosion. This type of attack is most often found in water-service channels or along the bottom of shells where sourwater might collect. It can be found by scraping at suspected areas with a stiff scraper. Whether the attack is seriousdepends on its location and depth. Quite often. pass partitions can be almost completely corroded and sHIl functionefficiently, unless the carbon shell is broken or chipped.In any type of exchanger, corrosion may occur where dissimilar metals are in dose contact The less noble of the twometals will corrode. Thus, carbon steel channel gasket surfaces near brass tubesheets will often corrode at a higherrate than they would otherwise.Cracks are most likely to occur where there are sharp changes in shape or size or near welded seams, especially if ahigh stress is applied to the piece. Parts such as nozzles and shell flanges should be checked for cracks if excessivestresses have been applied to a unit.When process stream velocities are high in exchangers, erosion damage can be expected at changes in the directionof flow. Damage would occur on or near such parts as tube inlets in tubular units and at retum bends in doubte-pipeunits and condenser box coils. The area of the shell adjacent to inlet impingement plates and bundle baffles issusceptible to erosion, especially when velocities are high.A distinctive pruss ian blue color on bundle tubes indicates the presence of ferri-ferrocyanide. Hydrogen blistering islikely to be found on the exchanger shell near this color. A long straightedge may prove useful in determining theexistence of blistering. Irregularities of the surface show up when the straightedge is placed on it A straightedge isalso useful when investigating pitting.A.. 10 Inspection of Coils and Double-pipe Exchanger ShellsBasically, coils in open condenser boxes and double-pipe exchanger shells are composed of pipe. They should beinspected according to the procedures detailed in API 574. (See Annex B for a sample form for making an inspectionreport on a double-pipe exchanger.)First, a thorough visual inspection should be made, Including a complete hammering of the pipe. A scraper may beused to detect extemal pitting. a common defect found on the outside of coils in condenser boxes.Following the visual inspection, thickness measurements should be taken. It is generally sufficient to use calipers tomeasure the open ends of double-pipe exchanger shells. To measure the wall thickness of coils and the middlesection of double-pipe shells, UT and ET devices can be used.The enclosures of condensers or cooler boxes are made of concrete or IIght-gauge carbon steel. These enclosuresshould be visually inspected when th e enclosed coli is inspected. When the container is made of carbon steel, thehammer is the most useful inspection tool available to aid the visual check. Thin spots in the container wall can be foundby hitting the wall with the hammer. calipers can be used to measure the wall thickness at the open top. Ifmeasurements below the top are required, the NDE instruments can be used or test-hole drilling can be applied.Concrete walls are inspected best by picking at selected points with a scraper to check for spalllng, cracks, or soft spots.
  • 73. INsP£COOH PAAcncEs FOR PReSSURE VEssaa 65A.ll Inspection of Extended Plate ExchangersExtended plate exchangers are designed so that the flow openings between the plates are QUite small. For this reasonand because of the lnaccessIbIity of the urn Interior, these exchangers are usually built 01 alloys highly resistant tocot I osion In their expected servIoa. In most cases, the alloys used also wiI be highly resistant to 00fT0Sk)n in refinefyatmospheres. VIsual examilation, except as discussed In 10.8.3. will not reveal much. The outer Slriaces can bechecked for nicks, cuts. _ . or oIher forms ri med1anlcaJ " " - and for bulgmg from Internal faiIu .... Goodlighting Is essential for this inspection and will prove valuable when performing the soap tests discussed In 10.8.2.These units are usually built with integral channels and distrbution manifolds, the thickness of whictl can beaccurately measured with the UT Instruments and then recorded. It Is not advisable to use drilling equipment on theexchangers because the equipment could be easily damaged at these points. Welding of the alloys used In the units.such as aluminum and austenitic stainless steel alloys, requires welder skills not always readily available.Ught tapping with a small 18 oz.. (225 g)] hammer Is useful In looking for aacked or broken parts on the exposedportions of the extended plate exchangers. The sound of the tHaw gives a due to the condition. Cracked plates ormanifold sections give off a tiM) sound, which can be recognlzed more easily as more experience Is with the use r:Ia hammer is acquired.A.12 Inspection of Air-cooled ExchangersRefer to API 661 for desaiptions, minimum design aiteria, and generallnformatioo regarding air-oooled exchangefs.API 510 and the principles of API 661 are to be followed In any ratings. repairs. and alterations of this type ofexchanger. (See Annex B for a sample form for making an Inspection report on an air~ exchanger.)Tubes that are enclosed In fins cannot be Inspected from the exterior. The best methods for inspecting the tubes arethe Intemal-rotary, UT thickness-testing devk:es, ET. or remote field ET. These methods wOO!; from the Interior of thetubes. With oompetent operatora and dean tubes, thicknesses and defects can be found with these methods. Thetubes must be thoroughly deaned before any method Is effective.The external fins of the tubes should be checked for cleanliness. tf the fins need cleaning, washing with clean wateralone or dean water with soap may be sufficient If net, care should be taken in selecting a cleaning solution. Usually,the fins are aluminum and they oould be harmed If the wrong cleaning medium is used.The exterior of the tubes should be Inspected between the tubesheet and the start of the fins. Exchangers InIntennittent service or In servioe cool enough to allow moisture to collect In this area are subject to external corrosionsevere enough to cause leaks In this area. CoaUngs applied to this area will alleviate the problem of corrosion.The Insides of the tubes may be visually Inspected near the tube--sheet ends of the air cooler. Fiber optic devices andboresoopes are excellent devk:es for this type of inspection. A probe rod te In. (3.2 mm) or less in diameter andapproximately 36 In. (91 em) In length with a pointed tip bent at 90" to the axis of the rod also may help to locate pitsor corrosion at the rube ends.ErosIorK:orTOsI at the rube INets Is a common problem with alr~ heat exchangers. This damage can befound by visual Inspection through the header-box plug ho6es, or directly If the header box has a removable coverplate. If suitable conditions exist. reflecting sunlight Into the tubes with a mlrTOr Is useful in Inspec:OOg for erosion-00<r081on.The box-type header ends of the air cooler shot.id be Inspected using the same techniques as recommended for apressure vessel. In addition, the shatp change of direction caused by its rectangular construction should be carefullychecked for cracking. The header boxes with removable cover plates are obviously the easiest to Inspect. A fiberoptics scope may be the only way to dleck a header that has plug-type dosures as opposed to a cover plate.
  • 74. 66 API RECOt.tMENOEO PRACTICE 072 Legend 1 stationary head-channel 21 floating-head cover-extemal 2 stationary head-boi1net 22 floating tube-sheet skirt 3 stationary-head flange-channel or bonne1 23 packing box 4 channel cover 24 packing 5 stationary-head nozzle 25 packing gland 6 stationary tubesheet 26 lantern ring 7 lubes 27 tie rods and spacers 8sheIJ 28 transverse baffles or support plates 9 she~ cover 29 impingement plate 10 shell ftange--stationary-head end 30 longitudinal baffle 11 shell flange---49ar-head end 31 pass partition 12 shell nozzle 32 vent connec1ion 13 sheU-cover flange 33 drain connection 14 expansion joint 34 instrument connection 15 floating tubesheet 35 support saddle 16 floating-head cover 36 liftlng lug 17 floating-head flange 37 support bracket 18 floating-head backing device 38 weir 19 split shear ring 39 liquid level connection 20 slip-on backing flange AESNOTE AES refers to heat exchanger type (see Figure A. 12). Figure A.11-Heat Exchanger Parts
  • 75. INSPECTlON PRACTICES FOR PRESSURE VE ssas 67 BEM AEPFigure A.11-Heat Exchanger Parts (continued)
  • 76. 68 API RECOMMENDED PR,t.CllCE 572 CFU AKT Figure A.11-Heat Exchanger Parts (continued)
  • 77. INSPECTION PRACTICES FOR P RESSURE VESSElS 69 AJWFigure A.11-Heat Exchanger Parts (continued)
  • 78. 70 API RECOMMENDED PRACTICE 572 Front End Rear End Shall Types Stationary Head Types Head Types ~T I~ ~ I ., . A E I I L fIXed lube sheet one-pass shell like "A" stationary head ,-","- ; . I~ ~ .. 1 I, channel and removable cover F M ftJ-i------------- fixed tube sheet two-pass shell with like "S" s1alionary head B longitudinal baffle 6 ~ " ::"1 -... ... - ,,; . ~I ----ui---- u I~ •. N G fIXed tube sheet like ·N" stationary head split flow p :aE3~u ~I +--} I~ removable tube H outside packed floating head c bundle ...1--.,"::, only channel integral with tube sheet double-split flow s ~-:~~-~;- " J _ _ ,_ ..-= and removable cover I ~I I I~ floating head with J backing device I ":jr divided flow T ~~""" 1..) :;";;; .. N -=~ ! !!== T pun through floating head channellnlegral with lube sheet and removable cover K T 1 , , , .1 U :~ ~ kettle-type reservoir U-tube bundle : I~r- I, ,;. " ~I I~ ~ o X W externally sealed special high·pressure closure cross·flow floating lube sheet Figure A 12-Heat Exchanger Types
  • 79. AnnexB (informative) Towers8.1 GeneralTowers all either directly enrich 8 gas Of liquid, strip a gas or liquid, or fractionate a liquid. These processes 8recollectively called ·mass transfer.· Towers or columns (the terms tower and column are used Interchangeably wfttIlnthe petrochemical Industry) come In a wide variety of shapes and sizes, but the one thing they all have in common Isbase purpose. that is, they all at the very basic level, promote, cause, contain, allow, enoourage. or otherwise make"mass transfer" happen. The difference in concentration of a partiaJlar molecule is the prime rTIOV8f In mass transfer.Molecules move from an area of high concentration to an area of low concentration. The mass transfer in a tower Isusually from a liquid to a gas or from a gas 10 8 liquid. The most corrvnon types of towers use contacting elementssuch as trays or packing to facilitate mass transfer between a gas and a liquid (see Figure B.1 and Figure B.2). Bothpecking and trays accomplish this by Increasing the available surface area for the gaslliquld contact. Figure B.1-Typical Trays In 8 Tower Figure B.2-Random Packing In a Tower 71
  • 80. nIn addition to Increasing contact area (and inaeaslng contact time). trays allow additional distillation 10 take place ateach tray.Tray decks both inaease the available oontad area and provide additional distillation stages 10 take place as !he hoigases rise through the tray perforations. liquid levels are maintained on the trays via weirs, and a vapor seal IsmaIntained via downcomers. Figure B.3 diagrams how the trays wfth downcomers work. Figure B.3-Trayl with Downc:omersGaseslvapors, released from the feed liquid (after belng heated). travel up the column through the tray perforations(the bubble cap depicted In Figure 8.4 Is a type of tray perforation) while liquid flows across the trays and down thetower via the downcorners from the feed inlet down to the stripping section (countercurrent How). The area above thefeed Inlet Is known as the rectification or enrichment section. The enrichment section utilizes a liquid reflux ofcondensed ovemead gas to further enrich the overhead product.. Figure B.4-Bubble Cap Flow Path
  • 81. 13M06t of the towers used in the petrochemical Industry utilize the distillation-type stripping process desaibed aboveand depicted in FtgUre 8 .5; however, In cases where distillation is impractical, iqu~uid extraction aocompIishesmass transfer utiHzing the diff8l8llC8 between the c:hemical structxes of fINo liquids. Uquid-liquid extractionnecessitates t8COV8fY of sotvent or rarfinate via distiHatlon stripping. Some other types of mass transfer operationswhich utilize distiUatioo-type stripping are stripping, absorption (also known as saubblng). and dehydration.Fractionation uses slmple distillation via selecttve cooling to remove and collect those fractions of the feed which bolland condense at different temperatures. The heal source needed to cause phase change (liquid to gas) can be firedheaters, steam Injection, steam reboilers, or reboilers using preheated process streams. fraction to condemer refUx from Reboier to FJgu ... B.~Tower Stripping and Recttftcatlon SectIon
  • 82. APt ~ FAAc11C£ 572"B.2 Trayed TowersB.2.1 GeneralTrayed towers oonslst of cylindrical shell courses with both top and bottom heads, with nozzles where appropriate,lllied wtIh tray decks to raootate the gasIIiquid oonIact They may also Include oonicaI transition sections, Internalsumpslba1fes, demlsters, Inlet distributons, or a variety of other components. Multiple towers may even be fabricatedas a single pressure vessel, stacked on top of each other.Trayed towers come In several different configurations, from c:ascacHHype trays such 8S disk and donut trays to sieveIrays, bubble cap Irays and Iigh capacity valve Irays.B.2.2 Cascade TrayoThe two most common types of cascade trays are shed trays and dlskldonut trays. Cascade trays utilize a differentapproach to gasIIlquid oontact than regular trays. Shed trays may be anything from angle Iron to half pipes. Largenumbers of shed trays are arranged In rows, Installed perpendicular to each other Md k> the gas and liquid flow suchthat breakup of the failing liquid takes p&ace. Gas flow up ttvough the droplets of liquid Is the primary source of contactfor mass transfer. In disk/donut trays (see FIgure B.6) the disks and dorIuts are Installed In alternating sequence, withthe donuts mounted to the shell, and the disks suspended In the center of the tower, with both the disks and thedonuts being perpendicular 10 the gas and liquid flow. As liquid repeatedly cascades from the disks to the donuts,"-ting and bnIaIwp at the liquid _ place. Figure B.6--0lsklDonut Tray
  • 83. INsP£cnoN PfWmCEs fOR PRESSURE VEssa.s 15Batne trays (sometimes caBed -splash trays") are aoid baftIea, Installed on altamaling sides, perpendlrular to the gasJliquid flows. These individual trays each typk:ally obstruct about 60 % of the tower to ensure that the faUlng liquidImpacts the tray below. The batrIe tray arrangement Is depicted In Figure B,7.Contact with the falling and/or splashing droplets Is the main source of liquidJllapor oontact for an cascadtHype trays,Internals assodated with cascade trayed towers are usually ImItecI to sirnpte pipe Inlet distribution wtth steamspargers In the bottom to provide heating and gas now volume.B.2.3 Sieve Troy.Sieve trays ant tray ptates with perlorations in them simiar to 8 sieve (see FiglK8 B.8), hence the name. No valves8(8 present Sieve trays can be subdivided n tl aIngkt-fIow and dua6-fIow trays. Single f(MI refe~ to the flow throughthe troy perto<ation.. On single-flow trays. the pnmary flow po.. of the Hquld ~ aaoss the troy and down thedownoorner to the tray below.The downcomenI oct " transport the iquid to the next troy. and _ disengagement of the gas and the lIQuid.The primary flow poOl of the gas on singl&-llow trays Is through the troy _lions. The _lions In ~sieve tray are sized with this In mind. Single-now sieve trays are customarily used where Ilght-to-moderate fouHng bypreclpttates and/or polymers Is anticipated.Dual flow also refers to flow through the tray perforations. On dual-now trays, there are no downconlers. The primaryflow poOl of both the deoamdIng liquid and the ascondIng gas Is through the tray peIfotations. In rospon.. " iquidfallilg from above and gas bubbling from below, the standing liquid on the tray forms waves throughout the liquid.Gas flow up ~ primarily at the wave troughs. and liquid flow down "rough the perforations Is pnmarily at the waveaests. Jet tabs simUar In appearance to very small upward fadng scoops are utilized to promote even liquid nowItvoughout the sieve troy. Ripple trays are atypa of dual·fIowtroy whlcl1 magnifies the aestJIroogh _ p via theCXlITUIj8Ied design of the troy panels. DuaI·fIow trays are customarily used for proaISS8S whlcl1 exhibit heavy foulingdue to the fonnation 0( prec:ipi1ates or potymers. Both types of &Jeve bays have better anti-foullng characteristics thanstandard vaNe trays, but must operate In a very Umited range of operating rond/tions to be efIicienl-.SIeve trays must be installed and maintained level. Sieve trays which ere not level can rapidly lose efficiency duo tob60w through where ereas of the liquid level on the tray are shallow. FIgure B.9 show a sieve tray that has beenB.2.4 Valvo TroyoValve trays are trays that have valves Installed at the perforations In the tray deck. Perforations are typically largerthan those in sieve trays, as weft The advantage of valve trays over sieve trays Is that the valve Is able to dose, 01 Inthe case of lIoatIng valves even pertially close, abwing the pressure of the rising gas to be malnlaloed. This slowsthe tower to operate over a much ItIcIer range of operating conditions than sieve trays would allow (FIgure B.10 toFigure B.16 show typCaI tower drawings and types of valves). Trays are frequently designed to have more than oneweight of valve installed, to ailow balandng of gas now through the tray. This also allows the back pressure below thetray to be malntalned. Valve trays can be subdivided Iota fixed valve and ftoating valve trays.8.2.4.1 fixed YltvesBubble cap trays are fixed valve trays. For a good portion of the history of fractionation trays, bubble caps were theonly tray valve. Bubble caps remain In service throughout the Industry In systems where low liquid now rates and highvariations In vapor flow and reslstance to heavy fouling are required. Bubble cape come In a variety of shapes and- . """ roood (mushtoom " - ) " _ (brick " _ loaf capo) In both _ad "- and solid (FRI1 _ researdllncorporated-typ (FRHype))"-.While operating ranges are less than those allowed by moveable valve trays, slgnfficant Increases in operatingranges and emdency over sieve trays and bt.ObIe cap trays are possible using fixed valves extruded from the tray
  • 84. " F===- -+----4Bame os,. Plan o Elevation FJgure B.7--8aftkt Tray Arrangement
  • 85. INsPECTION PRACnclEa FOR PRESSURE VEsseu n .........•,..•. ••..•••••, . . .... I • ... . • • •..•.. •.. · ,.... ~ • • • • • • • • •·•••• • • ~ ••••••••• •••••• ••••• .... . • ••• • ••••• •••••• ••••• . ....... • • • .<) ~ .....• ••••• • • • • • • • _0 " ) :) Figure B.8-S1w11 Traydecks. Fixed valves offer lateral gas now to Inhibit fouling rather than the vertical gas fIow of sieve trays, end highermechanical strength than ftoatIng valve trays, with no moving parts to wear out.NErNer fixed vatve designs offer even greater operating ranges, eftk::Iency and fouUng res!stance but at the C06t oflosing the single piece construction of the extruded valves and at the cost of additional wear as valve tabs loosen oroonOOe.B.2.4.2 F1ooti"ll Va""MovIng or ftoating vatve trays are trays in which valves have been Inserted into or are placed above the trayperforations. These valves are retained In the bay perforations via bent or twisted "feer andfor are kept positionedabove the perforations by cages tabbed to the tray deck. Valves are allowed to move freely (or "1Ioar) from the closedposltIon (down) through ruly opened (up) posltIon a. pushad by the vapor pressure below the ..y. _ allows va,,high Itmdown ratios, and much less weeping than conventional fixed valve or sieve trays. As with the fixed vaNes,the horizontal gas !low limits entrainment and foulng .Valves may be 8ITIO(I(h edged, or pn:Mded with tabs andfor dimples on the edges to prevent rotation and sticking ofthe valves (due to vapor lode between the vatve and tray deck), respectively. FloatIng valves may be round orredangulw In shape. Floating valve _ of eltherlype offer a "<Iller elliclency Plquldlvapor contact) over a muchwtder operating range than sieve trays due to their ability to control vapor flow. MultiPe valve weights are frequentlyinstalled in the same tray to widen the operating range. Caged valves are frequently utilized In low Ilqukf flowsystems.B.3 Packed Towo",B.3.1 GoneralPacked towers all have bask3/) the S<:me conftgUfCltion, with the only slgrVftcalt varIaI:*3 being the type of packingused. Packed towers have one or more packing beds, supported by bed supports. wtth dstribution systems above thebed to 8fISIX8 even wetting of the peddng (see Agora B.17).
  • 86. 78 Tray Distortion Figure 8.8---8...... T~ DistortionBed limiters may Of may not be instaled and may be Integral to the dlatribution system. CoIec:tor (chimney 1nIys)/redistrlbutors are commonly used between packed beds and In some seMces are InstaBed below the bottom bed aswell. Due to the larger surface 8rea BVSItabIe for mass transfer, packing has the advantage of being able to handelarger liquid rates with higher efficlenclea and with lower pmssure drop than all but the newest of the high capadlytrays. Packing can be subdivided Into random packing and structured packing.B.3.2 Random PackingRandom pad(WIg takes lis name from the method in which It Is kladed, I.e. alkJwed to fall at random onto the bed-.supports. Random packing comes In a variety of sizes, from 0.50 in. in diameter to 3 in.• and can be rustorn otderedIn any size and almost MY material, from carbon steel to ceramic and plastic. Random packing shapes range fromthe original raschIg rings through palt rings and various "super rings." Figure B.18 shows pall rings for random_ _ _ low pnI88UTII drop, high _ and high .-.:y, _ !he malntenanco cost offradionation trays, but is typk:aly more expensive for large diameter columns. Random paddng ~ less Ihan Ideal forlarge dameter toweB with low liquid now rates and high vapor flow rates due to the diIfiaJlty In maintaining packingwetting throughout the bed at low liquid rates.
  • 87. INSPECTION PRocT1cEs FOR PReSSURE IJEssas • • ,Figure 8.10-Typical Trayed Tower
  • 88. 80 • 1 - - Flgurw B.11-Float Valves wtth Two Weights . e, -" • t " "g p -t p ": "" .>t. ..,...._, ....... #> ., 1t 7 , """ --::. Figure B.12-Flxed Valves q
  • 89. INsPEcnoH Aw:ncE1 FOR PREssuRe VEllal 81 Figura B.1~ubb&eCapV.IYeI • Figura B.14--&trudedVaIvesB.3.3 Strucwred PackingStructured paddng gets its name from the fact that Its assembled Into blocks 10 facilitate loading and assembty Intobeds. SlnJcturod paoklng ~ construcled of coougated metal (typically, • non<om>s/ve high alloy) a""ged such thatthe oom.Jg8t1ons oppose one another. The oom.Jg8ted metal Is then Ixx.M into bbc:b. Most structured peddng Isinstalled such that each succaecllng layer Is goo out from the previous layer, this can be noticed In FigIX8 8.19 ofstructured packing. ThIs allows an Interfacial area for mixing and spreading of the ijquld throughout the packing.Surface texturing Is frequently Pf8SG"t on the sheet metal to Increase wettng and Instill turbulence In the gaa flowwhich facilitates mass transfer. Depending on service, wall wiper rings may be Installed at each layer to rec:hannelanyliquid or vapor whlctl has migrated to the wall.
  • 90. 82 Floating Valves F~ ..... B.15-New Floating V.lve Tray Flgu .. B.l6-C1IiIOd VoIvHWIthin Its operating range, structured packing provkSes higher capadty and lower pressure drop than crosscurrenttrays or random packing.Packing bed support grids and hold downs are typically much larger spaced. Frequently, box and trough distributionsyslBms may be _ d1rec1ly upoo the bed. wtth lillie _ support required. Gnd-Iype paddng ~ commonlyutilzed In heaVy fouling seMoa. The surface of grid--type paddng is Invariabty SI1"IOOth to sHow any particulates towash 011 Inhlb41!ng coko fonnolion. TIle grid-Iypo pocking Is depicted In Figu" 8.20.8_4 Inspection ofTawersBA.l GenlralDue to the compIicatBd structure of a tower and the wide variations In feed sources possible in todaya petrocherricalmarket, past reports and OJrrent ptfnts are InvaJuabie aids In performing a thorough vtsual Inspection. Past turnaround
  • 91. 83I FFigure B.17-Typlc.l PKk..:l Tower Or.wing
  • 92. 84 API RECOMMEN:JeO PAAcncE 572 Packing Figure B.18-Random Packing , Pall Rings Figure B.19-Structured Packing
  • 93. . xfOrkI (Style 2» PlICklng Remov•• flgur. B.2O-Grfd-styll Packingreports provide aitical data on the location and severity of ongoing COfTOSkm and wear. An up-to-date or OOfT8dedelevation "",,",ng of the """" not onty allows those ...YIousIy Identified problems 10 be mapped out for analysis andmakes following capital work easler, It also allows inspection progress to be easily tracked, while ensuing that thosesame history Hems are not over1ooked.With tcY.<ers. should an external visual inspection be required tt Is customary to perform the external Inspection on theway up the tower. Extemallnspedion from the bottom up and intemallnspectlon from the top down Is the rustomarymethod.The following tools at a minimum shook! be with the inspector when they ctimb the tower to begin the Inspedion. 4 oz to 6 oz ban peen hammer, nspedion light (1Iashlght), digital camera, pit gaugeo, scratch &Wi, """"", tape measure, paint markers, wire toothbrush. notebook and penslpendis, carpent9f"s or plumbers level, inspedionrnimlf, sampie bags.PIloIogmphy and nspectlon-lt " not posslble 10 Iak. 100 many photcgmpha of the condition of a dstiU8tion """".cameras have long been an Important tool for Inspection, and the advent cA digital photography has made a pictorialpormIssions and ponn;uing are _nodrecord of the actual conc:ition of a toNer easy and inexpensive. care should be taken to en8lKe that proper for photography In the course of ;"spodlons.
  • 94. ..BA.2 SoIetyCombIning confined space entry, the large, convoluted Interior spaces typically found Inside towers and the mobilityInvolved In oompleting the Internal Inspection In a timely manner makes internal Inspections of trayed towersinhel8nlly dalgotous. When> possible, two Inspectors shooId be asslgned when W<>I1drg _ very large 1OWonI. InadcitIon to the normal precautions associated wtth oonfined apace entry for Intemal vistJa£ Inspection (carehi readingof any permits, and any Job safety analysis or Its equiwh!lnt which might be required In the facility In whidl you arewottOng). the following additional safety precautions are advIsabMI. 1) PrIor to entry, enSlQ that the entry attendant(s) Is famlltar wtth the InIemaI con1Iguration d the tower, and understands the physical basics of your task, such as climbing on and aaoss trays, moving between trays. and of the access and egress point which have been approved. 2) Prior to entry, ensure that the entry attendant, the Inspector(s) and any other persons involved with the mama Inspection understand the limits or the approved oommunlcatlon method. WherI visual contzK:t Is lost, most facilities rely on radio communication between the antrant(s) and the enby attendant. The extreme noise level Inherent to common forced ventilation methods may prevent Yefbal c:orrmunlcation. Communication sounds and meanings should be woriuKt out In advance to be effective. 3) Prior to entry. ensure that scaffolding, where required for entry, access to the Internals and/or &gf9ss from the _ , Is insIaIIed. The pnIS<IIlC8 01 scaffold from the boIIom heed to the boIIom IrBy (see Fig"", B.21) and bridging any extra ¥ride tray spadng suc:il 88 that found at distJ1butonI or transition secaons should be connrmed prior to performing this visual Ins_. 4) Tray manways (see FIgure 8 .22) can be extremely easy to traverse In one direction, but very dilficUt In the opposite direction. Tray hardware and sharp CXln"Ief"8 can catdl on clothing or exposed sldn. 5) Release d gases and vapors from under debris and/or from under liquids such 8S water left after washing or steam out is possible. SUch conditions should be addressed prior to beglmlng the inapectIon where visible, and prior to completion of the mpection when dlscoYefed In situ. Figure 8.23 depicts 8 dangerous condition that shan be assessed and dealt with prior to Internal inspection. 6) Upset IrBy deci<s are Inherenlly dangerous _ _ ,., dimbIng. ca.. should be "en to .....,... _ evenly while perfonnlng damage assessments. Use of fall protection and/or rebieval devices is hlghty I8OOmmeoded under upset conditions. Fall protection Is also highly reoommendecl In towers where severe tray tIllnrlng ~ sospeded. 7) Wherever possible, hard ladders such as seatfoId ladders should be utilized, to aUow su1ftciant time and stability tor vllsuallnspection. Who.. hanj _ are not possible, yo-yo type fall proIoction (see FIgu.. 8.24) should be used in c:onjulction with the rope, strap 0( other soft ladders. 8) All dlsbibutors whk:h are obstructing Internal or external manways should be temporarily removed to aKow access and emergency egress.
  • 95. IHsPecnoN PRAcncEs FOR PA£18URE VESSELS " HomSIYood--HDwg 933831-0002 20..0 0 Scaffold • Figure B.21-Dlagrwn of Requlr.d Scaffolding
  • 96. 88 FlUu.... B.22--Htxagonallbnwaya Figure B.23---St1ndJnv 011 .nd Watw
  • 97. . Collapsed trays due to thinning (Note Yo-Yo)B....3 ExtemallnapectlonThe Anchor Botts-Oue to the leverage applied by the height of the tower and the corrosion masking effect offireproofing, particular care should be taken when Inspecting the anchor bolting of lowers (see Figura 25 andFIg.... 26).SkIrt FlreproofIng--Any aack over 0.250 In. in width, and any aack which has displacement or bulging of thea>ncnIte firaproofing material shooId be tnvestigated for COITOSlon under filllptOOfirg (CUF). tdontifyirg CUF. as withCUI. II a primary lOcus of todays mechanical integrity programs. Figure 8.27 shows aacks wittm 8 Warsfireproofing. • Figure B.25--Corroded Anchor BoftIng
  • 98. go Cracked and Bulged Fireproofing Figure B.27-Cracked and Bulged FIreproofingTower skirts should be Inspected for debris and skirt drains sholdd be checked for obstructions. Debris in the skirt(see rlg!J8 B.28) is a fire hazard, and obstructed skirt drains foster CXlIT06ion of the anchor batting and skirt. as wellas allowing minor leakage al the bottom headlnozzIeslftanges to go undetected.B.U Intemal InspectionThose tools which are nonnaI to the visual Inspector (see 8.2) are sufficient for the inspection of towers. No specialtools or equipment are required to perform IntemaI visual Inspection of a tower.
  • 99. 91Preliminary, or -dirty Inspectioos" shown In FIgura B.29 through FIgure B.35, should be performed upon opening theexternal manways. before whatever forced ventilation Is to be Instaled Is Installed. Early detection of pnMousIyunexpected damage to Internals due to upset and/or corrosion Is crudal to the timely completion of repairs.De",",,""""" of the degnIe of -.mal cleaning which might be _Ired ~ auclal to the timely CX>IllPetion ofdlscovery M)t1c:. Hand cleanlng of those areas not adequately cleaned via steam out and chemical deanlng isfrequently required due to the oompIexIty of the Internal oonflgurations.Us!ng the equipment elevaHon drawing, manway covers; manway gasket aurfaces end manway bore Internal. . . - . should be labeled and Inspectod. Debris I" Skirt Figure B.28 Debris In Sldrt F1ti1Ufe B.2I--PreUmlnary InspKtion
  • 100. 92 API R~D PRAcnce 572 Figure B.3O--8ed Damage at Preliminary Inspection Figure B.31-Manway Corrosion Figure B.32--Manway Uner Damage
  • 101. INSPECTION PAAcncEs FOR PRESSURE VESSB.S OJ . ... _1 M ........ II c __ •O•• k.1 5.1111"1 SlI rt . C. Figure B.33--Corroslon on Gasket Seating SurfaceCracked Plug welds Manway liner damage covered by Blower at Inltlallnspeetlon Figure B.34-Corroalon on Gasket Seating Surface
  • 102. . API REcot&IENXo PR.t.cnce 572 Very Light • •,• • of Shell Co rrosion due t o conden ••tion Figure 8.35--$urfaet ColTOllon of ShellPatticUar care should be taken with nned manways and COY8IS.Craddng aM bulging at liner plug welds and oonoequendal ootrOSion bahlod the _ . oonoded or damaged _surfaces and/or Internal COOOI!IIon of the bore or stagnant areas should be dfsoovered prior to installation of ventilationequipmenl8.4.5 Viluallnlpection of Packed TowersSA.5.1 GeneralPacked towers have two basic sets of oonditions; packing removed and packing In place. If pecking Is not removed, alimited or partial visual Inspection Is the most whim can be performed. Under these conditions, the degree ofInspection Is a variable, cootrolled by the degree of disassembfy of the internals, the type of packing and the amountof access pennitted by operations.8 .... 5.2 PKked Towel1l Packing In PlaceInspection of a tower with packing in place Is limited to the top and bottom heads, the adjacent shell, and those otherportions of the pressure retaining boundary that are aocessible, the accessible nozzle bores, the top and bottomsurface pactilg and the Internals (FIgure B.36 and Agura B.37 demorsbate the Nmitad visibility of a paddng In placeInspectionl·Normal visual inspection and quantificetlon of the surface texture and 00IT0Si0n present on the top head and shellcourse may be suppktmentad with UT thickness measurements. Thickness measlX8ments fA susceptible areas Ofareas of vtslble impingement shoukt be taken in oonjuncllon with the visual Inspection throughout the tcM<er. SuctlateaS of impingement can frequentty be found above demister pads, and are indicattve c:J pad bypass, usually due toimproper instalation or breakdown within the pad. If Internal UT thidaless measurements are to be taKen subsequentto the visual Inspection, ldentiftcatlon and high visibility mar1dng of the areas where measLl"ements are to be taken Isof great importance. Figure 8 .38 to Figure 8.40 gives examples of fouled demister pads and Identify Internal UTthickness measurement locations.When not removed by Inspection scope, demfster pad installation defects warrant removal when Indicattve ofdemister bypass, damage to the pads Of retention grid Of heavy fouling of the pads. No2::Ve bores end nozzSeattactment wekjs on the top shell course and the top head, especially those with little Of no flow 8UCh as blind flangednozzies and those for PSVs, should receive partiaJlar attention. Temperature diffen:tnC8S between the top head andthe nozzle bon> may lead to ",.,apilation of eotnl8Ive Hquids from the IMHf1ead vapors.
  • 103. . Inspection of p.Kklng from tM bottom heM Ho touUng or dMnage . .FIgure B.3&--lnapectfon From the Bottom Head ~ • Inspection of p.cklng vi. Or1flc. PI.te ChimneyFigure B.37-1nspection of Packing vMI RfMr Figunt 8.38--Otmlster Bypass Deposftl
  • 104. . Figure B.39-Fouled Demlster Pads 0 ............. " ___ .... .............In ...... preb..... ~ss Figure B.4O--Faulty Demister Installationtn the case of contactor towers with random packing Installed, removal of the packing bed Is preferred. Vibnltion of thepacklng against the shell can cause or accelerate erosionloorroslon as contaminants from the process stream build-up In the solvent or aaubbing media.All vlsible portions of the towsr weld seams should be Inspected for cracking, wear, pitting and preferential00fT0Si0n of the heat affected zone wald or shell (Figure B.41 through FIgUre B.43 &how examples of thesedamage mechanisms).When inspecting the Internals of a packed tower with the Internals still Installed, access can be severely limited. Asmany perforations of the Internal piping and the distribution system as posstbIe shoukJ be inspected. All perforationsshould have appropriate shaping and square cut edges (see FIgUre 8.44)."Out-of-round" and loss of edge profile 00 Internal distributor perforations are indicative of wear or corrosion. Note anyvisible obstructions of perf01 atlons or distribution piping for oorredIon.ChImney or ooIlector trays frequently require supplemental cleaning, since they are designed to hold Aquid. Properdeanlng of this area Is requillld to allow dlscov9l) of oorroalon or pitting of the tray dad: and shell. Draw sumps, If- . shcx.Ol be particularly wei cleaned 10 aIow dose visual inspection of the dmw nozzle atlactvnent weld andthe nazzje bore for COfTOSion.
  • 105. ., F1gu... B.41-Prefe1enUai CorrosJon of the Hud to Shell Weld Figure B.42-Head Seam Preferential ConosionChImney trays are someUmes subjected to cyclic pressure due to var1atlons In vapor now and cyclic lIQuid loads.CtWnneys should be dlecked for distortion (see Figure B.45) as well as aacIOOg. Seal welded chlrmey trays shouldbe inspected for aackIng at the base and vertical edges of the chimneys, at the deck seam seal welds and at the rngseal welds.Box and trough distributors, where installed, should be checked for ntemal debris, obstruction of any perforations andfor any distortion or damage to drip point enhancement devices (where Installed). 88e Figure B.46 through FiguraB.48. Trough. wtlk;h .... holding liquid probably have obstruded peIforations.1QttI1ng haldliare" on IntemalB is the most coovnon method of ensuring tightness, however, hardware whichappears tight when "rattled" may be held In place by a single Itv"ead, with an exposed threadrlg evenly degradedwhere In contact with the process ftulds. This Is fairly common on the reflux distribution system of amine towers.Slriklng several nutslbolts sIwpIy at an angle with the Inspection hammer should reveal this condition (see FIguraB.49). In 81 other cases, where halVNare Is actually hit with the Inspection hanmer, hitting the washer Is best. The
  • 106. . Figure B.oU-Preferential Corrosion of the Shell Figure B.44--Perforaflon Degradation ,f2DA-2Ot1 M.ln F.-.ctJon.tor Figura B.45--Chlmney Tray Deformation at Draw Sump
  • 107. INSPECTlOH PlW:ncEs fOR PFlUSURE VEssa.s ..Figure B .~ouled Trough, on Box and Trough DI,b1butor FIgura B.Aa-80x and Troughs
  • 108. 100 Agu,.. B.49--Htt the Washers, Not the Balta Figure B.5O--Random Packing on Vlilve Traytorque values on tower hardware are relatively low, and loosening may result from hammer blows. Tower attachmentsshould also be SOlIldecI with an Inspection hammer to ensure attachment welds are not Cf8Cked.In all cases, the distance from !he padting to the bed Imiter should be 19COfded. Ensure recon:ting of this Infonnationprior to the removal 01 the bed limiter If the bed limiter is to be removed for access. Bed limiter Integrity and hardwareshould be dIecKed, as well as ched<1ng for pecking migration due to overiarge grid size on the bed limiter (seeFig... 8.50)._ pad<ing may or may no! haw • sepa .... hokkIown gI1d. Bed NmItsrs for random pad<ing ... generallybolted to lugs or dips welded to the shell. Rather than bolted to the shaU, hokS-OOwn grids are supported by thestructured packing (see FIgure B.51). and In disbibuttx" deslgls which have dlstrlbutonl: sitting dlredly on the packing,hokkIown grids are usually no! """""od. Ant Indications 01 pacIdng migration, such as paddng loose above thelimiter or loose inside the box and trough distribution system should be noted. Migrated pecking found on chimneytrays or In adjacent process equipment should be noted In the tower report upon discovery.Any Indications of ooIlsp5e or break up of the packing should be reootded. VIsual lodlcatlons of thinning andfragmentation of random packing are typically found at the gas Injection support plata, or downstream In the bottomsfi~_. Bed collapse wi! be Indicated by fragmentallon and a slgnltlcanl drop " pad<ing bod heIghI as shown
  • 109. " Bed Limiter above packing Fuure B.S1-8ed Umltar Abo" Random Packing Figure B.52-Olalodged PackJngby !he distance between !he top of !he bed and !he bed 6miter. Upset beds of stnJctun!d packing ... usually aaslIyvisible dut1ng the preliminary Inspection. FaKen pacKing sheets or support gnd members may be visible (seeFIg.." B.52) on !he _ tray betow !he bed.A good "rule of thumb" for thinned random packing Is that if you ani able to significantly distort the packing with atinge< and thumb. reoonvnendation !of I1IjlIaooment should be made. W looks thinned. and has knffo odges 1 _ Hof !he sharpness _ o d with !he otamping process. Hprobably ~ thin.Caution-M.tal PKkInv of ." types Is tharp. Ca,. ahoutd be exerelHd and gkJVM ,hould be worn wheninapeettng or handtlng metal packing.
  • 110. 102 API RECOtAENlEO PRI.cncE 572The inspection of the support ring. attactvnent welds and gas Injection suppori plate or bed support grd mustfnlquenl1y be perlomted from !he bottom head. An; indications of damage and/or wuar visible from In excess 015 ftshould be considered sufficient cause to provkte for closer visual inspection.Where close visoaIlnspodion 01 ...... c:omponents ~ possible. pat1icUar attention should be paid In !he Integrity 01the gas Injection support plate/support grid bonfng and positioning (center1ng), as well as the support ring attachmentwelds (sao FIgure B.53 and Figure B.54). ..."., ..., Figure B.53-Damaged Packjng Support Grid Support Grid Figure B.54-Suppon Grid from BelowDuring the Inspection of the bottom head and accessible sheI courses particular attention should be paid to thenozzle bores and attachment welds of slghtglass nozzles (see figure B.55) and any other nozzJes which have little orno flow duting normal operation.Temperature difr8f80C8S between the bottom head, bottom shell course and the nozzle bore frequently lead toprecipitation of COITOSIve liquids from the ovemead vspent All Inspection mirror Of camera should be used to Inspedany shell, attachment wefds, nozzle attachment welds and the oozzle bores which may be partially enclosed by stiliwells or Inlet diffusers. The Intemal surface of the bottom head Is frequently COY8I"8d with debris or scale, even after
  • 111. 103 ~ , L:J , 1 FJgure B.55--COIfOSfon Insfde Slghtgl... NozzSemec:hanical Of chemical cleaning. Scratching the internal surface thoroughly through minor debIIs with a scratch awlor pointed saaper will sometimes show any severe pitting prevkxJsIy obscured.Vortex breaker and anti-swIt1 baffles, where installed, should be sounded with an inspection hammer to insure soundattachment welds In additloo to visually Inspected for wear (see Figura B.56).8".5.3 Padc:1Id Towera-Pack.lng RemovedPacking removal allows the c:Io6e visual inspection of the condition of the packing In the loner bed, 88 wen as accessto the tops of support grids and the remainder of the shell. Random packJng should be checked fa< fragmentation andfouling of the packJng sutface. Fouled random packJng may no< be bIoddng""" _ to a fouled ex~ boodle.Footed random pac:fdng appeanI dirty, but actually has a highly adherent coating of deposits which retard easy row ofliquid through- out the bed. Random packing should come out of the bed dean, or with easily rinsed deposits on It.Slrudured _ should be Insped8d fa< frangibility (see FIgure •. 57), as shown by edges which appear nibbled,and which are easily bent .. fatigue faikMe. Slrudured packJng which Is fouled generally wiN have heavy _visible _ t h e _ of the block ofstrudured packJng. Highly adherent _ no """""the thickness shoutdbe reported to process engineering for evauation.
  • 112. ". Flgu," B.57~oulod G~"-09VISUal ilspection of the shell exposed by the removal c:J packed beds should be done with great care. RandompadOOg In carbon steel shefls will present a mottled appearance which may hide defects such as cutting of the shellOf pitting due to carbonic acid. 5aruc:tured packing which was Incorrectly oriented duling loading may have Initiatedd1anneIIng on the shell. These defects require dose visual Inspection to detect during the early stages, andscaffolding is rec::orMIEIrld to facilitate this inspection.8 ....5.4 Sb1p Unlng and CladdingMany towers have all or part of the intemal surface of the sheI and heads Ined with oooosiorHesIstant material. Theselners range from staIriess steel ~ conaetaJrefrac: 1ilIngs. Metallic liners may be Installed n sheets or strips,with plug wolds utilized 10 _ .... aJJ.at material 10 .... COIbon _ . _ ~ known as ..... Iining .• Plug - . . ""_ wolds at ....... ~ crack on trio type at .... frequently crack .... 10 . - - . at trapped gassesbehind the sb1l liner (see F1gute B.58). Coke or other 00IT0Sivea may ooIlec:t behind the finer, causing bliges oflhe liner.ThIs may result In additional aackIlg d the liner as well as corrosk:In of the underiying metal. RepaIrs to strl> linerusualy _ .... nIIT1<JViII at _ aection at _ "" .... nIIT1<JViII at any """ " oIher process deposits. BulgIng of 410 SS LIner Figura B.58-Cl"ICked Plug Weld
  • 113. ". Figure 8.59-8alnI8" Steel Donut Cladding BrMChIf corrosion Is present under the deposits, wed bUldup with a like material Is performed If required. Following thecompletion of the weld buildup, weld over1ay with a corroslon-realstant material Is usually performed. If strip liner isrepmc:ed Instead of using CXltT06ic:lrH8sta1t weJcI overiay, upon oompIetion of any approved repaIrs pressure testingwith air to 5 psi Is usually done to ensure that no gaps or defects remain In the strip Nnlng which might aIkJw additionalaccess to the undertylng metaLNozzJes which have been lined wtI frequentty have a threaded hole drtled through the boUom centertine of the nometo allow detection of Unertallure. Unless liner failure has been detected dLring this operational pertod such that repakshave not been made, these plugs, Ilke the ..... holes of relnfon:emeni pads, shoold not be plugged.Clad lining usually refers to explosion bonded stalnlesa steel cladding 00 carbon steel plate. This material, If properlyconstructed Is free of most of the aaclOOg and bulging associated with strip lining. Some clad ~te vessels utilize.donut" strip lining to cover the nozzle attactment welds (see FIgUI"8 B.59).Most dad towers use weld over1ay to caver the nozzle attachment weld with oorrosion-ntsIstant material, and to tiethe nozzle cladding into the sheIIIhead daddlng. This over1ay and the "donur Uoer used In pace of over1ay along withgouges to the Gadding and the carbon steel shell to clad shell interface weld comprise the ptimary areas of claddingfaillft (see Figure B.60 and Figure B.61). Flgu,. B.8O--ClMkIlng BrMCh at GotJgM In Bottom HAd
  • 114. " ......- 1041011 Flgu... 8.81-410 Stalnleu Steel Clad to Carbon StMllntertace Weld8.4.6 V,.uallnapection of Trayed Towerw8 .4.6.1 Internal Manwayslnstal*iWhen Internal tray manways 8f8 not removed, a Hmited or partfaJ visual nspection Is the rlICISt whidl can beperformed. Access aoould be provided onto !he top tray, at !he middle manway (If present) and onto !he bottom headfor inapectIon 0( the bottom shell courses and the underside of the botkxn tray to Inspect for damage. UT thicknessmeasurements of suspect areas should be performed c:onc:urrently with visual Inspection and the quantification eX the00IT0Skln character1stIcs of the sheI and heads. If i1temal UT thicKness measurements are to be taken ~t tothe visual Inspection. high vlslbHity maridng of the areas where measurements are to be taken Is of great Importance(see FIgu.. 8 .62), Figure B.62-SuPPementaJ UT Mar1dngs
  • 115. 1018 ....6.2 IntemaJ Mal1Wl)S RemovedB.4.6.2.1 GeneralThe primary difference between the Internal visual Inspection 0( trayed towers and packed towers is the traysthemselves and their support r1ngs. locations within trayed towers are delhed by the tray m.mber (from the assernbfydrawings), and the process activity laking place on the particular group of trays.EXAMPLE Trays 1 through 10 may be referred to either by nurrber. or as a group 8S "rectification section" or "thereflux trays.·Trays may be numbered from the top tray down, or the bottom tray up, depending upon the designer andmanufacturer. ChecIc the drawings before inspecting the tower to ensure proper numbering d the trays for reportilgpurposes. Towers may be constructed using severa/ tray types and manufacturers within a process section, or maybe consistent throughout 8 section or the entire tower. Basic understanding of the process purpose of each towerallows recogMion of the sections and the type fA chemical reaction taking sXace within that section. llis In Un akb Wlthe prediction of the bcatlons where corrosion. aacking, or other damage mechanisms may be expected.Eadl tray Is a separate distillation sIage, with _ activity consequen1!y Ia~ng place (against the shaU)ttvoughout the column. TNs chernk:al activity takes place In an environment fA varyilg concentrations of oonosivesubstances which in tum leads to varying corT06lon rates. Corrosbn rates and characteristics vary across the trays,within the section and across the tower. The large number of Internal attactvnent welds, coupled with the numeroushorizoolal sufaces aeates conditions whk:I1 promote _ _ type defeds (see Figure B.63 _ Figure B.65),such 8S environmental aacking anellor corrosion at the tray support ring attachment welds, the downcomerattachment welds and on both the upper and lower surface 0( the tray.Supplemental NOE. such as WFMPT. may be required In certain services (J.e. amine or caustic). NJ a general rule,the upper third or the lower third of the tower i8 where the most oorros/ve environment is typical) found. Wheredadding Is provided for corrosion protection. Interface welds between the dadding and shell shotJd be carefullyInspected fur Ioc:allzed/pnlleronlll corrosion. Cracking at the Toe of the weld on ring .ttachment w.kI ~":5"~ ~~~~ Ago,. B.83-Cracklng at Thry Support RIng W.ld
  • 116. "" Figure B.64-WFMPT Dlscoverwd CfKkIng Supplemental WFMPT FlgUfW B.65-Supplemental HOE May be NeededOther locations 10 Inspect for damage ara as follows. 1) The area of the feed Inlet and five to ten trays above and bekJwthe feed Inlet. 2) The ranux inlet. the adjacent shellI1lead and the first five to ten trays below the reflux Inlel 3) The shell across from and adjacent 10 the Inlet from the reboiler (If present). this Indudes the boaom head, bottoms nozzles and the head to shell seam.These areas are usually sulJtecled to the most turbulence within the tower.The areas or zones between trays (see Agura 6.66 and Figure B.61) where corrosion may be present are as follows.a) The UquId ~Thls area of the shell sees primarily liquid, IWld the beginnings of frothing. CorrosIon In this area ~ sometimes further complicated by the .......... af process _ . Spot-oheck.lng ( _ to six locations pM tray level) under _ Is raoommended. Saape opals 4 In. to 8 In. long, from above the _ height - . to and Including the tray support ring.
  • 117. 109 Flo .... 8 .6 7 _ 011 Activityb) The Froth Zona--Thls area sees less liquid, and if process deposits are present, they typfcally have a dlfIerent, lighter consistency than those present in the liquid zone. light spot c:heckIng Is usually sutncient (two to three locations per bay _ ).e) The Vapor ~Thls area consists of the last 3 in. or 4 In. below the tray. ThIs area of the shell sees primcriy relatively dry vapors, entrained droplets and any weeping liquid from the tray above. The shell In this area usualty sees very light corrosion, however, the tray support ring atIactlment weld and heat affected zone may be subjected to aoceIerated oonosIon, and deposit3 may cause aocektrated corrosion of tray hardware.Mechanical cleaning of this area may be needed If the initial dearing of the vessel has not removed the majority 0(the deposits from the XIdersIde of the tray (see Agura 8 .68).S .... 8.2.2 Trays and VafvesTray valves fall Into two loose categories. Moveable tray valves (see FlglQ B.69) are those which are designed toopen with sulfldent vapor pressure below the tray. These valves may be designed to remain either fully open (}I( fultycIo6ed, or may be designed to operate in partially opened/closed ~ as wei. FIXed valves are vaNes thai 818designed to be open at all times. They may be extruded from the tray deck Of be held to the tray deck by tabs pushedthrough the tray deck and bent
  • 118. 110 API REcOl.lNENDED PRACTICE 572 Figunt B.68-Hardware Corrosion Moveable valves Stuck open due to Process Deposits Figure B.69-Stuck Valves Always OpenMoveable Tray Valves and Associated Tray Perforations-Tray decks, valves and tray perforations are subject to avariety of corrosive Influences ranging from process deposits to vapor Impingement due to lateral vapor flow. Valveperforations which are unwom have square edges (see Figure 8 .70), and the perforation is round or rectangular, asappropriate.Moveable valves and associated tray perforations are subject to mechanical fretting (corrosion due to mechanicalremoval of any corrosion barrier which the tray and/or valves may develop), corrosion due to Impingement ofentrained liquids and high speed vapor low.With moveable valves, the tray deck immediately around tile perforation should be checked for indentation due tofretting (see FIgure 8.71) by the valve dimples. Tray decks with severe indentation should be replaced.Perforation edges may be fretted by the valve legs to an "out~f-round" condition (also known as "key holing" or"slotting" see Figure 8 .72). Key holing (or slotting in rectangular valves) is caused by rapid and continual cycling of thetray valve.Inspection of the valve legs and perforations Is easiest from underneath the tray (sea Figure B.73). Valve feet maycause indentation of the underside of the valve due to valve rotation while open. Such indentation is seldom of
  • 119. INSPEcnoo PRACTICES FOR PRESSURE VEssas 111Figure B.7O-Clean SquanMldged Perforation From Below , Leg fretting ectangular Valves Figure B.71-Vatve Fretting Slotting by rectangular valves from below Figure B.72-Slotting from Below
  • 120. 112 API R.eCONMENOED PRAC1lCE 012 Irupec:tJon of the wives perforations, legs and " Is easiest from below Figure B.73-Valve Leg and Perforation InspectIonsufficient in depth to warrant !ray replacement, however, should the indentation on the underside reach half thethickness of the tray, replacement should be considered.Some trays have anti-rotation tabs included inside the orifices. These tabs may be frequently found on perforations ofround valves with key holing.Moveable valves of all types should be manually checked for adjustment andlor thinning at each internal inspection.Round valves rnay be checked by pushing from below and shaking to attempt to push the valve ~r Into andthrough the valve perforation. Valves whose "feer will enter the perforatlon are either worn out (see Figure B.74),installed in an enlarged perforation or have leglfeet which have not been installed correctly. Properly Installed andadjusted round valves have legs which dont touch the perforation when centered, and feet which have at least halfthe top length of the foot always in contact with the perforation edge when raised (see Figure B. 75).Caged valves should have clean square edges. Most caged valve Installations are done with valves without dimples.Inspection of the cage valves includes checking for fretting damage to the cage andlor lhe valve. Valves with wornedges should be replaced. Orifices should be visually inspected for out-of-roundness. Orifice edge profiles should beched<ed for vapor flow damage. If Venturi-type oriflces are present, check for scoring of the inner surface on theraised portion of the orifice. Cage installation should be checked by grasping the cage and lightly shaking the cage.Most cages are installed with small tabs run through the tray deck and bentltwisted. Figure B.74--1ndentatfon of Valves
  • 121. INSPECTION PRACTICES FOR PRESSURE VEssas 113 New caged valves showing dimple Dimple wont pass leg for anti·rotatlon Figure B.75-New Caged Valves with Dimples Figure B.76-New Caged Valve Cage TabsWhen these tabs are not properly bentltwisted, the cage will come loose and allow the valve to escape (see FigureB.76). Corrosion of the cage tab or the tray deck penetration will allow cages to be removed In this manner. Cageswhich can be removed by hand may be replaced or adjusted to the limits of the cage and the tray deck to hold.8 .4.6.2.2.1 Fixed Trays ValvesFixed tray valves can be subdivided into two categories; those extruded from the tray deck Itself, and those which areremovable. Removable fixed valves are fastened to the tray deck via tabs through the tray decl<lperforation (seeFigure B.n and Figure B.78).Extruded fixed valves come in a variety of shapes and sizes. Most fixed valves, both extruded and tabbed aredirectional, e.g. the tray panel must be Installed with the valves facing a particular direction. As a general rule, one legof the valve will be wider than the other. The wide leg goes toward the flow; the thin leg goes with the flow.Fixed valves are by design always open. liquid bypassing is kept to a minimum by the design of the valve, i.e. by thewide end being toward the flow, causing liquid to Impact and swirl out away from the perforation (open area), and by
  • 122. 114 API REcot.4MENDED PRACTICE 572 FIgure B.n-Small Fixed Valves FIgure B.78-flxed Valves Lateral Vapor Directional Flowthe lateral vapor flow from under the cap of the valve. This lateral vapor flow forces the swirling liquId away from theopen area (perforation). Tapering of the fixed mctangular valve also Imparts some directional Impetus to the liquid.Valves which have three or more legs are generally nondirectional. and use the fateral vapor flow to prevent weeping,foster vapor liquid contact and to suspend process particulates and detritus to reduce or prevent fouling.Areas of interest to the inspector are the edges of the perforetion and the edges of the raised cap. These areas aresubjected to accelerated corrosion due to Impingement of entrained liquids. To a lesser degree, these areas are alsosubjected to cavitation brought about by phase change of Impacting entrained liquids due to high speed vapor flowparticularly in vacuum towers. Such wear or corrosion will cause the valves to present a wom appearance at theedges of the perforation and cap. Overall , extruded valve trays are very robust. and require little in the way ofmaintenance. Corrosion or wear of the cap and legs will create perforation growth and shrinking of the extruded capand legs due to corrosion will eventually make replacement of the trays necessary.Removable fixed valves are directional valves, which typically provide enhanced Ilquidlvapor contact and resistanceto fouling vs. standard fIXed valves (see Figure B.79). These valves are as a group more efficient but less robust thanextruded valves. For tabbed in valVes, corrosion of the tabs or of the tab penetration and improper installation orhandling of the tray decks may cause loosenIng of the valve and consequential side to side chattering of the valves inservice, leading to blown valves and indentation damage to the tray deck (see Figure 8.80).
  • 123. INSPECTION PRACllCES FOR PRESSURE VEssas 115 Removeable fixed valve. under h •• vy deposits Figure B.7~9movable Fixed Valves Reduce Fouling Figure B.8O--Removable Fixed Valves Tray DamageRemovable fixed valves which are fastened to the tray via the tray perforation (with wide legs) are less subject toloosening and hence less subject to chattering and Indentation. However, due to the thinner gauge metal used, theyare subject to manual deformation. Care should be taken to prevent damage to these valves during maintenance andInspectlon activities.B.4.6.2.2.2 Bubble Cap TraysBubble caps are very large fixed valves. Methods of mounting bubble caps to chimneys vary with individual designs,with bolting and tapered pins being the most common. Bubble caps come in three baslc shapes; round (Mushroomcaps, see Figure 8.81), rectangular (brick or bread loaf caps) and (rarely) polygonal shaped caps. Tunnel trays use atype of roocIlfied bubble cap.Bubble caps are designed In two basic configurations, with a skirt of bubble fingers descending to below the liquidlevel, and solid caps in which the solid cap has a solid skirt whIch extends to below the liquid level. Solid caps are alsoknown as FRI caps. Bubble caps are primarily In service where low liquid flow rates make long liquid stay times andhence good seals on the bubble caps possible. and in severely fouling service.
  • 124. 116 API REC<lW.4ENDED PRACTICE 572 l Figura B.81-8ubble Caps on Stepped Trays Figure B.82--Flbrous Depostts and Fouling Under Bubble CapsBubble cap trays are extremely durable. Property installed bubble caps are very stable, wi1h little or no maintenancerequired other than replacing the occasional cap broken or dislodged during tray opening. Bubble caps are subject tofouling of the chimney throat Consequently, this fouling may not be readily visible and close visual Inspection may berequired across the entire tray bottom. Clearing of fouling by heavy and/or fibrous materials may require disassemblyof the valve cap from the throat due to valve configuration (see Figure B.82).B.4.6.2.2.3 Tray Decks and Hardware.Overall, tray deck corrosion and wear is usually fairty gradual when the areas actually impacted by the valves are nolconsidered. Primary locations of concern are the active and inactive panels of deck. the welrn, the downcomer panelsand the hardware. Tray gasketJng (If any) between tray and ring, as well as between the tray support ring and the traydeck. itself should be inspected for gaps.Corrosion of the tray panels may be generalized throughout the active and inactive panels if the tray is level. Randomareas of the active and inactive tray panels should be scraped free of process residue and any process or COfTOSionscale (see Figure 8.83). Note the presence of pitting or roughening of the tray panels. Bulging, sagging and distortionof the tray panels, may allow pooling or puddling of liquid corrosives which have precipitated from solution. Corrosiveprocess deposits may collect in these areas as welt. If present, these areas of corrosion are highly visible. Anydisruption of the even plain of the tray deck should be scraped clear of process residue and any process or metallicscale for close visual examination for accelerated corrosion.
  • 125. INSPECTION PRAcnces FOR PRESSURE VEssas 117 Tray Deck Smooth under deposits FIgure B.83-Tray Deck Should be Scraped Clean Fatigue Cracking of Sieve Tray -• - • • • • • • ~ FIgure B.84-Tray Fatigue CrackingMany tray deck materials become embrittled under process conditions (Le. 41 0 stainless steel in high-temperarureprocesses). In addition, the vibrations of most modem valve trays may become pronounced under severe operatingconditions, leading to cracking of the tray deck at support and stress points (see Figure B.84).The aligned pinpoint corrosion at the "breakover" work hardened points previously mentioned are such stress points.Cracking of the tray deck is frequently adjacent to internal manway openings. Close visual inspeclion of these areasafter wire brushing may be required to locate cracking.Weirs and down comer panels of cross flow trays are subject to surface corrosion Similar to that expenenced by thetray decks (see Rgure B.85), without the instances of pooling or puddling of corrosives mentioned above. Mostdamage or problems wHh down comer panels are due to loose or missing hardware. Loose or missing hardware ondowncomer anti-jump baffles or downcomer anti-vibration dips are the main point of failure fur these tray components.Most hardware issues on trays result from; mismatched hardware, I.e. carbon steel hardware Installed instead ofcorrosion-resistant alloy hardware, hardware which is loosened due to tray vibration (see Figure B.86), galled stainlesssteel hardware and Improper Installation. Inspection for loose hardware and hardware adrift on the tray decks is done by
  • 126. 118 API RECOMMEI«lED PRAcTICE 572 Figure B.85--llght-to-moderate Weir Corrosion Figure B.86-Loose and Missing Hardware Failuresounding of the tray and downcomer panels with a 4 oz to 6 oz ball peen hammer. When striking individual haroware,efforts should be made to strike the edges of washels as the washers will not gall (also avoids damaging hardware).Typical torque values for 3/8 in.tray hardware range from 10 ft-lb to 14 ft-Ib and 1/2 In. tray hardware torque valuesrange from 18 ft..jb to 22 ft..jb. Agure B.87 and Agure B.88 indicate areas that needed to be proper1y tightened.Particular attention should be paid to the intended purpose and location of hardware If direct contact with the hammerhead is the preferred method 01 testing.Tray clamps or clips are friction fittings, as is hardware in a number 01 other locations on the various types of trays.Movement of the washerlhardwarelclip is to be expected. Friction clamps and hardware which do not showmovement may have been over tightened.B.4.6.2.2.4 Tower Attachments-Tray Support Rings, Support Clips, Downcomer Bars, etc.Tray support rings are generally constructed of material that matches the shell or cladding material of construction. Intowers which are clad with corrosion-resistant alloy material, tray support rings may or may not be constructed of clad
  • 127. INSPECnON PRAcncES FOR PRESSURE VESSELS 119 Clips not Tightened New Inst lIatlon Figure B.87-Oowncomer and Seal Pan Clamps Loose Downcomer clips not tightened Figure B.88-Downcomer Clamp Loosematerial. The carbon steel tray support ring may be welded to the shell with carbon steel weld materials, or may bewelded to the cladding itself. utilizing compatible alloy welding rod. In towers constructed of corrosion-resls1ant alloymaterials, carbon steel tray support rings may be welded directly to the shell with compatible corroslon-resistant alloy.Thicknesses vary with ring material, diameter and applied corrosion allowance.Even with construction drawings and previous reports, direct visual confirmation of support ring attachmentconfiguration may be the only way to ascertain how a particular ring or group of rings are attached. The tops of traysupport rings (see Figure B.89), the tray support ring top side fillet welds and the shell In this area are quite often thesite of the most aggressive corrosion in a tower (see Figure B.90 and Figure B.91).The support ring and fillet weld are in the "liquid zone; yet tray design frequently leaves the circumference of the traya stagnant area. This allows any process debris and corrosion detritus which is not swept down column by the liquidflow of cross flow trays to collect on top of the ring at the edge of the tray.The tray support ring also supplys a horizontal surface (bound on one ide by the shell and on the other side by thetray) for collection or puddling of any corrosives which may have precipitated out of process fluids. Corrosion of this
  • 128. 120 API RECOMMENDED PRACTICE 012 Tray 7 ring hoi Figure B.89-Tray Support Ring Corroded to Failure Scale detritus, Process Deposits and Hardware adrift at Support Ring Figure B.9O--Depostts Adjacent to Shell are on Ringtype is often typified by bright orange colored corrosion residue on, and sometimes under the ring (applicable tocarbon steel support rings, see Figure B.92).The area of a carbon steel ring covered by alloy tray decks may corrode under these conditions with little or no visualindications other than the above mentioned orange residue. If inspection of the ring between the tray and the shellshows localized corroslon to be present, consideration to removal of all or part of the tray to allow inspection of thepreviously covered ring surface, particularly where the possibility offonnic add precipitation exists.Tray support ring upper and lower attachment welds are sometimes subject to localized corrosion In excess of thatsuffered by the shell or ring (see Figure 8 .93, Figure 8.94, and Figure 8 .95). This preferential corrosion may bedifficult to spot without wire brushing to remove surface debris and process deposits. StItch welds are sometimesused to attach the lower side of the tray support ring to the shell. Cracking of these sUtch welds is common. Carefulexamination of the stitch welds should be undertaken to ensure no crack propagation into the shell has taken place.Tray support ring butt welds are prone to cracking as well.Propagation of cracking from this source Into the shell is possible. When discovered, stop drilling may need to beperformed if weld repair is not performed. If Indications of corrosion between the shelf and ring are present. such as
  • 129. INSPECTION PRACTICES FOR PRESSURE VEssa.s 121Figure B.91-5hetl Corroded to Half Wall Adjacent Top Three Rings Figure B.92-Support Ring Grooving Tray Support Ring Attachment Weld Cracking • Figure B.93-Cracklng of Ring Attachment Weld
  • 130. 122 API RecoMMENCEO PRACTICE 572 ... I . ....... . .. ~~ ~~~ Tray support ring Butt weld cr eking Figure B.94-Tray Support Ring Butt Weld Cracking FIgure B.9S-8reechlng of the Seal WeldCOfTOsIon residue leaking from between the stitch welds, additional NDE such as external UT should be considered.Tray support ring upper attachment welds are prone to cracking, particularty at the ends adjacent downco/TlefS. Carefulexamination of the welds shoutd be undertaken to ensure no crack propagation into the shell has taken place.If tray support rings are seal welded, close visual Inspectlonlinvestigatlon of all possible breeches of the seal weldshould be performed. Breaching of the seal welds may allow process fluids/deposits to accumulate between the ringand shell, leading to localized corrosion of the shell.Downcomer attachment bars generally show corrosion characteristics similar to that of the she". Downcomer bars areusually only welded on the outside edge due to the internal angle induced space limitations. The internal angle behindthe down comer bar has the potential to develop contact or crevice corroSion, and Is subject to the buildup of possiblecorrosive deposits. This area may require additional cleaning. Downcomer bar attachment welds are sometimesprone to cracking at the upper and lower ends. Careful examination of the welds should be undertaken to ensure nocrack propagation into the shell Is presenl
  • 131. tNSPECTlON PRACTICES FOR PRESSURE VEssas 123Support clipS and lug6 welded to he shell generally show oorrosion characteristics similar to that of the sheillhead. Aswith the above tower attachments. cracking of the attachment. welds andlor preferential corrosion due to bad weldingmetallurgy are the prtmary sources of failure.8 .4.6.3 DetectIng Surface Corrosion In TowenoCorrosion In towers may be found at virtually every level, at any point of the circumference. The unlined shell may berelatively uncorroded, and removal of Identical deposits two trays do...." will reveal oorrosion to 0. 060 In.+ generalpitting. When necessary, deposits should be removed by hand at a minimum of every other tray.Shadowing the shell above the top tray, from the bottom head or from the scaffold Installed from the bottom head tothe bottom tray Is the best method of locating oorroslon in these areas. The shell inside downoomers is the onlylocation between trays where adequate room for shadowing exists (see Figure B.96 and Figure B.97). This areashould be shadowed at every opportunity. Shadowing the shell down the Downcomer Figure B.96-Shadowlng Inside the Downcomer Figure B.97-Shadow the Downcomer Shell Every Tray
  • 132. AnnexC (informative) Sample Record FonnsThe Inspection record for pressure vessel In service illustrates a form used to store data gathered during theInspection of a pressure vessel In service. Most plants develop a more detailed set of forms that also Includes otherpertinent data.The permanent pressure vessel record illustrates a form that is used to record all the basic data of an Individualpressure vessel and that becomes the permanent record for that vessel.The vessel inspection sheet Illustrates a form used as a progressive record of thicknesses. from which a corrosionrate can be calculated. Three versions of this form are included. One Is blank. The other two show sketches thatmight be made for different types of pressure vessels. Information on only one pressure vessel should be recorded onany Individual copy of this form.Normally, an inspector would use one copy oftnls form to record field data. and another copy would become an officerecord. An inspector might use this form without a sketch when Inspecting a vessel for which no basic data Isavailable. In this case, they would make a sketch of the vessel on the form. including all pertinent dimensions anddata they am secure In the field.The record of all pressure vessels on an operating unit Illustrates a form used to record and report the actual physicalconditions and the allowable operating conditions of all pressure vessel on an operating unit.The exchanger inspection field datasheet. the exchanger data record, the exchanger Inspection report form . the aircooler exchanger Inspection report form. and the double-plpe exchanger Inspection report form illustrate other forms.NOTE Computer storage and retrieval of data in a format similar to that of the sample forms is acceptable and may beadvantageous in many cases.44 The falawing forms are merely examples for illustration purposes only. (Each company should develop its own approach.) They are not to be considered exclusive or exhaustive in nature. API makes no warranties, express or Implied for reliance on or any omissions from the Information contalned in this dOOJment 124
  • 133. OWNER OR USER NO. OWNER DATE _ _ _ _ _ __ JURISDICTION OR NATIONAL BOARD NO. OWNER DATE _ _ _ _ __ _ _ MANUFACTURER _____________________________________________ MANUFACTURERS SERIAL NO . ____________________________________ INSPECTION RECORD FCTION RECORD FOR DESIGN PRESSURE TEMPERATURE ____________________ PRESSURE VESSEL IN SER: VESSEL IN SERVICE MAXIMUM ALLOVlIABLE ORIGINAL HYDROSTATIC WORKING PRESSURE TEST PRESSURE _________________ ORIGINAL THICKNESS A B C D _ _ _ ____ CORROSION ALLOWANCE A B C D _ _ _ ____ MAXIMUM METAL MINIMUM ALLOWABLE I THICKNESS AT 1ICKNESSAT TEMPERATURE AT METAL THICKNESS AT CRITICAL POINTS TICAL POINTS CRITICAL POINTS CRITICAL POINTS DATE OF DATE OF NEXT SIGNATURE OF INSPECTION A B C D I C D A B C D A B C D INSPECTION INSPECTOR ~ I (Jj ~ ;0 ~ (Jj ~ ~ I ~DESCRIPTION OF LOCATION DATE _____________________________DESCRIPTION OF LOCATION DATE _____________________________DESCRIPTION OF LOCATION DATE ______________________________DESCRIPTION OF LOCATION DATE ______________________________DESCRIPTION OF LOCATION DATE ______________________________NOTE: MANUFACTURERS DRAWING CAN BE USED TO SHOW THE LOCATSE USED TO SHOW THE LOCATION OF A, B, C, AND D. ... ~
  • 134. 126 API RECOMMENDED PRACTICE 572 NAMEOFUNIT ________________________________________ VESSEL NAME _________________________________________ PERMANENT PRESSURE LOCATION ___________________________________________ ORIGINAL ITEM NO. ____________________________________ VESSEL RECORD DATE _____________________________________________ HISTORY ESTIMATE NO. MANUFACTURERS TEST PRESSURE ORDER NO. DATE RECEIVED MANUFACTURED BY DATE INSTALLED MANUFACTURERS SERIAL NO. COMPANY NO. MANUFACTURERS INSPECTOR COMPANY INSPECTOR DESCRIPTION GENERAL REINFORCEMENT DRAWING NO. FACTORY OR FIELD FABRICATORS TOP HEAD TYPE CONTRACTORS ELLIPTICAL HEMISPHERICAL COMPANY DISHED POSITION (VERTICAL OR HORIZONTAL) CROWN REGION KNUCKlE REGION CODE CONSTRUCTED CONICAL (ANGLE) CODE YEAR FLAT COOESTAMP JOINT EFFICIENCY MATERIAL SPECIFIED AND GRADE OR TYPE ORIGINAL THICKNESS BASE CORROSION AllOWANCE LINING MANoNAYS THICKNESS NO. STRESS RELIEVED (ORIGiNAl) SIZE RADIOGRAPHED (ORIGINAL) FLANGE RATING COtAPLETE REINFORCEMENT WELD INTERSECTION FACTORY OR FIELD SIZE BOTTOM HEAD TYPE NOMINAL INSIDE DIAMETER ELLIPTICAL HEMISPHERICAL LENGTH BASE LINE TO BASE LINE OISHED DESIGN CROWN REGION KNUCKLE REGION PRESSURE, PSI CONICAL (ANGLE) TEMPERATURE, O F FLAT STRESS, PSI JOINT EFFICIENCY MAXIMUM AllOWABLE OPERATING PRESSURE, PSI ORIGINAL THICKNESS MAXIMUM AllOWABLE TEMPERATURE, O F CORROSION AllOWANCE LIMITED BY MANoNAYS SHELL NO. TYPE OF CONSTRUCTION SIZE t"Kt:~uru::. ,.-,:). TEMPERATURE, O F FLAT STRESS, PSI JOINT EFFICIENCYMAXIMUM ALLOWABLE OPERATING PRESSURE, PSI ORIGINAL THICKNESSMAXIMUM ALLOWABLE TEMPERATURE, O F CORROSION AllOWANCE LIMITED BY MANWAYS SHELL NO. TYPE OF CONSTRUCTION SIZE JOINT EFFICIENCY FLANGE RATING TYPE OF SUPPORT REINFORCEMENT INTERIOR OR EXTERIOR STIFFENERS FACTORY OR FIELD ORIGINAL THICKNESS NOZZlES CORROSION ALLOWANCE MINIMUM FLANGE RATINGMANoNAYS TYPE FACING NO. OPENINGS REINFORCED SIZE REMARKS FLANGE RATINGNOTE: A COPY OF THIS SHEET SHALL BE PREPARED FOR EACH INDIVIDUAL VESSEL IN A UNIT. IF NEW VESSELS ARE INSTALLED OR ANY CHANGES ARE MADE TO PRE-SENT VESSELS AFFECTING THE DESCRIPTION ITEMS, A NEW OR REVISED COPY OF THIS SHEET SHAlL BE SUBMITTED WITH THE CURRENT INSPECTION REPORT.
  • 135. INSPECTION PRACTICES FOR PRESSURE VESSElS 127 UNIT ____________________________________________ NAMEOFVESSEL _______________________________________ VESSEL INSPECTION SHEET ___________________________________________ D ~ E T E R LENGTH __________________________________________ VESSEL NO. ________________________________________ DRAWINGS SHELL LINING IilTERNALFABRICATORCONTRACTORCOMPANY SKETCH WALL THICKNESS MEASUREMENTS POINT NO. MINIMUM INSPECTION ORIGINAL ALLOWABLE IilTERVALS NO. THICKNESS THICKNESS DATE I I I I I I I WALL THICKNESS MEASUREMENTS POINT NO. MINIMUM INSPECTION ORIGINAL ALLOWABLE IilTERVALS NO. THICKNESS THICKNESS DATE 1 2 3 4 5 6 7 8 9
  • 136. 128 API RECOMMENOED PRACTICE 572 UNIT _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ NAMEOFVESSEL _______________________________________ OIAMETER ____________________________________________ VESSEL INSPECTION SHEET ~NGTH _______ ________________________________ VESSELNO. ____________________________________________ DRAWINGS SHELL LINING INTERNAl FABRICATOR CONTRACTOR COMPANY SKETCH WALl THICKNESS MEASUR£IIENTS POINT NO. MINIMUM INSPECTION ORIGINAl AlLOWAB~ INTERVAlS NO. THICKNESS THICKNESS DATE I I I I I I I WALl THICKNESS MEASUR£IIENTS POINT NO. MINIMUM INSPECTION ORIGINAl AlLOWAB~ INTERVAlS NO. THICKNESS THICKNESS DATE 1 2 J 4 5 6 7 8 9
  • 137. INSPECTION PRACTICES FOR PRESSURE VESSElS 129 UNIT _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ NAMEOFVESSEL _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ____ VESSEL INSPECTION SHEET DIAMETER _ _______________________________________ ~NGTH _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ VESSELNO . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___ DRAWINGS SHELL LINING INTERNALFABRICATORCONTRACTORCOMPANY SKETCH . 4 in. 3 In. 24 in. Manway 3-10" 1/2 in. Makoup 7 Spaaos at 1-6" - 10-6" 4-6%Cr _ ~in lhick -::sq. f 11.0" WALL THICKNESS MEASUREMENTS POINT NO. MINIMUM INSPECTION ORIGINAl AlLOWABLE INTERVAlS NO. THICKNESS THICKNESS DATE 1 I I I I I I I WALL THICKNESS MEASUREMENTS POINT NO. MINIMUM INSPECTION ORIGINAl AlLOWABLE INTERVAlS NO. THICKNESS TI-lICKNESS DATE 1 2 3 4 5 6 7 8 9
  • 138. RECORD OF ALL PRESSURE VILL PRESSURE VESSELS NAMEOFUNIT ____________________________________________________________ LOCATION _______________________________________________________________ - ~ ON AN OPERATING UNI10PERATING UNIT INSPECTIONANDTESTNO. ____________________________________________________ DATE ______________________________________________________________ (SHEET 1) (SHEET 1)NAME OF VESSELCOMPANY VESSEL AND SKETCH NO.OPERATING DATAHOURS UNDER PRESSURE TO DATESERVICE DATAAVERAGE MAXIMUM OPERATING PR ESSURE, PSI E, PSIAVERAGE MAXIMUM OPERATING TEMPERATURE, O F TURE. O F TOP BOTTOM ~NO. TRAYSNO. BAFFLESNO. COILSINSPECTION AND TEST DATA i m o "tIINSPECTORNOMINAL INSIDE DIAMETER ~ hi ~MINIMUM THICKNESS SHELL LOCATION TOP HEAD BOTTOMHEADJOINT EFF ICIENCY SHELL HEADSHEAD FACTOR TOP BOTTOMLAST INSPECTION INSIDE WELDS OUTSIDE WELDS UNDER INSULATION EXTENT INSPECTION
  • 139. NAMEOFUNIT ____________________________________________________________ RECORD OF ALL PRESSURE ALL PRESSURE VESSELS LOCATION ___________________________________________________________ ON AN OPERATING UNI OPERATING UNIT INSPECTIONANOTESTNO. ____________________________________________________ DATE ______________________________________________________________ (SHEET 2) (SHEET 2)NAMe OF VESSELCOMPANY VESSEL AND SKETCH NO.TEST PRESSURE VESSEL, PSI COILS, PSITEST MEDIUM ITIME PRESSURE HELD -(1) • (2)MAXIMUM ALLOWABLE OPERATING PRESSURE, PSI ,URE, PSIMAXIMUM ALLOWABLE OPERATING ~ TEMPERATURE, F LIMITED BY ~WORKING STRESS AT OPERATlNG TEMPERATURE, PSI ~ enAPPROVED OPERATING PRESSURE, PSI o ;:0 ~APPROVED OPERATlNG TEMPERATLRE, F FSAFETY VALVE SETTING, PSI ~PROTECTIVE LINING DATA ~DRAWING NO. ~DATE INSTALLED ~MATERIAL AND TYPESECTION LINEDDATE REPAIRED EXTENT OF REPAIRSDATE PREVIOUS LINING REMOVED CAUSE OF REMOVALREMARKS .... ~
  • 140. .... ORIGINAL THICKNESS , 2 3 4 5 6 7 8 9 0 " 2 3 4 5 8 17 8 9 20 ~ DRILL POINT LOCATIONS WITH THICKNESS MEASURED IN 0.0 INCHES DATEMfr.Design Data: Type • Tubes Shell Shell ~ Fluid 1IIru Temperature Pressure Size :I: Material ~ Z Cl m -y-~ ORIGINAL :::a 9 THICKNESS z > .... 4 NOZZLE LOCATIONS WITH THICKNESS MEASURED IN 0.0 INCHES en J2 8- 9 4 DATE , 2 3 4 5 6 7 8 9 0 " 2 3 4 5 6 17 8 9 20 "U m ~ m 7~ .~ ;" 13 ~ ~ 0 -I (5 im z 0 m 9.... .... Z 0 "a 2 a 5 " in r- 1:1 ~ ~ 9". ,:. ./FL C n m C C7I ~ -.j , ~ ):Ii i I en :I: m T T T m -I $" $" 8 B t w $" B LEGEND REVISIONS o • REMOVABLE TEST PLUG WELDED TEST PLUG 9 a CALiPERED TEL L TALE HOLD Shell cover Floating head .ad Channel cover - - -_._- ---- -
  • 141. ORIGINAl Tl-IICKNESS DATE 4 8 1 9 1101 11 112113 1 141 15116117 1 18119120(( Shell [;~~_~;::::~==_Temp.-== I~~~~~S II I I I I I I I I I I I I I I I I I I I I m ~ ::J: Bundle NOZZLE LOCATIONS WITl-I THICKNESS MEASURED IN 0.01 INCHES » ~~~~-1 _Temp.___ Tubes: Size _ _ Mat. _ _ _ DATE 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 I I Z C) m ~ ::~~:~al I ::a o m c (/l ~ ~ ~ ::a m ~ n o ~ ::a ~ c ~ ~ LEGEND G> REMOVABLE TEST PLUG e a [J SIDE SHOWN • WELDED TEST PLUG e TELL TALE HOLD X REVERSE SIDE REVISIONS SCAlE SHOWNDRAWN BY _ _ _ __ DRAWING NO. CHECKED BY _ _ __ DATE _ _ _ APPROVED BY _ __ ~
  • 142. 134 API RECOMMENDED PRACTICE 572 EXCHANGER INSPECTION REPORT FORM TO: DATE UNIT EQUIPMENT SERVICE RETURNED DATE OF LAST DOWNTIME TO SERVICE INSPECTION REASON INSPECTION COMMENTS MINIMUM THICKNESS LAST RETIRING ORIGINAL INSPECTION PRESENT THICKNESS SHELL SHELL COVER CHANNEL CHANNEL COVER TOP NOZZLE (SHELL) BOTIOM NOZZLE (SHELL) TOP NOZZlE (CHANNEL) BOTIOM NOZZLE (CHANNEL) TUBES RECOMMENDATIONS WORK REQUESTED BY INSPECTED BY cc: SIGNED CHIEF INSPECTOR
  • 143. INSPECTION PRACTICES FOR PRESSURE VESSELS 135 AIR COOLER EXCHANGER INSPECTION REPORT FORMNAME OF UNIT PLANT AEXCHANGER NAME B .................................................... ....................................................ORIG. ITEM NO. ~~ ~::::;: .................................................... .................................................... .................................................... .................................................... .................................................... ....................................................PLANT NO. ~~ ....................................................PLUG TYPE - REMOVABLE HEADER I ~ • 5 1·0 :0 ~ ! • ! 1·5 2·5 3·5 45DATE ORIG. EXCH. INST.DATE PREV. BDLE. INST. j~ CAUSE REMOVAL 1 5 10 15 20 25 30 35 40 45 50 t t t t t t t t t t tDATE PRES. BOlE. INST. .................................................... .................................................... ....................................................MArl HANDLED .................................................... .................................................... ....................................................DESIGN - PRESS. PSI ~==:: :::::::::::::::::::::::::::::::::::::::::::::::::::: .................................................... TEMP. "F ~~OPER. - PRESS. PSI I • : • • • • • 3~ • 4~ ! 1 10 15 20 25 30 40 TEMP. OFTUBE - MATERIAL North-South East-West -DIAMETER East-West North-South ~ ~ -THICK ~ - LENGTH 4FIN - MATERIAL II 07· THICKNESS DATA POINT NO. DATE INSP. ORIG. PREV. INT. NO. THK. MIN. 1 2 3 4 5 6INSP. & TEST DATADATEGENERAL CONDITION CHANNEL SECTION-.IUBE SECTION 5 6INSP. & TEST DATADATEGENERAL CONDITION CHANNEL SECTION TUBE SECTION FINS FAN FAN HOUSINGNO. TUBES PLUGGEDCHEMICALLY CLEANEOMAX. AlLOW. PRESS. PSI TEMP. FTEST PRESS. PSIAPPROVED - PRESS. PSI TEMP. F
  • 144. 136 API RECOMMENDED PRACTICE 572 DOUBLE-PIPE EXCHANGER INSPECTION REPORT FORM NAME OF UNIT PLANT ~ 6 EXCHANGER NAME 2 ~ 8 ORIG. ITEM NO. Pl.ANTNO. 7 ~P 3 12 0 @~ 4 SERVICE DATA 5 DATE INT. TUBE INST. DATE PREV. INT. TUBE 0 ~ INSTAlLED REMOVED " 11 CAUSE REMOVAl " I DATE EXTER TUBE INSTAlLED J REMOVED CAUSE REMOVAl THICKNESS DATA POINT NO. DATE OPERATING DATA INSP. ORIG. PREV. TYPE OF SERVICE INT. NO. THK. MIN. 1 INT. PIPE EXT. PIPE 2 STATE OF MEDIUM 3 MED. OR MArl HAND. 4 DESIGN - PRESS. PSI 5 TEMP. O F 6 OPER - PRESS. PSI 7 TEMP O F 8 9 10 11 12 13 INSP. & TEST DATA DATE INSPECTION INTERVAl lIMITlNG • INT. TUBE THK. LIMITING - A TUBE THK. GENERAl CONDITION INT. TUBE SECTION EXT. TUBE SECTION INT. TUBE MATERIAl DATE INSPECTION INTERVAl lIMITlNG • INT. TUBE THK. LIMITING - A TUBE THK. GENERAl CONDITiON INT. TUBE SECTION EXT. TUBE SECTION INT. TUBE MATERIAl EXT. TUBE MATERIAl DATE lAST INSPECTED CHEMICALLY CLEANED INT. MAX. All. • PRESS. PSI TEMP. OF EXT. MAX. All. • PRESS PSI TEMP OF INT. TEST PRESS. PSI EXT. TEST PRESS. PSI INT. EXT. INT. EXT. INT. EXT. INT. EXT. INT. EXT. INT. EXT. TUBE TUBE TUBE TUBE TUBE TUBE TUBE TUBE TUBE TUBE TUBE TUBE
  • 145. API provides additional resources and programs to the oil and natural gas industry which arebased on API Standards. For more infonnation, contact:API MONOGRAM@) LICENSING API INDIVIDUAL CERTIFICATIONPROGRAM PROGRAMS (lCP®)Phone: 202-962-4791 Phone: 202-682-8064Fax: 202-682-8070 Fax: 202-682-8348E£nail: cenification~apLorg Email: icp@api.orgAPI QUALITY REGISTRAR API ENGINE OIL LICENSING AND(APIGR@) CERTIFICATION SYSTEM (EOlCS)> ISO 9001 Registration Phone: 202-682-851 6> ISO/ TS 29001 Registration Fax: 202-962-473 9> ISO 1400 1 Reg istrat ion Email: eolcs@api. org> API Spec Ql ~ RegistrationPhone: 202-962-4791 API PETROTEAM (TRAINING,Fax: 202-682-8070 EDUCATION AND MEETINGS)Email: certi£ication~api.org Phone: 202-682-8195 Fax: 202-682-8222API PERFORATOR DESIGN Email: petroteam~api.orgREGISTRATION PROGRAMPhone: 202·682-8490 API UNIVERSITyTMFax: 202-682-8070 Phone: 202-682-8195Email: perfdesign@api.org Fax: 202-682-8222 Email: trainin~api.orgAPI TRAINING PROVIDERCERTIFICATION PROGRAM Check out the API P ublications}Programs,(API TPCPTM) and Services Catalog online at www.api.org.Phone: 202-682-8490Fax: 202·682-8070Email: tpcp@api.org en rg-f1ill Copojright 2008 - API, oll ,!ghu resefV<!d. A P~ APIITIOOOiI"m. AJ>IQR. API Spec 01. API TPCP. ICP, API Urwer31ty and the API logo ..... lIlthQr In!d,,,",,,~ or reglstetW<! trad"""rk> of APl in the Unlilld States ancIor other cou ntr ies.
  • 146. 1220 L Street. NWWashington, DC 20005-4070USA202.682.8000Additional copies are available through TechstreetPhone Orders: 1-800~99-92n (Toll-free In the U.S. and Canada) 734-780-8000 (Local and International)Fax Orders: 734-780-2046Online Orders: www.techstreet.comInformation about APt Publications, Programs and Servicesis available on lhe web al www.apLorg Product No . C57203