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  • ~~ STD=API/PETRO SBZ-ENGL PUBL 2000 m 0732290 Ob22502 5 9 3 W Risk-Based Inspection Base Resource Document API PUBLICATION 581 FIRST EDITION, MAY 2000 American Petroleum mÉ!- Institute H l i g You epn Strategiesf i r TOdayS Get The Job Environmental Partnership Done Right? --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 581-ENGL 2000 H 0732290 0621503 42T m S- & Strategies for Tudayi Environmental PartnerJhip API ENVIRONMENTAL, HEALTH AND SAFETY MISSION AND GUIDING PRINCIPLES --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- The members of the American Petroleum Institute arededicated to continuous efforts to improvethecompatibility ofour operations withthe environment whileeconomically developing energy resources and supplying high quality products and service4 to consum- ers. We recognize our responsibility to work with the public. the government. and others to develop and to use natural resources in an environmentally sound manner while protecting the health and safety of our employees and the public. To meet these responsibilities. API members pledge to manage our businesses according to the following principles using sound science to prioritize risks and to implement cost-effective management practices: e To recognize and to respond to community concerns about our raw materials. prod- ucts and operations. e To operate our plants and facilities. and to handle our raw materials and products in a manner that protects the environment, and the safety and health of our employees and the public. e To make safety. health and environmental considerations a priority in our planning. and our development of new products and processes. e To advise promptly, appropriate officials, employees, customers and the public of infomlation on significant industry-related safety, health and environmental hazards, and to recommend protective measures. e To counsel customers, transporters and others in the sale use, transportation and dis- posal of our raw materials, products and waste materials. e To economically develop and produce natural resources and to conservethose resources by using energy efficiently. e To extend knowledge by conducting or supporting research on the safety, health and environmental effects of our raw materials, products, processes and waste materials. e Io commit to reduce overall emissions and waste generation. e To work with others to resolveproblems created by handling and disposal of hazard- ous substances lrom our operations. e To participate with government and others in creating responsible laws, regulations and standards to safeguard the community, workplace and environment. e To promote these principles and practices by sharing experiences and offerixlg assis- tance to others who produce, handle, use, transporl or dispose of similar raw materi- als. petroleum products and wastes.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 541-ENGL 2000 m 0732290 Ob21504 3bb --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Risk-Based Inspection Base Resource Document Downstream Segment API PUBLICATION 581 FIRST EDITION,MAY 2000 American Petroleum Institute HelpingYou Get The Job Done Right?COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584. View slide
  • SPECIAL NOTES API publications necessarily addressproblems of a general nature. With respect to partic- ular circumstances, local, state, and federallaws and regulations should reviewed. be 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, norundertaking their obligations under local, state, fed- or eral laws. Information concerning safety and healthrisks and proper precautions with respect to par- ticular materials and conditions should beobtained from the employer, the manufacturer or supplier of that material, or the materialsafety 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 withdrawn at least every five years. Sometimes a 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 has been granted, upon republication. Status of the publication can be ascertained from the API Downstream Segment [telephone (202) 682-8000]. A catalog of N publications and materials is published annually and updated I quarterly by API, 1220 L Street, N.W., Washington, D.C. 20005. This document was produced underAPI 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 generalmanager of the Downstream Segment, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. Requests for permission to reproduce or translate all or any part of the material published herein should also be addressed to the general manager. API standards are published to facilitate the broad availability of proven, sound engineer- ing and operating practices. These standards are not intended to obviate the need for apply- ingsound engineering judgment regardingwhenandwherethesestandardsshould 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 inconformancewiththemarking requirements of an API standard is solely responsible for complying with all the applicable requirements of that standard.API does not represent, warrant, or guarantee that such prod- ucts do in fact conform to the applicableAPI standard. All rights reserved. No part of this work muy be reproduced, stored ina retrieval system,or transmitted by arly means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission from the publisher. Contact the Publisher, API Publishing Services, 1220 L Street, N.W., Washington, D.C.20005. Copyright O 2000 American Petroleum Institute --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584. View slide
  • ~~ ~~ STD.API/PETRO PUBL 5131-ENGL 2000 W 0732290 Ob21506 L39 m FOREWORD A P I publications maybe used by anyone desiring to doso. Every effort has been by made the Institute to assure the accuracy reliability of the data containedin 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 of federal, state, or municipal regulation with which this any publication may conflict. Suggested revisions are invited and should be submitted to the general manager of the Downstream Segment, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. iii --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~ STD.API/PETRO 581-ENGL PUBL 2000 0732290 Ob21507 075 m CONTENTS Page O INTRODUCTION ..................................................... G1 0.1 Background ..................................................... 0-1 0.2 Executive Summary ............................................... 0-1 1 SCOPE .............................................................. 1.1 1.1 General ......................................................... 1-1 1.2 An Integrated Management Tool ..................................... 1-1 1.3 Applications of RBI ............................................... 1-1 1.4 Defining and Measuring Risk ...................................... . 1-3 1.5 The Relationship Between Inspection andRisk ........................ . 1-3 1.6 Current Inspection Practices ....................................... . 1-5 1.7 A Risk-Based InspectionSystem ................................... . 1-6 1.8 ............................. . l -6 Qualitative and Quantitative Applications 1.9 The Interaction Between RBI and Other Safety Initiatives ............... . 1-6 2 REFERENCES AND BIBLIOGRAPHY ................................... 2. 1 2.1 References ...................................................... 21 . 2.2 Bibliography..................................................... 2. 1 3 DEFINITIONS ........................................................ 3.1 4 RISK ANALYSIS ..................................................... 4.1 4.1 Fundamentals .................................................... 4-1 4.2 System Definition for a Traditional RiskAnalysis ....................... 4.1 4.3 Hazard Identification .............................................. 4. 1 4.4 Probability Assessment fora Traditional Risk Analysis ................... 4.3 4.5 Consequence Analysis for a Traditional Risk Analysis .................... 4-4 4.6 Ways to Present Risk Results ........................................ 4-6 5 QUALITATIVE APPROACH TO RBI (OPERATING UNIT BASIS) ...........5.1 5.1 General ......................................................... 5.1 5.2 Qualitative Approach to RBI (Equipment Basis) ........................ 5-4 6 OVERVIEW OF QUANTITATIVE RBI ................................... 6.1 6.1 General ......................................................... 6-1 6.2 Consequence Overview ............................................ 6-1 6.3 Likelihood Overview .............................................. 6.4 6.4 Calculation of Risk ............................................... 6-5 7 CONSEQUENCE ANALYSIS ........................................... 7. 1 7.1 General ......................................................... 7.1 7.2 Determinimg a Representative Fluid and Its Properties.................... 71. 7.3 Selecting a Set of Hole Sizes ........................................ 74 7.4 Estimating the Total Amount of Fluid Available for Release ...............7.4 7.5 Estimating the Release Rate ........................................ 7 . 6 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 7.6 Determining The T p Of Release ................................... ye 7.7 7.7 Determining the Final Phase of the Fluid .............................. 7.8 7.8 Evaluating Post-LeakResponse .................................... -7-8 7.9 Determining the Consequencesof the Release .......................... 7.9 7.10 Financial Risk Evaluation ......................................... 7.29COPYRIGHT 2003; American Petroleum Institute Previous page is blank.04/08/2003 19:50:55 MDT Questions or comments about this message: please Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, call the Document Policy Management Group at 1-800-451-1584.
  • ~ ~~ ~ ~~ S T D * A P I / P E T R O P U B L 5 4 1 - E N G L 2000 W 0732290 Ob21508 T 0 1 E Page 8LIKELIHOODANALYSIS .............................................. 8-1 8.1 Overview of Process for Likelihood Analysis ........................... 8.1 8.2 GenericFailureFrequencies ........................................ 8.1 8.3 Equipment Modification Factor ...................................... 8.3 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 8.4 Management Systems Evaluation Factor ............................. 8.22 9 DEVELOPMENT OF INSPECTION PROGRAMS TO REDUCE RISK .........9.1 9.1 Introduction ..................................................... 9. 1 9.2 Development of Inspection Programs ................................. 9. 1 9.3 Reducing Risk Through Inspection................................... 9.8 9.4 Approach to Inspection Planning ................................... 9.13 10 PLANT DATABASE STRUCTURE .................................... .10.1 10.1 Information Required for RBI Analysis ............................. . I 0.1 10.2 Components of the RBI Datasheet ................................. . 1 0.1 10.3 Recommended Sources of Data for the RBI Datasheet .................. I0.8 10.4 Procedures for Inventory Calculation ............................... . I 0.8 11 TECHNICAL MODULES .............................................. 11-1 11.1 Technical Module Introduction ..................................... 11.1 11.2 Technical Module Format ......................................... 11. 1 APPENDIX A WORKBOOK FOR QUALITATIVE RISK-BASED INSPECTION ANALYSIS............................................... A- 1 APPENDIX B WORKBOOK FOR SEMI-QUANTITATIVE RISK-BASED INSPECTION ANALYSIS .................................. B-1 APPENDIX C WORKBOOK FOR QUANTITATIVE RISK-BASED INSPECTION ANALYSIS .................................. C- 1 APPENDIX D WORKBOOK FOR MANAGEMENTSYSTEMS EVALUATION ........................................... D-1 APPENDIX E OSHA 1910 AND EPA HAZARDOUS CHEMICALS LIST ........ 1 E. APPENDIX F COMPARISON OF API AND ASME RISK-BASED INSPECTION ............................................. .F. 1 APPENDIX G THINNING TECHNICAL MODULE ......................... G- 1 APPENDIX H STRESS CORROSION CRACKING TECHNICAL MODULE. . . . . H-1 APPENDIX I HIGH TEMPERATURE HYDROGENATTACK (HTHA) TECHNICAL MODULE..................................... I- 1 APPENDIX J FURNACE TUBE TECHNICAL MODULE ..................... J- 1 APPENDIX K MECHANICAL FATIGUE(PIPING ONLY) TECHNICAL MODULE ................................................ K-1 APPENDIX L BRITTLE FRACTURE TECHNICAL MODULE .................L. 1 APPENDIX M EQUIPMENT LININGS TECHNICAL MODULE ...............M- 1 APPENDIX N EXTERNAL DAMAGE TECHNICALMODULE ............... N- 1 Figures 1-1Management of Risk UsingRBI ................................... . l -2 1-2 RiskLine ....................................................... 1.4 1-3 RelationshipBetween Existing andDeveloping Documents ............. . l -7 1-4Risk-BasedInspection Program for In-Service Equipment ............... 1-8 4- 1 Overview of Risk Analysis ......................................... 4.2 viCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 581-ENGL 2000 m 0732290 Ob23509 948 m Page 4-2 Events in a Typical Scenario ....................................... 4.3 4-3 Stylized F/N Plot................................................ 4-7 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 5- 1 Qualitative Risk Matrix ........................................... 5.3 6- 1 Overview of Quantitative RBI Approach .............................. 6.2 6-2 Overview of Consequence Calculation ............................... 6.3 7- 1 RBI Consequence Calculation Overview ............................. 7.2 7-2 Process to Determine the Type Release............................. of 7.7 7-3 RBI Release Event Trees......................................... 7.13 7-4 Top View ofToxic Plumefor a Continuous Release .................... 7.20 7-5 Consequence Areafor Continuous HF Releases ....................... 7.20 7-6 Consequence Area for Continuous H$ Releases ...................... 7.2 1 7-7 Top View ofToxic Plumefor an Instantaneous Release ................. 7.2 1 7-8 Consequence Areafor InstantaneousHF and H2S Releases..............7.22 7-9 Continuous Chlorine Release ...................................... 7.23 7-10 Continuous Ammonia Release ..................................... 7.24 7-1 1 Instantaneous Chlorine Releases ................................... 7.25 7-12 Instantaneous Ammonia Releases.................................. 7.25 7-13 Caustic/Acid Modeling Results.................................... 7.26 7-14 Business Interruption Costs ....................................... 7.33 8-1 Calculating Adjusted Failure Frequencies ............................. 8.2 8-2 Overview of Equipment ModificationFactor .......................... 8-4 8-3 Damage Rate Confidence-InspectionUpdating vs.Inspection Effectiveness .8.9 8-4 Failure Frequency-InspectionMuence on Calculated Frequency .........8.11 8-5 Management Systems Evaluation Score vs.PSM Modification Factor .....8.24 9- 1 POD Curvesfor Ultrasonic Inspection ............................... 9.8 9-2 Probability of Failure With Time .................................... 9.9 B- 1 Level II Risk Matrix ............................................. B-1 B-2 Level II Qualitative Risk Matrix ................................... B-3 F- 1 ASME Qualitative Risk Matrix ..................................... F.2 F-2 API QualitativeRisk Matrix........................................ F.3 G-IA Determination of Technical Module Subfactors for Thinning ............ G-4 G-1B Determination of Technical Module Subfactors for Thinning ............ G-5 G-1C Determination of Technical Module Subfactors for Thinniig ............ G-6 G-2A Determination of HC1 Corrosion Rates ............................. G- 13 G-2B Determination of HC1 Corrosion Rates ............................. G-14 G-3 Determination of High Temperature Sulfidic and Naphthenic Acid Corrosion Rates ............................................... G-21 G-4 Determination of High Temperature HZS/H~S Corrosion Rates .......... G-26 G-5 Determination of Sulfuric Acid Corrosion Rates...................... G-31 G-6 Determination of HF Corrosion Rates .............................. G-36 G-7 Determination of Sour Water Corrosion Rates ....................... G-38 G-8 Determination of Amine Corrosion Rates ........................... G40 G-9 DeterminationofOxidation Rate .................................. G45 H-1A Determination of Technical Module Subfactor for Stress Corrosion Cracking ...................................................... H-3 H-1B Determination of Technical Module Subfactor for Stress Corrosion Cracking ...................................................... H4 H-2DeterminationofSusceptibility to Caustic Cracking ................... H-9 H-3 CausticSoda Service Graph...................................... H-10 H-4 Determination of Susceptibility to Amine Cracking ................... H-13 H-5 Determination of Susceptibility of Sulfide Stress Cracking ............. H-15 H-6 Determination of Susceptibility to HIC/SOHIC ...................... H- 18 vi¡COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD=API/PETRO PUBL 581-ENGL 20011 Page H-7 Determination of Susceptibilityto Carbonate Cracking ................ H-20 H-8 Determination of Susceptibility to Polythlonic Acid Cracking (PTA) ..... H-23 H-9 Determination of Susceptibility to ClSCC........................... H-25 H-1 1 Determination of Susceptibility to HSC-HF ......................... H-27 H-12 Determination of Susceptibilityto HIC/SOHIC HF ................... H-30 I- 1 Determination of HTHA Corrosion Rates............................. 1.4 J-IA Determination of Technical Module Subfactors for Furnace Tubes .........J-4 J-1B Determination of Technical Module Subfactors for Furnace Tubes .........J-5 J-1C Determination of Technical Module Subfactors for Furnace Tubes .........J-6 K- 1 Determining the Piping Mechanical Fatigue Technical Module Subfactor. K-5 . L- 1 Impact Test Exemption Curves ..................................... L.3 L-2 Determination of Technical Module Subfactors for Low Temperature/Low Toughness Fracture................................ L.7 L-3 Determination of Technical Module Subfactors for Temper Embrittlement .L.10 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- L-4 Fracture h e s t Curves .......................................... .L. 12 L-5 Determination of Technical Module Subfactors for 885°F Embrittlement...L.13 L-6 . Impact Properties of Sigmatized Stainless vs 304 SS, 2% Sigma / 321 SS, 10%Sigma .................................................... 1-14 L-7 . Property Trendsof Toughness vsTemperature....................... .L. 16 L-8 Determination of Technical Module Subfactor for Sigma Phase Embrittlement .................................................. 1-16 M- 1 Determination of the Equipment Linings Technical Module Subfactor .....M-3 N- 1 Flowchart for External Damage .................................... N-2 N-2 Flowchart of External Corrosionfor Carbon and Low Alloy Steels ........ N-5 N-3A Flowchart of CUI for Carbon and Low Alloy Steels ................... N-10 N-3B Flowchart of CUI for Carbon and Low Alloy Steels ...................N-11 N-4 Flowchart of External SCC for Austenitic Stainless Steels ..............N-12 N-5A Flowchart of External CUI for Austenitic Stainless Steels..... i ........ N-15 N-5B Flowchart of External CUI for Austenitic Stainless Steels ..............N-16 Tables 1-1 Basic Elements inLoss of Containment .............................. 1.4 1-2 Components of VehicleInspection .................................. 14 4- 1 Typical Data Collected Risk Analysis............................. 4-4 for 7- 1 List of Materials Modeled in Base Resource Document RBI ..............7.3 7-2 Properties of the BRD Representative Fluids .......................... 7.3 7-3 Hole Sizes Used in Quantitative Analysis ......................... 7-4 RBI 7-4 Assumptions Used When Calculating Liquid Inventories Within Equipment.7-5 7-5 Guidelines for Determining the Phase of a Fluid ....................... 7.8 7-6 Detection and Isolation System Rating Guide ......................... 7.9 7-7 Leak Durations Basedon Detection and Isolation Systems ...............7.9 7-8 Continuous Release Consequence ... Equations-Auto Ignition Not Likely 7.11 7-9 Instantaneous Release Consequence Equations-Auto Ignition Not Likely.7-1 1 7-10 Continuous Release Consequence Equations-Auto Ignition Likely ......7.12 7-1 1 InstantaneousRelease Consequence Equations-Auto Ignition Likely ....7.12 7-12 Specific EventProbabilities-Continuous Release Auto Ignition Likely...7.14 7-13 . Specific Event Probabilities-Instantaneous Release Auto Ignition Likely.7.15 7-14 Specific EventProbabilities-Continuous Release Auto Ignition Not Likely7- 16 7- 15 Specific Event Probabilities-Instantaneous Release Auto Ignition NotLikely .................................................... 7-17 7-16 Adjustments to Flammable Consequences for Mitigation Systems ........7.17 viiiCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD*API/PETRO PUBL 581-ENGL 2000 m 0732290 Ob2151L 5 T b m Page 7-17 Continuous Release Durations for Chlorine and Ammonia ..............7.23 7-18 MI-RBI Caustic/Acid Equations .................................. 7.24 7-19 Environmental Cleanup Costs Inputs ............................... 7.27 7-20 Fluid Leak Properties ............................................ 7.28 7-21 Environmental Cleanup CostsOutputs .............................. 7.28 7-22 Tank Underground Leak Rates for RBI Analysis ...................... 7.28 7-23 Detection Times for Storage Tank Floor Leaks........................ 7.28 7-24 Risk Comparison of a Typical Distillation Unit ....................... 7.30 7-25 Equipment Damage Costs ........................................ 7.3 1 7-26 Material Cost Factors ............................................ 7.3 1 7-27 Estimated Equipment Down Time .................................. 7.32 8-1 Suggested Generic EquipmentFailureFrequencies ..................... 8.3 8-2 ConvertedEquipmentModificationFactor ............................ 8.5 8-3 Confidence i predicted DamageRate ............................... n 8.7 8-4 Generic Descriptions of Damage State Categories ...................... 8.7 8-5 InspectionEffectivenessforGeneralInternal Corrosion .................8.8 8-6 General C o r r o s i o t s p e c t i o n Effectiveness ......................... 8.8 8-7 Confidence i Damage Rate After Inspection .......................... n 8.9 8-8 Calculated Frequency of Failure for Different Damage States ............8.10 8-9CalculatedTechnicalModuleSubfactor ............................. 8.10 8-10 Measured Corrosion Rates Approximately */2 of the Expected Rate .......8.13 8-11 Measured Corrosion Rates Approximately l/4 of the Expected Rate.......8.14 8-12 Measured Corrosion Rates Approximately l/10 of the Expected Rate ......8.15 8-13 Ranking According to Plant Conditions ............................. 8.16 8-14 Penalty for Cold Weather Operation ................................ 8. 16 8- 15 Penalty for Seismic Zone Operations ............................... 8.16 8- 16 Nozzle Count versus Numeric Value ................................ 8. 17 8- 17 Complexity Factors ............................................. 8. 18 8-18 Code Status Values .............................................. 8.18 8-19 LifeCycleValues ............................................... 8.19 8-20 Operating Pressure Values ........................................ 8.19 8-2 1 Operating Temperature Values. .................................... 8.19 8-22 Values for Vibration Monitoring of Pumps and Compressors ............8.19 8-25 Numeric Values for Stability Rankings .............................. 8.20 8-23 Numeric Values for Planned Shutdowns ............................. 8.20 8-24 Numeric Values for Unplanned Shutdowns ........................... 8.20 8-26 Numeric Valves for Relief Valve Maintenance ........................ 8.22 8-27 Numeric Values for Relief Valve Fouling Tendencies ................... 8.22 8-28 Numeric Value for Corrosion Service ............................... 8.22 8-29 Numeric Values for Very Clean Service ............................. 8.22 8-30 Management Systems Evaluation .................................. 8.24 9-1 DamageTypesand Characteristics .................................. 9.2 9-2 Corrosion Damage Mechanisms .................................... 9.2 9-3 Stress Corrosion Cracking DamageMechanisms ....................... 9.2 9-4 HydrogenInduced Damage Mechanisms ............................. 9.3 9-5 Mechanical Damage Mechanisms ................................... 9.3 9-6 Metallurgical and EnvironmentalDamageMechanisms ................. 9.3 9-7 Effectiveness of Inspection Techniques for Various Damage Types.........9-4 9-8 Factors Considered i Assessing Inspection Effectiveness ................ 9.5 n 9-9 The Five Effectiveness Categories................................... 9.6 9-10 Generic Descriptions of Damage State Categories ...................... 9.6 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO 581-ENGL PUBL 2000 0732270 0623512 432 9 Page 9-1 1 Quantitative Inspection Effectiveness-Likelihood That Inspection Result Determines the True Damage State ............................ 9.7 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 9-12 Damage Subfactors Chart........................................ 9.10 9-13 Damage Factors for Four Inspection Plans ........................... 9.12 9-14 Inspection Program Evaluation for Risk Reduction Optimization .....9. 12 and 9-15 Relationship Between the Level Inspection andthe Technical Module of Subfactor ..................................................... 9. 14 9-16 Furnace Inspection Intervals With a TMSF Less Than Ten ..............9. 14 9-17 Furnace Inspection Intervals With a TMSF Greater Than ............ Ten 9.14 9-18 Actions Required for a Short-Term TMSF ........................... 9.15 9-19 Actions Required for HTHA ...................................... 9.15 10-1 Recommended Sourcesof Data for RBI Datasheet .................... 10.9 11-1 Inspection Effectiveness Categories ................................ 11-2 B- 1 Inventory Category Ranges....................................... B- 1 B-2 Description of Inventory Categories ................................ B- 1 B-3 Consequence Area Categories ..................................... B-2 B -4 Variability of Technical Module Subfactors.......................... B-2 B-5 Technical Module Subfactor Conversion ............................ B-2 E- 1 List of Regulated Substances Thresholds for Accidental Release and Prevention-Requirements for Petitions under Section 112(r) of the CleanAirActasAmended ......................................... E-4 E-2 List of Regulated Toxic Substances and Threshold Quantities for Accidental ReleasePrevention-CAS Number Order-100 Substances . . . . E.6 E-3 List of Regulated Flammable Substances and Threshold Quantities for Accidental Release Prevention..................................... E.8 E-4 List of Regulated Flammable Substances and Threshold Quantities for Accidental ReleasePrevention4AS Number O r d e r 4 2 Substances ... .E. 10 G- 1 Basic Data Required for Thinning Analysis (Corrosion RateEstablished) . . G-2 G-2 Steps to Determine Estimated Corrosion Rates (Corrosion Rate Not Established) ................................................... G-3 G-3 Limit State Function for Ductile Overload........................... G-3 G-4 Screening Questions for Thinning Mechanisms ....................... G-7 G-5 Type of Thinning ............................................... G-7 G-6A Guidelines for Assigning Inspection Effectiveness-General Thinning .... G-8 G-6B Guidelines for Assigning Inspection Effectiveness-Localized Thinning ... G-8 G-7 Thinning Technical Module Subfactors .............................. G-9 G-8 Guidelines for Determining the Overdesign Factor .................... G-9 G-9 On-Line Monitoring Adjustment Factor Table ....................... G- 10 G-10 Basic Data Required for Analysis oMCl Corrosion ................... G- 11 G-1 1 Determination of pH h Cl- Concentration........................ r n G-11 G-I2 Estimated Corrosion Rates for Carbon Steel ......................... G-11 G-I3 Estimated Corrosion Rates for Series Stainless Steels ..............G- 12 300 G-14 Estimated Corrosion Rates for Alloys 825,20,625, C-276 ............. G- 12 G-15 Estimated Corrosion Rates Alloy B-2 and Alloy for 400 ............... G- 12 G-I6 Basic Data Required for Analysis High Temperature and Naphthenic of Corrosion .................................................... G-17 G-I7 Estimated Corrosion Rates for Carbon Steel ......................... G- 17 G-18 Estimated Corrosion Rates for 11/4 and2*/4Cr Steel .................. G-18 G-19 Estimated Corrosion Rates 5% Cr Steel ......................... for g-19 G-20 Estimated Corrosion Ratesfor 7% Cr Steel ......................... G-20 G-21 Estimated Corrosion Rates 9%Cr Steel ......................... for G-22 G-22 Estimated Corrosion Ratesfor 12% Cr Steel ........................ G-23 XCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL SBL-ENGL 2000 H 0732290 Ob2LSL3 379 m page G-23 Estimated Corrosion Ratesfor Austenitic S S without Mo .............. G-24 G-24 Estimated Corrosion Rates for 316 S S with 2.5% Mo ............... G-25 G-25 Estimated Corrosion Ratesfor 316 S S with 2 2.5% Mo and 317 S S ...... G-25 G-26 Basic DataRequired for Analysis of High Temperature H2S/H2 Corrosion. G-26 G-27 Estimated Corrosion Rates Carbon Steel. 1 Cr and 2/4 Cr Steels ... G-27 for l/4 G-28 Estimated Corrosion Ratesfor 5% Cr Steel ......................... G-27 G-29 Estimated Corrosion Rates for7% Cr Steel ......................... G-28 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- G-30 Estimated Corrosion Ratesfor 9% Cr Steel ......................... G-28 G-31 Estimated Corrosion Ratesfor 12% Cr Steel ........................ G-29 G-32 Estimated Corrosion Ratesfor 300 Series S S ........................ G-29 G-33 Basic Data Required Analysis ofSulfuric Acid Corrosion........... G-30 for G-34 Estimated Corrosion Ratefor Carbon Steel ......................... G-32 G-35 Estimated Corrosion Ratefor Carbon Steel ......................... G-32 G-36 Estbpated Corrosion Ratesfor 304 S S ............................. G-33 G-37 Estimated Corrosion Ratesfor 316 S S ............................. G-33 G-38 Estimated Corrosion Ratesfor Alloy 20 ............................ G-33 G-39 Estimated Corrosion Ratesfor Alloy C-276 ......................... G-34 G-40 Estimated Corrosion Ratesfor Alloy B-2 ........................... G-34 G-41 Basic Data Required for Analysis of Hydrofluoric Acid Corrosion ....... G-35 G-42 Estimated Corrosion Rates Carbon Steel......................... for G-35 G-43 Estimated Corrosion Ratesfor Alloy 400 ........................... G-35 G 4 Basic Data Required Analysis ofSour Water Corrosion............. G-37 for G-45 Estimated Corrosion Rates for Carbon Steel ......................... G-38 G46 Basic Data Required for Analysis AmineCorrosion ................ G-40 of G-47 Corrosion rateof Carbon Steel in MEA (I20 wt%) and DEA (530 wt %) G-41 G-48 Corrosion Rate of Carbon Steel in MDEA (I50 wt%) ................ G-42 G-49 Corrosion Rate Multiplier High AmineStrengths.................. G-42 for G-50 Estimated Corrosion Ratesfor Stainless Steel for all Amines G-43 ........... G-5 1 Basic Data Required Analysis of High Temperature Oxidation for Corrosion .................................................... G-43 G-52A Estimated Corrosion Ratefor Oxidation ............................ G-44 G-52B Estimated Corrosion Rate Oxidation............................ for G-44 H- 1 Basic Data Required Analysis of Stress Corrosion Cracking .......... H-2 for H-2 Screening Questions forSCC Mechanisms........................... H-2 H-3 Determination of Severity Index ................................... H-5 H-4A Effectiveness of Inspection for Caustic Cracking ...................... H-5 H-4B Effectiveness of Inspection for Amine Cracking & Carbonate Cracking.... H-5 H-4C Effectiveness of Inspection for Sulfide Stress Cracking and Hydrogen Stress Cracking................................................. H-6 H-4D Effectiveness of Inspection for HIC/SOHIC and HIC/SOHIC-HF ........ H-6 H-4E Effectiveness of Inspection for lTA ................................ H-6 H-4F Effectiveness of Inspection for ClSCC .............................. H-7 H-5 Technical Module Subfactor Determination.......................... H-7 H-6 Basic Data Required for Analysis CausticCracking ................. H-8 of H-7 Basic Data Required Analysis of Amine Cracking for ................. H- 11 H-8 Basic Data Required for Analysis Sulfide Stress Cracking ........... H-14 of H-9 Environmental Severity ......................................... H-14 H- 10 Susceptibility to SSC ........................................... H-14 H-1 1 Basic Data Required for Analysis of HIC/SOHIC-H2S ................ H- 16 H-12 Environmental Severity ......................................... H- 17 H-13 Susceptibility t HIC/SOHIC .................................... o H-17 H- 14 Basic Data Required Analysis of CarbonateCracking .............. H- 19 for xiCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • Page H-15 Susceptibility to Carbonate Cracking .............................. H-20 H-16 Basic DataRequired for Analysis Polythionic Acid Cracking......... H-21 of H-17 Susceptibility to PTA-OperatingTemperatures = 800°F .............. H-22 H-18 Susceptibility to PTA-Operating Temperatures > 800°F .............. H-22 H-19 Basic Data Required for Analysis ClSCC......................... of H-24 H-20 Process SideSusceptibility to ClSCC (for pH < 10)...................H-24 H-2 1 Process SideSusceptibility to ClSCC (for pH > 10)................... H-24 H-22 Basic Data Required for Analysis HSC-HF ....................... of H-26 H-23 Susceptibility to HSC-HF for Carbon and Low Alloy Steel ............. H-26 H-24 Basic Data Required for Analysis of HIC/SOHIC-HF ................. H-29 H-25 Susceptibility to HIC/SOHIC-HF ................................. H-29 I- 1 Screening Questions for HTHA Module.............................. 1-2 1-2 Basic DataRequired for Analysis of HTHA ........................... 1-2 1-3 Carbon and Low Alloy SteelSusceptibility to HTHA ...................1-2 1-4 Inspection Effectiveness Guidelinesfor HTHA ....................... -1-2 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 1-5 Technical Subfactors Adjusted Effective lnspection .................. for 1-3 J- 1 Furnace Tube Generic Failure Frequencies ............................ J- 1 J-2 Screening Questions for Furnace Technical Module .................... J- 1 J-3 Basic DataRequired for Analysis Furnace Tubes..................... of J-2 J-4 Metal Temperature Limitfor Creep Consideration...................... J-3 J-5 Tube Stress Limit for Creep Consideration............................ J-6 J-6 Larson MillerParameter Expressions................................ J-7 J-7 Guidelines for Assigning Inspection Effectiveness ...................... J-7 J-8 Inspection Effectiveness Reduction Factor............................ J-8 J-9 Guidelines for Determining the On-line Monitoring Factor ...............J-9 J-10 List of Materials Modeled for Furnaces .............................. J-9 J-1 1 Hole Sizes Used in Furnaces RBIAnalysis............................ J-9 J-12 Guidelines for Determining the Phase a Fluid ...................... of J-10 J- 13 Adjustments to Flammable Consequencesfor Mitigation Systems ........J-11 J- 14 Specific Event Probabilities-Continuous Release Auto Ignition Likely . . J-12 . J- 15 Continuous Release Consequence Equations-Auto Ignition Likely ...... J- 12 K- 1 Screening Questions for Piping Mechanical Fatigue Technical Module K-2 .... K-2 Basic Data Requiredfor Analysis ofPiping Mechanical Fatigue .......... K-2 K-3 Previous Fatigue Failures ......................................... K-3 K-4 Audible or Visual Shaking........................................ K-3 K-5 Shaking Adjustment Factor ....................................... K-3 K-6 Type of Cyclic Force ............................................ K-3 K-7 Corrective Action Taken .......................................... K-3 K-8 Piping System Complexity ....................................... K-3 K-9 Joint or Branch Design ........................................... K-4 K-10 Pipe Condition ................................................. K-4 K-11 BranchDiameter ............................................... K-4 L- 1 Basic Data Required for Analysis of Brittle Fracture ....................L- 1 L-2 Screening Questions for Brittle Fracture Mechanisms ...................L- 1 L-3 Basic Data Required for Analysis Low Temperaturebw Toughness of Fracture ........................................................ 1-3 L-4 No Technical Module Subfactor for Post-weld Heat Treatment ............1-4 L-5 Technical Module Subfactor for Post-weld Heat Treatment ............... 1-4 L-6 Carbon and Low Alloy Steels. and Impact Exemption Curves .............1-5 L-7 Screening Questions for Temper Embrittlement........................ L-S L-8 Basic Data Required for Analysis of Temper Embrittlement ..............L-S L-9 Materids Susceptible to Temper Embrittlement ........................ 1-9COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD*API/PETRO PUBL 581-ENGL 2000 Page L- 10 Screening Questions for 885°F Embrittlement ........................ L.l 1 L-1 1 Basic Data Requiredfor Analysis of 885°F Embrittlement ..............L.1 1 L-12 Materials Mc d by 885" F Embrittlement ......................... L.1 1 ete L-13 885°F Embrittlement Technical Module Subfactor .................... L.12 L- 14 Screening Questions forSigma PhaseEmbrittlement .................. L.14 L-15 Basic Data Required Analysis of Sigma Phase Embrittlement for .........L.14 L-16 . Data for Property Trendsof Toughness vs Temperature ............... .L. 15 L-17 Sigma Phase Ernbrittlement Technical Module Subfactors ............. .L. 15 M- 1 Typical Examplesof Protective Internal Linings ...................... M-1 M-2 Screening Questions forEquipment Linings General Approach .......... M-1 M-3 Basic Data Requiredfor Analysis of Ekpipment Linings. ............... M-1 M-4 Lining Types and Resistance...................................... M-2 M-5A Lining Failure Factors ........................................... M4 M-5B Lining Failure Factors"Organic Coatings ........................... M-5 M-6 Lining Condition Adjustment ..................................... M-5 N-1 Screening Questions for External Corrosion .......................... N-1 N-2 Basic Data Required for External Corrosion of Carbon andLow Alloy Steels ........................................................ N-3 N-3 Corrosion Rate Default Matrk-Carbon Steel Extemal Corrosion ........ N-4 N4 Adjustments for Coatings Quality .................................. N4 N-5 Adjustments forPipe Support Penalty ............................... N 4 N-6 Adjustments for Interface Penalty .................................. N4 N-7 Inspection Effectiveness.......................................... N-4 N-8 Basic Data Required for CUI for Carbon and Low Alloy Steels .......... N-7 N-9 Basic Assumptions and Methods CUI for Carbon and for . Low Alloy Steels N-7 N-10 Adjustments for Coatings ........................................ N-7 N-1 1 Adjustments for Complexity ...................................... N-8 N-12 Adjustments for Insulation Condition ............................... N-8 N-13 Adjustments for Pipe Support Penalty............................... N-8 N- 14 Adjustments for Interface Penalty .................................. N-8 N-15 CUI for Carbon and Low Alloy Steels Inspection Categories ............ N-9 N-16 Basic Data Required External SCCof Austenitic Stainless Steels for ...... N-9 N-17 SCC Susceptibility of Austenitic Stainless Steels ..................... N- 11 N-18 Adjustments for Coatings ....................................... N- 11 N-19 External SCC of Austenitic Stainless Steel Inspection Categories........ N-11 N-20 Severity Indexfor C1.SCC ....................................... N-12 N-2 1 Basic Data Requiredfor External CUISCC for Austenitic Stainless Steels N-13 N-22 CUI SCC Susceptibility of Austenitic Stainless Steels ................. N-13 N-23 Adjustments for Coatings ....................................... N-13 N-24 Adjustments for Complexity ..................................... N-13 N-25 Adjustments for Insulation Condition .............................. N-13 N-26 Adjustments for Chloride Free Insulation ........................... N-14 N-27 CUI for Stainless SteelsInspection Categories ....................... N-14 xiii --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~ ~~ STD.API/PETRO PUBL 58%-ENGL 2000 m 0732290 O b 2 L 5 L b 088 Risk-Based Inspection-Base Resource Document Section &Introduction 0.1 BACKGROUND percentage of the riskis associated with a small percentage of the equipment items. RBI permits the shift of inspection and The American Petroleum Institute (MI) Risk Based maintenance resources to provide a higher level of coverage Inspection Project was initiated in May 1993 by an industry on the high-risk items andan appropriate effort onlower risk sponsored group to develop practical methods for Risk Based is to equipment. A potential benefit of a RBI program increase Inspection. This sponsor group was organized and adminis- operating times and run lengths of process facilities while tered by API the and included the following members: improving, or at least maintaining, the same levelrisk. of Amoco; ARCO; Ashland; B P Chevron; CITCQConoco; Dow Chemical, DNO Heather, DSM Services; Quistar The purposes of the Risk-Based Inspection Program are Exxon; Fina; Koch; Marathon;Mobil;Petro-Canada;Phil- summarized as follows: lips; Saudi Aramco; Shell; Sun: Texaco; and UNOCAL. a. Screen operating units within a plant to identify areas of The Base Resource Document (BRD) clearly states there high risk. are limitations to the methods presented within it, and lists b. Estimate a risk value associated with the operation of each some ofthose limitations. The BRD states “to accurately por- equipment item in a refineryor chemical process plant based tray the risk in a fac ility... a more rigorous analysis may be on aconsistent methodology. necessary, suchas the traditional risk analysis described ...” c. Prioritize the equipment basedon the measured risk. According to the proposal for the API sponsor p project, pu d. Design an appropriate inspection program. the BRD, and the methods itin were “to be aimed at an inspec- e. Systematically manage the risk of equipment failures. tion and engineering function audience.” The BRD is specifi- cally not intended to “become a comprehensive reference on The RBImethod defines the risk of operating equipment as the technologyof Quantitative Risk Assessment (QRA).” the combination of two separate terms: the consequence of For failure rate estimations, the proposal promised “meth- failure and the likelihood failure. of odologies to modlfy generic equipment item failw rates” via The BaseResource Document includes a qualitative analy- “modification factors.” In addition, the proposal specified that sis that allows operating units to be quickly prioritized for for this activity, “the contractor would seek involve special- to further risk analysis. The result of the qualitative analysis ized expertise by drawing upon API Committee on Refinery positionstheunitwithinafive-by-fiveriskmatrix, which Equipment member resources for task.” This was done in this rates it from lower to higherrisk. the project by the formation of working groups of sponsor 0.2.2 The likelihood analysis isbasedona generic data- members who directed the development of the modification base of failure frequencies byequipment types which are factors, with assistanceby the contractor. modified by two factors that reflect identifiable differences For consequence calculations, safety, monetary loss, and from“generic” to the equipment itembeing studied. The to environmentalimpact were all be included. For safety eval- Equipment Modification Factor reflects the specific operating uations, the proposal noted that existing algorithms AIChE in conditions of each item, and the Management Modification CPQRA guidelines are “complex andare best suited for use Factor is based on anevaluation of the facility’smanagement in a computerized form.” Itwas proposed that “for ease use of practices that affect the mechanical integrity of the equip- the safety consequences be limited to the evaluation of: burn- ment. The management systems evaluation tool is based on ing pools of liquids,ignitedhighvelocity gas andliquid API guidelines and is included as a workbook of audit ques- releases, explosions of vapor clouds, and toxic impacts.” tions in the Base Resource Document. The result of the BRD project and subsequent projects has been the development of simplified methods for estimating The likelihood analysis includes a series of TechnicalMod- failure rates and consequences of pressure boundary failures. ules that assess the effect of specific failure mechanisms on The methods areaimedatpersons who arenotexpert in the probability of failure. The Technical Modules serve four QRA. Subsequent computer programs have been developed functions: to further ease the application of the BRD methods. a. Screen the operation to identify active the damage mechanisms. 0.2 EXECUTIVE SUMMARY b. Establish a damagerate in the environment. 0.2.1 Risk-BasedInspection(RBI) is amethodforusing c. Quantify the effectiveness of the inspection program. risk as a basis for prioritizing and managing the efforts an of d. Calculate the modification factor to apply to the generic inspection program. In an operating plant, a relatively large failure frequency. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- o-1COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 0-2 API PUBLICATION 581 0 2 3 The consequences of releasing a hazardous material .. Guidelines are provided to develop and modify an inspec- are calculatedby: tion program so it will appropriately manage the risks that have been identified in the risk calculation and prioritization a. Estimating the release rate based on the developed scenarios. steps. A simple method is presented for categorizing inspec- b. Predicting the outcome. tioneffectiveness estimating probability the and the that c. Applying effect modelsto estimate the consequences. inspection planwill identify thetrue damage state in a piece of equipment. The effects of alternate inspection plans, and an Flammable, toxic, environmental and business interruption effects are covered in the Risk-Based Inspection methodol- approach to developing an inspection program, are presented. ogy. A Quantitative RBI Workbook is provided to guide the Worked examples of actual plant equipment are provided user step-by-step throughthe calculations for both the likeli- to demonstrate the methodology. A Risk-BasedInspection hood and consequence analyses. study, sponsored by the full committee, has been performed at a Shell facility. This study will serve as a pilot program for 0.2.4 The likelihood and consequence are combined to pro- the group. duce an estimate of risk fcr each equipment item. The items Future workmight include development of an industry fail- can then be ranked based on the risk calculation, but the like- ure database, software to support Risk-Based Inspection, and lihood, consequence, and risk all stated separately, identi- are expanding the program to fit into other industry initiatives, fying the major contributor risk. to including Reliability Centered Maintenance (RCM). --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • Section I-Scope 1.1 GENERAL The RBI approach allows any combination of these types of risks to be factored into decisions concerning when, where, This document is about using risk as a basis for prioritizing and how to inspect a process plant. and managingan inspection program, where equipment items be RBI is flexible and can applied on several levels. Within to be inspected are ranked according to their risk. In nearly this document, RBI is applied to the equipment within the pri- every situation,once risks have been identified,alternate mary pressure boundaries. However, can be expanded to the it opportunities are available reduce them. On other hand, to the system level include and additional equipment, such as nearly all major commercial losses are the result of a failure instruments, control systems,electrical distribution, and criti- to understandor manage risk. cal utilities. Expanded levels of analyses may improve the It is important to understand that the Risk-Based Inspec- payback for the inspection efforts. tion methodology, as presented in this Base Resource Docu- A RBI approach can also be made cost-effective by inte- ment, represents only of many possible approaches to the one grating with recent industry initiatives and government regu- use of risk as an inspection criteria. As with all forms of risk lations, such as API RP 750, Management of Process assessment,many approaches are validdependingonthe Hazards, Process Safety Management (OSHA 29 CFR assessment goals and level detail desired. of 1910.1 19), the proposed Environmental Protection Agency or the The RBI methodology provides basis for managing risk Risk Management Programs for Chemical Accident Release by making an informed decision inspection frequency, level on Prevention. of detail, andtypes of NDE. In most plants, a large percent of be the total unit risk will concentrated in a relatively small per- 1.3 APPLICATIONS OF RBI cent of the equipment items.These potential high-risk compo- nents may require greater attention, perhaps through a revised 1.3.1 Optimization Procedures inspection plan.The cost of the increased inspection effort can sometimes be offset by reducing excessive inspection efforts in When the risk associated with individual equipment items the areas identified as having lower risk. With a RBI program is determined the and relativeeffectiveness of different in place, inspections wcontinue to be conducted as deíìned li inspection techniques in reducing risk is quantified, adequate in existing working documents, but priorities and frequencies information is available for developing an optimization tool will be guided by RBI procedure. the for planning and implementing a risk-based inspection. The purposes of a (RBI) program are as follows: Figure 1-1 presents stylized curves showing the reduction --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- in risk that canbe expected when degree and frequency of the a. To provide the capabilityto define and measure risk, creat- inspection are increased. Where there is no inspection, there ing apowerfultool for managing many oftheimportant may be a higher level of risk. With an initial investment in elements of a process plan; inspection activities,riskdropsata steep rate. A point is b. To allow management to review safety, environmental and reached where additional inspection activitybegins to show a business-interruption risks in an integrated, cost-effective diminishing return and, eventually, may produce very little manner, additional risk reduction. c. To systematically reducethe likelihood of failures by mak- Not a l inspection programs are equally effective detect- l in the ing better use of inspection resources; and ing in-service deterioration and reducing risks, however. Vari- d. Identify areas of high consequence that can be used for ous inspection techniques are usually available to detect any plant modificationsto reduce risk (risk mitigation). given damage mechanism, and each method will have a dif- ferent cost and effectiveness. The upper curve i Figure 1-1 n 1.2 AN INTEGRATEDMANAGEMENTTOOL represents a typical inspection program. reduction in risk A is achieved, but not at optimum efficiency. Until now, no cost- The RBI program presented in this Base Resource Docu- effective method has been available to determine the combi- ment takes the first step toward an integrated risk manage- nation of inspection methods and frequencies that are repre- ment program. In the past, the focus of risk assessment has sented onthe lower curve in Figure l. 1- been on-site safety-related issues. Presently, is there an RBI provides a methodology for determining the opti- increased awareness of the need to assess risk resulting from: mum combination of methods and frequencies. Each avail- able inspection method can be analyzedanditsrelative a. On-site risk to employees. effectiveness in reducing failurefrequency estimated. Given b. Off-site riskto the community. this information and the cost of each procedure, an optimi- c. Business interruption risks. zation programcan be developed. Similar programs are d. Risk of damageto the environment. available for optimizing inspection efforts in other fields. 1-1COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 581-ENGL 2000 m 0732290 06,23519 897 1 -2 API PUBLICATION 581 The key to developing such a procedure istheability to Many of these factors are strongly influenced by the Pro- quantify the risk associated with each item of equipment cess Safety Management (PSM) system in place at the facil- and then to determine the most appropriate inspection tech- ity. As described in Section 1.9.2, a RBI program can also niques for that piece of equipment. consider the effectiveness the management systems. of Increased inspection reduces risk through a reduction in future failure frequencies by corrective and preventative mea- 1.3.2 Database Improvements sures taken after the inspection has identified problem areas. Inspection does not alter consequences, which are the other The accuracy and utility of risk studies could be improved componentrisk. of Consequences are changedthrough if process-specific failure data were available. Initial efforts design changes or other corrective actions. However, theRBI by the process industryto develop such databases include the methodology can identify areas where consequences of possi- following: ble failure events can bereduced by system changes or miti- a. A consortium of offshore exploration and production com- gation procedures. panies operating in the North Sea has been supporting the As shown in Figure 1-1, ri& cannot be reduced to zero Offshore Reliability Database (OREDA), an equipment reli- solely by inspection efforts.The uninspectable factors forloss ability database, for more than decade. a of containment include, are not limited to, following: but the b. The UK Operators Exploration andProduction Forum ini- a.Humanerror. tiated a Hydrocarbon Leak and Ignition Database in 1993, b. Natural disasters. with the goal of creating a source of high quality leak and c. External events (e.g., collisions or falling objects). ignition datato be used in offshorerisk assessments. d. Secondary effects from nearby units. c. The American Institute of Chemical Engineers Centerfor e. Deliberate acts (e.g., sabotage). Chemical Process Safety has initiated pilot project, with the a f. Fundamental limitations ofthe inspection method. goal of assessing existing data and data collection systems, in g. Design errors. an effort to support an industry-wide equipment reliability h. Previous unknown mechanisms of deterioration. database patterned after OREDA. Risk with Typical Inspection Programs R I S K Risk Using RBI Uninspectable Risk LEVEL OF INSPECTION ACTIVITY Figure 1-1-Management of Risk Using RBI --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 581-ENGL 2000 m 0732290 Ob21520 509 RISK-BASED BASEINSPECTION RESOURCE DOCUMENT 1-3 d. The Materials Properties Councilhas proposed a program becomeaplatform to integrate, direct, and measure the to quantify failure histories for the specific problem of low- activities of these specialists. temperature brittle failure potentialas a result of auto-refrig- The output from a RBI analysis can also be useful in risk eration of light liquid hydrocarbons. reduction efforts outside inspection planning.Traditional e. A future phase of ti American hs Petroleum Institute inspection activities may be driven by the likelihood-of-fail- Project on Risk-Based Inspection is under consideration that ure part of the risk equation, rather than the consequence of is intended to establish an equipment failure databaseto sup- failure. of Risks high consequence can be reduced by port, with high quality data, the methodology described in improved isolation capabilityor other mitigation procedures. this BRD. The output of a RBI analysis, when sorted by consequence Additional references to use as starting points for process can provide a prioritized list such efforts. for specific failure data include: What Went Wrong, T. A. Kletz,GulfPublishing Co., 1.4 DEFININGANDMEASURING RISK Houston, T X , 1986. The RBI system defines risk the product of two separate as Handbook of Case Histories in Failure Analysis, ASM terms-the likelihood that a failure will occur andthe come- International, Materials Park, OH, 1992. pence of a failure. Understanding the two-dimensional Safety Digest of Lessons Learned, Sections 1 through 6, aspect of risk allows new insight into the use of risk as an American Petroleum Institute, Washington, D.C., 1982. inspection prioritization tool. Understanding How Components Fail, D. J. Wulpi, Figure 1-2 displays the risk associated with the operation ASM Intemational, Materials Park, OH, 1987. of a number of equipment items in a process plant. Both the Defects and Failures in Pressure Vessels and Piping, H. likelihood and consequence of failure have been determined Thielsch, Krieger Publishing Co.,Malabar, FI, 1977. for ten equipment items, and the results have been plotted. Risk-Based Inspection should incorporatepmss-specific The points representthe risk associated with each equipment failure data whenthey become available, either from industry item. Ordering by risk produces a risk-based ranking of the groups or internally within a company. equipment items tobe inspected. From this list, an inspection plan can be developed that focuses attention on the areas of 1.3.3 Other Uses For RBI highest risk. - Table 1 1 shows how the risk of loss of containment relates 1.5 THE RELATIONSHIP BETWEEN INSPECTION to thevarious categories thatmay contribute to a failure.Loss AND RISK of containment occurs only when the pressure boundary is breached. As the figure demonstrates, however, failure of any Given that the "risk" of: an accident has two components, of the equipment categories or human factors can act a pre- as likelihood and consequence, inspection, an activity intended cursor to the failure of the pressure boundary. power failure A to limit risk mustreduce oneor both of the risk components. or an instrument malfunction can result in a process upset. If We gainsubstantialinsight into therelationshipbetween appropriate action is not takenby the process operator, condi- inspection and risk by recognizing which component of a risk tions can be reached that will result in a breach or failure of particular inspection activity is intended to reduce. An anal- the pressure envelope. It follows, therefore, that damage pre- ogy helps to clarify this concept. vention efforts should be coordinated across all these areas. One of the greatest risks people face in modem society is This integrated approach will require a significant para- the risk of injury or death in an automobile accident. People digm shift within the process industry. First, priorities will accept that risk individually, butcollectively our society tries be based on risk,rather than just on the likelihood of failure to control that risk. Obvious examples of control are limits on that drives many inspection decisions today. Second, organi- driver age, training and testing of drivers, prohibition of driv- zational approaches will need re-examination.Current prac- ing under the influence of alcohol, placing limits on speed, tice usually assigns maintenance and inspection and enforcing other laws and regulations.Another action responsibility by the category of equipment: electrical, society has taken is to require inspection of all automobiles an instrumentation and controls, fixed equipment, and rotating on a yearly basis. This action seems important intuitively, but equipment. Environmental,safety, risk, and process respon- what effect does it have? Does it affect the likelihood ofacci- sibilities also are typicallyassigned to dedicated groups, dents, the consequences, or both? Table 1-2 indicates some each in a different part of the organization and different possible conclusions by examining the components of the from those responsible for equipment performance. Some vehicle inspection. companies have begun to organize into Technology Teams, The effect of inspecting any specific component on likeli- where people with these specialist backgrounds can focus hood or consequence could be argued, but most people would their efforts on continuously improving the reliability of the agree that these inspections are important. For our personal process. Risk-Based Inspection, in its broadest sense, could safety, we keep our cars in good condition. Although state --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 1-4 API PUBLICATION 581 CONSEQUENCE Figure 1 -2-Risk Line Table 1-1-Basic Elements in Loss of Containment inspection can be a nuisance, few would vote to eliminate them; we want the“other guy” to maintainhis car to our high Category Precursor Loss of Containment standards.Why? It reduces our risk! ~ ~~ Pressure Boundary X X In this analogy, al of the inspections except one arefunc- l Mechanical Equipment X tioninspections; the exception iscondition a inspection. Functional inspections, such as for the horn, are pasdfail. If Equipment Electrical X the horn works, itpasses the inspection. The exception is the Instrument Controls and X inspection of the car’s tires. If car is driven to the inspection a station, the tires are filled with a r and are functioning prop- iSystems Safety X erly. However, the passlfail criterion in this case is not theFactors Human X function, but the condition of the tires.Ifthetreadwear exceeds a certain limit, the tires do not pass the inspection. There are many ways to test the function of a component and Table 1-2-Components of Vehicle Inspection many ways to test condition. Some tests may do both. the The important pointis that the test used mustbe appropriate tothe Component Likelihood Consequence if desired result. Checking the tires’ pressure to see they have Hom a r in them would be as meaningless as visually examining i Headlights the horn to see if it works. T r Signals un The above analogy illustrates that inspection can affect Brakes X risk. When inspection is expanded to a process plant, how- ever, the issue becomes increasingly complicated. For one Wipers thing, an entire vehicle can be safety inspected in a few min- Tires X utes, whereas a thorough inspection of a single component Seat Belts X in a process plant can easily take several days. When we --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 581-ENGL 2000 M 0732290 0621522 381 M RISK-BASED RESOURCE DOCUMENT BASE INSPECTION 1 -5 consider the number of components to be inspected, and the Reconstruction) represent the body of accepted inspection number of appropriate ways of inspecting them, the task of practices for pressure boundaryequipment. The RBI proce- setting priorities can appear very significant. dures presented in this Base Resource Document draw on these API Standards and otherindustry practices to identify 1.6 CURRENT INSPECTIONPRACTICES potential problem areas and quantify the relative seventy of the concerns. In process plants,inspectionandtestingprogramsare established to detect and evaluate deterioration and damage API inspection standards have established rules for setting due to in-service operation. The effectiveness of inspection minimum inspection frequencies in situationswhere the dam- programs varies widely, however. Atone end of the scale are age mechanismis loss of material. Long intervalsare permit- the reactive programs, which concentrate on known areas of ted if the service is non-corrosive.However, the standards concern, in contrast to a broad program covering a variety of provide only limited guidance for setting inspection frequen- equipment. The extreme of this would be the “don’t fix it cies for cracking and for situations where material properties unless it’s broken” approach. are changing. Somewhere in the middle of the inspection-effectiveness As RBI proceduresand fitness-for-service (WS) guide- scale is the approach that conducts inspections on a scheduled lines are incorporated into API standards, the concept of mea- basis, but with a limited variety of inspection methods, per- suring and managing risk willbecome key a part of haps ultrasonic thickness (UT) measurement or radiography. inspection planning. The most comprehensive inspection programs are designed to meet the intent of A P I and other inspection standards by 1.6.2Frequency of Inspection identifying the in-service deterioration modes and designing an inspection program for detecting specilïc defects. These Fitness-for-service procedures can be used to set inspec- p r o m s are based on understanding of all potential an dam- tion intervals for cracking or changing material properties. age mechanisms in each equipment item. The actual rate of deterioration is a function of a complex Themost comprehensivetestingmethodscanbevery interaction of material properties, process environment, oper- costly, without being cost effective. R B I has the potential to ating conditions, and state of stress. In the W S pracedure, a reduce these costs in away that will still provide a system of conservative estimate of the deterioration rate is calculated. prioritizing inspections so they will fully address safety con- The amount of damage that the component can withstand is cerns. A risk-based ranking of all equipment items provides thencalculated,and the nextinspectionis scheduled well the basis for allocating inspection efforts so that potentially before the anticipated failure. With each future inspection, the high-risk areas can receive sophisticated and frequent inspec- actual deterioration rate is better defined, and inspection fre- tions, while low-risk areas are inspected in a manner com- quencies can be adjusted accordingly. mensurate with the lower risk. 1.6.3 Linking RBI to Inspection Standards --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 1.6.1 Technical Basis An even moredirect l n than theone to fitness-for-service ik In general, pressure envelope deterioration and damage can procedures exists between RBI and the large body of infor- be classified into eight very broad damage types: mation that defines today’s inspection practices. Made up of working documents such as API 510,API Std 653,and API a. Thinning. 570, these inspection practices are deeply imbedded in the b. Metallurgical changes. RBI prioritization procedure. Codes and standardsfrom API, c. Surface connected cracking. ASME,and other organizations havebeenusedwhenever d. Dimensional changes. possible in the screening and evaluation procedures and in e. Subsurface cracking. establishing the factors used to modify generic failure fre- f. Blistering. quency values. Where definitive standards have not yet been g. Micro fissuringhicrovoid formation. established, industry experience and good practices have pro- h. Material properties changes. vided the basis for evaluation. i. Positive Material Identification (PMI). When API issues the Recommended Practice (RP580) for Understanding the types of damage can help the inspector Risk-Based Inspection, it too will become part of this broad select the appropriate inspection method and location for a body of information. This “full loop” conceptis illustrated in particular application. Figure 1-3. With the RBI RP in place, inspections will con- The existing A P I Inspection Standards (API 510, Pres- tinue to be conducted as defined in existing working docu- sure Vessel Inspection Code; API 570, PipingInspection ments, but priorities and frequencies will be guided by the Code; and API653,Tank Inspection, Repair, Alteration, and RBI procedure.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD-APIIPETRO PUBL 541-ENGL 2000 m 0732290 Ob21523 2 L B 1-6 API PUBLICATION 581 1.6.4 Relationship to Other Existing and Figure 1-4 also incorporates a periodic audit of the whole Developing API Documents system. With thisfeature, incorporating the recommendations from the system audit, the risk-based inspection fits into the Figure 1-3 illustrates interaction the between RBI and Quality Improvement Process (QIP) and allows for continu- other existing and developing M I documents. API RP 750, ous improvement. Management o Process Hazards, provides a comprehensive f definition of an effective processsafety management system. 1.8 QUALITATIVEANDQUANTITATIVE Among other things, it requires useof process hazard analy- APPLICATIONS ses,compilation of mechanicaland operating records and procedures,andimplementationofaneffectiveequipment The RBI procedure can be applied qualitatively, quantita- inspection program. Rp 750 is shown as the umbrella policy tively or in combination. Both approaches provide a system- under which existing inspection codes operate and new pro- atic wayto screen for risk, identify areas of potential concern, cedures are being developed. and develop a prioritized list for more in-depth inspection or analysis. Both develop a risk ranking measure to be used for The relationship between RBI and other developing proce- evaluating separately the probability of failure and pten- the dures is illustrated by the interaction between the Base tial consequence of failure. These two values are then com- Resource Document (BRD) the and Material Properties bined to estimate risk. Council (MPC).API andMPC are nearingcompletion of API The primary difference betweenthe qualitative and quanti- RecommendedPractice 579, Fitness-For-Service. This and tative approach is the level of resolution. The qualitative pro- other developing procedures will be integratedinto exist- also cedurerequires less detailedinformationaboutthefacility ing procedures,where appropriate. and, consequently, its abilitytodiscriminateismuchmore limited. The qualitative technique would normally be used to 1.7 A RISK-BASEDINSPECTIONSYSTEM rank unitsor major portionsof units at a plant site to determine priorities for quantitative RBI studies or similar activities. A fullyintegratedRisk-Based Inspection system should A quantitative RBI analysis, on the other hand, will pro- contain the steps shown in Figure 1-4. The system includes vide risk values for each equipment item and pipe segment. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- inspection activities, inspectiondata collection, updating, and With this level of information, a comprehensive inspection continuous improvement of system. Risk analysis is “state the plan can be developed for the unit. of knowledge” specific and, since the processes and systems are changing with time, any risk study can only reflect sit- the 1.9 THE INTERACTION BETWEEN RBI AND uation at the time the data was collected. Although any sys- OTHER SAFETY INITIATIVES tem when first established may lack some needed data, the risk-based inspection program can be established based on The Risk-Based Inspection methodology has been the available information, using conservative assumptions for designed to interact withothersafetyinitiativeswherever unknowns. As knowledge is gainedfrom inspection and test- possible. The output from several of these initiatives provides ing programs and the database improves, uncertainty in the input for a variety of RBI evaluations and, in some instances, program will be reduced. This results in reduced uncertainty the RBI riskrankings can be used to improve other safety sys- in the calculated risks. tems. Some examples are givenbelow. When an inspection identifies equipment flaws, they are evaluated usingappropriate engineering analysis or the 1.9.1 Process Hazard Analysis emerging fitness-for-service methods. Based on this analy- A Process Hazard Analysis (Pm)usesasystematized sis, decisions can be made for repairs, maintenance, or con- approach to iden@ and analyze hazards in a process unit. tinued operation. The knowledge from gained the The RBI study can include a review of the output from any inspection, engineering evaluation and maintenance is cap- PHAs that have been conducted on the unit being evaluated. tured and used to update the plant database. The new data Hazards identified in the PHA can be specifically addressed willaffecttherisk calculations and risk ranking for the in the RBI analysis. future. For example, a vessel suspected of operating with Potential hazards identified in a PHA would often impact stress corrosioncracks could havea relatively high risk of the probability-of-failure side the risk equation. hazard The ranking. After inspection, repairs, and change or removal of may result from a series of events that couldcause a process the adverse environment, the risk calculated for the vessel upset, or it could be the result of process or instrumentation wouldbesignificantlylower, moving it down in the risk deficiencies. In either case,the hazardmightincreasethe ranking and allowing the revised risk-based inspection plan probability offailure, in which case the RBI procedure would to focus onother equipment items. reflect the same.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO SBL-ENGL PUBL 2000 m 0732270 Ob2L524 154 m INSPECTION BASE RESOURCE RISK-BASED DOCUMENT 1-7 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- I I L"" (Under development) MPC FITNESS FOR SERVICE Working Research Working Documents Documents Documents Figure 1 -3-Relationship Between Existing and Developing DocumentsCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • PLANT DATABASE I RISK BASED PRIORITIZATION 1 INSPECTION PLANNING I QIP I INSPECTION RESULTS FITNESS FOR SERVICE INSPECTION UPDATING SYSTEM AUDIT Figure 1-4-Risk-Based Inspection Programfor In-Service Equipment Some hazards identified would affect the consequence side agement systems in maintaining the mechanical integrity of of the risk equation. For example, the potential failure of an the unit being evaluated. The results ofthe management sys- isolationvalvecouldincrease the inventoryavailable for tems evaluation are factored into the risk determinations. release in the event of a leak. The consequence calculation in Several of the features of a good PSM program provide the RBI procedure canbe modified to reflect this added hazard. input for a R B I study. Extensive data on the equipment and The plant layout and construction might be evaluated to see the process are required in the RBI analysis, and output from if it has the following characteristics: PHAs and incident investigation reportsincreases the validity a. Equipment spacing and orientation that facilitates mainte- of thestudy. In turn, the RBI procedures can improve the nance and inspection activities and minimizes the amount of PSMprogram. An effective PSM program must include a damage in caseof a fireor explosion. well-structured equipment inspection program. The RBI sys- b. Control rooms and other operator stations that are located tem will improve the focus of the inspection plan, resulting in and constructed in a manner provideproper shelter in case to a strengthened PSM program. of a fire or explosion. Operating comprehensive witha inspection program c. Appropriate attention hasbeen given to leak detection,fire should reduce the risks of releases from a facility and should water systems, and otheremergency equipment. provide benefits in complying with safety-related initiatives. 1.9.2ProcessSafetyManagement 1.9.3 Equipment Reliability A strong Process Safety Management system of the kind Equipment reliability programs can provide input to the RP described in API 750 can significantly reduce the risk in a probability analysis portion of a RBI program. Specifically, process plant. Section 8.4 and the Workbook in Appendix C reliability records can be used to develop equipment failure include methodology to assess the effectiveness of the man- probabilitiesandleakfrequencies.Equipment reliability is --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • - ~~ STD*API/PETRO PUBL 581-ENGL 2000 H 0332290 Ob2352b T27 RISK-BASED RESOURCE DOCUMENT BASE INSPECTION 1-9 especially important if leaks can be caused by secondary fail- analysis, the QRAshares many of the data requirements of a ures, such as loss of utilities. RBI. If a QRA has beenprepared for a process unit, the B I R Future work might l i reliability efforts such as Reliabd- program can borrow extensively from this effort. Information ity Centered Maintenance (RCM) with RBI, resulting in an common to both aQRA and a R B I program is as follows: integrated programto reduce downtimein an operating unit. a. Generic data b. Population information. 1.9.4 Traditional Quantitative Risk Assessment c. Ignition sources. Quantitative Risk Assessment(QRA)refers to the pre- d. Meteorological data. scriptive methodology that has resulted f o the application rm e. Dispersion distances. of risk analysis techniques at petrochemical process facilities. f. Conditional probabilities for fate of vapor cloud. For all intents and purposes, it is a traditional risk analysis. Section 4 presents a more detailed discussion of QRA and Because R B I takes some of its parentage from traditional risk compares R B I with atraditional risk analysis. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • Section 2-References and Bibliography 2.1 REFERENCES OS HA^ Unlessspecified otherwise, the most recent editions or Process Safety Management of Highly Hazardous Chemicals Standard, Title 29, revisions of the following standards, codes, and specifica- tions shall, to the extent specified herein, form a part of this Code ofFederal Regulations (CFR) Part 1910.1 19 (FR57(36); 6356-6417 publication. API 2.2 BIBLIOGRAPHY Std. 5 10 Pressure Vessel Inspection Code: Mainte- nance, Inspection, Rating, Repair, and 2.2.1 Risk Analysis Fundamentals Alteration Loss Prevention in the Process Industries, F.P. Lees, Butter- Std. 570 Inspection, Repair, Alteration, and Rerat- worths, London, 1980. ing of ln-Service Piping Systems Std. 653 Tank Inspection, Repair, Alteration and The Risk Based Management System:N e w Toolfor Assess- A Reconstruction ing MechanicalIntegrity, PW-Vol. 251, Reliabilityand RP 521 Guide for Pressure-Relieving and Depres- Risk in Pressure Vessels and Piping, J. E. Aller, R. Dunlavy, suring Systems K. R. Riggs, and D. Perry, ASME, 1993. RP 530 Calculation of Heater Tube Thickness in Process Safety Managementof Highly Hazardous Chemicals Petroleum Refineries Standard, Title 29, Code of Federal Regulations ( C m ) P r at RP 579 Fitness-for-Service 1910.119 FR57 (36); 6356-6417, February24,1992. RP 941 Steels for HydrogenService at Elevated Temperatures and Pressures in Petroleum Risk Management Programsfor Chemical Accident Release Refineries and PetrochemicalPlants Prevention, 40 CFR Part 68, Proposed Rule, Docket A-91-73, 750 Management of Process Hazara3 Environmental Protection Agency, WashingtonD C , 1993. AIChE/CCPS’ Offshore Reliability Data, OFtEDA participants, OREDA-92, Guidelinesfor Chemical Process Quanti- distributed by DNV Technica, Hbvik, Norway. tative Risk Analysis HydrocarbonLeak andIgnitionDatubase, ReportN658, Guidelines for Hazard Evaluation --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- DNV Technica, preparedfor EBrP Fonun, 1992. Procedures Guidelinesfor Use ofvaporCloud Disper- Fitness-For-ServiceEvaluation Procedures for Operating sion Models Pressure Vessels, Tanks, und Piping in Refinery and Chemical Service, Consultant’s Report-“PC Program on Fitness for ASME* Service, T. L. Anderson, R. D. Memck, S . Yukawa,D. E. Boiler and Pressure Vessel Code, Section Bray, L. Kaley, andK. Van Scyoc, Materials Properties Coun- W, “Pressure Vessels,” Division 1; Sec- cil, Inc., New York,N Y , September, 1993. tion IX, “Welding and Brazing Qualifications” What Went Wrong, T. A. Kletz, Gulf Publishing Co., Houston, T X , 1986. EPA3 Risk Management Programsfor Chemical Handbook of Case Histories in FailureAnalysis, ASM Inter- Accident ReleasePrevention, 40 CFR Part national, Materials Park, OH, 1992. 68, Proposed Rule, Docket A-91-73 SafetyDigest of Lessons Learned, Sections 1through 6, NFPA4 American Petroleum Institute, Washington, D.C., 1982. Fire Protection Guide to Hazardous Mate- rials, 10th Edition, 1991 Understanding How Components Fail, J. Wulpi, American D. Society for Metals, Metals Park,OH, 1987. ‘AmericanInstitute of ChemicalEngineers/CenterforChemical DefectsandFailures in PressureVesselsand Piping, H. Process Safety,345 East 4 t Street,New York 10017. 7h Thielsch, Krieger Publishing Co., Malabar, FL., 1977. *ASME International, P r Avenue, NewYork, New York 10016. 3 ak 3U.S.Environmental Protection Agency, M Street, S.W., Wash- 401 ington, D.C. 20406. 50ccupational Safety and Health Administration, U.S. Department 4NationalFire Protection Association,1 Batterymmh Park,Quincy, of Labor. Publications are available f o the U.S. Government rm Massachusetts 02269. Printing Office, Washington, 20402. D.C. 2- 1COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 2-2 Large Property Damage Losses in the Hydrocarbon-Chemi- Development of a ProbabilityBasedLoad Criterion for cai Industries, A Thirty-Year Review, 14th Edition, Marsh & American National Standard A58, National Bureau of Stan- McLennan, M&M Protection Consultants, 1992. dards Spec. Pub. 577, Ellingwood, et.al., 1990. Analysis of Large Property Losses in the Hydrocarbon and 2.2.2 Consequence Analysis Chemical Industries, J. Krembs, J. Connolly, M&M Protec- Perry’s Chemical Engineering Handbook, 6th Edition, R. H. tion Consultants, Refinery and Petrochemical Plant Mainte- Perry, and D. Green, (editors) McGraw-Hill, New York, 1984. nance Conference,May 23-25,1990. Methods for the Calculation of Physical Efsects of the Escape 2.2.4 Development of Inspection Programs of Dangerous Materials: Liquids and Gases, Apeldoon, TNO, The Netherlands,1979. Probability, Statistics, and Decision for Civil Engineers, J. R. Benjamin, andA Cornell, McGraw-Hill, New York, 1970. Atmospheric Difision: The Dispersion of Windborne Mate- rial from Industrial and Other Sources, 2nd Edition, F. Pas- AssessingInspectionResultsUsingBayes’ Theorem, 3rd quill, Wdey,New York, 1974. International Conference & Exhibition on Improving Reli- ability in Petroleum Refineries and Chemical Plants, Novem- User Manual for Process Hazard Analysis Software Tools ber 15-18, 1994, A. Tallin, and M. Conley, DNV USA, Inc., (PHAST), Version 4.1, DNV Technica, Temecula, California, Gulf Publishing Company. 1993. The Unreliability of Non-Destructive Examinations, O. Forli, Hazardous Waste Tank Failure (HWTF) and Release Model: and B. Pettersen, 4th European Conferenceon Non-Desuuc- Description of Methodology, Pope-Reid Associates, Inc., tive Testing, London, 1987. sponsoredbyEnvironmental Protection Agency,Office of Solid Waste, EPA/530/SW86/012,Interim draft report,Wash- Non-Destructive Evaluation of Steel StructuresTechniques ington, DC 1986. andReliability, O. Forli,Conference on Non-Destructive Evaluation of Civil Structures and Materials, Boulder, Colo- The Properties of Gases and Liquids, 4th Edition, Reid, Rob- rado, 1990. ert C, et. al., McGraw-Hill, New York, 1987, Reliability Optimization of Manual Ultrasonic Weld Inspec- Dow’s and Fire Explosion Index Hazard Classifrcation --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- tion, W.H. van Leeuwen, Dutch Welding Institute (NIL) to Guide, 7th Edition, American Institute of ChemicalEngi- PISC Management Board Meeting, Glasgow, 1990. neers-AIChE Technical Manual, New York, 1994. Materials Evaluation, pp. 812-821, No. 47, J. Perdijon, July, 2.2.3 Likelihood Analysis 1989. Loss Control in the Process Industries, F. P. Lees, 1980. PISC-II Report Nos. 1-5, Programme for the Inspection of Steel Components, Nuclear Energy Agency, Committee on A Survey of Defects in Pressure Vessels, Smith and Warwick, the Safetyof Nuclear Installations, CSNI Nos. 106-110. 1981. Roles of Non-Destructive Inspection Reliability Assessment in WASH-1400,1970, modified by Ref 4. U. S . Nuclear Regula- of Structures, M. Murata, Y. Aikawa, M. Nakayama, Nippon tory Commission, Steel Technical Report 32,1987. No. Pipe and Vessel Failure Probability,H. M. Thomas, Reliabil- DetectionandDisposition Reliability of Ultrasonics and ity Engineering Journal, 198l. Radiography for Weld Inspection, R. DeNale, and C. Lebow- ENI Reliability Databook, Component Reliability Handbook, itz, David Taylor Research Center, Annapolis,D M. C. Galvanin, V. Columbari, G.Bellows, Italy, 1982. Probabilistic Fracture Mechanics and Reliability, J. V. F” Nuclear Plant Reliability Data System, Southwest Research van,(editor),Dordrecht, NL: MartinusNijhoff Publishers, Institute, 198l. 1987, p. 276. Probability, Statistics, and Decisionfor Civil Engineers, J. R. of Probabilistic Lifetime Assessment Ammonia Pressure Ves- Benjamin, and A. Comell, McGraw-Hill, New York, 1970. sels, Life Prediction of Corrodible Structures, O. Saugerud, and S . Angelsen, NACE, Houston,TX, 199l. Assessing Inspection Results Using Bayes’ Theorem, 3rd International Conference & Exhibition on Improving Reli- Positive Materials IdentiJícation of Existing Equipment, H. A. ability in Petroleum Refineries and Chemical Plants, Novem- Wolf, 2nd Intemational Symposium on Mechanical Integ- the ber 15-18, 1994, A. Tallin, and M. Conley, DNV USA, Inc., rity of Process Piping, MTI PublicationNo.48, Houston, Gulf Publishing Company. 1996COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~ STD.API/PETRO PUBL 581-ENGL 2000 m 0332290 Ob21529 33b Section 3”Definitions For the purposes of this publication the following defini- 3.13 consequence area: Reflects the area within which tions apply: an the results of equipment failure will evident. be 3.1 affected area: Represents the amount of surface area 3.14consequence category: See Damage Conse- thatexperiences an effect (toxic dose,thermalradiation, quenceCategory,ChemicalFactor, Quantity Factor, State explosion overpressure, etc.) greater than a pre-defined limit- Factor, Auto-Ignition Factor, Pressure Factor, Credit Factor. ing value. 3.15consequence modeling: Prediction of failure 3.2 auto-ignition factor (AF): Accounts for the consequences based on a set of empirical equations, using increased probability ofignition for a fluid releasedat a tem- release rate (for continuous releases) or mass (for instanta- perature aboveits auto-ignition temperature. neous releases)as input. 3.3 auto-ignition temperature: Temperatureforwhich 3.16 continuous release: One that occurs over a longer a materialcan ignite without a sourceof ignition. period of time, allowing the fluidto disperse in the shape of an elongated ellipse. 3.4 average individual risk: A similar concept to the Fatal Accident Rate, but with a time period one year. of 3.17 corrosion, general: Refers to corrosion dominated by uniform thinning that proceeds withoutappreciable local- 3.5 average rate of death: The average number of fatal- ized attack. ities fromall incidents that might be expected per unit time. 3.18 corrosion, localized: Describes different forms of 3.6Bayes’ theorem: A statistical method which can corrosion, all of which have thecommon feature that the cor- effectively relate an uncertain inspection result with prior to rosion damage produced is localized rather than spread uni- --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- the inspection “expectations” and provide an increased level formly overthe exposed metal surface. of confidence on the equipment damage rate predictions. 3.1 9 cost: Of activities, both dkect and indirect, involving 3.7business interruption (financialrisk): Includes any negative impact, including money, time labor, disruption, the costs which are associated with any failure of equipment goodwill, political and intangible losses. in a process plant. These include, but are not limited to: cost of equipment repair and replacement; downtime associated 3.20 creditfactor (CRF): Accounts for the safety fea- with equipment repair and replacement; costs due potential to tures engineeredinto the unit. injuries associated with a failure; and environmental cleanup 3.21 damage consequence factor: Combination of costs. Chemical Factor, Quantity Factor,State Factor, Auto-Ignition Factor, Pressure Factor, and Credit Factor. 3.8 chemical factor (CF): combination of a chemical A material’s Flash Factor and its Reactivity Factor. Flash Fac- 3.22 damage factor: A measure of the risk associated torscorrespond to the material’s NFF’A Classrating:the with known damage mechanism in the unit; including levels Reactivity Factor is function of how readiiy the material a can of general corrosion, fatigue cracking, low temperature expo- explode when exposed anignition source. to sure, and high-temperature degradation. 3.9 weather cold operation: The additional risks 3.23 damage mechanism: Corrosion or mechanical imposed on plant operations by cold climates,as they inhibit action that produce the equipment damage. maintenance and inspection activities can and result in reduced operatormonitoring of outside equipment. 3.24damagestate: Classificationofequipmentbased on its condition, level of damage. 3.10 condition factor (CCF): physical condition of The 3.25 detection: System a i m s to reduce the leak duration. the equipment from a maintenance and housekeeping per- spective. 3.26 direct effect model: Uses a passlfail approach to predict the consequence from a given outcome. See Impact 3.1 1 consequence: The outcomeof an event or situation Criteria, Probability Unit. expressed qualitatively or quantitatively, being a loss, injury, disadvantage or gain. 3.27 discharge: Material release due to a failure. It can be either instantaneous in nature constant. or 3.12 consequence analysis: performed to aid in estab- lishing a relative ranking of equipment items on the basis of 3.28 dispersibility factor ( I ) A measure of the abil- DF: risk. ity of a materialto disperse. 3-1COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~~ S T D . A ~ I / P E T R O P U B L 581-ENGL 2000 m 0732290 0623530 458 3-2 581 API PUBLICATION 3.29dispersion: Vaporcloudwill be formed after the 3.43 fault tree analysis: A deductive approach to hazard release of vapor or volatile liquid in the environment. The identificationthat focuses onthe causes of an undesired vapor cloud is dispersed through mixing with air until the event. concentration eventually reaches a safe level or is ignited. 3.44 fireball: Occurs when a large quantity of fuel ignites 3.30ductileoverload: Occurswhentheflow stress is after it has undergoneonly limited mixing with the surround- exceeded bythe stress caused by the applied loads. ing ar i. 3.31environment: Areaoutsideafacility’s jurisdiction 3.45 flammability range: Difference between upper and that would require substantial costs to remediate in the event lower flammability limits. of contamination. It can include groundwater tables that pass through the bounds of the facility and would allow contami- 3.46 flammable consequence: Result of the release of nation of waterexternal to the facility. a flammable liquid the environment. in 3.32 environmental consequence: Acute effects from 3.47 flammable effect: Physical behavior of the hazard- a spill; also impact of liquid releases into the environment. the ous material that is released. See Safe Dispersion, Jet Flame, Explosion, Flash Fire, Fireball, and Pool Fire. 3.33environmental effect: 3.48 flash fire: Occurs when a cloud of material bums 3.34environmentalimpact: Criteria spills for to the under conditions that do not generate significant overpres- environment: spills on water, spills above ground, leaking and sure. storage tanks. 3.49 flash temperature: Temperature for which a mate- 3.35 equipment complexity: Indicatorwhichdifferen- rial can ignite given a source of ignition. tiates process vessels based on their size and complexity. 3.50 fluid phase: Defined as either gas or liquid. 3.35.1 equipment factor: Number of components in the to unit that have the potential fail. 3.51 frequency: A measure of likelihood expressed as the number of occurrences of an event in a given time. See also 3.36equipmentmodificationfactor: Specificcondi- Likelihood and Probability. tions that can have a major influence on the failure frequency of the equipment item. The conditions are categorized into 3.52 gas release rate: Is calculated inatwo-steppro- four subfactors. See Technical Module Subfactor, Universal cess.The first step determineswhichgasflowregimeis Subfactor, Mechanical Subfactor, and Process Subfactor. present(sonic for higherinternalpressures,subsonicfor lower pressures). The second step estimates the release rate 3.37event: Anincident or situation,whichoccurs in a using the equation for the specific flow regime. particular place during a particular intervaltime. of 3.53 generic failure frequency: A compilation of avail- 3.38eventtree: Visuallydepict possible the chainof able recordsof equipment failurehistories,developedfor events that lead to the probability of flammable outcomes; each type of equipment and each diameter of piping; built used show various to how individualevent probabilities using records from al plants within a companyor from vari- l should be combined to calculate the probabilityfor the chain ous plants within an industry, from literature sources, past of events. reports, and commercial data bases. The values represent an 3.39 event tree analysis: A technique which describes do industry in general and not reflectthe true failure frequen- the possible range and sequence of the outcomes which may cies for a specificplant or unit. arise from an initiating event. 3.54hazard: A source of potentialharm or asituation 3.40 explosion: Occurs under certain conditions when a with a potential cause loss. to flame front travels very quickly. 3.55hazard operability and study (HAZOP): A 3.41 failure mode and effects analysis (FMEA): An structured brainstorming exercise that utilizes a list guide- of inductive analysis that systematically details, on the compo- words to stimulate team discussions. The guidewords focus nentlevel, al possiblefailuremodesandidentifies l their on process parameters, such as flow, level, temperature, and resulting effects on the system. The technique is most effec- pressure, and then branch outto include other concerns, such tive at identifying single-point failures in a system. as human factors, andoperating outside normal parameters. 3.42fatalaccidentrate (FAR): Estimatednumberof 3.56healthconsequencecategory: Combinationof fatalitiesper 108 exposurehours(roughly l o o 0 employee Toxic Quantity Factor, Dispersibility Factor, Credit Factor, working lifetimes). and Population Factor. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 3.57 IDLHvalue: Immediately Dangerous to Life or 3.72 IOSS: negativeconsequence,financial Any or other- Health value. wise. 3.58impactcriteria: Used to estimate consequences 3.73 loss of containment: Occurs only when the pres- from an outcome; also known as effect models. See Direct sure boundary is breached. Effect Model, Probability Unit. 3.74managementsystemsevaluation: An evalua- 3.59 individual risk measures: Consider the risk to an tion of d areas of a plant’s Process Safety Management’s individual who might be located at any point in the effect system that impact directly or indirectly on the mechanical zones of incidents. integrity of process equipment. 3.60inspectioneffectiveness: Is qualitatively evalu- 3.75 management evaluation systems factor: atedbyassigningtheinspectionmethods toone offive Adjusts the genericfailure frequencies for differences in Pro- descriptive categories ranging fromHighly effective to Inef- cess Safety Management systems. The factor is derived from fective. the results of an evaluation of a facility or operating unit’s management systems that affect plant risk. 3.61 inspection factor: A measure of theeffectiveness of the current inspection program and its ability to identify 3.76mechanical design factor: Measures safety the the activeor anticipated damage mechanisms in the unit. factor within thedesign of the unit, whether it is designedto 3.62 instantaneous release: One that occurs so rapidly current standards, and how unique, complexinnovative the or that thefluid disperses as a single large cloud pool. or unit design is. 3.63 inventory: Upperlimitoftheamountoffluidthat 3.77 mechanical subfactor: Addresses conditions can be released from an equipment item. related primarily to the design and fabrication of the equip- ment. item, such ascomplexity, construction code, life cycle, 3.64 inventory group: Inventoryofattached equipment safety factors and vibration monitoring. that can realistically contribute fluid mass a leaking equip- to ment item. 3.78 mitigation systems: designed to detect, isolate Are and reduce the effects of a release of hazardous materials. 3.65 isolation: Use of isolation systems results in reduc- tion of leak duration time. 3.79monitor: To check, supervise,observecritically, or record the progress of an activity, actionor system on a regu- 3.66 jet flame: Results when a high-momentum gas, liq- lar basis inorder toidentify change. uid, or two-phase release is ignited. 3.80 NBP: Normal Boiling Point. 3.67 life cyde of equipment: Is an indicator which is based on the design life of the equipment item and on the 3.81NFPA flammabilityindex: National Fm Protec- number of years that the item has been in its current service. tion Agency Flammability Index. 3.68 likelihood: Used as a qualitativedescription of prob- 3.82 operational boundaries: Boththenormalopera- ability and frequency. tionandperiodsofnon-routineoperation(startups,shut- --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- downs, processupsets, etc.) of the system being studied. 3.69 likelihood analysis: A database of generic failure frequenciesforonshorerefiningandchemical processing 3.83 phase of dispersion: “Finalstategas” or “Final equipment; which is then modified the Equipment Modifi- by state liquid.” cation Factor and the Management Systems Evaluation Fac- 3.84 PHAST Process HazardsAnalystsScreeningTool, tor. See Generic Failure Frequency, Equipment Modification an integrated software package containing atmospheric dis- Factor and Management Systems Evaluation Factor. persion and consequence modeling routines. 3.70likelihoodcategory: Assigned by evaluating the 3.85physicalboundaries: All equipment that items six factors thatafFect the likelihoodof a large leak.Each fac- make up the pressureenvelope of the system being studied. tor is weighted and their combination results in the Likeli- hood Factor. S e e Equipment Damage Factor, Factor, 3.86pipingcomplexity: Comprisedofthenumberof InspectionFactor, Condition Factor, ProcessFactor, and of connections, numberof injection points, number branches, Mechanical Design Factor. and numberof valves of a piping segment. 3.71 limit state function: Definesamodeof failure, g 3.87plantcondition: Currentcondition of thefacility ( i ,where Zi are random variables associated with the fail- Z) being evaluated, based on general appearance of the plant, ure of process equipment. Probability of failureis the proba- effectivenessoftheplant’smaintenanceprogramandthe < biLity of being in the failure set, g (Zi)O. plant layout and construction.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 3.88 pool fire: Causedwhenliquid poolsof flammable 3.102 release duration: Inventory in the system divided materials ignite. by the initial release rate. 3.89populationfactor (PPF): A measure the num- of 3.103releaserate: 1s the relatively constant rate of berof people thatcanpotentially be affected by atoxicrelease for a material over alongperiod of time. release event. 3.104 representative fluid: Represents a process stream 3.90 post-leak response SyStemS: Mitigation systemsmixture risk the analysis. that are designed todetect, isolate and reducethe effects of a release of hazardous materials. 3.105 risk: chance The of something happening that will have an impact upon objectives. In Risk-Based Inspection, 3-91 Pressure factor (PRF): A measure of howquicklyriskis definedas the productoftwo separate terms-the fluid the can escape. likelihood that a failure will and occur the consequence a of 3.92 primary containment: Refers to all pieces of equipment which containmaterials. process 3.106 risk acceptance: An informed not decision to 3.93 probability: Likelihoodofaspecific outcome, mea-become inVOhd i ariskSih~atiOn- n sured the ratio of specific by outcomes to the total number of 3.107 ,.¡&-based management: Process of risk possible outcomes is expressed as a results (including uncertainties) to between O and 1, with O indicating an impossible outcome the means of risk reduction. and 1 indicating an outcome is certain. 3.108 risk control: That part of risk management which 3.94 probability unit (Probit): A statistical method Of involves the of and assessing a consequence. See Impact Criteria, Direct Effect --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- to eliminate,avoid or minimizeadverse risks facing an Model. enterprise. 3.95 process factor (PF): A measure of the potential for abnormal operations orupset conditionsto initiate asequence 3.109riskidentification: Processofdeterminingwhat can happen, whyand how. leading to a loss of containment. Itis a function of the number shutdowns of or process interruptions (planned or 3.1 1O risk indices: single number measure ofrisk. A unplanned), the stability of the process, and the potential for failureofprotectivedevicesbecause of plugging or other 3.1 risk 11 management: Systematicapplication of causes. management policies, procedures and practices to the tasks of identifying, analyzing, assessing, treating monitoring and 3.96 processsubfactor: A numericvalue assigned to risk. the conditions that are most influenced by theprocess (conti- nuity and stability) and how the facilityis operated. 3.1 12 safe dispersion: Occurs when flammable fluid is released and then disperses without ignition. 3.97 qualitativerickbasedinspection: Provides a broad-based risk assessment of an operating unit or a part of 3.1 13 scenario: Set of events that can result in an unde- anoperating unit. A qualitative inspection requires less sirable outcome. detailed information about the facilityand, as a result, its abil- ity to discriminate is much more limited. 3.114secondary containment: Mitigation system designed to contain process fluidin case of a release from pri- 3.98quantitativeinspection: Provides risk values for mary containment equipment. each equipment item and pipe segment in a unit. With this level of information, a comprehensive inspectionplan canbe 3.1 15 seismic activity: Higher probability of failure of a developed for the unit. facility located in a seismically active area, even when the plant has beendesigned to appropriate standards. 3.99 quantitative risk assessment: Refers to the pre- scriptive methodology that has resulted from the application 3.116 societal measures: risk Consider risk the to of risk analysis techniques at petrochemical process facilities. groups of people are in the effect zones of incidents. that 3.100 quantity factor (QF): Largest amount of material 3.117statefactor (SF): ameasureofhowreadilya that could reasonably be expected to be released from a unit material will flash to a vapor when it is released to the atmo- in a single event. sphere. 3.101 release mass: Amount of material (in lbs) which 3.118 technical module: Systematic methods used to will bereleased during an instantaneous release. assesstheeffect of specificfailure mechanisms on theCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD-API/PETRO PUBL SBL-ENGL 2000 I0732290 Ob2L533 Lb7 I RISK-BASED DOCUMENT INSPECTION BASE RESOURCE 3-5 probability of failure. It evaluates two categories of infor- 3.122 toxic quantity factor (TQF): A measure of both mation: deterioration rate of the equipment items material the quantity and the toxicity of a material. The quantity por- of construction, resulting from its operating environment; tion is based on mass; the toxicity is found using the NFPA and the effectiveness of the facility’s inspection program to toxicity factor NH. identify and monitor the operativedamage mechanisms prior to failure. 3.123universalsubfactor: Numericvalueassignedto the conditions that equally affect all equipment items in the 3.119 technical module subfactor (TMSF): Ratio of facility. See Plant Condition, Cold Weather Operations, and the fiequency of failure due to damage to generic failure the Seismic Activity. frequencytimes likelihood the that the damage is level present. 3.124vibrationmonitoringelement: Value assigned for monitoring rotating equipment such as pumps and com- 3.120 toxic consequence: Effect of a toxic release. equipment fail- pressors to detect developing problems before 3.121 toxic effect: Toxic consequence. ure occurs. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD*API/PETRO PUBL 561-ENGL 2000 U 0732270 Ob21534 OT3 W --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Section &Risk Analysis 4.1 FUNDAMENTALS 4.2 SYSTEM DEFINITIONFORATRADITIONAL RISK ANALYSIS The RBI program outlined in this Base Resource Docu- ment is not a full risk analysis. At its core, RBI is a hybrid In the system definition phase of the analysis, the ground technique that combines the two disciplines of risk analysis rules are establishedandallpertinentinformationiscol- and mechanical integrity. Someof the techniques of RBI are lected. The ground rules of the analysis typically include the similar to those seen in traditional risk analysis, but the two following: arenot interchangeable.BeforeimplementingaRBIpro- gram, one should have a grasp some ofthe fundamen- first of a Goals and objectives-stating the motivation for conduct- . tals of a traditional risk analysis. Knowing the fundamentals ing the risk analysis. Possibleobjectives a e satisfying r: of a risk analysis will help in understanding the differences regulatory requirements, doing a costbenefit analysis, evalu- betweenthe two techniques.Itwillalsohelptheuser to ating risks of a proposed expansion project. understand some of the jargon that has been developed by b. Required risk measures-spelling outthefinalresults risk analysts. required to meet the objectives. This section presents an abbreviated review of the major c. System boundaries-defining the physical and operating concepts of a traditional risk analysis. Figure4-1 portrays an limits of the system. Physical boundaries define the e up qi overview of the traditional risk analysis process. In its ele- ment included in the study. Operating boundaries include the mental form, a risk analysis comprised of five is tasks: function or operating mode of system. the a. System definition. d. Level of detail4efining how units within the system will b. Hazard identification. be analyzed. Questions, such as “will each section of piping c. Probability assessment. be modeled?” or “will piping be combined into groups for d. Consequence analysis. easier analysis?” need to be resolved early in the program. e. Risk results. e. Data collection-defining what data must be captured and risk Some of the phases of a analysis are treated differently maintained. Upto-date drawingsandoperatingprocedures in a RBI program. For example, while hazard identification is are collected for future review. Other pertinent data, such as a critical step in a traditional risk analysis,the RBI program weather or population, may also be gathered, depending on focuses on the pressure boundary of a unit, and it assumes the objectives of the study. If, for instance, the study pertains that failures are due to identifiable mechanisms of degrada- only in flammable hazards and nearest residence is over a the tion in that boundary. Secondary causes of a leak, such as mile away, there would be no need to collect detailed offsite instrument failures or human errors, are included implicitly in population data. A sample of data usually gathered in a risk the RBI program’s treatment of management systems, while aanalysis is provided in Table l. 4- traditional risk analysis would account for these failures in explicit terms. 4.3 HAZARDIDENTIFICATION is The major focus of a traditional risk analysis to evaluate a variety of scenarios that may lead to undesirable outcomes. The task of hazard identification has received much atten- Both the likelihood and the magnitude of these outcomes are tion in recent years.As a result, it is probably most mature the estimated and displayedas results. of the various disciplines that comprise a risk analysis. Poten- In a risk analysis, a scenario represents the set of events tial hazard scenarios need be identified, and there many to are 4-2 that can result in undesirable outcome. Figure presents an techniques for doing so. the order of events in a typical risk analysis scenario: a. Loss of containment. 4.3.1 Hazard and Operability Study b. Detection. A Hazard and Operability Study (HAZOP) is a structured c. Isolation. brainstorming exercise that uses a list of guidewords to stimu- d. Mitigation. late team discussions. The guidewords initially focus on pro- Depending onthe nature of the process and detail of the the cess parameters, such as flow, level, temperature, and study, a risk analysis may include thousands of different sce- pressure, and then branch out include other concerns, such to narios, similar to the one shown here. The analysis would risk as human factors, and operating outside normal parameters. evaluate both the likelihood and the consequence of set of the In a well-designed plant, the majority of identified potential events ineach scenario. ForRBI, likelihood andconsequence deviations are typically operability issues. However, potential are also evaluated, but for a carefully defined and limited safety concerns andenvironmentalconsiderationsarealso number of scenarios. identified. The HAZOP is typicallyperformed by ateam 4-1COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 4-2 API PUBLICATION 581 1 SYSTEM DEFINITION HAZARD IDENTIFICATION --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- /+ F PROBABILITY CONSEQUENCE RISK S Figure 4-l-overview of Risk AnalysisCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 5B3-ENGL 2000 0732290 0623536 97b RISK-BASED BASEINSPECTION RESOURCE DOCUMENT 4-3 L If inspected a not properly, vessel may 1 The leaking hydrocarbon forms a vapor If doud which drifts through the unit. DETECTION fails, little can be done to avert major consequences. 1 ISOLATION allows the operators to stop the release and minimize the consequences of theleak. 1 The effects of therelease canbe reduced if MITIGATION measures are properly implemented. Figure 4-2-Events in a Typical Scenario familiar with the process, rather than an individual, inorder to 4.3.3 Checklists brainstorm the potential hazards most effectively. Checklists are convenient to use the if process is not extremely complex and if the hazards are fairly well known. 4.3.2 Failure Modes and Effects Analysis --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- The checklists are typically developed from other detailed Failure Modes and Effects Analysis (FMEA) is a inductive n hazard identificationstudies, reports from previous accidents, analysis that systematically details, the component level, all on or from expert judgment. Checklists are easy to apply, but possible failure modes and identifies theirresulting effects on they may omit a hazard that is unique to a particular process the system. The technique is most effectiveat identifying sin- or facility. gle-pointfailuresinasystem.The FMEA is usuallyper- formed by filling in a table with the following information: 4.3.4Fault Tree Analysis a. Name. Fault Tree Analysisis a deductive approach hazard iden- to b. Equipment number. tification thatfocuses on causesof an undesired event. The the c. Description/use. approach can be exhaustive to apply, yet it can produce very d. Failure mode. useful results in some situations. It is particularly effective at e. Effect on system. uncovering hazards due to secondary and tertiary causes. f. Probability. 4.4PROBABILITYASSESSMENTFOR A g.Criticality. TRADITIONAL RISK ANALYSIS It is common to have individuals performFMEAs, but they can be performed by a team of experts inorder to ensurethe The probability assessment is conducted to estimate the proper expertise is utilized. probability of Occurrence for the scenarios identified in theCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 4-4 API PUBLICATION 581 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Table 4-1-Typical Data Collected for Risk Analysis recurrence period is sometimes used to refer to the recipro- cal of the frequency. In our example, the recurrence period HAZARDS INFORMATION for the leak would be five years. Inventory of hazardous materials To obtain the frequencyof the scenario (Fscenario), multiply Material Safety Data Sheets the frequency of the leak all (Fhak) by the probability of events Existing HAZOP results that The followresulting likelihood the is scenario’s Location of ignition sources frequency. The mathematical representation of the likelihood DESIGN AND OPERATING DATA of the sequence, in terms of frequency, is shown below: Vessel sizes Piping diameters and lengths FScenario = FLeak X POutcorne Operating conditions Pump andcompressor flow rates 4.5CONSEQUENCEANALYSIS FOR A Dike and drainage design TRADITIONAL RISK ANALYSIS Operating procedures WEATHER DATA The consequences of a release from process equipment or Average wind speeds pipework vary depending on such factors as physical proper- Probabilities of wind directions (“wind rose”) ties of the material, its toxicity or flammability,weather con- DETECTION SYSTEMS ditions, release duration, and mitigation actions. The effects Gas detection may impact plant personnel or equipment, population in the nearby residences, and the environment. Flame, fire detection Hazardous consequencesa e estimated in five phases: r Toxic detection FIREPR(YTECTI0NSYSTEMS l. Discharge Extinguishing agents 2. Dispersion Flow rates 3a. Flammable Effects Actuation procedure 3b. Toxic Effects HISTORICAL DATA 3c. Environmental Effects Site history for release events Depending on the material released, only one of the three Occupational injury statistics effects(3a-3c) is usuallycalculated,although all of them On-site population distribution (day and night) may be possible with releases of certain mixtures. Refer to OFFSITJ? DATA Section 7 for further information on hazardous effects, as they Offsite population relate toRBI. Land use within 1-5 miles Topography around site 4.5.1ConsequencePhase1-Discharge Sources of ahazardousreleaseinclude pipe and vessel previous phase of the risk analysis. If a scenario occurs fairly leaks and ruptures, pump seal leaks, and relief valve venting. frequently,it is best to usehistorical data to estimate the The mass of material, its releaserate, and material andatmo- event’s probability. However, itis often the case in the petro- spheric conditionsat the time of release key factors in cal- are leum industrythat the events ofconcern are so rare that suffi- culating consequences. cient data does not exist to estimate their probability based on Releases can be instantaneous, as in the case of a cata- historical data alone. strophic vessel rupture or constant, as in a sigmficantrelease When historical data is lacking, a building-block approach of material over a limited period of time. The nature of the is used. Probability estimates for all elements of the scenario release will also affect the outcome. With appropriate equa- areobtained and combined to predict the overallscenario tions, it is possible to model either of the two release condi- probability. tions: instantaneous or constant. The most common measure of probability for a scenario 4.5.2ConsequencePhase2-Dispersion is its frequency. Frequencycan be used for a single event or a series of events. Typically, a year is used as the standard When a vapor volatile liquid is released, foms a vapor or it time interval for a frequency analysis. Frequencies may be cloud that may or may not be visible. The vaporcloud is car- very small numbers, such as one a million years for in infre- ried downwind as vapor and suspended liquid droplets. The quent events, or they may be relatively high values, such as cloud is dispersed through mixing with air until the concen- once a month or four times a day. If, for example, a pipe is tration eventually reaches a safe level is ignited. or known to leak about everyfive years or so, it would have a Initially, a vapor cloud will expand rapidly because of the leak frequency of one fiveyears, or 0.2 per year. The term in internal energy of thematerial.Expansionoccursuntil theCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- material pressure reaches that of ambient (atmospheric) condi- The bum rate and flame velocity determines what type of tions. For heavy gases, the material spreads along the ground fire results.Flashfires occur withalarge, dilute cloud in and air is entrained in the vapor cloud, due to the momentum which the material bums faster than the release rate. Conse- of the release. Turbulence in the assists in mixing. cloud quences from a flash fire are only significant within or near As the concentration drops, atmospheric turbulence the perimeterof the burning cloud. becomes the dominant mixing mechanism, and a concentra- A fireball occurs when a large quantity of relatively con- tion profile develops across the vapor cloud. This concentra- centrated material ignites. Thermal radiation levels from the tion profile is an important feature in determining the impacts localizedsource are appreciablebeyond the cloudbound- of the vapor cloud. aries, althoughthey are usually short-lived. Several factors determine the phenomena of dispersion in Jet flames result when a high-momentum gas, liquid, or Phase 2: two-phased release is ignited. Thermal radiation levels are a. Density-The density of the cloud relative to air is a very generally high in direct line with the jet. If a material released important factor affecting cloud behavior. If denser than a r i, is not ignited immediately, a flammableplume or cloud may the cloud will slump and spread out under its own weight as develop. On ignition, this will “flash” or bum back to form a soon as the initial momentum of release starts to dissipate. the jet flame. A cloud oflight gas does not slump, but rises above the point Pool fires are caused by the ignition of pools of non-vola- of release. tile or refrigerated materials.The effects of thermal radiation b. Release Height and DirectiowReleases from a high ele- are limited to a region surrounding pool itself. the vation, such as astack, can result in lowerground-level to Once a cloud dilutes below its lower flammability limit, concentrations for both light and heavy gases. Also, upward it can no longer ignite. releases will disperse more quickly than those directed hori- Under certain conditions, a flame front may travel very zontally or downwards, because ar entrainment i is quickly, causing a pressure wave ahead of the front. If the unrestricted by the ground. flame speed is less than the speed of sound, a deflagration c. Discharge Velocity-For materials that are hazardous only occurs.Iftheflamespeedreachesthe speed of sound, it as at high concentrations, such flammable materials, the initial results in a detonation. Explosion effects are the result of the A discharge velocity is very important. flammable high veloc- overpressure wave generated by deflagrationsor detonations. ity jet may disperse rapidly due toi i i l momentum mixing. nta Explosion intensity is measuredin terms of overpressure lev- d. Weather-The rate of atmospheric mixingis highly depen- els and duration. dent on weather conditions at the time of release. Weather Overpressure ismost damaging to buildings and structures. conditions are defined by three parameters-wind direction, In fact, during an explosion, people inside buildings may be speed and stability. The wind speed has two main effects on a greater riskthan those outside. Collapsingstructures, flying t the release: it determines the overall at which the released rate brick and glass, and othermissiles pose the greatest threat to material is carried downwind (the bulk velocity), and it deter- people during an explosion. mines the of level turbulencewithin cloud, the which the decreases concentrations within vapor cloudas it is diluted 4.5.4 ConsequencePhase3B-Toxic Effects by air. Turbulence generally increases with wind speed. When a toxic material is released, the consequences are 4.5.3 Consequence Phase 3A“Flammable Effects determined by both its concentration and duration. In other Five types of flammable effects can result from a burning words, in order for a toxic effect appear, the cloud must be to hydrocarbon: of sufficient concentration and must linger long enoughfor it the effects to manifest themselves. The required concentra- a. Flash fire. tion and duration a function ofthe material itself. are b. Fireball. Currently, a number of methods are used assess the con- to c. Jet flame. sequence of a toxic vapor cloud terms of concentration and in d. Pool fire. duration. For a variety of reasons, it is difficult to precisely e. Explosion. evaluate toxic responses caused by acute exposures to hazard- A cloud containing flammable material may not be imme- ous materials.First,humansexperiencea widerange of diately explosive. If the concentration of the initial release is adverse health effects from exposure. Second, there is a high above the material’s upperflammability limit, it cannot ignite degree of variation in response among individuals intypical a unless it has becomediluted and asource of ignitionis population. Factors suchas age, health, and level of exertion present. A flame propagates from the point of ignition can affect response toxics. Third, much the data on toxic to of through the region of the cloud thatis between the upper and responses has been taken from animal studies, which do not lower flammability limits. necessarily extrapolate well humans. toCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~ ~~ STD.API/PETRO PUBL 5BL-ENGL 2000 m 0732290 Ob21539 h85 W 4-6 API PUBLICATION 581 There are common two approaches evaluating to the a. Individual Risk Contours: the geographical distribution of effects of a toxic release. The first uses a single criterion that individual risk. These contours show the expected frequency identifiesaspecificlevelatwhichseriousadversehealth of an event capableof causing a fatalityat a specific location, effects may occur. The second uses a probabilistic approach regardless of whether anyone is presentat that location. that reflects a probability of harm among a population for a b. Maximum Individual Risk: the individual risk to the per- given dose. son exposedto the highest riskin an exposed population. This The latter approach uses what is called a probit function can be found by calculating the individual risk at every geo- (6.2.3), which reflects the uncertainty in the response among graphical location, where people are present, and searching humans to a given dose. for the highest value. 4.5.5Consequence Phase 3C"Environmental 4.6.3 Societal Risk Effects Societal risk is a measure risk to agroup of people the of in The release of a hazardous material, resulting from the e#ect zones o incidents. It is most often f expressed in terms of types of scenarios that are addressed by the RBI, usually has the frequency distribution of multiple fatality events.One limited consequences. The most serious environmental dam- common graphical presentation shows frequency the of age results from a large leakof a persistent material, such as events resulting in N or more fatalities. This type of graph is crude oil, whichmay damage flora andfauna,andmay commonly h o w n as an F/N plot. A stylized F/Nplotis require significant cleanup efforts. shown inFigure 4-3. Assessing environmental damage is extremely difficult Societal risk measures are usually reducedto a single num- because of the many factors involved in cleanup efforts and inber risk index to allow easy comparison between different estimating the costs for possible civil penalties or fines. Envi- plants. One example is the Societal Risk Index (SRI) which is ronmental damage is typically assessed based a dollar-per- on also known as thePotential Loss of Life (PLL). This index is of barrel estimate for the material and locationrelease. calculated by summing all the risk pairs used to construct the F/N curve. What this means in practice is taking each data 4.6 WAYS TO PRESENT RISK RESULTS point generated in a traditional risk analysis for frequency of There is no single to measure or present an estimate of way occurrence (F) and corresponding number of fatalities (N), the risk of operating a chemical process. Historically, a num- multiplying F and N together, and summing the results. Note ber of measures have been used express risk in the context to that this operation is done on the raw F and N data from a of a risk analysis. Risks to people are normally presented in quantitative risk assessment. A common misunderstanding is one of three ways described in the following sections. that the points on the F/N plot can be used to calculate the SRI or PLL directly. The multiplying ofrisk pairs cannot be 4.6.1 Indices Risk done directly from the F/N curve becausethe curve shows the frequency for N or more fatalities. Risk indices are a single number measure risk. Some of of The difference between individual andsocietal risk is often the more common risk indices are: confusing. The following scenario provides an illustration to a. Fatal Accident Rate (FAR):the estimated number fatali- of help clanfy the differences: ties per 108 exposure hours (roughlylo00 employee working An office building, located near a high explosives depot, lifetimes). contains 400 people during the day, and one guard at night. If b. Average IndividualRisk a similar concept to the FAR,but thelikelihood of an explosion at the depot resulting in of with a time period one year. destruction of the building is constantthroughout the 24-hour c. Average Rate of Death: the average number of fatalities day, then each individual in that building is subject to a cer- from al incidents that might expected per unit time. l be tain individual risk. This individual risk is independent of the number ofpersons present; it is the Same for each ofthe 400- 4.6.2Individual Risk Measures day people as it is for the one night person. In contrast, the Individual risk measures consider the risk to an individual societal risk is the risk to the whole population in the build- who might be located at any point in the effect zones of inci- ing, andis 400 times higher during the when the building day dent. Some of the more common individual risk measures aer: is occupied than it is at night when onlyone personis at risk. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~~ ~ STD.API/PETRO 581-ENGL PUBL 2000 W 0732290 Ob21540 3T7 RISK-BASED BASEINSPECTION RESOURCE D~CUMENT 4-7 Stylized F/N Plot 1 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 0.1 0.01 0.001 0.0001 0.00001 1 10 1O0 N, Number of Fatalities Figure 4-3-Stylized F/N PlotCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • Section 5-Qualitative Approach To RBI (Operating Unit Basis) 5.1 GENERAL physical boundariesof the study area must be defined before the qualitative analysis is conducted. This section describes the qualitative method using risk for The following sections provide narrative overviewof the a to examine refinery and petrochemicaloperations for process factors that are derivedduring the qualitative analysis, as hazards associated with pressure equipment integrity. detailed in the workbook (see Appendix A). The qualitative approach is similar to that of the quantita- tive analysis, except that the qualitative approach requires less 5.1.2 Likelihood Category detail and is far less time consuming. While the results it yields are not as precise as those of the quantitative analysis, Part A of the workbook deals with likelihood category, the it provides a basis for prioritizing a risk based inspection pro- which is assigned by evaluating the six factors that affect the --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- gram. likelihood of a large leak. Each factor is weighted, and their A qualitative analysis can be performed at any of the fol- combination results inthe likelihood factor. This factor is lowing levels: plotted on the vertical axis the risk matrix (see of Figure 5-1). The six subfactors that make up the likelihood category as are a. An operating unit-example: a complete crude processing follows: unit. b. A major area or functional section in an operating unit- a. Amount of equipment (Equipment Factor, EF). example: the vacuum sectionof the crude processing unit. b. Damage mechanisms (Damage Factor, DF). c. A system+a major piece of equipment and its auxiliary c. Appropriateness of inspection (Inspection Factor, IF). equipment-xample: an atmospheric heater including the d. Current equipment condition (Condition Factor, CCF). feed preheat exchangers and charge pump. e. Nature of the process (Process Factor, PF). unit Throughout this chapter, the term will be used in refer- f. Equipment design (Mechanical Design Factor, MDF). ence to any of these levels of analysis. The qualitative The sum of these six components establishes the overall approach is strongly influenced by the number of equipment likelihood factor. The likelihood category is then assigned items in the unit being studied. Comparable studies should be based on the overall l k l h o factor. ieiod based on similar equipment counts. The qualitative analysis can be performedusing the simple 5.1.2.1 The Likelihood Equipment Factor(EF) is related to workbook approach presented in AppendixA, where a series the number of componenti in the unitthat have the potential of tables guides the user through the evaluation, The work- to fail. TheEF has a maximum value of15 points. book was prepared with the philosophy thata typical refinery 5.1.2.2 The LiklihoodDamage Factor (DF) a measure is unit could be assessed in a few hours. of the risk associated with known damage mechanisms in the Qualitative R B I procedures havethree functions: unit. These mechanisms include levels of general corrosion, a. Screening the units within the site to select the level of fatigue cracking, low temperature exposure, and high-temper- analysis needed and to ascertain the benefit of further analy- ature degradation. This factor receives a maximum value of ses (quantitative R B I or some other techruque). 20 points in the overall assessment. b. Rating the degree of risk within the units and assigning 5.1.2.3 The LikelihoodInspectionFactor (IF) provides a them to a positionwithin a risk matrix. measure of the effectiveness of the current inspection pro- c. Identrfying areas of potential concern at the plant, which gram and its ability to identify the activeor anticipated dam- may ment enhanced inspection programs. agemechanisms in the It unit.examinesthe types of The analysisfirst determinesa factor representing the like- inspections, their thoroughness, and the management of the lihood of failure within the area, then a factor for the conse- inspectionprogram. This factorisweightedwithnegative quences. The two are then combined in the risk matrixto numbers because the quality of the inspection program will produce a riskrating for the unit. partially offset the likelihood of failure inherent in the dam- Before embarking on the more detailed steps of the qualita- age mechanisms from the DF above. The maximum weight tive RBI analysis, the user can perform a simple screening for the inspection factoris 15 points. process, to determine the relativerisks among units. 5.1.2.4 The LikelihoodConditionFactor (CCF) accounts for the physical condition of the equipment from a mainte- 5.1.1 Rating Units Based on Potential Risk nance and housekeeping perspective. A simple evaluation is The qualitative analysis determines a risk rating for an performed onthe apparent condition and upkeepthe equip of operating unit by categorizing the two elements of risk like- ment from a visual examination. The CCF has a maximum lihood and consequence. The chemicals involved and the value of 15 points.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 5.1.2.5 The Likelihood Process Factor ( P m is a measureof of the material’s flash factor and its reactivity factor. Flash the potentialfor abnormal operations or upset conditions to ini- factors correspond to the material’s NFF’A 1 Class rating, tiate a sequence leadingto a loss of containment. It is a func- while the reactivity factor is a function of how readily the tion of the number ofshutdowns or process intemptions material can explodewhen exposed to an ignition source. (planned or unplanned), the stability of the process, and the potential for failure of protective devices because of plugging 5.1.3.3 The Consequence Quantity Factor (QF) represents thelargest amount of material thatcould reasonably be or other causes. The PF weightedat a maximumof 15 points. is expected to be released from a unit in a single event. fac- The 5.1.2.6 The Likelihood Mechanical Design Factor (MDF) tor is based on the largest mass (in pounds) of flammable measures the safetyfactorwithinthedesignoftheunit: inventory in the unit. whether it is designed to current standards, andhow unique, complex, or innovative the unit design is. The is weighted MF 5.1.3.4 The Consequence State Factor (SF)is a measure of at 15 points. how readily amaterial will flashto a vapor when is released it to the atmosphere. is determined from a ratio of the average It 5.1.3 Consequence Category process temperature to the boiling temperatureat atmospheric pressure (using absolute temperatures in the ratio). There are two majorpotentialhazardsassociatedwith refinery and petrochemical operations: (a) f r and explosion ie 5.1.3.5 The Consequence Auto-Zgnition Factor (AF) is risks and (b) toxic risk. In determining the toxic consequence incorporated into the Qualitative Workbook to account thefor category, RBI considers only the acute effects. increased probability of ignition for a fluid releasedat a tem- --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Theconsequence analysisdeterminesadamageconse- perature above its auto-ignition temperature. quence factor, in the Qualitative Workbook, Part B, and a 5.1.3.6 The Consequence Pressure Factor (PRF)is a mea- health consequence factor in Part C.These determinations are sure of howquickly the fluid can escape. In general, liquids or usually made for each chemical. Many chemicals, however, gases processed at high pressure (greater than 150 psig) are exhibit a predominate risk (either fire/explosion or toxicity); more likely to be released quickly and result in an instanta- is thus if the predominant risk for a given chemical known, it neous-type release, withmoresevereconsequencesthana is necessary to determine only thefactor for that risk and not continuous-type release. for both. The consequence that generates the highest letter category is used to determine the qualitative risk rating. Note 5.1.3.7 A Consequence Credit Factor (CRF)is determined B that if a chemical has no flammable characteristics, Partcan to account for the safety features engineered into the unit. be skipped; if it is obvious that no toxic hazards are present, These safety features can play a significant role in reducing Part C can be skipped. the consequencesof a potentially catastrophic release. Several in If there are several chemicals present relatively large per- aspects of unit design and operationare included inthis factor: centages in the area, the user should conduct the exercise sev- a. Gas detection capabilities. of eral times”-once for each the chemicals present in relatively A large proportions. good rule ofthumb is to review the chem- b. Inerting of atmosphere. icals withhigh health consequence, plus c. Security of fire-fighting systems. those that comprise at least 90 - 95% of the total mass of chemicals the area. in d. Isolation capabilities. e. Blast protection. 5.1.3.1 The Damage Consequence Category, Part B in the f. Rapid dump systems. Qualitative Workbook, is derived from a combination fiveof elements that determine the magnitude of a íire and/or explo- g. Fireproofing of cables and structures. sion hazard: h. Capacity of fire water supply. i. Existence of fixed foam systems. a. Inherent tendency to ignite (Chemical Factor, CF). j. Existence of fire water monitors. b. Quantity that canbe released (Quantity Factor, QF). k. Water spray curtains. c. Ability to flash to avapor (State Factor, SF). d. Possibility of auto-ignition (Auto-Ignition Factor,AF). 5.1.3.8 The potential for a fire or explosion to cause dam- e. Effects of higherpressureoperations(PressureFactor, age to the equipment in the unit is then determined by the PW). Damage Potential Factor (DPF). This is accomplished by a f. Engineered safeguards (Credit Factor, CRF). rough estimate of the value of equipment near large invento- g. Degree of exposure to damage (Damage Potential Factor, ries of flammable or explosive materials. DPF). 5.1.3.9 The Damage Consequence Category is then found 5.1.3.2 The Consequence Chemical Factor (CF),a chemi- by combining the above consequence factors and selecting cal’s inherent tendency to ignite, is derived as a combination the category based rangesof these combined factors. onCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD-API/PETRO PUBL 581-ENGL 2000 m 0732290 Ob2L543 O O b W INSPECTION RISK-BASED BASERESOURCE DOCUMENT 5-3 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- A B C D E Consequence Category Figure 5-l-Qualitative Risk Matrix 5.1.3.10 The Health Consequence Category, Part C in the 5.1.3.13 Again,a Credit Factor (CRE) isdeterminedto QualitativeWorkbook,isderivedfromthefollowingele- account for the safety features engineered into the unit. Credit ments that are combined to express the degreeof a potential is given for the following: toxic hazard in a unit: a. Toxic material detection capabilities. a. Quantity and toxicity (Toxic Quantity Factor, TQF). b. Isolation capabilities. b. Ability to disperse under typical prucess conditions (Dis- c. Rapid dump systems. persibility Factor,DF). d. Mitigation systems (spraycurtains, etc.). c. Detection and mitigation systems (Credit Factor, m ) . C 5.1.3.14 The Population Factor ( P P 0 is a measure of the d. Population in vicinity of release (Population Factor, PPF). number of people that can potentially be affected by a toxic release event. The population factor is scaled to show that, as 5.1.3.1 1 The Toxic Quantity Factor (TQF)is a measure of more people are located in a hazard zone, a smaller percent- both the quantity andthe toxicity of a material.The quantity age of the population willbe affected. This result is supported portion is based on mass and is found using an approach by actual data from past toxicrelease events. similar to that shown in the quantity factor in Part B. The toxicity of the material is found using the NFPA toxicity 5.1.3.15 The Health Consequence Cutegory is then found factor, NH. by combining the above consequence factors and selecting the category based on ranges ofthese combined factors. The 5.1.3.12 The Dispersibility Factor ( D F ) is a measure of consequence categories (health and damage) are assigned let- the ability of a material to disperse. It is determined directly ter scores, and theone with the highest value is plotted on the from thenormal boiling point of the material. The higher the horizontal axis of the risk matrix to develop a risk rating for boiling point, the less likely a material is to disperse. the unit.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 5-4 API PUBLICATION 581 5.1 -4 Results 5.2 QUALITATIVEAPPROACHTORBI The likelihood category rating and the highest rating from (EQUIPMENT BASIS) either the damage or the health consequence categories are 5.2.1 Summary usedtoplaceeachunitwithinafive-by-fiveriskmatrix, shown as Figure 5-1. When results are plotted on the matrix, The key variables identified that affect flammable conse- they give an indication of the level of risk for the unit being quencesarefluidtype(withinabroadlydefinedrange), evaluated. When the qualitativeanalysis has included several inventory (again within large ranges) and fluid state in the materials or a multi-component mixture, the unit receiving process (liquidor gas). With just these three variables, a flam- thehighestriskcomponentwill be thebestindicator of mability consequence ranking can determined. With addi- be whether further evaluation necessary, as well asthe urgency is tional information of temperature and pressure, the ranking of that evaluation. can be refined. 5.1.5 Identifying Areas of Inspection Concern Toxic consequences depend heavily upon the percentage of the process fluid that is toxic. Highly toxic process streams or The risk matrix results be used to locate areas of poten- can those that contain a portion of highly toxic components can tial concern and to decide which portions of the process unit beevaluatedusingjustthesame inputs as above,plus a need the most inspection attention or other methods of risk reduction. It can also be used to decide whethera full quanti- broadly estimated range of the percentage of the toxic com- tative studyis justified. ponent in the stream. The shadings provided in Figure 5-1 are guidelines for Business interruption is evaluated by a simple three-cate- determining the degree of potential risk. The shadings are gory assessment production on impact, plus information not symmetrical, as they are based on the assumption that, about whether excess production capacity exists, or if the in almost every case, the consequence factorwill carry more product is in a sold-out market. weight in determining total risk than will the likelihood Likelihood is determinedby simply estimating the suscep- component. tibility of the equipment to one more of six damage mech- or Without the shading, it seems clear that, as theplotted anisms that contribute the most to process plant failures. An value for the likelihood and consequence categories moves towardthe upperright of the matrix, the amount of risk adjustment is made based on the length of time since that last increases. Companies generally wl develop and apply their il inspection was performed on the equipment. own criteria to determine when it becomes necessary to per- Finally,suggested a inspectionfrequency delivered is RBI form a quantitative or adjust their inspection practices. of based on both the consequences and likelihood failure. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STDmAPI/PETRO PUBL 581-ENGL 2000 9 0732270 Ob21545 789 m Section 6"Overview of Quantitative RBI 6.1 GENERAL b. Determineifthefluid is dispersed in a rapidmanner (instantaneous) or slowly (continuous). The failure of pressure-containing equipment and subse- quent release of hazardous materials can lead to many unde- c. Determine if the fluid disperses in the atmosphere a liq- as sirable effects.The FU31 program has condensedthese effects uid or a gas. into four basicrisk categories: d. Estimate the impactsof any mitigation system. e. Estimate the consequences. a Flammable events can cause damage in two ways: thermal . As shown in Figure 6-2, the environmental consequence radiation and blast overpressure. Most of the damage from takes its input directly from release rate or mass informa- the thermal effects tends to occur at close range, but blast effects tion. Also, businessinterruptionrisks are derived directly can causedamage over a larger distance from the blast center. from results found for flammable events. b.Toxic releases, in the RBI approach, are only addressed when they affect personnel. Only acute, as opposed to chronic, exposure is considered. Thesereleases can cause 6.2.1Estimating The Release Rate effects at greater distances thanflammableevents. Unlike The RBI methodology groups all releases into either two of flammable releases, toxic releases do notrequire an addi- types: instantaneous or continuous. Instantaneous releases are tional event (e.g., ignition, as in the case of flammables) to those that empty the contents of a vessel in a relatively short cause anundesirable event. period of time, as in the case brittle failure ofa vessel. Con- of c. Environmental risks are an important component to any tinuous releases are those that occur over period of time a long consideration of overall risk in a processing plant. The RBI 7.5 at a relatively constant rate. Section describes the rules that program focuses onacuteenvironmentalrisks rather than categorize each releaseas either instantaneous or continuous. chronic risks from low-level emissions. Environmental dam- Equations are then used to model the two release types. age can occur with the release of many materials; however, the predominant environmental risk comes from the release 6.2.2 Predicting Type of Outcomes of large amounts of liquid hydrocarbons outside the bounds of the plant. In the contextof the RBI analysis, the outcome a release of d. Business interruption can often exceed the costs of equip- refers to the physical behavior of the hazardous material. mentand environmental damage and, therefore, should be Examples of outcomes are safe dispersion, explosion, or jet accounted for in the RBI program. Equipment replacement fr.Outcomes should not be confused with consequences. ie costs (accounted for in flammable damage estimates) can be For the R B I analysis, consequence (discussed in the next sec- trivial compared to the business loss of a critical unit for an tion) refers to the adverse effectson people, equipment, and extended period of time. the environment as a resultof the outcome. An overview of the quantitative R B I prioritization is The actual outcomeof a release depends on the nature and shown in Figure 6-1. The approach begins with the extrac- properties of the material released. brief discussion of pos- A tion of process, equipment, and other information from the sible outcomesfor various types of events is provided below. RBI database. Various scenarios arethen developed to show how leaks may occur and how they can progress into unde- 6.2.2.1 Flammable Effects sirable events. In the quantitative RBI calculation, one of the four defining factors in a leak scenario is the size of the hole Six possible outcomes can result from the release of a in the equipment. Since there is a one-to-one correspon- flammable fluid: dence between hole sizes and scenarios, these terns are often used interchangeably. a. Safe dispersion occurs when flammable fluid is released The risk calculation is performed for eachscenario, for a ll and then disperses without ignition. The fluid disperses to four risk categories, if desired. The risk for each equipment concentrations below its flammable limits before it encoun- item is then found by summing the individual risk compo- ters a source of ignition. Although no flammable outcome nents fromeach scenario (hole size) calculation. of a OCCLUS,it is still possible that the release flammable mate- rial (primarily liquids)couldcauseadverseenvironmental 6.2CONSEQUENCE OVERVIEW effects. Environmental events addressed separately. are b, Jerfires result when a high-momentum gas, liquid, or two- The consequences of releasing a hazardous material are phase release is ignited. Radiation levels are generally high estimated in five distinct steps: close to the jet. If a released material is not ignited immedi- a. Estimate the release rate or the total mass available for ately, a flammable plume or cloudmay develop. On ignition, release. this will flash or bum back to form jet flame. a 6-1 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • . STD.API/PETRO PUBL SB&-ENGL 2000 m 0732290 Ob2154b B15 6-2 581 . Extract from RBI Database Select a Set of Hole Sizes Section 7.3 Estimate likelihoodof leak Section 8 Estimate consequences Section 7 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Risk = Likelihoodx Consequence Section 6.4 All consequences completed? / YES / All 1 YES v Sum risksfor all scenarios Section 6.4 Figure 6-l"0verview of Quantitative RBI ApproachCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • INSPECTION BASE RISK-BASED RESOURCEDOCUMENT 6-3 . Fluid Properties: Range of Hole Sizes: In Equipment and 0.25, l",4 , Rupture At Ambient Conditions Section 7.3 Section 7.2 Estimate Release Rate Section 7.5 Determine if release is continuous or instantaneous Section 7.6 Determine if Fluid Desperses as a Gas or a Liquid Section 7 7 . ASSESS MITIGATION Section 7.8 v t v FLAMMABLE TOXIC ENVIRONMENTAL CONSEQUENCE CONSEQUENCE CONSEQUENCE BUSINESS INTERRUPTION CONSEQUENCE Figure 6-2"overview of Consequence Calculation --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 6-4 API PUBLICATION 581 c. Explosions occur under certain conditions when a flame is to convert the outcomes to consequences. Effect models, front travels very quickly. Explosions cause damage by the also known as impact criteria, are used to estimate conse- overpressure wave thatis generated bythe flame front. quences from an outcome. d. Flush fires occur when a cloud of material burns under RBI uses two distinct types of impact criteria to estimate conditions that do not generate significant overpressure. Con- consequences from a given outcome: the direct efect model sequences from a flash fire are only significant within the and the probit. Direct effect models are used for flammable, perimeter and near the burning cloud. Flash fires do not cause environmental,business and interruption consequences, overpressures high enough damage equipment. to while toxic consequences are estimated using the probit, for e. Afirebafl occurs when a large quantity of fuel ignites after example. it has undergone only limited mixing with the surrounding The direct effect model uses a pass/fail approach to predict ar Thermal effects from the fireball extend well beyond i. the the consequence from a given outcome. It assumes that no boundaries of the fireball, but they usually short-lived. are effect is observed if theoutcomeisbelowthepredefined f. Pool fires arecausedwhen liquid poolsof flammable threshold. It assumes a single effect for any outcome above materials ignite. The effects of thermal radiae-on are limited the threshold.This approach is fairly coarse since, in reality, a to a region surrounding the pool itself. spectrum ofeffects are observed for a range of outcomes. The probit (short for probability isunit)a statistical 6.2.2.2ToxicEffects method of assessing a consequence. It reflects a generalized Two outcomes possible are when a toxic material is time-dependent relationship for a variable that a probabi- has released: safe dispersal manifestation of toxic effects. or listic outcome described by the normal distribution. The pro- In order for a toxic effect to occur, two conditions mustbe bit has a meanvalue of 5 and a variance of . l met : a. The releasereach must people in sufficient a 6.3 LIKELIHOOD OVERVIEW concentration. The likelihood analysis begins with a database of generic b. Itmustlingerlongenough for the effects to become failure frequencies for the specific equipment types. These harmful. generic frequencies are thenmodifiedbytwoterms,the If either of the conditions are not met, the release of the equipment modification factor (FE) and the managernent sys- toxic material results in safe dispersal, a technical term used tem evaluation factor (FM). An adjusted failure frequency is in risk assessment indicate thatthe incident falls below the to calculated bymultiplying the generic failure frequency by the passlfail threshold (see Section 6.2.3). twomodificationfactors.Thefollowing equation demon- If both of the above conditions (concentration andduration) strates thelikelihood analysis: are met, and people are present, toxic exposure will occur. Frequency &jus& = Frequencygeneric FE X FM X (6.1) 6.2.2.3 Environmental Effects From an environmental standpoint, safedispersal occurs if The database of generic failure frequencies is based on a the released material is entirely contained within physical the compilation of available equipmentfailurehistoriesfrom --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- boundaries of the facility. If thematerial cannot be contained, multiple industries. From these data, generic probabilities of the releaseofahazardousmaterialwill result in aspill. failure have been developed for eachtype of equipment and Ground water contamination is considered be a release that to each diameterof piping. goes beyond plant boundaries. The equipment modification factor examines the specific environment in which each item of equipment operates, then 6.2.2.4Business InterruptionEffects develops amodification factor unique to that equipment item. are Business interruption effects analyzed usingflammable The managernent systems evaluation factor adjusts for the event consequences. As such, the outcomes associated with influence of the facility’s Process Safety Management system the business interruption analysisare the same as those listed on the mechanical integrity of the plant. This adjustment is previously for the effects of flammable events. applied equallyto all equipment itemsin a study. This factor will only provide discrimination for studies at 6.2.3ApplyingEffect ModelsTo Estimate different plants or between units with differing management Consequences systems.However, the evaluationprocess can be used to The first two steps in the consequence calculation predict improve the effectiveness of the PSM program,thereby the outcome in terms of physical phenomena. The third step reducing overall risk.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~ ~ STD.API/PETRO PUBL 581-ENGL 2000 D 0732290 Ob21547 524 RISK-BASED RESOURCE BASE INSPECTION DCCUMENT 6-5 6.4 CALCULATION OF RISK where Given the RBI definition for risk as the productofthecon- Risk, = risk forascenario (fi2 or $ peryear) sequence andthe likelihood offailure, in mathematical terms, the risk for a scenario is Riski,,,,, = risk per item equipment (ft2 or $ per year) An example of the risk calculation is presented below. Risks = C x F, , (6.2) Suppose, after out carryinglikelihood both the and conse- quence calculations, an equipment item showed the following where results: S = scenarionumber Likelihood Risk Consequence C, = consequence (area in fi2 or $) for scenario, Scenario Frequency Equipment Equipment (per year) Damage Damage F, = failure frequency (per year) for scenario, l/4 inch leak 6.9 x 10-6 540 sq. f. t .O037 sq. ft/yr. 1 inch leak 1.7 x lC5 7.500 ft. sa. .1275 sa. ft./yr. For each equipment item, risk is the sumof the risks for the 4 inch leak 1.7 x 10-6 17,500 s .ft q .O289 sq. G.&. all of that item’s scenarios. The units of risk depend on the consequence of interest:In the RBI approach, ft2 per year for Rupture 1.0 x 10-6 130,OOO s .f. .13 sq.ft./yr. q t flammable or toxic consequences, dollars per year for envi- Total Risk of Equipment Damage for Item- 0.29sq. A& .. ronmental or business interruption.The risk for an equipment item is Note: that by examining the for each hole size, the is dom- risks risk inated almost equally by the 1 inch and rupture cases. may not This be intuitive atfirst, but careful study of the methods used can reveal Riski,,, = Z R i s k , unanticipated results that may imply actions that were not at first S obvious. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD-API/PETRO PUBL 581-ENGL 2000 D 0732290 Ob21550 246 m Section 7"Consequence Analysis 7.1 GENERAL The properties of fluidscan typically be found in standard chemical referencebooks. It should be noted that, in the RBI The consequence analysis in an RBI programis performed consequence discharge model, the NBP is used in detemin- to aid in establishing a relative ranking of equipment on items ing the phase of the material following release and either the the basis of risk.The consequence measures presented int i hs the MW or density is used in determining the release rate, chapter are intended as simplified methods for establishing depending whether a liquid or gas, respectively, is released. relative priorities for inspection programs. If more accurate Forevaluating consequences, however, following the is consequence estimates are needed, the analyst shouldrefer to important: more rigorous analysis techniques,such as those used in Flammable consequence results arenot highly sensitive to quantitative risk analysis. the exact material selected, provided the molecular weights An overview of the R B I consequence calculation is shown are similar, because air dispersion properties and heats of in Figure 7-1. The consequences of releasing a hazardous combustionaresimilar for allhydrocarbons with similar fluid are estimated in seven distinct steps: molecular weights. This is particularly true for straight chain a. Determining representative fluid and its properties (Sec- alkanes, but becomes less true as the materials become less tion 7.2). saturated or aromatic. b. Selecting a set of hole sizes, to find the possible range of Hence, one should be very careful when applying the RBI consequences in the risk calculation (Section 7.3). BRD consequence formulas to materials (such as aromatics, chlorinatedhydrocarbons,etc.) notalreadydefined in the c. Estimating the total amount of fluid available for release BRD. In such cases, it is recommended that test runs using (Section 7.4). quantitative consequence analysisprograms be made to more d. Estimating the potential release rate (Section 7.5). appropriately select the correct material that yields similar e. Defining the type of release, to determine themethod used consequence areas. for modeling the dispersion and consequence (Section . ) 76. The fluid properties that apply to the BRD representative f. Selecting the final phase of the fluid, i.e., a liquid or a gas fluids are listed in Table 7-2. The Cp constants are used in (Section 7.7). the IdealGas Heat Capacity Equation: A + BT + CT2 + DT3 g. Evaluating the effect of post-leak response (Section 7.8) (J/mol-K). h. Determining the area potentially affected by the release, or For example, applying the aforementioned method, a mate- the relativecost of the leak due todown time or environmen- rial containing 10 mol% C3, 20 mol% C, 30 mol% Cg. 30 t l cleanup (Section 7.9). a mol% cg, and 10 mol% C, would have the following average "key" properties: 7.2 DETERMINING A REPRESENTATIVE FLUID AND ITS PROPERTIES MW = 74.8 Because very few refinery streams are pure materials, the AIT = 629.8"F selection of a representative material almost always involves NBP = 102.6F making some assumptions. These assumptions, and the sensi- tivity of the results, dependto a degree upon the of c m type o- DENSITY = 38.8 lb./ft3 quences that are to be evaluated. Table 7-1 presents the list of materials modeled in R B I for the Base Resource Document. in Thus, the best selection from the materials the represen- For mixtures,the representative material should be defined tative fluids list would be C3-C5, since the property of first firstly by the NBP and MW, and secondly by the density. If importance is the NBP, and it is non-conservative to select a these values are unknown, one for the mixture can be calcu- representative fluid with a higher NBP than the fluid beiig lated using: considered. If the mixture contains inerts such as COZ, water, etc.,the PropertyMi, = &i Properryi flammable/toxic materials of concern shouldbe chosen, excludmg these materials.This is a somewhat crude assump- where tion that wl result in slightly conservative results, but itis a il fair enough estimation for this process. For instance, if the xi = mole fraction of the component and Proper& material is 93 mol% water and 7 mol% C20, simply model it may be NBP,MW, or Density as C20, using the corresponding inventory the hydrocarbon. of 1 7- --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 581-ENGL 2000 D 0732290 Ob2L55L L82 D 7-2 PUBLICATION API 581 Range of Hole Sizes: Fluid Properties: 0.25", ", Rupture 1 In Equipment and Release Rate at Ambient Conditions I Total Mass Available for Release I I I I I I CONTINUOUS INSTANTANEOUS I USE FLOW RATE use total mass I I I I I I I I I I I Continuous/ Liquid Continuous/ G ; L I Instantaneous/ Liquid I I Instantaneous/ Gas 1 I I I I I I "_"""" I r - - - - - -, I MITIGATION -I I I I I FLAMMABLE TOXIC ENVIRONMENTAL I CONSEQUENCE CONSEQUENCE CONSEQUENCE I I I I I l BUSINESS INTERRUPTION (typical of a type/phase release) / I CONSEQUENCE I I J Figure 7-1-RBI Consequence Calculation Overview --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD-API/PETRO PUBL 58%-ENGL 2000 D 0732290 Ob21552 O19 m RESOURCE RISK-BASED BASE INSPECTION DOCUMENT 7-3 Table 7-1-List of Materials Modeled in RBI Base Resource Document --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Examples Representative Material of Applicable Materials c -c2 1 LNG ethylene, ethane, Methane, c -c 3 5 LPG isobutane,butane,Propane, c 5 Pentane c -C 6 S heptanerun,straight naphtha, lightGasoline, %-C12 -1 c6 c3 1 or atmospheric gas kerosene, fuel, Jet c 7c 5 1 -2 crude typical G s oil, a Cu+ crude heavy Residuum, H2 only HydrogenHydrogen H2S sulfide only HF fluoride Hydrogen Water Water Steam Steamacid Low-pressure (low) Acidth acid Low-pressure Acid (medium) caustic Acid ( i h hg) caustic with acidLow-pressure Benzene, Aromatics Styrene Styrene Table 7-2-Properties of the BRD Representative Fluids Normal Boiling Auto Molecular Ambient Density Point TemperatureGas Gas Gas Gas Cp Cp Cp Cp 1bm3 Weight Fluid OF Constant Constant A State B Constant Constant C D QF Cl-C2 23 5.639 193 Gas 12.3 1.15OE-O1 -2.870E-051,036 -1.300E-O9 c3-c4 51 3.610 6.3 GaS 2.632 0.3188 1.347Em 1.466E-08 6% C6C8 100 42.702 210 Liquid -5.146 6.762E-01 -3.651E-04 7.658E-08 433 C9-C 12 149 45.823 364 Liquid -8.5 l.OlOE+OO -5.56OE-04 l. 180E-07 406 C13-Cl6 205 47.728 502 Liquid -11.7 1.390E+OO -7.720E-04 1.67OE-O7 396 C17-C25 280 48.383 65 1 Liquid -22.4 1.94OE+OO -1.120E-03 -2.530E-07 396 C25+ 422 56.187 98 1 Liquid -22.4 1.940E+oO -1.12OE-O3 -2.53OE-O7 396 H2 2 4.433 -423 Gas 27.1 9.270E-O3 -1.380E-05 7.65OE-O9 752 H2S 34 6 1.993 -75 Gas 31.9 1.440E-03 2.43OE-O5 -1.180E-08 500 HF 20 60.370 68 Gas 29.1 6.610E-04 -2.03OE-O6 2.500E-09 32,000 Water 18 62.3 212 Liquid 32.4 0.001924 1.05E-05 -3.6E-O7 da Steam 18 62.3 212 Gas 32.4 0.001924 1.05E-05 -3.6E-O7 da Acid (low) 18 62.3 212 Liquid 32.4 0.001924 1.05E-05 -3.6E-09 da Acid (med.) 18 62.3 212 Liquid 32.4 0.001924 1.05E-05 -3.6E-O9 n/a Acid (high) 18 62.3 212 Liquid 32.4 0.001924 1.05E-O5 -3.6E-09 da Aromatics 104 42.7314 293.3 Liquid -28.25 0.6159 4.02E-04 9.94E-08 914 Styrene 104 42.7314 293.3 Liquid -28.25 0.6159 4.02E-04 9.94E-08 914 Note: Reid, Robert et. al., The Properfies of Gases and Liquids, 4th Edition, McGraw-Hill, New York, 1987. C, COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584. ~~ ~
  • 7.3 SELECTING A SET OF HOLE SIZES Table 7-3"Hole Sizes Used in Quantitative RBI Analysis In order to carry out the RBI risk calculation in a practical manner, a discrete set hole sizes must be used. would be of It Representative Hole Value Size Range impracticaltoperform risk calculations for a continuous Small O - /4 inch / q inch spectrum of hole sizes. Experience has shown that limiting the number of hole sizes allows for an analysis that is man- Medium l/4 - 2 inches 1 inch ageable yet still reflects the range possible outcomes. of 2 - 6 inches 4 inches Large The RBI method uses a predefined set of hole sizes. This approach provides reproducibility and consistency between Rupture > 6 inches entire diameter of item, up to a maximum of 16 inches studies, and it increases the ease with which the process can be automated with software. RBI defines hole sizes that represent small, medium, large, 7.3.3Pump Hole SizeSelection andrupturecases. The rangeofholesizes is chosento address potential onsite and offsite consequences. For onsite Pumps are assumed to have three possible hole sizes: l/4- effects, small and medium hole-size cases usually dominate inch, 1-inch, and 4-inch. Ifthe suction line is lessthan4 the risk because of their much higher likelihood and potential inches, the last possible hole size will be the full suction line for onsite consequences. For offsite effects, medium and large diameter. Ruptures are not modeled for pumps, and the use of hole-size cases will dominate the risk.To address both onsite three hole sizes for pumps is consistent with historical failure andoffsiterisk,and to providegoodresolutionbetween data. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- equipmentitems, RBI generally usesfour hole sizes per equipment item. 7.3.4 Compressor Hole Size Selection Table 7-3 presents the hole sizes selected for the RBI Both centrifugal andreciprocatingcompressorsusetwo program. hole sizes: 1-inch and 4-inch (or suction line full bore rupture, Table 7-3 defines the possible sizes of holes used in the risk whichever is the smaller diameter). The selection of only two calculation. Depending on the piece of equipment,all of the hole sizesis consistent with historical failure data. above hole sizes may not be feasible. The following para- graphs provide a discussion of how the hole are selected sizes 7.3.5 Atmospheric StorageTank Hole Size for specific pieces of equipment: Selection Atmospheric storage tanks have unique features requiring 7.3.1PipeHole Size Selection special hole sizes. They are usually surrounded by a berm, Piping uses the standard four holesizes: l/4-inch, 1-inch, creating a secondary containment area for leakage. The floor 4-inch, and rupture, provided the diameter ofthe leak is less ofthe t n may leak for extended periods of time before ak than, or equal to, the diameter of the pipe itself. For exam- detection, leading tounderground contamination. ple, a 1-inch pipecan have only two hole sizes, l/4-inch and RBI assumes that these tanks are at least partially above- rupture, because the largest possible choice is equivalent to ground, and that the time to detect a leak is dependent on the 1-inch hole size. A 4-inch pipe can havethree: 1/4-inch, detection methods. Because of the above features and limita- 1-inch, and rupture, for the same reason. tions, the following hole sizes and locations are assumed for atmospheric storage tanks: 7.3.2 Pressure Vessel Hole Size Selection a. l/4-inch, 1-inch, and 4-inch leaks from above-ground sides of the tank. Pressure vessels assume the standard four hole sizes for al l b. Tank rupture fromthe walls or from the floor, provided the sizes and types of vessels. Equipment types included in this floor rupture can flow freely onto the ground around thetank. general classificationae r: c./4-inch and 1-inch leaks in the floor of an atmospheric a. Vessel-standard pressure vesselssuch as KO drums, storage tank. accumulators, and reactors. b. Filter-standard types of filters and strainers. 7.4 ESTIMATING THETOTAL AMOUNT OF FLUID c. Column-distillation columns, absorbers, strippers, etc, AVAILABLE FOR RELEASE d. Heat Exchanger Shell-shell side of reboilers, condens- The RBI consequence calculation requires an upper-limit ers, heat exchangers. for the amount of fluid that can be released from an equip- e. Heat Exchanger Tube-tube side of reboilers, condensers, ment item (the Inventory). In theory, the total amountof fluid heat exchangers. that canbe released is the amount that held withinpressure- is f. FinlFan Coolers-fin/fan-type heat exchangers. containing equipment such as vessels and piping, betweenCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~ STD*API/PETRO PUBL 5B3-ENGL 2000 m 0732290 0623554 993 RESOURCEINSPECTION BASERISK-BASED D~CUMENT 7-5 isolation valves that can be quickly closed. In reality, emer- TaMe 7-4-Assumptions Used When Calculating be gency operations can performed over time to close manual Liquid Inventories Within Equipment valves, deinventorysections, or otherwise stop a leak.In addi- tion, piping restrictions and differences in elevationcan serve Percent Item VolumeEquipment or to effectively slow stop a leak. Liquidliquid Columns 50%of each material Note:TheInventorycalculation as presentedhere is used as an Tray Columns (treated as two upper limit and does not indicate thatthis amount of fluid would be items) released in all leak scenarios. top half 50% vapor bottom half 50% liquid The quantitative RBI approach does not use detailed fluid Knock-out Potsand Dryers l W o liquid hydraulicmodeling.Rather,a simple procedure is used to determine the mass of fluid that realistically be released could Accumulators andDrums 50% liquid in the event of a leak.When an equipment item is evaluated, Separators 50% volume of each material/ its inventory is combined withother attached equipment that phase can realistically contribute fluid mass to leaking item. These Pumps and Compressors Negligible items together forman Inventory Group. The procedure esti- Heat Exchangers 50% shell-side, 25% tube-side mates available mass the lesser of two quantities: as Furnaces 50%liquid/SO% vaporin the a. The mass of the equipment item plus the mass that can be tubes added to it within three minutes from the Inventory h u p , Piping 100% full assuming the sameflow rate from the leakingequipment item, but limited to 8-inchleak in the case ruptures. an of b. The totalmass of the modeled fluid in Inventory Group the b. An accumulator and its outlet piping. associated with thepiece of equipment. c. A long feed pipeline. The three-minute time limit for the added fluid is basedon d. A storage tank and its outlet piping. the dynamics of a large leak scenario. In a large leak, the e. A series of heat exchangers andthe associated piping. leaking vessel will beginto deinventory, while the secondary Once the liquid piping and equipment groups are estab- vesselprovidesmakeup to feed the leak.Large leaks are lished, then add the inventories for each item to obtain the expected to last for only a few minutes, becauseof the many group inventory. This liquid inventory wouldbe used foreach cues givento operators that a leak exists.The amount of time equipment item modeled from that group. the rupture will be fed is expected to range from 1 to 5 min- utes. Three minutes waschosen since it is the midpoint of this 7.4.3Vapor Systems range.Eventhoughthe three-minute assumption is not as For vapor systems, common equipment and piping group applicable to small leaks, it is far less likely that small leaks for vapor systems include: will persist long enough empty the leaking vessel and con- to tinue onto empty other vessels. a The top half of the distillation . column, its overhead piping, Estimating the inventories equipment and pipingcan be for and the overhead condenser. done usingthe following guidelines: b. A vent header line, its knock-out pot, and its exit line. For vapor systems, however, the inventory is not likely to 7.4.1 Equipment Items be governed by the amount of vapor in the equipment items, Liquid inventories within equipment items can be calcu- butratherthe flow ratethrough the system.Therefore,it lated. In line with coarse risk methodology (and some from would be desired to use this flow rate for a given period of API RP 521), the following assumptions in Table 7-4 can be time (say, 60 minutes) and use inventory. I this rate isnot this f used (note that normal operating levels should be used, if known and, since flashing may occur from the liquid also sys- known): tem, itmay be preferable to simply use the upstream group’s liquid inventory. This, however, is likely to lead to a some- 7.4.2 LiquidSystems what more conservative inventory. Forliquidsystems, define therepresentativeequipment 7.4.4 Two-Phase Systems groups which, given acertain failure within that group,could result in similar consequences. Examples of liquid systems Fortwo-phasesystems,such as separators,thepotential be spill inventory the liquidis most likely to used, as it is the of may include: assumption that the release occurs at the of the equipment base a. The bottom half of a distillation column, its reboiler, and item. Again, some conservatism may occur. Fortwo-phase the associated piping. pipes, the upstream spill inventorycan be a consideration such --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • that, if a majority is liquid, then the liquid spill inventory where should be determined. Conversely, if upstream inventory is QL = liquid discharge rate (Ibs/sec), primarily two-phaseor gaseous, then the vapor inventory can be calculated withan allowance for the liquid portion. C d = dischargecoefficient, 7.5 ESTIMATINGTHERELEASERATE A = hole cross-sectional area (sq i ) n, The R B I consequence analysis models all releases as one r = density of liquid (lb/ft3), of two types: DP = difference between upstream and atmospheric a. Instantaneous-also called a “puff” release. pressure (psid), b. Continuous-also known as a “plume” release. g, = conversion factorfrom lbf to lb, (32.2 lb,-ft / An instantaneous release is one that occurs so rapidly that Ibfsec2). the fluid dispersesas a single large cloud or pool. A continu- Thedischargecoefficient for fully turbulentflowfrom ous release is one that occurs over a longer period of time, sharp-edged orificesis 0.60 to 0.64. A value of 0.61 is recom- allowing the fluid to disperse in the shape ofan elongated mended for the R B I calculations. The above equation is used ellipse (dependingon weather conditions).At the onset of the for both flashing and non-flashing liquids. analysis, it is not known if the leak can produce a puff or a plume. Therefore,the analyst must first calculate a theoretical release rate, then apply judgment to determine which release 7.5.2 Gas Release Rate Equations type is more appropriate. There are two regimes flow of gases throughan orifice: for Release rates depend upon the physical properties of the sonic (or choked) for higher internal pressures, and subsonic material, the initial phase, and the process conditions. The flow for lower pressures.G s release rates, therefore, are cal- a analyst choosesthe correct release rate equation, based on the culated in a two-step process. first step determines which The phase of the material when it is inside the equipment item, flow regime is present. The second step estimates the release and its discharge regime (sonic subsonic), as the material is or rate, using the equation for the specificflow regime. The fol- released. Two-phase flow equations have been omitted in the lowing equationdefines pressure the at which the flow interest of simplicity, regimes changefrom sonic to subsonic: The initial state of the fluid is required to be defined as either liquid or gas. The “state” is simply the phase of the where hazardous material that could be released while in the vessel/ line, prior to coming into contact with the atmosphere (i.e., flashing and aerosolization not included atthis point). is For two-phase systems (condensers, phase separators, evap- orators, reboilers, etc.), some judgment as to the handling of In the model needs be taken into account. most cases, choos- to Pt,,,,, = transition pressure (psia), ing liquid as the initial state is more conservative, but maybe P, = atmospheric pressure (psia), preferred. One exception may be for two-phase pipes. H r , ee be the upstream spill inventory can a consideration such that, if K = Cp/Cv, a majority of the upstream material that could be released is vapor, then “vapor” should be selected. The results should also C, = ideal gas heat capacity at constant pressure be checked accordingly for conservatism. It is also suggested (BW-lb mol “F), that items containing two-phases have a closely approximated C , = ideal gas heat capacity at constant volume potential spill inventory; this should assist in not overpredict- (Btufib mol OF). ing results. The release rate equations as follows: are For cases where the pressure within equipment item is the 7.5.1 LiquidDischargeRateCalculation greater than PtrUns, the sonic gas discharge rate equation use and, for cases where the pressure is less than or equal to Discharges of liquidsthroughasharp-edgedorificeare P,,, use the subsonic gas discharge rate equation. described by the work o Bernoulli and Toricelli (Perry and f Green, 1984) andcan be calculated a: s 7.5.3 Sonic Gas Discharge Rate Calculation Discharges of gases at sonic velocity through an orifice be (Perry and Green, 1984) can calculated as: --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 582-ENGL 2000 m 0732290 Ob2255b 7b4 m RESOURCE INSPECTICN RISK-BASED BASE DOCUMENT 7-7 where (7.3) w g(subsonic) = gas discharge rate, subsonic flow (lbshec) All other parameters are as defined previously. where wg(sonic) = gas discharge sonic rate, flow (lbs/sec), 7.6DETERMINING THE TYPE OF RELEASE --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- c d = dischargecoefficient (for gas c = 0.85 to l), d Differentmethods are used to estimatetheeffectsof an instantaneous versus a continuous type of release. The calcu- A = cross-section area (in.*), lated consequences can differ greatly, depending on the type P = upstream pressure (psia), chosen to represent release. Therefore, it is veryimportant the that a release is properly categorized into one of the two M = molecular weight (lb/lbmol), release types. R = gas constant (10.73 ft3-psia/lb-moloR), The criteria below stem from review of historical data on a T = upstream temperature (OR). fires and explosion, which shows that unconfined vapor cloud explosions are morelikelytooccur if more than 10,OOO pounds of fluid are released in a short period of time. The 7.5.4 Subsonic Gas Discharge Rate Calculation modeling of continuous releases uses a lower probabilityfor a vapor cloud explosion (VCE) following a leak. Thus, using Discharges of gases at subsonic velocity through an orifice this threshold to define continuous release reflects the ten- can be calculated a : s dency for amounts released in a short periodof time, lessthan l0,OOO pounds, to result in a flash fìre rather thana VCE. The following process is provided to determine the appro- priate method for modeling the release. The process is depicted in Figure 7-2. Yes I this a "small" (V4-in.) hole? s No v Calculate the amount released in 3 minutes. v Yes No Is this amount > 10,000lbs? v v v INSTANTANEOUS CONTINUOUS Figure 7-2-Process to Determine the Type of ReleaseCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 0732290 Ob21557 bTO m STD-API/PETRO PUBL 581-ENGL 2000 7-8 API PUBLICATION 581 Table 7-5-Guidelines for Determining the Phase of a Fluid Phase of Fluid at Steady-State Phase of Fluid at Steady-State Determinationof Final Phase for Operating Conditions Ambient Conditions Consequence Calculation gas gas model as gas liquid gas model as gas liquid model as gas unless the fluid boiling point at ambient conditions is greater 8OoF, then model as a liquid than liquid liquid as liquid a. All “Small” (l/d-in.) holesmodeled are as continuous 7.8.1.1 Flammable Releases leaks. For the release of flammable materials, isolation valves b. If it takes leSSthan three to 170 000 pounds, Serve reduce the release rate or mass by a to specified mount, the release from the given hole size is instantaneous, and it is depending on the quality of these systems. modeled as a puff type of release. c. All slower release rates are modeled Continuous. as 7.8.1.2 Toxic Releases 7.7 DETERMINING THE FINAL PHASE OF THE Release duration is estimated from the types leak detec- of FLUID tion andisolation systems. The duration is then used as direct input to the estimation of toxic consequences. Mitigation sys- The dispersion characteristics of a fluid after release are tems, such as water curtains, will serve to reduce the spread strongly dependent on the phase (i.e., gas or liquid) in the of material which, turn, will reduce the final consequences. in environment. If there is no change of phase for the fluid when going from the steady-state operating conditions to 7.8.1.3 Releases to the Environment steady-state ambient conditions, the final phase of the fluid is the same as the initial phase. However,if the fluid would Environmentalconsequences are mitigatedintwoways: tend to change state upon release, the phase of the material physical barriers act contain leaks on-site, and detection and to may be difficult to assess for thepurpose of the consequence isolation systems limit the duration of the leak. In RBI, the volume contained onsite is accounted for directly in the spill calculations. Table 7-5 provides simple guidelines for deter- mining the phase of the fluid for the consequence calcula- calculation. Detection and isolation systems serve to reduce the duration ofthe leak and, thus, the final spill volume. tion, if more sophisticated methods are not available. Consultation with process or operations personnelis appro- priate in this determination. 7.8.2 Assessing Post-Leak Response Systems All petrochemical processing plants have a varietyof miti- 7.8EVALUATINGPOST-LEAKRESPONSE gation systems thatare designed to detect, isolate, and reduce the effects of release of hazardous materials.RBI has devel- a Evaluating post-leak response is the final step the conse- in oped a simplified methodology assessing the effectiveness for quence analysis. In this step, the various mitigation systems in of of various types mitigation systems. place are evaluated for effectiveness in limiting consequences. Mitigation systems affect a release in different ways. Some systems reduce duration by detecting and isolating the leak. 7.8.1ApproachToEvaluatingPost-LeakResponse Other mitigation systems minimize the chances for ignition Two keyparameters are determined in the post-leak or the spread of material. In RBI, consequence mitigation response evaluation: release duration and reduction of the systems are treated two ways: in spread of hazardous materials. Release duration is a criti- calparameter intoxicand environmentalconsequence a. Systems that detect and isolate a leak. evaluations. Flammable materials quicklyreachsteady- b. Systems that are applied directly to the hazardous material state concentrations, therefore, duration is not a significant to reduce consequences. factor for flammables. Business interruption risks are esti- mated directly from flammable consequenceresults so 7.8.3 Assessing Detection and Isolation Systems they, too, are not highly sensitive to the leak duration. Detection and isolation systems are assessed using a two- For these reasons, different approaches are necessary for step process: evaluating the post-leak response for the 4 types of conse- quences analyzed in RBI. The specific approaches for each a. Determine the classification rating the applicable detec- of consequence type are described briefly below. tion and isolation system. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 583-ENGL 2000 m 0732290 Ob21558 537 m RISK-BASED RESOURCE DOCUMENT BASE INSPECTION 7-9 b. Refer to the specific consequence calculation section to Table 7-&Detection and Isolation System Rating estimate the effects of detection and isolation systems on the Guide the consequences. Table 7-6 provides guidance to the user for assigning a T p Detection Detection y e of System Classification qualitative letter rating B, or C ) to the units detection and (A, isolation systems. These letter ratings are later used in the Instrumentation to designed specifically A detect materiallosses by changes in operat- consequence estimation sections determine the effect of the to ing conditions (ie., loss of pressure or mitigation systems on final consequences. Note that Detec- flow) in t e system. h tion System A is usually found only in specialty chemical applications and is not often used in refineries. It is provided Suitably to located detectors determine B here for completeness. when the material is present outside the The information presented in Table 7-6 is used only when pressure-containing envelope. evaluating the consequences o continuous-type releases. In f visual cameras, detection, or detectors C other words, if more than 1, O pounds of hydrocarbon are 0 O O with marginal coverage released in 3 minutes, the process of assessing detection and isolation capabilityis not applied. . Qpe Isolation Isolation of System Classification Using human-factors analysis techniques, quality ratings the and of the detection isolation systems have translated into been Isolation activated shutdown or systems A an estimate of leak duration. Totalleak duration, presented in directly fromprocess instrumentation or detectors, with no operator intervention. Table 7-7, is the sum of the following times: a. Tune to detectthe leak. Isolation systems by shutdown activated or B b. Tune to analyze the incident and decide upon corrective operators in the control room or other suit- action. able locations remote the leak. from c. Time to complete appropriate corrective actions. The values in Table 7-7 are suggested for use in RBI. If the Isolation on dependent manually-operated C valves user has access to better information regarding operator response times, those values instead of Table7-7. use 7.8.4 Assessing Direct-ApplicationSystems There is no standard approach to assessing systems that Table 7-7-Leak Durations Based on Detection and apply the mitigation measures directly to the hazardous mate- Isolation Systems rial. For this reason, these types of mitigation systems are Isolation Detection addressed separately for each consequence t p .Refer to 7.9 ye System Rating Rating Leak System Duration for details. A A 20 minutes for /&inchleaks 7.9DETERMININGTHECONSEQUENCES OFTHE 10 minutes for 1-inch leaks RELEASE 5 minutes for 4-inch leaks The following sections presentthe methodology for calcu- A B 30 minutes for l/4inch leaks lating the consequence measures for each of the four major 20 minutes for 1-inch leaks consequence categories: flammable, toxic, environmental, and 10 minutes for 4-inch leaks business interruption. C 40 minutes for /4-inch leaks 7.9.1Overview of Consequence Estimation 30 minutes for 1-inch leaks 20 minutes for 4-inch leaks The 4 major consequence categories are analyzed in differ- ent ways: AorB 40 minutes for l/4-inchleaks a. flammable toxic The and consequences are calculated 30 minutes for 1-inch leaks 20 minutes for 4-inch leaks using event trees determine the probabilities of various out- to comes (e.g., flash fies, vapor cloud explosions), combined C 1 hour for /4-inch leaks with summary equations based on using computer modeling 3 minutes for 1-inch leaks 0 to determine the magnitude of the consequence. 20 minutes for 4-inch leaks b. Business interruption risks are estimated as a function of the flammable consequence results. A, B, or C 1 hour for /&ch leaks c. Environmental consequences are determined directly from 40 minutes for 1-inch leaks mass available for release or from the release rate. 20 minutes for 4-inch leaks --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 7-1O The flammable and toxic consequence computations have 7.9.3.1FlammableConsequenceAnalysis been calculated using a hazards analysis screening software Procedure package containing atmospheric dispersion and consequence The determination of flammable consequences has been modeling routines. As will be seen in the next sections, the greatly simplified for this BRD, allowing the RBI analyst to output has been distilledto a usable form correlating conse- by --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- quences directly to releaseparameters. As aresult,conse- determine approximate consequence measures using only the following information: quences are estimated from a setempirical equations, using of release rate (for continuous releases) or mass (for instanta- a. The representative material and its associated properties. neous releases) as input. If RBI users so desire, they may sub- b. The type and phase of dispersion. stitute comparable dispersion and consequence models for the c. The release rate or mass, depending on thetype of disper- predefined summary equations provided this chapter. in sion andthe effects of mitigation measures. 7.9.2GeneralInputAssumptions 7.9.3.1.1 Theconsequenceresults derived are using the following steps: The computer modelingused to determine finalconse- quences required specific input regarding meteorological and Step l. Note thetype of release and the phase ofdispersion. release conditions. Meteorological conditions representative Step 2. Choose the appropriate table, based onthe type of of the Gulf Coast annual averages were used for RBI conse- release: quence analysis. The input assumptions were follows: as Table 7-8 for continuous type releases where auto igni- a. Atmospheric Temperature 70°F. tion is not likely. b. Relative Humidity 75%. Table7-9forinstantaneoustype releases whereauto c. Wind Speed 8 mph. ignition isnot likely. d. Stability Class D. Table 7-10 for contiiuous type releaseswhere auto e. Surface Roughness Parameter 0.1 (typical for processing ignition is likely. plants). Table 7-1 1 for instantaneous type releases where auto f. Initial pressures and temperaturestypical of mediurn-pres- ignition is likely. sure processing conditions within a refinery. Step 3. Once the correct table has been selected, refer to g. Both vapor and liquid releases from a vessel containing the correct half of the table to use: saturated liquid, withrelease orientation horizontaldown- Left half for gases. wind at an elevation of ten feetover a concrete surface. Right half for liquids. Analysis hasshown that theseassumptions are satisfactory Step 4. Choose appropriate the column, based on the for a wide varietyof plant conditions. desired effectof interest: Area of equipment damage. 7.9.3 Flammable/Explosive Consequences Area of potential fatalities. For flammable materials, RBI measures consequences in Step 5. Select the equation in the appropriate column cor- terms of the urea affected by the ignition of a release. There responding to the representative material. are severalpotentialoutcomes for any releaseinvolvinga Step 6. Replace the “X’ in the equation with either the flammable material, however, RBI determines a single com- release rate or release mass, depending the t p of release. on ye bined resultas the average ofall possible outcomes, weighted The resulting value is the probability-weighted affectedarea, according to probability. Theprobability of an outcome is dif- in square feet. ferent from, and should not be confused with, the likelihood 7.9.3.1.2 The consequence tables referred to the in of a release (see Section 8). The probability of an outcome above procedure were derived using the following 3-step represents the probability that a specific physical phenome- process: non (outcome) will be observed after the release has occurred. Potential release outcomes for flammable materials are: Step 1. Predicting the probabilities of various outcomes Step 2. Calculating the consequences for each type of out- a. Safe Dispersion(SD). come. b. Jet Fire (W. Step 3. Combining the consequences into a single proba- c. Vapor Cloud Explosion (VCE). bility-weighted empirical equation. d. Flash Fire (FF). e. Fireball (BL). a. Step 1--predicting Probabilities of Flammable Outcomes f. Liquid Pool Fire (PF). Each outcome is the result of a chain of events. trees, Event A brief description of each outcome hasbeen provided in as shown in Figure 7-3, were used inR B I to visually depict 6.2.2. l. the possible chain of events that lead to each outcome. TheCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD=API/PETRO PUBL SBJ-ENGL 2000 0732290 Ob2LSb0 L95 INSPECTION BASE RISK-BASED RESOURCE DCCUMENT 7-1 1 Table 7-8-Continuous Release Consequence Equations-Auto Ignition Not Likelp Final Phase Gas Final Phase Liquid Area of Quipment Area of Area of Equipment Area of Material Damage (ft2) Fatalities (fi2) Damage (ft2) Fatalities (fi2) c142 A = 43 #.98 A = 110#.% c344 A = 49 A = 125#.% c5 A = 25.2 A = 62.1 A = 536 A = 1544 c6-Cs A = 29 A = 68 A = 182 A = 5 16 c9-c 12 A = 129 . 9 8 A = 29 #.% A = 130 A = 313 CIS16 A=64#.W A = 183 fi.89 c1N25 A = 20 #.W A = 51 c5 2+ A = 11~0.91 A = 33 H2 A = 198 A = 614 X"933 HS 2 A = 32 x1.O0 A = 52 .d.C"J HF Aromatics A = 121.39.~?.~~~~ A = 359 #.8821 Styrene A = 121.39#.8911 A = 359 9.8821 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Note: Shaded area represents cases which equationsare nonapplicable. in x = total release rate, lb/=. A = area, ft2. aNot likelyif process temperature is lessh n auto ignition temperature plus 80°F. ta Table 7-9-Instantaneous Release Consequence Equations-Auto Ignition Not Likelp Final Phase G s a Final Phase Liquid Area of Equipment Area of Area of Equipment Area of Material Damage (ft2) Fatalities (fi2) Damage (ft2) Fatalities (fi2) c142 A = 41 .8.67 A = 79 f i . 6 7 c344 A = 28 A = 51.1 #.15 c 5 A = 13.4 A = 20.4 #.16 A = 1.49fi.8s A = 4.34 c648 A = 14 A = 26 A = 4.35 A = 12.1 #.la C612 A = 7.1 A = 13 A = 3.3 A = 9.5 #.76 CIS16 A = 0.46 A = 1.3 ClS2.5 A=0.11d*91 A = 0.32 c25+ A = 0.03 A = 0.081$ W . H2 A = 545 A = 982 #.6s2 H2S A = 148 A = 211 HF Aromatics A = 2.26 #.8227 A = 10.5 #-7583 Styrene A = 2.26 #.8227 A = 10.5$.7sa3 Note: Shaded area represents cases which equationsare nonapplicable. in x = total release mass, lb. A=area,ft2. aNot likely if process temperature is less auto ignition temperature plus than 8PF.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO SBL-ENGL PUBL 2000 I0732290 ObZL5bL 0 2 1 7-12 API PUBLICATION 581 Table 7-1O-Continuous Release Consequence Equations-Auto Ignition Likelya Final Phase Gas Final Phase Liquid Area of Equipment Area of Area of Equipment Area of Material Damage (ft2) Fatalities (ft2) Damage (ft2) Fatalities (fi2) C1X2 A = 280 A = 745 A = 315 xl-OO A = 837 A = 304 xl.OO A = 81 1 xl.OO A = 313 x1.O0 A = 828 xl.OO AA 525 = = 1315 A = 39 1#.95 A=981 #.92 A = 560 P.95 A = 1401,8.92 A = 1023 9.92 A = 2850 A = 861 A = 2420 #.m A = 544 x .? A = 1604#.m --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- A = 1146xl.00 A = 3072 &O0 A = 203 A = 375 Styrene Shaded area represents cases which equations are nonapplicable. in x = total release rate, Ib/sec. A = area, ft2. aMust be processed at least80°F above auto ignition temperature. Table 7-11-Instantaneous Release Consequence Equations-Auto Ignition Likelp Final Phase Gas Final Phase Liquid Area of Equipment Area of Area of Equipment Area of Material Damage (fi2) Fatalities (fi2) Damage (ft2) Fatalities (ft2) c1x2 A = 1079 A=31009.~~ c 3 4 4 A = 523 A = 1768 c5 A = 275 #.61 A = 959 %x8 A = 16.8.61 A = 962 #.63 W 1 2 A = 28 1 A = 988 A = 6.0 #.53 A = 20 $34 c13416 A = 9.2 A = 26 C17-C25 A = 5.6 A = 16 A = 1.4 A = 4.1 P " . A = 4193 #.621 A = 1253 HF Aromatics Styrene Shaded area represents cases which equations are nonapplicable. in x = total release mass, lb. A = area, fi2. aMust be processed at least 80°F above autoignition temperature.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~ STD.API/PETRO PUBL SBL-ENGL 2000 E 0732290 O b Z L S b 2 T b 8 RISK-BASED INSPECTION RESOURCE BASE DOCUMENT 7-13 Instantaneous-Type Release VCE Late lanition I I Fire Flash Fireball Ignition Early Final State Above AIT Fireball Gasn Safe I No lanition Ignition Pool Liquid Final I Safe No Ignition Continuous-Type Release VCE Flash Fire Fire I Jet IgnitionEarly --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---State Final AIT Fire Jet Gas I L Safe No Ignition Pool Fire Ignition I Liquid State I I Fire Jet I No Ignition DisDersion Safe Figure 7-%RBI Release Event Trees COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 561-ENGL 2000 m 0732270 0623563 q T 4 7-14 API PUBLICATION 581 Table 7-12-Specific Event Probabilities-Continuous Release Auto ignition Likelp Final State Liqui&hcessed Above AT I Probabilities of Outcomes Fluid Ignition VCE Fireball Flash Fire Jet Fue Pool Fire c142 c344 1 1 05 . 0.5 0.5 0.5 1 Final State Gas - Processed Above I AT Probabilities of Outcomes --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Fluid Ignition VCE Flash Fire Fireball Fire Jet Pool Fire c142 0.7 0.7 c -4 3c 0.7 0.7 CS 0.7 0.7 c648 0.7 07 . c412 0.7 0.7 c13416 c17425 c25+ H2 0.9 0.9 H2S 0.9 0.9 Note: Shaded areas represent outcomes that not physically possible are aMust be processed a least 80°F above A T t I event trees also are used to show how various individual event Flammability Range(difference between upper and probabilities should be combined to calculate the probability lower flammability limits). for the chain of events. If a fluid is released at a temperature well above its auto For a given release type,the factor that defines the outcome ignition temperame (at least 80°F above), ignition probabili- of the release of flammable material the probability and is tim- ties will change dramatically. These reflected i Tables 7- are n ing of ignition. The three possibilities depicted in the outcome 12 and 7- 13. event trees were: no ignition, early ignition, and ignition. late b. Step 24alculating Consequences for Each Outcome The event tree outcome probabilities for all release types To calculate the consequences of a particular event, it is are presentedin Tables 7-12 and 7-13 according to the release first necessaryto define the threshold levels neededto cause a type and material. Each row within tables contains proba- the specific consequence. These threshold levels are referredto as bilities for each potentialoutcome, according to material. impact criteria. Event trees developed for standard risk analyses were used to RBI uses 2 sets of impact criteria to determine the size of develop therelative outcome probabilities.Ignition probabili- the area affected: equipment damage and personnel fatality. ties were basedon previously developed correlations. In gen- eral, ignition probabilities are foundas a function ofthe Muipment Damage Criteria: following parameters for the fluid: Explosion Overpressure-5psig. Thermal Radiati0~12,OOOBTU/hr-ft2 (iet fire and Auto Ignition Temperature (AIT). pool íïre). Flash temperature. Flash Fire”25% of the area within the lower flamma- NF€?A FlammabilityIndex. bility limits (LFL) the cloud whenignited. ofCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 583-ENGL 2000 0332290 Ob23564 830 RISK-BASED INSPECTION BASE RESOURCEDEUMENT 7-15 Table 7-13-Specific Event Probabilities-Instantaneous ReleaseAuto Ignition Likelp Final State L i q u i b b e s s e d Above AIT Probabilitiesof Outcomes Fluid Ignition VCE Fireball Flash Fire Jet Fire Pool Fire c142 0.7 0.7 C S 4 0.7 0.7 c 5 0.7 0.7 c648 0.7 0.7 W 1 2 0.7 0.7 c1416 Cls25 Cu+ H2 0.9 0.9 H2S 0.9 0.9 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Probabilities of Outcomes Flash Fire Jet Fluid Fireball Ignition VCE Fire 1 Pool Fire c42 0.7 0.7 c344 0.7 0.7 CS 0.7 0.7 c648 0.7 0.7 W 1 2 0.7 0.7 c13416 Cls25 Cu+ H2 0.9 0.9 H2S 0.9 0.9 Note: Shaded areas represent outcomes that not physically possible. are aMust be processed at least 80°F above AIT. Personnel Fatality Criteria: x = release rate (lb/sec for continuous) or release Explosion Overpressure-5psig. mass (lb for instantaneous). Thermal Radiation-4,OOO BTU/hr-ft2 (jet fire, fireball, and poolfire). The consequences of releases of flammable materials are Flash F i r e t h e LFL limits of the cloud when ignited. not strongly dependent on the duration of the release, since most fluids reach a steady state size or “footprint” within a A set of representative materials was run through the haz- short period of time when dispersed in the atmosphere. The ards analysis screening programto determine conse- the only exception to t i generalization is a pool fire resulting hs quence areas for all potential outcomes. Theconsequence from the continuous release of a liquid. If flammable liquids areas were then plotted against the release rate or mass to are released in a continuous manner, the consequences asso- generate graphs. When plotted on a log/log scale, the conse- ciated with a pool fire will depend on the duration and the quence curves fonn straight l i e s that can fit toan equation be total mass of the release. relating consequence area the release rate or mass. to For pool fires, the R B I method assumes a dike size of 100 are The consequence equations presented in the following feet by 100 feet (l0,OOO square feet) and estimates the flam- form: mable consequences due to pool fire of that size. a A=axb (7.5) Step 3-Calculation of the CombinedConsequence Area where An equation that represents a single consequence area for be the combinationof possible outcomes can derived for each A = consequence area (ft2), of the four release types, !inal phase cases. The combined a,b = material and consequence dependent constants, consequence area is determined a two-step process: byCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD-APIIPETRO PUBL 581-ENGL 2000 H 0732290 0623565 7 7 7 H 7-16 API PUBLICATION 581 Table 7-1&Specific Event Probabilities-Continuous Release Auto Ignition Not Likelp Final State Liquid-Processed Below AIT Probabilitiesof Outcomes Fluid Ignition VCE Flash Fire Fireball Fire Jet Pool Fire c -c2 1 c -c 3 4 o. 1 c 5 o. 1 0.02 00 .8 c - 6 c8 o.1 0.02 00 .8 (&-c12 0.05 00 .1 00 .4 c3 - 1 1 c6 0.05 0.01 0.04 c7 - c 5 1 2 0.02 0.005 0.015 C25+ 0.02 0.005 005 .1 H2 H2S Final State Gas--Processed Below AIT Probabilities of Outcome Fluid Ignition VCE Flash Fire Fireball Fue Jet Pool Fire c -c 1 2 0.2 0.04 0.06 o.1 c -c 3 4 o.1 0.03 0.02 0.05 c5 o.1 0.03 0.02 0.05 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- %-C, o.1 0.03 0.02 0.05 C9-cl2 0.05 0.01 0.02 0.02 c 3 -c16 1 c7 - c5 1 2 C25+ 0.02 H2 0.9 0.4 0.4 o. 1 H2S 0.9 0.4 0.4 0.2 Note: Shadedareas represent outcomes that not physically possible. are aNot likely if process temperature lessthan auto ignition temperature plus is 80°F. l. Multiply the consequence area for each outcome (com- Pi = specific event probability, from Table or 7-9, 7-8 putedfromEquation 7.5) by theassociatedevent tree Ai = individual outcome consequence area, from probabilities (taken Table from 7-12 or 7-13). the If impact criterion uses only a portion of the consequence Equation 8.5 (ft2). area (for instance, flash fires use only 25% of the area The procedure for combining consequence equations for within theLFL for equipment damage) include in the this all of the potential outcomes was performed for aof repre- set probability equation. sentative materials.The results are presented in Table 7-14 for 2. Sum all of the consequence-probability products found continuousreleases and Table 15 for instantaneous releases. 7- in Step 1. The equation that summarizes the result of the process is as 7.9.3.2 Adjustments to Release Magnitudes for follows: Mitigation Systems The adjustments to release characteristics based on detec- Ac*& = PlAl + P2 +...+ Pgli A2 (7.6) tion, isolation and mitigation systems provided in Table are 7- where 16. These valuesare based on engineering judgment, utilizing experience in evaluating mitigation measures in quantitative Ac*& = combined consequence area (ft2), risk analyses. See 7.8.2 for a discussionof the rating process.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • RISK-BASEDiNSPECTlON BASE DOCUMENT RESOURCE 7-17 Table 7-1&Specific Event Probabilities-Instantaneous Release Auto Ignition Not Likelp Final State Liquid--Processed Below AIT Probabilitiesof Outcomes Fluid Ignition VCE Fireball F ash Fm I Jet Fire Pool Fire c -c 1 2 o. 1 o.1 o. 1 0.1 0.05 0.05 0.05 0.05 0.02 0.02 0.02 0.02 Fluid Ignition VCE Fireball Flash Fm Jet FIre Pool Fire c - 1 c 2 0.2 0.04 0.01 0.15 c c 3 4 - o. 1 0.02 0.0 1 0.07 CS o. 1 0.02 0.01 0.07 c -c 6 8 o. 1 0.02 0.01 0.07 c, - c2 1 00 .1 00 .4 0.025 0.005 c3 c6 1- 1 c7 - 1 c5 2 c 5 -k 2 H2 0.9 0.4 o.1 04 . H2S 0.9 0.4 o. 1 0.4 Note: Shaded areas represent outcomes thatnot physically possible. are aNot likelyif process temperature is less auto ignition temperature plus than 80°F. Table 7-1"Adjustments to Flammable Consequences for Mitigation Systems ~~ ~ Response System Ratings Detection Adjustment Consequence Isolation Amass by or rate release Reduce A 25% A B rate release Reduce by or mass 20% AorB by mass C or rate release Reduce 10% B by mass or B rate release Reduce 15% C consequences C to No adjustmentnt Consequence System Mitigation Inventoryblowdown, coupled isolation with system rated B or higher Reducereleaserate or mass 25% by Fire water deluge system and monitors Reduce consequence area by 20% Fm water monitorsonly Reduce consequence area 5% by Foam spray system Reduce consequence area by 15% --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD=API/PETRO PUBL 581-ENGL 2000 I0732290 Ob21567 5 4 T 7-1a API PUBLICATION 581 7.9.3.3AssumptionsandLimitations 7.9.4.3 Representative Materials If the material being released is not apure toxic material, a The consequence modeling procedurefor RBI is a greatly representativematerialshould be used for dischargerate simplified approach to relatively a complexdiscipline. modelingpurposes. The representativematerialshould be Because of the levelofsimplification,alargenumberof selected based upon the average boiling point, density, and assumptions are implicit in the procedure in addition to the molecular weight of the mixture. Since HF is a flame s u p assumptions that would be part of a more in-depth analysis. pressant,flammableconsequences can be ignoredfor HF This section is intended highlight a few of the more impor- to concentrations greater than 65 mol%. tant assumptions related to the simplified approach, but does not attempt a comprehensive discussion. 7.9.4.4 Release Rate/Mass a. The consequence area does not reflect where the damage 7.9.4.4.1 For the most part, HF is stored, transferred, and occurs. Jet and pool fires tend to have damage areas localized processed in liquid form. However, the toxic impact associ- around the point of the release, vapor cloud but explosions and ated with a release of liquid HF to the atmosphere is due to flash fires may result in damagefrom the release point. far cloud. A toxic vapor cloud of the dispersion of the toxic vapor b. The use of a fixed set of conditions for meteorology and HF can be produced by flashing of liquid upon release or the release orientationsis a great simplification over detailed con- evaporation from a liquid pool. For RBI, the initial state of sequence calculations because factors these can have a HF is assumed to be liquid the models for calculating the significant impacton the results. toxic impact areasfor HF liquid releases take into account the c. The use of the standardized event trees for consequence possibility of flashing and pool evaporation. For releases, HF is outcomes and ignition probabilities a limitation of the RBI R B I uses the following guidelines: method.Thesefactorsareverysite-specific,andtheuser a. If the released material contains HF as a component in a needs to realize that they are chosen to reflect representative mixture, the massfraction of HF is obtained, and conditions for the petrochemical industry. b. The liquid rate (or mass) of only the HF component is used to calculate the toxic impact area. 7.9.4ToxicConsequences 7.9.4.4.2 Hydrogen sulfide, due to its low boiling point, is Toxic fluids are similar to flammables in that not all toxic processed as a vapor or, when processed under high pres- releasesresultinasingletypeofeffect.Bythemselves, sures, quickly flashesupon release. In either case, the release hydrogen fluoride (HF), ammonia, and chlorine pose only a of H2S to the atmosphere results in the quick formation of a toxic hazard. On the other hand, some toxic materials such as toxic vapor cloud. For H2S releases, RBI uses the following hydrogen sulfide (H$) are both toxic and flammable. How- guidelines: ever, any toxic material, when mixed with hydrocarbons, can a. If the released material contains H2S as a component in a pose flammable and toxic hazards. R B I allows for each of mixture, themass fraction of H2S is obtained, and these possibilities. b. If the initial state of the material is a vapor, themass frac- R B I evaluates the risks associated with four toxic materials tion of H2S is used to obtain the vapor discharge rate (or that typically contribute to toxic risks for a refinery: hydrogen mass) of only H2S; t i rate (ormass) is usedto determine the hs fluoride (HF), hydrogen sulfide (H2S), ammonia (NH3), and impact area, or chlorine (Cl). The same approach can be used to evaluate c. If the initial state of the materialis a liquid, the mass frac- other toxic materials. tion of H2S is used to obtain the vapor flash rate (or mass) of only the H2S; this rate (or mass) is used to determine the 7.9.4.1 Scenario Development impact area. The selection of scenarios follows the methodology pre- 7.9.4.4.3 For continuous releases, the discharge rate should be calculated as in 7.4. RBI uses a simplified sented in 7.2, using l/4-inch,1-inch,4-inchand rupture approach for modeling releases of mixtures. If a release hole sizes. The release duration is provided by the analyst, material is a mixture, the resulting toxic material release anddependsupon the circumstances associated with the rate should then be calculated by multiplying the mass frac- release. The release rate (either liquid or vapor) is then cal- tion of the toxic component by the previously-calculated culated as in 7.4. discharge rate. For example,if the initial phase of a material being released is 1 wt% H2S in gas oil, the material has the 7.9.4.2MaterialConcentrationCut-Off potential for both toxic and flammable outcomes from the As a general rule, it is not necessary to evaluate a toxic vapor, and flammable outcomes from the liquid. Therefore, the following procedure is followed, usingC17 as the repre- release if the concentration of the material within the equip- sentative material: ment item is at or below the IDLH (Immediately Dangerous to Life or Health) value. ForHF, this is 30 ppm, for H2S this a. Calculate the liquid discharge rate for C17 as described in is 300 ppm, for NH3, it is 300 and for Cl it is 30. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 7.4.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STDmAPIIPETRO PUBL SBL-ENGL 2000 0732290 Ob2LSbB 4Bb m INSPECTION BASERESOURCE RISK-BASED DOCUMENT 7-19 b. When estimating flammable consequences, calculate the Pr = A + B In (CN?) (7.7) potential flammable consequence areas as in 7.8.1 and take the worst case between: where 1. The flammableeffects of C 7 using 100% of the 1 Pr = a measure of the percentage of the population release rate that sustains a certain level of harm, 2. Theflammableeffectsof H2S basedon1%of the release rate C = concentration (ppm), c. Calculate the toxic effectsof H2S, using 1%of the release rate. r = exposure duration (minutes), For instantaneous releases, use the above procedure, sub- A,B,N = mathematical constants used to formulate the stituting inventory for release rate. probit equation, each toxic fluid has its own A, B, and N. 7.9.4.5ReleaseDuration R B I uses a single fixed probability of fatality (50% proba- 7.9.4.5.1 Thepotentialtoxicconsequencein R B I is esti- bility of fatality) to determine the toxic impact.This level cor- mated both using the duration and release rate, release responds toa probitvalue of 5.0. whereas the flammable impact Rin I relies onjust the release B rate. The duration a release depends on following: of the 7.9.5 ConsequenceEstimation a The inventorythe in equipment and item connected A consequence analysis toolwasused for a range of systems. release rates and durations to obtain graphs of toxic conse- b. T i e to detect and isolate. quence areas. Release durations of instantaneous (less than 3 be c. Any response measures that may taken. minutes), 5 minutes (300 sec), 10 minutes(600 sec), 20 min- 7.9.4.5.2 For RBI, the maximum release duration is set a t utes (1200 sec), 40minutes (2400 sec), and1 hour (3600 s ce) one hour,for the following two reasons: were evaluated to obtain toxic consequence areas for varying release rates. a It is expected that the plant’s emergency response person- . nel will employ a shutdown procedure and initiate a combination of mitigation measures to limit the duration of a 7.9.5.1 Consequence Area release. The cloud footprint for a theoretical continuous release is b. The HF toxicitydatausedinestimatingthe toxic dose roughly the shape ofanellipse, as showninFigure 7-4. 5 effect are based on animal tests ranging fromminutes to 60 Hence, the area the cloud covers is somewhat conservatively minutes in duration. assumed to be an ellipse and is calculated using the formula 7.9.4.5.3 As explained in 7.5, release duration can be esti- for an ellipse area: mated as the inventory in the system divided by the initial release rate. While the calculated duration may exceed one Area = nab (7.8) hour, there may be systems in place that will significantly shorten this time, such as isolation valves and rapid-acting u = l/2 of the cloud width (minor axis), taken at its leakdetectionsystems.Timesshould be determined on a largest point (within the50% probability of case-by-case basis. An effective release duration should be fatality dose level), calculated as the minimum of: a. One hour. b = of the downwinddispersion distance (major b. Inventory divided by release rate. axis), taken at the50% probability of fatality c. Values listed in Table 7-7(release duration based on detec- dose level, tion and isolation systems ratings), plus the time required for k = 3.14157. the isolated area to deinventory through the leak. The consequence area results for continuous releases of 7.9.4.6ToxicImpactCriteria toxics arepresented in Figures 7-5and 7-6. The toxic impact is a function of two components: expo- For instantaneous releases, the dispersion the cloud over of sure time and concentration. These two components combine time is depicted in Figure 7-7. The area covered by the cloud to result in an exposure that referred to as the toxic dose. is is conservatively assumed to be an ellipse, except that the x- In RBI, the degreeof injury froma toxic release is directly distance (a) is simply l / ~ themaximum cloud width as of related to the toxic dose. RBI relates dose to injury using a determined from the dispersion results. The consequence area probit. For toxic vapor exposure, the probit shortened form (a curves, as a functionof the release mass, are presented Fig- in of probability unit)is represented as follows: ure 7-8 for instantaneous releases of toxics. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~ STD.API/PETRO PUBL SB&-ENGL 2000 m 0732290 Ob2LSb9 312 H 7-20 API PUBLICATION 581 Point of release A b v Y-distance from ;elease --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- >- T X-distance from release Figure 7-4-TOp View of Toxic Plumefor a Continuous Release 100,000,000 n /X 10,000,000 1,000,000 10,000 1O0 0.1 1 10 1 O0 1O00 HF Release Rate (Ibdsec) & 5 min. ----W"-- 10 min. + min. - - x- - -4Omin. -1 30 hour Figure 7-5"Consequence Area for Continuous HF ReleasesCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • INSPECTION RISK-BASEDRESOURCE DOCUMENTBASE 7-21 1,000,000 100,000 I I 10,000 n .I * , 1,000 1 1O0 o. 1 1 10 1O0 1O00 H2S Release Rate (Ibslsec) - - x- - -40 min.%*, 1 hour Figure 7"Consequence Area for Continuous H2S Releases --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- >- I X-distance from release Figure 7-7-TOP View of Toxic Plume for an Instantaneous ReleaseCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 581-ENGL 2000 m 0732290 Ob21571 ~ 7 m 0 7-22 API PUBLICATION 581 100,000,000 10,000,000 1,000,000 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 100,000 10,000 100 I 10 1O0 1O00 1 O000 100000 1000000 Release Rate (Ibkec) 1 H2S --+--HF[ Figure 7-8“Consequence Areafor Instantaneous HF and H2S Releases 7.9.5.2 Outcome Probabilities 7.9.5.4 AmmoniaKhlorineModeling In the event therelease can involve both toxic and flamma- A saturated liquid at ambient temperature(75°F) was used, ble outcomes, it is assumed that either the flammable out- with liquid being released from the tank. The tank head was come consumes the toxic material, or the toxic materials are set at 10 feet. dispersed and flammable materials have insignificant conse- To determine an equation for the effect area of a continu- quences. In ti case, the probability for toxic event is the hs the ous release of ammonia and chlorine,four release cases (0.25 remaining nonignition frequency the event (i.e., the for proba- in, 1 in., 4 in., and 16 in.) were run for various release dura- bility of “safe dispersion,” explained in5.2.2.1). as tions (10, 30, and 60 minutes). A plot of the release rate vs. the consequence area when the probit equals five is shown in 7.9.5.3 Calculation of the Combined Figures 7-9and 7-10. Consequences for Toxic Releases The relationship between the release rate and the area fol- Toxic consequence resultscan be averaged using thesame lowed the following formula: methods presented in 7.8.1, using Equation 7.6. As with the A=cxb flammable results, consequence areas for the individual toxic events are multipliedby their corresponding event probabili- where ties. The result is a single consequence area that represents an A = the effect area in square feet, This average of a l possible outcomesfor the equipment item. l procedure is done for each equipment item. x = the release mass in lbs.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • INSPECTION RISK-BASED BASE DOCUMENT RESOURCE 7-23 1.OE+09 I 1 .OE+07 1.OE+06 1 .OE+05 1 .OE+04 1 .o00 10.000 100.000 1000.000 10000.000 Chlorine Release Rate (Iblsec) I -0 6 min. - - + - -30 min. 10 min. I Figure 7-9-Continuous Chlorine Release The constants (c and b) are listed in Table 7-17for the dif- Table 7-17"Continuous Release Durations for ferent cases. Chlorine and Ammonia For instantaneous release cases, four masses of ammonia Release and chlorine were modeled (10, 100, 1 O . and 1 , O lb), OO , 0O O Chemical Duration C b and the relationship between inventory and are to probit mass --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- five was found to b : e 60 minute 1.01 46,563 Chlorine 30 minute 27,7 1 1 1.10 A = 14.97 for chlorine, and 10 minute 15,147 1.10 A = 14.17 #.9011 for ammonia. 60 minute 1.16 11,049 Plots of instantaneous the release rates vs. the consequence Ammonia 3 minute 0 7,852 1.16 area areshown in Figures 7-11 and 7-12. 10 minute 1.19 2,690 7.9.6 Consequences of Steam Leaks To determine an equation for the effect area of a continu- Steam represents a hazard personnel who are exposed to to ous release of steam, four release cases (0.25 in., 1 in., 4 in., steamathightemperatures. In general,steam is at 212OF and 16 i . were run for the varying steam pressures. plot of n) A immediately after exiting a hole in an equipment item.Within the release rate vs. the area covered by a 20% concentration a few feet, depending upon its pressure, steam will begin to of steam shows alinear relationship, with an equation of: mix with air, cool and condense. At a concentration of about steam/& 20%, the mixture cools about to 140F. approach The A =0 . 6 ~ used here is toassume that injury occursonlyabove 140°F. where 140°F was selectedas the threshold for injury to personnel,as this is the temperature which above OSHA requires hot that A = the effect in square feet, area surfaces be insulated to protect personnel against burns. x = the release rate in lbs/=.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD*API/PETRO PUBL 581-ENGL 2000 m 0732290 Oh2L573 8 4 3 7-24 API PUBLICATION 581 1.OE+09 1.OE+O8 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 1.OE+07 8 1.OE+06 C f i E " O 1.OE+05 1.OE+04 - 1 .OE+03 1 .O00 10.000 100.000 1000.000 10000.000 Ammonia Release Rate (Ibslsec) I 60 min. -- - -I 30 min. - - Figure 7-1&Continuous Ammonia Release For instantaneous release cases,four masses of steamwere Table 7-18-Apt-RBI CaustidAcidEquations modeled (10 lb, 100 lb, 1,OOO lb, and 1 , O lb), and the rela- 0 O O tionship between inventory mass and area to 20% concentra- Pressure Range Equation tion was found be: to Low pressure-0-20 psig y = 2,699.5 f l m 4 A = 63.317 #-6384 Medium Pressure-2 1 - 4 0 psig y = 3,366.2 2.2878 where Pressure High 2 40 psig y = 6,690 fl.2"9 A = the effect area in square feet, x = the release mass in lbs. As seen i Figure 7-13, each pressure canbe described by n a unique relationship, 7.9.7 Consequences of AcidICaustic Leaks For caustics/acids that have only splash type consequences, y=b$ water was chosen as a representative fluid to determine the personnel effect area. This area was defined the at 180" semi- where circular area covered by the liquid spray, or rainout. Modeling was performed at four pressures (15 psig. 30 psig, and 60 y = personnel area effect (fiz), psig) for four hold sizes (0.25 in, 1 in. 4 in. and 16 in.). Only x = release rate (lb/s), and b and c are constants for continuous releases were modeled, as instantaneous releases that pressure do not producerainout. The results were analyzed toobtain a correlation between release rate and effect area.The resultant The 45 psig and 60psig trendlines are very close relative to equations were obtained from Figure 7-4. The resulting equa- the others. Therefore, these pressures were combined into one tions shown are in Table 7- 18. larger range ( A O psig). The equation for the 60 psig trendlineCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD=API/PETRO PUBL 583-ENGL 2000 m 0732290 0623574 78" RISK-BASED BASEINSPECTION RESOURCEDOCUMENT 7-25 1.OE+06 1.OE+05 1.OE+04 1.OE+03 1.OE+02 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 1 .o00 10.000 100.000 1000.000 10000.000 Release Rate (Ibkec) Figure 7-1 1-Instantaneous Chlorine Releases 1.OE+05 A N , 1.OE+04 1 a 8 C a l $ cn 1.OE+03 ò o 1 .OE+02 I 10.000 I I I I I I 1(Il3.000 11 00.000 D 3 1 O0O1 . 0 000 Release Rate (Iblsec) Figure 7-1 2-Instantaneous Ammonia ReleasesCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • Acid/Caustic Spray Areas 100000 90000 80000 m c. 70000 .c f 15 psig 60000 v 0.304 30 psig m y = 4684x.6X E 50000 m 45 psig a c h 40000 A 60 psig Q u) 30000 20000 0.2024 y = 2699.5~ 1O000 O --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- O 1 O000 30000 40000 20000 50000 Release Rate (Iblsec) Figure 7-13“CaustidAcid Modeling Results was chosen to represent this range sinceit represents al pos- l other costsin the “Business Interruption” section and included sible release rates. Ranges werealso chosen for the and 30 15 as part of the financial The B R D methods allowfor rigor- risk. psig cases. ous calculations, but also allow for simplifications and other The selected ranges represent the pressures at which caus- assumptionsbased on theanalyst’sopinions.Tables 7-19 ticdacids are commonly used: through7-23 are an attempt atsimplifyingthemethod as much as possible. a. Low pressure (15psitrepresentative of O - 20 psi. b. Medium pressure (30 psi+representative of 21 - 40 psi. 7.9.9.1 Environmental Cleanup Costs Methods for c. High pressure (60psitrepresentative of > 40 psi. Equipment Other Than Bottoms Tank 7.9.8 Effects o Mitigation Measures f The user has the option whether or not to include environ- mental cost consequence in the risk equation. The default To this point, isolation and detection capabilities have been should be “No” (do notcalculate). Most processequipment is taken into account in calculating the quantity of material that located in specially paved and drainedareas so that any liquid may be released during a loss-of-containment event. How- not evaporated or burned goesto special spill and waste han- ever, there may be additional systems, such as water spray, in dling facilities designed for the purpose of avoiding environ- place that can mitigate a releaseonce the material has reached mental consequences. An option is to allow the entry of the the atmosphere. The effectiveness of mitigatingsystemscan be simply percent of fluid expected to escape from diked areas. If the user wants to consider the environmental effects, he accounted for in RBI by reducing the release rate and dura- chooses whether the spill will be on the ground, if it will go or tion for continuous releases,or by reducing the release mass into water. This is very important for plants withstorage and for instantaneous releases. handling facilities on waterways. The RBIanalyst willneed to provide his or her own reduc- First determine if the final stateis a gas.If so, exit the mod- tion factors, based on theeffectiveness of theirparticular ule. Then determine if autoignition is likely. If so, also exit spray-system design or passive mitigation technology. the module (the liquid will probably ignite and bum). be Only “liquidfinal state,autoignition not likely,” will cal- 7.9.9EnvironmentalCleanupCosts culated. If the normal boiling point is less than 200”F, then Environmental consequences expressed as a cost,so the are exit the module. (See Section7.2, presumably lighter boiling consequences should calculated separately and added to the liquids will evaporate.) beCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~ ~~~~~~ S T D = A P I / P E T R O PUBL 5 8 1 - E N G L 2000 9 0732290 Ob2157b 5 5 2 m RISK-BASED RESOURCE DOCUMENTBASE INSPECTION 7-27 Table 7-1+Environmental Cleanup Costs Inputs Input units Consider environmental release? input User Y/N Release to ground or water? Water Ground/ user input Damage factor from each damage module module none routine Damage Representative fluid input User Final state none or liquid gas module Consequence Instantanmus or continuous release none module Consequence Consequence module none not Autoignition likely or likelyIblgal Fluid density, converted Ib/gal table to Lookup Normal boiling point tables Lookup k g .F Release duration Calculated from BRD Table 7-7 minutes Release rate, for each hole size lbslsec module Consequence Group inventory lbs module Consequence Percent of fluid evaporating below) table From (see lookup % Equipment type input User Tank foundationtype input User h below) m table none (see none Detection time for floor leaks table Lookupevents& Generic failure frequency table Lookup New equipment type,tank floor Add to equipment table Method of detection User input Time of testing for tighmess tests user input Percent of rupture contained byk d area d e i user input value (Default %, 50%) Cleanupm t , below ground changeable)table $/gallon p hku (user Cleanup cost, above ground changeable) Lookup $/gallon table (user Cleanup cost, water changeable)table $/gallon (user Lookup Check to see if the release is instantaneous or continu- 7.9.9.2 Environmental Cleanup Costs Methods for ous. Instantaneous releases use the entire group inventory. Tank Bottoms Forcontinuous releases, calculate the release duration If the equipment type is atank bottom, onlys m d (1/4-in.) from Table 7-7. Check that therelease duration is not lim- and medium (1-in.) hole sizes are considered. For lackof bet- ited by the flow rate for each holesize. Use the minimum ter data, the generic failure frequency for tanks can be used value for duration. Use the duration, flow rate, and density (these surely include some bottom leaks). to calculate the gallons of liquid released. Physical prop- The user specifies the type of foundation and the type of erties of representative fluids in the BRD are shown in leak detection (see Tables 7-22 and 7-23). Note that for tight- Table 7-2. Subtract from this value the percent of liquid --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- ness testing (not usually done; involves cleaning, filling with expected to evaporate(e.g. in a 24-hour period) as shown water and holding for a period of time), the time between in Table 7-20. tests (e.g. one year) mustbe specified. Multiply theremaining fluid by the cost fluid cleanup, of Use either the flow rate based on foundationand test time based on ground or water release. Multiply this value by or the threshold value for the leak detection method to deter- the hole-size frequency timesthe combined technical mod- mine the leak amount as shown in Table 7-23. Multiply the ule subfactors. Add all resulting values to get the environ- leak amounttimes the cost ofundergroundleakcleanup. mental cost risk in $/y. Multiply this times 0.9 to account Multiply times the generic frequency and the combined tech- for releases that ignite and do not result in environmental nical module subfactors. This will produce the risk of under- contamination. ground leaks. COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STDmAPIIPETRO P U B 1 581-ENGL 2000 0732290 Ob21577 499 7-28 API PUBLICATION 581 Table 7-20-Fluid Leak Properties --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Molecular % Evaporating Density Weight Fluid NJ3P in 24 hours* H2 4.433 2 423 100 c1-c2 23 15.639 -193 100 H2S 34 6 1.W3 100 -75 c -. 3 c5 58 36.209 31 100 60.37 HF 20 68 100 la0 42.702 210 90 W 1 2 149 45.823 364 50 c13416 502205 47.728 10 65 48.383 cls2.5 280 1 5 2 981 422 56.187 * Estimated Values Table 7-21-Environmental Cleanup Costs Outputs Output Name Units PrimaryISecondary Volume released, for each hole size gallons Secondary Volume released to environment, each hole size for gallons Secondary Cleanup cost, each hole size for Secondary $ Total cleanup cost Secondary Cleanup risk for each hole size Secondary $IF Total cleanup risk primary W Table 7-22-Tank Underground Leak Rates for RBI Analysis Type of Foundation Leak Rate (gd/day) inch hole hole1 inch Clay 0.038 O. 15 Silt 5.25 24 Sand 6.5 29 Gravel 42 192 Table 7-23-Detection Times for Storage Tank Floor Leaks Time to Detect (days) Method of Detection or Threshold (gallons) Tightness Testing Time-interval between tests Inventory Monitoring Threshold-10% tank volume U-TU~S Threshol.”-sOO galmonth Time-1 Wells Vapor COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • S T D m A P I I P E T R O PUBL 581-ENGL 2000 m 0732290 Ob23578 325 m RISK-BASED DOCUMENT INSPECTION BASE RESOURCE 7-29 7.10FINANCIAL RISK EVALUATION 7.10.2FinancialRiskMethods In the April 1995 Base Resource Document, risk could The basic method ofrisk analysis a presented in theBRD be calculated using cost as the measure of consequence. is not changed for the financial risk analysis.The risk is still This was referred to as the “business interruption” calculated as the consequence of failure (now expressed as approach. Use of this method revealedafew potentially cost in dollars) times the likelihood failure. For a rigorous of serious shortcomings: and flexible analysis, the consequences (costs) are evaluated at the hole size level. Risk is also evaluated at the hole size a The method used only the affected area as the basis of . level by using the likelihood of failure associated with each determining the cost of a failure. This led to zero cost for hole size. The totalrisk is calculatedas the sum of the risks of equipment that had zero affected area (e.g. nonflammable, each hole size. nontoxic releases). b. The method considered only business interruption as the 7.10.2.1EquipmentDamage Costs-By Specific basis of the cost associated with a failure. Items These problems are addressed in the “Level III” approach The most serious problem with the original (April 1995) by recognizing that there are many costs associatedwith any BRD “business interruption’’ approachis that the cost of the failure of equipment a process plant. These include, but in are equipment item being evaluated was not directly considered. not limitedto: Thus any failure withzero affected area ledto zero risk. This is not realistic, since afailure of a steam pipe definitely a has a. Cost of equipment repair and replacement cost impact, evenif it does not result in a large area of dam- b. Downtime associated with equipment repair and age compared to a hydrocarbon pipe. replacement --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- The solution is evaluate the cost the equipment failure to of c. Costs due topotential injuries associated with afailure itself, independent of whether or not it has an affected area. d. Environmental cleanup costs Then, any other costs can be added. Testing of t i method hs The modified approach for Level III is to consider all of has resulted in nonflammable piping moving from near the these costs on both an equipmentspecific basis andan bottom of the risk if ranking to near the top, especially it has a affected area basis. Thus, any failurehas costs associated with high likelihood of failure due to some damage mechanism. the it, whether or not the failure actually results in release of a Thus, such a pipe would appropriately consideredby Risk- be hazardous fluid. Recognizing and using this fact presents a Based Inspectionas a high priority candidate inspection. for more realistic value the risk associated with a failure. of Since The method was tested using both a composite financial on thecosts include more thanjustbusiness interruption, the the combination of all possible leak scenarios (hole sizes), approachused for Level III is calledthe “financial risk” and using a specific cost &sociated with each hole size and approach. unique to each equipment item. The latter approachwas cho- sen based on the inherent differences in the costs associated 7.10.1 Conclusions: Risk Comparison of Affected with very small compared very large holes. small holein to A Area Basisvs. Financial Basis a piping system can sometimes be repaired with little or no impact on production by of a temporary use clamp until a per- Table 7-24 shows methods similar to the LevelIII methods manent repair can be scheduled during normal maintenance above worked into an examplefrom a typical distillation unit. this shutdowns. Larger holes usually do not allow option, and Note carefully t e risk ranking based on affected area vs. the h shutdown plus repair costs are greatly increased. risk ranking basedon financial risk.There is very little differ- Table 7-25 shows the equipment damage costs suggested ence in the highrisk items withone very importantexception. for the equipment included in the BRD. Actual failure cost Item P-3 1 is a pipe containing a non-flammableand non-toxic be data for equipment should used if available, fluid. Based on affected area, the consequence is zero, there- Note that pipingcost estimates areon a per foot basis. The fore the risk is zero. Using only the consequence area as the sources cited were used estimate the relative installedcosts to basis for risk, the item was ranked near the very bottom of of the equipment. Since repair or replacement of equipment equipment. When the cost of the item failure was included, usually does not involve replacement all supports, founda- of this item automatically jumped to near the top of the list. This tions, etc., the repair and replacement costs presented do not is primarily due to a very high technical module subfactor. reflect actual installed cost. The pipe is subject to a damage mechanism and based on The cost estimates shown in Table 7-25 are based on car- technical module inputs of damage rate and pastinspections, bon steel prices. It is suggested the LevelIII approach that for the pipehas a high likelihood of failure. By allowing the costs these costs be multiplied by a material cost factor for other of failure to be considered, the financial risk pointed out that a materials. Table 7-26 shows the suggested values for these potential for failure with repair, replacement, and downtime cost factors. These factors are based on a variety of sources was to be considered. from manufacturer’sdata and cost quotations.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD*API/PETRO PUBL 5BL-ENGL 2000 M 0732290 Ob21577 2 6 1 7-30 API PUBLICATION 581 Table 7-24-Risk Comparison of a Typical Distillation Unit Conse- Represen- Risk Damage SumTech. Risk queme Fluid tative Equipment Risk Rank Risk Rank Area Mod. Adjusted ID m State Fluid fi2& ft2/yr $&r $&r (fi2) Frequency Subfactors P-30 Pipe-6 Liquid 1092 1 $ 5,573,859 1 1296 3205.1 8.42E-O1 P-4 1 16 Pip-> Liquid 193 2 $ 936,178 2 6487 170.6 2.97E-02 P-42 Pipe-10 Liquid 154 3 $ 754,536 3 5562 185.0 2.78E-02 c-1 Columntop Vapor 133 4 $ 651,147 4 1322 646.9 1.01E-01 E-33 Exchanger-TS Liquid 31 5 $ 166,135 5 1692 115.7 1.80E-02 E-37 Exchanger-TS Liquid 31 6 $ 166,135 6 1692 115.7 1.8OE-02 E-39 ExChanger-TS Liquid 31 7 $ 166,135 7 16.92 115.7 1.8OE-O2 E-52 Exchanger Liquid 22 9 $ 161,306 8 203 683.3 1.07E-01 P-3 Pipe- 12 Liquid 16 11 $ 126,325 10 190 641.6 8.66E-O2 P” Pip-8 Liquid 19 10 $ 100,906 11 1713 80.7 1.1 3E-02 P-1 Pipe- 12 Liquid 8 14 $ 75.669 12 93 653.6 8.82E-02 D4 Drum Liquid 12 12 $ 69,461 13 711 110.2 1.72E-02 D-10 Drum Liquid 9 13 $ 44,980 14 1493 37.7 5.88E-O3 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- P-11 Pipe-12 Liquid 8 15 $ 41,432 15 1086 51.5 6.95E-03 P-3 1 Pipe-1 Liquid O 200 $ 40,907 16 O 3846.2 9.72E-O1 P-23 Pip->16 Liquid 6 16 $ 34,437 17 1539 23.9 4.16E-03 E- 100 Exchanger Liquid 5 17 $ 24,630 18 6194 5.2 8.16E-O4 E-54 Exchanger Liquid 3 21 $ 24,254 19 203 102.7 1.6OE-O2 P-8 Pip-8 Liquid 4 18 $ 22,944 20 1610 18.9 2.73E-03 E-42 Exchanger Liquid 3 22 $ 22,895 21 198 98.6 1.54E-02 7.10.2.2EquipmentDamage Costs-Other 7.10.2.3 Business InterruptionCosts-By Specific Affected Equipment Items As presented in the BRD, it is still necessary to calculate Another weakness in the original(April 1995) BRD “Busi- the equipment damage costs to other equipment in the vicin- the ness Interruption” approach was that downtime associated ity of the failure, the failure results in a flammable event. It with an individualequipment failure was also based on if is intendedthat for the Level III approach a Process Unit con- affected area. Thus the downtime of the failure itself w s not a stant value of equipment cost per ft2 be used as a default the considered, and if the failure hadzero affected area, again value for all equipment in the unit. In other words, as a start- cost associatedwith it was zero. ing point the average cost of other equipment surrounding This weakness is corrected in much that same way that the any givenpiece of equipment is about the same. could be This weakness of not considering equipment damage and repair refined for individual equipment by items allowingthe was corrected. For eachhole size, an estimated down time for default value to be overridden with a higher or lower value each equipment itemis presented in Table 7-27. where appropriate. For illustration purposes,an average cost Centrifugal pumps are assumed to have on-line spares, so of equipment used in the pilot study was $550/ft2.This value thereis no downtimeassociated with thefailure of these is multiplied by the affected area to obtain the cost of other equipment types. equipment damaged by the failure.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • INSPECTION RISK-BASED BASE RESOURCE DOCUMENT 7-31 Table 7-25-Equipment Damage Costs Failure Failure Cost Failure Cost Cost Failure Cost W Description Rupture* Large* Small* Medium* Pump1 Centrifugal single Pump, seal $1,000 $2,500 $5,000 $5,000 Pump2 Centrifugal Pump, double seal $1 ,000 $2,500 $5,000 $5,000 COlumnBTM Column $10,000 $25,000 $50,000 $100,000 Columntop Column $10,000 $25,000 $50,000 $100,000 CompC Compressor, Cenhifugal $10,000 $20,000 $100,000 $300,000 CompR Compressor, Reciprocating $5,000 $10,000 $50.000 $100,000 Filter Filter $1,000 $2,000 $4,000 $10,000 FillfíUl FinPan Coolers $1,000 $2,000 $20,000 wO Oo , Exchanger Heat Exchanger, Shell $1,000 $2,000 $20,000 $60,000 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Pipe-0.75 piping, 0.75” diameter, per f t $5 $0 $0 $10 Pipe- 1 Piping, 1”diameter, perft $5 $0 $0 $20 Pipe-2 Piping, 2“ diameter, per ft $5 $0 $0 $40 Pipe4 Piping, 4 diameter, per ft $5 $10 $0 $60 Piped Piping, 6” diameter, per ft $5 $20 $0 $120 Pipe-8 Piping, 8” diameter, perft $5 $30 $60 $180 Pipe- 10 piping, lo” diameter, per ft $5 $40 $80 $240 Pipe-12 piping, 12” diameter, per ft $5 $60 $120 $360 pipe-16 piping, 1 6 diameter, per f t $5 $80 $160 $500 Pipe-> 16 Piping, >16“ diameter,per ft $10 $120 $240 $700 Drum Pressure vessels $5,000 $12,000 $20,000 $40,000 Reactor Reactor $10,000 $24,000 $40,000 $80.000 -R P Reciprocating F’umps $1,000 $2,500 $5,000 $10,000 Tn ak Atmospheric StorageT n ak $40,000 $40,OOo $40,000 $80,000 Heater Furnace Tubes for FiredHeater $1,000 $10,000 $30,000 $60,000 * Sources: 1.Yamartino, J., “Installed Cost of Corrosion Resistant piping-1978”, Chemical Engineering, 30,1978. Nov. 2. Peters,M. S ,T i e r h a u s , K.D., Plant Design and Economics for Chemical Engineers, McGraw-Hill, 1968. . Table 7-26-Material Cost Factorsterial Factor Cost Material Carbon Steel 1.o Alloy Clad 600 7.0 7.8 Lined 1Il4 Cr “Teflon” Mo CS 1.3 8 Nickel2 Il4 CrMo Clad 1.7 .o 5 Cr Il2 Mo 1.7 Alloy 800 8.4 7 Cr‘12 Mo 8.5 2.0 Cu/Ni 70130 904L Clad 304 SS 2.1 20 9Alloy Mo Cr ‘/2 2.6 405 SS Alloy 2.8 400 15 410 SS Alloy 2.8 600 15 Nickel 304s 3.2 18 625 Clad 316SS Alloy 3.3 Titanium CS “Saran” lined 3.4 CS Rubber Lined Alloy 4.4 “‘ C 29 Zirconium 3 16 SS 4.8 CS GlassLined Alloy 5.8 “B 36 Tantalum Clad Alloy400 6.4 !N/lo CulNi 6.8 COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 5B1-ENGL 2000 m 0732290 Ob21583 9 1 T m 7-32 API PUBLICATION 581 Table 7-27-Estimated Equipment Down Time Outage Time Outage Time Outage Time Outage Time Medium W Small Description Pump1 Centrifugal Pump, single seal O O O 0 Pump2 Centrifugal Pump, double seal O O O 0 COlumnBTM column 4 2 5 21 Columntop Column 2 4 5 21 CompC Compressor, Centrifugal 2 3 7 14 CompR Compressor, Reciprocating 2 3 7 14 Filter Filter O 1 1 1 Finfan Fin/Fan Coolers 1 1 3 5 Exchanger Heat Exchanger, Shell 1 1 3 5 Pipe-0.75 Piping, 0.75" diameter, perf t O O O 1 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Pipe- 1 Piping, 1" diameter, per ft. O O O 1 Pipe-2 Piping, 2" diameter, perft O O O 2 Pipe4 Piping, 4" diameter, perft O 1 O 2 Pipe-6 Piping, 6 diameter, per ft O 1 2 3 Pipe-8 Piping, 8" diameter, per ft O 2 3 3 Pipe-10 Piping, 10 diameter, perft O 2 3 4 Pipe-12 Piping, 12" diameter, per ft O 3 4 4 Pipe-16 Piping, 16" diameter, perft O 3 4 5 Pipe->16 Piping, >16" diameter, per ft 1 4 . 5 7 Drum Pressure vessels 2 3 3 7 Reactor Reactor 6 4 14 : 6 Pump Reciprocating Pumps O O O 0 Tank Atmospheric StorageTank O O O 7 Heater Fumace Tubes for Fired Heater 1 2 4 5 7.10.2.4 Business Interruption Costs-Other event can lead to under ranking this event with respect to Affected Equipment risk, if injury costs arenot considered, then a risk could be present that is not considered in allocating inspection an If a failure does have affected area, the cost of downtime resources. for replacement and repair ofother affected equipment must The method for the Level III approach is to use a process be considered. The LevelIII approach still uses the downtime unit constant of population densityas a default for all equip associated with a total cost of other equipment damage. Fig- ment in the unit. This default value can be overridden by ure 7-14 shows the method: higher or lower values depending on specific equipment loca- tion with respect to controls rooms, walkways, roads, etc. In 7.10.2.5 PotentialInjuryCosts addition to the populationdensity,the cost per individual Another cost to consider when a failure occurs is the affected must also be entered. This value must be sufficiently potential injury costs. This a controversial area, but need not high to adequately represent typical costs businesses of an to be. When a business takes this cost into account in a risk injury up to and including fatal injuries. For the example that managementscheme,then appropriateresourcescan be follows, the population density was set at O.OOO1 persons per spent to prevent these injuries from happening. Just as fail- fi2 (one person per l , O fi2), and the cost injury was set 0O O per ure to considerthebusiness cost o a zero affected area f at $lO,0o0,OOO.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~ STD*API/PETRO PUBL 58s-ENGL 2000 D 0732290 Ob2L582 856 W DOCUMENT BASE RISK-BASED RESOURCE INSPECTION 7-33 1O0 I"""".--.. __I ".lll_ I Q) I 3 . " "..l.."""" .I" .. a c u) P P 10 I..I.. "" ____ I I -1 1 1 0.1 1 10 100 ~ 1O00 Property Damage ($MM) Figure 7-14-Business Interruption Costs --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • Section &Likelihood Analysis 8.1 OVERVIEW OF PROCESS FOR LIKELIHOOD --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- a. The technical module that examines materialsconstruc- of ANALYSIS tion, the environment and the inspection program. b. Universal conditions that affect equipment items at the all As with other Risk-Based Inspection methods in the Base facility. ResourceDocument, the followingrepresentsa suggested c. Mechanical considerations that vary from item to item. methodology. More detailed analysis may yield more accu- d. Process influences that can affect equipment integrity rate results.The likelihood analysis begins with adatabase of generic failure frequencies for onshore refining and chemical The equipment modification factor is discussed in 8.3. processing equipment.These genericfrequencies are then modifiedby two terns, the equipmentmodificationfactor 8.1.3ManagementSystemsEvaluationFactor (FE) and the management systemsevaluation factor (FM), to The effectiveness of a company’s process safety manage- yield an adjustedfailure frequency, as follows: ment system can have a pronounced effect on mechanical integrity. The RF31 procedure includes an evaluating tool to x FrequencydjuSled= Frequencygeneric FE x FM (8.1) assess the portions of the facility’s management systems that most directly impact failure frequency of equipment items. This calculation is shown graphically inFigure 8-1. This evaluation consists of a seriesof interviews withinspec- tion, maintenance, process, and safety personnel. The ques- The modification factors reflectidentifiable differences tions are based primarily on guidelines from A P I (RP 750, between process units and among equipment items within a Std.510, Std. 570, etc.). process unit. The first adjustment, the equipment modifica- The evaluation is sufficiently detailedto provide effective tion factor, examines details specifìc to each equipment item discrimiition between management systems. It is described and to the environment in which that item operates, in order in 8.4, and the evaluation workbookis included as Appendix to develop a modification factor unique to that piece of equip C. A scale is provided in Figure to convert the evaluation 8-5 ment. The secondcorrection, the managementsystems evalu- score to a management systems evaluation factor. ationfactor, adjusts for the influence of the facility’s management system on the mechanical integrity of the plant. 8.2 GENERICFAILUREFREQUENCIES This adjustment is applied equally to all equipment items. If the managementsystems being evaluated are different for dif- If enough data were available for a given equipment item, ferent units or areas of the plant, the differences should be truefailureprobabilitiescould be calculatedfrom actual identifiedand the management systemsevaluation factor if observed failures. Even no failures have occurred inpiece a adjusted accordingly. of equipment, we know from experience that the truefailure Modification factors withavaluegreater than 1.0 will probability is greater than zero, and that the equipmentitem increase theadjusted failure frequency, and those with a value has not operated long enough experience a failure. to less than 1.0 will decrease it. Both modification factors are As a first step in estimating this non-zero probability, it is always positive numbers. necessary to t r to a larger equipment pool to find enough un failures to provide a reasonable estimate of true probabil- the 8.1.1 GenericFailureFrequency ity. This generic equipment pool is used to produce a generic failure frequency. The database of generic failure frequencies is based on a The generic failure frequencies built using records are from compilation of available records of equipment failure histo- all plants within a company or from various plantswithin an nes. The records can come from variety of sources. a Generic industry, from literature sources, past reports, and commer- failure frequencies have been developed from these data for cial data bases. Therefore, the generic values represent an eachtypeof equipment and each diameter of piping. A industry in general and not reflect the true failure do frequen- detailed generic database is presentedin Section 8.2and cies for a specific plant unit. or Table 8- l. Generic frequencies are assumed to follow a log-normal distribution, with error rates ranging from 3 to 10. Median 8.1.2 EquipmentModificationFactor values are quoted in Table l. 8- The RBI method requires that the analyst use a generic The equipment modification factor identifies the specific failure frequency to “jump start” the probability analysis. A conditions that can have a major influence on the failure fre- data source should be chosen that represents plants equip- or quency of the equipment item. These conditions are catego- ment similar to the equipment being modeled. For instance, rized into four subfactors: much high-quality generic data can be derived from nuclear 8-1COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 8-2 API 581 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- % r r L -? L 7- x Figure 8-l-Calculating Adjusted Failure FrequenciesCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • DOCUMENT INSPECTION RESOURCE RISK-BASED BASE 8-3 Table 8-1-Suggested Generic Equipment Failure Frequencies Data Source Equipment (References) sizes)fourforyear holeLeak Frequency (per ~~ 14 in. 1 in. Rupture 4 in. CentrifugalPump, single seal 1 6x 5x104 1x104 Centrifugal h n ,double seal up 1 1x104 1c3 6x 5x104 Column 2 8x1U5 6x10-6 2x104 2x104 Compressor, Centrifugal 1 1x104 1x103 Compressor, Reciprocating 6 6x 1Q3 6x104 Filter 1x10-5 1 5x10-5 9~10-4 1x10-4 FinFan Coolers 2x104 3 3x 104 5x10-8 2x104 Heat Exchanger, Shell 1 4x1W5 10-6 1x104 6x 1x10-5 Heat Exchanger, Tube Side 1 4x 1P5 1x104 6x 1x10-5 106 Piping, 0.75 in. diameter, perf t 3 1x10-5 3~10-~ Piping, 1 in. diameter, per ft 5xlo-6 3 5x10" Piping, 2 in. diameter, per ft 3xlo-6 3 6 x1e7 Piping, 4 in. diameter, per ft 3 9x lm7 6x le7 7 ~ 1 0 ~ Piping, 6 in. diameter, perft 4x 3 10-7 4x le7 8x1V8 Piping, 8 in. diameter, per ft 3 3xW7 8x1W8 3x1Q7 2x104 Piping, 10 in. diameter, per ft 3 2x10-7 8 ~ 1 0 ~ 3 ~ 1 0 ~ 2x108 Piping, 12 in. diameter, perft 3 lX10-7 3x1W7 3~10-~ 2x1044 Piping, 16 in. diameter, perf t 3 1x10-7 2x104 2x10-7 2x104 Piping, > 16 in. diameter, per ft 3 1W8 6x 2x10-7 2x104 1x10-8 Pressure Vessels 2 4x1@ 6x10-6 1x104 1x10-5 Reactor 2 1x10-4 3x lo4 2 x 1 ~3 ~ 1 0 ~ 5 Reciprocating Pumps 7 0.7 .o 1.O01 .O01 Atmospheric StorageT n 2x10-5 ak 5 1x10-5 1 0 ~ 4~ 1x10-4 plant reportingdatabases;however, the data maynot be tion is expected to increase failure frequency approximately appropriate to a refinery application because ofthediffer- of one order magnitude. in ences in maintenance and inspection quality, andthe nature Throughout this portion of an RBI analysis, it is assumed of the service. The analyst should always be familiar with that all equipment items have been designed and fabricated in generic data sources being used, andtheir appropriateness to accordance with industry and company standarddesign prac- the equipment being analyzed. tices, unless there is specific evidence to the contrary. These A suggested list of generic failure frequencies and their standard practices are generally basedon recognized industry sources are provided in Table 8-1. standards, such as ASME, T E M A , and ANSI. It is beyond the scope of an RBI analysis to confirm design accuracy. R B I 83 EQUIPMENTMODIFICATIONFACTOR . highlights the conditions that can have an adverse influence on properly designed equipment. The numeric values derived An equipment modification factor,or FE, is developed for reflect theimpact ofthese conditions on failure frequency. each equipment item, based on the specific environment in AU numeric values assigned to quantify therate of damage FE which the item operates. The is composed of four subfac- are positive numbers, since probability of failure cannot be tors which will be discussed below.An overview of theequip reduced by the existence of a damage mechanism. However, ment modification factor is shown Figure 8-2. in by definition, generic failure frequencydata include all equip- Each subfactor is composed of several elements which are ment items, some with on-going damage mechanisms and analyzed according to well-defined rules. For each element, some without. It follows that when an equipment item has no numeric values are assigned to indicate how much the failure operative damage mechanism, it should have a failure fre- frequency will deviate from generic, a result of the condi- as quency that is somewhat lower than generic. To account for tion being analyzed. Positive values are assigned for condi- this, all equipment items assigned a base are numeric value of tions that are judged to be more deleterious than generic, and -2.0, and damage mechanism values are added as appropri- negative values are used to indicate a reduction in expected ate. The -2.0 base adjustment value was developed while vali- failure frequency. A value of +10 is assigned when the condi- dating a plant-wide FU31 study. When no damage mechanisms --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- a-4 API 581 U 1 Figure 8-24verview of Equipment Modification FactorCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~ - STD.API/PETRO PUBL 581-ENGL 2000 0732290 Ob21587 338 m INSPECTION BASE RISK-BASED RESOURCE DOCUMENT 8-5 are identified, this system results in a negative numeric value Table 8-24onverted Equipment Modification Factor for the equipment item (and therefore a lower than generic failure frequency),all other factors being equal. If the sum of numeric values is. .. the FE is. .. If the summed equipment factor is a negative value, it is Less than -1.0 The reciprocal the absolute of converted as describedbelow to develop a positivefinal value of the numeric value equipment modification factor. -1.0 to +1.0 1.o Section 9 defines therequired datafor a R B I study andrec- Greater than +1.O Equal to the numeric value ommends sources for obtaining the data. It also includes a sample datasheet that can be used to gather the information this section. The fully developed Technical Modulesare pre- needed to establish F .E F sented in Appendices through N. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- After the subfactors have been analyzed, the numeric val- The user of the RBI system should not consider procedures ues for all the separatedeterminations are summed to yield a described in this chapter to be all-inclusiveor inviolable. This final numeric value for the equipment item. The final equip- chapter is intended to establish a method for the systematic ment modification factor is based on this value. The sum can and reproducible analysis of the factors that affect failure fre- be either positive or negative, and it will normally rangefrom quency. At the sametime, theR B I study shouldbe conducted -10 to +20,although atthe start of the program, the factor can under the oversight of a person or persons with appropriate be much higher when piece of equipment has high damage a a technical expertise. rate and a relatively ineffective inspection history. The final Analyzing the effect of in-service damage and inspection on numeric value is converted anF E as shown in Table to 8-2. the probability of failure involves the following seven steps: The resulting equipment modification factor is unique for each equipment item and based on the item’s specific oper- is a. Screen for damagemechanismsandestablishexpected ating environment. damage rate. b. Determine the confidence level in the damage rate. 8.3.1 Technical Modules c. Determinetheeffectivenessofinspectionprograms in confirming damage levels and damage rates. The Technical Modules thesystematic methods usedto are d. Calculate the effectof the inspection program on improv- assess the effect of specific failure mechanisms on the proba- ing the confidence level the damage rate. in serve four functions: bility of failure. They e. Calculate the probability that a given level damage will of a. Screenfor the damagemechanisms undernormaland exceed the damage tolerance of the equipment and result in upset operating conditions. failure. b. Establish a damagerate in the environment. f. Calculate the technical module subfactor. c. Quant~fy effectivenessof the inspection program. the g. Calculate the composite technical module subfactor all for d. Calculate the modification factor to be applied to the damage mechanisms. “generic” failure frequency. This section presents an overview of the approach follow- The Technical Module evaluates two categories of infor- ing the example of a Technical Module for general internal mation: corrosion. General corrosion is defined as uniform thinning 1. Deterioration rate of the equipment item’s material of over a substantial portion of the equipment wall. Different construction, resultingfrom its operating environment. technical modulesWUdeal with localized corrosion because 2. Effectivenessof the facility’s inspectionprogram to ofthehighervariabilityoflocalizedcorrosionrates, the identify and monitor the operative damage mechanisms greaterdifficulty of detectinglocalizedcorrosion,andthe prior to failure. ability of pressure equipment to tolerate deeper flaws if the affectedareaissmallenough.Continuingtheexample of Inspection techniques required to detect and monitor one failure mechanism may be totally different from those needed will general corrosion, the following pressure vessel be used as a case study demonstrate the methods. to for another mechanism. These differences are addressed by creating aseparate Technical Module for each damage mech- Vessel: Atmospheric Overhead Accumulator anism. For some damage mechanisms, rateof damage can the Material: SA 285-Gr.C be significantly greater under certain non-routine conditions, Thickness: 3/8 in. such as temperature excursions or abnormal changes in the Design Pressure: 50 psig concentrations of a particular contaminant. These conditions Corrosion Allowance: 3 1 , ~n i. often occur during process upsets or startups and shutdowns. Diameter: 6ft6in. The Technical Module accounts for such conditions and mod- Design Corrosion Rate: 1 mY 0 P ifies the probability failure accordingly. An example ofthe of Age: 6 years process for developing a Technical Module is presented in Prior Inspection Data: noneCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 8-6 API 581 The sevensteps of the analysis are described below. uncertainty in expected damage rates will include consider- ation of case histories from a variety similar processes and of 8.3.1.1 Screen for Damage Mechanism and equipment. The best information will come from operating Establish ExpectedDamage Rate experiences where the conditions that led to the observed damage rate could realistically be expected to occur in the The screening step consists of evaluatingthe combinations equipment under consideration.Other sourcesof information ofprocess conditions and constructionmaterials for each could include databases of plant experience or reliance on equipment item, to determine what damage mechanisms are expert opinion. The latter method is used most often, since potentiallyactive.If no damage mechanismsare found, a plant databases, where they exist, usually do not contain suffi- --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- technical module subfactor of -2 is applied to that specific ciently detailed information. piece of equipment, giving a reduction from the generic prob- Example: Economical equipment design usually requires ability of failure. For the general corrosion technical module, internal corrosion rates of less than five m i l s per year. How- two screening questions are used ever,higher rates aresometimes observed. It is notvery a. Is the corrosionrate known to be less than1 mpy? or unusual to observe corrosion rates twice what was expected b. Is the equipmentdesigned with a corrosion allowance? or previouslyobserved.Usually these higher rates are If the answer to the first question is no, or alternatively,if detected during inspections, butsometimes the occurrence of theanswer to the second questionisyes,theanalyst is higher-than-expected corrosion ratesis not detected until fail- directed to proceed with the evaluation of the equipment item. ure of the pressure boundaryof the process occurs. Where a damagemechanism is identified, therate of dam- Observed less frequently are corrosion rates as much as age progression is generally known or can be estimated for four times the expected rate. Rarely are corrosion rates for process plant equipment.Sources of damage rate information uniform corrosion more than four times the rate expected. include: (Localized corrosion can be significantly more variable and a. Published data. thus must be evaluated in a separate technical module.) The b. Laboratory testing. default values provided here are expected to apply to many c. In-situ testing. plant processes. Notice that the uncertainty in the corrosion d. Experience with similar equipment. rate varies, depending on the source and quality of the corro- e. Previous inspection data. sion rate data, Supplements to the technical modules are being developed For general internal corrosion, the reliability of the infor- for specific materials-environment combinations, and refer- mation sources used to establish a corrosion rate can be put ences describing the specific mechanisms are provided. into the following three categories: Example: Forgeneral internal corrosion, the damage is rate the corrosion rate used in an API 510 or MI 570 calculation 8.3.1.2.1 Low Reliability Information Sources for to determine the remaining life and the inspection frequency. Corrosion Rates In some cases, a measured of corrosion may not avail- rate be a. Published data. able. The Technical Modules will provide default values, typ- b. Corrosion rate tables. ically derived from published data or from experience with c. “Default” values. use are similar processes, to until inspection results available. Case Study: In our pressure vessel example, the screening Althoughthey are often used for design decisions,the step has confirmed that the process wouldbe expected to actual corrosion rate that will be observed in a given process cause generalinternal corrosion in the vessel. With inspec- no situation may significantly differ from design value. the tion data, the design corrosion data of 10 mpy is the best esti- mate availablefor the damage rate. 8.3.1 -2.2 Moderate Reliability Information Sources for Corrosion Rates 8.3.1.2 Determine the Confidence Level in the a. Laboratory testing with simulated process conditions. Damage Rate b. Limited in-situ corrosion coupon testing. The damage rate in process equipment is often not known Corrosion rate data developed from sources that simulate with certainty. The ability to state the rate of damage pre- the actual process conditions usually of provide a higher level cisely is limited byequipment complexity, process and metal- confidence in the predicted corrosion rate. lurgical variations, inaccessibility for inspection, and limitations of inspection and test methods. 8.3.1.2.3 High Reliability Information Sources for The uncertainty in the expected damage rate canbe deter- Corrosion Rates mined from historical data on the frequency with which vari- ous damage rates occur. A realisticunderstanding of the a. Extensive field data from thorough inspections.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • RISK-BASED BASERESOURCE DOCUMENT INSPECTION 8-7 b. Coupon data, reflecting five or more years of experience In general, inspection programs are classified into one of with the process equipment (assuming no change in process five categories: conditions has occurred). a. Highly effective. If enough data are available from actual process experi- ence, there is little likelihood that the actual corrosion rate b. Usually effective. will greatly exceed the expected value under normal operat- c. Fairly effective. ing conditions. d. Poorly effective. Table 8-3 expresses the degree of confidence that the true e. Ineffective. damage rate falls into the listed damage ranges, based on rate At this point, the B R D will continue illustrating develop the reliability of the damage rate data. ment of the Technical Module with the general examples of Case Study: In our pressure vesselexample, the anticipated internal corrosion. corrosion rate is based on the design information. this case, In Section 8.2.2 explains how the estimate of inspection published data were consulted, and the designer had signifi- effectiveness is developed and how categories are assigned cant experience with the process. Confidence in the corrosion Example: For general internal corrosion, the damage rate can rate information is based on the judgment that data is “low the be determined very effectively with a thorough inspection, reliability.” but even “spot” random measurements yield considerable information since the corrosion rate usually does not vary 8.3.1 -3 Determine the Effectiveness of Inspection much except over fairly large areas. Programs in Confirming Damage Levels It is important to recognize that inspection codes and prac- and Damage Rates tices expect thichess measurements to be taken at repeatable locations to improve the accuracy of corrosion rate calculations. Inspection programs (the combination of NDE methods such as visual, ultrasonic, etc., used to determine the equip Three inspection programs are described and their effec- ment condition) vary in their effectiveness for locating and tiveness category are defined in Table 8-4. sizing damage, and thus for determining damage rates. Limi- Default values, based on expert opinion, are provided i n tations in the ability of a program to improve confidence in Table 8-6, indicating the level of confidence that each of the the damage level result from the inability to inspect 100%of three levels of inspection effectiveness will accurately deter- mine the corrosion rate. the areas subject to damage, and frominherent limitations of some test methods to detect and quantlfy damage. Probabil- Case Study: In our pressure vessel example, no inspections have been performed. . --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- ity-of-detection curves provide someinformation on inherent test limitations and are discussed infurther detail in 8.2.3. Table 8“Generic Descriptions of Damage State The technical modules are based on three damage states Categories which are defined in Table 8-4. The effectiveness of an inspection program can be quanti- Damage Category Corrosion State Example-neral tatively expressed as the l i e l i h d that the observed damage Damage State 1 The rate general corrosion is of state (and thus the predicted damagerate) actually represents The damage in the equipment less than or equal to the rate the true state. As in the previous discussion of damage rate is no worsethan what is predicted by past inspection estimates, plant information and experience, together with expected based on damage rate records, or historical data if no models or experience. inspections havebeen expert opinion, provide information with which to express the performed. inspection program’s effectiveness. Damage State2 The rate of general corrosion is Table 8-Monfidence in Predicted Damage Rate The damage in the equipment as much as twice the predicted is “somewhat” worsea t n h rate. Actual Low Moderate anticipated. This level of dam- High age is sometimes seen in simi- Damage Rate Reliability Reliability Reliability Data Data Data lar equipment items. Range Predicted rate 0.5 0.7 0.8 Damage State3 The rate general corrosion is of or less The damagein the equipment as much as four times the pre- Predicted rate 0.3 0.2 O. 15 is “considerably” worse than dicted rate. to two times anticipated. This level of dam- rate age is rarely seen in similar Two to four 0.2 o.1 00 .5 equipment items, buthas been times predicted observed on occasion industry rate wide.COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 5BL-ENGL 2000 0732290 Ob21590 922 8-8 API 581 Table 8-5-Inspection Effectiveness for General Internal Corrosion Qualitative Examples Inspection Corrosion Effectiveness General CategoIy Highly Effective Inspectionmethods correctlyidentify anticipated the in-service Assessment general of corrosion complete by intemal visual damage incase nearly every (90%). examination measurements. coupled ultrasonic with thickness Usually Effective TheinspectionmethodswillcorrectlyidentifytheactualdamageAssessment of generalcorrosion bypartialinternalvisual most state timethe of (70%). examination ultrasonic coupled with thickness measurements. Fairly Effective The inspection methods will correctly identify the true damage state Assessment of general corrosion by external spot ultrasonicf half about (50%). measurements. thickness Poorly Effective Theinspectionmethodswillprovidelittleinformationto conre~tly Assessment of general corrosion by hammer testing, telltale holes. identify the true damage state (40%). Ineffective The inspection method will provide no or almost no information that Assessment of general internal corrosion by external visual correctly will state damage identify true the (33%). examination. Table 8-6General Corrosion-Inspection Effectiveness Likelihood that inspection result determines the true damage state Damage State Range of actual rate damage Ineffective Effective Effective Effective 1 Measuredrate or less 0.33 0.5 0.7 0.9 2 Measured to 2x measured rate rate 0.33 0.3 0.2 0.09 3 2x to 4x measured rate 0.33 0.2 o.1 0.01 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 8.3.1.4 Calculate the Effect of the Inspection The probabilities, p[AilBk]are called posterior probabilities. Program on Improving the Confidence For those unfamiliar with the equation,it can be expressed Level in the Damage Rate as follows: “the probability of the true state, given the of state At t i point, the Technical Module has defined need to hs the a sample equals [(the probability of the sample state, given determine the probabilityof a given damage state occurring thetrue state) times (the priorprobability of the state)] in the equipment item being evaluated. The problem is the of divided by [the sum over all states of (the probability of the general form: “Given an expectation of a given state, and sample state, given the true state) times (the prior probability given that a test can be performed to improve the confidence of the state)]”. of level in the expectation that state, what is the expectation of The powerof the theorem is that it provides formal means a the state after the test is performed, if the test does not yield of incorporating an uncertain inspection result with informa- conclusive results?’ Problems of this type can be solved using a widely recog- tion on the expected condition based on an analysis or opinion. nized statistical method called Bayes’ Theorem. theorem This Given an expectation of the likelihoods of different dam- combines the prior probabilities p[Ad (the expected state) age rates, and given inspection results that tend to indicate withtheconditionalprobabilities, p[ekbAi](the inspection one rate or another, Bayes’ Theorem is used to update the effectiveness) to yield an expression for the probability that prior expectations. an equipment item is in any state Ai given that the item was The inspection frequency and the total number of inspec- observed tobe in state Ak which results in observation Bk, tions are used perform the inspection updating. The “value” to of an inspectionin improving the certaintyof t e damage rate h can clearly be determined using Bayes’ Theorem. The updated confidencein damage rates is then used tocalculate the j=l amount of damage that may be present in the equipment. COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 581-ENGL 2000 D 0732290 Ob21591 8b9 D RISK-BASED DOCUMENT INSPECTION BASE RESOURCE 8-9 Example:Fortheabove examples ofexpecteddamage TechnicalModuleistocalculate the frequency of failure rates and inspection effectiveness, the updated confidence in associated with a given damage state. the damage rates after inspection be determined: can Failure of process equipment with respect to damage states a. corrosion rates for a new plant are e s t i m a d h m corn- depends on a number of random variables, 21,z2*** such Zn, sion tables as maximum pressure, maximum crack size, yield suength, b. A thorough inspectionconduct& is after he or fracture toughness. spacethese The of quantities is divided operation into two regions: c. The expected corrosion rate is confirmed a. The safe set is the region the space that contains combi- of As shown in Table8-7, the confidence in the expected cor- Zi, nations of the basic variables, that do not result in failure. be rosion rate can updated by BayesTheorem: CaseStudy: In ourpressure vessel example, the first b. The failure set is the region of this space that contains all inspection is determined to a usually effective inspection. be combinations of the variables,Zi, that resultin failure. Table 8-7 is shown in graphic form in Figure 8-3. Note that A mode of failure isdefined by a limit state function g(Zi). the inspection serves reduce the uncertainty in the expected to The surface described by g(Zi)= O divides the variable into corrosion rate. the safe setwhere g(ZJ > O and the failure set whereg(Zi) O. For example, the limit state function for a pressure vessel 8.3.1.5 Calculate the Frequency at which a Given might b : e Level of Damage Wl Exceed the Damage il g = S-L Tolerance of the Equipment and Result in Failure where The potential damage rates,represented by the uncertainty S = strength, in the estimated damage rate, will lead to different levels of damage after a given in time operation. The next step in the L = load. Table 8-7"Confidence in Damage Rate After Inspection Aftera Fairly Effective After a Usually Effective After a Highly Effective Damage Range State Rate Inspection Damage Inspection Inspection Rate of 1 Measured rate or less 0.66 0.814 0.940 2 Measured rate to 2x measured rate 0.24 o. 140 0.056 3 2 to 4x measured rate o. 10 0.046 0.004 1 , I """""""""""""""""~ """""""""""""""""" """""""""""""""""- Corrosion Rate, mpy No inspection %?"Fairly" Effective "Usually"Effective H "Highly"Effective Low reliabilitydata source, one inspection Figure 8-&Damage Rate Confidence-Inspection Updating vs. Inspection Effectiveness --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • 8-1O API 581 Whenever the load exceeds the strength, the vessel fails The frequency of failure for the damage state is divided by and g(SL)c O. the “generic”failurefrequency.The resulting ratio shows For a failure mode that is described by a limit state func- how much more likely the equipment being analyzedis to fail tion, the probability of failure the probability of being in the is as a result of the given damage state than is the “generic” failure set, g(Zi) O. Several approaches can be used to calcu- equipment item. This ratio is then multiplied by the likeli- late the probability of failure. For RBI, since this is a deci- hood that the damage state exists, as updated by inspection sion-making tool, relatively simple reliability index methods information. have been chosen. Case Study: For the pressure vessel subject to general cor- The procedure used here is to “calibrate” the calculated rosion, Table 8-9 shows the calculated technical module sub- probabilityoffailure to the generic failurefrequency by factor. As an illustration of the effect of inspection updating, adjusting the inputs to the reliability index so that an “accept- the subfactor is calculated for two cases: able” level of damage corresponds to the generic failure fre- quency. This “calibrated” reliability index model is used to a. The vessel is six years old and has not yet beeninspected. calculate a failure frequency for higher damage states. b. The vessel is six years old and has received inspection one Example: For the case of general corrosion, the mode of rated “usually effective.” failure is ductile overload, which occurswhen the flow stress in a thinned wall is exceeded by the stress caused by the Note: the reduction in the technical module subfactor following the applied loads. inspection. For the example above with different potential corrosion The table is illustrated in graphicform in Figure 8-4. Note rates, the damage state (wall loss) is calculated for each rate. that the inspection serves to significantly reduce the likeli- Thenthefrequency of failure for each stateiscalculated hood of the higher damage states. using a simple reliability indexmethod. The technical module subfactor is the sum of the partial Case Study: For the pressure vessel example, remember damage factors for the different damage states. The lowest that the vessel has been in service for six years. Table 8.8 shows the probabilities of failure correspond to the three that that a technical module subfactor can be is 1.0, since in the different damage states. risk analysis no credit given for the absence of any one is par- ticular type of damage. 8.3.1.6 Calculate the Technical Module Subfactor 8.3.1.7 Calculate the CompositeTechnical Module The next step in the Technical Module is to calculate the Subfactor forall Damage Mechanisms “technical module subfactor” thatis used to compare the fre- quency of failure due to the damage state, to the generic fail- A technical module subfactor is calculated for each dam- ure frequency for the equipment type under consideration. age mechanism that is active in the piece of equipment. To The technical module subfactor is the ratio of the frequency calculate the composite (total) technical module subfactor for of failure due to damage, to the generic failure frequency, the equipment, all the individual of subfactors are added. This times the likelihood that thedamage level is present. approach has the advantage of showing a quantitative change Table 8-€&Calculated Frequency of Failure for Different Damage Statesrosion Damage Rate State wall Loss FrequencyWallRemaining of Failure 1 0.010in./yr 00 .6 0315 . 8 x 104 2 0.020 in./yr 0.12 0.255 2 x 10-5 3 0.040 in./yr 0.24 015 .3 5x lo3 Table 8-9-CalculatedTechnical Module Subfactor “Generic” Likelihood of Likelihd of Probability Probability Ratio to Damage (before Partial Damage Damage (after Partid Damage Damage State of Failure of Failure “Generic” inspection) Factor (no insp.) inspection) Factor (1 insp.) 1 8x 10-6 l x lo“ 00 .8 05 . 00 .4 08 .1 00.6 2 2x 1 ~ 5 l x lo“ 0.2 0.3 00 .6 O. 14 0.03 3 5 x la3 1x10-4 50 0.2 10 0.05 2e Total Technical 10 2 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • ~~ ~~ ~~ STD.API/PETRO 581-ENGL PUBL 2000 H 0732290 Ob21573 b 3 L m RISK-BASED INSPECTION BASERESOURCE DOCUMENT 8-11 0.8 0.7 - - ------ """"""""""""""""""" 0.6 ---- ---- """"""""""""""""""" 0.5 -------- """""""""_"""""""""- 0.4 "_ """"""""""""""""""" 0.3 -" """""""""_"""""""""~ 0.2 "_ """ """"""_""""""" o. 1 "_ """ """" - --- --- - O 0.08 0.2 50 Ratio of Calculated to Generic Failure Frequency NOinspection W One inspection One "usually"effective inspection Figure 8-&Failure Frequency-Inspection Influence on Calculated Frequency in the total factor if any one of the subfactors changes. The sons using data or tools such as the Technical Module Supple- approach also reflects that different damage mechanismsare ments. often not completely independent. That is, damage caused by Two methods are suggested for establishing corrosion rates one mechanism may influence the severity damage caused of intheabsenceofcorrosiondata, expert opinion or prior by another (for example, stress corrosion cracking may begin knowledge of the type and rate of corrosion occurring in a at stress concentrators caused by pitting corrosion). particular system. 8.3.1.8 Using Measured Corrosion Rates in the 8.3.1-8.1Method #l-Simplified Approach --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- Absence of Expert Opinion or Data When a corrosion is to be used forRisk-Based Inspec- rate A serious weakness can exist in the application of RBI tion in the absence corrosion rate data or information about of technology as outlined in this chapter if the source of corro- localized corrosion, the question usually arises: "How much sion rate data is not properly considered. In the model pre- inspection is needed to determinethe rate and type of corro- sented, corrosionrates are always assumed to have a potential sion? It may be risky use spotexternal thickness measure- to to be higher than expected, unlessthispotentialhasbeen ments for such purposes, but it may be a waste of money to elimiiated by thorough ormultiple inspections. The technical use more thorough methods if they are not needed. The fol- module subfactortables for thinning are based on a simplified lowing guidelinesare offered to aid in a decision. version of Bayesian updating that assumes that expert opinion a Localized corrosion likely: a . Use"highly effective" will generally be used establish corrosion rates.Since such to method to determine positively if localized corrosion is expert opinions are fairly reliable, and generally err on the occurring.These methods are described in theTechnical conservative side, the method used will also generally err on Module for Thinning, Appendix F. Process streams that the conservative side. However, many plants do not have or should be in this category include any that contain water or use expert opinionas the basis for corrosion rates, but instead other conductive fluid plus: rely entirely upon thickness measurements taken by techni- 1. Chlorides or other halides. cians who havelittle or noknowledge of process corrosion. In 2. Sulfur compounds. such a case, the corrosion rate measured can be much less 3. Organic acids. than the actual corrosion rate (depending on the degree to b. Localized corrosion possible: Use a"usually"effective which the corrosion is localized and upon the effectiveness method determine to positively if localized corrosionis In level of the inspection). such cases, it is strongly suggested occurring.These methods are described in theTechnical that corrosion rate estimates be made by knowledgeable per- Module for Thinning, Appendix F. Process streams thatCOPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD=API/PETRO PUBL 561-ENGL 2000 S?& œ 8-12 API 581 should be in this category include any that do not contain lowing tables, 8-9 through 8-1 1, the confidencelevelis water or other conductive fluid*but do contain: described in one of three ways: l. Chlorides or other halides. a. High-Opinion ordata is very slightly conservative, lower 2. Sulfur compounds. rates are not expected. 3. Organic acids. b. Medium-Opinion or data is somewhat conservative, c. Localized corrosion unlikely: a Use“fairly effective” some chance of lower ratesis recognized. method to determine positively localized if corrosion c. Low”Opinion or data is highly conservative, significant is occurring.ThesemethodsaredescribedintheTechnical chance of lower rates is recognized. Module for Thinning, Appendix F. Process streamsthat Example: Corrosion rate data for a piping system is well should be in this category include any that do not established from performance of similar systems, and issup- contain also water or other conductive fluid and do not contain: ported by published data and laboratory tests. The expected maximum corrosion rate is 10 mpy, and it is known that the l . Chlorides or other halides. corrosion is often highly localized. A contractor takes spot 2. Sulfur compounds. thickness measurementsand reports acorrosionrate of 1 3. Organic acids. mpy. Obviously, there is reason be skeptical about the to data. “Other conductive fluid” refers some classes of organic to Since the contractor took only spot measurements and is not chemicals that, like water, can conduct electricity. These flu- especially knowledgeableaboutwhere to takethem,the ids (e.g. dimethyl formamide, n-butyl alcohol, are not nor- inspection effectiveness is judged as “ p r l y effective.” In mally part of refinery process streams, are present in some but Table 8-12 the factor for 1 poorly effective inspection result- chemical plants). As a general rule, fluids with a conductivity ing in a measurementof l/10 the expected rate for a high con- of less than ohm” cm-l are nonconductive there- and fidence expected rate is 8.3. This factor is multiplied by the fore tendto be noncorrosive. measured rate of 1 mpy yields an input rate of 8.3 mpy. In other words, the data from the measurementhas not success- fully changed the expert opinion significantly. thatNote 8.3.1.8.2Method #24igorOus Approach repeated inspections and more highly effective inspections (if There sometimes arises a situation in which corrosion data,they continue to observe the lower corrosion rate)will result expert opinionor prior knowledge of the type and of cor- rate in the RBI input corrosion rate approaching the measured If rosion do not a p e with the inspection findings. the inspec- rate. The factors in Tables 8-10 and 8-1 1 are used similarly. tion finds higher rates of corrosion than expected, then there is little doubt that these higher rates exist and they should be 8.3.2 Universal Subfactor used unlesstheyareattributedto some processupset or The universalsubfactor covers conditions that equally unusual condition that has been corrected. On the hand, other affect all equipment items in facility. As a result, the infor- the if the inspection data shows lower rates of corrosion than mation concerning these conditions needs be collected and to expected, then a conflict arises about whichdata is correct. recorded only once.The numeric values assigned for each of If the measured corrosion rates lower thanthe expected are the three elements of the subfactor are applied equally toal l corrosion rate, then repeated observations of these lower rates equipment items. must be used to “override” the expected rate, much in the As shown in Figure 8-2, the universal subfactor includes same way that repeated inspections eliminate the possibilities the following elements: of higher corrosion rates using current methods. As more the a. Plant condition. inspections are performed, or more highly effective inspec- b. Cold weather operation. tions are performed, the corrosion rate be used approaches to c. Seismic activity. the measured rate from the higher expected rate. The corro- sion rate to be used will depend on the number and types of 8.3.2.1 Condition Plant inspections, how much lower than the expected rate is the measured rate, andalso upontheconfidencelevelofthe This element considers current condition of the facil- the expert opinion or data that is used to establish expected rates. ity being evaluated. The ranking should be based on the Bayesianupdatingwasusedtogeneratethefollowing professional judgment of the observer, when considering the followingcharacteristics: tables. A factor is looked up from the table based the num- on ber and types of inspections. This factor is multiplied by the a. The general appearance of the plant, as assessed during a measured rate to generate the rate that should be entered in plant walk through. Factors observe include: to the program. 1. The overall state of housekeeping. The degreeto which there is a dispute between the 2. Evidencetemporary of repairs, particularly if it expected and measured rates depends in upon the confi- part appears that the “temporary” condition has been in place dence that can be placed on the expected rates. In the fol- for an extended period. --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD-APIIPETRO PUBL 581-ENGL 2000 m 0732290 Ob21595 404 RESOURCE BASE INSPECTION RISK-BASED D~CUMENT 8-13 Table 8-1O-Measured Corrosion Rates Approximately l/2 of the Expected Rate Wtd. Avg. Com. Rate; Measured Rate = l/2 of Expected, Confidence= High Level of Inspection UsuallyInspections No. of Highly 1.8 1 1.4 2 1.o 1.S 1.8 1.9 3 1.o 1.1 1.7 1.9 4 1.o 1.o 1.S 1.8 5 1.o 1.o 1.3 1.8 6 1.o 1.o 1.2 1.7 7 1.o 1.o 1.1 1.7 8 1.o 1.o 1.1 1.6 9 1.o 1.o 1.o 1.6 10 1.o 1.o 1.o 1.S 11 1.o 1.o 1.o 1.4 12 1.o 1.o 1.o 1.3 Wtd. Avg. Corr. Rate; Measured Rate = l/2of Expected; Confidence= Medium Level of Inspection usuallyInspections No. of Highly 1 1.1 1.S 1.7 1.8 2 1.5 1.o 1.2 3 1o . 1.o 1.6 1.4 4 1.o 1.o 1.6 1.2 5 1.o 1.o 1.1 1.S 6 1.o 1.o 1.4 1.1 7 1.o 1.o 1o . 1.4 8 1.o 1.o 1.o 1.3 9 1.o 1o . 1.o 1.2 10 1.o 1.o 1.o 1.2 11 1.o 1.o 1.o 1.2 12 1.o 1.o 1.1 Wtd. Avg. Corr. Rate: Measured Rate = l/2 of Expected, Confidence= Low Level of Inspection No. of Inspections Usually Highly 1 1.4 1.1 1.2 2 1.2 1.o 1.1 3 1.o 1.o 1.3 1.1 4 1.o 1.o 1.3 1.1 5 1.o 1.o 1.o 1.2 6 1.o 1.o 1o . 1.2 7 1.o 1.o 1.o 1.1 8 1.o 1o . 1.o 1.1 9 1.o 1.o 1.o 1.1 10 1.o 1.o 1.o 1.1 11 1.o 1.o 1.o 1.1 12 1.o 1.o 1.o 1.1 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD.API/PETRO PUBL 581-ENGL 2000 0732290 0623596 340 m 8-14 API 581 Table 8-11-Measured Corrosion Rates Approximately l/4 of the Expected Rate Wtd. Avg. COIT. Rate: Measured Rate= l/4 of Expected Confidence= High Level of Inspection usually No. of Inspections Highly 1 2.0 3.4 3.6 3.7 2 1.1 2.4 3.4 3.7 3 1.o 1.4 3.0 3.6 4 1.o 1.1 2.5 3.5 5 1.o 1.o 2.0 3.3 6 1.o 1.0 1.5 3.2 7 1.o 1.o 1.3 3.0 8 1.o 1.o 1.1 2.8 9 1.o 1.o 1.1 2.5 10 1.o 1.o 1 .o 2.3 11 1.o 1.o 1.o 2.1 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`--- 12 1.o 1.o 1.o 1.9 ~~ Wtd. Avg. Con. Rate; Measured Rate = */4 of Expected: Confidence= Medium Level of Inspectionhly No. of Inspections 1 2.9 1.3 2.4 2 2.4 1 .o 1.5 3.O 3 1.9 1.o 1.1 2.8 4 1.o 1.o 2.6 1.6 5 1.o 1.o 2.4 1.3 6 1o . .o 2.1 1 1.2 7 1.o 1.o 1.1 1.9 8 1.o 1.o 1.o 1.8 9 1.o 1. o 1.o 1.6 10 1.o 1.o 1.o 1.5 11 1.o 1.4.o 1 1.0 12 1.o 1.o 1.o 1.3 Wtd. Avg.Com. Rate; M a u e Rate = l/4 of Expected; Confidence= Low esrd Level of Inspection Usually No. of Inspections Highly 1 1.1 1.5 1.9 2.1 2 1.o 1.1 1.6 2.0 3 1.o 1.o 1.3 1.8 4 1.o 1.o 1.2 1.6 5 1.o 1.o 1.1 1.5 6 1.o 1.o 1.1 1.4 7 1.o 1o . 1.0 1.3 8 1.o 1.o 1.o 1.3 9 1.o 1.o 1.o 1.2 10 1.o 1.o 1.o 1.2 11 1.o 1.o 1.o 1.1 12 1.o 1.o 1.o 1.1 COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STDmAPI/PETRO PUBL 58L-ENGL 2000 0732290 0b2L597 287 m RISK-BASED BASE INSPECTION DOCUMENT RESOURCE 8-15 Table 8-12-Measured Corrosion RatesApproximately of theExpectedRate Wtd. Avg. Com. Rate: Measured Rate = l/10 of Expected, Confidence= High Level of Inspection No. of Inspections HishlY Poorly usually Fairly 1 9.0 8.3 2 8.3 5.3 1 3 7.2 .o 2.3 1 4 5.7 .o 1.3 5 4.0 1.o 1.1 1 6 .o 1.o 7.7 2.8 7 1.o 1.o 7.1 1.9 8 1.o 1.o 6.5 1.5 1 9 .o 1.o 5.8 1.3 10 1.o 1.o 1.1 5.2 1 11 .o 1.o 4.5 1.1 1 12 .o 1.o 1.o 3.9 Wtd. Avg. Com.Rate; Measured Rate = l/10 of Expected; Confidence = Medium Level of Inspection No. of Inspections usually Highly 1 2 2.5 5.6 7.2 3 1.o 1.3 4.1 6.6 4 1.o 1.1 2.8 6.0 5 1.o 1.o 2.0 5.3 1 6 .o 1.o 1.6 4.7 7 1.o 1.o 1.3 4.1 8 1.o 1.o 3.6 1.2 1 9 .o 1.o 3.1 1.1 1 10 .o 1.o 2.7 1.1 1 11 .o 1.o 1.o 2.3 1 12 .o 1.o 1.o 2.1 Wtd. Avg. Com Rate; Measured Rate= l/10 of Expected, Confidence = Low Level of Inspection No. of Inspections Highly Poorly Usually Fairly 2.7 1 1.5 2 1.o 1.5 2.9 4.2 3 1.o 1.1 2.1 3.7 4 1.o 1.o 1.6 3.2 5 1.o 1.0 1.4 2.8 6 1.o 1.o 1.2 2.5 7 1.o 1.o 1.1 2.2 8 1.o 1.o 1.1 2.0 9 1.o 1.o 1.o 1.8 10 1.o 1.o 1.o 1.7 11 1.o 1.o 1.o 1.5 12 1.o 1.o 1.o 1.4 --`,```,`,,``,,`,`,`,``,,,``,,,-`-`,,`,,`,`,,`---COPYRIGHT 2003; American Petroleum Institute Document provided by IHS Licensee=Shell Services International B.V./5924979112, User=, 04/08/2003 19:50:55 MDT Questions or comments about this message: please call the Document Policy Management Group at 1-800-451-1584.
  • STD=API/PETRO PUBL 581-ENGL 2000 8-16 API 581 3. Deteriorating paint, excessive number of steam leaks, Table 8-1%-Ranking According to Plant Conditions or other evidence that routine maintenance being is neglected. Numeric Plant Condition Category Value b. Effectiveness of the plants maintenance program, based on interviews with operations maintenance personnel. An and Significantly better than industry A -1.0 standards effective program will: l . Complete most maintenance activities properly the first About equal toindustry standards B O time, with few call-backs. Below industry standards C + 1.5 2. Avoid excessive and growing backlogs of work requests. Significantly below industry standards D + 4.0 3. Maintain a constructive relationship between mainte- nance and operations personnel. c. Plant layout and constructi