1、Item No. 24215NACE International Publication 34101This Technical Committee Report has been preparedby NACE International Task Group 174* onRefinery Additives Injection FacilitiesRefinery Injection and Process Mixing Points March 2001, NACE InternationalThis NACE International technical committee rep
2、ort represents a consensus of those individual memberswho have reviewed this document, its scope, and provisions. Its acceptance does not in any respect precludeanyone from manufacturing, marketing, purchasing, or using products, processes, or procedures not includedin this report. Nothing contained
3、 in this NACE International report is to be construed as granting any right, byimplication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or productcovered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of LettersPa
4、tent. This report should in no way be interpreted as a restriction on the use of better procedures or materialsnot discussed herein. Neither is this report intended to apply in all cases relating to the subject. Unpredictablecircumstances may negate the usefulness of this report in specific instance
5、s. NACE International assumes noresponsibility for the interpretation or use of this report by other parties.Users of this NACE International report are responsible for reviewing appropriate health, safety,environmental, and regulatory documents and for determining their applicability in relation to
6、 this report prior toits use. This NACE International report may not necessarily address all potential health and safety problems orenvironmental hazards associated with the use of materials, equipment, and/or operations detailed or referredto within this report. Users of this NACE International rep
7、ort are also responsible for establishing appropriatehealth, safety, and environmental protection practices, in consultation with appropriate regulatory authorities ifnecessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of thisreport.CAUTIONARY NOTIC
8、E: The user is cautioned to obtain the latest edition of this report. NACEInternational reports are subject to periodic review, and may be revised or withdrawn at any time without priornotice. NACE reports are automatically withdrawn if more than 10 years old. Purchasers of NACEInternational reports
9、 may receive current information on all NACE International publications by contacting theNACE International Membership Services Department, 1440 South Creek Dr., Houston, Texas 77084-4906(telephone +1281228-6200).ForewordThis technical committee report has been written tosummarize and convey an unde
10、rstanding of materials andcorrosion concerns and successful practices that have beenused in the design and operation of refinery process mixingpoints and injection facilities. Its publication is part of aneffort begun in September 1993, when an ad hoc taskgroup on injection equipment sponsored by NA
11、CEInternational Specific Technology Group (STG) 34 (formerlyGroup Committee T-8) on Refining Industry Corrosionreached the conclusion that problems with injectionpractices existed in the industry, due largely to a deficiencyin communication of good practices. Task Group 174(formerly T-8-21) was form
12、ed to address these problems.The task group conducted a survey of problematic refineryinjection and process mixing points, and it sponsored asymposium on injection systems. The results of the taskgroups work constitute the basis for this report.The goal of this report is to help the reader develop a
13、nawareness of issues around refinery injections and toconvey basic understanding of key variables and designfactors. This report is intended for use by process,mechanical, and materials and corrosion engineering andinspection personnel who design, install, operate, andinspect refinery unit injection
14、 systems.Task Group 174 (formerly T-8-21) on Refinery AdditivesInjection Facilities prepared this technical committee report.It is published by NACE International under the auspices ofSTG 34 (formerly Group Committee T-8) on PetroleumRefining and Gas Processing._* Chairman W.C. Fort, Equilon Enterpr
15、ises, LLC, Houston, TX.NACE International2Table of ContentsSection 1: Introduction. 3Section 2: Definitions. 3Section 3: Refinery Injection Experience. 4Section 4: Avoiding Injection Point Problems 12Section 5: Process Design of Successful Injection Points. 12Section 6: Injection System Hardware Sel
16、ection. 22Section 7: Performance Verification and Monitoring 27Section 8: Reliability, Inspection, and Monitoring. 27Section 9: Considerations for Water Wash Applications. 28Section 10: Considerations for Process Chemical Injections 32Section 11: Considerations for Process Mixing Points 38References
17、 41Appendix A: Case Histories. 41Appendix B: Injection System Installation Checklist 45Appendix C: Sample Injection Point Data Sheet 46Appendix D: Injection Point Data Reviewed in Audit Process . 48FiguresFigure 1: Total Injection Points Identified. 4Figure 2: Problem Injection Points Types. 6Figure
18、 3: Type of Corrosion Damage Reported at the Injection Point. 7Figure 4: Size of the Area of Maximum Corrosion Loss 8Figure 5: Injection Point Corrosion Distance from Injection Point. 9Figure 6: Location of Maximum Injection Point Corrosion. 10Figure 7: Gas-Liquid Flow Regimes in Horizontal Piping.
19、14Figure 8: Gas-Liquid Flow Regimes in Vertical Upflow Piping. 15Figure 9: Baker Plot for Gas-Liquid Flow in Horizontal Piping. 16Figure 10: Flow Map for Gas-Liquid Upflow in Vertical Piping. 17Figure 11: Types of Injectors . 19Figure 12: Injection Nozzle Discharge Orientations. 20Figure 13: Injecto
20、r and Nozzle Orientations. 21Figure 14: Schematic of a Possible Corrosion Control Chemical Injection System for aCrude Distillation Column Overhead. 23Figure 15: Removable Injectors that Facilitate Inspection and Cleaning. 25Figure 16: Schematic of a Retractable Injector 26Figure 17: Ammonium Chlori
21、de Deposition from NH3and HCl. 30Figure 18: Double-Drum Overhead Condensing System of the Atmospheric Tower in aCrude Distillation Unit 34Figure 19: Common Types of Hydrogen Addition Point. 40Figure A1: Hydrodesulfurizing Unit Separator Overhead Piping Isometric 42Figure A2: Atmospheric Crude Column
22、 Overhead Piping Isometric 43Figure A3: Light Ends Recovery Piping Isometric 44Tables1. Problem Injection Points Reported 52. Original Materials of Construction of Problem Injection Points 63. Location of Injection Point Corrosion. 94. Causes of Injection Point Corrosion. 115. Injection Point Upgrad
23、e 12NACE International3Section 1: Introduction1.1 Many different types of process additives are used tomaintain reliability and optimal performance of refineryoperations. An additive can be a proprietary chemical suchas a corrosion inhibitor, antifoulant, oxygen scavenger, or awater stream injected
24、to dissolve salt deposits or dilutecorrosive process components. Typically, these additiveshave been injected into refinery piping systems throughsmall branch connections either directly or through a quill orspray nozzle. The locations at which these additives areintroduced into process streams are
25、commonly referred toas injection points.1.2 Several corrosion mechanisms associated withinjection points have become apparent to refinery personnelover the years. Many of these problems have resulted inhighly localized deterioration. In recent years, several well-publicized piping failures associate
26、d with injection pointshave been discussed at industry forums such as NACE andAPI(1)meetings. Upon discussion, it has become apparentthat in several cases, existing levels of attention directed atinjection point problems were not adequate to identify andmitigate problems. As a result, industry organ
27、izations havesponsored work to better define good practices arounddesign and integrity of injection systems. API has includedinspection of injection points in API 570.11.3 Each refinery injection situation is different in thedetails that determine success or failure. Because of thevariety and unique
28、ness of applications, this report is not tobe used or interpreted as a compilation ofrecommendations, because recommendations are outsidethe scope of technical committee reports. There is no intentto provide detail in this report for quantitative design of aninjection system. Rather, relevant issues
29、 are introducedand, when possible, considerations and practices that havebeen successfully used are given to aid the application ofgood engineering judgment on the part of the designer.Section 2: DefinitionsFor purposes of this report, the following definitions apply.Coinjectants or Carriers: Larger
30、 volume additions to theinjectant stream to increase the volume of the injectant, todilute the injectant, or otherwise facilitate injection andmixing.Injectant or Injectant Stream: The process additive, washwater, or the smaller process stream that is being added tothe other process stream at a mixi
31、ng point or injection point.Injection Point: A process mixing point at which there is asignificant potential for degradation of equipment integritydue to operation (or mis-operation) of the injection orchange in the process parameters at the mixing point. Allrefinery injection points are process mix
32、ing points. Thecriterion that separates injection points from other mixingpoints is one of predicted performance. Some refiningcompanies have identified injection points for specialattention during design, and they have specified additionalmonitoring and/or enhanced inspection during operation.This
33、was done in recognition of the fact that injections havecaused significant equipment integrity problems, and part ofthe reason was that their design and operation might havereceived insufficient scrutiny. Some injections have beeninstalled without close attention simply because they wereperceived as
34、 small add-ons with little potential for causing aproblem. Three major types of refinery injections addressedin this report are (1) process chemical injections, (2) waterwash injections, and (3) process mixing points.Mixed Stream: The combined injectant and receivingstreams downstream from the injec
35、tion point.Process Chemical Injection: Injection of relatively smallamounts of additives into refinery streams. Additivesinclude a limitless variety of inhibitors, anti-foulants, andprocess chemicals added either neat or diluted with water ora hydrocarbon as a carrier. Process chemical injections fa
36、llwithin the API 570 definition of injection points.Process Mixing Point: Points of joining of process streamsof differing composition and/or temperature. For purposesof this report, process mixing points where additional designattention, operating limits, and/or process monitoring areutilized to av
37、oid corrosion problems fall within the definitionof injection points. These may include mixing pointsinvolving water, steam, hydrocarbon vapors, hydrocarbonliquids, or solids. Process mixing points are referred to as“mixing tees” in API 570, and they are specifically excludedfrom the API 570 definit
38、ion of injection points.Receiving Stream or Main Process Stream: The streaminto which the injection is made.Small Connection: A small-diameter nipple or nipplecoupling of 500Area (in.2)NumnberReportedchemical process waterArea of maximumcorrosion is2 10 3Not Reported 14 233.5.6 Figure 6 summarizes d
39、ata on the actual locationof maximum injection point corrosion. The highestfrequency was reported to occur just downstream fromthe injection point on the same side of the pipe as theinjection point. But the maximum injection pointcorrosion was just as likely to be found at the oppositeside of the pi
40、pe or 90 from the injection point when thedata were taken together. Maximum losses werereported in a few cases in downstream elbows (ortees). The reason might be that inherent systemcorrosion not resulting from the injection was alsoreported as part of injection point corrosion.05101520250 1 2 3 4 5
41、 101520255075101502020Pipe Diameters (Main Process Line)NumberReportedMaximum IP Corrosion DistanceFarthest IP Corrosion DistanceMaximum IP Corrosion within 20 Pipe Diameters in 90% of cases.Farthest IP Corrosion within 20 Pipe Diameters in 70% of cases.NACE International10Figure 6: Location of Maxi
42、mum Injection Point CorrosionLegend: DS = downstream; OR = outside radius; IR = inside radius3.5.7 Reports by survey respondents on the apparentcauses of degradation associated with probleminjection points are summarized in Table 4. Mostdamage (96% of cases) was attributed to corrosion.Condensation,
43、 evaporation, and impingement were themost commonly reported causes of corrosion. Threeother cases included thermal fatigue, caustic stresscorrosion cracking, and mechanical failure of acompression fitting, respectively.0510152025UpstreamInjectionnozzleDSsamesideDSoppositesideDS90degtoInjectionDSelb
44、owORDSelbowIRDSelbowmiddleDSteeDSequipmentNumberReportedwaterprocesschemicalNACE International11Table 4: Causes of Injection Point CorrosionInjection Point TypeCorrosion CausesChemical Process WaterTotalCondensation 7 7 9 23Evaporation 2 2 6 10Impingement 5 5 10Inadequate mixing 1 2 - 3Amine hydroch
45、loride salts 2 - - 2High velocity 2 - - 2Temperature 1 - 1 2Alloy nonresistant 1 - - 1Concentrated chemical 1 - - 1Erosion corrosion - - 1 1Injection corrosive atprocess1-Partial neutralization ofacid1- 1Reaction - - 1 1O2in water - - 1 1Not reported 12 2 6 20Other degradation causes(SCC, thermal fa
46、tigue,mechanical failure)2-1 33.6 Inspection of Problem Injection Points3.6.1 65% of the cases reported using inspections tohelp manage injection point corrosion problems.3.6.2 The maximum injection point inspection intervalwhen reported was 48 months. Problem injectionpoints were inspected at least
47、 twice as frequently asthe remainder of the piping in 63% of the casesreported.3.7 Problem Injection Point Upgrading3.7.1 Table 5 summarizes the statistics on injectionpoint upgrades reported in the survey. 63% of theproblem injection points were physically upgraded tomanage the problem. Some respon
48、dents reporteddoing both upgrading and increasing inspectionfrequency.3.7.2 Changing materials of construction was the mostcommon upgrade reported. Next was upgrading theinjection type, which usually meant installation of aquill. In a significant number of cases, pipingconfiguration changes (i.e., m
49、oving the injection point),and actual process changes (i.e., eliminating theinjection) were also reported.3.7.3 The injector (usually a quill) was the mostcommon component reported to have beenmetallurgically upgraded. Upgrades to the material ofconstruction of the main process line were almost asfrequent. Most upgrades were to austenitic stainlesssteels. A significant number of upgrades to Ni-Cr-Moalloys were also reported.3.7.4 Respondents judged most upgrades assuccessful. In only one case (out of 75) was it reportedthat the upgrading did not successfull
