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Overview of Process Plant

Piping System Maintenance

and Repair

Participants Workbook

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CONTACT INFORMATION

ASME Headquarters

1-800-THE-ASME

ASME Professional Development1-800-THE-ASME

Eastern Regional Office

8996 Burke Lake Road - Suite L102Burke, VA 22015-1607703-978-5000800-221-5536703-978-1157 (FAX)

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You can also find information on

these courses and all of ASME,including ASME ProfessionalDevelopment, the Vice Presidentof Professional Development,and other contacts at the ASMEWeb site...

http://www.asme.org

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Overview of Process Plant Piping SystemMaintenance and Repair

Edited by:

Vincent A. CarucciCarmagen Engineering, Inc.

Copyright 1999 by

All Rights Reserved

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TABLE OF CONTENTS

Part 1: PARTICIPANT NOTES.3

Part 2: BACKGROUND MATERIAL36

I. Introduction ....37

II. Inspection and Testing Practices ....40

III. Inspection Frequency and Extent .45

IV. Evaluation and Analysis of Inspection Data ....49

V. Repairs, Alterations, and Rerating ....55

VI. Inspection of Buried Piping .....65

VII. Summary ..68

VIII. Suggested Reading ......69

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Part 1:Participant Notes

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Notes:

Notes:

1

Overview of Process Plant

Piping System

Maintenance and Repair

2

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

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Notes:

Notes:

3

Scope of API 570

Inspection, repair, alteration, rerating of in-

service metallic piping systems

To be used by qualified organizations andindividuals

Included fluid services: process fluids,

hydrocarbons, similar flammable or toxic

services

4

Scope of API 570 (Cont.)

Excluded and optional piping systems

Hazardous services below threshold limits

Water, steam, steam-condensate, BFW, CategoryD 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

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Notes:

Notes:

5

Definitions

Alteration - Physical change affecting

pressure containing capability

or flexibility

Repair - Work to restore piping systemto be suitable for designconditions

MAWP - Maximum permitted internal

pressure for continuous

operation at design temperature

6

Definit ions (Cont.)

Rerate - Change in design pressure,

design temperature, or both

Piping Circuit - Pipe section exposed to

similar corrosivity, with

similar design conditions

and material

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Notes:

Notes:

7

Types of Pipe Deterioration

Injection points

CUI

Service-specific and

localized corrosion

Environmentalcracking

Fatigue cracking

Brittle fracture

Deadlegs

Soil-to-air interfaces

Erosion and

corrosion/erosion

Corrosion underlinings and deposits

Creep cracking

Freeze damage

8

Typical Injection

Point Circuit

Figure 1

*

*

*

*

*

*

*

Ove rh ead L in e Greater of 3D or 12"

Injectionpoint

OverheadCondensersInjection point

piping circuitDistillationT o we r

* = Typical TML

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Notes:

Notes:

9

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 25-250F

CS systems in intermittent service over 250F

Deadlegs and attachments protruding frominsulation

10


(Cont.)

Austenitic stainless steels operating in range150-400F

Vibrating systems with damaged insulationjacketing

Steam-traced systems with tracing leaks

Systems with deteriorated coatings and/or

wrappings

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Notes:

Notes:

11

Locations Susceptible to CUI

Penetrations/breaches injacket

Damaged/missing

jacketing

Hardened, separated, or

missing caulking

Piping low points in

systems that haveinsulation breach

Insulation plug locations

Insulation termination points

Jacket seams on top ofhorizontal piping or

improperly lapped/sealedjacket

Bulges or staining ofinsulation or jacketing, ormissing bands

Carbon or low-alloy steel

components in high-alloysystems

12

Inspection Types

Internal visual

Thickness measurement

External visual

Vibrating piping

Supplemental inspection

Radiography Thermography

AET UT

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Notes:

Notes:

13

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 ortemporary repairs

14

Thickness Measurement

Locations (TMLs)

Specific inspection areas along piping circuit

Nature of TML varies by location

Selection considers potential for local corrosionand service-specific corrosion

Thickness monitoring at TMLs

TMLs distributed in circuit

More TMLs and more frequent monitoring basedon situation

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Notes:

Notes:

15


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

16

TML Selection

More TMLs:

Leak has high risk potential

High potential for localized

corrosion

High CUI potential

Fewer TMLs:

Low risk if leak

Long, straight piping

No TMLs:

Extremely low risk if leak

Non-corrosive service

Higher corrosion rates

Complex system

Relatively non-corrosive

service

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Notes:

Notes:

17


Methods

UT for pipe over NPS 1

RT for pipe NPS 1

Use appropriate UT procedures

Pit depth measurements

18

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

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Notes:

Notes:

19

Other Inspections

Material verification and traceability

Valve inspection

Weld inspection

Flanged joint inspection

20

Piping Service Classes

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 wate r; over public throughways

Services not in other classes

Includes most process unit piping and selected off-site piping

Flammable services that do not significantly vaporize when leak

Services harmful to human tissue but located in remote areas

1

2

3

Class Description

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Notes:

Notes:

21

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 inspections

22

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

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Notes:

Notes:

23

Maximum Inspection

Intervals

Circuit Thickness VisualType 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

24

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

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Notes:

Notes:

25

CUI Inspection

Considerations

Insulation damage at higher elevations may causeCUI 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

26

CUI Inspection Targets

P ipe Amoun t o f Fol low-up Amoun t o f NDE at

C lass NDE o r I nsulat ion Suspec t A reas on Pipi ng

Removal Where Within SusceptibleInsulation Damaged Temperature Ranges

1 75% 50%

2 50% 33%

3 25% 10%

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Notes:

Notes:

27

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 ofnext inspection date

28

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 instrumentsor machinery

Consider classification and potential for cracking,corrosion, CUI

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Notes:

Notes:

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(Cont.)

Threaded connections

Inspection based on SBP and auxiliary piping

requirements

Select TMLs that can be radiographed

Additional considerations if potentially subject tofatigue damage

30

Remaining L ife Calculations

RL =

Where: RL = Remaining life, years

tact = Minimum measured thickness,in. (May average at test point)

tmin = Minimum required thicknessfor location, in. Per B31.3 or

detailed calculations.

CR

tt minact

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Notes:

Notes:

31

Remaining Life Calculations

(Cont.)

RL for circuit based on shortest calculated RL

Determines

Inspection interval

Repair/replacement needs

32

Corrosion Rate Calculations

Long term and short term

Compare to determine which governs

Rationalize if significantly different

CR (LT) =

CR (ST) =

)sinspectioninitialandlastbetweenyears(

tt lastinitial

)sinspectionpreviousandlastbetweenyears(

tt lastprevious

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Notes:

Notes:

33

Corrosion Rate Estimation

New Systems or Changed

Service ConditionsDetermine using one of the following:

Data from other systems of similar material in

comparable service

Estimated from Owner-users experience or from

published data on systems in comparable service

Thickness measurements

After maximum 3 months service

Consider using corrosion coupons or probes to helpestablish measurement timing

Repeat until establish CR

34

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 years

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Notes:

Notes:

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Example 1 (Cont.)

Service Class 1 5-year interval

CR/Maximum = = 5.5 x 10-3in./yr.

CA/Available

= (0.32 - 0.28) = 0.04 in.

Maximum Interval = = 3.6 years

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Notes:

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37

Example 2

DP = 500 psig, DT = 400F

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

38

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

OK

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Notes:

Notes:

39

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

40

Example 3 (Cont.)

Not acceptable. Must either:

Reduce inspection interval

Confirm maximum operating pressure will notexceed 450 psig before 7th year

Renew pipe before 7th year

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Notes:

Notes:

41

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

42

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 weldand 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

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Notes:

Notes:

43

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 conditionschange or system modified

44

Recordkeeping Requirements

Owner-user responsibility

Permanent/progressive records required

To include: Service Classification

Identification Inspection interval

Inspection and test details Results of thickness measurementsand responsible individual and other inspections and tests done

Repairs (temporary and Pertinent design information and

permanent), alterations, piping drawingsreratings done

Maintenance and other Date and results of externalevent s a ff ec ti ng sys tem inspect ionsintegrity

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Notes:

Notes:

45

Author izat ion 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 andafter completion

46

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

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Notes:

Notes:

47

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 metal

48

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.)

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Notes:

Notes:

49

Typical Welded Repairs

Figure 2Split Sleeve

tst

CL

SeeDetail2

MT orPT

See Detail1

ts

t

CL

1/8"

MaximumG

ap

FieldWeld

ts

Field Weld

Backing Strip

LEGEND:

ts=Sleeve Thickness

t = Pipe Thickness

Detail " 1"FilletGirth Weld

Detail2Butt Weldfor Seam

50


(Cont.)

Figure 3Complete-Encirclement Box

CL

CL

CL

LiftingLugs

SplitBox andEndPlateson CL Typ.

Typ.

Typ.(2)3/4" - 3000#Couplings

EndPlate,(2) Required

NewContainmentBox

Typ.

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Notes:

Notes:

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(Cont.)

Figure 4Partial Box

52


(Cont.)

Figure 5Lap Patch

tp

t

1/8"

MaximumG

ap

LEGEND:

tp

= SleeveThickness

t = PipeThickness

Detail " 1"

SeeDetail1

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Notes:

Notes:

53

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 fluids

54

Typical Non-Welded Repairs

Figure 6Flange Clamp

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Notes:

Notes:

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Typical Non-Welded Repairs

(Cont.)

Figure 7

Bolted Box

56

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

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Notes:

Notes:

57

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

58

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

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Notes:

Notes:

59

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 engineer

60

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, orstraight pipe sections of equal diameter andthickness, 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

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Notes:

Notes:

61

Rerating

Requirements to be met:

Design calculations

Inspection verifiescondition and CA provided

Safety valves reset

All system components

acceptable

Records updated

Meet original or latestcode

Must be pressure tested

unless already done atsufficient pressure

Acceptable to inspector or

piping engineer

Piping flexibility adequate

for design temperaturechanges

Temperature decreasejustified by impact testresults

62

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

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Notes:

Notes:

63

Other Requirements fo r

Buried Pipe

Inspection Methods

Intervals

Extent

Repair Methods

64

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

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Part 2:Background Material

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I. Introduction

The 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 be

followed by process plants. This course is based on API 570.

Scope of API 570

API 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 in

API 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 Service

Unless 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 thresholdlimits, as defined by jurisdictional regulations.

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Excluded and Optional Piping Systems

API 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 plants 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 byjurisdictional regulatories.

- Water (including fire protection systems), steam, steam condensate, boilerfeedwater, 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 orreciprocating mechanical devices (e.g., pumps, compressors, etc.) wherethe primary design considerations and/or stresses are derived from thefunctional requirements of the device.

- Internal piping or tubing of fired heaters or boilers.

- Pressure vessels, heaters, furnaces, heat exchangers, and the fluidhandling or processing equipment (including internal piping andconnections for external piping).

- Plumbing, sanitary sewers, process waste sewers, and storm sewers.

- Piping or tubing with an outside diameter not exceeding that of NPS

- 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 on

areas that would have the largest potential effect should leakage or failure occur.However, this should not be interpreted that these excludable or optionalsystems 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:

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The failure of a high pressure steam or boiler feedwater system could havesignificant personnel safety consequences. An owner might include suchservices in his API 570 program.

The failure of an NPS vent connection in an included fluid service could

have significant personnel safety and economic consequences. An ownermight wish to include such systems in his API 570 program.

Definitions

API 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 designimplications affecting the pressure containing capability orflexibility of a piping system beyond the scope of its design.

Repair The work necessary to restore a piping system to a conditionsuitable for safe operation at the design conditions.

MAWP The maximum internal pressure permitted in the pipingsystem for continued operation at the most severe conditionof coincident internal or external pressure and temperature(minimum or maximum) expected during service.

Rerate A change in either or both the design temperature or themaximum allowable working pressure.

Piping Circuit A section of piping that has all points exposed to anenvironment of similar corrosivity and that is of similar designconditions and construction material.

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II. Inspection and Testing Practices

Types of Pipe Deterioration

The 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 localizedcorrosion

Erosion and corrosion/erosion

Environmental cracking Corrosion beneath linings anddeposits

Fatigue cracking Creep cracking

Brittle fractures Freeze damage

Several of these items are briefly discussed below.

Injection Points

Portions 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.

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*

*

*

*

*

*

*

Overhead Line Greater of

3D or 12"

Injection

point

Overhead

CondensersInjection point

piping circuitDistillation

Tower

* = Typical TML

Typical Injection Point Circui tFigure 1


Piping 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 CUI

might 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

- Deluge systems

- Steam vents

- Process spills, moisture ingress,acid vapors

Carbon steel piping operating in the range 25F to 250F.

Carbon steel piping operating intermittently above 250F.

Deadlegs or other attachments protruding from insulation and at a differenttemperature than the active line.

Austenitic stainless steel piping operating between 150F and 400F.

Vibrating piping that may damage insulation jacketing.

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Steam traced piping that may have leaking tracers.

Piping with deteriorated coating or wrapping.

Locations Susceptible to CUI

For 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 underinsulation.

Types of Inspection

The 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 remoteinspection 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.

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Vibrating Piping. Excessive piping vibration should be reported toengineering for evaluation. Excessive pipe vibration or other line movementcould result in leakage at flanged joints or threaded connections, or a fatiguefailure. It should be remembered, however, that some amount of pipevibration is normal.

Supplemental Inspection. Other inspection methods may also be used basedon the specific situation. These include radiography, thermography, acousticemission 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 Selection

The 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

High potential for localized corrosion

High CUI potential

Higher corrosion rates

Complex system

Fewer TMLs

Low risk if leak

Large, straight piping

Relatively non-corrosiveservice

No TMLs

Extremely low risk if leak

Non-corrosive service

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Thickness Measurement Methods

The 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 gauges

In all areas, appropriate inspection procedures must be used to obtain reliableresults.

Pressure Testing

Except where local jurisdictions require it, pressure tests are not normally doneas part of a routine inspection. When pressure tests are done (e.g., after

alterations) 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 blowndry).

Other Inspections

Other inspections may also be required.

Material verification and traceability. When alterations or repairs are made onlow or high-alloy piping systems, the inspector must ensure that the correctmaterials are used.

Valve inspection. Inspect valves for any unusual corrosion patterns orthinning. Valves in high temperature cyclic service might be subject to fatiguecracking. 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 deteriorationas part of the normal inspection activity if problems are suspected.

Flanged joint inspection. Flanged joints should be examined for signs ofleakage. The cause of any leakage found should be determined. Specialattention should be paid to flanges that have been clamped and pumped withsealant to stop leaks since the bolting might corrode and/or crack with time.

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III. Inspection Frequency and Extent

Piping Service Classes

Process 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 formexplosive 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

Inspection Intervals

Inspection 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 experience

The maximum interval between thickness measurements should be the lower ofhalf the remaining life or what is specified in the following table:

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Circuit TypeThickness

Measurements, Years Visual 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

The inspection intervals must be reviewed and adjusted as necessary based onthe results of the thickness measurements that are made.

Extent of Visual External Inspection

External 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 this

CUI Inspection Considerations

After 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:

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PipeClass

Amount of follow-up NDE orinsulation removal where

insulation is damaged

Amount of NDE at suspect areason piping within susceptible

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 Measurements

Each 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.


Other 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 570

Secondary Process Piping 1 Inspect per all requirements of API 570

2 & 3 Inspection is optional

Deadlegs 2 & 3 Inspect where corrosion was experiencedor is anticipated

Note 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.

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Secondary, Auxi liary SBP

Inspection 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 CUI

Threaded Connections

Threaded connections are inspected based on the same criteria as other SBP.TMLs for threaded connections should only include those that can be

radiographed 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.

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IV. Evaluation and Analysis of Inspection Data

Remaining Life Calculations

The remaining life of piping systems must be calculated based on the corrosionrate using the following:

Calculation Equation

Remaining Life, RL

ratecorrosion

tt minact tact= Actual minimum thickness, in

inches, determined at inspection

tmin= Minimum required thickness, ininches, for the limiting section or

zoneCorrosion Rate, CR (LT)

1

lastinitial

D

tt D1= Time (years) between last andinitial (nominal) inspections

Corrosion Rate, CR (ST)

2

lastpreviousl

D

tt D2= Time (years) between last andprevious inspections

The 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 an

attempt to determine the cause. The remaining life of the circuit should be basedon the shortest calculated remaining life.

Corrosion Rate Estimation

The 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 incomparable service.

Estimate based on the owner-users experience or from published data forsimilar material in comparable service.

Make initial thickness measurements after no more than three months ofservice. Corrosion coupons or probes may be useful to help determine whenthickness measurements should be made. Make additional thicknessmeasurements as necessary until the corrosion rate is determined.

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Example 1 - Inspection Interval Determination

An 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, 0.32

Based 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 the

remaining life criterion.

CR/Maximum=10

32.0375.0 = 5.5 x 10-3in./yr.

Available corrosion allowance = (0.32 - 0.28) = 0.04 in.

Maximum Interval =310x5.5x2

04.0

= 3.6 years < 5 years

Maximum thickness measurement interval is 3.6 years.

MAWP Determination

The 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 forapplied loadings other than pressure.

The following examples illustrate calculation of the MAWP. Note that in bothcases, only the pipe thickness is considered.

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Example 2 MAWP Determination

Design Pressure 500 psig

Design Temperature 400F

Pipe Material A 106 Gr. B

Pipe Size NPS 16

Allowable 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./year

Next Planned Inspection 5 years

Estimated Thinning Until Next Inspection 5 x 0.01 = 0.05 in.

MAWP =D

EtS2(from B31.3)

MAWP =( )

16

05.0x232.0x1x000,20x2

MAWP = 550 psig >500 psig

Since the MAWP exceeds the system design pressure, the system may remainin service at the design pressure without repairs, replacements, or rerating.

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Example 3 Check Increased Inspection Interval

For 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.

MAWP =D

EtS2(from B31.3)

MAWP =( )

16

07.0x232.0x1x000,20x2

MAWP = 450 psig

The MAWP is less than the design pressure. Therefore, either the inspectioninterval must be reduced, the operating pressure must not exceed 450 psig, or

the pipe must be repaired or replaced.

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Minimum Required Thickness Determination

The 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 required

thickness. 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 Evaluation

Local 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 depthand length of the locally thin area, the pipe diameter, and nominal thicknessto determine whether the thin area is acceptable. It intrinsically accounts forthe additional strength that the surrounding uncorroded pipe provides to thethin area.

ASME Section VIII, Division 2, Appendix 4 criteria. This is a detailednumerical stress analysis approach that permits a more exact calculation andevaluation of the local stresses. The basic code allowable stress (rather thanthe Division 2 allowable stress) is used in this analysis, but not less than 2/3of 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 seamand its joint efficiency is less than one, the proximity of a thinned area to theweld is relevant.

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- If the thinned area is more than the larger of 1 inch or twice the measuredthickness away from the weld, then weld joint efficiency does not need tobe considered.

- If the thinned area is closer to the weld, then weld joint efficiency must beconsidered.

If a pipe cap is corroded, the location of the corrosion is relevant (i.e., in theknuckle region or central portion). The knuckle region of a cap requires alarger minimum thickness than the central portion.

Piping Stress Analysis

Performing 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 beidentified for further evaluation or repair.

Adequate flexibility to accommodate thermal displacements must beprovided. 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 atflanged 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 newequipment item with associated piping to the system).

Recordkeeping Requirements

The 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

Identification

Inspection and test details andresponsible individual

Repairs (temporary and permanent),alterations, reratings done

Maintenance activities and otherevents affecting system integrity

Classification

Inspection interval

Results of thickness measurementsand other inspections and tests done

Pertinent design information andpiping drawings

Date and results of externalinspection

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V. Repairs, Alterations, and Rerating

In all cases, repairs and alterations must meet ASME B31.3 requirements.

Author ization and Approval

All 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 cracksthat occurred in-service. The purpose of this is to attempt to identify thecause of the crack and correct it.

The inspector must approve all repairs and alterations at the designated holdpoints and at completion of the work.

Welded Repairs

Welded 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 distinction

is made between temporary and permanent repairs.

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Temporary Repairs

A full encirclement welded split sleeve or a box-type enclosure may beinstalled over the damaged or corroded area (See Figures 2 through 4). Thesleeve 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 pipewall unless the piping engineer is convinced that the crack will not propagatefrom under the repair.

A fillet-welded split coupling or a lap patch may be used to repair localizeddeterioration (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 may

remain 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.

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ts

t

C

L

See Detail 2

MT or PT

See Detail 1

ts

t

CL

1/8"

MaximumG

ap

Field Weld

ts

Field Weld

Backing Strip

LEGEND:

ts = Sleeve Thickness

t = Pipe Thickness

Detail " 1 "

Fillet Girth Weld

Detail 2

Butt Weld for Seam

Welded Split SleeveFigure 2

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CL

CL

CL

Lifting Lugs

Split Box and

End Plates on CL Typ.Typ.

Typ.(2) 3/4" - 3000# Couplings

End Plate,

(2) Required

New

Containment

Box

Typ.

Complete-Encirclement BoxFigure 3

Partial BoxFigure 4

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tp

t

1/8"

Maximum

Gap

LEGEND:

tp = Sleeve Thicknesst = Pipe Thickness

Detail " 1 "

See Detail 1

Lap PatchFigure 5

Permanent Repairs

A relatively small defect may be repaired by completely removing it and thenfilling the resulting groove with weld metal.

Locally corroded areas may be repaired by first removing any surfaceirregularities and contamination, and then restoring the thickness with weldmetal. This approach is only practical for relatively small areas.

If the system can be taken out of service, a cylindrical section of pipe thatcontains the defective area can be removed and replaced.

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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 pipecurvature to avoid local geometric discontinuities that could act as stressconcentration points.

In all cases, appropriate NDE should be done of the final welds to ensure thatthey are high quality. Butt welds will typically be 100% radiographically (RT)or ultrasonically (UT) examined, along with either liquid penetrant (PT) ormagnetic particle (MT) examination. Other welds will typically be PT or MTexamined.

Non-Welded Repairs

Non-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 encompasses

the 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.

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Bolted Flange ClampFigure 6

Courtesy of Plidco International, Inc.

Bolted Pipe BoxFigure 7

Courtesy of Plidco International, Inc.

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Welding and Hot Tapping Requirements

All 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 300F may be used as an alternative to PWHT if

the 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 adequatefracture toughness and there is no hazard associated with pressure testing,startup, and shutdown.

The minimum preheat temperature is measured and maintained, and the jointis 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 300F preheat alternative may not be used.

PWHT is preferably done in a 360band around the pipe that encompasses the

weld 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, localstrains and distortions caused by local heating, and surface and volumetricNDE done after PWHT.

A minimum 300F preheat is maintained while welding.

The PWHT temperature is maintained for a distance of at least twice the pipethickness from the weld.

The PWHT temperature is monitored by two or more thermocouples.

Controlled heat is also applied to any branch connection or other attachmentlocated within the PWHT area.

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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 consideringthe 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 API570.

Pressure Testing

Pressure 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 the

inspector 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, onlythe final closure weld is not pressure tested.

The closure weld is a full-penetration weld between a weld neck flange and astandard pipe component; or between straight pipe sections, axially aligned(not miter cut) of equal diameter, thickness, and material. Alternatives thatinvolve 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 oncompleted fillet welds.

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Rerating

The 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 verifythe system for the new conditions.

The rerating must meet the requirements of either the original constructioncode or the latest edition of that code.

Current inspection data must verify that the system is adequate for theproposed conditions and has sufficient remaining corrosion allowance.

The system must be pressure tested for the new conditions, unless recordsindicate that a previous test was done at a pressure that was greater than orequal to that required for the new conditions.

The safety valves must be reset for the new design pressure and confirmed tohave 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.) mustbe checked and found to be acceptable for the new design conditions.

Piping flexibility is adequate for the new design temperature. Newcalculations 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 testresults (or exemptions) if required by the code.

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VI. Inspection of Buried Piping

Corrosive 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 Methods

Several methods may be used to inspect a buried piping system.

A visual surveillance may be made above the area of the pipe for visibleindications of leaks. These indications could include:

- Surface contour change

- Softening of paving asphalt

- Bubbling crater puddles

- Soil discoloration

- Formation of liquid pools

- Odor

A close-interval electric potential survey can be conducted over the buriedpipe. 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 isintact and free of holidays. The survey data can be used to determine theeffectiveness of the coating and the rate of coating deterioration.

Soil resistivity measurements may be used to determine the corrosiveness ofthe soils in contact with the pipe. A mixture of different soils in contact withthe 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, videocameras, or excavation.

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Inspection Frequency and Extent

Method Frequency/Comment

Above-grade visual 6 Months

Pipe-to-soil potential survey - 5 year interval for poorly coated pipewhere CP potentials are inconsistent

- Conduct survey along pipe route ifno CP or where leaks have occurreddue to external corrosion

Coating holiday survey Frequency based on indications thatother corrosion control methods areineffective

Soil corrosivity 5 year interval if no CP system andover 100 ft. is buried

CP system monitoring Per NACE 0169 and API RP 651

Internal Base on results of above-groundinspections

External (if no CP) Pigging or excavation intervals basedon measured soil resistivity per Table 1

Leak testing (i.e., pressure testing) Alternative or supplement to inspection.

Hydrotest at 1.1 x MAOP

Interval of Table 1 if no CP

Interval per Table 1 if CP

Soil Resistivity, ohm-cm Inspection Interval, years

10,000

5

10

15

Table 1

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Repair of Buried Piping

Repairs to buried piping may involve coatings, clamps, or welding.

Coating repairs must be inspected to ensure that they meet the followingcriteria:

- 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. Theyare 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.

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VII. Summary

Inspection, repair, alteration, and rerating of in-service piping systems are normalactivities that must be dealt with in process plants. Requirements and

procedures 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.

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VIII. Suggested Reading

1. API 570 Piping Inspection Code

2. ASME B31.3 Process Piping3. ASME B31G Manual for Determining the Remaining Strength of

Corroded Pipelines

4. API Publication 2201 Procedure for Welding or Hot Tapping on EquipmentContaining Flammables

5. NACE RP0169 Control of External Corrosion on Underground orSubmerged Metallic Piping Systems

6. API RP651 Cathodic Protection of Aboveground PetroleumStorage Tanks

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