Api570 my self study notes

API 5703rd edition, NOV 20092013- My Exam Preparation Notes Piping Inspection Code: In-service inspection, rating, repair and alteration of piping systems.

Charlie Chong/ Fion Zhang/ He Jungang / Li Xueliang

Fion Zhang2013/March/5

-,

-,

-RBI, RBV, QRA, RCM, ,

-API 57901/ASME FFS-1 ,

-RBV,

-/,(Material Technology),

-- /(,,,),

API 570?, ,,,


Objective !/,.

API 570 Charlie Chong/ Fion Zhang

Methodology

API 570 & referred standards. This inspection code recognizes API Standard 579-1/ASME FFS-1, Fitness-for-service, API Recommended Practice 580, Risk-based Inspection


REFERENCE PUBLICATIONS A. API Publications:

API Standard 570 Inspection, Repair, Alteration, and Rerating of In-Service Piping Systems

API RP 571, Damage mechanisms Affecting Fixed equipment in the Refining Industry

API Recommended Practice 574 Inspection Practices for Piping System Components

API RP 577, Welding Inspection and Metallurgy API Recommended Practice 578 Material Verification Program for

New and Existing Alloy Piping Systems

Copyright American Petroleum Institute


Section V, Nondestructive Examination


Section IX, Welding and brazing Qualifications


B16.5, Pipe Flanges and Flanged Fittings


B31.3, Process Piping


Content:(9 Sections with 3 Appendices.)

Content:(9 Sections with 3 Appendices.)

1. Scope 2. Normative References3. Terms & Definitions4. Owner/User Inspection Organizations5. Inspection, Examination, and Pressure Testing Practices6. Interval/Frequency and Extent of Inspection7. Inspection Data Evaluation, Analysis, and Recording8. Repairs, Alterations, and Re-rating of Piping Systems.9. Inspection of Buried Piping

Annex A (informative) Inspector CertificationAnnex B (informative) Requests for InterpretationsAnnex C (informative) Examples of Repairs

9 3 .

1. Scope 2. Normative References 3. Terms & Definitions4. Owner/User Inspection Organizations /5. Inspection, Examination, and Pressure Testing Practices

,,6. Interval/Frequency and Extent of Inspection /7. Inspection Data Evaluation, Analysis, and Recording

,8. Repairs, Alterations, and Re-rating of Piping Systems.

,,9. Inspection of Buried Piping10. Inspection of Buried Piping

9 3 .

Annex A (informative) Inspector CertificationAAnnex B (informative) Requests for InterpretationsBAnnex C (informative) Examples of RepairsC

Sec~0Forward


Forward

A. This edition supersedes all previous editions. Each edition, revision, or addenda may be used beginning with the date of issuance. Effective 6 months after publication. 6

B. During the six month lag time between issuance and affectivity, the user must specify which edition/addenda is mandatory.6, /.

C. Use of API publications API

May be used by anyone desiring to do so. No warranties given. Disclaims liability or responsibility for loss or damage. API

D. Submit revisions, reports, comments and requests for interpretations to API.API

Sec~11 Scope

1 Scope 1.1.1 Coverage

API 570 covers inspection, rating, repair, and alteration procedures for metallic and fiberglass reinforced plastic (FRP) piping systems and their associated pressure relieving devices that have been placed in-service.

,,

1.12The intent of this code is to specify the in-service inspection and condition-monitoring program that is needed to determine the integrity of piping.

API570 ,

,---------------------------------------./,.

Metallic

FRP/GRP

PE/PVC/PP/PS/ABS/

FRP/GRP

Inservice-

New Construction/

UPVC Piping

1.2.1 Included Fluid Services

Except as provided in 1.2.2, API 570 applies to piping systems for process fluids, hydrocarbons, and similar flammable or toxic fluid services, such as the following:

1. Raw, intermediate, and finished petroleum products;, ,

2. Raw, intermediate, and finished chemical products;, , ;

3. Catalyst lines;4. Hydrogen, natural gas, fuel gas, and flare systems;

, ,

5. Sour water and hazardous waste streams above threshold limits, as defined by jurisdictional regulations;

6. Hazardous chemicals above threshold limits, as defined by jurisdictional regulations;

7. Cryogenic fluids such as: LN2, LH2, LOX, and liquid air;, , , ,.

8. High-pressure gases greater than 150 psig such as: GHe, GH2,GOX, GN2, and HPA (High-Purity Air).150 psig

API 570

1.2.2 Optional Piping Systems and Fluid Services

The fluid services and classes of piping systems listed below are optional with regard to the requirements of API 570.

a) Fluid services that are optional include the following:

1) hazardous fluid services below threshold limits, as defined by jurisdictional regulations;

2) water (including fire protection systems), steam, steam-condensate, boiler feed water, and Category D fluid services, as defined in ASME B31.3. (),,,, ASME B31.3 D

b) Other classes of piping systems that are optional are those that are exempted from the applicable process piping construction code.

Not all piping in the facilities are covered: Process piping that are within the scopes Optional piping (1.2.2) Owner/user wishes to include (1.2.2).

API570!

1.3 Fitness-For-Service and Risk-Based Inspection (RBI) &

This inspection code recognizes Fitness-For-Service concepts for evaluating in-service damage of pressure containing components. API 579 provides detailed assessment procedures for specific types of damage that are referenced in this code. This inspection code recognizes RBI concepts for determining inspection intervals. API 580 provides guidelines for conducting a risk-based assessment.

:

API 579 , API 580

RBI-API 580/581

Fitness-for-serviceAPI Standard 579-1/ASME FFS-1,

1.3 Fitness-For-Service and Risk-Based Inspection (RBI)API 570 Recognized

RBIAPI 580/581

API 570 Recognized

A risk assessment and risk management process that is focused on inspection planning for piping systems for loss of containment in processing facilities, which considers both:

the probability of failure and consequence of failure due to material deterioration.

Fitness-for-service(FFS) API Standard 579-1/ASME FFS-1.This inspection code recognizes fitness-For-Service concepts for evaluating in-service damage of pressure containing components. API 579 provides detailed assessment procedures for specific types of damage that are referenced in this code.

API 570 Recognized

API 570 Recognized FFS/RBI - API570

Take/has priority over API570 requirements on extents and intervals of inspection (with limitation see 5.2.4)API Standard 579-1/ASME FFS-1., API570.

5.2.4 The maximum intervals between RBI assessments are outlined in 6.3.2, Table 2.

Fitness-for-service (FFS) API Standard 579-1/ASME FFS-1.

Assessment requires the use of a future corrosion allowance

Assessment of General Metal LossAPI 579-1/ASME FFS-1, Section 4. Assessment of Local Metal LossAPI 579-1/ASME FFS-1, Section 5. Assessment of Pitting CorrosionAPI 579-1/ASME FFS-1, Section 6.

In some cases will require the use of a future corrosion Allowance

Assessment of blisters and laminations-API 579-1/ASME FFS-1, Section 7

Assessment not requires the use of a future corrosion allowance

Assessment of weld misalignment and shell distortions- API 579-1/ASME FFS-1, Section 8.

Assessment of crack-like flaws- API 579-1/ASME FFS-1, Section 9. Assessment of effects of fire damage-API 579-1/ASME FFS-1, Section 11.

Sec~22 Normative References

2 Normative References

1 ASME International, 3 Park Avenue, New York, New York 10016-5990, www.asme.org.

2 American Society for Nondestructive Testing, 1711 Arlingate Lane, P.O. Box 28518, Columbus, Ohio 43228, www.asnt.org.

3 ASTM International, 100 Barr Harbor Drive, West Conshohocken, Pennsylvania 19428, www.astm.org.

4 Materials Technology Institute, 1215 Fern Ridge Parkway, Suite 206, St. Louis, Missouri 63141-4405, www.mti-link.org.

5 NACE International (formerly the National Association of Corrosion Engineers), 1440 South Creek Drive, Houston, Texas 77218-8340, www.nace.org.

6 National Fire Protection Association, 1 Batterymarch Park, Quincy, Massachusetts 02169-7471, www.nfpa.org.

Sec~33 Terms, Definitions, Acronyms, and Abbreviations

3 Terms, Definitions, Acronyms, and Abbreviations

3.1.19 design temperature of a piping system component

The temperature at which, under the coincident pressure, the greatest thickness or highest component rating is required. It is the same as the design temperature defined in ASME B31.3 and other code sections and is subject to the same rules relating to allowances for variations of pressure or temperature or both. Quality control functions performed by examiners (or inspectors) as defined elsewhere in this document.

The API 570 candidate must know all terms and definitions. Some of the terms that have been on the test, include:

3.1 Alterations3.4 Authorized Inspection Agency3.6 Auxiliary Piping3.9 Deadlegs3.12 Examiner3.13 Imperfections3.16 Injection Point3.31 Piping Circuit3.33 Piping System3.34 Primary Process Piping3.37 Repair3.38 Repair Organization3.41 SBP3.46 Test Point3.47 TML

Sec~44 Owner/User Inspection Organization

4 Owner/User Inspection Organization

4 Owner/User Inspection Organization

4.1 General4.2 Authorized Piping Inspector Qualification and Certification 4.3 Responsibilities4.3.1 Owner/User Organization4.3.2 Piping Engineer4.3.3 Repair Organization4.3.4 Authorized Piping Inspector4.3.5 Examiners4.3.6 Other Personnel

,/: 5

1. Piping Engineer / Corrosion Specialist /

2. Repair organization

3. API Authorized Inspector

4. Examiners

5. Other Personnel

Charlie Chong/ Fion Zhang

4.1 General

/

1. ,, .

2. API 570.3. /,.4. ,

.: ,,,pH,,,,.

Integrity operating envelopes /:

,.: pH

Charlie Chong/ Fion ZhangAPI 580

4.2 Authorized Piping Inspector Qualification and Certification

Authorized piping inspectors shall have education and experience in accordance with Annex A of this inspection code. Authorized piping inspectors shall be certified in accordance with the provisions of Annex A. Whenever the term inspector is used in this code, it refers to an authorized piping inspector.

A

Education and Experience.

1. BS in engineering or technology plus one year of experience in the design, construction, repair, operation, or inspection of piping systems or supervision of piping inspection.

2. 2-year certificate or degree in engineering or technology plus 2 years of experience in the design, construction, repair, operation, or inspection of piping systems or supervision of inspection of piping systems.

3. The equivalent of a high school education plus 3 years of experience in the design, construction, repair, operation, or inspection of piping systems or supervision of inspection of piping systems.

4. A minimum of five years of experience in the design, construction, repair, inspection or operation of piping systems, or supervision of inspection.

Education and Experience.

Charlie Chong/ Fion ZhangAPI 580

4.3 Responsibilities4.3.1 Owner/User Organization/4.3.1.1 Systems and Procedures

An owner/user organization is responsible for developing, documenting, implementing, executing, and assessing piping inspection systems and inspection procedures that will meet the requirements of this inspection code. These systems and procedures will be contained in a quality assurance inspection/repair management system and shall include:/./

/,,,,API570

1. organization and reporting structure for inspection personnel;

2. documenting and maintaining inspection and quality assurance procedures;

3. documenting and reporting inspection and test results;

4. developing and documenting inspection plans;

5. developing and documenting risk-based assessments;

6. developing and documenting the appropriate inspection intervals;

4.3.1.1 Systems and Procedures

7. corrective action for inspection and test results;

8. internal auditing for compliance with the quality assurance inspection manual;

9. review and approval of drawings, design calculations, and specifications for repairs, alterations, and re-ratings;,,,

10. ensuring that all jurisdictional requirements for piping inspection, repairs, alterations, and re-rating are continuously met;

11.reporting to the authorized piping inspector any process changes that could affect piping integrity;

12. training requirements for inspection personnel regarding inspection tools, techniques, and technical knowledge base;

13.controls necessary so that only qualified welders and procedures are used for all repairs and alterations;

14. controls necessary so that only qualified NDE personnel and procedures are utilized;

15. controls necessary so that only materials conforming to the applicable section of the ASME Code are utilized for repairs and alterations; ASME

16.controls necessary so that all inspection measurement and test equipment are properly maintained and calibrated;

17. controls necessary so that the work of contract inspection or repair organizations meet the same inspection requirements as the owner/user organization;,/.

18. internal auditing requirements for the quality control system for pressure-relieving devices.

4.3.1.2 MOC

The owner/user is also responsible for implementing an effective MOC process that will review and control changes to the process and to the hardware. An effective MOC process is vital to the success of any piping integrity management program in order that the inspection group will be able to anticipate changes in corrosion or other deterioration variables and alter the inspection plan to account for those changes. The MOC process shall include the appropriate materials/corrosion experience and expertise in order to effectively forecast what changes might affect piping integrity. The inspection group shall be involved in the approval process for changes that may affect piping integrity. Changes to the hardware and the process shall be included in the MOC process to ensure its effectiveness. / MOC- MOC/, - MOC.

4.3.1.2 MOC

Changes to the hardware and the process shall be included in the MOC process to ensure its effectiveness.

: (1) (, , , ,,) (2) (:,,,,,,,).

4.3.2 Piping Engineer

The piping engineer is responsible to the owner/user for activities involving design, engineering review, rating, analysis, or evaluation of piping systems covered by API 570./, API 570: ,,,,.

4.3.3 Repair Organization

All repairs and alterations shall be performed by a repair organization. The repair organization shall be responsible to the owner/user and shall provide the materials, equipment, quality control, and workmanship necessary to maintain and repair the piping systems in accordance with the requirements of API 570.API 570,

4.3.4 Authorized Piping Inspector

When inspections, repairs, or alterations are being conducted on piping systems, an authorized piping inspector shall be responsible to the owner/user for:

determining that the requirements of API 570 on inspection, examination, quality assurance and testing are met.

The inspector shall be directly involved in the inspection activities which in most cases will require field activities to ensure that procedures are followed.

The inspector is also responsible for extending the scope of the inspection (with appropriate consultation with engineers/specialists), where justified depending upon the findings of the inspection. /,,/.

Where non-conformances are discovered, the inspector is responsible for notifying the owner-user in a timely manner and making appropriate repair or other mitigative recommendations. /.

field activities

4.3.5 Examiners

4.3.5.1 The examiner shall perform the NDE in accordance with job requirements.

4.3.5.2 The examiner is not required to be certified in accordance with Annex A and does not need to be an employee of the owner/user. The examiner shall be trained and competent in the NDE procedures being used and may be required by the owner/user to prove competency by holding certifications in those procedures. Examples of other certifications that may be required include ASNT SNT-TC-1A, ASNT CP-189, and AWS QC1.

4.3.5.3 The examiners employer shall maintain certification records of the examiners employed, including dates and results of personnel qualifications. These records shall be available to the inspector.

.

ASNT SNT-TC-1A, ASNT CP-189, AWS QC1 ...

4.3.6 Other Personnel

Operating, maintenance, engineering or other personnel who have special knowledge or expertise related to particular piping systemsshall be responsible for timely notification to the inspector orengineer of issues that may affect piping integrity such as the following:

a) any action that requires MOC; b) operations outside defined integrity operating envelopes;

IOEc) changes in source of feedstock and other process fluids;

.d) piping failures, repair actions conducted and failure analysis reports;

/e) cleaning and decontamination methods used or other maintenance

procedures that could affect piping and equipment integrity; /()

a) reports of experiences that other plants have had with similar service piping and associated equipment failures;

f) any unusual conditions that may develop (e.g. noises, leaks, vibration, etc.). (,,,)

Sec~55 Inspection, Examination, and Pressure Testing Practices

5 Inspection, Examination, and Pressure Testing Practices,,

5 Inspection, Examination, and Pressure Testing Practices,,

5.1 Inspection Plans5.2 Risk-Based Inspection5.3 Preparation for Inspection5.4 Inspection for Types and Locations of Damage Modes of

Deterioration and Failure 5.5 General Types of Inspection and Surveillance 5.6 CMLs 5.7 Condition Monitoring Methods 5.8 Pressure Testing of Piping Systems-General -5.9 Material Verification and Traceability 5.10 Inspection of Valves 5.11 In-service Inspection of Welds 5.12 Inspection of Flanged Joints 5.13 Inspection Organization Audits

5.1 Inspection Plans

5.1.1 Development of an Inspection Plan

5.1.1.1 An inspection plan shall be established for all piping systems within the scope of this code. The inspection plan shall be developed by the inspector and/or engineer. A corrosion specialist should be consulted as needed to clarify potential damage mechanisms and specific locations where degradation may occur. A corrosion specialist should be consulted when developing the inspection plan for piping systems that operate at elevated temperatures [above 750oF (400oC)] and piping systems that operate below the ductile-to-brittle transition temperature.

/. . 750C (400C) -

.

New Fabrication In-Service

,

750C (400C) - ,

-:(),,,(),

-:(,)()

-(,,,,,),

-.

-:/(/) -:(

/)

A corrosion specialist should be consulted if the service temperature operate above 750oF (400oC) ITP.

750oF (400oC)

A corrosion specialist should be consulted

750oF (400oC)

Piping systems that operate at elevated temperatures may suffer;;

graphitization

Hydrogen Blistering

Hydrogen Blistering Creep / Stress Rupture

Graphitization

Graphitization

Piping systems that operate below the ductile-to-brittle transition temperature -

5.1.1.2 The inspection plan is developed from the analysis of several sources of data. Piping systems shall be evaluated based on (1) present or (2) possible types of damage mechanisms. The methods and the extent of NDE shall be evaluated to assure they can adequately identify the damage mechanism and the severity of damage. Examinations shall be scheduled at intervals that consider the: ;

a) type of damage, b) rate of damage progression, c) tolerance of the equipment to the type of damage,

d) capability of the NDE method to identify the damage, e) maximum intervals as defined in codes and standards, and

f) extent of examination.

: .

Additionally, the use of RBI (see 5.2) is recommended when developing the required inspection plans, and to review recent operating history and MOC records that may impact inspection plans.

. ITP.

ITP ;

1. RBI 2. 3. MOC /()

5.1.1.3 The inspection plan should be developed using the most appropriate sources of information including those references listed in Section 2. Inspection plans shall be reviewed and amended as needed when variables that may impact damage mechanisms and/or deterioration rates areidentified. See API 574 for more information on the development of inspection plans.

()/-/

/-/:/ (1) (2)

5.1.2 Minimum Contents of an Inspection Plan

The inspection plan shall contain the inspection tasks and schedule required to monitor identified damage mechanisms and assure the pressure integrity of the piping systems.

(1) / (2) ,.

The plan should:

a) define the types of inspection needed, e.g. internal, external, on-stream (nonintrusive);(// - /).

b) identify the next inspection date for each inspection type;

c) describe the inspection methods and NDE techniques;

d) describe the extent and locations of inspection and NDE at CMLs;/ CML.

e) describe the surface cleaning requirements needed for inspection and examinations for each type of inspection;

: In-service , on-stream ()

f. describe the requirements of any needed pressure test (e.g. type of test, test pressure, test temperature, and duration);()(:,,,)

g. describe any required repairs if known or previously planned before the upcoming inspection. ,.

Generic inspection plans based on industry standards and practices may be used as a starting point in developing specific inspection plans. The inspection plan may or may not exist in a single document, however the contents of the plan should be readily accessible from inspection data systems.

:,,

.

5.1.3 Additional Contents of an Inspection Plan

Inspection plans may also contain other details to assist in understanding the rationale for the plan and in executing the plan. Some of these details may include:

1. describing the types of damage anticipated or experienced in the piping systems; ,.

2. defining the location of the expected damage; 3. defining any special access, and preparation needed.

.

5.2 RBI

5.2 RBI

RBI can be used to determine inspection intervals and the type and extent of future inspection/examinations. When the owner/user chooses to conduct an RBI assessment it shall include a systematic evaluation of both the probability and the associated consequence of failure, in accordance with API 580. API 581 details an RBI methodology that has all of the key elements defined in API 580.

RBI (API 580/581) - ,:

/

Identifying and evaluating potential damage mechanisms, current equipment condition and the effectiveness of the past inspections are important steps in assessing the probability of piping failure. Identifying and evaluating the process fluids, potential injuries, environmental damage, equipment damage and equipment downtime are important steps in assessing the consequence of piping failure. Identifying integrity operating envelopes for key process variables is an important adjunct to RBI (see 4.1).

,: . ;

: ,,,.: ,,,,,.

,RBI.

5.2.1 Probability Assessment

The probability assessment shall be in accordance with API 580 and shall be based on all forms of damage that could reasonably be expected to affect equipment in any particular service. Examples of those damage mechanisms are shown in Table 1. Additionally, the effectiveness of the inspection practices, tools, and techniques used for finding the potential damage mechanisms shall be evaluated. Other factors that should be considered in a probability assessment include: -1,. ,;

a) appropriateness of the materials of construction; b) equipment design conditions, relative to operating conditions;

c) appropriateness of the design codes and standards utilized;

,d) effectiveness of corrosion monitoring programs; .

e) the quality of maintenance and inspection quality assurance/quality control programs; //,

f) both the pressure retaining and structural requirements; (/,)?g) operating conditions both past and projected. (//)

Piping failure data will be important information for this assessment when conducting a probability assessment..

5.2.2 Consequence Assessment

The consequence of a release is dependent on type and amount of process fluid contained in the equipment. The consequence assessment shall be in accordance with API 580 and shall consider the potential incidents that may occur as a result of fluid release, the size of a potential release, and the type of a potential release (includes explosion, fire, or toxic exposure.) The assessment should also determine the potential outcomes that may occur as a result of fluid release or equipment damage, which may include: health effects, environmental impact, additional equipment damage, and process downtime or slowdown.

(, , )., , ,

RBIAPI 580

15 minutes break!

http://www3.nhk.or.jp/nhkworld/w/movie/

5.2.3 Documentation

API 580 . :

a. the most appropriate inspection and NDE methods, tools, and techniques;,,,

b. the extent of NDE (e.g. percentage of equipment to examine);(),

c. the interval for internal (where applicable), external, and on-stream inspections; - (/.

d. the need for pressure testing after damage has occurred or afterrepairs/alterations have been completed;//.

e. the prevention and mitigation steps to reduce the probability and consequence of equipment failure. (e.g. repairs, process changes, inhibitors, etc.). ,(,,)

API Standard 579-1/ASME FFS-1, Fitness-for-service , API RP 580, Risk-based Inspection

API 570 & referred standards.

-Regulatory

5.2.4 Frequency of RBI Assessments

When RBI assessments are used to set equipment inspection intervals, the assessment shall be updated after each equipment inspection as defined in API 580. The RBI assessment shall also be updated each time process or hardware changes are made or after any event occurs that could significantly affect damage rates or damage mechanisms. The maximum intervals between RBI assessments are outlined in 6.3.2, Table 2.

RBI :

API580

-2.

RBI (1) API570 (2)- ().

Q-Risk based inspections include which of the following:

a) Likelihood assessmentb) Consequence analysisc) Operating and inspection historiesd) All of the above

Q- An RBI assessment can be used to alter the inspection strategy provided:

a) The degradation methods are identifiedb) The RBI is fully documented.c) A third party conducts the RBId) Both A and B above

5.3 Preparation for Inspection

5.3.1 General

, : , . , [(OSHA)/.

API Recommended Practice 574, Inspection Practices for Piping System Components

5.3.2 Inspection Equipment Preparation 5.3.3 Communication 5.3.4 Piping Entry

/!

1. ,2. /. 3. .4. .5. . 6. .

()

1. .2. 3. /. 4. .5.

5.3.5 Records Review

Before performing any of the required inspections, inspectors shall familiarize themselves with prior history of the piping system for which they are responsible. In particular, they should review the piping systems prior inspection results, prior repairs, current inspection plan, and/or other similar service inspections. Additionally it is advisable to ascertain recent operating history that may affect the inspection plan. The types of damage and failure modes experienced by piping systems are provided in API 571 [5] and API 579-1/ASME FFS-1.

, :

(:) API 571API 579-1/ASME FFS-1.

5.4 Inspection for Types and Locations of Damage Modes of Deterioration and Failure/

5.4.1.1 .-1

5.4.1.2 ,, ; (1), (2), (3)(4) . /().

Competency Requirements?

Where were we?

Can we be entrusted?

http://news.zynews.com/2013-02/25/content_4123540_6.htm

API 571 Program InformationAPI 571 Certification program tests individuals knowledge and expertise in the field of Corrosion and Materials. The examination questions are derived from API RP 571 - Damage Mechanisms Affecting Fixed Equipment in the Refining Industry.

API welcomes highly specialized inspectors, corrosion engineers, chemical engineers and other professionals across the entire petrochemical industry to obtain this certification as a validation of their profound knowledge of corrosion processes.

Body of Knowledge for this examination consists of the entire RP 571 with the exception of the following sections: 1.1, 3.1, 4.1, 5.2.

Completely optional, yet adding significant value to your professional credentials it will show your employers and clients that you have obtained a high level of proficiency and understanding in this important field.

http://www.naceinstitute.org/cstm/education/certification/certsearch.aspx

5.4.2 Areas of Deterioration for Piping Systems

,.

a. injection points and mix pointsb. Dead-leg, c. CUI, d. soil air interfaces, e. service specific and localized corrosion, f. erosion and corrosion/erosion, /g. environmental cracking, h. contact point corrosion. ()

i) fatigue cracking,j) creep cracking,k) brittle fracture,l) freeze damage,m) contact point corrosion.

API 571API 574

5.5 General Types of Inspection and Surveillance

5.5 General Types of Inspection and Surveillance

/,.:

a. b. c. d. e. f. g. ()h.

6/./7(),.

5.5.1 Internal Visual Inspection

,,,, .

:, /.

Internal Visual Inspection

5.5.2 On-stream Inspection

API . (1) (2) .

: , (: ,).

API 574 .API Recommended Practice 574, Inspection Practices for Piping System Components

5.5.3 Thickness Measurement Inspection

, (1) (2) ...,.(), . : , UT,/,.

(), . : , UT,/,.

5.5.4 External Visual Inspection

,, ,,, /,.

,. , . , ( EMAT Lamb wave UT ) :

. ,,./.. , API 570.

5.5.5 External Inspection of Buried Equipment

a. b. c. d. (,,)e. f. g.

5.5.6 CUI Inspection

API 574 CUI CUI .CUI.

, . CUI,.

:

a.

b. c. ()d. e. f. g. .

5.5.7 Vibrating Piping and Line Movement Surveillance

.

(,, ,, ,) , /(MT/PT) .

, , .

5.5.8 Supplemental Inspection ,: thermography . .

Acoustic emission, acoustic leak detection, and thermography can be used for remote leak detection and surveillance., ,

Areas susceptible to localized erosion or erosion-corrosion should be inspected using visual inspection internally if possible or by using radiography. Scanning of the areas with UT is also a good technique and should be used if the line is larger than NPS 12.X. NPS 12 UT

A New Method for Radiographic Image Evaluation for Pipe Wall Thickness MeasurementJ. Belenkij, C. Mller (Nockemann), M. ScharmachBundesanstalt fr Materialforschung und Prfung (BAM), Unter den Eichen 87, 12205, Berlin, Germany. V. Vengrinovich, Institute of Applied Physics, Akademicheskaya str.16, 220072, Minsk, Belarus.

5.5.9 Injection Point Inspection

Injection points are sometimes subject to accelerated or localized corrosion from normal or abnormal operating conditions. Those that are may be treated as separate inspection circuits, and these areas need to be inspected thoroughly on a regular schedule. .

The selection of thickness measurement locations (TML) within injection point circuits subject to localized corrosion should be in accordance with the following guidelines:

a. establish TML on appropriate fittings within the injection point circuit,TML.

b. establish TML on the pipe wall at the location of expected pipe wall impingement of injected fluid,TML

c. establish TML at intermediate locations along the longer straight piping within the injection point circuit may be required,(),TML

d. establish TML at both the upstream and downstream limits of the injection point circuit. TML.

The preferred methods of inspecting injection points are radiography and/or UT, as appropriate, to establish the minimum thickness at each TML. Close grid ultrasonic measurements or scanning may be used, as long astemperatures are appropriate.

TML

-(1) , (2) . (). , TML.

TML-using radioscopy

Close grid UT nicmeasurements or scanning may be used, as long astemperatures are appropriate.

.().

Q-Injection points subject to accelerated or localised corrosion may be treated as _____.

a) The focal point of an inspection circuitb) Separate inspection circuitsc) Piping that must be renewed on a regular scheduled) Locations where corrosion inhibitors must be used

Q- The recommended upstream limit of inspection of an injection point is a minimum of:

a) 12 feet or 3 pipe lengths whichever is smallerb) 12 inches or 3 pipe diameters whichever is smallerc) 12 inches or 3 pipe diameters whichever is greaterd) 12 feet or 3 pipe lengths which is greater

Q- The recommended upstream limit of inspection of an injection point for an 8 inches catalytic line is a minimum of:

a) 12 feet or 3 pipe lengths whichever is smallerb) 12 inches or 3 pipe diameters whichever is smallerc) 24 inchesd) 12 feet or 3 pipe lengths which is greater

Q- The recommended downstream limit of inspection of an injection point is a minimum of;

a) Second change in flow direction past the injection point, or 25 feet beyond the first change in flow direction whichever is less

b) Second change in flow direction past the injection point, or 25 feet beyond the first change in flow direction whichever is greater

c) Second change in flow direction past the injection point, or 25 inches beyond the first change in flow direction whichever is less

d) Second change in flow direction past the injection point, or 25 inches beyond the first change in flow direction whichever is greater.

Q- Select thickness measurement locations (TMLs) within injection point circuits subjected to localised corrosion according to the following guidelines. Select the one that does not belong.

a) Establish TMLs on appropriate fittings within the injection point circuit.b) Establish at least one TML at a location at least 25 feet beyond the

downstream limit of the injection point.c) Establish TMLs on the pipe wall at location of expected pipe wall

impingement or injected fluid.d) Establish TMLs at both the upstream and downstream limits of the

injection point circuit.

Q- What are the preferred methods of inspecting injection points ?

a) Radiography and / or ultrasonicb) Hammer test and / or radiographc) Ultrasonic and / or liquid penetrantd) Liquid penetrant and / or eddy current.

17- During periodic scheduled inspections, more extensive inspection should be applied to an area beginning ______ upstream of the injection nozzle and continuing for at least ______ pipe diameters downstream of the injection point.

a) 10 inches, 20b) 12 feet, 10c) 12 inches, 10d) 10 feet, 10

18- Why should deadlegs in piping be inspected? (API574-7.4.3)

a) API 510 mandates the inspection of deadlegsb) Acid products and debris build up in deadlegsc) The corrosion rate in deadlegs can vary significantly from

adjacent active piping.d) Caustic products and debris build up in deadlegs.

5.6 CMLs

5.6.1 General

API 574API 571CMLS: CML .CML:

(CUI)

5.6.2 CML Monitoring CML

CMLS,; CML. ,,/,CMLs . olefin plant cold side piping, anhydrous ammonia piping, clean noncorrosive hydrocarbon product, or high-alloy piping for product purity.,,, .

The (1) thinnest reading or an (2) average of several measurement readings taken within the area of a examination point shall be recorded and used to calculate corrosion rates, remaining life, and the next inspection date in accordance with Section 7.

TML/CML (1) (2) (, ) ISOCMLs .

ISOCMLs .

5.6.3 CML Selection CML , .

CML , : (1) , (2) (3) (4) . CMLs , .

A number of corrosion processes common to refining and petrochemical units are relatively uniform in nature, resulting in a fairly constant rate of pipe wall reduction independent of location within the piping circuit, either axially orcircumferentially. Examples of such corrosion phenomena include high temperature sulfur corrosion and sour water corrosion (provided velocities are not so high as to cause local corrosion/erosion of elbows, tees, and other similar items).

CML

(/, ,) CML.

- High-temperature sulfur corrosion- Sour water corrosion

CMLs :

,,,///,,.

CMLs

,,/.

CMLs can be eliminated for piping systems with any of the following characteristics:

CMLs :

/

CMLsCMLs .

5.7 Condition Monitoring Methods

5.7 Condition Monitoring Methods 5.7.1 UT and RT /

ASME BPVC Section V, Article 23, and Section SE797.

NPS 2, ;/.

150oF(65oC ), //.

NPS 1;,.,UT,.

Profile Radiography

,

, , , (), , , (150oF/65oC), , ,1 /8(3.2), .

,,.

, .

5.7.2 Other NDE Techniques for Piping Systems

.,,,. API 571.

ASME BPVC, Section V, Article 7, ASME BPVC, Section V, Article 6, ASME BPVC, Section V, Article 2, ASME BPVC, Section V, Article 4, 5, 23, ACFM, ASME BPVC, Section V, Article 8, Metallographic Replica, . ASME BPVC, Section V, Article 11 & 12, . Infrared thermography, ASME BPVC Section V, Article 10, UT (LRUT-Lamb).

5.7.3 Surface Preparation for NDE

.

5.7.4 UT Shear Wave Examiners

/,

,, / FFS

5.8 Pressure Testing of Piping Systems - General-

5.8 Pressure Testing of Piping SystemsGeneral

:

:

ASME B31.3. API 574, API 579-1/ ASME FFS-1 &

ASME PCC-2. /.

:

,90

SMYS ()

5.8.1 Test Fluid

,,.

. ,120oF / 49oC

SS 300()

(250ppm,) (50ppm-)

For sensitized austenitic stainless steel piping subject to polythionic stress corrosion cracking, consideration should be given to using an alkaline-water solution for pressure testing (see NACE RP 0170). (NACE RP 0170)

NACE RP0170-2004_

After testing is completed, the piping should be thoroughly drained (all high-point vents should be open during draining), air blown, or otherwise dried. If potable water is not available or if immediate draining and drying is not possible, water having a very low chloride level, higher pH (>10), and inhibitor addition may be considered to reduce the risk of pitting and microbiologically induced corrosion.

, ,.,.

, ,;

pH(>10),

5.8.2 Pneumatic Pressure Tests

A pneumatic (or hydro-pneumatic) pressure test may be used when it is impracticable to hydrostatically test due to temperature, structural, or process limitations. However, the potential risks to personnel and property of pneumatic testing shall be considered when carrying out such a test. As a minimum, the inspection precautions contained in ASME B31.3 shall be applied in any pneumatic testing.

,,,.

, . ASME B31.3.

5.8.3 Test Temperature and Brittle Fracture Considerations:

,,,,()(,,),.

,: (1) , (2) ,25% (3) 8 ksi (). ,.

21/4Cr-1Mo .

:,,,, , .

Sigma Phase

Graphitization

http://www.ndt.net/article/wcndt00/papers/idn022/idn022.htm

Evaluating the condition & remaining life of older power plantsEyckmans Marc - Product ManagerLaire Charles- Product ManagerD'ambros Laurent Engineer LABORELEC - BELGIUM Failure analysis & Material assessment in plants

:,:

2 (5 cm) 30F (17C) MDMT

2 (5 cm)10 F ( 6C) MDMT

120 F(50C), .

5.8.4 Precautions and Procedures

MAWP .,,

ASME B31.3 , ,,, ,,,,.

ASME B16.34 (,)

,

, ,.

5.8.5 Pressure Testing Alternatives

,,./. UT..

:ASME B31 Code Case 179/181, Tie-in joint ().

5.9 Material Verification and Traceability

. API 578.

,,/ 100%PMI .

, .

:

, , :

,PMI(retroactive).

().

API 578,,

/,,

,,.

5.10 Inspection of Valves

,, . , ,.

.(1) (2)-

When valve body and/or closure pressure tests are performed after servicing, they should be conducted in accordance with API 598.

- /- API 598- API Standard 598, Valve Inspection and Testing .

;, /. .

;, .,.

5.11 In-service Inspection of Welds

,, .

,,-. ,,. API 577 .

.

,(),.

.

http://www.bam.de/en/kompetenzen/fachabteilungen/abteilung_8/fg83/fg83_ag5.htm

Crack-like flaws and environmental cracking shall be assessed by an engineer in accordance with API 579-1/ASME FFS-1 and/or corrosion specialist. Preferential weld corrosion shall be assessed by the inspector.

Issues to consider. when assessing the quality of existing welds include the following:

original fabrication inspection method and acceptance criteria; extent, magnitude, and orientation of imperfections; length of time in service; operating versus design conditions; presence of secondary piping stresses (residual and thermal); potential for fatigue loads (mechanical and thermal); primary or secondary piping system; potential for impact or transient loads; potential for environmental cracking; repair and heat treatment history; weld hardness.

;

(crack-like & SCC) API 579-1/ASME FFS-1

(preferential weld corrosion) .

, ,/, , , - (), , , , , , ,

ASME B31.3 , 100%,,, .,.

, ., ASME B31.3

5.12 Inspection of Flanged Joints

, /. . ,. , ,,, ,,/.

.. ASME/ASTM. ASME PCC- 1

ASME PCC-1, Guidelines for Pressure Boundary Bolted Flange Joint Assembly

5.13 Inspection Organization Audits

,

//.

() () / , ,,.

42) Different types of inspection and surveillance are appropriate depending on the circumstances and the piping system. Pick the one that does not belong in the following list:-

a) Internal and external visual inspectionb) Thickness measurement inspectionc) Vibrating piping inspectiond) Chemical analysis inspection

43) Internal visual inspections are ______ on piping unless it is a large diameter transfer line, duct, catalyst line or other largediameter piping system.

a) The most effective inspectionb) The most useful means of inspectionc) Not normally performedd) The major means of inspection

44) Name an additional opportunity for a normal non-destructive internal inspection of piping.

a) When the piping fails and the interior is revealedb) When maintenance asks for an internal inspectionc) When piping flanges are disconnectedd) When a fire occurs and the pipe is in the fire

45) Why is thickness measurement inspection performed?

a) To satisfy jurisdictional requirementsb) To determine the internal condition and remaining thickness of the

piping componentsc) To determine the external condition and amount of deposits inside

the pipingd) To satisfy heat transfer requirements of the piping

46) Who performs a thickness measurement inspection?

a) The operator or control manb) The inspector or examinerc) The maintenance workers or supervisord) The Jurisdiction or OSHA

47) When corrosion product build-up is noted during an external visual inspection at a pipe support contact area, lifting of such supports may be required for inspection. When doing this, care should be:

a) Exercised if the piping is in-serviceb) Used when determining the course of actionc) Practiced so as not to disturb the supportsd) Taken that a complete record of the problem is made

8.What is the best thing to do with dead legs that are no longer required?

a) Ultrasonically inspect oftenb) Radiograph oftenc) Inspect oftend) Remove them

9) Risk based inspections include which of the following:

a) Likelihood assessmentb) Consequence analysisc) Operating and inspection historiesd) All of the above

10) An RBI assessment can be used to alter the inspection strategy provided:

a) The degradation methods are identifiedb) The RBI is fully documented.c) A third party conducts the RBId) Both A and B above

11) Which one of the following is not a specific type of an area ofdeterioration?

a) Rectifier performanceb) Injection pointsc) Deadlegsd) Environmental cracking

6. For a typical injection point pipe circuit starts upstream of injection point from a distance of

a) 3 times pipe diameter or 12 inches which ever is greater b) 2 times pipe diameter or 12 inches which ever is greater c) Fixed 12 inches irrespective of pipe diameter d) None of the above

15.Select thickness measurement locations (TMLs) within injection point circuits subjected to localised corrosion according to the following guidelines. Select the one that does not belong.

a) Establish TMLs on appropriate fittings within the injection point circuit. b) Establish at least one TML at a location at least 25 feet beyond the

downstream limit of the injection point. c) Establish TMLs on the pipe wall at location of expected pipe wall

impingement or injected fluid. d) Establish TMLs at both the upstream and downstream limits of the

injection point circuit.

12) Injection points subject to accelerated or localised corrosion may be treated as __________.

a) The focal point of an inspection circuitb) Separate inspection circuitsc) Piping that must be renewed on a regular scheduled) Locations where corrosion inhibitors must be used

13) The recommended upstream limit of inspection of an injection point is a minimum of:

a) 12 feet or 3 pipe lengths whichever is smallerb) 12 inches or 3 pipe diameters whichever is smallerc) 12 inches or 3 pipe diameters whichever is greaterd) 12 feet or 3 pipe lengths which is greater

14) The recommended downstream limit of inspection of an injection point is a minimum of

a) Second change in flow direction past the injection point, or 25 feet beyond the first change in flow direction whichever is less

b) Second change in flow direction past the injection point, or 25 feet beyond the first change in flow direction whichever is greater

c) Second change in flow direction past the injection point, or 25 inches beyond the first change in flow direction whichever is less

d) Second change in flow direction past the injection point, or 25 inches beyond the first change in flow direction whichever is greater.

16) What are the preferred methods of inspecting injection points ?

a) Radiography and / or ultrasonicb) Hammer test and / or radiographc) Ultrasonic and / or liquid penetrantd) Liquid penetrant and / or eddy current.

17) During periodic scheduled inspections, more extensive inspection should be applied to an area beginning __________ upstream of the injection nozzle and continuing for at least __________ pipe diameters downstream of the injection point.

a) 10 inches, 20b) 12 feet, 10c) 12 inches, 10d) 10 feet, 10

18) Why should deadlegs in piping be inspected?

a) API 510 mandates the inspection of deadlegsb) Acid products and debris build up in deadlegsc) The corrosion rate in deadlegs can vary significantly

from adjacent active piping.d) Caustic products and debris build up in deadlegs.

19) Both the stagnant end and the connection to an active line of a deadleg should be monitored. In a hot piping system, why does the high point of a deadleg corrode and need to be inspected?

a) Corrosion occurs due to directed currents set up in the deadlegb) Erosion occurs due to convective currents set up in the deadleg.c) Corrosion occurs due to convective currents set up in the deadlegd) Erosion occurs due to directed currents et up in the deadleg

20)What is the best thing to do with deadlegs that are no longer in service?

a) Ultrasonically inspect oftenb) Radiograph oftenc) Inspect oftend) Remove them

21)What are the most common forms of corrosion under insulation (CUI).

a) Localised corrosion of non-ferrous metals and chloride stress corrosion cracking of carbon steel.

b) Localised corrosion of chrome-moly steel and chloride stress corrosion cracking of ferritic stainless steel.

c) Localised corrosion of carbon steel and chloride stress corrosion cracking of austenitic stainless steel

d) Localised corrosion of nickel-silicon alloy and caustic stress corrosion of austenitic stainless steel

22)What climatic area may require a very active program for corrosion under insulation?

a) Cooler northern continent locations.b) Cooler direr, mid-continent locationsc) Warmer, marine locationsd) Warmer drier, desert locations

23)Certain areas and types of piping systems are potentially more susceptible to corrosion under insulation. Which of the items listed is not susceptible to CUI?

a) Areas exposed to mist over-spray from cooling water towers.b) Carbon steel piping systems that normally operate in-service above 250

degrees but are in intermittent service.c) Deadlegs and attachments that protrude from insulated piping and operate at

a different temperature than the temperature of the active line.d) Carbon steel piping systems, operating between 250 degrees F and 600

degrees F.

24) What location is subject to corrosion under insulation and inspection contributes to it?

a) Locations where pipe hangers and other supports exist.b) Locations where insulator has been stripped to permit inspection of the piping.c) Locations where insulation plugs have been removed to permit piping thickness

measurements.d) Locations where there is damaged or missing insulation jacketing.

25) Soil-to-air (S/A) interfaces for buried piping are a location where localised corrosion may take place. If the buried part is excavated for inspection, how deep should the excavation be to determine if there is hidden damage?

a) 12 to 18 inchesb) 6 to 12 inchesc) 12 to 24 inchesd) 6 to 18 inches

26) At concrete-to-air and asphalt-to-air interfaces of buried piping without cathodic protection, the inspector look for evidence that the caulking or seal at the interface has deteriorated and allowed moisture ingress. If such a condition exists on piping systems over __________ years old, it may be necessary to inspect for corrosion beneath the surface before resealing the joint.

a) 8b) 5c) 15d) 10

27) An example of service-specific and localised corrosion is:-

a) Corrosion under insulation in areas exposed to steam ventsb) Unanticipated acid or caustic carryover from processes into non-alloyed

pipingc) Corrosion in deadlegsd) Corrosion of underground piping at soil-to-air interface where it

ingresses or egresses.

28)Erosion can be defined as: (2013 June)

a) Galvanic corrosion of a material where uniform losses occurb) Removal of surface material by action of numerous impacts of solid or liquid

particlesc) Gradual loss of material by a corrosive medium acting uniformly on the

material surfaced) Pitting on the surface of a material to the extent that a rough uniform loss

occurs

29)A combination of corrosion and erosion results in significantly greater metal loss that can be expected from corrosion or erosion alone. This type of loss occurs at: (2013 June)

a) High-velocity and high-turbulence areasb) Areas where condensation or exposure to wet hydrogen sulphide or

carbonates occurc) Surface-to-air interfaces f buried pipingd) Areas where gradual loss of material occurs because of a corrosive medium

30) Environmental cracking of austenite stainless steels is caused many times by:-

a) Exposing areas to high-velocity and high-turbulence streamsb) Excessive cyclic stresses that are often very lowc) Exposure to chlorides from salt water, wash-up water, etc.d) Creep of the material by long time exposure to high temperature and stress

31) When the inspector suspects or is advised that specific piping circuits may be susceptible to environmental cracking, the inspector should:

a) Call in a piping engineer for consultation.b) Investigate the history of the piping circuit.c) Obtain advice from a Metallurgical Engineer.d) Schedule supplemental inspections.

32) If environmental cracking is detected during internal inspection of pressure vessels, what should the inspector do? (2013 June)

a) The inspector should designate appropriate piping spools upstream and downstream of the vessel to be inspected if piping is susceptible to environmental cracking.

b) The inspector should consult with a metallurgical engineer to determine extent of the problems

c) The inspector should review history of adjacent piping to determine if it has ever been affected.

d) The inspector should consult with a piping engineer to determine the extent of the problems.

33)If external or internal coatings or refractory liners on a piping circuit are in good condition, what should an inspector do? (2013 June)

a) After inspection, select a portion of the liner for removalb) The entire liner should be removed for inspectionc) Selected portions of the liner should be removed for inspectiond) After inspection, if any separation, breaks, holes or blisters are found, it

may be necessary to remove portions of the lining to determine the condition under it.

34)What course of action should be followed it a coating of coke isfound on the interior of a large pipe of a reactor on a Fluid Catalytic Cracking Unit? (2013 June)

a) Determine whether such deposits have active corrosion beneath them. If corrosion is present, thorough inspection in selected areas may be required.

b) The coke deposits should be removed from the area for inspection.c) The coke deposits may be ignored the deposits will probably

protect the line from corrosion.d) Consult with a Process Engineer and a Metallurgist on the necessity

of removing the coke deposits.

35)Fatigue cracking of piping systems may result from

a) Embrittlement of the metal due to it operating below its transition temperatureb) Erosion or corrosion / erosion that thin the piping where it cracksc) Excessive cyclic stresses that are often well below the static yield strength of the

materiald) Environmental cracking caused by stress corrosion due to the presence of

caustic, amine, or other substance.

36)Where can fatigue cracking typically be first detected?

a) At points of low-stress intensification such as reinforced nozzlesb) At points of high-stress intensification such as branch connectionsc) At points where cyclic stresses are very lowd) At points where there are only bending or compressive stresses.

37) What are the preferred NDE methods for detecting fatigue cracking? (2013 June)

a) Eddy current testing ultrasonic A-scan testing, and / or possibly hammer testing

b) Liquid penetrant testing, magnetic particle testing and / or possibly acoustic emission testing.

c) Visual testing, eddy current testing and / or possibly ultrasonic testingd) Acoustic emission testing, hydro-testing, and / or possibly ultrasonic testing.

38) Creep is dependent on:

a) Time, temperature, and stressb) Material, product contained, and stressc) Temperature, corrosive medium, and loadd) Time, product contained and load

39)An example of where creep cracking has been experienced in the industry is in the problems experienced with cracking of 1.25 % Chrome steels operating at temperatures above __________ F.

a) 500b) 900c) 1000d) 1200

40)Brittle fracture can occur in carbon, low-alloy and other ferritic steels at or below __________.

a) 140 degreeb) Ambientc) 100 degreed) 30 degree

41)Water and aqueous solutions in piping systems may freeze and cause failure because of the

a) Expansion of these materialsb) Contraction of these materialsc) Construction of these materialsd) Decrease of these materials

42)Different types of inspection and surveillance are appropriate depending on the circumstances and the piping system. Pick the one that does not belong in the following list:-

a) Internal and external visual inspectionb) Thickness measurement inspectionc) Vibrating piping inspectiond) Chemical analysis inspection

43)Internal visual inspections are __________ on piping unless it is a large diameter transfer line, duct, catalyst line or other large diameter piping system.

a) The most effective inspectionb) The most useful means of inspectionc) Not normally performedd) The major means of inspection

44)Name an additional opportunity for a normal non-destructive internal inspection of piping.

a) When the piping fails and the interior is revealedb) When maintenance asks for an internal inspectionc) When piping flanges are disconnectedd) When a fire occurs and the pipe is in the fire

45)Why is thickness measurement inspection performed?

a) To satisfy jurisdictional requirementsb) To determine the internal condition and remaining thickness of the piping

componentsc) To determine the external condition and amount of deposits inside the

pipingd) To satisfy heat transfer requirements of the piping

46)Who performs a thickness measurement inspection?

a) The operator or control manb) The inspector or examinerc) The maintenance workers or supervisord) The Jurisdiction or OSHA

47)When corrosion product build-up is noted during an external visual inspection at a pipe support contact area, lifting of such supports may be required for inspection. When doing this, care should be: (2013 June)

a) Exercised if the piping is in-serviceb) Used when determining the course of actionc) Practiced so as not to disturb the supportsd) Taken that a complete record of the problem is made

48)Qualified operating or maintenance personnel also may conduct external visual inspections when:

a) Satisfactory to the owner-userb) Acceptable to the inspectorc) Agreeable to the maintenance supervisord) Permissible to the operation supervisor

49)Who would normally report vibrating or swaying piping to engineering or inspection personnel?

a) Operating personnelb) Maintenance personnelc) Jurisdictional personneld) OSHA personnel

50)Thermography is used to check for:

a) Vibrating sections of the piping systemb) Detecting localised corrosion in the piping systemc) Abnormal thermal expansion of piping systemsd) Hot spots in refractory lined piping systems

51)Thickness measurement locations (TMLs) are specific _______ along the piping circuit where inspections are to be made

a) Pointsb) Areasc) Itemsd) Junctures

52)The minimum thickness at each TML can be located by:

a) Electromagnetic techniquesb) Ultrasonic scanning or radiographyc) Hammer testingd) MT and / or PT

53)Where appropriate, thickness measurements should include measurements at each of __________ on pipe and fittings: (2013 June)

a) Two quadrantsb) Three locationsc) Four quadrantsd) Six points

54)Where should special attention be placed when taking thickness measurements of an elbow?

a) The outlet endb) The inlet endc) The inside and outside radiusd) The sides

55)TMLs should be marked on inspection drawings and __________ to allow repetitive measurements

a) On the inspectors notesb) On a computer systemc) On the piping systemd) On maintenance department charts

56)What is taken into account by an experienced inspector when selecting TMLs?

a) The amount of corrosion expectedb) The patterns of corrosion that would be expectedc) The number and the cost of reading the TMLsd) Whether the TMLs are easily accessed

57) In theory, a piping circuit subject to perfectly uniform corrosion could be adequately monitored with __________ TMLs.

a) 1b) 2c) 3d) 4

58) More TMLs should be selected for piping systems with any of the following characteristics:

a) Low potential for creating a safety or environmental emergency in the event of a leak.

b) More complexity in terms of fittings, branches, deadlegs, injection points, etc.

c) Relatively non-corrosive piping systemsd) Long, straight-run piping systems

59)Fewer TMLs can be selected for piping systems with any of the following characteristics:

a) More complexity in terms of fittings, branches, deadlegs, injection points, etc.

b) Higher expected or experienced corrosion ratesc) Long, straight-run piping systemsd) Higher potential for localised corrosion

60)TMLs can be eliminated for piping systems with the following characteristics:

a) Higher potential for creating a safety or environmental emergency in the event of a leak.

b) Low potential for creating a safety or environmental emergency in the event of a leak.

c) Extremely low potential for creating a safety of environmental emergency in the event of a leak.

d) More complexity in terms of fittings, branches, deadlegs,injection points, etc.

61)What is usually the most accurate means for obtaining thickness measurements on installed pipe larger than NPS 1?

a) MTb) UTc) PTd) ET

62)What thickness measuring technique does not require the removal of some external piping insulation?

a) AEb) UTc) ETd) RT

63) When ultrasonic thickness measurements are taken above __________ degrees F, instruments couplants, and procedures should be used that will result in accurate measurements at the higher temperature

a) 150b) 175c) 200d) 250

64)Typical digital thickness gages may have trouble measuring thickness less than __________ inches.

a) 0.2188b) 0.1875c) 0.1562d) 0.1250

65)When pressure testing of piping systems are conducted, they shall be performed in accordance with the requirements of:

a) ASME B31.3b) ASME B&PV Code, Section VIIIc) SA B16.5d) API 510

66)If a lower pressure test (lower than prescribed by code) is used only for tightness of piping systems, the __________ may designate the pressure

a) Owner-userb) Inspectorc) Jurisdictiond) Contractor

67)The preferred medium for a pressure test is __________:

a) Steamb) Airc) Waterd) Hydrocarbon

68)If a non-toxic hydrocarbon (flammable) is used as the test medium, the liquid flash point shall be at least __________ F or greater.

a) 95b) 100c) 110d) 120

69)Piping fabricated of or having components of 300 series stainless steel should be tested with __________.

a) Water with a pH of 4b) Water with a pH of 6c) Water with a chloride content of less than 400 ppm chloridesd) Steam condensates

70)For sensitised austenitic stainless steel, piping subject to polythionic stress corrosion cracking, consideration should be given to using __________ for pressure testing

a) An acidic-water solutionb) An alkaline-water solutionc) A water with a pH of 5d) A water with a pH of 4

71)When a pipe requires post weld heat treatment, when should the pressure test be performed?

a) During heat treatmentb) Before any heat treatmentc) After any heat treatmentd) No test is required

72)During a pressure test, where test pressure will exceed the set pressure of the safety relieve valve or valves on a piping system, the safety relief valve or valves should be __________ when carrying out the test.

a) Altered by screwing down the adjusting screwb) Reset to exceed the test pressurec) Checked or testedd) Removed or blanked

73)When using block valves to isolate a piping system for pressure test, what precaution should be taken?

a) Do not use a globe valve during a testb) Make sure the packing gland of the valve is tightc) Do not exceed the permissible seat pressure of the valved) Check the bonnet bolts to make sure they are tight

74)Several methods may be used to verify that the correct alloy piping is in a system. Pick the incorrect method from the list below:

a) Holographyb) Optical spectrographic analyserc) X-ray fluorescent analyserd) Chemical spot checking

75)Name a part of a piping system that thickness measurements are not normally routinely taken.

a) Elbowsb) Expansion loopsc) Teesd) Valves

76)If environmental cracking is found during in-service inspection of welds, who assesses the problem?

a) Owner-userb) Inspectorc) Piping Engineerd) Metallurgist

77)If an inspector finds an imperfection in an original fabrication weld and analysis is required to assess the impact of the weld quality on piping integrity, which of the following may perform the analysis?

a) An API 510 inspector, WPS inspector, A Pressure Vessel Engineerb) An API 570 inspector, a CWI inspector, a piping engineerc) An owner-user, a B31.3 inspector, an industrial engineerd) A Jurisdictional representative, a API 574 inspector, a Chemical

Engineer

78) According to API 570, some welds in a piping system that has been subjected to radiography according to ASME B31.3:

a) Will meet random radiograph requirements and will perform satisfactorily in-service without a hydrofest

b) Will not meet random radiograph requirements, and will not perform satisfactorily in-service even though hydrotested.

c) Will meet random radiograph requirements, and will not perform satisfactorily in-service after a hydrotest

d) Will not meet random radiograph requirements, but will still perform satisfactorily in-service after being hydrotested.

ASMEB31.3, 344.1.3random spot examination:3 a specified partial examination of a percentage of a specified kind of item in a designated lot of piping2

2 A designated lot is that quantity of piping to be considered in applying the requirements for examination in this Code. The quantity or extent of a designated lot should be established by agreement between the contracting parties before the start of work. More than one kind of designated lot may be established for different kinds of piping work.

3 Random or spot examination will not ensure a fabrication product of a prescribed quality level throughout. Items not examined in a lot of piping represented by such examination may contain defects which further examination could disclose. Specifically, if all radiographically disclosable weld defects must be eliminated from a lot of piping, 100% radiographic examination must be specified.

79)How should fasteners and gaskets be examined to determine whether they meet the material specifications:

a) All fasteners and gaskets should be checked to see if their markings are correct according to ASME and ASTM standards

b) A representative sample of the fasteners and gaskets should be checked to see if their markings are correct according to ASME and ASTM standards

c) Purchase records of all fasteners and gaskets should be checked to see if the fasteners and gaskets meet ASME and ASTM standards

d) A representative sample of the purchase records of fasteners and gaskets should be checked to see if the fasteners and gaskets meet ASME and ASTM standards.

81.What course of action is called for when an inspector finds a flange joint that has been clamped and pumped with sealant? (2013 June)

a) Disassemble the flange joint; renew the fasteners and gaskets. The flanges may also require renewal or repair.

b) Renew all the fasteners and renew the gasket if leakage is still apparent.c) Check for leakage at the bolts; if re-pumping is contemplated, affected

fasteners should be renewed.d) No action is required since the joint has been pumped with a sealant.

80) When checking flange and valve bonnet bolts for corrosion, what type of NDT is usually used?

a) RTb) UTc) VTd) AE

http://photobucket.com/images/charliechong?page=1

Sec~66 Interval/Frequency and Extent of Inspection/

6 Interval / Frequency and Extent of Inspection/6.1 General 6.2 Inspection During Installation and Service Changes

6.3 Piping Inspection Planning 6.4 Extent of Visual External and CUI Inspections CUI 6.5 Extent of Thickness Measurement Inspection 6.6 Extent of Small-bore, Auxiliary Piping, and Threaded-connections

Inspection ,6.7 Inspection and Maintenance of Pressure-relieving Devices (PRD)

6.1 General

6.1 General

:

API 570 ; ,,,.

:

/.. API 580,,

:

,,.

:

,(/) .

6.2 Inspection During Installation and Service Changes

6.2.1 Piping Installation

, (ASME B31.3) . :

1. ,//, , , ;

2.

, CML/TML:

, .

6.2.2 Piping Service Change

(1) (,, ) ,, .

(2) (3) ,,()..

6.3 Piping Inspection Planning

6.3.1 General

(-1)

API 571. Section 6.3.4 ,.

/. (1) (2) (3) (4) (5) .

RBI -(1) (2)

,, -, ,.

6.3.2 RBI for Inspection Planning RBI

An RBI assessment may be used to increase or decrease the inspection limits described in Table 2. Similarly, the extent of inspection may be increased or decreased beyond the targets in Table 3, by an RBI assessment. When used to increase inspection interval limits or the extent of inspection, RBI assessments shall be conducted at intervals not to exceed the respective limits in Table 2, or more often if warranted by process, equipment, or consequence changes. These RBI assessments shall be reviewed andapproved by a piping engineer and authorized piping inspector at intervals not to exceed the respective limits in Table 2, or more often if warranted by process, equipment or consequence changes.

RBI 2, RBI2,,,.

RBI -(1) (2)

6.3.3 Inspection Intervals

RBI() :

-2.

,: , , ,.

6.3.4 Piping Service Classes 6.3.4.1 General

, . , ,-.

: : RBI(failure scenario), (probability).

Damage mechanism failure mode failure Scenario Consequence

: : RBI COF(failure scenario), (probability) . :. ;Damage mechanism () failure mode () failure Scenario (x) Consequence (:)

;

Class 1,2,3,4 + +

+,+

: S/A , CUI, +++

6.3.4.2 Class 1Services with the highest potential of resulting in an immediateemergency if a leak were to occur are in Class 1. Such an emergency may be safety or environmental in nature.

Class 1, .

Class 1:

(a, b, c)

: ,,, 3%,,

+ plus: ,, ,

+ plus(

1. Flammable services that can auto-refrigerate and lead to brittle fracture.: (),,

2. Pressurized services that can rapidly vaporize during release, creating vapors that can collect and form an explosive mixture, such as C2, C3, and C4 streams. Fluids that can rapidly vaporize are those with atmospheric boiling temperatures below 50oF (10oC) or where the atmospheric boiling point is below the operatingtemperature (typically a concern with high-temperature services).: ,50o F(10oC) (),

3. Hydrogen sulfide (greater than 3% weight) in a gaseous stream.3%,

4. Anhydrous hydrogen chloride ,5. Hydrofluoric acid ,6. Piping over or adjacent to water and piping over public throughways (refer to

Department of Transportation and U.S. Coast Guard regulations for inspection of over water piping). ,

7. Flammable services operating above their auto-ignition temperature. : .

6.3.4.3 Class 2

Services not included in other classes are in Class 2. This classification includes the majority of unit process piping and selected off-site piping. Typical examples of these services include but are not necessarily limited to those containing the following:

a) on-site hydrocarbons that will slowly vaporize during release such as those operating below the flash point, ;

b) hydrogen, fuel gas, and natural gas, ,,,c) on-site strong acids and caustics. .

,. (1,3,4)2.

Class 2: .

6.3.4.4 Class 3Services that are flammable but do not significantly vaporize when they leak and are not located in high-activity areas are in Class 3. Services that are potentially harmful to human tissue but are located in remote areas may be included in this class.

Class 3,, .(?,?,?),.

Services that are potentially harmful to human tissue but are located in remote areas may be included in this class. (???)

1. on-site hydrocarbons that will not significantly vaporize during release such as those operating below the flash point;: ,

2. distillate and product lines to and from storage and loading;,,

3. tank farm piping; ,4. off-site acids and caustics. .

a) steam and steam condensate; b) air; c) nitrogen; d) water, including boiler feed water, stripped sour water;

,;,e) lube oil, seal oil; ,f) plumbing and sewers: g) ASME B31.3, Category D services; D

6.3.4.5 Class 4 / 4 Services that are essentially nonflammable - and nontoxic are

in Class 4, as are most utility services. Inspection of Class 4 piping is optional and usually based on reliability needs and business impacts as opposed to safety or environmental impact. Examples of Class 4 service include, but are not necessarily limited to those containing the following:

Class 4

Class 4

,

ASME B31.3, Category D services

ASME B31.3 Category D Fluid Service: a fluid service in which all the following apply:

1. the fluid handled is nonflammable, nontoxic, and not damaging tohuman tissues as defined in para. 300.2,,

2. the design gage pressure does not exceed 1035 kPa (150 psi)10

3. the design temperature is from -29oC (-20oF) through 186oC (366oF) -29oC ~ +186oC

6.4 Extent of Visual External & CUI Inspections & CUI

http://www.ndt.net/article/wcndt00/papers/idn751/idn751.htmhttp://www.ndt.net/article/0298/twomey/twomey.htm

http://www.tmqc.com.tw/motion.asp?siteid=1002958&menuid=17737&postid=16895&csw=1

Guided Wave Ultrasonic Testing (GWUT)

External visual inspections, including inspections for CUI, should be conducted at maximum intervals listed in Table 2 to evaluate items such as those in API 574. Alternatively, external visual inspection intervals can be established by using a valid RBI assessment conducted in accordance with API 580.

2, RBI

Corrosion under insulation

API574, 7.4.4.1 Insulated Piping Systems Susceptible to CUI

7.4.4 CUI

External inspection of insulated piping systems should include a review of the insulation system integrity for conditions that could lead to CUI and signs of ongoing CUI. API 570 documents the requirements of a CUI inspection program. Sources of moisture can include rain, water leaks, condensation, deluge systems, and cooling towers. The two forms of CUI are localized corrosion of carbon steel and chloride SCC of austenitic stainless steels. See API 571 for additional details on CUI mechanisms. This section provides guidelines for identifying potential CUI areas for inspection. The extent of a CUI inspection program may vary depending on the local climate. Marine locations in warmer areas may require a very active program, whereas cooler, drier, mid-continent locations may not need as extensive a program.

7.4.4.1 Insulated Piping Systems Susceptible to CUI

Certain areas of piping systems are potentially more susceptible to CUI, including:

a) those exposed to mist over-spray from cooling water towers;b) those exposed to steam vents;c) those exposed to deluge systems;d) those subject to process spills or ingress of moisture or acid vapors;e) carbon steel piping systems, including ones insulated for personnel protection, operating between 10F (12C) and 350F

(175C); CUI is particularly aggressive where operating temperatures cause frequent or continuous condensation and re-evaporation of atmospheric moisture;

f) carbon steel piping systems which normally operate in service above 350F (175C), but are in intermittent service;g) dead-legs and attachments that protrude from insulated piping and operate at a different temperature than the operating

temperature of the active line;h) austenitic stainless steel piping systems operating between 120F (60C) and 400F (205C) (susceptible to chloride SCC);i) vibrating piping systems that have a tendency to inflict damage to insulation jacketing providing a path for water ingress;j) steam traced piping systems that can experience tracing leaks, especially at tubing fittings beneath the insulation;k) piping systems with deteriorated insulation, coatings, and/or wrappings; bulges or staining of the insulation or jacketing

system or missing bands (bulges can indicate corrosion product buildup);l) piping systems susceptible to physical damage of the coating or insulation, thereby, exposing the piping to the environment.

API RECOMMENDED PRACTICE 574THIRD EDITION, NOVEMBER 2009

7.4.4.2 Typical Locations on Piping Circuits Susceptible to CUI The above noted areas of piping systems can have specific locations within them that are more susceptible to CUI. These areas include the following.

a) All penetrations or breaches in the insulation jacketing systems, such as:

dead-legs (vents, drains, etc.); pipe hangers and other supports; valves and fittings (irregular insulation surfaces); bolt-on pipe shoes; and steam and electric tracer tubing penetrations.

b) Termination of insulation at flanges and other piping components.c) Damaged or missing insulation jacketing.d) Insulation jacketing seams located on the top of horizontal piping or improperly lapped or sealed insulation jacketing.e) Termination of insulation in a vertical pipe.f) Caulking which has hardened, separated, or is missing.g) Low points in piping systems that have a known breach in the insulation system, including low points in long unsupported

piping runs.h) Carbon or low-alloy steel flanges, bolting, and other components under insulation in high-alloy piping systems.

Particular attention should be given to locations where insulation plugs have been removed to permit piping thicknessmeasurements on insulated piping. These plugs should be promptly replaced and sealed. Several types of removableplugs are commercially available that permit inspection and identification of inspection points for future reference.


API574, 7.4.4.1 Insulated Piping Systems Susceptible to CUI

:

1. those exposed to mist over-spray from cooling water towers;

2. those exposed to steam vents;

3. those exposed to deluge systems;

4. those subject to process spills or ingress of moisture or acid vapors;/

5. carbon steel piping systems, including ones insulated for personnel protection, operating between 10o F (12oC) and 350oF (175oC); CUI is particularly aggressive where operating temperatures cause frequent or continuous condensation and re-evaporation of atmospheric moisture;


6. carbon steel piping systems which normally operate in service above 350oF (175oC), but are in intermittent service; (-)

7. dead-legs and attachments that protrude from insulated piping and operate at a different temperature than the operating temperature of the active line;

8. austenitic stainless steel piping systems operating between 120oF (60oC) and 400oF (205oC) (susceptible to chloride SCC);,-

9. vibrating piping systems that have a tendency to inflict damage to insulation jacketing providing a path for water ingress; ()

10. steam traced piping systems that can experience tracing leaks, especially at tubing fittings beneath the insulation; -

11. piping systems with deteriorated insulation, coatings, and/or wrappings; bulges or staining of the insulation or jacketing system or missing bands (bulges can indicate corrosion product buildup);,,

12. piping systems susceptible to physical damage of the coating or insulation, thereby, exposing the piping to the environment.


API 574 7.4.4.1-

1. (): 10F ~ 350F (-12C~175 C) CUI /./.

2. 350F (175C ), .

3. 120F~400F( 60C~ 205C) (SCC )


API 574 7.4.4.1-

1. (): 10F ~ 350F (-12C~175 C)

2. 350F (175C ), .

3. 120F~400F( 60C~ 205C) (SCC )

//

API 574 7.4.4.1-

//

Piping systems that are known to have a remaining life of over 10 years or that are adequately protected against external corrosion need not be included for the NDE inspection recommended in Table 3. However, the condition of the insulating system or the outer jacketing, such as a cold-box shell, should be observed periodically by operating or other personnel. If deterioration is noted, it should be reported to the inspector. The following are examples of these systems:

10,-3 NDE., ,.

CUI ;

1. piping systems insulated effectively to preclude the entrance ofmoisture,

2. jacketed cryogenic piping systems,3. piping systems installed in a cold box in which the atmosphere is

purged with an inert gas, 4. piping systems in which the temperature being maintained is

sufficiently low or sufficiently high to preclude the presence of water.

23) Certain areas and types of piping systems are potentially more susceptible to corrosion under insulation. Which of the items listed is not susceptible to CUI?

a) Areas exposed to mist over-spray from cooling water towers.b) Carbon steel piping systems that normally operate in-service above 250

degrees but are in intermittent service.c) Deadlegs and attachments that protrude from insulated piping and operate at

a different temperature than the temperature of the active line.d) Carbon steel piping systems, operating between 250 degrees F and 600

degrees F.

22) What climatic area may require a very active program for corrosion under insulation?

a) Cooler northern continent locations.b) Cooler direr, mid-continent locationsc) Warmer, marine locationsd) Warmer drier, desert locations

21) What are the most common forms of corrosion under insulation (CUI).

a) Localised corrosion of non-ferrous metals and chloride stress corrosion cracking of carbon steel.

b) Localised corrosion of chrome-moly steel and chloride stress corrosion cracking of ferritic stainless steel.

c) Localised corrosion of carbon steel and chloride stress corrosion cracking of austenitic stainless steel

d) Localised corrosion of nickel-silicon alloy and caustic stress corrosion of austenitic stainless steel

24) What location is subject to corrosion under insulation and inspection contributes to it?

a) Locations where pipe hangers and other supports exist.b) Locations where insulator has been stripped to permit inspection of the

piping.c) Locations where insulation plugs have been removed to permit piping

thickness measurements.d) Locations where there is damaged or missing insulation jacketing.

6.5 Extent of Thickness Measurement Inspection

http://campbell.ws/rope_access/oil_rig/index.htm

TML, ().

6.6 Extent of Small-bore, Auxiliary Piping, and Threaded-connections Inspections. , ,

6.6.1 SBP Inspection

() .

:

/ (:).

API570, 3.1.72primary process piping

Process piping in normal, active service that cannot be valved off or, if it were valved off, would significantly affect unit operability. Primary process piping normally includes most process piping greater than NPS 2, and typically does not include small bore or auxiliary process piping (see also secondary process piping).

,, , 2

API570, 3.1.85secondary process piping

Process piping, often SBP downstream of block valves that can be closed without significantly affecting the process unit operability.

,,

Deadlegs with CMLs should be tracked in a separate piping circuit from the mainline pi

Api570 my self study notes

Engineering

Transcript of Api570 my self study notes