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  • 1. S T D - A P I / P E T R O R P L2RL-ENGL L797 m 07322911 115bBOL2 T U 2 m Recommended Practice Setting, for Maintenance, Inspection, of Operation, and Repair Tanks in Production Service API RECOMMENDED PRACTICE 12R1 FIFTH EDITION, AUGUST 1997 EFFECTIVE DATE: OCTOBER1,1997 American Petroleum 1 InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 2. ~ STD.API/PETRO RP L 2 R L - E N G L 1997 D 0 7 3 2 2 7 0 05bBOl13 9q9 W Recommended Practice for Setting, Maintenance, Inspection, Operation, and Repair of Tanks in Production Service Exploration and Production Department API RECOMMENDED PRACTICE 12R1 FIFTH EDITION, AUGUST 1997 EFFECTIVE DATE: OCTOBER 1,1997 American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 3. SPECIAL NOTES API publications necessarily address problems of general nature. With respect partic- a to ular circumstances, local, state, and federal laws and regulations should be reviewed. API is not undertaking to meet the duties of employers, manufacturers,or suppliers to warn and properly train and equip their employees, and others exposed, concerning health and safety risks and precautions, nor undertaking their obligations under local, state, or federal laws. Information concerning safety and health risks and proper precautions with respect to par- be ticular materials and conditions should obtained from the employer, the manufacturer or or supplier of that material, the material safety data sheet. Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or prod- uct covered by letters patent. Neither should anything contained in the publication be con- strued as insuring anyone against liability infringement of letters patent. for Generally, API standards are reviewed and revised, reaffirmed, or withdrawnevery at least five years. Sometimesa one-time extension of up to two years will be added to this review cycle. This publication will no longer be in effect five years after its publication date as an operative API standard or, where an extension hasbeen granted, upon republication. Status of the publication can be ascertained f o the API Authoring Department [telephone rm (202) 682-8000]. A catalog of API publications and materialsis published annually and updated quarterly by API,1220 L Street, N.W., Washington, D.C.20005. This document was produced under API standardization procedures that ensure appropri- ate notification and participation in the developmental process and is designated as an API standard. Questions concerning the interpretation of the content of this standard or com- ments and questions concerning the procedures under which this standard was developed should be directed in writing to the director the Authoring Department (shown on the title of page of this document), American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. Requests for permission to reproduce or translate or any part of the material all published herein should also addressed to the director. be API standardsare published to facilitate the broad availability of proven, sound engineer- ing and operating practices. These standardsare not intended to obviate the needfor apply- ing sound engineering judgment regarding whenandwherethese standardsshould be utilized. The formulation and publication of API standards is not intended in any way to inhibit anyone from using any other practices. Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible for complying all the applicable with requirements of that standard. API does not represent, warrant,or guarantee that such prod- ucts do in fact conform to the applicable API standard. All rights reserved No part of this workmay be reproduced, storedin a retrieval system, or transmitted by any means,electronic, mechanical, photocopying, recording, otherwise, or without prior written permission from the publisher Contact the Publisher; API PublishingServices, 1220 L Street, N. W ,Washington,D.G. 20005. Copyright O 1997 American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 4. STD.API/PETRO RP LER1-ENGL L977 D 0 7 3 2 2 7 0 05bAOL5 711 W FOREWORD This API recommended practice is under the jurisdiction of the A P I Subcommittee on Standardization of Field Operating Equipment. This fifth edition is a reformatted reissue of the 1991 fourth edition, which was reaffirmed by 1996 letter ballot. This recommended practice provides guidelines for (a) setting and connecting of lease tanks at new tank battery installations and in other production and treating service, (b) main- taining and operating lease tanks, and (c) inspecting and repairing tanks constructed in accordance withA P I 12 series (B, F and P) standards. D, Changes adoptedin the fourth editionof this recommended practice address both techni- cal and environmenWsafety issues. Major technical revisions included(a) development of tank inspection criteria and scheduling intervals, (b) adoption of repair recommendations, and (c) inclusion of a sectionaddressing spill preventioncontrolandcountermeasures (SEC). A numberoffederal, state, and local environmental and safety regulations affect the design and the operationof storage tanks utilized in production operations. In preparing this recommended practice, the following safety and environmental concerns were addressed: a. Personal safety assurance. b. Prevention of catastrophic failure. c. Prevention of operational mishaps, such tank overflows. as d. Minimization of the potential for leaks. The environmental statutes and regulations affecting the operation of lease facilities are constantly evolving. Individuals utilizing this document should review federal, state, and local regulationsto determine whether the practices recommended in document are con- this sistent with current laws and regulations. This recommended practice shall become effective on the date printed on the cover but may be used voluntarily from the of distribution. date API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to assure the accuracy reliability of the data contained in them; however, the and Institute makes no representation, warranty, guarantee in connection with this publication or and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation any federal, state,or municipal regulation with which of this publication may conflict. be Suggested revisions are invited and shouldsubmitted to the directorof the Exploration and Production Department, American Petroleum Institute,1220 L Street, N.W., Washing- ton, D.C. 20005-4070. iiiCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 5. CONTENTS page 1 SCOPE.............................................................................................................................. 1 2 REFERENCES................................................................................................................. 1 3 DEFINITIONS................................................................................................................. 2 SElTlNC AND CONNECTING TANKS 4 RECOMMENDED PRACTICE FOR ....... 3 4.1 Setting of New or Relocated Tanks ........................................................................ 3 4.2 Proper Measurement and Sampling Oil in Tanks Used for of Measurement and Providingfor Storage Efficiency .............................................. 3 4.3 Delivery of Measured Quantities to Pipeline Tanks Used in for Measurement ..................................................................................................... 4 4.4 TankIntegrity .......................................................................................................... 4 5 RECOMMENDED PRACTICE FOR A F E OPERATION AND S SPILL PREVENTION OF TANKS ................................................................................ 5 5.1 OperatingSafety ..................................................................................................... 5 5.2 SpillPrevention ....................................................................................................... 7 6 RECOMMENDED PRACTICE FOR EXAMINATION, INSPECTION, AND MAINTENANCE OF TANKS .............................................................................. 7 6.1General .................................................................................................................... 7 6.2 Maintenance ............................................................................................................ 8 6.3 Routine Operational Examination .......................................................................... 8 6.4 External Condition Examination ............................................................................ 8 6.5 Internal Condition Examination ............................................................................. 9 6.6 InternaYExternal Inspections .................................................................................. 9 6.7 Inspection Techniques ........................................................................................... 10 6.8 Shell Welds ............................................................................................................ 11 6.9 Records.................................................................................................................. 11 7 RECOMMENDED PRACTICE FOR ALTERATION OR REPAIR OF TANKS ...... 11 7.1 vpes of Repairs .................................................................................................... 11 7.2 Preparation of Tank for Repairs............................................................................ 11 7.3 Minimum Thickness and Material Requirement of Replacement Shell Plate.... 11 7.4Weld Joints ............................................................................................................ 11 7.5 Alteration of Tank Shells to Change Shell Height ............................................... 12 7.6 Repair of Shell Penetrations................................................................................. 12 7.7 Hot Taps ................................................................................................................ 12 7.8 Leak Detection on Bottom Replacement .............................................................. 12 7.9 Reconstructionof a Dismantled Tank................................................................... 12 7.10 Required Hydrostatic Testing ............................................................................. 12 7.1 1 Nameplates .......................................................................................................... 13 APPENDIX A RECOMMENDED QUALIFICATIONS FOR QUALIFIED INSPECTORS AND COMPETENT PERSONS .................................... 15 APPENDIX B EXAMPLE CALCULATIONOF VENTING REQUIREMENTS ....... 17 APPENDIX C INDUSTRY OBSERVATIONS AND EXPERIENCES ON SHELL CORROSIONAND BRIITLE FRACTURE ........................... 19 VCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 6. ~ STD.API/PETRORPL2RL-ENGL L777 0 7 3 2 2 9 0 05bBOL7 59Ll m Page APPENDIX D CHECKLIST FOR EXTERNAL CONDITION EXAMINATION 21 ...... APPENDIX E CHECKLIST FOR INTERNAL CONDITION EXAMINATION 25 ....... APPENDIX F MINIMUM THICKNESS FORTANK ELEMENTS........................... 29 APPENDIX G CHECKLIST FOR EXTERNAL INSPECTION .................................. 31 APPENDIX H CHECKLIST FOR INTERNAL INSPECTION ................................... 37 APPENDIX I FIGURES AND DIAGRAMS................................................................ 43 Figures 1 Example of Straight Line Tank Battery Installation and Piping Configurations ..45 2 Example of Small-Volume Shop-Welded Tanks Foundation and Connection Configurations.................................................................................... 46 3A Example Tank Battery Installation Showing Dikeirewall and Example Piping Configuration ............................................................................... 47 3B Example Tank Battery Installation Top View Showing Dikepirewall and Example Piping Configuration ........................................................................ 48 4 Corrosion Calculation Nomenclature .................................................................... 49 Tables 1 Internal Tank Examinationhnspection Schedule..................................................... 8 2 External Tank Examinationhnspection Schedule .................................................... 8 F- 1 Summary of Minimum Thickness for Tank Elements .......................................... 30 viCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 7. STD.API/PETRO RP 22RL-ENGL 2 7 7 7 m 0732290 0 5 b A O L A 420 m Recommended Practicefor Setting, Maintenance, Inspection, Operation, and Repair of Tanks in Production Service 1 Scope 2 References 1.1 This recommendedpracticeshould be considered as a This recommended practice includes reference, either by in guide on new tank installations and maintenance of existing total or in part,the most recent editions the following stan- of tanks. It contains recommendations for good practicesin (a) dards, unlessa specific editionis listed: the collection ofwell or lease production, (b) gauging, (c) API delivery to pipeline carriers for transportation, and (d) other production storage and treatment operations. In particular, the Spec 11N Lease Automatic Custody Transfer(LACT) spill prevention and examinatiodinspectionprovisions of this Equipment recommended practice should be companion to the spill pre- Spec 12B BoltedTanks for Storage ofProduction vention control and countermeasures (SPCC)prevent envi- to Liquids ronmental damage. Spec 12D Field Welded Tanksfor Storage of Produc- tion Liquik This recommended practice intended primarily for appli- is Spec 12F Shop Welded Tanksfor Storage of Produc- cation to tanks fabricatedto API Specifications 12F3, D,F, and tion LiquirLF P (sometimes called the API 12 series document) when in this Spec 12P Fiberglass Reinforced Plastic Tanks employed in on-land production service; but its basic princi- Bull D16-1974 Suggested Procedure for Development of ples are applicable atmospheric tanks of other dimensions to Spill Prevention Control and Countenea- and specifications when they are employed in similar oil and sures Plans gasproduction,treating,andprocessingservices.It is not applicable to refineries, petrochemical plants, marketing bulk W 0 Classtjication of Locations for Electrical 50 Installationsat Petroleum Facilities stations,orpipelinestoragefacilitiesoperated by carriers. T n s fabricated to API Standard or its predecessor (API ak 650 RP 520 Sizing, Selection, and Installation of Pres- sure-RelievingDevicesinRejîneries, Part Standard 12C) should be maintained in accordance with API 1, "Sizing and Selection" Standard 653. Std 650 Welded Steel Tanks Oil Storage for 1.2 This document recommends maintenance practices Std 653 Tank Inspection, Repair; Alteration, and basedontheestimated corrosion rate life ofvarioustank Reconstruction components. Corrosion rate of tank components willvary life Std2000 Venting Atmospheric and Low-Pressure widely with location, environment, service, type fluid, and of StorageNonrefrigerated Tanks: and corrosion mitigation techniques elected by the ownedopera- Refrigerated tor. Recommendations for specific corrosion mitigation tech- Std 2003 Protection Against Ignitions Arising Outf o niques are not within the scope of this document. For such and Static, Lightning, Stray Currents recommendations, see publications of the National Associa- Publ 2009 Safe Welding and Cutting Practices in tion of CorrosionEngineers (NACE) (see Section 2). Refineries,Gasoline Plants, and Petro- chemical Plants 1.3 This documentcontainssomespecificsafetyrecom- RP 2015 Safe Entryand Cleaning of Petroleum Stor- mendations applicable to tanks. For complete safety recom- age Tanks,PlanningandManagingTank mendations, see publications of the API Committee on Safety Entry Decommissioning From Through and Fire Protection. Recommissioning 1.4 The schematic drawings included in this publication are Publ 2207 Preparing Tank Bottom for Hot Work examples only of some features described in the document. Publ 2210-1982 Flame Arresters for Vents of TanÆ Petro- Numerous variations in piping systems andtank components leum Products are knowntogive satisfactoryservice.Unusualgrades of EnvironmentalDocument: Guidance crude, particularly heavier grades, may cause the ownedoper- Onshore Waste Solid Management in ator to elect other equally satisfactory practices. Exploration and Production Operations MPMS, Chapter 6.l-"Lease Automatic 1.5 Leaseautomaticcustodytransfer(LACT)operations Custody Transfer (LACT) Systems" are covered in API SpecificationlN, and in the API Manual 1 MPMS, Chapter 8.1-"Manual Sampling of Petroleum Measurement Standards, Chapter 6.l. of Petroleum and Petroleum Products" 1COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 8. 2 PmcncE 12R1 API RECOMMENDED NACE 3.10condition examination (internallexternal): A RP-01-78 Design, Fabrication, and Surface Finish of review of history and physical observation of a tank and its Metal Tanks and Vessels to be Lined for adjacent equipmentby a competent person. Chemical Immersion Service 3.1 1 corrosion rate: Estimated or measured rate metal of RP-05-75 Design, Installation, Operation,andMain- less due to corrosion. tenance of Inteml CathodicProtection 3.12 corrosion rate life: The corrosion rate life of a tank System in Oil Treating Vessels is definedas follows: SPEz (Tcurrent - Tminimum 1 Petroleum Handbook Corrosion Rate Life (years) = corrosion rate (inchedyear) 3 Definitions Where: For the purposes this standard, the following definitions of T, ,, , = the thickness, in inches, measured at the time of apply inspection for the limiting section used in the 3.1 alteration: Anywork doneonatankwhichdeparts determination. from the original design and includes changes in size, shape, = Tmhim,,,,, the minimum allowable thickness, in inches, Ïor or structural members. the limiting section zone. or 3.2 applicable standard for alteration: The applica- 3.13 frangible deck A tank in which the roof deck is ble standard for alterationis the latest revision of the origi- designed to fail under pressure loading. For design criteria, nal API specification. seeAPISpecification 12D. Frangibledecksmayalso be called weak seamconstruction. 3.3applicablestandardforinspectionorrating: Any tank covered this recommended practice may be rated by 3.14hottap: Aprocedureforinstallingappurtenances or inspected either the original specification under which it by penetrating the shell deck of a tank that is in service. or was built or, at the option of the ownedoperator, the latest 3.15 inspection (internallexternal): A detailed inspec- revision of the same specification. tion to appraise the suitability for service of a tank including 3.4 applicable standard for repair: For design, materi- sufficient measurements to estimate its remaining corrosion of als, workmanship, and testing any new piece or part added be rate life. Inspections shall done only by a qualified inspec- to the tank, the applicable standard latest revision the is the of tor. Inspections are categorized in the following four ways: original API specification. For original parts, see applicable a. Scheduled inspections: Routine inspections performed at standard for inspection or rating. intervals specified by the ownedoperator based on the corro- 3.5 atmospheric pressure tank: tank designed for A sion rate life of the class of tanks. internal pressures up to, but not exceeding,2% pounds per b. Unscheduled inspections: Inspections prompted by results square inch gauge in the vapor space above the contained obtained from a condition examination or by an operational liquid. alert. 3.6change in location: Anyrelocation or within c. Externalinspections:Inspectionsmadewithouthuman between fields, units, or plants. entry or visual inspection of internal parts. d.Internalinspections:Inspectionswhichrequirehuman 3.7 change in service: A change from previous operating entry or visual inspection of internal parts. conditions involving different properties of the stored product, such as specific gravity, corrosivity, temperature, or pressure. 3.16 operational alert:Any operational malfunction of a tank which may signal a potential deterioration. 3.8classof tank Classificationfora group oftanks according to service,coatings,corrosionmitigationtech- 3.17 owner/operator: The legal entity having both con- niques, locale, and setting. trol of and/or responsibility for operation and maintenance of 3.9competentperson: Aresponsibleindividual,des- an existing storage tank. ignated by the owner/operator, who is capable of recogniz- 3.18 potentialdeterioration: Potentialdeterioration is ing existing and predictable hazards. Recommended indicated by a warning sign of deterioration. This warning qualifications for a competent person are given Appendix in may be obtained from corrosion coupons or fluid analysis and A of this document. may indicate the need for a condition examination of a tank. 3.19 qualified inspector: An individualdesignated by NACEInternational, P.O. 218340, Houston, Texas 77218. Box Engineers, P.O. Box 833836, *Society of Petroleum Richardson, Texas the owner/operator has the technical to read and 75083-3836. measurement employ and specifications API understandCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 9. RECOMMENDED PRACTICE FOR SElTlNG, MAINTENANCE, OFTANKSP O U n N SERVICE INSPECTION, OPERATION, AND REPAIR IN R D CO 3 toolsrequired to evaluatetechnicalcompliancewiththe c. Ensure that any fluids leaking through the bottom of the specifications. Recommended qualifications are presented in tank will drain to the perimeterof the tank rather than pene- Appendix A. trate the soil and/or groundwater. 3.20 reconstruction: Theworknecessarytoreassemble 4.1.5 The foundation sub-base shouldbe well-graded, com- a tank that has been dismantled and relocated to a new site. pacted soil. If the soil is not sufficiently impermeable to pre- vent migration of fluids into soils below the tank, a plastic 3.21 roufine operationalexamination: visual A sheet or other barrier to liquid should placed over thesub- be examination made by operators or technicians during their base to provide an impermeable barrier. Thesubbase should routine attendance at a facility to determine the occurrence of be raised at the center the tank to facilitate drainage toward of an equipment malfunction or a tank leak. No written record the perimeter. Drainage should be providedawayfrom the of a routine operational examination need be kept unless an tank. equipment malfunctionor tank leakis detected. 4.1.6 The foundation base should be made of gravel, shell, 4 Recommended Practicefor Setting and sand, concrete, or other material that facilitates drainage and Connecting Tanks provides structural support. A retainer ring may be used to 4.1 SElTlNG OF NEW OR RELOCATEDTANKS confine loose material and to facilitate detection of liquid drainage from below the tank. 4.1.1 The location of tanks should be selected after consid- 4.1.7 The foundation should be level at the circumference ering operationalneeds, canier requirements, prevailing ofthetankandgreaterthanthetankdiameterunlessa winds,environmentalandsafetyconditions,andalllocal, used. Level bases are required for tanks which retainer ring is state, and federal regulations governing such locations. are used for measurement of produced liquids. 4.1.2 Tanksshouldbeconstructedinaccordancewiththe 4.1.8 Ifaretainerring is used it and doesnotextend following: or beyond the diameter of the tank, small seep holes tell-tale a. API Specification 12B. devices shouldbe provided as a means for visible leak detec- b. API Specification 12D. tion and drainage. c. API Specification 12F. d. M I Specification 12P 4.2 PROPER MEASUREMENT AND SAMPLING OF OIL INTANKS USED FOR MEASUREMENT 4.1.3 Tank spacingshouldcomplywithlocal,state,and AND PROVIDING FOR STORAGE EFFICIENCY federal regulations. In general, tanks should be located in a straight lineas shown in Appendix I, Figure. The minimum l 4.2.1 All lease tanks should be set and maintained as level shell-to-shell spacing for personnel access betweentanks is and as free of distortion as possible. Inlet and outlet connec- 3 feet (91 centimeters) with spacing adjusted so that pipe tions shouldbe located so as to cause level settlement basic of headers can be prefabricated to standard patterns. If tanks sediment during filling or draining. are set with pipeline connections facing one another, suffi- cient space should provided between tank shells safely be to 4.2.2 The main hatch (thiefor gauge) shouldbe of standard afford proper inspection and operation of valves and other size as shown in API 12 Series tank specifications, and should appurtenances. Personnel access to all piping connections be located in the roof deck adjacent to the top chime directly for operations, inspection, and maintenance should be con- above the pipeline outlet except in the following situations: sidered in the design. Appendix I, Figure 2 shows examples a. Where a connection is provided with an upturned ell or of small shop welded tanks with foundation and connection other appurtenance inside the shell the tank. of configurations. AppendixI, Figures 3A and 333 show exam- b. Where wet-oil (oil with basic sediment and water content ples of battery installations with piping configurations when above pipeline specifications) is encountered. dikedfirewalls are used. The recommendations for barriers, or c. Where sample cocks LACT units are used for sampling. valves, drains, vents, and the like shown in these figures are discussed in more detail in the remainder of this recom- In the cases described in 4.2.2, Items a, b, and c, a mini- mended practice. mum of 6 feet (1.8 meters) circumferentially should separate the main hatch and the pipe outlet. If an auxiliary hatch is 4.1.4 Thefoundation of atankshouldbedesignedand necessary as a second point to measure the settled basic sedi- installed to do the following: ment and water content, it should be located diametrically a. Support the tank that it will remain level and elevated. so across from the main hatch. b. Drain rainwater away from the base and bottom of the Gauging or striking plates should installed at or near the be tank so as to keep the underside as dry possible. as bottom chime, directly below the gauging hatch, the innage ifCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 10. ~ ~ S T D - A P I I P E T R O R P L 2 R L - E N G L L777 m 0732290 0 5 b 8 0 2 L T L 5 m 4 API RECOMMENDED PRACTICE 12R1 method of gaugingis used. These plates should be attached to 4.3DELIVERY OF MEASUREDQUANTITIES the tank shell and must be set level and anchored. TO PIPELINE INTANKS USED FOR MEASUREMENT 4.2.3 The pipeline connection should be located in the tank shell at a height so that the bottom of the pipe ell (firmly 4.3.1 The carrier’s gauger should be able, through observa- anchored) or other fitting the inside of the tank is a mini- on tion and sealing, assure that the carrier has complete control to mum of 12 inches (31 centimeters) above the tank bottom. In of the tankcontents, while sameare being run to the pipeline. cone-bottom tanks, the connection may be6 inches (15 centi- 4.3.2 The valves on the pipeline outlet, the drain line, the meters) above the bottom chime of the tank. A valve equipped filling line, and the equalizer line should of a reliable type be with a tamper-proof sealing device should be installed in this and design and equipped with adequate sealing devices. line immediately adjacent to the tank. 4.3.3 The drain line, if it does not empty directly into an 4.2.4 Except for tanks having frangible decks, the fill line opendrainordraw-offtrough,shouldbeprovidedwith a may be located either through the deck near the tank shell or means for assuring inspection that its valve does not leak. may be introduced into the side of the tank at, or about, the Such a visible check usually consists of a tee with bullplug height of the pipeline outlet. Downcomer inlet lines may be located adjacent to the valve. It should be accessible at all selected as an option by the operator to reduce rolling or agi- times, in other words, it should be kept permanently free from tation of the stored liquids and may be required by some car- dirt, rock, and other obstructions. riers. When installed, such lines should extend down to below the nominal low-liquid level. They should be vented with at 4.3.4 All pipeline valves should be provided with an inde- least two %-inch(1.27-centimeter)holesdirectlybelowthe pendent means, such as a block-and-bleed system, to insure roof deck to permit gas to escape and to as siphon breakers. act that they seal properly. 4.2.5 For cylindrical tanks, the drain line should be located 4.4 TANKINTEGRITY in the tank shelladjacent to the bottom chime and not be less 4.4.1 Tank integrity is required to provide economy, safety, than 2 inches (5.1 centimeters) in nominal pipe size. For cone and environmental protection. bottom tanks, it may be located either in the bottom adjacent to the tank shell or in the center of a cone bottom. When 4.4.2 Welded tanks should be liquid and vapor tight. placed adjacent to the shell, it should be located a minimum New MI Specificationl2B bolted tanks should be either of 6 feet (1.8 meters) and preferably 180 degrees from the hydrostatic or pressure tested on site prior to being put in ser- main hatch. This line should have a valve equipped for seal- vice to assure that they are pressure tight. If hydrotested, the ing and be installed adjacent to the tank. roof should be pressure tested up to the maximum allowable working pressure. 4.2.6 The equalizer connection, any, should be located in if Welded or fiberglass tanks should be tested in accordance the shell no closer than 12 inches (31 centimeters) from the with the procedures outlined in A P I Specifications 12D, 1W, top chime.This line should have valve equipped for sealing, a and 12P. which is readily accessible from the walkway. 4.4.3 In low-resistance soils where electrolytic action may 4.2.7 Steamcoilsorhotwatercoils, ifused,shouldbe be prevalent, the corrosive effect on tank should be mini- the installed inside the tankin a manner which will not interfere mized by providing vapor barrier, external coating, cathodic with measurements taken through the main or the auxiliary protection, andor electrical isolation. hatch, and the inlet and the outlet lines should have valves installed adjacent to the tank shell. 4.4.4 In corrosive fluid or sour gas service, corrosion of a tank’s interior can be significantly reduced by the proper 4.2.8 Sample cocks, ifused,shouldbeinstalledinaccor- application of a corrosive resistant material to the sur- dance with API Manual of Petroleum Measurement Stan- faces affected and by the installation of sacrificial anodes. &&, Chapter 8.1. Test cocks should be installed 4 inches The use of sacrificial anodes without internal coating of (10 centimeters) below the bottom of the pipeline connec- the tank usually results in a very short anode life and is tions.Theyshould be located a minimum of 6 feet(1.8 not recommended. A properly designed cathodic protec- meters) distance circumferentially from the pipeline outlet tion system to NACE RP-05-75 that penetrates the water and the drain line connections and 8 feet (2.4 meters) from phase should be installed and maintained to prevent cor- the fill line connection. All sample cocks should be equipped rosion at the coating holidays. Shortened anode life, due with non-leaking valves, plugged inspection tees and tamper- to higher operating temperature, should be accounted for proof sealing devices. Lines from all cocks should extend a in the initial design, and internal inspections should be minimum of 4 inches (10 centimeters) inside the tank. scheduled accordingly.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 11. STD.API/PETRO RP L2R1-ENGL 1777 m 0732270 0 5 b 8 0 2 2 751 R RECOMMENDED INSPECTION, OPERATION,REPAIR PRACTICE FOR SETTING. MAINTENANCE, AND IN SERVICE OFTANKSPRODUCTION 5 A good quality coating such as coal tar, epoxy, polyester, 4.4.7 If hydrogensulfide(H$)ispresentinthesystem, phenolic, or fiberglass-reinforced plastic should be used, and one should consider using vent piping made from nonferrous the surface preparation and application should be inaccor- materials, special alloys or internally coated steels to help dancewith NACE "01-78,orSteel StructuresPainting preventelementalsulfurorironsulfide (Fes) deposition Council (SSPCY Standards.Experiencehasshownthat a problems. If fiberglass-reinforced plasticis used, it shouldbe major key to obtaining good coating protection lies in ade- properly supported anda 2-foot (61-centimeter) long section quately preparing the underlying surface. Prior to applying of steel pipe should be installed on the open end. This steel any coating material, the surface should be inspected to assure pipe shouldbe electrically connectedto the tank shell. that itis clean and blasted the proper standard. to Tank decks should be internally coated if the tank is used 4.4.8 Flame arresters, if installed, should be connected to in sour gas service or whenever oxygen ingressis likely (for the venting system and should be installed consistent with the example, tanks withouta gas blanket or tanks handling oxy- recommendations presented in API Publication 2210. genated water). Special construction techniques can be used 4.4.9 A vacuum relief valve is recommended for all tanks. for reducing tank corrosion in corrosive sour service. One or However, for tanks over 3000 barrels in volume and other such technique is the placement of rooffdeck beams on the tanks subject to local regulations,a pressure-vacuum valveis outside of rooffdeck. the This technique also facilitates required on the vent line or connection.This valve should be inspection in seismically active areas. large enough to prevent rupture or distortion of the tank due If a tank contains both steam coils and an internal coating, to temperature change or during filling or emptying opera- the coils should be located at a sufficient distance from the tions as determined by theAPI 12 series tank specifications or surface to avoid coating damage. in API Standard 2000. 4.4.5 Protective coatings suitable for the environment at the Pressure-vacuum valves must be selected to provide for location should be applied to the exterior of the tank using normal inflow and outflow venting at an outlet pressure less acceptable surface preparation and application techniques. than the thief hatch exhaust pressure and at inlet pressure an greater than the thief hatch vacuum setting. Pressure regula- 4.4.6 All hatches, connections, other and access points tors on vapor recovery systems or gas blanket systems, any, if should be vapor tight. Connections and cleanout plates should must be set at values consistent with those set for the pres- be capable ofholdingpressureinexcessofthepressure- sure-vacuum valves and the thief hatches avoid loss of gas to relieving device. If the tank fluids contain hydrogen sulfide or blanket ortank rupture. the recommended gas blanket must be maintained, then a spring-action thief hatch with an appropriate envelope gas- 4.4.10 Pressure-vacuum valvesmust be located the at ket such as a Viton@ or B, or equivalent, material should A highest pointin the ventline, and the line must not containa be used. liquid trap. Normal or primary venting through the vent connection. is Individual tank vents or combined vent systems for multiple 5 Recommended Practice for Safe tanks may be employed. This connection may be located con- Operation and Spill Prevention Tanks of veniently in thetank or, except for tanks having dome covers installed with loose fitting long bolts, this connection be may 5.1OPERATING SAFETY located in the dome cover. Tanks in some installations may require additional pressure relief devices for emergency vent- 5.1.1 Normalabovegroundoperationsof tanks should be accessible from platfoms and walkways. Tank decks, plat- ingduringpotential exposure fire against exterior. the Requirements are specified in the appendixes of the API 12 forms, and walkways and the area around the, tanks should be kept cleared of accumulation of oil, basic &bent, and sur- 2000. series specifications and API Standard If required, such devices may take the formof larger or additional vent valves, face water. thief hatches, or dome covers having loose-fitting bolts. All 5.1.2 Themaingaugehatch,valves,andotherappurte- primary and auxiliary venting devices including thief hatches nances requiring personnel access for operation or mainte- should be kept in good working order. nance shouldbe made accessible from elevated platforms and Thief-hatch-sizing requirements and sample calculations walkways which provide clear walkingiworking surfaces so are presented in Appendix B. These are basedon the Society that personneldo not have to walk on roofs or decks. of Petroleum Engineers Petroleum Handbook, API Recom- mended Practice520, and the requirements API Specifica- of 5.1.3 Elevatedplatforms,walkways,andstairwaysshould tion 12D. meet OSHA and API tank standards. 3Steel Structures Painting Council, 4400 Fifth Avenue, Pittsburgh, Pennsyl- 5.1.4 Piping, walkways, platforms, and so forththatmust vania 15213. rest onor against the tank shell deck shouldbe secured to it. orCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 12. 6 PwcncE 12R1 API RECOMMENDED 5.1.5 The pipeline valve, the drain valve, and the test or d.Flaming. inspection locations should accessible from a firm nonskid be e.Grinding. walking surface whichis free of obstructions and above nor- f. Painting around spark-producing equipment. mal levels of rainwater accumulation. If a firewall or dike is g. Acetylene cutting. built, it should be traversed by this walking surface, which should lead to the gauging platform stairwaywell as to the as h.Sandblasting. lower level valves and check points. Soldering. i. j. Torching; 5.1.6 Allconnections to openingsintheroofdeck,for k. Any other potentially spark-producing operations. example, filling line and vapor vent or breather line, should be located so that theydo not interfere with opening and clos- 5.1.1 1 Fired equipment located within150feet (46meters) ing of hatch lids or access to thief or gauge hatches. of an atmospheric tank or a thief hatch, should be equipped III with flame arrestors except where Class liquids are stored 5.1.7 NO SMOKING signs should be displayed appropri- (See API Recommended Practice 500). Location of perma- ately at points in facilities where there controlled access or is nent fired equipment must comply with local, state, and fed- boundary fencing.Where accessnot is controlled, NO eral regulations. be SMOKING signs should visible from normal road path- or way approach. 5.1.12 Rapid removal of liquid from an atmospheric stor- 5.1.8 Tanksinstalledforproductionandstorage of crude age tank presents the possibility of tank collapse. This may oil that contains toxic or poisonous gases, as H,S, should such occur even if a vent or thief hatch is installed but is notprop erlysized(SeeAppendix have signs posted at all entries to the facility and at the bottom B). Theownedoperatorshould entry of all stairways leading up to gauge hatches warning of develop safe liquid transfer procedures to prevent any poten- the presenceoftoxic or poisonoussubstances.Approved tial fillindemptying problems. breathing apparatusshould be used in accordance with OSHA regulations. 5.1.13 Grounding or bonding of leasetankbatteriesfor crude oil and produced water is not normally required for 5.1.9 Tanksareclassified as confined spaces withinthe tanks placed directly on the ground without heavy electrical OSHA regulations and warrant special attention before per- insulation. For storage and transfer of refined products such sonnel are allowed to enter. A permit system should be estab- as diesel, gasoline, circulating oils, and forth, at a produc- so lished prohibits that personnel (ownedoperator and/or tionfacility,groundingshould be providedinaccordance contractor) from entering the tank until the atmosphere has with API Standard 2003. been tested for hydrogen sulfide, oxygen deficiency, explosiv- Grounding practice and cathodic protection practice must ity, and the presence of any substance, such as benzene, for be consistent to avoid corrosion effects. which an exposure limit has been published. Special proce- dures should be developed and implemented to assure per- 5.1.14 Downcomerpipesfortopfillinletlinesarenor- sonnelsafetyprior to enteringanyconfinedspace.These mally optional in crude oil and salt water tanks. However, procedures should address items such as respiratory protec- they are recommended for tanks storing refined liquids while tion, standby personnel, and lockouthag-out procedures. steel downcomer pipes may be used to reduce the potential forstaticchargeaccumulationsin API Specification 12P 5.1.10 Atmospheric tanks used in the oil and gas industry tanks (See API Specification 12P). For additional information present a significant explosion hazard if ignition sources are see API Standard2003. introduced inan uncontrolled fashion. Operations which tem- porarily employ open fires, automotive and welding equip- 5.1.15 Inlightning-proneareas,lightningstrikes of mas- ment, internal combustion engines, open and dripproof sive size are a cause of tank battery fires and explosions. A electric motors should be prohibited inside dikes or firewalls properly designed and installed lightning protection system and in any area 50 feet (15.2 meters) from sources of vapor may reduce the occurrence of explosions and fires due to release from undiked tanks oil accumulations without spe- or lightning strikes in the vicinity of the tank. Personnel should cial permissionof the owner/operator. The owner/operator of not mount tanks during thunderstorms. a tank should establish a hot-work permit system prior to allowing any hot work be performed on any tank. Hot work 5.1.16 The opening of tanks and equipment that have con- to should be defined to include the following: tained H$ can result in spontaneous combustion due to the presence ofFes. Recognition ofthis potential ignition source a. Arc welding. is important in planning work in gaseous areas.To minimize b.Cad welding. problems, the use of nonferrous pipe to prevent iron sulfide c.Chipping. formation in vent areas may considered. beCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 13. ~ S T D . A P I / P E T R OR P L Z R L - E N G L 1777 0732290 05bB02LI 724 RECOMMENDED INSPECTION, OPERATION, AND REPAIR PRACTICE FOR SETTING, MAINTENANCE, OFTANKSPRODUCTION SERVICE IN 7 5.2SPILLPREVENTION and guidelines established in this document. The owner or operator should have the option of employing, within the lim- 5.2.1 A reviewlocal, and of state, federal regulations itations of the jurisdiction, appropriate any engineering, should be made to determine spill prevention requirements. inspection, recording and systems. The program should An evaluation of spill prevention requirements and measures include provisions for the safety of the inspector and any should be made on a site-specific basis. other personnel, and should consider the difficulty or impos- If a formal spill prevention plan is requiredby regulation, sibility of entry into small tanks. API Bulletin D-I6 should be consulted for guidance. Regard- less of regulatory requirements, Bulletin D-16 contains rec- 6.1.2 Manyfactorsmust be evaluatedwhendetermining ommendations for spill prevention that can utilized at any be the suitability of an existing tank for continued service or for facility includes and sections secondary on containment achange of service,orwhenmakingdecisionsinvolving (dikes), facility drainage, high-level alarms, and flowline and repairs, alterations, dismantling, relocating, or reconstructing facility inspection. an existing tank. These factors include the following: 5.2.2 Dikes or firewalls shouldbe constructed to contain, at a. Internal corrosion due to the product stored or water cor- a minimum, the volume of the largest tank enclosed plus an roding the bottom. allowance for rainwater (normally, percent additional tank 10 b. External corrosion due to environmental exposure. volume). The diked area should be impervious in order to c. Stress levelsand allowable stress levels. containspilledoiluntilitcan be cleanedup.Theground d. Properties of the stored product such as specific gravity, enclosed by the dike should sloped so as to drainany water be temperature, and corrosivity. away from tanks, and it should be kept cleared of any accu- e. Metal design temperatures at the service location of the mulations of oil, basic sediment, and water. tank. A pipe drain, used, shouldbe provided at the lowest point if f. External roof life, wind, snow, and seismic loadings. to permit draining accumulations of storm water. This pipe drain should have a locked-closed valve outside the drainage g. Tank foundation, soil, and settlement conditions. area to ensure proper containment control of fluids other and h. Chemical analysis and mechanical properties of the con- than storm water. Other substances, suchsaltwater, oil, and as struction materials. basic sediment spilled within the diked area should be dis- i. Distortions of the existing tank. posed of properly. API Environmental Guidance Document, j . Operating conditions, such filling or emptying rates and as Onshore Solid Waste Management in Exploration and Pro- frequency. duction Operations, as well as applicable regulations, should be consulted when disposing of these substances. Additionally, combinations any ofthese factors together of with pressure due to fluid static head, internal and external 5.2.3 In the event dikes are not practical, the area around pressure,nozzle loads, attachment loads, and settlement the tank should be sloped as to drain into a pit, catch basin, so should be included as part of the evaluation. or sump system. This is to reduce the possibility of to damage General industry observations and experience with shell adjacentproperties or pollutionofponds,streams,rivers, corrosion and brittle fracture are included in Appendix C. bays, and so forth. 6.1.3 The fitness for purpose and structural integnty of a 5.2.4 The owner/operator establish should operating tank are important assure its long-term, leak-free condition. to practices or installleveldetectionalarms to circumvent As such, both internal and external observations required. are potentialoverflowor other operationalproblems. If this These observations are divided into examinations and inspec- cannot be done consistently, then proper level control sys- tions. The examinations are conducted knowledgeable and by tems are recommended. trained field operations personnel. There are two classifica- tions for examinations. The first is done routinely oper- by the 6 RecommendedPracticefor atorsofthebattery.These are called routine operational Examination, Inspection and examinations. The second classification of examinations are Maintenanceof Tanks called conditions examinations. These examinations can be doneinternallyandexternally.However,theseinspections 6.1 GENERAL require a person who is more highly skilled and knowledge- able. This person called acompetentperson. is 6.1.1 The owners or users of tanks should have an ongoing inspection program that will assure their tanks have sufficient Conditioninspectionsarealsodoneinternallyorexter- integrity for normal service without any undue expectation of nally. These inspections require the most highly skilled and endangering workers, the public, or the environment. A a s trained personnel. Usually, the condition inspections should minimum,theprogramshouldmeettherecommendations need to be done only after the competent person conducts anCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services ~~
  • 14. Table I-Internal Tank Examination/lnspection Schedule Scheduled By Whom WhenCondition examination person a tank is: Competent inspector or qualified a. Cleaned for normal operations. b. Transferred to a new location. c. Service of a tank is changed more than years after an inspection. 5 d. Entered for any type of maintenance modification. or Condition inspection AtQualified ofrate end of Y2 corrosion inspector life.pe Unscheduled By Whom Condition examination results When from an extemal condition examination warrant it. or Competent person qualified inspector Condition inspection warranted When by results of condition examination. Qualified inspector Table 2-External Tank ExaminatiorVlnspection Schedule Scheduled T y p Frequency By Whom Routine operational examination At least once a month. Field personnel, technicians Condition examination Once ayear. Competent personor qualified inspector Condition inspection As determined from corrosion rate but more thanI5 years after not Qualified inspector construction. Unscheduled S p e Frequency Whom By Condition examination or When operational alert, malfunction, shell deck leak,or potential Competent person qualified inspector or bottom leak is reported as a result of operational examination. an Condition inspection When warranted by results condition examination. of Qualified inspector examination, and it is determined that more detailed assess- a vention control and countermeasures ( S E C ) as outlined in ment of the tank’s integrity required. is API Bulletin D-16. Appendix A lists the various qualifications for a competent The ownedoperator should establish procedures for visual person and a qualified inspector. examinationandreportingofequipmentmalfunctions or A summary of the typesof observations, the frequency, and leaks (routine operational examination), identified by opera- the associated personnel qualifications are shown in Tables 1 tional personnelor technicians during their routine attendance and 2. Table 1 shows the schedule summary external exam- for at a facility. 2 inations and inspections. Table shows the schedule summary At a minimum, routine operational examinations should be for internal examinations inspections. detailed and The made at least once a month for any in-service tank. Written requirements associated with each oneof these examinations/ records need not be retained except leaks or operational for inspections are presented in the remainder this section. of alerts. 6.2 MAINTENANCE 6.4EXTERNALCONDITIONEXAMINATION Theowners/operatorsoftanksshouldhave a preventive 6.4.1 An externalconditionexaminationmay be done on maintenance program to assure tank integrity for normal ser- either a scheduled or unscheduled basis: vice without undue expectation of endangering workers, the public, or the environment. a.Unscheduled: An external condition examination should Specific programs are at the option of the owner/operator, be made by a competent person when an operational alert, but should include draining of bottom water and/or sediment, malfunction, shell or deck leak, or potential bottom leak is replacement of gaskets, replacementof seals, inspection sac- of reported as result of a routine operational examination. rificial anodes, and repair of coatings and linings as required. b. Scheduled: An external condition examination should be performed at least once a year by a competent person for any 6.3ROUTINEOPERATIONALEXAMINATION in-service tank. A proper level of surveillance of all properties is recom- 6.4.2 This examination should include a visualinspection mended for efficient and prudent operations and for spill pre-of the tankexterior surface check for leaks, shell distortion, to COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 15. RECOMMENDED PRACTICE FOR SElTlNG. MAINTENANCE, INSPECTION. OPERATION, AND REPAIR OFTANKSPRODUCTION SERVICE IN 9 and evidence of corrosion and to determine the condition of A suggested checklistfor internal condition examination is the foundation pad, drainage, coatings, cathodic protection (if shown in Appendix E. Summary results of the general 3rd- any), and appurtenances and connections. The need for addi- ings from an internal condition examination shouldbe tional detailed inspections measurements and should be retained for a period of five years unless superseded by a determined from the results of this examination. Leaks are newer internal condition examination summary report. not acceptable while the tank is in service. Extensive corro- sion and/or pitting should be further evaluated for possible 6.6 INTERNAUEXTERNAL INSPECTIONS repair. External and internal inspections may be scheduled by the A suggested checklist for an external condition examina- ownedoperator based on the corrosion rate life of the tank tion is presented in Appendix D. and should be performed by a qualified inspector. Internal Summary results o the general findingsf i m an external f inspections should be done by safety isolating, cleaning, and condition examination should be retained a period of not for ventilating the tank in accordance with API Recommended less than five years or until superseded by a newer extemal Practice 2015; also thetankbottomwould be preparedin condition examination summary report. accordance with API Publication 2207, as applicable. 6.5INTERNALCONDITIONEXAMINATION 6.6.1DevelopmentofCorrosionHistory 6.5.1 An internalconditionexaminationmay be doneon Tank ClassificationI either a scheduledunscheduled For examina- or basis. either Tanks may be divided into classes depending ontheir tion situation, the tank should safely isolated, cleaned, and be physicalconstruction,setting,environment,liquidservice, ventilatedinaccordancewithAPIRecommendedPractice lining, protection coating, type of internal cathodic protec-~ 2015: tion, chemical inhibition, and other factors which impact cor- a. Unscheduled: An unscheduled internal condition examina- rosion rate life. tion should be made by a competent person when an opera- Experience has shown that tanks can be roughly divided tional alert or potential bottom leakis reported asa result of a into the following eight generic classes with regard to corro- routine operationalexamination or an external condition sion protection, and canbe further subclassified according to examination. the type of fluid stored (crude oil or producdwater-flood b. Scheduled: A scheduledinternalconditionexamination supply water), and geographical location (high plains, wet- should be made, as a minimum, for the following events: lands, etc.). The eight generic classes as follows: are l . When a tank is cleaned for normal operational require- a. Lined with cathodic protection with gas blanket. a ments. b. Lined with cathodic protection without gas blanket. a 2. When there is a change in location or ofa tank. c. Lined without cathodic protection with gas blanket. a 3. When the service of a tank is changed more than 5 d. Lined without cathodic protection withoutgas blanket. a years after a detailed internal inspection. e. Unlined with cathodic protection witha gas blanket. 4. When the tank is entered for any type of maintenance f. Unlined with cathodic protection withouta gas blanket. or modification. g. Unlined without cathodic protection with gas blanket. a 6.5.2 Whenever ownership/operatorship a tank changes, of h. Unlined without cathodic protection without blanket. a gas thenew ownedoperator should obtain the original records and files on the tank. If adequate records are available, the not Determination of Corrosion Rate new ownedoperator should consider performing an internal For a given class of tanks, corrosion rates may be either examination. predicted, basedonoperational experience,ordetermined 6.5.3 This visualexamination of the tankinteriorshould from measurements made from sampling tanks of the same include checks for leaks, shell distortion, cracks, condition of class and similar service. any coating, evidence of the nature and severity of internal The following roof deck and shell corrosion rates can be corrosion, evidenceof damage to the structural supports and determined from external ultrasonic measurements. Tank bot- rafters, and condition cathodic protection system. of tom corrosion rates can be determined by a variety of meth- ods. These include following the internal external and Results fromthis examination may determine theneed for techniques. an additional detailed internal inspection or may result in a it conclusion to either repair or to replace the tank without fur- a. Internal: ther detailed internal inspection (See 6.7 for detailed inspec- 1. By external ultrasonic measurement on the one-foot- tion techniques). wideannularring at theshell-bottomconnection, at a COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 16. 10 PRACTICE API RECOMMENDED 12R1 minimum of eight areas around the tank Appendix I, (see The inspection may be either external or internal depending Figure 4). on the location of the suspected flaw. 2. By resultsobtainedfromscheduledinternalinspec- b. Scheduled inspections: tions. 1. The timing of scheduled external or internal inspec- 3. By analysis of historical field data. tions should be based on the predicted corrosion rate life b. External: of the tank given by the formula: as l . By external examination at eight areas on the one-foot- ( tcurrent - ?minimurn 1 Corrosion Rate Life (years) = wideannularringattheshell-bottomconnection(see corrosion rate (inchesbeur) Appendix I, Figure 4). As a minimum condition, inspections should occur at the 2. By results obtainedfromscheduledexternalinspec- beginning of the last quarter of the predicted life when a tions. minimum required plate thickness is still in place. 3. By analysis of historical field data. 2. Minimum required thicknesses for various tank ele- Whenever possible, field measurements should be ments are shown in Appendix These are based on struc- F. used to establish the corrosion rates used for determining tural integrity considerations anda remaining 5-year tank inspectionintervals.However,intheabsenceofhistorical life. Thus, the calculated minimums are based on the cor- data, published reports APIor other operators be used by may rosion rate for the tank. The minimum acceptable thick- to establish or to support initial corrosion rate estimates, but ness is the critical element thickness before the tank is theseshouldbeverified or revised as soon as fielddata scrapped or repaired. becomes available. These criteria are suggested for individual lease tank batteries, but the owner/operator may elect to modify these 6.6.2 Critical Sample Size Necessary to Determine criteria for other services or environments. These mini- Corrosion Rate mumvalues are suggestedforpurposes of inspection. They should not be construed as limit values for either The number of tanks which should be included to deter- acceptance or rejection of a tank in any specific service. mine the corrosion rate for a generic class and subclass corro- 3. Following a scheduled inspection, adjustments in cor- sionconditionshould be basedonasufficientnumberof rosion rate life predictions should be made based on the randomly selected tanks so as to be statistically significant. new findings. However, it should be noted that localized corrosion rates at 4 External inspection intervals should not exceed three- . holidays in lining of tanks without cathodic protection may fourths of the predicted shellhoof deck corrosion rate life be difficult to predict. for any class of tanks or a maximum of years. 15 5 . Internal inspection intervals should not exceed three- 6.6.3 Extent of Physical Measurements fourths of the predicted corrosion rate life of any class For the purposes of this document, a measurement of at of tanks, least 2 percent of the critical area willconsidered the mini- be mumphysicalcoveragenecessarytodeterminecorrosion 6.7INSPECTIONTECHNIQUES rates. Individual rates should be determined for individual construction members (bottom, shell chimes, roof deck, and 6.7.1 External,ultrasonicthicknessmeasurements of the so forth). These measurements can be done by a variety of shell canbe a meansof determining a rate uniform general of ways. These ways include, at a minimum, dividing the area corrosion while the tank is in service, and can provide an into a square grid and making at least one measurement at indication of the integnty of the shell. The extent of such each grid point or inspection of the critical one-foot-wide measurements should be determined by the owner/operator annular ring,by dividing this into grids and inspecting a suffi-based on the corrosive environment and previous known cor- cient number of locations to equal the minimumof two per- rosion ratesat the location. cent of the total area. Asuggested external condition inspection checklist is included in Appendix . G 6.6.4 Inspection Schedule 6.7.2 Internal inspection is primarily required to the fol- do Recommended schedules for tank inspections are as fol- lowing: lows: a. Ensure that the tank bottom and internal piping are not a. Unscheduledinspections:Inspectionsarerequired if a severely corroded and leaking. leak, near a through-wall pit, or severe roof deck corrosion is b. Gather the data necessary for the minimum bottom and observed during a condition examination (internal/external). shell thickness assessments. As applicable, these data shouldCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 17. also take into account internal and external ultrasonic thick- b. Epoxy or fiberglass-reinforced plastic for limited areas of ness measurements made during in-service inspection. roof deck holes or thin sections in non-highly stressed smc- c. Identify and evaluate any tank bottom settlement for tanks tural areas. that are used for fluid measurement. c. Bolted patches, steel, or plastic plugs of permanent con- d. Evaluate tanks for stresses associated with bottom settle- nection type. ment. d.Boltedorthreaded-type tank flangeswithbull-plugsor e. Evaluate rate of corrosion of. the roof and the corrosion blinds. rateassociatedwiththetankstructuralsupportssuch as e. Various of typescommercial devices which feature rafters and center poles. mechanical connectionsof sufficient strength consistent with f. Evaluatethedegreeofcorrosionprotectionprovidedby tank structural requirements. cathodic protection and/or internal coatings. 7.1.2 Selection of a particularrepair methodconsistent A suggestedInternalConditionInspectionchecklist is withanticipated requirements tank is an ownedoperator included in AppendixH. option. 6.8 SHELLWELDS 7.1.3 Temporary repairsshouldbecorrected, at owner’s/ operator’s convenience, to permanent repairs within a two- The corrosion condition of the tank shell welds should be year time periodunless the tank removed from service. is visually evaluated to determine their suitability for continued service, the requirement for the use of other nondestructive Note: Rberglass orepoxy-reinforcedplasticpatches are not an accepted structural repair for steel t n s ak. inspection, or for their needfor repair. 7.2PREPARATIONOFTANKFORREPAIRS 6.9 RECORDS Prior to performinganyinteriortankrepairs, the tank be Records should maintained by the owneror user of tanks should be safely isolated, cleaned, and ventilated in accor- from the date adoption ofthis recommended practice by the of dance with API Recommended Practice2015. If hot work is owner/operator. These records should contain pertinent data required, tank bottoms should prepared in accordance with be reports, tank identification, relief equipment test information, API Publication 2207. and documents recording the results of inspection and repairs. Information relativeto the tank integrity, such corrosion for as 7.3 MINIMUM THICKNESS AND MATERIAL associated or similar systems, should be included. Records REQUIREMENT OF REPLACEMENT should demonstrate that repairs are consistent with the service SHELL PLATE and appropriate codes.All basic data may, at the option of the The minimum thickness and material of the replacement ownedoperator, be maintained by the classof tank rather than shellplateshouldmeettheminimumrequirementsofthe on an individualbasis.After the adoptionof this recom- original standard used for construction and should be less not mended practice, repairs and inspections should be recorded than the greatest nominal thicknessof any plate in the same on an individual basis. Inspection records should be retained courseadjoiningthereplacementplate,exceptwherethe with permanent equipment records. adjoining plateis a thickened insert plate. 7 Recommended Practice for Alteration 7.4WELD JOINTS or Repairof Tanks 7.4.1 Welding and Inspection Requirements 7.1TYPES OF REPAIRS The following welding and inspection requirements apply: Alteration or repair of tanks should be made whenever the results of inspection indicate alteration or repairs are neces- a. Welding on M I Specificationl2B bolted tanks is not rec- sary. n u s , leaks, structurai damage, or minimum thickness ommended. criteria shown in Appendix F summary table not being~met b.Welding consumablesshouldconformtotheAmerican should require repair unless the projected servicelife is less Welding Society(AWS)4 Classification applicable to the than the remaining tank life. intended use. c. New weld joint details should meet the welding require- 7.1.1 Storage tanks may be repaired without welding or hot ments of the current revisionofthe applicable standard. work by various forms of patching and reinforcementinclud- ing the following: d. All welding and inspection should be done by qualified personnel. a. Epoxy or fiberglass-reinforcedplasticliners for bottom and shell leak repair. ‘ mra Welding Society,550 N.W.LeJeune Road, Miami, Florida 33135. A ei n cCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 18. S T D - A P I I P E T R O RP LZRL-ENGL L777 0732270 05b8027 20b m 12 API RECOMMENDED PRACTICE 12R1 7.4.2RepairofWelds 7.7HOTTAPS The following applies to weld repairs: 7.7.1 Preparationsfor hottapsshould be madeinaccor- a. Cavities resulting from gouging or grinding operations to dance withAPI Publication 2009. remove weld defects shouldbe examined by visual and mag- 7.7.2 Welding tanks on containing flammableliquids or netic particleor liquid penetration methods. produced water should be restricted to locations below the b. Completed repairsof butt-welds should be examined over tank liquid level unless the has been made completely inert. A theirfulllength by visualandradiographic or ultrasonic lower explosion limit (LEL) of zero is required in the welding methods. environment. Tank liquid level should be monitored during c. Completed repairs of fillet welds should examined over be welding to assure that welding below the liquid level. How- is their full length visual and magnetic particle or liquid by pen- ever, before welding below the liquid level of tanks contain- etration methods. ingflammableliquids,ultrasonicthicknessmeasurements 7.4.3 Acceptable Criteria for Existing Shell Plate to should be made toensure the welding arc will not bumholea New Shell Plate Welds through a badly corroded area, releasing and ignitinga stream of flammable liquid. The following acceptable criteria applies for existing shell plate to new shell plate welds: 7.8LEAKDETECTIONON BOTTOM a. If the radiograph or ultrasonic inspection results of an REPLACEMENT intersection between a new and old weld reveals unac- When planning a tank bottom replacement, consideration ceptable welds by current standards, the existing welds should be given to removing the old bottom or providing a may be evaluated according to the original standard of means of preventing galvanic corrosion and/or shielding of construction. cathodic protection. When a tank bottom is replaced from b. Shell replacement plates should be welded with butt joints inside the tank, a means for visual leak detection should be with complete penetration and complete fusion. A lap-welded included in the refurbished unit. a second bottom is added If patch plate may be used to repair an individual pit or pin hole- to the tank, for example, an impervious barrier (plastic sheet type leak subject to ownedoperator approval provided that it or cement layer) should installed over the old bottom be tank meets the following conditions: andsloped to drain liquids to the tank perimeter.Holes, l . It is designed as a reinforcing plate. spaced no more than 10 feet (3 meters) apart should be drilled 2. The fillet welds join the plate to an existing plate@) into thetank shell immediately above this barrier. having good structural integrity. 7.9 RECONSTRUCTION OF A DISMANTLED TANK 7.5 ALTERATION OFTANK SHELLSTO CHANGE SHELL HEIGHT 7.9.1 Prior to reconstruction of a dismantled tank, all inter- nal and external parts should be inspected, and parts found Tank shellsmay be altered by adding new plate materialto defective should be replaced. increase the height of the tank shell.Themodifiedshell height should be in accordance with the requirements of the 7.9.2 Any reconstructed tank should be in accordance with applicable standard andshould take into considerationall the latest version ofthe applicable standard. anticipated loadings. 7.9.3 After repairs,alterations, andlor reconstruction is completed, internal any or externalcoatingsshould be 7.6 REPAIR OF SHELL PENETRATIONS repaired if required for corrosion prevention in the current service. 7.6.1 Repairs of existingshellpenetrationsshould be in compliance with the applicableM I Standard. 7.10REQUIREDHYDROSTATICTESTING 7.69 Reinforcing plates may be added internally or exter- 7.10.1 A full hydrostatic test held for 12 hours should be nally for the repair of unreinforced or leaking nozzles. or performed on altered reconstructed tanks. 7.6.3 Welding performed on plate that has been exposed 7.102 A fullhydrostatictestheldfor 4 hours should be to H,S may require specialwelding procedures. performed on a repaired tank. 7.6.4 Welding on tanks which contain flammable fluids is 7.10.3 Hydrostatictesting maybewaivedby the owner/ not recommended unless the tank is isolated, drained, and operator in cases where minor repairs have been made in steamed. Also, tests for combustibilityshould be made prior accordance w t the applicable standard and the welds have ih t welding. o been nondestructively examinedt validate their integrity. oCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 19. ~~~ ~ ~ ~~ 7.11 NAMEPLATES e. Nominal shell height. Weldedor fiberglass tanks reconstructed in accordance f.Nominalcapacity. with this standard should be identified by a corrosion-resis- g. Bottom thickness. tant metal plate. Letters and numerals not less than %-inch h. Shell thickness. high should be embossed, engraved, orstamped in the name i. Design pressure. plate to indicate information follows: as j. Shellmaterial. k. Owner/operator tank designation, if applicable. a. Reconstruction t appropriate W 12 series specification. o 1 b. Reconstruction contractor. be The applied nameplate should consistent in design with c. Year reconstruction was completed. the applicable stan- that in current use in the latest revision of d. Nominal diameter. dard.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 20. APPENDIX A-RECOMMENDED QUALIFICATIONS FOR QUALIFIED INSPECTORS AND COMPETENT PERSONS A.l Qualified Inspectors d. Repair welding. e. Foundation evaluation andtank settlement. Qualified inspectors should have education and experience equal to at least one of the following: f. Repair and alteration methods. g. Material corrosion considerations. a. A degreeinengineeringplus 1 yearofexperiencein h. Hydrostatic and leak testing. inspection of tanks or pressure vessels. i. Dismantling and reconstruction. b A 2-year certificate in engineering or technology from a . j. Safetyconsiderations. technical college, and 2 years of experience in construction, k. Structural considerations. repair, operation, or inspection, of which one year must inbe 1. Nondestructive inspection techniquessuch as radio- inspection of tanks or pressure vessels. graphic, ultrasonic, magnetic particle, liquid penetrant, and c. The equivalent of a high school education plus three years acoustic emission. of experience in construction, repair, operation, inspection, or of which one year mustbe in inspection of tanks or pressure m. Record keeping. vessels. A.2 Competent Person In addition to working knowledge of this document and APISpecifications12B, D, F and P, a qualifiedinspector Competentpersonnelfor tank conditionexaminations should have experience in, knowledge of, or training in the should have education and experience equalthe following: to following ae s r a: a. A high school graduateor equivalent. a. Internal and external inspection. b. A minimum of 5 years of oil field production experience. b. Tank, shell, andbottom evaluation. c.Knowledgeandunderstandingof therequirementsand c. Brittle fracture. recommendations in document. this 15COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 21. APPENDIX B-EXAMPLE CALCULATION OF VENTING REQUIREMENTS Required EmergencyVting Area of Common Thief Hatches Without drainage, when thetank does not havea frangible deck5 and the wetted surface area is less than or equal to 2800 Size ID Area (in?) square feet (260 square meters): 8-inchcm) round (20 44 (284 cm2) Q, = 1107Ao.82 8 inch X 18 inch (20 X 46 cm) cm 130 (839 cmz) With drainage, when the tank does not have a frangible 8 inch x 22 inch (20 cm x 56 cm) 154 (994 cm2) deck and the wetted surface area is than or equal to 2800 less square feet(260 square meters): Note: cm = centimeten; ID = inside diameter; in. inches. = Q, = 553 Ao." For wetted surfaceareas greater than 2800 square feet (260 Example Problem: square meters), set wetted surface, A , equal to 2800 square TankVpe H-500 Steel bolted feet (260 square meters). Diameter 15 feet 4% inches Where: Height 16 feet 1 inch Design Conditions Q, = required venting rate,ScF/Hr (cubic feet of free air Pressure 3 ounces per hour at F and 14.7 psia). W Vacuum LA ounce A = wetted surface (square feet). Reduction Due to Addition of Insulation calculations: Required Insulation How Maximum VentingPressure: P,= = 1.5 x 3 ounces = 4.5 ounces 1 inch 0.300 Q, 2 inches O. 150 Q, WettedArea: 0.075 inches 4 Q, nDL = IC X 15.385 X 16.083 = 777.35 fi* Thief Hatches Emergency Venting Capacity: Q, = 833 A (Pi, - p0ut)0.5 Q, = 1107 X (777.35)0.82 259,689 ft2 = Where: Capacity of Inch X 22 Inch Single Thief Hatch: 8 Q, = required venting rate,SCFMr (cubic feetof free air per hour at W F and 14.7 psia). - Pi, P,,, = 45/16x 27.72 = 7.8 inches of water A = hatch area (square inches). Q, = 883 X 154 x (7.8)0.5 379,777 ft2 = Pi, = absolute pressure insidetank (inches of water). P,,, = absolute pressure outside tank (inches water). of Result Maximum AllowablePressure During Venting Only one thief hatch required. is P,,,, = 1.5 x Design Pressure (Gauge) Note: These requirements provide for venting during exposure fire against an the lower chime exterior surface. A complete listingof venting nquirements for any size tank is included in the appendix of the individual API series 12 ih requirements. wt frangible decks meet emergency venting specification. 17COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 22. ~- ~ S T D - A P I I P E T R OR PL Z R L - E N G L L777 0732290 05b8033 737 APPENDIX C-INDUSTRY OBSERVATIONS AND EXPERIENCES ON SHELL CORROSION ANDBRllTLE FRACTURE C.1 Shell Corrosion that all governing requirements for repairs, alterations, recon- Shell corrosion occurs in many forms and varying degrees struction, or change in service are in accordance with this of severity and may result a generally uniform loss of metal in standard (including a need for hydrotesting major after over a large surface area or in a localized area. Pitting may repairs, modifications, or reconstruction). The effectiveness also occur. Each case must be treated as a unique situation of the hydrostatic test in demonstrating fitness for continued and a thorough inspection conducted to determine the nature service is shown by industry experience. and extent of corrosion prior to developing a repair proce- b. If a tank shell thickness is no greater than 0.5 inch (1.27 dure. Pitting does not normally represent a significant threat centimeters), the risk failure due to brittle fractureis mini- of to the overall structural integrity a shell unless present ina of mal, provided thatan evaluation for suitabilityof service has severe form with pits in close proximity to one another. How- been performed. The original nominal thickness the thick- for ever, pitting corrosion isa primary reason for tank leaks and be est tank shell plate should used for this assessment. may result in subsequent underside corrosion. Criteria for c. The thickest plate for an API 12 series tank is less than evaluatingbothgeneralcorrosionandpittingaredefined the 0.5 inches (1.27 centimeters),whichis the necessary below. thickness to induce brittle fracture. This critical wall thick- Widely scattered pits that do not effect the structural integ- ness is confirmed from actual production experience. Thus, rity of thetank may be ignored provided following: the brittle fracture is not a concern for API 12 series tanks unless they are operatingin arctic service. a. No pit depth results in the remaining shell thickness being d. An evaluation can be performed to establish a safe operat- less than one-half the minimum acceptable tank shell thick- ing envelope for a tank based on the past operating history. ness exclusive ofthe corrosion allowance. This evaluation should be based on the most severe combina- b. Their dimensions along any line does not exceedinches 2 tion of temperature and liquid level experienced by the tank an (5.1 centimeters) in 8-inch (20-centimeters) length. during its life. The evaluation may show that the tank needs to be rerated or operated differently; several options exist. These C.2 Brittle Fracture options include the following: The following concerning fracture: applies brittle 1. Restrict the level. liquid a. Forthepurposeofthis assessment,hydrostatictesting 2. Restrict the minimum metal temperature. demonstrates that an aboveground atmospheric storage tank 3. Change the service to a stored product with a lower in a petroleum or production service is fit for continued use specific gravity. and at minimalrisk of failure dueto brittle fracture, provided 4. Combinations of the precedinga, b, and c. 19COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 23. APPENDIX D-CHECKLIST FOR EXTERNAL CONDITION EXAMINATION 21COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 24. STD.API/PETRO R P L2RL-ENGL L977 m 0 7 3 2 2 9 0 05b8035 5 0 T PRACTICE FOR &lTlNG. MAINTENANCE, RECOMMENDED INSPECTION. OPERATION, AND REPAIR OFTANKSPRODUCTION IN SERVICE 23 Checklist for External Condition Examination ldsndflcadon lank Designation: Size: Date of Inspection: Level: Measured or Estimated Liquid Contents: Foundation Tank Properly Supported Y ESMO Grade RlnglFoundation Structurally Sound YESIN0 Tank Bottom Visible Signs of Leakage Around Tank Bottom YESMO Adequate Drainage Away From Tank YESNO Tank Shell Active Leaks YEW0 If Yes, Number & Location Signs of Past Leakage If Yes. Number & Location Structural Integrity (Distortions, Warping) YESNO If Yes, Type & Location Coating C n t nSatisfactory od o i Y ES/NO If No, Type & Location Severe Corrosion and/or Pits Y ESIN0 If Yes, Type & LocationCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 25. ~~ S T D . A P I / P E T R O R P L 2 R L - E N G L 1777 W 0 7 3 2 2 7 0 05bA03b L(qb W 24 API RECOMMENDED A T E 12Rl P CI R C Checklist for External Condition Examination (Continued) Roof Deck Hdes YESMO If Yes, Number & LocationDeck Adequate off of Y ESMO Coating YESMO If No, Type & Location Severe If Yes, Type & Location AppurtenancsslMiscellaneous Thief Hatch and Vent Valve Seals Air Tight YESMO Gas Blanket System Operational (If Applicable) YESMO StaiwaydWalkwaysStructurally Sound Y ESMO Proper Warning Signs Place in Y ESMO Dikes Maintained YESMO or Gas If Fiberglass Tank, All Metal Parts Bonded Blankcd Operatio n a l YESMO Tank Area Clear of Trash & Vegetation YESMO Cathodic Protection System Operational Y ESMO Piping Properly Supported YESMOCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 26. APPENDIX €-CHECKLIST FOR INTERNAL CONDITION EXAMINATION 25COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 27. PRACTlCE FOR %l"lNG, MAINTENANCE, INSPECTION. OPERATION. AND REPAIR RECOMMENDED OFTANKS IN PRODUCTION SERVlCE 27 Checklist for Internal Condition Examination ldentlfication Tank Designation: size: Date of Inspection: Measured or Estimated Liquid Level: Contents: Tank Shell Any Visual Leaks or Cracks Y ESNO If Yes, Number& Locationoblems Any Integrity Structural (Distortions or Warping) YESNO If Yes, Number& Location Coating ConditionSatisfactory YESMO If No, Type & Location Internal Corrosion (Severe P t ) is YESNO If Yes, Type& Location Roof Deck Hdes YESMO I Yes, Number& Location f Coating ConditionSatisfactory YESNO If No, Type & Location COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 28. 28 API RECOMMENDED PMCE 12Rl Checklist for Internal Condition Examination (Continued) Severe Corrosion and/orPits YESMO If Yes, Type & Location Structural Supports or Rafters Damaged YESMO If Yes, Type & Location AppurtenanwolMiocellaneous Cathodic Protection Systemsstisfactory Y ESMO If No, Location & ProblemCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 29. APPENDIX F-MINIMUMTHICKNESS FORTANK ELEMENTS F.1 Introduction to be used in the preceding equation are presented in the fol- lowing: The following minimum thickness criteria for predicting the corrosion rate life of API Specification12 D, and F tank B, a. Isolated individual pits: elements is intended to pr0vide.a safety factor of at least 5 T,, is equal to 5 years times the corrosion rate. yearsofremaininglife.See Figure 4 (inAppendix I) for b. Tank bottom: nomenclature. 1. Critical annular ring area: 7;is equal to T,, or a minimum of 0.062 inches. 0.50 F.2 Procedure 2. Primary bottom thickness: F.2.1 STEP #I T? is equal to5 times the corrosion rate or minimum of a 0.05 inches. For API series steel 12 standard tanks, determine an c. T n shell ak acceptable design thickness at the end of corrosion rate of life 1. Ring#l: the tank using the following equation for Minimum Thick- T, is equal to0.75 T,, or a minimum of 0.062 inches. ness Calculation for API Standard 653. 2. Rings #2 and #3: TZ and T,3 values are equal to T, or a minimum of 0.50 , 0.062 inches. d. Tank roof deck Where: 1. Areas where personnel access is permitted only with Tmin= acceptable minimum thickness in the lowest foot walkboards or reinforcement. of the shell as used in the prediction of corrosion T, is equal to 5 years timesthe corrosion rateor a mini- rate lifeof the tank in inches. mum of 0.05 inches. D = nominal tank diameter in feet. 2. Areas wherepersonnelaccess is permittedwithout H = height of high liquid level above bottom in feet. walkboards, or reinforcement. G = design specific gravity of stored liquid. T is equal to0.090 inches. , E = joint efficiency: Any area of 100square inches with a thickness of less than 0.090 inches should be repaired. 1.00 for corroded plate in bolted tanks and cor- roded plate away from welds weldedtanks. in e. Center pole and rafters. These members must retain suffi- cient structural integrity to support dead and live loads 20 of 0.70 for unknown efficiency of welds. poundsfsquare foot. 0.85 or 1.O0for radiographed welds in accord with normal design practice for the class, service, and Except for major foundation failuremajor seismic activ- or manufacture of the tanks. ity failure, API design center poles and rafters rarely fail prior S = 0.80E to roof or bottom failure. However, frequently rafter bolting Y = specified minimum strength yield (A-36 steel failures (with subsequent falling rafters) occur concurrently plate, or better, is used in most modern API 12 with, or prior to, roof or bottom failure. Inspection intervals series tanks). based on roofdeck, shell, and bottom failure should normally provide adequate information assure the structural integrity to Note: This formula permits calculation of thickness at 80 percent of yield strength, which exceeds normal design practice for mechanicaland structural of these members. elements in production facilities. It is intended foruse in API Recommended Practice 12R1 to predict useful corrosion It is NOT intended to serve a life. as F.2.4 STEP #4 design criteria for new features as a sole acceptance/rejection criteria. or The working equation for computing the corrosion life rate F.2.2 STEP #I2 of a given tank element is as follows: Obtain estimates for, or whenever possible, data supporting the annual corrosion rate for isolated pits, roof deck, shell, and tank bottom each class of tanks. for (Teum, - Tmidmum) Corrosion rate life (years) = Corrosion rate (incheslyear) F.2.3 STEP #3 The resultant corrosion rate life is used to establish the For the tank elements shown on Figure 1 (Appendix the I), remaining life and recommending inspection interval forthe suggested corresponding remaining minimum thickness,Tmh, tank. 29COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 30. 30 API RECOMMENDED PRACTICE 12R1 Table F-l-Summary of Minimum Thickness for Tank Elements Absolute Calculated Element T Minimum Minimum *pits lsolated SXCP 0.050 inch Bottom Critical annulus Tb 0.50 T 0.062 inch Primary section Tb2 5XCP 0.050inch Shell Ring It1 T2 T 0.062 inch Rings #2+3 T:, : T 0.50 T 0.062 inch Roof deck No access T : SXCP 0.050 inch Wlth access T, 5XCP 0.090 inch rate. aApplicable corrosion COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 31. APPENDIX G-CHECKLIST FOR EXTERNAL INSPECTION 31COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 32. PRACTICE FOR SElTINO, MAINTENANCE, RECOMMENDED INSPECTION. OPERATION. AND REPAIR OFTANKS PRoWCTloN SERVICE IN 33 Checklist for External Inspection Idemtification Tank Designation: Size: Date of Inspection: Measured or Estimated Liquid Level: Contents: Foundation Tank Shell Adequately Supported YESMO Tank FloorLevel (No Differential Settlement) YEW0 Signs of Sdl or Foundation Failure (Major Tank Settlement) YESMO Grade RinglfoundationStructurally Sound YESNO Adequate DrainageAway from Tank YESMO Tank Bottom Visible Signsof Leakage Around TankBottom YEW0 BottomlshellConnection Freeof Cracks & Leaks YESMO Tank Shell Tank Shell Patches YESMO If Yes, Number& Location Tank Shell Abnormalities/Distorlitions YEW40 If Yes, Number & Location of Visible Signs Hdeskeaks YESMO If Yes, Number8 Location Cracks or Seepage in Seam YEmO IfYes, Number 81Location Cracks in ShelVRoof Seam Y E W If Yes, Number & Location condition of ExternalCoating of Uninsulated Tanks, Hdes, Disbanding, Deterioration, Discoloration Number & LocationCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 33. ~ ~~ STD.API/PETRO RP LZRL-ENGL L971 m 0 7 3 2 2 9 0 0568044 5 1 2 m 34 API RECOMMENDED PRACTICE 12R1 Checklist for External Inspection (Continued) C n t nof Insulation Protection Insulated Tanks, Shell Material (HdesITears). Number od o i of & Location Seal AroundRoof/ShellJoint (Separations). Number Location & ~~~ ~ ~ ~~ _______~ _ _ _ _ ~ ~ ~~~~ Seal Around Appurtenances (Separations). NumberLocation & External Corrosion YEW0 Tank BdtrRivets Corrosion YESMOM If Yes, Number & Location Tank Fiberglass Delaminated YEWNOMA If Yes, Number & Location Results of Ultrasonic Measurements In Vapor Zone In Liquid Zone Tank Roof Deck Hatches Securely Closed YEWNOMA Roof Patches Y ESMO If Yes, Number & Location Roof Deck AbnormalitieslDistorlitions YESMO If Yes, Number & Location Visible Signsof Holeskeaks YEW0 If Yes, Number & LocationCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 34. RECOMMENDED CEFOR SElTlNG. PRACTI MAINTENANCE, INSPECTION. OPERATI N.AND REPAIR O OFTANKSPROOUCTION CE IN SERVI 35 Checklist for External Inspection (Continued) Deck External Corrosion None, Minimal, Moderate, Severe YEWNOAdequate off of Deck Deck, Holes, Disbonding, Deterioration, Discoloration Condition of External Coating of Uninsulated Number & Location Condition o Insulation Protection of Insulated Deck f Roof Material (Holeflears). Number & Location & Location Seal Around Appurtenances (Separations). Number ~ ~~ ~ ~~~ ~~ Results of Ultrasonic Thickness Measurements. (Compare Original to Values) Results of Hammer Tests Appurtenances Thief Hatch8, Vent Valves Seal Properly YESNO Thief Hatch Opens Freely W/O Plugging YEW0 Vent Valve Operational YES/NO Sample & Drain Valves Leak YES/NO Inspect Nozzle Seams for Cracks YEWNO Piping, and the like, Properly Supported of Tank Off YEWNO Tank Shell Dimpling Connections at YESNO Metal Appurtenance Bonded Gas Blanket OR Operational on Fiberglass Tank YES/NO/NA Stairways &Walkways Structurally Sound YESNOCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 35. 36 API RECOWENDEDPRACTICE12R1 Checklist for External Inspection (Continued) Miscellaneous cathodic Protecthl operati n*tenti i o a Adequate YEWNOMA Vapor Recavery System Operational YESINOM Gas Blanket System Operational YESINOM Containment Dikes and/or Liner Maintained Adequate Size & Y€S/NO/NA Proper Warning Signs inPlace YESNO Automatic Level IndicatorOperational& Accurate (Compare to Hand Gauge Level) Y€S"A Tank Area Clean of Trash & Vegetation YEWNO Recommended Futute ActionCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 36. APPENDIX H-CHECKLIST FOR INTERNAL INSPECTION 37COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 37. RECOMMENDED PRACTICE SElTING, FOR INSPECTION, OPERATI N, AND REPAIR MAINTENANCE, O OFTANKS PRODUCTION SERVICE IN 39 Checklist for Internal Inspection Identification Tank Designation: Size: Date of Inspection: Measured M Estimated Liquid Level: Contents: Pre-Inspection Tank Properly Cleaned YEW0 Tank Atmosphere Properiy Tested YEW0 Tank Properly Isolated YEW0 Tank Structurally Sound YES/NO Confined Space Entry Procedure Implemented YESMO Tank Bottom Floor Adequately Supported (Limited Voids Under Floor Plate) YESIN0 Drainage. If Low Spots Exist, Number& Location Floor Sloped for Adequate YESMO Plate Buckling/Deflection Acceptable YEW0 Visually Inspect& Record Plate &Weld Condition Inspect ShelUBottom Seam Condition of Internal Coating (Holes, Disbonding, Deterioration). NumberLocation & Inspect & Describe Pitting Appearance (Depth, Sharp Edged, Lake Type, Dense, Scattered) Results of Ultrasonic Thickness MeasurementCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 38. 40 API RECOMMENDED PwcncE 12R1 Checklist for Internal Inspection (Continued) Results o Vacuum Tests f Results of Penetrant Dye Tests Results of Hammer Tests Results of Other Testing (MagneticFlux Leakage, Acoustical Emission, and forth) so In Earthquake Zones 3 & 4, Roof Supports Restrained Horizontal From Movement (Not Only Welded to Floor) YESMO Identify Areas to Be Repalred. Number & Location Tank Shell Visually Inspect & Record Plate &Weld Conditions. Number& Location Conditionof Internal Coating (Hdes, Dishding, Deterioration). Number Location & Survey Shell to Check Plumb & Roundness ~~~ Results of Ultrasonic Thickness Measurements Vapor Zone inCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 39. ~~ ~ Checklist for Internal Inspection (Continued) in Liquid Zone Identify Areas to Be Repaired. Number Location & Tank Roof Inspect & Describe Pitting Appearance (Depth, Sharp Edged, Type, Dense, Scattered) Lake Conditions of Internal Coating. (Holes, Disbonding, Deterioration) NumberLocation & Visually Inspect Record Plate & &Weld Conditions. Number Location & Results of Ultrasonic Thickness Measurements Check Roof Support Columnsfor: Thinning in Vapor Zone Thinning in Liquid Zone Drain Opening ln Bottom Pipe or Concrete Filled of Proper Attachment Roof & Bottom to Inspect Girders Rafters for Thinning & Glrders & Rafters Properly Secured YESNO Identify Areas to Be Repaired. Number& LocationCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 40. 42 PRAcncE RECOMMENDED API 12R1 Checklist for Internal Inspection (Continued) Appurtenances Seals & Gaskets Visually Inspect All Inspect & Service PressureNacuum HatchesNalves Inspect Gauge Well (if Existing) Inspect Internal Reinforcing Pads Existing) for Cracks (i Inspect Internal Nozzle Seams for Cracks, Corrosion, and the like Inspect Diffusers& Rolling Systems Inspect Swing Lines Inspect Wear Plates Recommended Future ActionCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 41. APPENDIX I-FIGURES AND DIAGRAMSCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 42. ECOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 43. 46 API RECOMMENDED PRACTICE 12R1COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 44. S T D . A P I / P E T R O RP L 2 R L - E N G L L997 m 0 7 3 2 2 9 0 0568055 3 T B m RECOMMENDED OFTANKS PRODUCTION SERVICE PRACTICE FOR SElTlNG. MAINTENANCE, INSPECTION. OPERATION. AND REPAIR IN 47 P .- P h -" "" "L " kCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 45. 48 API RECOMMENDED PwcncE 12R1 LCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 46. -No personnel access_I_ Personnel access T. corroded min. I T?corroded min. Liquid height T H 4 Ts3min. 4T : corroded min. corroded I Rafters if any eCenter any pole if II Il 0.A ." UIU i Illly 2rd ring 1 I thickness Design a- corroded min. Tb T, D min. thickness corroded Tb* min. corroded f / ring annularcritical Figure 4-Corrosion Calculation Nomenclature 1 L 7 1st ring 1 critical shellCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 47. Additional copies available from API Publications and Distribution: (202)682-8375 Information about API Publications, Programs and Services is available on the World Wide Web at: httpi/www.api.org American 1220 L Street, Northwest Petroleum Washington, D.C.20005-4070 Order No. G12R15 Institute 202-682-8000COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services ~ ~ ~ ~~~ ~~ ~~