Overview of process plant piping sysetm maintenance ane repa


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Overview of process plant piping sysetm maintenance ane repa

  1. 1. Overview of Process Plant Piping System Maintenance and RepairParticipant’s Workbook
  2. 2. CONTACT INFORMATION ASME Headquarters 1-800-THE-ASME ASME Professional Development 1-800-THE-ASMEEastern Regional Office Southern Regional Office8996 Burke Lake Road - Suite L102 1950 Stemmons Freeway - SuiteBurke, VA 22015-1607 5037C703-978-5000 Dallas, TX 75207-3109800-221-5536 214-746-4900703-978-1157 (FAX) 800-445-2388 214-746-4902 (FAX)Midwest Regional Office1117 S. Milwaukee Ave. Western Regional OfficeBuilding B - Suite 13 119-C Paul DriveLibertyville, IL 60048-5258 San Rafael, CA 94903-2022847-680-5493 415-499-1148800-628-6437 800-624-9002847-680-6012 (FAX) 415-499-1338 (FAX)Northeast Regional Office326 Clock Tower Commons You can also find information onRoute 22 these courses and all of ASME,Brewster, NY 10509-9241 including ASME Professional914-279-6200 Development, the Vice President800-628-5981 of Professional Development,914-279-7765 (FAX) and other contacts at the ASME Web site...International Regional Office1-800-THE-ASME http://www.asme.org
  3. 3. Overview of Process Plant Piping System Maintenance and Repair Edited by: Vincent A. Carucci Carmagen Engineering, Inc. Copyright © 1999 by All Rights Reserved
  4. 4. TABLE OF CONTENTSPart 1: PARTICIPANT NOTES……………………………………….3Part 2: BACKGROUND MATERIAL…………………………………36I. Introduction ……………………………………………………..….. 37II. Inspection and Testing Practices ………………………....………40III. Inspection Frequency and Extent ……………………….………45IV. Evaluation and Analysis of Inspection Data ……..…….…….…49V. Repairs, Alterations, and Rerating ………………………..…..…55VI. Inspection of Buried Piping …………………………..…….…..…65VII. Summary …………………………………………….……….……68VIII. Suggested Reading ……………………...…………..………….69
  5. 5. Part 1:Participant Notes 3
  6. 6. Overview of Process Plant Piping System Maintenance and Repair1Notes: Course Outline • Introduction • General • Inspection and Testing Practices • Inspection Frequency and Extent • Evaluation and Analysis of Inspection Data • Repairs, Alterations, and Rerating • Inspection of Buried Piping • Closure 2Notes: 4
  7. 7. Scope of API 570 • Inspection, repair, alteration, rerating of in- service metallic piping systems • To be used by qualified organizations and individuals • Included fluid services: process fluids, hydrocarbons, similar flammable or toxic services 3Notes: Scope of API 570 (Cont.) • Excluded and optional piping systems – Hazardous services below threshold limits – Water, steam, steam-condensate, BFW, Category “D” services – Systems on movable structures governed by jurisdictions – Systems integral with mechanical devices – Internal piping – Plumbing and sewers – Size ≤ NPS 1/2 – Non-metallic or lined piping 4Notes: 5
  8. 8. Definitions • Alteration - Physical change affecting pressure containing capability or flexibility • Repair - Work to restore piping system to be suitable for design conditions • MAWP - Maximum permitted internal pressure for continuous operation at design temperature 5Notes: Definitions (Cont.) • Rerate - Change in design pressure, design temperature, or both • Piping Circuit - Pipe section exposed to similar corrosivity, with similar design conditions and material 6Notes: 6
  9. 9. Types of Pipe Deterioration • Injection points • Deadlegs • CUI • Soil-to-air interfaces • Service-specific and • Erosion and localized corrosion corrosion/erosion • Environmental • Corrosion under cracking linings and deposits • Fatigue cracking • Creep cracking • Brittle fracture • Freeze damage 7Notes: Typical Injection Point Circuit O ve rh ead L in e G re ate r of 3D or 1 2" * * In jectio n p oin t * * * O ve r hea d In jectio n p oint Co nde ns e rs D istilla tion pipin g cir cuit * T o we r * * = Typical T M L 8 Figure 1Notes: 7
  10. 10. Systems Susceptible to CUI • Areas exposed to: – Mist overspray from cooling water towers – Deluge systems – Steam vents – Process spills, moisture ingress, acid vapors • CS systems operating in range 25-250°F • CS systems in intermittent service over 250°F • Deadlegs and attachments protruding from insulation 9Notes: Systems Susceptible to CUI (Cont.) • Austenitic stainless steels operating in range 150-400°F • Vibrating systems with damaged insulation jacketing • Steam-traced systems with tracing leaks • Systems with deteriorated coatings and/or wrappings 10Notes: 8
  11. 11. Locations Susceptible to CUI• Penetrations/breaches in • Insulation termination points jacket • Jacket seams on top of• Damaged/missing horizontal piping or jacketing improperly lapped/sealed• Hardened, separated, or jacket missing caulking • Bulges or staining of• Piping low points in insulation or jacketing, or systems that have missing bands insulation breach • Carbon or low-alloy steel• Insulation plug locations components in high-alloy systems 11Notes: Inspection Types • Internal visual • Thickness measurement • External visual • Vibrating piping • Supplemental inspection – Radiography – Thermography – AET – UT 12Notes: 9
  12. 12. External Visual Inspection • Observations by non-inspectors • Scheduled inspections by qualified inspector and documented • Check for: – Leaks – Misalignment – Vibration – Support condition – Corrosion – Insulation condition – Paint condition – Unrecorded field – Incorrect components modifications or temporary repairs 13Notes: Thickness Measurement Locations (TMLs) • Specific inspection areas along piping circuit – Nature of TML varies by location – Selection considers potential for local corrosion and service-specific corrosion • Thickness monitoring at TMLs – TMLs distributed in circuit – More TMLs and more frequent monitoring based on situation 14Notes: 10
  13. 13. Thickness Measurement Locations (TMLs) (Cont.) • Test points - circles – Within TMLs Pipe Size Circle Diameter ≤ NPS 10 ≤ 2” > NPS 10 ≤ 3” – Thickness averaging • Mark TMLs for follow-up measurements 15Notes: TML Selection • More TMLs: – Leak has high risk potential – Higher corrosion rates – High potential for localized – Complex system corrosion – High CUI potential • Fewer TMLs: – Low risk if leak – Relatively non-corrosive – Long, straight piping service • No TMLs: – Extremely low risk if leak – Non-corrosive service 16Notes: 11
  14. 14. Thickness Measurement Methods • UT for pipe over NPS 1 • RT for pipe ≤ NPS 1 • Use appropriate UT procedures • Pit depth measurements 17Notes: Pressure Testing • Normally not part of routine inspections – Some jurisdictional exceptions • Done per ASME B31.3 • Normally a hydrotest • Special considerations for stainless steel piping 18Notes: 12
  15. 15. Other Inspections • Material verification and traceability • Valve inspection • Weld inspection • Flanged joint inspection 19Notes: Piping Service Classes Class Description 1 • Highest potential of immediate emergency if leak • Examples: – Flammable service that may auto-refrigerate – Pressurized services that may rapidly vaporize and form explosive mixture – H2S in gas stream (> 3 wt. %) – Anhydrous hydrogen chloride; HF – Pipe over or adjacent to water; over public throughways 2 • Services not in other classes • Includes most process unit piping and selected off-site piping 3 • Flammable services that do not significantly vaporize when leak • Services harmful to human tissue but located in remote areas 20Notes: 13
  16. 16. Inspection Intervals • By Owner-user or inspector based on: – Corrosion rate and remaining life calculations – Piping service classification – Applicable jurisdictional requirements – Judgment based on operating conditions, inspection history, current inspection results, conditions warranting supplemental inspections21Notes: Inspection Intervals (Cont.) • Maximum thickness measurement intervals shorter of: – Half remaining life (considers corrosion rate) – Maximum specified in API 570 • Review/adjust intervals as needed 22Notes: 14
  17. 17. Maximum Inspection Intervals Circuit Thickness Visual Type Measurements, years External, years Class 1 5 5 Class 2 10 5 Class 3 10 10 Injection points 3 By Class Soil-to-air interfaces - By Class 23Notes: Extent of Visual External Inspection • Bare piping – Assess condition of paint and coating systems – Check for external corrosion, other deterioration • Insulated piping – Assess insulation condition – Additional inspection if susceptible to CUI 24Notes: 15
  18. 18. CUI Inspection Considerations • Insulation damage at higher elevations may cause CUI at lower areas remote from damage • RT or insulation removal and VT normally required • Expand inspection as necessary • CUI inspection targets specified in API 570 • Systems that may be excluded – Remaining life over 10 years – Adequately protected against external corrosion 25Notes: CUI Inspection Targets Pipe Amount of Follow-up Amount of NDE at Class NDE or Insulation Suspect Areas on Piping Removal Where Within Susceptible Insulation Damaged Temperature Ranges 1 75% 50% 2 50% 33% 3 25% 10%26Notes: 16
  19. 19. Extent of Thickness Measurements • Obtain thickness readings on representative sampling of TMLs on each circuit • Include sampling data for various components and orientations in each circuit • Include TMLs with earliest renewal date based on prior inspection • More TMLs → more accurate prediction of next inspection date 27Notes: Extent of Other Inspections • Small-bore piping (SBP), ≤ NPS 2 – Primary process lines and Class 1 secondary lines: + Per all API 570 requirements – Classes 2 and 3 SBP + Inspection optional + Inspect deadlegs where corrosion expected • Secondary, auxiliary SBP – Inspection optional if associated with instruments or machinery – Consider classification and potential for cracking, corrosion, CUI 28Notes: 17
  20. 20. Extent of Other Inspections (Cont.) • Threaded connections – Inspection based on SBP and auxiliary piping requirements – Select TMLs that can be radiographed – Additional considerations if potentially subject to fatigue damage29Notes: Remaining Life Calculations tact − tmin • RL = CR Where: RL = Remaining life, years tact = Minimum measured thickness, in. (May average at test point) tmin = Minimum required thickness for location, in. Per B31.3 or detailed calculations.30Notes: 18
  21. 21. Remaining Life Calculations (Cont.) • RL for circuit based on shortest calculated RL • Determines – Inspection interval – Repair/replacement needs31Notes: Corrosion Rate Calculations • Long term and short term – Compare to determine which governs – Rationalize if significantly different t initial − t last • CR (LT) = ( years between last and initial inspection s) t previous − t last • CR (ST) = ( years between last and previous inspection s) 32Notes: 19
  22. 22. Corrosion Rate Estimation New Systems or Changed Service Conditions Determine using one of the following: • Data from other systems of similar material in comparable service • Estimated from Owner-user’s experience or from published data on systems in comparable service • Thickness measurements – After maximum 3 months service – Consider using corrosion coupons or probes to help establish measurement timing – Repeat until establish CR 33Notes: Example 1 • Pipe = NPS 16, tinitial = 0.375” • Service = Gas with 3.5% H2S • treq = 0.28 • tmeas = 0.36, 0.32, 0.33, 0.34, 0.32 • In operation 10 years34Notes: 20
  23. 23. Example 1 (Cont.) • Service → Class 1 → 5-year interval 0.375 − 0.32 • CR/Maximum = = 5.5 x 10-3 in./yr. 10 = (0.32 - 0.28) = 0.04 in. • CA/Available 0.04 • Maximum Interval = = 3.6 years 2 x 5.5 x 10 −3 < 5 years ∴ Maximum thickness measurement interval = 3.6 years 35Notes: MAWP Determination • Based on applicable code (ASME B31.3) • MAWP of system based on weakest component (e.g., pipe, flanges, valves, fittings, etc.) • Unknown material - Calculate based on lowest grade material and joint efficiency of code • MAWP calculation based on: – Actual measured thickness – Double estimated corrosion until next inspection – Allowances needed for other loadings36Notes: 21
  24. 24. Example 2 • DP = 500 psig, DT = 400°F • Pipe = NPS 16, STD weight, A-106 Gr. B, OD = 16 in. • S = 20,000 psi, E = 1.0 • tmeas = 0.32 in. • CR = 0.01 in./yr. • Next planned inspection - 5 years 37Notes: Example 2 (Cont.) • Estimated thinning until next inspection - 5 x 0.01 = 0.05 in. MAWP = 2 S Et/D = 2 x 20,000 x 1 x [0.32 - 2 x 0.05]/16 = 550 psig > 500 psig ∴ OK38Notes: 22
  25. 25. Example 3 • Same system as Example 2 • Change next planned inspection to 7 years • Estimated thinning until next inspection - 7 x 0.01 = 0.07 in. MAWP = 2 S Et/D = 2 x 20,000 x 1.0 [0.32 - 2 x 0.07]/16 = 450 psig 39Notes: Example 3 (Cont.) ∴ Not acceptable. Must either: – Reduce inspection interval – Confirm maximum operating pressure will not exceed 450 psig before 7th year – Renew pipe before 7th year 40Notes: 23
  26. 26. Minimum Required Thickness Determination • Based on: – Pressure, mechanical, structural considerations – Appropriate design formulae and code allowable stress • Consider general and localized corrosion • Consider increasing calculated value if high potential failure consequences – Unanticipated/unknown loads – Undiscovered metal loss – Resistance to normal abuse 41Notes: Local Thin Area Evaluation Alternatives • ASME B31.G criteria • Numerical stress analysis and ASME Section VIII, Division 2, Appendix 4 criteria – Code allowable stress but < 2/3 SMYS at temperature – Additional considerations if temperature in creep range • Additional considerations if corroded longitudinal weld and E < 1.0 – Weld includes base metal each side of weld within greater of 1 in. or twice measured thickness • Additional considerations for corroded pipe caps 42Notes: 24
  27. 27. Piping Stress Analysis • Piping to be supported and restrained to: – Safely carry weight – Have sufficient flexibility for thermal movement – Not vibrate excessively • Not normally part of inspection, but: – Prior analyses identify high stress locations – Compare predicted thermal movements with actual – Analysis often needed to solve vibration problems • New analyses may be needed if conditions change or system modified43Notes: Recordkeeping Requirements • Owner-user responsibility • Permanent/progressive records required • To include: – Service – Classification – Identification – Inspection interval – Inspection and test details – Results of thickness measurements and responsible individual and other inspections and tests done – Repairs (temporary and – Pertinent design information and permanent), alterations, piping drawings reratings done – Maintenance and other – Date and results of external events affecting system inspections integrity 44Notes: 25
  28. 28. Authorization and Approval of Repairs, Alterations, and Rerating • Authorization – Work by appropriate repair organization – Authorized by inspector before starting – Piping engineer must approve alterations first – Inspector may designate hold points • Approval – Design, execution, materials, welding procedures, examination, testing to be approved by inspector or piping engineer – Owner-user to approve on-stream welding – Consult piping engineer before repairing service-induced cracks – Inspector to approve all repairs/alterations at hold points and after completion45Notes: Welded Repairs • Follow principles of ASME B31.3 or original construction code • Temporary repairs – Full encirclement split sleeve or box-type enclosure (generally not for cracks) – Fillet welded split coupling or lap patch if: • Localized deterioration • SMYS < 40,000 psi • Material matches base metal unless otherwise approved 46Notes: 26
  29. 29. Welded Repairs (Cont.) – May be welded onstream with proper design, inspection, procedures – Replace with permanent repair next opportunity + May extend if approved/documented by piping engineer + Owner-user establishes appropriate procedures • Defect repair – Remove defect to sound metal – Deposit weld metal47Notes: Welded Repairs (Cont.) • Locally corroded areas – Remove surface irregularities and contamination – Deposit weld metal • Remove/replace cylindrical section • Insert patch – Full-penetration weld – 100% RT or UT for Class 1 or 2 systems – Rounded corners, 1 in. minimum radius • NDE after welding (e.g., PT, MT, etc.)48Notes: 27
  30. 30. Typical Welded Repairs ts t MT or PT See Detail 1 C L See Detail 2 LEGEND: ts = Sleeve Thickness t = Pipe Thickness Field Weld Maximum Gap C L F ield Weld ts 1/8" ts Backing Strip t Detail " 1 " Detail 2 Fillet Girth Weld Butt Weld for Seam Figure 2 Split Sleeve49Notes: Typical Welded Repairs (Cont.) Lifting Lugs C L Split Box and Typ. End Plates on C L Typ. C L New Containment Box End Plate, (2) Required C (2) 3/4" - 3000# Couplings L Typ. Typ. Figure 3 Complete-Encirclement Box 50Notes: 28
  31. 31. Typical Welded Repairs (Cont.) Figure 4 Partial Box51Notes: Typical Welded Repairs (Cont.) See Detail 1 Maximum Gap LEGEND: t p = Sleeve Thickness tp t = Pipe Thickness 1/8" t Detail " 1 " Figure 5 Lap Patch 52Notes: 29
  32. 32. Non-Welded Repairs • Temporary onstream repairs of locally thinned sections, circumferential linear defects, flange leaks, etc. • Bolted leak clamp or box • Design must consider: – Control of axial thrust load if piping may separate – Effect of clamping forces on pipe component – Need for and properties of leak sealing fluids53Notes: Typical Non-Welded Repairs Figure 6 Flange Clamp 54Notes: 30
  33. 33. Typical Non-Welded Repairs (Cont.) Figure 7 Bolted Box55Notes: Welding and Hot Tapping Requirements • Per principles of ASME B31.3 or original construction code • Procedures, qualifications, recordkeeping • Hot tapping (or other onstream welding) – Per API Publication 2201 – Detailed inspection, design, installation, safety procedures required 56Notes: 31
  34. 34. Welding and Hot Tapping Requirements (Cont.) • Preheat – Per applicable code and welding procedure – May be alternative to PWHT • PWHT – Per applicable code and welding procedure – May be needed due to service – Local PWHT may be possible 57Notes: Welding and Hot Tapping Requirements (Cont.) • Design – Full-penetration groove welds for butt joints – New and replacement components per applicable code – Special design considerations for fillet-welded patches • Materials • NDE 58Notes: 32
  35. 35. Pressure Testing • Done if practical and deemed necessary by inspector • Normally required after alterations and major repairs • May use NDE instead after consultation with inspector and piping engineer59Notes: Pressure Testing (Cont.) • If not practical to pressure test final closure weld: – Pressure test new or replacement piping – Closure weld is full-penetration butt weld between WN flange and standard pipe component, or straight pipe sections of equal diameter and thickness, axially aligned, equivalent materials. SO and SW flange alternatives identified – 100% RT or UT – MT or PT root pass and completed weld for butt- welds, and on completed weld for fillet welds 60Notes: 33
  36. 36. Rerating Requirements to be met: • Design calculations • Must be pressure tested • Inspection verifies unless already done at condition and CA provided sufficient pressure • Safety valves reset • Acceptable to inspector or piping engineer • All system components acceptable • Piping flexibility adequate for design temperature • Records updated changes • Meet original or latest • Temperature decrease code justified by impact test results 61Notes: Inspection of Buried Piping • Significant external corrosion possible • Inspection hindered by inaccessibility • Above-grade visual surveillance for leak indications • Close-interval potential survey • Pipe coating holiday survey • Soil resistivity • Cathodic protection monitoring 62Notes: 34
  37. 37. Other Requirements for Buried Pipe • Inspection Methods • Intervals • Extent • Repair Methods63Notes: Summary • Inspection, repair, alteration, rerating of in- service piping systems are normal activities • Requirements and procedures are necessary to maintain piping system integrity • API 570 is industry standard to be used 64Notes: 35
  38. 38. Part 2:Background Material 36
  39. 39. I. IntroductionThe structural integrity of piping systems must be maintained after they havebeen placed into service so that they will provide safe, reliable, long-termoperation. Therefore, existing piping systems require periodic inspection todetermine their current condition and permit evaluation of their structural integrityto permit future operation. Should unacceptable deterioration or flaws beidentified, pipe repairs may be required. Existing piping systems might alsorequire alterations or rerating to accommodate new operational needs (or toaccommodate deterioration that cannot or will not be repaired).Process plants must adopt and follow established procedures for the inspection,repair, alteration, and rerating of piping systems after they have been placed intoservice. API 570, “Piping Inspection Code – Inspection, Repair, Alteration, andRerating of In-Service Piping Systems,” provides the basic procedures to befollowed by process plants. This course is based on API 570.Scope of API 570API 570 was developed for the petroleum refining and chemical processindustries. But since most of its requirements have broad applicability, it may beused for any piping system. It must be used by organizations that maintain orhave access to an authorized inspection agency, a repair organization, andtechnically qualified piping engineers, inspectors, and examiners (as defined inAPI 570).While API 570 applies to all petroleum refineries and chemical plants, its scopedefines both specific included fluid services, and excluded and optional pipingsystems. Thus, API 570 requirements do not necessarily have to be applied toevery piping system in a refinery or chemical plant.Included Fluid ServiceUnless identified by API 570 as being an excluded or optional system, API 570applies to piping systems for process fluids, hydrocarbons, and similar flammableor toxic fluid services. Examples of these are the following:• Raw, intermediate, and finished petroleum or chemical products.• Catalyst lines.• Hydrogen, natural gas, fuel gas, and flare systems.• Sour water and hazardous waste streams or chemicals above threshold limits, as defined by jurisdictional regulations. 37
  40. 40. Excluded and Optional Piping SystemsAPI 570 permits the following fluid services and classes to be excluded from itsspecific requirements. This is done to focus attention (with associated manpowerand budget expenditures) on applications that would have the most significantconsequences should a pipe failure occur. However, any of these excludedsystems may be included in a plant’s API 570 program at the option of the owner.• Fluid services that are excluded or optional include the following: - Hazardous fluid services below threshold limits, as defined by jurisdictional regulatories. - Water (including fire protection systems), steam, steam condensate, boiler feedwater, and Category D fluid services (as defined by ASME B31.3).• Classes of piping systems that are excluded or optional are as follows: - Piping systems on movable structures covered by jurisdictional regulation (e.g., piping systems on trucks, ships, barges, etc.). - Piping systems that are an integral part or component of rotating or reciprocating mechanical devices (e.g., pumps, compressors, etc.) where the primary design considerations and/or stresses are derived from the functional requirements of the device. - Internal piping or tubing of fired heaters or boilers. - Pressure vessels, heaters, furnaces, heat exchangers, and the fluid handling or processing equipment (including internal piping and connections for external piping). - Plumbing, sanitary sewers, process waste sewers, and storm sewers. - Piping or tubing with an outside diameter not exceeding that of NPS ½ - Nonmetallic piping and polymeric or glass-lined piping.API 570 permits these services and systems to be excluded from its specificrequirements to focus inspection, engineering, and maintenance resources onareas that would have the largest potential effect should leakage or failure occur.However, this should not be interpreted that these “excludable or optional”systems should be completely ignored. Furthermore, the consequences of afailure in some of these systems could be dangerous or unacceptable inparticular circumstances. Therefore, owners may wish to include some of theseservices or systems in their API 570 program in all respects, and differentrequirements and procedures may be used for other services or systems. Forexample: 38
  41. 41. • The failure of a high pressure steam or boiler feedwater system could have significant personnel safety consequences. An owner might include such services in his API 570 program.• The failure of an NPS ½ vent connection in an “included” fluid service could have significant personnel safety and economic consequences. An owner might wish to include such systems in his API 570 program.DefinitionsAPI 570 contains definitions of technical terms that are used in the standard.The following are several of these terms used in this course:• Alteration A physical change in any component that has design implications affecting the pressure containing capability or flexibility of a piping system beyond the scope of its design.• Repair The work necessary to restore a piping system to a condition suitable for safe operation at the design conditions.• MAWP The maximum internal pressure permitted in the piping system for continued operation at the most severe condition of coincident internal or external pressure and temperature (minimum or maximum) expected during service.• Rerate A change in either or both the design temperature or the maximum allowable working pressure.• Piping Circuit A section of piping that has all points exposed to an environment of similar corrosivity and that is of similar design conditions and construction material. 39
  42. 42. II. Inspection and Testing PracticesTypes of Pipe DeteriorationThe piping inspection techniques that are used must consider the type(s) ofdeterioration that might be found in particular services or locations. The followingtypes and areas of deterioration might occur:• Injection point corrosion • Deadleg corrosion• Corrosion under insulation (CUI) • Soil-to-air (S/A) interfaces• Service specific and localized • Erosion and corrosion/erosion corrosion• Environmental cracking • Corrosion beneath linings and deposits• Fatigue cracking • Creep cracking• Brittle fractures • Freeze damageSeveral of these items are briefly discussed below.Injection PointsPortions of a piping system that are in the vicinity of injection points may besubject to accelerated or localized corrosion. Such regions should be treated asseparate inspection circuits and be thoroughly inspected periodically. API 570provides suggested lengths of pipe upstream and downstream of the injectionpoint that should be included in the injection point circuit. Figure 1 illustrates atypical injection point circuit. 40
  43. 43. Overhead Line Greater of 3D or 12" * * Injection point * * * Overhead Injection point Condensers Distillation piping circuit * Tower * * = Typical TML Typical Injection Point Circuit Figure 1Systems Susceptible to CUIPiping systems may be subject to external corrosion under insulation (CUI) insituations where the integrity of the insulation system has been compromised.Therefore, special inspection attention should be paid to situations where CUImight be a concern. The following highlights areas and types of piping systemsthat might be more prone to CUI:• Areas exposed to : - Mist overspray from cooling towers - Steam vents - Deluge systems - Process spills, moisture ingress, acid vapors• Carbon steel piping operating in the range 25°F to 250°F.• Carbon steel piping operating intermittently above 250°F.• Deadlegs or other attachments protruding from insulation and at a different temperature than the active line.• Austenitic stainless steel piping operating between 150°F and 400°F.• Vibrating piping that may damage insulation jacketing. 41
  44. 44. • Steam traced piping that may have leaking tracers.• Piping with deteriorated coating or wrapping.Locations Susceptible to CUIFor systems that are susceptible to CUI, inspection efforts should be focused firston the most likely locations where corrosion might be found. The followingsummarizes such locations:• Penetrations through or breaches in the insulation jacketing.• Insulation terminations at flanges and other piping components.• Damaged or missing insulation jacketing.• Insulation jacket seams located on the top of horizontal piping.• Improperly lapped or sealed insulation jacketing.• Insulation termination points in vertical pipe.• Caulking that has hardened, separated, or is missing.• Bulged or stained insulation or jacketing, or missing bands.• Piping low points in systems that have a breach in the insulation system.• Carbon or low-alloy steel flanges, bolting, or other components under insulation.Types of InspectionThe particular type of inspection that is used depends on the details of the pipingsystem, the service, and the type(s) of deterioration expected.• Internal Visual. Only applicable for large diameter piping, by using remote inspection techniques, or at local areas that are accessible at openings.• Thickness Measurement. Used to determine the extent of pipe thinning and may be done with the system either in or out of service.• External Visual. Done to determine the condition of the pipe exterior, insulation, paint and coating systems. Also used to check for misalignment, leakage, or vibration. 42
  45. 45. • Vibrating Piping. Excessive piping vibration should be reported to engineering for evaluation. Excessive pipe vibration or other line movement could result in leakage at flanged joints or threaded connections, or a fatigue failure. It should be remembered, however, that some amount of pipe vibration is normal.• Supplemental Inspection. Other inspection methods may also be used based on the specific situation. These include radiography, thermography, acoustic emission testing (AET), or ultrasonic thickness surveys.Thickness Measurement Locations (TMLs)TMLs are the specific areas in a piping circuit where inspections are made. TMLlocations and their number are selected based on the potential for localized orservice-specific corrosion and the consequences should a failure occur.Pipe wall thicknesses are measured at “test points” within the TMLs, and thethickness readings may be averaged to arrive at a composite thickness readingat the TML. A test point is a circle having the following maximum diameters. Pipe Size Circle Diameter ≤ NPS 10 ≤ 2” > NPS 10 ≤ 3”TML SelectionThe number and location of the TMLs must be based on the expected types andpatterns of corrosion expected in the particular service. More TMLs• Leak has high potential to cause damage • Higher corrosion rates• High potential for localized corrosion• High CUI potential • Complex system Fewer TMLs• Low risk if leak • Relatively non-corrosive service• Large, straight piping No TMLs• Extremely low risk if leak• Non-corrosive service 43
  46. 46. Thickness Measurement MethodsThe following thickness measurement methods are normally used.• UT for pipe over NPS 1• RT for pipe ≤ NPS 1• Pit depth measurements for pitted areas using pit depth gaugesIn all areas, appropriate inspection procedures must be used to obtain reliableresults.Pressure TestingExcept where local jurisdictions require it, pressure tests are not normally doneas part of a routine inspection. When pressure tests are done (e.g., afteralterations) they should be based on the following:• Must meet ASME B31.3 requirements.• Test fluid must be water unless this would have adverse consequences (e.g., freezing, process contamination, water disposal problem).• Stainless steel piping requires special attention (e.g., potable water and blown dry).Other InspectionsOther inspections may also be required.• Material verification and traceability. When alterations or repairs are made on low or high-alloy piping systems, the inspector must ensure that the correct materials are used.• Valve inspection. Inspect valves for any unusual corrosion patterns or thinning. Valves in high temperature cyclic service might be subject to fatigue cracking. All subsequent pressure tests should be per API 598.• Weld inspection. Welds are always inspected as part of new construction, repairs, and alterations. They are also sometimes inspected for deterioration as part of the normal inspection activity if problems are suspected.• Flanged joint inspection. Flanged joints should be examined for signs of leakage. The cause of any leakage found should be determined. Special attention should be paid to flanges that have been clamped and pumped with sealant to stop leaks since the bolting might corrode and/or crack with time. 44
  47. 47. III. Inspection Frequency and ExtentPiping Service ClassesProcess piping systems are categorized into different classes to help identifysystems where greater inspection efforts should be made. Greater effort shouldbe devoted to systems where there would be more significant safety orenvironmental impact should a leak occur. Class Description 1 • Highest potential of immediate emergency if leak. • Examples: - Flammable service that may auto-refrigerate - Pressurized services that may rapidly vaporize and form explosive mixture - H2S in gas stream (> 3 wt. %) - Anhydrous hydrogen chloride; HF - Pipe over or adjacent to water; over public throughways 2 • Services not in other classes • Includes most process unit piping and selected off-site piping 3 • Flammable services that do not significantly vaporize when leak • Services harmful to human tissue but located in remote areasInspection IntervalsInspection intervals are determined based on the following:• Corrosion rate and remaining life calculations• Piping service classification• Jurisdictional requirements• Judgment of inspector and piping engineer based on experienceThe maximum interval between thickness measurements should be the lower ofhalf the remaining life or what is specified in the following table: 45
  48. 48. Thickness Circuit Type Measurements, Years Visual External, YearsClass 1 5 5Class 2 10 5Class 3 10 10Injection Points 3 By ClassSoil-to-Air Interfaces - By ClassThe inspection intervals must be reviewed and adjusted as necessary based onthe results of the thickness measurements that are made.Extent of Visual External InspectionExternal visual inspection should also be conducted at the same maximumintervals as are used for thickness measurements.Bare piping should be checked for:• The condition of paint and coating systems• External corrosion• Other deterioration (e.g., leakage, damaged supports, etc.)Insulated piping should be checked for:• Damaged insulation or jacketing• Signs of CUI for systems that might be subject to thisCUI Inspection ConsiderationsAfter external visual inspection, additional inspection must be done for systemspotentially subject to CUI. The additional inspection required depends on thepipe class and whether the insulation is damaged, as specified in the followingtable: 46
  49. 49. Amount of follow-up NDE or Amount of NDE at suspect areas Pipe insulation removal where on piping within susceptible Class insulation is damaged temperature ranges 1 75% 50% 2 50% 33% 3 25% 10%The inspection may be expanded as necessary based on the initial results.Systems with a remaining life of over 10 years, or that are adequately protectedagainst external corrosion, need not be included in the CUI inspection program.However, the condition of the insulation system should be periodically checkedby operating personnel to identify signs of deterioration.Extent of Thickness MeasurementsEach thickness measurement inspection must obtain thickness readings from arepresentative sampling of TMLs in each circuit. The sampling should includedata from the various components in the circuit and in different orientations (i.e.,horizontal and vertical). TMLs with the shortest remaining life must be included.The inspection should obtain as many measurements as necessary to accuratelyassess the condition of the piping system.Extent of Other InspectionsOther inspections are also required to adequately assess the condition of apiping system.Small-Bore Piping (SBP) [ ≤ NPS 2]Inspect SBP per the following: Service Class Inspection Requirement Primary Process Piping All Inspect per all requirements of API 570Secondary Process Piping 1 Inspect per all requirements of API 570 2&3 Inspection is optional Deadlegs 2&3 Inspect where corrosion was experienced or is anticipatedNote that while inspection is optional for Class 2 or 3 SBP, the owner mustalways consider the potential consequence should a leak develop in SBP thathas not been inspected. 47
  50. 50. Secondary, Auxiliary SBPInspection is optional for SBP associated with instruments and machinery.Consider the following in determining whether inspection will be done:• Piping system classification• Potential for environmental or fatigue cracking• Potential for corrosion based on experience with adjacent primary systems• Potential for CUIThreaded ConnectionsThreaded connections are inspected based on the same criteria as other SBP.TMLs for threaded connections should only include those that can beradiographed during scheduled inspections.Threaded connections that might be subject to fatigue damage (e.g., thoseassociated with machinery systems) should be periodically assessed.Consideration may be given to using a thicker wall, adding bracing, and/or usinga welded connection in situations where the potential fatigue damage is aconcern. 48
  51. 51. IV. Evaluation and Analysis of Inspection DataRemaining Life CalculationsThe remaining life of piping systems must be calculated based on the corrosionrate using the following: Calculation Equation Remaining Life, RL tact = Actual minimum thickness, in t act − t min inches, determined at inspection corrosion rate tmin = Minimum required thickness, in inches, for the limiting section or zone Corrosion Rate, CR (LT) t initial − t last D1 = Time (years) between last and D1 initial (nominal) inspections Corrosion Rate, CR (ST) t previousl − t last D2 = Time (years) between last and D2 previous inspectionsThe long term and short term corrosion rates should be compared and the highervalue used in the remaining life calculations. If there is a significant differencebetween the two corrosion rates, further evaluations should be made in anattempt to determine the cause. The remaining life of the circuit should be basedon the shortest calculated remaining life.Corrosion Rate EstimationThe expected corrosion rate must be estimated for new piping systems or forsystems whose service has been changed. One of the following methods mustbe used to determine the probable corrosion rate.• Data collected from other piping systems fabricated of similar material and in comparable service.• Estimate based on the owner-user’s experience or from published data for similar material in comparable service.• Make initial thickness measurements after no more than three months of service. Corrosion coupons or probes may be useful to help determine when thickness measurements should be made. Make additional thickness measurements as necessary until the corrosion rate is determined. 49
  52. 52. Example 1 - Inspection Interval DeterminationAn NPS 16 piping system has been in operation for 10 years and has been takenout of service for its first thorough inspection. The following information is given:• Pipe service - Gas with 3.5% H2S• Minimum required thickness - 0.28 in.• Originally installed thickness - 0.375 in.• Thicknesses measured at five locations: 0.36, 0.32, 0.33, 0.34, 0.32Based on the information provided, what maximum thickness measurementinterval should be used for this system?Solution:The pipe service places this system into Class I. Therefore, the maximuminterval cannot be more than 5 years based only on the service. Now check theremaining life criterion. 0.375 − 0.32CR/Maximum = = 5.5 x 10-3 in./yr. 10Available corrosion allowance = (0.32 - 0.28) = 0.04 in. 0.04Maximum Interval = = 3.6 years < 5 years 2 x 5.5 x 10 −3∴ Maximum thickness measurement interval is 3.6 years.MAWP DeterminationThe MAWP of a piping system must be determined based on the requirements ofthe applicable piping code (i.e., ASME B31.3 in the case of process plant pipingsystems). The MAWP of the system is that of the weakest component within thesystem. Thus, in addition to the pipe itself, all other system components must beconsidered (e.g., flanges, valves, etc.). If the pipe material is unknown, theMAWP calculations must be based on the lowest grade (i.e., weakest) materialand lowest weld joint efficiency that would be permitted by the code.The MAWP calculation is based on:• The actual thicknesses determined by inspection.• Double the estimated corrosion loss until the next inspection is done.• Additional allowances that might be necessary in specific cases to account for applied loadings other than pressure.The following examples illustrate calculation of the MAWP. Note that in bothcases, only the pipe thickness is considered. 50
  53. 53. Example 2 – MAWP DeterminationDesign Pressure 500 psigDesign Temperature 400°FPipe Material A 106 Gr. BPipe Size NPS 16Allowable Stress 20,000 psi (from B31.3)Longitudinal Weld Efficiency 1.0 (A 106 Gr. B is seamless pipe)Thickness Measured During Inspection 0.32 in.Observed Corrosion Rate 0.01 in./yearNext Planned Inspection 5 yearsEstimated Thinning Until Next Inspection 5 x 0.01 = 0.05 in. 2 S EtMAWP = (from B31.3) D 2 x 20,000 x 1 x (0.32 − 2 x 0.05 )MAWP = 16MAWP = 550 psig > 500 psigSince the MAWP exceeds the system design pressure, the system may remainin service at the design pressure without repairs, replacements, or rerating. 51
  54. 54. Example 3 – Check Increased Inspection IntervalFor the same system as in Example 1, determine if the inspection interval can beincreased to seven years.Estimated thinning until next inspection = 7 x 0.01 = 0.07 in. 2 S EtMAWP = (from B31.3) D 2 x 20,000 x 1 x (0.32 − 2 x 0.07 )MAWP = 16MAWP = 450 psigThe MAWP is less than the design pressure. Therefore, either the inspectioninterval must be reduced, the operating pressure must not exceed 450 psig, orthe pipe must be repaired or replaced. 52
  55. 55. Minimum Required Thickness DeterminationThe minimum required thickness of a piping system (i.e., the retirementthickness) must be determined considering all applicable design loads. Thedesign pressure of the system will normally govern the minimum requiredthickness. However, local loading conditions (e.g., wind or earthquake, valveweights, local thermal displacement stresses, etc.) might govern the minimumrequired thickness in particular situations. Both general and localized corrosionmust be considered.In cases where there are significant safety or economic loss consequencesshould a failure occur, it is prudent to increase the minimum required thicknessabove the calculated value. This additional allowance is meant to account forunanticipated or unknown loads, undiscovered metal loss, tolerance in thethickness measurements, and resistance to normal abuse.In all cases, the normal code design formulas and allowable stresses must beused.Local Thin Area EvaluationLocal areas of a pipe may have thinned much more than the surrounding region.A conservative evaluation approach for such regions is to consider the locallycorroded region in isolation and determine the minimum thickness there. If thisapproach produces an acceptable MAWP, then there is no need to go further.However, if the resulting MAWP is not acceptable, then a more detailedevaluation approach using one of the following methods may be used.• ASME B31.G criteria. This simplified approach considers the maximum depth and length of the locally thin area, the pipe diameter, and nominal thickness to determine whether the thin area is acceptable. It intrinsically accounts for the additional strength that the surrounding uncorroded pipe provides to the thin area.• ASME Section VIII, Division 2, Appendix 4 criteria. This is a detailed numerical stress analysis approach that permits a more exact calculation and evaluation of the local stresses. The basic code allowable stress (rather than the Division 2 allowable stress) is used in this analysis, but not less than 2/3 of the specified minimum yield stress (SMYS). Additional considerations are required if the design temperature is in the creep range of the material.• Weld joint efficiency considerations. If the pipe has a longitudinal weld seam and its joint efficiency is less than one, the proximity of a thinned area to the weld is relevant. 53
  56. 56. - If the thinned area is more than the larger of 1 inch or twice the measured thickness away from the weld, then weld joint efficiency does not need to be considered. - If the thinned area is closer to the weld, then weld joint efficiency must be considered.• If a pipe cap is corroded, the location of the corrosion is relevant (i.e., in the knuckle region or central portion). The knuckle region of a cap requires a larger minimum thickness than the central portion.Piping Stress AnalysisPerforming a piping stress analysis is not normally a part of inspection andmaintenance. However, stress analysis considerations must still be kept in mind.• The pipe must be adequately supported to carry its weight. Locations where supports have become damaged or are otherwise ineffective should be identified for further evaluation or repair.• Adequate flexibility to accommodate thermal displacements must be provided. Identify situations where thermal expansion might be restricted (e.g., due to interference by adjacent items).• The pipe must not vibrate excessively, since this could cause leakage at flanged joints and threaded connections, or cause a fatigue failure.• A new stress analysis may be required if the design conditions are changed (e.g., due to equipment rerate) or if the system is modified (e.g., adding a new equipment item with associated piping to the system).Recordkeeping RequirementsThe owner-user is responsible for maintaining permanent and progressiverecords for all piping systems covered by API 570. These records form the basisfor developing a cost-effective inspection and maintenance program. Therecords must include the following information:• Service • Classification• Identification • Inspection interval• Inspection and test details and • Results of thickness measurements responsible individual and other inspections and tests done• Repairs (temporary and permanent), • Pertinent design information and alterations, reratings done piping drawings• Maintenance activities and other • Date and results of external events affecting system integrity inspection 54
  57. 57. V. Repairs, Alterations, and ReratingIn all cases, repairs and alterations must meet ASME B31.3 requirements.Authorization and ApprovalAll repairs and alternations must be done by a qualified repair organization(defined in API 570) and must be authorized by the inspector before beginning.Alterations must also be approved by a qualified piping engineer. The inspectormay designate hold points during repairs and alterations to permit sufficient timefor inspection.Additional approvals are required as follows:• The inspector or piping engineer must approve the design, execution, materials, welding procedures, examination, and testing.• The owner-user must approve all on-stream welding.• The piping engineer should be consulted prior to weld repair of any cracks that occurred in-service. The purpose of this is to attempt to identify the cause of the crack and correct it.• The inspector must approve all repairs and alterations at the designated hold points and at completion of the work.Welded RepairsWelded repairs are preferably done while the piping system is out of service.However, it may be possible to make weld repairs while the piping system is inoperation in particular situations provided appropriate inspections, precautions,and hot work permit procedures are used. API 570 does not distinguish betweenshut down and on-stream repairs with respect to the specified requirements, andthe owner must develop appropriate on-stream repair procedures.API 570 recognizes that it may be necessary to temporarily repair a pipingsystem to permit its continued operation as fast as possible. Thus, a distinctionis made between temporary and permanent repairs. 55
  58. 58. Temporary Repairs• A full encirclement welded split sleeve or a box-type enclosure may be installed over the damaged or corroded area (See Figures 2 through 4). The sleeve or box must be welded to the pipe at locations that are thick enough to remain intact during welding. A piping engineer must design these repairs. This method will typically not be used to repair longitudinal cracks in the pipe wall unless the piping engineer is convinced that the crack will not propagate from under the repair.• A fillet-welded split coupling or a lap patch may be used to repair localized deterioration (e.g., pitting or pinholes) if the SMYS ≤ 40,000 psi (See Figure 5).Temporary repairs should be removed and replaced with permanent repairs atthe next available maintenance opportunity. However, temporary repairs mayremain longer if the piping engineer approves this and documents it. In mostsituations, temporary repairs should generally be designed as if they will remaininstalled for a long time. 56
  59. 59. tst MT or PT See Detail 1 C L See Detail 2 LEGEND: ts = Sleeve Thickness t = Pipe Thickness Field WeldMaximum Gap C L Field Weld ts1/8" ts Backing Strip t Detail " 1 " Detail 2 Fillet Girth Weld Butt Weld for Seam Welded Split Sleeve Figure 2 57
  60. 60. Lifting Lugs C L Split Box and Typ. End Plates on C L Typ. C L New Containment Box End Plate, (2) Required C (2) 3/4" - 3000# Couplings LTyp. Typ. Complete-Encirclement Box Figure 3 Partial Box Figure 4 58
  61. 61. See Detail 1 Maximum Gap LEGEND: tp = Sleeve Thickness tp t = Pipe Thickness 1/8" t Detail " 1 " Lap Patch Figure 5Permanent Repairs• A relatively small defect may be repaired by completely removing it and then filling the resulting groove with weld metal.• Locally corroded areas may be repaired by first removing any surface irregularities and contamination, and then restoring the thickness with weld metal. This approach is only practical for relatively small areas.• If the system can be taken out of service, a cylindrical section of pipe that contains the defective area can be removed and replaced. 59
  62. 62. • An insert patch (i.e., flush patch) may be used as a repair if: - Full penetration groove welds are used. - The welds are 100% radiographed or ultrasonically examined for Class 1 or 2 piping systems. - The patches have rounded corners with a 1 inch minimum radius. Care must be taken to ensure that insert patches conform to the pipe curvature to avoid local geometric discontinuities that could act as stress concentration points.• In all cases, appropriate NDE should be done of the final welds to ensure that they are high quality. Butt welds will typically be 100% radiographically (RT) or ultrasonically (UT) examined, along with either liquid penetrant (PT) or magnetic particle (MT) examination. Other welds will typically be PT or MT examined.Non-Welded RepairsNon-welded repairs may be used to temporarily repair a locally damaged portionof a pipe or piping component while the system remains on-stream (or possiblydepressured but not gas-freed and cleaned). This approach may be used forlocally thinned sections or linear defects (either partially or completely throughthe pipe thickness), or leaking flanges.Non-welded repairs typically employ a bolted clamp or box which encompassesthe damaged component (See Figures 6 and 7). The design of the clamp or boxmust be adequate for the pressure thrust force from the damaged pipe if there isconcern that the pipe will completely separate at the area of deterioration. Thepipe must also have adequate thickness at the clamp or box attachment points towithstand the applied bolting force needed to hold the clamp in place.Bolted clamps or boxes will often require injection of a leak sealing fluid toprovide a tight seal at the pipe or component interface. The sealant must becompatible with the service fluid and design conditions. 60
  63. 63. Bolted Flange Clamp Figure 6Courtesy of Plidco International, Inc. Bolted Pipe Box Figure 7Courtesy of Plidco International, Inc. 61
  64. 64. Welding and Hot Tapping RequirementsAll welding must be done in accordance with ASME B31.3 or the original pipingconstruction code using qualified procedures and welders. Any welding that isdone while the system is in operation (e.g., hot tapping) must meet therequirements of API Publication 2201. All local design, inspection, testing, andhot work permit procedures developed by the owner must also be followed.Preheat and Postweld Heat Treatment (PWHT)Preheat and PWHT requirements must be per the applicable code (i.e., ASMEB31.3). Preheating to at least 300°F may be used as an alternative to PWHT ifthe system was originally given PWHT as a code requirement (i.e., based only onmaterial type and thickness), provided:• The pipe is P-1 steel.• Mn-Mo steels are operated at a high enough temperature to provide adequate fracture toughness and there is no hazard associated with pressure testing, startup, and shutdown.• The minimum preheat temperature is measured and maintained, and the joint is covered with insulation immediately after welding to slow the cooling rate.In situations where PWHT is required due to service considerations (e.g.,caustic), then the 300°F preheat alternative may not be used.PWHT is preferably done in a 360° band around the pipe that encompasses theweld area. Local PWHT may be substituted on local repairs for all materialsprovided:• An appropriate procedure is developed by a piping engineer.• The procedure considers thickness, thermal gradients, material properties, charges resulting from PWHT, the need for full penetration welds, local strains and distortions caused by local heating, and surface and volumetric NDE done after PWHT.• A minimum 300°F preheat is maintained while welding.• The PWHT temperature is maintained for a distance of at least twice the pipe thickness from the weld.• The PWHT temperature is monitored by two or more thermocouples.• Controlled heat is also applied to any branch connection or other attachment located within the PWHT area. 62
  65. 65. • The PWHT is required for code compliance and not for service considerations (e.g., caustic).Design, Materials, and NDE• All butt joints must be full-penetration groove welds.• Piping components must be replaced if a repair is not likely to be adequate.• Fillet welded patches must be designed by the piping engineer considering the following requirements: - Appropriate weld joint efficiency - The possibility of crevice corrosion - Adequate strength per criteria specified in API 570• New and replacement component materials must be per the applicable code.• NDE must be per the applicable code, owner-user specifications, and API 570.Pressure TestingPressure testing is normally required after alterations and major repairs, or ifotherwise practical and deemed necessary by the inspector. NDE may beconsidered as an alternative to pressure testing only after consultation with theinspector and the piping engineer.There may be situations where it is not practical to pressure test a final closureweld in a replacement section of pipe. The following requirements must be metin these cases:• The new or replacement pipe section must be pressure tested. Thus, only the final closure weld is not pressure tested.• The closure weld is a full-penetration weld between a weld neck flange and a standard pipe component; or between straight pipe sections, axially aligned (not miter cut) of equal diameter, thickness, and material. Alternatives that involve slip-on and socket welded flanges are also identified in API 570.• The final closure weld must be 100% RT or UT examined.• MT or PT must be done on the root pass and final weld for butt welds, and on completed fillet welds. 63
  66. 66. ReratingThe following requirements must be met to permit rerating a piping system to anew design temperature or MAWP:• Design evaluations must be done by the piping engineer or inspector to verify the system for the new conditions.• The rerating must meet the requirements of either the original construction code or the latest edition of that code.• Current inspection data must verify that the system is adequate for the proposed conditions and has sufficient remaining corrosion allowance.• The system must be pressure tested for the new conditions, unless records indicate that a previous test was done at a pressure that was greater than or equal to that required for the new conditions.• The safety valves must be reset for the new design pressure and confirmed to have adequate relieving capacity.• The rerating must be acceptable to the inspector or piping engineer.• All components in the system (e.g., valves, flanges, bolts, gaskets, etc.) must be checked and found to be acceptable for the new design conditions.• Piping flexibility is adequate for the new design temperature. New calculations may be required to confirm this.• The engineering records for the system must be updated.• A decrease in the minimum operating temperature is justified by impact test results (or exemptions) if required by the code. 64
  67. 67. VI. Inspection of Buried PipingCorrosive soil conditions may cause significant external deterioration of buriedpiping. Buried piping is typically protected from these soil conditions by using anexternal coating or wrap, or by using a cathodic protection system. Periodicinspection of a buried piping system is still required to ensure that the externalprotection system is effective; however, this inspection is hindered byinaccessibility.Inspection MethodsSeveral methods may be used to inspect a buried piping system.• A visual surveillance may be made above the area of the pipe for visible indications of leaks. These indications could include: - Surface contour change - Soil discoloration - Softening of paving asphalt - Formation of liquid pools - Bubbling crater puddles - Odor• A close-interval electric potential survey can be conducted over the buried pipe. This survey may locate active corrosion points on the pipe surface. Corrosion cells can be located in this way since the electric potential at a corrosion area will be measurably different from that of an adjacent area.• A holiday survey may be done on coated pipe to ensure that the coating is intact and free of holidays. The survey data can be used to determine the effectiveness of the coating and the rate of coating deterioration.• Soil resistivity measurements may be used to determine the corrosiveness of the soils in contact with the pipe. A mixture of different soils in contact with the pipe can cause corrosion.• If a cathodic protection (CP) system is used for corrosion protection, it should be periodically monitored to ensure that it is providing adequate protection. NACE RP0169 and API RP 651 provide guidance for this monitoring.• Direct inspection of buried piping may be done using intelligent pigging, video cameras, or excavation. 65
  68. 68. Inspection Frequency and Extent Method Frequency/CommentAbove-grade visual 6 MonthsPipe-to-soil potential survey - 5 year interval for poorly coated pipe where CP potentials are inconsistent - Conduct survey along pipe route if no CP or where leaks have occurred due to external corrosionCoating holiday survey Frequency based on indications that other corrosion control methods are ineffectiveSoil corrosivity 5 year interval if no CP system and over 100 ft. is buriedCP system monitoring Per NACE 0169 and API RP 651Internal Base on results of above-ground inspectionsExternal (if no CP) Pigging or excavation intervals based on measured soil resistivity per Table 1Leak testing (i.e., pressure testing) Alternative or supplement to inspection. • Hydrotest at 1.1 x MAOP • Interval ½ of Table 1 if no CP • Interval per Table 1 if CP Soil Resistivity, ohm-cm Inspection Interval, years < 2000 5 2000 – 10,000 10 > 10,000 15 Table 1 66
  69. 69. Repair of Buried PipingRepairs to buried piping may involve coatings, clamps, or welding.• Coating repairs must be inspected to ensure that they meet the following criteria: - Sufficient adhesion to prevent underfilm migration of moisture - Sufficient ductibility to resist cracking - Free of voids and gaps - Adequate strength to resist damage due to handling and soil stress - Can support supplemental CP - Tested with a high-voltage holiday detector• The location of clamp repairs must be logged in the inspection records. They are considered temporary repaired and are to be replaced with a permanent repair at the first opportunity.• Welded repairs of buried piping must meet the same requirements as those for above-ground piping. 67
  70. 70. VII. SummaryInspection, repair, alteration, and rerating of in-service piping systems are normalactivities that must be dealt with in process plants. Requirements andprocedures are necessary in carrying out these activities to ensure that pipingsystem integrity is maintained. API 570 is the industry standard that is used toform the basis for more detailed procedures that must be developed by processplant owners. 68
  71. 71. VIII. Suggested Reading1. API 570 Piping Inspection Code2. ASME B31.3 Process Piping3. ASME B31G Manual for Determining the Remaining Strength of Corroded Pipelines4. API Publication 2201 Procedure for Welding or Hot Tapping on Equipment Containing Flammables5. NACE RP0169 Control of External Corrosion on Underground or Submerged Metallic Piping Systems6. API RP651 Cathodic Protection of Aboveground Petroleum Storage Tanks 69
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