API STD 510 2001 Pres Vessel Inspection Code 2001

Pressure Vessel Inspection Code:
Maintenance Inspection, Rating,
Repair, and Alteration
API 510
EIGHTH EDITION, JUNE 1997
ADDENDUM 1, DECEMBER 1998
ADDENDUM 2, DECEMBER 2000
ADDENDUM 3, DECEMBER 2001
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Institute
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Pressure Vessel Inspection Code:
Maintenance Inspection, Rating,
Repair, and Alteration
Downstream Segment
API 510
EIGHTH EDITION, JUNE 1997
ADDENDUM 1, DECEMBER 1998
ADDENDUM 2, DECEMBER 2000
ADDENDUM 3, DECEMBER 2001
American
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Institute
Helping You
Get The Job
Done Right?
COPYRIGHT American Petroleum Institute
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SPECIAL NOTES
API publications necessarily address problems of a general nature. With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed.
API is not undertaking to meet the duties of employers, manufacturers, or suppliers to
warn and properly train and equip their employees, and others exposed, concerning health
and safety risks and precautions, nor undertaking their obligations under local, state, or federal laws.
Information concerning safety and health risks and proper precautions with respect to particular materials and conditions should be obtained from the employer, the manufacturer or
supplier of that material, or the material safety data sheet.
Nothing contained in any API publication is to be construed as granting any right, by
implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent. Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent.
Generally, API standards are reviewed and revised, r e a m e d , or withdrawn at least every
five years. Sometimes a one-time extension of up to two years will be added to this review
cycle. This publication will no longer be in effect five years after its publication date as an
operative API standard or, where an extension has been granted, upon republication. Status
of the publication can be ascertained from the API Standards Department [telephone (202)
682-8000]. A catalog of API publications and materials is published annually and updated
quarterly by API, 1220 L Street, N.W., Washington, D.C. 20005.
This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API
standard. Questions concerning the interpretation of the content of this standard or comments and questions concerning the procedures under which this standard was developed
should be directed in writing to the director of the Standards Department, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. Requests for permission to
reproduce or translate all or any part of the material published herein should also be
addressed to the general manager.
API standards are published to facilitate the broad availability of proven, sound engineering and operating practices. These standards are not intended to obviate the need for applying sound engineering judgment regarding when and where these standards should be
utilized. The formulation and publication of API standards is not intended in any way to
inhibit anyone from using any other practices.
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All rights reserved. No part of this work may be reproduced,stored in a retrieval system, or
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without prior writtenpermission from the publisher: Contact the Publishel;
API Publishing Services, 1220 L Street, N. IT,Washington,D.C. 20005.
Copyright O 1997, 1998, 2000, 2001 AmericanPetroleum Institute
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FOREWORD
98
This edition of API 510 supersedes all previous editions of API 510, Pressure Vessel
Inspection Code: Maintenance Inspection, Rating, and Repair of Pressure Vessels.Each edition, revision, or addenda to this API standard may be used beginning with the date of issuance shown on the cover page for that edition, revision, or addenda. Each edition, revision,
or addenda to this API standard becomes effective 6 months after the date of issuance for
equipment that is rerated, reconstructed, relocated, repaired, modified (altered), inspected,
and tested per this standard. During the 6-month time between the date of issuance of the
edition, revision, or addenda and the effective date, the user shall speci@ to which edition,
revision, or addenda, and the equipment is to be rerated, reconstructed, relocated, repaired,
modified (altered), inspected and tested.
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IMPORTANT INFORMATION CONCERNING USE OF ASBESTOS
OR ALTERNATIVE MATERIALS
Asbestos is specified or referenced for certain components of the equipment described in
some API standards. It has been of extreme usefulness in minimizing fire hazards associated
with petroleum processing. It has also been a universal sealing material, compatible with
most refining fluid services.
Certain serious adverse health effects are associated with asbestos, among them the serious and often fatal diseases of lung cancer, asbestosis, and mesothelioma (a cancer of the
chest and abdominal linings). The degee of exposure to asbestos varies with the product and
the work practices involved.
Consult the most recent edition of the Occupational Safety and Health A m s t r a t i o n
(OSHA), U S . Department of Labor, Occupational Safety and Health Standard for Asbestos,
Tremolite, Anthophyllite, and Actinolite, 29 Code of Federal Regulations Section
1910.1001; the U S . Environmental Protection Agency, National Emission Standard for
Asbestos, 40 Code of Federal Regulations Sections 61.140 through 61.156; and the U S .
Environmental Protection Agency (EPA) rule on labeling requirements and phased banning
of asbestos products, published at 54 Federal Register 29460 (July 12, 1989).
There are currently in use and under development a number of substitute materials to
replace asbestos in certain applications. Manufacturers and users are encouraged to develop
and use effective substitute materials that can meet the specifications for, and operating
requirements of, the equipment to which they would apply.
SAFETY AND HEALTH INFORMATION WITH RESPECT TO PARTICULAR
PRODUCTS OR MATERIALS CAN BE OBTAINED FROM THE EMPLOYER, THE
MANUFACTURER OR SUPPLIER OF THAT PRODUCT OR MATERIAL, OR THE
MATERIAL SAFETY DATA SHEET.
iv
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CONTENTS
1
1.3
Fitness-for-Service................................................
......................................................
2-1
DEFINITIONS.......................................................
3-1
OWNER-USER INSPECTION ORGANIZATION .........................
4.1 General ........................................................
4.2 API Authorized Pressure Vessel Inspector Qualification and Certification . . .
4.3 Owner-User Organization Responsibilities............................
4.4 API Authorized Pressure Vessel Inspector Duty ........................
4-1
INSPECTIONPRACTICES ............................................
5.1 Preparatory Work ................................................
5.2 Modes of Deterioration and Failure .................................
5.3 Corrosion-Rate Determination .....................................
5.4 Maximum Allowable Working Pressure Determination . . . . . . . . . . . . . . . . . .
5.5 Defect Inspection ................................................
5.6 InspectionofParts ...............................................
5.7 Corrosion and Minimum Thickness Evaluation ........................
5.8 Assessment of Inspection Findings ...................................
5-1
5-1
5-1 101
5-2
5-2 00
5-2 01
5-3 98
5-3
5-4 101
INSPECTION AND TESTING OF PRESSURE VESSELS AND
PRESSURE-RELIEVING DEVICES ....................................
6.1 General ........................................................
6.2 Risk-Based Inspection ............................................
6.3 External Inspection ..............................................
6.4 Internal and On-Stream Inspection ..................................
6.5 PressureTest....................................................
6.6 Pressure-Relieving Devices ........................................
6.7 Records........................................................
6-1
6-1
6-1
6-1
6-2
6-4
6-4
6-4
REFERENCES
5
6
1.1
01
loo
4- 1 98
4-1
4-1
4-1 198
1
REPAIRS. ALTERATIONS. AND RERATING OF PRESSURE VESSELS . . . . 7-1
7.1 General ........................................................
7-1
7.2 Welding .......................................................
7.3 Rerating .......................................................
ALTERNATIVE RULES FOR EXPLORATION AND PRODUCTION
PRESSURE VESSELS ................................................
8.1 Scope and Specific Exemptions.....................................
8.2 GlossaryofTems ...............................................
8.3 Inspection Program ..............................................
8.4 PressureTest ...................................................
8.5 Safety Relief Devices.............................................
8.6 Records........................................................
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8-1
8-1
8-1
8-1
8-3
8-3
8-3
lg8
o1
Page
APPENDIX A ASME CODE EXEMPTIONS ...............................
A- 1
APPENDIX B AUTHORIZED PRESSURE VESSEL INSPECTOR
CERTIFICATION .........................................
B- 1
APPENDIX C SAMPLE PRESSURE VESSEL INSPECTION RECORD . . . . . . . . C-1
APPENDIX D SAMPLE REPAIR. ALTERATION. OR RERATING OF
PRESSURE VESSEL FORM ................................
D-1
APPENDIX E TECHNICAL INQUIRIES ..................................
E-1
Figure
7-1 Rerating Vessels Using the Latest Edition or Addendum of the ASME
Code Allowable Stresses ............................................
7-6
Table
5-1 Values of Spherical Radius Factor ICL..................................
7- 1 Welding Methods .................................................
5-4
7-2
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Pressure Vessel Inspection Code:
Maintenance Inspection, Rating, Repair, and Alteration
1 Scope
1. I
ing, transporting, lease processing, and treating liquid
petroleum, natural gas, and associated salt water (brine)] may
be inspected under the alternative rules set forth in Section 8.
Except for Section 6, all of the sections in this inspection code
are applicable to pressure vessels in E&P service. The alternative rules in Section 8 are intended for services that may be
regulated under safety, spill, emission, or transportation controls by the U.S. Coast Guard; the Office of Hazardous Materials Transportation of the U.S. Department of Transportation
(DOT) and other units of DOT; the Minerals Management
Service of the U.S. Department of the Interior; state and local
oil and gas agencies; or any other regulatory commission.
GENERAL APPLICATION
This inspection code covers the maintenance inspection,
repair, alteration, and rerating procedures for pressure vessels
used by the petroleum and chemical process industries. The
application of this inspection code is restricted to organizations that employ or have access to an authorized inspection
agency as deíìned in 3.4. Except as provided in 1.2, the use of
this inspection code is restricted to organizations that employ
or have access to engineering and inspection personnel or
organizations that are technically qualified to maintain,
inspect, repair, alter, or rerate pressure vessels. Pressure vessel inspectors are to be certified as stated in this inspection
code. Since other codes that cover specific industries and general service applications already exist (for example, Sections
VI, VII, and XI of the ASME Boiler and Pressure Vessel
Code and the National Board Inspection Code),the industries
that fit within the restrictions above have developed this
inspection code to fulfill their own specific requirements.
This inspection code applies to vessels constructed in
accordance with the APIIASME Code for Unjred Pressure
Vesselsfor Petroleum Liquids and Gases, Section VI11 of the
ASME Code, and other recognized pressure vessel codes; to
nonstandard vessels; and to other vessels constructed noncode or approved as jurisdictional special. This inspection
code is only applicable to vessels that have been placed in
service (including items further described in 1.2) and have
been inspected by an authorized inspection agency or
repaired by a repair organization as defined in 3.15.
Adoption and use of this inspection code does not permit
its use in conflict with any prevailing regulatory requirements.
1.2.2 The following are excluded from the specific requirements of this inspection code:
a. Pressure vessels on movable structures covered by other
jurisdictional regulations (see Appendix A).
b. All classes of containers listed for exemption from construction in the scope of Section VIII, Division 1, of the
ASME Code (see Appendix A).
c. Pressure vessels that do not exceed the following volumes
and pressures:
1. Five cubic feet (0.141 cubic meters) in volume and
250 pounds per square inch (1723.1 kilopascals) design
pressure.
2. One and a half cubic feet (0.042 cubic meters) in volume and 600 pounds per square inch (4136.9 kilopascals)
design pressure (see Appendix A).
1.3 FITNESS-FOR-SERVICE
This inspection code recognizes fitness-for-service concepts for evaluating in-service degradation of pressure-containing components. API RP 579 provides detailed
assessment procedures for specific types of degradation that
are referenced in this code.
1.2 SPECIFIC APPLICATIONS
1.2.1 All pressure vessels used for Exploration and Production (E&P) service [for example, dnlling, producing, gather-
1-1
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PRESSURE
VESSELINSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,REPAIR,
AND ALTERATION
2-1
SECTION 2-REFERENCES
NACE2
RP 0472
M ñ 0175
98
O0
RP 576
RP 579
mibl220 1
Inspection of Pressure-RelievingDevices
Fitness-For-Service
Proceduresfor Welding or Hot Tapping on
National Board3
National Board Inspection Code
NB-23
WRC4
Bulletin 412
ASNTS
CP-189
Note: This publication is out of print. To obtain a copy please inform
the person taking your order that you require this publication for the
API 510 Inspector CertificationExam.
ASME‘
Boiler and Pressure Vessel Code, Section V, Section VI,
Section VII, Section VIII, Section IX, and
Section XI
‘ASME International, Three Park Avenue, New York, N Y 100165990, www.asme.org.
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Methods and Controls to Prevent In-Service Environmental Cracking of Carbon
Steel Weldments In Corrosive Petroleum
Refining Environments
Sulfide Stress Cracking Resistant Metallic
Materialsfor Oilfield Equipment
SNT-TC-1A
Challenges and Solutions in Repair Weldingfor Power and Processing Plants
Standard for Qualijïcation and Certijïcation of Nondestructive Testing Personnel
Personnel Qualijïcation and Certijïcation
in Nondestructive Testing
2NACE International, P.O. Box 218340, Houston, Texas, 772188340, www.nace.org.
3National Board of Boiler and Pressure Vessel Inspectors, 1055
Crupper Avenue, Columbus, Ohio 43229, www.nationalboard.com.
4The Welding Research Council, 3 Park Avenue, 27th Floor, New
York, N Y 10016-5902,www.forengineers.org.
5AmericanSociety for Nondestructive Testing, Inc., 1711 Arlingate
Lane, P.O. Box 28518, Columbus, Ohio, 43228-0518,
www.asnt.org.
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PRESSURE
VESSELINSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,REPAIR,
AND ALTERATION
3-1
SECTION 3-DEFINITIONS
For the purposes of this standard, the following definitions
apply.
3.1 alteration: A physical change in any component or a
rerating that has design implications that affect the pressure-containing capability of a pressure vessel beyond the
scope of the items described in existing data reports. The
following should not be considered alterations: any comparable or duplicate replacement, the addition of any reinforced nozzle less than or equal to the size of existing
reinforced nozzles, and the addition of nozzles not requiring
reinforcement.
3.2 ASME Code: Abbreviation and shortened title for the
ASME Boiler und Pressure Vessel Code. This abbreviated
title includes the addenda and code cases of the ASME Boiler
und Pressure Vessel Code.
The ASME Code is written for new construction; however, most of the technical requirements for design, welding, examination, and materials can be applied in the
maintenance inspection, rating, repair, and alteration of
operating pressure vessels. When the ASME Code cannot be
followed because of its new construction orientation (new or
revised material specifications, inspection requirements,
certain heat treatments and pressure tests, and stamping and
inspection requirements), the engineer or inspector shall
conform to this inspection code rather than to the ASME
Code. If an item is covered by requirements in the ASME
Code and this inspection code or if there is a conflict
between the two codes, for vessels that have been placed in
service, the requirements of this inspection code shall take
precedence over the ASME Code. As an example of the
intent of this inspection code, the phrase “applicable
requirements of the ASME Code” has been used in this
inspection code instead of the phrase “in accordance with
the ASME Code.”
3.3 authorized pressure vessel inspector: An
employee of an authorized inspection agency who is qualified and certified to perform inspections under this inspection code.
3.4 authorized inspection agency: Any one of the following:
a. The inspection organization of the jurisdiction in which
the pressure vessel is used.
b. The inspection organization of an insurance company that
is licensed or registered to write and actually does write pressure vessel insurance.
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c. The inspection organization of an owner or user of pressure vessels who maintains an inspection organization for his
equipment only and not for vessels intended for sale or resale.
d. An independent organization or individual that is under
contract to and under the direction of an owner-user and that
is recognized or otherwise not prohibited by the jurisdiction
in which the pressure vessel is used. The owner-user’s inspection program shall provide the controls that are necessary
when contract inspectors are used.
3.5 construction code: The code or standard to which a
vessel was originally built, such as AFWASME, API, or State
SpeciaVnon-ASME.
3.6 inspection code: Shortened title for API 510 used in
this publication.
3.7 inspector: Refers to an authorized pressure vessel
inspector in this document.
3.8 jurisdiction: A legally constituted government administration that may adopt rules relating to pressure vessels.
3.9 maximum allowable working pressure: The
maximum gauge pressure permitted at the top of a pressure
vessel in its operating position for a designated temperature. This pressure is based on calculations using the minimum (or average pitted) thickness for all critical vessel
elements, exclusive of thickness designated for corrosion
and loadings other than pressure.
3.10 minimum allowable shell thickness: The thickness required for each element of a vessel. The minimum
allowable shell thickness is based on calculations that consider temperature, pressure, and all loadings.
3.11 on-stream inspection: The inspection used to
establish the suitability of a pressure vessel for continued
operation. Nondestructive examination @DE) procedures are
used to establish the suitability of the vessel, and the vessel
may or may not be in operation while the inspection is being
carried out. Because a vessel may be in operation while an
on-stream inspection is being carried out, an on-stream
inspection means essentially that the vessel is not entered for
internal inspection.
3.12 pressurevessel: A container designed to withstand
internal or external pressure. This pressure may be imposed
by an external source, by the application of heat from a direct
or indirect source, or by any combination thereof. This d e h i tion includes unñred steam generators and other vapor generating vessels which use heat from the operation of a
processing system or other indirect heat source. (Specific lim-
3-2
API 510
its and exemptions of equipment covered by this inspection
code are given in Section 1 and Appendix A.)
3.13 pressure vessel engineer: Shall be one or more
persons or organizations acceptable to the owner-user who
are knowledgeable and experienced in the engineering disciplines associated with evaluating mechanical and material
characteristics which affect the integrity and reliability of
pressure vessels. The pressure vessel engineer, by consulting with appropriate specialists, should be regarded as a
composite of all entities needed to properly assess the technical requirements.
3.14 quality assurance: All planned, systematic, and
preventative actions required to determine if materials, equipment, or services will meet specified requirements so that
equipment will perform satisfactorily in service. The contents
of a quality assurance inspection manual are outlined in 4.3.
3.15 repair: The work necessary to restore a vessel to a
condition suitable for safe operation at the design conditions.
If any repair changes the design temperature or pressure, the
requirements for rerating shall be satisfied. A repair can be
the addition or replacement of pressure or nonpressure parts
that do not change the rating of the vessel.
3.16 repair organization:Any one of the following:
a. The holder of a valid ASME Certificate of Authorization
that authorizes the use of an appropriate ASME Code symbol
stamp.
b. An owner or user of pressure vessels who repairs his or her
own equipment in accordance with this inspection code.
c. A contractor whose qualifications are acceptable to the
pressure-vessel owner or user and who makes repairs in
accordance with this inspection code.
d. An individual or organization that is authorized by the
legal jurisdiction.
3.17 rerating:A change in either the temperature ratings
or the maximum allowable working pressure rating of a
vessel, or a change in both. The maximum allowable working temperature and pressure of a vessel may be increased
or decreased because of a rerating, and sometimes a rerating requires a combination of changes. Derating below
original design conditions is a permissible way to provide
for corrosion. When a rerating is conducted in which the
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maximum allowable working pressure or temperature is
increased or the minimum temperature is decreased so that
additional mechanical tests are required, it shall be considered an alteration.
3.18 examiner: A person who assists the API authorized
pressure vessel inspector by performing specific NDE on
pressure vessels but does not evaluate the results of those
examinations in accordance with API 5 1O, unless specifically
trained and authorized to do so by the owner or user. The
examiner need not be certified in accordance with API 5 1O or
be an employee of the owner or user but shall be trained and
competent in the applicable procedures in which the examiner is involved. In some cases, the examiner may be required
to hold other certifications as necessary to satis@ the owner or
user requirements. Examples of other certification that may
be required are ASNT SNT-TC-lA, or CP189, or American
Welding Society6Welding Inspector Certification. The examiner’s employer shall maintain certification records of the
examiners employed, including dates and results of personnel
qualifications and shall make them available to the API authorized pressure vessel inspector.
3.19 controlled-deposition welding: Any welding
technique used to obtain controlled grain refinement and tempering of the underlying heat affected zone (HAZ)in the base
metal. Various controlled-deposition techniques, such as temper-bead (tempering of the layer below the current bead being
deposited) and half-bead (requiring removal of one-half of
the ñrst layer), are included. Controlled-deposition welding
requires control of the entire welding procedure including the
joint detail, preheating and post heating, welding technique,
and welding parameters. Refer to supporting technical information found in Welding Research Council Bulletin 412.
3.20 fitness-for-service assessment: A methodology whereby flaws and conditions contained within a structure are assessed in order to determine the integrity of the
equipment for continued service.
3.21 industry-qualifiedUT shear wave examiner:A
person who possesses an ultrasonic shear wave qualification
from API or an equivalent qualification approved by the
ownerluser.
6AmericanWelding Society, 550 N.W. LeJeune Road, Miami,
FL 33135. www.aws.org.
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PRESSURE
VESSELINSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,REPAIR,
AND ALTERATION
SECTION "OWNER-USER
98
98
An owner-user of pressure equipment shall exercise control
of the pressure vessel inspection program, inspection frequencies, and maintenance. The owner-user is responsible for the
function of an authorized inspection agency in accordance with
the provisions of API 5 1O. The owner-user inspection organization shall control activities relating to the maintenance inspection, rating, repair, and alteration of these pressure vessels.
Authorized pressure vessel inspectors shall have education
and experience in accordance with Appendix B of this inspection code. Authorized pressure vessel inspectors shall be certified by the American Petroleum Institute in accordance with
the provisions of Appendix B.
4-1
INSPECTION ORGANIZATION
g. Assurance that all jurisdictional requirements for pressure
vessel inspection, repairs, alterations, and rerating are continuously met.
h. Reports to the authorized pressure vessel inspector any
process changes that could affect pressure vessel integrity.
i. Training requirements for inspection personnel regarding
inspection tools, techniques, and technical knowledge base.
j. Controls necessary so that only qualified welders and procedures are used for all repairs and alterations.
k. Controls necessary so that only qualified nondestructive
examination @DE) personnel and procedures are utilized.
1. Controls necessary so that only materials conforming to
the applicable section of the ASME Code are utilized for
repairs and alterations.
m. Controls necessary so that all inspection measurement and
test equipment are properly maintained and calibrated.
n. Controls necessary so that the work of contract inspection
or repair organizations meet the same inspection requirements as the owner-user organization.
o. Internal auditing requirements for the quality control system for pressure-relieving devices.
4.4 API AUTHORIZED PRESSUREVESSEL
INSPECTOR RESPONSIBILITIES
When inspections, repairs, or alterations are being conducted on pressure vessels, an API authorized pressure vessel inspector shall be responsible to the owner-user for
determining that the requirements of API 5 1O on inspection,
examination, and testing are met, and shall be directly
involved in the inspection activities. The API authorized
pressure vessel inspector may be assisted in performingvisual inspections by other properly trained and qualified
individuals, who may or may not be certified vessel inspectors. Personnel performing nondestructive examinations
shall meet the qualifications identified in 3.18 but need not
be API authorized pressure vessel inspectors. However, all
examination results must be evaluated and accepted by the
API authorized pressure vessel inspector.
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PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
5-1
SECTION 5-1 NSPECTION PRACTICES
5.1 PREPARATORYWORK
Safety precautions are important in pressure vessel inspection because of the limited access to and the confined spaces
of pressure vessels. Occupational Safety and Health Administration (OSHA) regulations pertaining to confined spaces and
any other OSHA safety rules should be reviewed and followed, where applicable.
For an internal inspection, the vessel should be isolated by
blinds or other positive methods from all sources of liquids,
gases, or vapors. The vessel should be drained, purged,
cleaned, ventilated, and gas tested before it is entered. Where
required, protective equipment should be worn that will protect the eyes, lungs, and other parts of the body from specific
hazards that may exist in the vessel.
The nondestructive testing equipment used for the inspection is subject to the safety requirements customarily followed in a gaseous atmosphere. Before the inspection is
started, all persons working around the vessel should be
informed that people are going to be working inside it. People
working inside the vessel should be informed when any work
is going to be done on the exterior of it.
The tools and personnel safety equipment needed for the
vessel inspection should be checked before the inspection.
Other equipment that might be needed for the inspection,
such as planking, scaffolding, bosun's chairs, and portable
ladders, should be available if needed.
5.2 MODES OF DETERIORATION AND FAILURE
Contaminants in fluids handled in pressure vessels, such as
sulfur, chlorine, hydrogen sulfide, hydrogen, carbon, cyanides,
acids, water, or other corroding species may react with metals
and cause corrosion. Significant stress fluctuations or reversals
in parts of equipment are common, particularly at points of
high secondary stress. If stresses are high and reversals are frequent, failure of parts may occur because of fatigue. Fatigue
failures in pressure vessels may also occur because of cyclic
temperature and pressure changes. Locations where metals
with different thermal coefficients of expansion are welded
together may be susceptible to thermal fatigue. API RP 579,
Section 3 provides procedures for the assessment of equipment for resistance to brittle fracture.
Other forms of deterioration, such as stress corrosion cracking, hydrogen attack, carburization, graphitization, and erosion, may also occur under special circumstances. These
forms of deterioration are more fully discussed in API RP 579,
Appendix G.
Deterioration or creep may occur if equipment is subjected
to temperatures above those for which it is designed. Since
metals weaken at higher temperatures, such deterioration may
cause failures, particularly at points of stress concentration.
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Creep is dependent on time, temperature, stress, and material
creep strength, so the actual or estimated levels of these quantities should be used in any evaluations. At elevated temperatures, other metallurgical changes may also take place that
may permanently affect equipment.
For developing an inspection plan for equipment operating
at elevated temperatures [generally starting in the range of
750" 1000°F (400" 540"C), depending on operating conditions and alloy], the following should be considered in
assessing the remaining life:
~
~
a. Creep deformation and stress rupture.
b. Creep crack growth.
c. Effect of hydrogen on creep.
d. Interaction of creep and fatigue.
e. Possible metallurgical effects, including a reduction in
ductility.
Numerous NDE techniques can be applied to íìnd and
characterize elevated temperature damage. These techniques
include visual, surface, and volumetric examination. Additionally, if desired or warranted, samples can be removed for
laboratory analysis.
The inspection plan should be prepared in consultation
with an engineer having knowledge of elevated temperature
and metallurgical effects on pressure vessel materials of construction.
At subfreezing temperatures, water and some chemicals
handled in pressure vessels may freeze and cause failure.
At ambient temperatures, carbon, low-alloy, and other ferritic steels may be susceptible to brittle failure. A number of
failures have been attributed to brittle fracture of steels that
were exposed to temperatures below their transition temperature and to pressures greater than 20 percent of the required
hydrostatic test pressure; most brittle fractures, however, have
occurred on the íìrst application of a particular stress level (the
íìrst hydrotest or overload). Although the potential for a brittle
failure because of excessive operating conditions below the
transition temperature shall be evaluated, the potential for a
brittle failure because of rehydrotesting or pneumatic testing of
equipment or the addition of any other additional loadings shall
also be evaluated. Special attention should be given to lowalloy steels (especially 2l/4 Cr-1Mo) because they may be
prone to temper embrittlement. [Temper embrittlement is a loss
of ductility and notch toughness due to postweld heat treatment
or high-temperature service (above 700°F) (37O"C).]
Other forms of deterioration, such as stress corrosion
cracking, hydrogen attack, carburization, graphitization, and
erosion, may also occur under special circumstances. These
forms of deterioration are more fully discussed in Chapter II
of the API Guidefor Inspection for ReJnery Equiyment.
98
5-2
API 510
5.3 CORROSION RATE DETERMINATION
5.5 DEFECT INSPECTION
For a new vessel or for a vessel for which service conditions are being changed, one of the following methods shall
be employed to determine the vessel’s probable corrosion
rate. The remaining wall thickness at the time of the next
inspection can be estimated from this rate.
Vessels shall be examined for visual indications of distortion. If any distortion of a vessel is suspected or observed, the
overall dimensions of the vessel shall be checked to confirm
whether or not the vessel is distorted and, if it is distorted, to
determine the extent and seriousness of the distortion. The parts
of the vessel that should be inspected most carefuiiy depend on
the type of vessel and its operating conditions. The authorized
pressure vessel inspector should be familiar with the operating
conditions of the vessel and with the causes and characteristics of potential defects and deterioration. (For recommended
inspection practices for pressure vessels, see API RP 572.)
Careful visual examination is the most important and the
most universally accepted method of inspection. Other methods that may be used to supplement visual inspection include
(a) magnetic-particle examination for cracks and other elongated discontinuities in magnetic materials; (b) fluorescent or
dye-penetrant examination for disclosing cracks, porosity, or
pin holes that extend to the surface of the material and for
outlining other surface imperfections, especially in nonmagnetic materials; (c) radiographic examination; (d) ultrasonic
thickness measurement and flaw detection; (e) eddy current
examination; (f) metallographic examination; (g) acoustic
emission testing; hammer testing while not under pressure;
and (h) pressure testing. (Section V of the ASME Code can
be used as a guide for many of the nondestructive examination techniques.)
Adequate surface preparation is important for proper visual
examination and for the satisfactory application of any auxiliary procedures, such as those mentioned above. The type of
surface preparations required depends on the individual circumstances, but surface preparations such as wire brushing,
blasting, chipping, grinding, or a combination of these preparations may be required.
If external or internal coverings, such as insulation, refractory protective linings, and corrosion-resistant linings, are in
good condition and there is no reason to suspect that an
unsafe condition is behind them, it is not necessary to remove
them for inspection of the vessel; however, it may be advisable to remove small portions of the coverings to investigate
their condition and effectiveness and the condition of the
metal underneath them.
Where operating deposits, such as coke, are normally permitted to remain on a vessel surface, it is particularly important to determine whether such deposits adequately protect
the vessel surface from deterioration. To determine this, spot
examinations in which the deposit is thoroughly removed
from selected critical areas may be required.
Where vessels are equipped with removable internals, the
internals need not be removed completely as long as reasonable assurance exists that deterioration in regions rendered
inaccessible by the internals is not occurring to an extent
beyond that found in more accessible parts of the vessel.
a. A corrosion rate may be calculated from data collected
by the owner or user on vessels providing the same or similar service.
b. If data on vessels providing the same or similar service are
not available, a corrosion rate may be estimated from the
owner’s or user’s experience or from published data on vessels providing comparable service.
c. If the probable corrosion rate cannot be determined by
either item a or item b above, on-stream determinations shall
be made after approximately 1000 hours of service by using
suitable corrosion monitoring devices or actual nondestructive thickness measurements of the vessel or system. Subsequent determinations shall be made after appropriate intervals
until the corrosion rate is established.
If it is determined that an inaccurate corrosion rate has
been assumed, the rate to be used for the next period shall be
increased or may be decreased to agree with the actual rate.
5.4 MAXIMUM ALLOWABLE WORKING
PRESSURE DETERMINATION
The maximum allowable working pressure for the continued use of a pressure vessel shall be based on computations
that are determined using the latest edition of the ASME
Code or the construction code to which the vessel was built.
The resulting maximum allowable working pressure from
these computations shall not be greater than the original maximum allowable working pressure unless a rerating is performed in accordance with 7.3.
Computations may be made only if the following essential
details comply with the applicable requirements of the code
being used: head, shell, and nozzle reinforcement designs;
material specifications; allowable stresses; weld efficiencies;
inspection acceptance criteria; and cyclical service requirements. In corrosive service, the wall thickness used in these
computations shall be the actual thickness as determined by
inspection (see 5.7) minus twice the estimated corrosion loss
before the date of the next inspection, except as modified in
6.4. If the actual thickness determined by inspection is greater
than the thickness reported in the material test report or the
manufacturer’s data report, it must be confirmed by multiple
thickness measurements, taken at areas where the thickness of
the component in question was most likely affected by the
thinning due to forming. The thickness measurement procedure shall be approved by the authorized pressure vessel
inspector. Allowance shall be made for other loads in accordance with the applicable provisions of the ASME Code.
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PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
o1
The owneríuser shall specify industry-qualified UT
shear wave examiners when the owner/user requires the
following: (a) detection of interior surface (ID) breaking
planar flaws when inspecting from the external surface
(OD); or (b) where detection, characterization, and/or
through-wall sizing is required of planar defects. Application examples for the use of such industry-qualified UT
shear wave examiners include fitness-for-service and
future monitoring of known interior flaws from the external surface. The requirement for use of industry-qualified
UT shear wave examiners becomes effective two years
after publication in this code or addendum.
5.6 INSPECTION OF PARTS
The following inspections are not all inclusive for every
vessel, but they do include the features that are common to
most vessels and that are most important. Authorized pressure vessel inspectors must supplement this list with any
additional items necessary for the particular vessel or vessels involved.
a. Examine the surfaces of shells and heads carefully for possible cracks, blisters, bulges, and other signs of deterioration.
Pay particular attention to the skirt and to support-attachment
and knuckle regions of the heads. If evidence of distortion is
found, it may be necessary to make a detailed check of the
actual contours or principal dimensions of the vessel and to
compare those contours and dimensions with the original
design details.
b. Examine welded joints and the adjacent heat-affected
zones for service-induced cracks or other defects. On riveted
vessels, examine rivet head, butt strap, plate, and caulked
edge conditions. If rivet-shank corrosion is suspected, hammer testing or spot radiography at an angle to the shank axis
may be useful.
c. Examine the surfaces of all manways, nozzles, and other
openings for distortion, cracks, and other defects, paying particular attention to the welding used to attach the parts and
their reinforcements. Normally, weep holes in reinforcing
plates should remain open to provide visual evidence of leakage as well as to prevent pressure build-up in the cavity.
Examine accessible flange faces for distortion and determine
the condition of gasket-seating surfaces.
98
API Recommended Practice 574 provides more information on the inspection of piping, valves, and fittings associated with pressure vessels. API Recommended Practice 572
provides more information on pressure vessel inspection.
5.7 CORROSION AND MINIMUM THICKNESS
EVALUATION
Corrosion may cause a uniform loss (a general, relatively
even wastage of a surface area) or may cause a pitted appearance (an obvious, irregular surface wastage). Uniform corrosion may be difficult to detect visually, and thickness readings
COPYRIGHT American Petroleum Institute
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5-3
may be necessary to determine its extent. Pitted surfaces may
be thinner than they appear visually, and when there is uncertainty about the original surface location, thickness determinations may also be necessary.
The minimum actual thickness and maximum corrosion rate
for any part of a vessel may be adjusted at any inspection. When
the minimum actual thickness or maximum corrosion rate is to
be adjusted, one of the following should be considered:
a. Any suitable nondestructive examination, such as ultrasonic or radiographic examination, that will not affect the
safety of the vessel may be used as long as it will provide
minimum thickness determinations. When a measurement
method produces considerable uncertainty, test holes may
be drilled, or other nondestructive techniques, such as
ultrasonic A-scan, B-scan, or C-scan, may be employed.
Profile radiography may be also employed.
b. If suitable openings are available, measurements may be
taken through them.
c. The depth of corrosion may be determined by gauging the
uncorroded surfaces within the vessel when such surfaces are
in the vicinity of the corroded area.
d. For a corroded area of considerable size in which the circumferential stresses govern, the least thickness along the
most critical element of the area may be averaged over a
length not exceeding the following:
1. For vessels with inside diameters less than or equal to
60 inches (150 centimeters), one-half the vessel diameter
or 20 inches (50 centimeters), whichever is less.
2. For vessels with inside diameters greater than 60
inches (150 centimeters), one-third the vessel diameter or
40 inches (100 centimeters), whichever is less.
When the area contains an opening, the distance on either
side of the opening within which the thicknesses are averaged shall not extend beyond the limits of the reinforcement
as deíìned in the ASME Code. If, because of wind loads or
other factors, the longitudinal stresses govern, the least
thickness in a similarly determined length of arc in the most
critical plane perpendicular to the axis of the vessel also
shall be averaged for computation of the longitudinal
stresses. The thickness used for determining corrosion rates
at the respective locations shall be the average thickness
determined as in the preceding. For the purposes of 5.4, the
actual thickness as determined by inspection shall be understood to mean the most critical value of the average thickness that has been determined.
e. Widely scattered pits may be ignored as long as the following are true:
1. No pit depth is greater than one-half the vessel wall
thickness exclusive of the corrosion allowance.
2. The total area of the pits does not exceed 7 square inches
(45 square centimeters) within any 8-inch (20-centimeter)
diameter circle.
3. The sum of their dimensions along any straight line
within the circle does not exceed 2 inches (5 centimeters).
API 510
5-4
f. As an alternative to the procedures just described, any
components with thinning walls that, because of corrosion or
other wastage, are below the minimum required wall thicknesses may be evaluated to determine if they are adequate for
continued service. The thinning components may be evaluated by employing the design by analysis methods of Section
VIII, Division 2, Appendix 4, of the ASME Code. These
methods may also be used to evaluate blend ground areas
where defects have been removed. It is important to ensure
that there are no sharp corners in blend ground areas to minimize stress concentration effects.
When using this criteria, the stress value used in the original pressure vessel design shall be substituted for the S, value
of Division 2 if the design stress is less than or equal to Kspecified minimum yield strength ( S M Y S ) at temperature. If
the original design stress is greater than %-specified minimum yield strength at temperature, then %-specified minimum yield strength shall be substituted for s,. When this
approach is to be used, consulting with a pressure vessel engineer experienced in pressure vessel design is required.
g. When the surface at a weld with a joint factor of other than
1.0, as well as surfaces remote from the weld, is corroded, an
independent calculation using the appropriate weld joint factor
must be made to determine if the thickness at the weld or
remote from the weld governs the allowable working pressure.
For this calculation, the surface at a weld includes 1 inch (2.5
centimeters) on either side of the weld or twice the minimum
thickness on either side of the weld, whichever is greater.
h. When measuring the corroded thickness of ellipsoidal and
torispherical heads, the governing thickness may be as follows:
1. The thickness of the knuckle region with the head rating calculated by the appropriate head formula.
2. The thickness of the central portion of the dished
region, in which case the dished region may be considered
a spherical segment whose allowable pressure is calculated by the code formula for spherical shells.
The spherical segment of both ellipsoidal and torispherical
heads shall be considered to be that area located entirely
within a circle whose center coincides with the center of the
head and whose diameter is equal to 80 percent of the shell
diameter. The radius of the dish of torispherical heads is to be
used as the radius of the spherical segment (equal to the diameter of the shell for standard heads, though other radii have
been permitted). The radius of the spherical segment of ellipsoidal heads shall be considered to be the equivalent spherical
radius KID,where D is the shell diameter (equal to the major
axis) and K, is given in Table 5-1. In Table 5-1, h is one-half
the length of the minor axis [equal to the inside depth of the
ellipsoidal head measured from the tangent line (headbend
line)]. For many ellipsoidal heads, D/2h equals 2.0.
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Table 5-I-Values
of Spherical Radius Factor K,
3 .O
1.36
2.8
1.27
2.6
1.18
2.4
1.08
2.2
0.99
2.0
0.90
1.8
0.81
1.6
0.73
1.4
0.65
1.2
0.57
1.o
0.50
Note: The equivalent spherical radius equals K,D; the axis ratio equals %h.
Interpolation is permitted for intermediate values.
5.8 ASSESSMENT OF INSPECTION FINDINGS
Pressure containing components found to have degradation
that could affect their load carrying capability (pressure loads
and other applicable loads, e.g., weight, wind, etc., per API RP
579) shall be evaluated for continued service. Fitness-for-service techniques, such as those documented in API RP 579,
may be used for this evaluation. The fitness-for-service techniques used must be applicable to the specific degradation
observed. The following techniques may be used as an alternative to the evaluation techniques in 5.7.
a. To evaluate metal loss in excess of the corrosion allowance, a fitness-for-service assessment may be performed in
accordance with the following sections of API RP 579, as
applicable. This assessment requires the use of a hture corrosion allowance, which shall be established based on Section 6
of this inspection code.
1. Assessment of General Metal Loss-API RP 579, Section 4
2. Assessment of Local Metal Loss-API RP 579, Section 5
3. Assessment of Pitting Corrosion-API RP 579, Section 6
b. To evaluate blisters and laminations, a fitness-for-service
assessment should be performed in accordance with API RP
579, Section 7. In some cases this evaluation will require the
use of a hture corrosion allowance, which shall be established based on Section 6 of this inspection code.
c. To evaluate weld misalignment and shell distortions, a fitness-for-service assessment should be performed in accordance with API RP 579, Section 8.
d. To evaluate crack-like flaws, a fitness-for-service assessment should be performed in accordance with API RP 579,
Section 9.
e. To evaluate the effects of fire damage, a fitness-for-service
assessment should be performed in accordance with API RP
579, Section 11.
o1
PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
SECTION 6-INSPECTION
AND TESTING OF PRESSUREVESSELS AND PRESSURERELIEVING DEVICES
6.1 GENERAL
981
Pressure vessels shall be inspected at the time of installation. Internal field inspections of new vessels are not required
as long as a manufacturer's data report assuring that the vessels are satisfactory for their intended service is available. To
ensure vessel integrity, all pressure vessels shall be inspected
at the frequencies provided in this section.
In selecting the technique(s) to be used for the inspection of
a pressure vessel, both the condition of the vessel and the environment in which it operates should be taken into consideration. The inspection, as deemed necessary by the authorized
pressure vessel inspector, may include many of a number of
nondestructive techniques, including visual inspection. Internal inspection is preferred because process side degradation
(corrosion, erosion, and environmental cracking) can be nonuniform throughout the vessel and, therefore, difficult to locate
by external NDE. On-stream inspection may be acceptable in
lieu of internal inspectionfor vessels under the specijc circumstances deíìned in 6.4. In situations where on-stream inspection
is acceptable, such inspection may be conducted either while
the vessel is out of service and depressurized or on stream and
under pressure. Except in response to an apparent need, such as
when environmental cracking (see Guide for Inspection of
ReJnery Equiyment, Chapter 11) is suspected, inspection techniques exceeding the examination requirements used in the
design and fabrication of the vessel are not required.
The appropriate inspection must provide the information
necessary to determine that all of the essential sections or components of the vessel are safe to operate until the next scheduled
inspection. The risks associated with operational shutdown and
start-up and the possibility of increased corrosion due to exposure of vessel surfaces to air and moisture should be evaluated
when an internal inspection is being planned.
6.2 RISK-BASED INSPECTION
9'
Identisling and evaluating potential degradation mechanisms are important steps in an assessment of the likelihood
of a pressure vessel failure. However, adjustments to inspection strategy and tactics to account for consequences of a
failure should also be considered. Combining the assessment
of likelihood of failure and the consequence of failure are
essential elements of risk-based inspection (RBI).
When an owneríuser chooses to conduct a RBI assessment,
it must include a systematic evaluation of both the likelihood of
failure and the associated consequence of failure. The likelihood assessment must be based on all forms of degradation
that could reasonably be expected to affect a vessel in any particular service. Examples of those degradation mechanisms
include: internal or external metal loss from an identified form
of corrosion (localized or general), all forms of cracking,
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6-1
including hydrogen assisted and stress corrosion cracking
(from the inside or outside surfaces of a vessel), and any other
forms of metallurgical, corrosion, or mechanical degradation,
such as fatigue, embrittlement, creep, etc. Additionally, the
effectiveness of the inspection practices, tools, and techniques
utilized for íìnding the expected and potential degradation
mechanisms must be evaluated. This likelihood of failure
assessment should be repeated each time equipment or process
changes are made that could significantly affect degradation
rates or cause premature failure of the vessel.
Other factors that should be considered in a RBI assessment include: appropriateness of the materials of construction; vessel design conditions, relative to operating
conditions; appropriateness of the design codes and standards
utilized; effectiveness of corrosion monitoring programs; and
the quality of maintenance and inspection quality assurance/
quality control programs. Equipment failure data and information will also be important information for this assessment.
The consequence assessment must consider the potential incidents that may occur as a result of fluid release, including
explosion, fire, toxic exposure, environmental impact, and
other health effects associated with a failure of a vessel.
It is essential that all RBI assessments be thoroughly documented, clearly deíìning all the factors contributing to both the
likelihood and consequence of a failure of the vessel.
After an effective RBI assessment is conducted, the
results can be used to establish a vessel inspection strategy
and more specifically better define the following:
a. The most appropriate inspection methods, scope, tools and
techniques to be utilized based on the expected forms of
degradation.
b. The appropriate frequency for internal, external, and onstream inspections.
c. The need for pressure testing after damage has been
incurred or after repairs or modifications have been completed.
d. The prevention and mitigation steps to reduce the likelihood and consequence of a vessel failure.
An RBI assessment may be used to increase or decrease
the 10-year inspection limit described in Section 6.4. When
used to increase the 10-year limit, RBI assessment shall be
reviewed and approved by a pressure vessel engineer and
authorized pressure vessel inspector at intervals not to exceed
10 years, or more often if warranted by process, equipment,
or consequence changes.
6.3 EXTERNAL INSPECTION
Each vessel aboveground shall be given a visual external
inspection, preferably while in operation, at least every 5 years
or at the same interval as the required internal or on-stream
inspection, whichever is less. The inspection shall, at the least,
38
6-2
981
981
API 5 10
determine the condition of the exterior insulation, the condition of the supports, the allowance for expansion, and the general alignment of the vessel on its supports. Any signs of
leakage should be investigated so that the sources can be
established. Inspection for corrosion under insulation (CUI)
shall be considered for externally-insulated vessels subject to
moisture ingress and that operate between 25°F (4°C) and
250°F (120"C),or are in intermittent service. This inspection
may require removal of some insulation. It is not normally
necessary to remove insulation if the entire vessel shell is
always operated at a temperature sufficiently low below 25°F
(4"C)l or sufficiently high [above 250°F (12O"C)]to prevent
the presence or condensation of moisture under the insulation.
Alternatively, shell thickness measurements done internally at
typical problem areas (for example, stiffening rings, around
nozzles, and other locations which tend to trap moisture or
allow moisture ingress) may be performed during
internal inspections.
Buried vessels shall be inspected to determine their external environmental condition. The inspection interval shall be
based on corrosion-rate information obtained from one or
more of the following methods: (a) during maintenance activity on adjacent connecting piping of similar material; (b)
from the interval examination (specified in the paragraph
above) of similarly buried corrosion test coupons of similar
material; (c) from representative portions of the actual vessel;
or (d) from a vessel in similar circumstances.
Vessels that are known to have a remaining life of over 10
years or that are protected against external corrosion-for
example, (a) vessels insulated effectively to preclude the
entrance of moisture, (b) jacketed cryogenic vessels, (c) vessels installed in a cold box in which the atmosphere is purged
with an inert gas, and (d) vessels in which the temperature
being maintained is sufficiently low or sufficiently high to
preclude the presence of w a t e r d o not need to have insulation removed for the external inspection. However, the condition of their insulating system or their outer jacketing, such as
the cold box shell, shall be observed at least every 5 years and
repaired if necessary.
6.4 INTERNAL AND ON-STREAM INSPECTION
The period between internal or on-stream inspections shall
not exceed one half the estimated remaining life of the vessel
based on corrosion rate or 10 years, whichever is less. In
cases where the remaining safe operating life is estimated to
be less than 4 years, the inspection interval may be the full
remaining safe operating life up to a maximum of 2 years.
For pressure vessels that are in noncontinuous service and
are isolated from the process fluids such that they are not
exposed to corrosive environments (such as inert gas purged
or filled with noncorrosive hydrocarbons),the 10 years shall
be the 10 years of actual service exposed life. Equipment
that is not adequately protected from corrosive environments may experience significant internal corrosion while
idle and should be carefully reviewed when setting inspec-
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tion intervals. In no case should these exceed one-half the
estimated remaining corrosion-rate life, or 10 years since
the last inspection. External inspections for vessels in noncontinuous service remain the same as for continuous service, as outlined in 6.3.
Except as noted below, internal inspection is normally the
preferred method of inspection and shall be conducted on
vessels subject to significant localized corrosion and other
types of damage. At the discretion of the authorized pressure
vessel inspector, on-stream inspection may be substituted for
internal inspection in the following situations:
a. When size, configuration, or lack of access makes vessel
entry for internal inspection physically impossible.
b. When the general corrosion rate of a vessel is known to be
less than 0.005inch (O. 125 millimeter) per year and the estimated remaining life is greater than 10 years, and all of the
following conditions are met:
1. The corrosive character of the contents, including the
effect of trace components, has been established by at
least 5 years of the same or comparable service experience
with the type of contents being handled.
2. No questionable condition is disclosed by the external
inspection specified in 6.3.
3. The operating temperature of the steel vessel shell
does not exceed the lower temperature limits for the
creep-rupture range of the vessel material.
4. The vessel is not considered to be subject to environmental cracking or hydrogen damage from the fluid being
handled.
5. The vessel is not strip-lined or plate-lined.
If the requirements of item b above are not met, as a result
of conditions noted during the scheduled on-stream inspection, the next scheduled inspection shall be an internal inspection. When a vessel has been internally inspected, the results
of a current inspection can be used to determine whether an
on-stream inspection can be substituted for an internal
inspection on a similar vessel operating in the same service
and conditions.
When an on-stream inspection is conducted in lieu of an
internal inspection, a thorough examination shall be performed using ultrasonic thickness measurements, or radiography, or other appropriate means of NDE to measure metal
thicknesses andor assess the integrity of the metal and welds.
If an on-stream inspection is conducted, the authorized pressure vessel inspector shall be given sufficient access to all
parts of the vessel (heads, shell, and nozzles) so that the
inspector is satisfied that an accurate assessment of the vessel
condition can be made.
A representative number of thickness measurements must be
conducted on each vessel to satis@ the requirements for an
internal or on-stream inspection. For example, the thickness for
all major components (shells, heads, cone sections) and a representative sample of vessel nozzles should be measured and
recorded, and the remaining life and next inspection interval
I98
98
PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
should be calculated for the limiting component. A decision on
the number and location of the thickness measurements should
consider results from previous inspections, if available, and the
potential consequence of loss of containment. Measurements at
a number of thickness measurement locations (TMLs) are
intended to establish general and localized corrosion rates in
different sections of the vessel. A minimal number of TMLs are
acceptable when the established rate of corrosion is low and
not localized. For pressure vessels susceptible to localized corrosion, it is vital that those knowledgeable in localized corrosion mechanisms be consulted about the appropriate placement
and number of TMLs. Additionally, for localized corrosion, it
is important that inspections are conducted using scanning
methods such as proíìle radiography, scanning ultrasonics, and
or other suitable NDE methods that will reveal the scope and
extent of localized corrosion.
The remaining life of the vessel shall be calculated from
the following formula:
Remaining life (years)
=
tactual
-
trequired
corrosion rate
[inches (mm) per year]
where
tactual = the actual thickness, in inches (millimeters),
tEqired
O
measured at the time of inspection for a given
location or component.
= the required thickness, in inches (millimeters),
at the same location or component as the tactual
measurement, computed by the design formulas
(e.g., pressure and structural) before corrosion
allowance and manufacturer’s tolerance are
added.
The long-term (LT) corrosion rate shall be calculated from
the following formula:
t... -t
imtial
actual
Corrosion rate (LT)=
time (years) between tinitialand tactual
,
The short-term (ST) corrosion rate shall be calculated from
the following formula:
‘previous - tactuai
Corrosion rate (ST)=
time (years) between tpreviousand tactual
,
tinitial = the thickness, in inches (millimeters), at the same
location as tahl measured at initial installation
or at the commencement of a new corrosion rate
environment.
tpEvious= the thickness, in inches (millimeters), at the same
location as tactuai measured during a previous
inspection.
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6-3
Long-term and short-term corrosion rates should be compared as part of the data assessment. The authorized inspector, in consultation with a corrosion specialist, shall select the
corrosion rate that best reflects the current process.
o,
6-4
API 510
service and the next period of inspection shall be established
for the new service.
981
6.5 PRESSURETEST
When the authorized pressure vessel inspector believes that
a pressure test is necessary or when, after certain repairs or
alterations, the inspector believes that one is necessary (see
7.2.9), the test shall be conducted at a pressure in accordance
with the construction code used for determining the maximum allowable working pressure. To minimize the risk of
brittle fracture during the test, the metal temperature should
be maintained at least 30°F (17°C) above the minimum
design metal temperature for vessels that are more than 2
inches (5 centimeters) thick, or 10°F (6°C) above for vessels
that have a thickness of 2 inches (5 centimeters) or less. The
test temperature neednot exceed 120°F (50°C) unless there is
information on the brittle characteristics of the vessel material
indicating that a lower test temperature is acceptable or a
higher test temperature is needed.5
Pneumatic testing may be used when hydrostatic testing is
impracticable because of temperature, foundation, refractory
lining, or process reasons; however, the potential personnel
and property risks of pneumatic testing shall be considered
before such testing is carried out. As a minimum, the inspection precautions contained in the ASME Code shall be
applied in any pneumatic testing. Before applying a hydrostatic test to equipment, consideration should be given to the
supporting structure and the foundation design.
When a pressure test is to be conducted in which the test
pressure will exceed the set pressure of the safety relief valve
with the lowest setting, the safety relief valve or valves should
be removed. An alternative to removing the safety relief
valves is to use test clamps to hold down the valve disks.
Applying an additional load to the valve spring by turning the
compression screw is not recommended. Other appurtenances, such as gauge glasses, pressure gauges, and rupture
disks, that may be incapable of withstanding the test pressure
should also be removed or should be blanked off or vented.
When the pressure test has been completed, pressure relief
devices of the proper settings and other appurtenances
removed or made inoperable during the pressure test shall be
reinstalled or reactivated.
981
6.6 PRESSURE-RELIEVINGDEVICES
Pressure relief valves shall be tested and repaired by repair
organizations experienced in valve maintenance. Each repair
organization shall have a fully documented quality control
system. As a minimum, the following requirements and
5Forvessels without minimum design metal temperature, the minimum acceptable operating temperature should be used in lieu of the
minimum design metal temperature.
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pieces of documentation should be included in the quality
control system:
a. Title page.
b. Revision log.
c. Contents page.
d. Statement of authority and responsibility.
e. Organizational chart.
f. Scope of work.
g. Drawings and specification controls.
h. Material and part control.
i. Repair and inspection program.
j. Welding, nondestructive examination, and heat treatment
procedures.
k. Valve testing, setting, leak testing, and sealing.
1. General example of the valve repair nameplate.
m. Procedures for calibrating measurement and test gauges.
n. Controlled copies of the manual.
o. Sample forms.
p. Repair personnel training or qualifications.
Each repair organization shall also have a fully documented training program that shall ensure that repair personnel are qualified within the scope of the repairs.
Pressure relief valves shall be tested at intervals that are
frequent enough to veri@ that the valves perform reliably.
This may include testing pressure relief valves on newly
installed equipment. Pressure-relieving devices should be
tested and maintained in accordance with API Recommended
Practice 576. Other pressure-relieving devices, such as rupture disks and vacuum-breaker valves, shall be thoroughly
examined at intervals determined on the basis of service.
The intervals between pressure-relieving-device testing or
inspection should be determined by the performance of the
devices in the particular service concerned. Test or inspection
intervals on pressure-relieving devices in typical process services should not exceed 5 years, unless service experience
indicates that a longer interval is acceptable. For clean
(nonfouling), noncorrosive services, maximum intervals
may be increased to 10 years. When service records indicate
that a pressure-relieving device was heavily fouled or stuck in
the last inspection or test, the service interval shall be reduced
if the review shows that the device may not perform reliably
in the hture. The review should include an effort to determine
the cause of the fouling or the reasons for the relief device not
operating properly.
6.7 RECORDS
Pressure vessel owners and users shall maintain permanent
and progressive records of their pressure vessels. Permanent
records will be maintained throughout
- the service life of each
vessel; progressive records will be re&arly updated to
include new idormation pertinent to the operation, inspection, and maintenance history of the vessel.
I98
lg8
I98
PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
Pressure vessel records shall contain four types of vessel
information pertinent to mechanical integrity as follows:
O0
a. Construction and design information. For example,
equipment serial number or other identifier, manufacturers’
data reports (MDRs), design specification data, design calculations (where MDRs are unavailable), and construction
drawings. For pressure vessels that have no nameplate and
minimal or no design and construction documentation, the
following steps may be used to verify operating integrity:
i. Perform inspection to determine condition of the vessel. Make any necessary repairs.
ii. Define design parameters and prepare drawings and
calculations.
iii. Base calculations on applicable codes and standards
and condition of the vessel following any repairs. Do not
use allowable stress values based on design factor of 3.5.
See ASME Code Section VIII, Division 1, paragraph
UG-lO(c) for guidance on evaluation of unidentified
materials. If UG-10 (c) is not followed, then for carbon
steels, use allowable stresses for SA-283 Grade C; and for
alloy and nonferrous materials, use x-ray fluorescence
analysis to determine material type on which to base
allowable stress values.
When extent of radiography originally performed is not
known, use joint factor of 0.7 for butt welds, or consider
performing radiography if a higher joint factor is required.
(Recognize that performing radiography on welds in a
vessel with minimal or no design and construction documentation may result in the need for a fitness-for-service
assessment and significant repairs.)
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6-5
iv. Attach a nameplate or stamping showing the maximum allowable working pressure and temperature,
minimum allowable temperature, and date.
v. Perform pressure test as soon as practical, as required
by code of construction used for design calculations.
O0
b. Operating and inspection history. For example, operating
conditions, including process upsets that may affect
mechanical integrity, inspection reports, and data for each
type of inspection conducted (for example, internal, external, thickness measurements), and inspection recommendations for repair. See Appendix C for sample pressure vessel
inspection records. Inspection reports shall document the
date of each inspection andor test, the date of the next
scheduled inspection, the name of the person who performed
the inspection andor test, the serial number or other identifier of the equipment inspected, a description of the inspection andor test performed, and the results of the inspection
andor test.
c. Repair, alteration, and rerating information. For example,
(1) repair and alteration forms like that shown in Appendix D,
(2) reports indicating that equipment still in-service with identified deficiencies or recommendations for repair are suitable
for continued service until repairs can be completed, and (3)
rerating documentation (including rerating calculations, new
design conditions, and evidence of stamping).
d. Fitness-for-service assessment documentation requirements are described in API RP 579, Section 2.8. Specific
documentation requirements for the type of flaw being
assessed are provided in the appropriate section of API RP
579.
DI
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PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
SECTION 7-REPAIRS,
ALTERATIONS, AND RERATING OF PRESSURE VESSELS
7.1 GENERAL
This section covers repairs and alterations to pressure vessels by welding. The requirements that must be met before
pressure vessels can be rerated are also covered in this section. When repairs or alterations have to be performed, the
applicable requirements of the ASME Code, the codes to
which the vessels were built, or other specific pressure vessel
rating codes shall be followed. Before any repairs or alterations are performed, all proposed methods of execution, all
materials, and all welding procedures that are to be used must
be approved by the authorized pressure vessel inspector and,
if necessary, by a pressure vessel engineer experienced in
pressure vessel design, fabrication, or inspection.
7.1. I Authorization
All repair and alteration work must be authorized by the
authorized pressure vessel inspector before the work is started
by a repair organization (see 3.13). Authorization for alterations to pressure vessels that comply with Section VIII,
Divisions 1 and 2, of the ASME Code and for repairs to pressure vessels that comply with Section VIII, Division 2, of the
ASME Code may not be given until a pressure vessel engineer experienced in pressure vessel design has been consulted
about the alterations and repairs and has approved them. The
authorized pressure vessel inspector will designate the fabrication approvals that are required. The authorized pressure
vessel inspector may give prior general authorization for limited or routine repairs as long as the inspector is sure that the
repairs are the kind that will not require pressure tests.
7.1.2 Approval
The authorized pressure vessel inspector shall approve all
specified repair and alteration work after an inspection of the
work has proven the work to be satisfactory and any required
pressure test has been witnessed.
7.1.3 Defect Repairs
A crack in a welded joint and a defect in a plate may be
repaired by preparing a U- or V-shaped groove to the full
depth and length of the crack and then íìlling the groove with
weld metal deposited in accordance with 7.2. No crack shall
be repaired without authorization from the authorized pressure vessel inspector. Repairing a crack at a discontinuity,
where stress concentrations may be serious, should not be
attempted without prior consultation with a pressure vessel
engineer experienced in pressure vessel design.
Corroded areas, as defined by 5.7, may be restored with
weld metal deposited in accordance with 7.2. Surface irregularities and contamination shall be removed before welding.
The nondestructive examination and inspection appropriate
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7-1
for the extent of restoration being performed shall be specified in the repair procedure.
7.2 WELDING
All repair and alteration welding shall be in accordance
with the applicable requirements of the ASME Code, except
as permitted in 7.2.11.
7.2.1 Procedures and Qualifications
The repair organization shall use qualified welders and
welding procedures qualified in accordance with the applicable requirements of Section IX of the ASME Code.
7.2.2 Qualification Records
The repair organization shall maintain records of its qualified welding procedures and its welding performance qualifications. These records shall be available to the inspector prior
to the start of welding. The repair organization’s qualified
welding procedures and welding performance qualifications
shall be in accord with the appropriate code.
7.2.3 Preheat or Controlled DepositionWelding
Methods as Alternatives to Postweld Heat
Treatment
Preheat and controlled deposition welding, as described in
7.2.3.1 and 7.2.3.2, may be used in lieu of postweld heat treatment (PWHT) where PWHT is inadvisable or mechanically
unnecessary. Prior to using any alternative method, a metallurgical review conducted by a pressure vessel engineer shall
be performed to assess whether the proposed alternative is
suitable for the application. The review should consider factors such as the reason for the original PWHT of the equipment, susceptibility of the service to promote stress corrosion
cracking, stresses in the location of the weld, susceptibility to
high temperature hydrogen attack, susceptibility to creep, etc.
Selection of the welding method used shall be based on the
rules of the construction code applicable to the work planned
along with technical consideration of the adequacy of the
weld in the as-welded condition at operating and pressure test
conditions.
When reference is made in this section to materials by the
ASME designation, P-Number and Group Number, the
requirements of this section apply to the applicable materials
of the original code of construction, either ASME or other,
which conform by chemical composition and mechanical
properties to the ASME P-Number and Group Number designations.
Vessels constructed of steels other than those listed in
7.2.3.1 and 7.2.3.2 that initially required PWHT shall be
postweld heat treated if alterations or repairs involving pressure boundary welding are performed. When one of the fol-
API 510
7-2
lowing methods is used as an alternative to PWHT, the
PWHT joint efficiency factor may be continued if the factor
has been used in the currently rated design.
7.2.3.1 Preheating Method (Notch Toughness
Testing Not Required)
a. Notch toughness testing is not required when this welding
method is used.
b. The materials shall be limited to P-No. 1, Group 1, 2, and
3, and to P-No. 3, Group 1 and 2 (excluding Mn-Mo steels in
Group 2).
c. The welding shall be limited to the shielded-metal-arc
welding (SMAW), gas-metal-arc welding (GMAW), and gastungsten-arc welding (GTAW) processes.
d. The weld area shall be preheated and maintained at a minimum temperature of 300°F (150°C) during welding. The
300°F (150°C) temperature should be checked to assure that
4 in. (10 mm) of the material or four times the material thickness (whichever is greater) on each side of the groove is
maintained at the minimum temperature during welding. The
maximum interpass temperature shall not exceed 600°F
(3 15°C). When the weld does not penetrate through the full
thickness of the material, the minimum preheat and maximum interpass temperatures need only be maintained at a distance of 4 in. (10 mm) or four times the depth of the repair
weld, whichever is greater on each side of the joint.
7.2.3.2 Controlled-DepositionWelding Method
(Notch ToughnessTesting Required)
a. Notch toughness testing, such as that established by
ASME Code Section VI11 Division 1, parts UG-84 and
UCS-66, is necessary when impact tests are required by the
original code of construction or the construction code applicable to the work planned.
b. The materials shall be limited to P-No. 1, P-No. 3, and PNo. 4 steels.
c. The welding shall be limited to the shielded-metal-arc
welding (SMAW), gas-metal-arc welding (GMAW), and gastungsten-arc welding (GTAW) processes.
d. A weld procedure specification shall be developed and
qualified for each application. The welding procedure shall
define the preheat temperature and interpass temperature and
~
include the post heating temperature requirement in f (1)
below. The qualification thickness for the test plates and
repair grooves shall be in accordance with Table 7-1.
The test material for the welding procedure qualification
shall be of the same material specification (including specification type, grade, class and condition of heat treatment) as
the original material specification for the repair. If the original
material specification is obsolete, the test material used
should conform as much as possible to the material used for
construction, but in no case shall the material be lower in
strength or have a carbon content of more than 0.35%.
e. When impact tests are required by the construction code
applicable to the work planned, the PQR shall include sufñcient tests to determine if the toughness of the weld metal and
the heat-affected zone of the base metal in the as-welded condition is adequate at the minimum design metal temperature
(such as the criteria used in ASME Code Section VI11 Division 1, parts UG-84 and UCS 66). If special hardness limits
are necessary (for example, as set forth in NACE RP 0472,
and MR 0175) for corrosion resistance, the PQR shall include
hardness tests as well.
f. The WPS shall include the following additional requirements:
~
1. The supplementary essential variables of ASME Code,
Section M, paragraph QW-250, shall apply;
2. The maximum weld heat input for each layer shall not
exceed that used in the procedure qualification test;
3. The minimum preheat temperature for welding shall
not be less than that used in the procedure qualification
test;
4. The maximum interpass temperature for welding shall
not be greater than that used in the procedure qualification
test;
5. The preheat temperature shall be checked to assure that
4 in. (10 mm) of the material or four times the material
thickness (whichever is greater) on each side of the weld
joint will be maintained at the minimum temperature during welding. When the weld does not penetrate through
the full thickness of the material, the minimum preheat
temperature need only be maintained at a distance of 4 in.
(10 mm) or four times the depth of the repair weld, whichever is greater on each side of the joint;
Table 7-I-Welding Methods as Alternatives to Postweld Heat Treatment
Qualification Thickneeses For Test Plates and Repair Grooves
Depth t of Test
Groove Welded”
t
t
Repair Groove
Depth Qualified
<t
<t
Thickness T of Test
Coupon Welded
< 2 in. (50mm)
> 2 in. (50mm)
Thickness of Base Metal
Qualified
<T
2 in. (50mm) to unlimited
aThe depth of the groove used for procedure qualification must be deep enough to allow removal of the required test specimens.
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PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
6. For the welding processes in 7.2.3.2 (c), use only electrodes and íìller metals that are classified by the filler
metal specification with an optional supplemental diffusible-hydrogen designator of H8 or lower. When shielding
gases are used with a process, the gas shall exhibit a dew
point that is no higher than -60°F (-50°C). Surfaces on
which welding will be done shall be maintained in a dry
condition during welding and free of rust, mill scale and
hydrogen producing contaminants such as oil, grease and
other organic materials;
7. The welding technique shall be a controlled-deposition, temper-bead or half-bead technique. The specific
technique shall be used in the procedure qualification test;
8. For welds made by SMAW, after completion of welding and without allowing the weldment to cool below the
minimum preheat temperature, the temperature of the
weldment shall be raised to a temperature of 500°F f 50°F
(260°C f 30°C) for a minimum period of two hours to
assist out-gassing diffusion of any weld metal hydrogen
picked up during Welding. This hydrogen bake-out treatment may be omitted provided the electrode used is classified by the filler metal specification with an optional
supplemental diffusable-hydrogen designator of H4 (such
as E7018-H4); and
9. After the íìnished repair weld has cooled to ambient
temperature, the final temper bead reinforcement layer
shall be removed substantially flush with the surface of the
base material.
7.2.4 Nondestructive Examination of Welds
Prior to welding, the area prepared for welding shall be
examined using either the magnetic particle &IT) or the liquid penetrant (PT) examination method to determine that no
defects exist. After the weld is completed, it shall be examined again by either of the above methods to determine that
no defects exist using acceptance standards acceptable to the
Inspector or code of construction most applicable to the work
planned. In addition, welds in a pressure vessel that was originally required to be radiographed by the rules of the original
code of construction, shall be radiographically examined. In
situations where it is not practical to perform radiography the
accessible surfaces of each non-radiographed repair weld
shall be fully examined using the most appropriate nondestructive examination method to determine that no defects
exist, and the maximum allowable working pressure and/or
allowable temperature shall be reevaluated to the satisfaction
of the authorized pressure vessel inspector and jurisdiction at
the location of installation.
7.2.5 Local Postweld HeatTreatment
Note, Before local postweld heat treatment is used, a metallurgical review
must be conducted to determine if the vessel was postweld heat treated due to
the characteristics of the fluid contained in it.
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7-3
Local postweld heat treatment (PWHT) may be substituted
for 360-degree banding on local repairs on all materials, provided that the following precautions are taken and requirements are met:
a. The application is reviewed, and a procedure is developed
by pressure vessel engineers experienced in the appropriate
engineering specialties.
b. The suitability of the procedure is evaluated. In evaluating
the suitability of the procedure, the following shall be considered: applicable factors, such as base metal thickness, decay
thermal gradients, and material properties (hardness, constituents, strength, and the like); changes due to local postweld
heat treatment; the need for full penetration welds; and surface and volumetric examinations after local postweld heat
treatment. In evaluating and developing local postweld heat
treatment procedures, the overall and local strains and distortions resulting from the heating of a local restrained area of
the pressure vessel shell shall be considered.
c. A preheat of 300°F (150°C)or higher, as specified by specific welding procedures, is maintained during Welding.
d. The required local postweld heat treatment temperature
shall be maintained for a distance of not less than two times
the base metal thickness measured from the weld. The local
postweld heat treatment temperature shall be monitored by a
suitable number of thermocouples (at least two). (When
determining the number of thermocouples necessary, the size
and shape of the area being heat treated should be considered.)
Heat shall be applied to any nozzle or any attachment
within the local postweld heat treatment area.
7.2.6 Repairsto Stainless Steel Weld Overlay and
Cladding
The repair procedure(s) to restore removed, corroded, or
missing clad or overlay areas shall be reviewed and endorsed
prior to implementation by the pressure vessel engineer and
authorized by the inspector.
Consideration shall be given to factors which may augment
the repair sequence such as stress level, P number of base
material, service environment, possible previously dissolved
hydrogen, type of lining, deterioration of base metal properties (by temper embrittlement of chromium-molybdenum
alloys), minimum pressurization temperatures, and a need for
hture periodic examination.
For equipment which is in hydrogen service at an elevated
temperature or which has exposed base metal areas open to
corrosion which could result in a significant atomic hydrogen
migration in the base metal, the repair must additionally be
considered by the pressure vessel engineer for factors affecting the following:
a. Outgassing base metal.
b. Hardening of base metal due to welding, grinding, or arc
gouging.
API 510
7-4
c. Preheat and interpass temperature control.
d. Postweld heat treatment to reduce hardness and restore
mechanical properties.
Repairs shall be monitored by an inspector to assure compliance to repair requirements. After cooling to ambient temperatures, the repair shall be inspected by the liquid penetrant
method, according to ASME Code, Section VIII, Division 1,
Appendix 8.
For vessels constructed with P-3, P-4, or P-5 base materials, the base metal in the area of repair should be examined
for cracking by the ultrasonic examination in accordance with
ASME Code, Section V, Article 5, paragraph T-543. This
inspection is most appropriately accomplished following a
delay of at least 24 hours after completed repairs for equipment in hydrogen service and for chromium-molybdenum
alloys that could be affected by delayed cracking.
7.2.7
I
Design
Butt joints shall have complete penetration and fusion.
Parts should be replaced when repairing them is likely to be
inadequate. Part replacements shall be fabricated according to
the applicable requirements of the appropriate code. New
connections may be installed on vessels as long as the design,
location, and method of attachment comply with the applicable requirements of the appropriate code.
Fillet-welded patches require special design considerations, especially relating to efficiency. Fillet-welded patches
may be used to make temporary repairs, and the use of íìlletwelded patches may be subject to the patches’ acceptance in
the jurisdiction in which they are required. Temporary repairs
using fillet-welded patches shall be approved by the authorized pressure vessel inspector and a pressure vessel engineer
competent in pressure vessel design; and the-temporary
repairs should be removed and replaced with suitable permanent repairs at the next available maintenance opportunity.
Temporary repairs may remain in place for a longer period of
time only if evaluated, approved, and documented by the
pressure vessel engineer and the authorized API pressure vessel inspector. Fillet-welded patches may be applied to the
internal or external surfaces of shells, heads, and headers
as long as, in the judgment of the authorized pressure vessel inspector, either of the following is true:
a. The fillet-welded patches provide design safety equivalent
to reinforced openings designed according to the applicable
section of the ASME Code.
b. The íìllet-welded patches are designed to absorb the membrane strain of the parts so that in accordance with the rules of
the applicable section of the ASME Code, the following
result:
1. The allowable membrane stress is not exceeded in the
vessel parts or the patches.
2. The strain in the patches does not result in fillet-weld
stresses that exceed allowable stresses for such welds.
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Overlay patches shall have rounded corners. Flush (insert)
patches shall also have rounded corners, and they shall be
installed with full-penetration butt joints.
Refer to API Publication 2201 when making on-stream
repairs.
A full encirclement lap band repair may be considered a
long term repair if the design is approved , and documented
by the pressure vessel engineer and the authorized API pressure vessel inspector and the following requirements are met:
a. The repair is not being made to a crack in the vessel shell.
b. The band alone is designed to contain the full design pressure.
c. All longitudinal seams in the repair band are full penetration butt welds with the design joint efficiency and inspection
consistent with the appropriate code.
d. The circumferential íìllet welds attaching the band to the
vessel shell are designed to transfer the full longitudinal load
in the vessel shell, using a joint efficiency of 0.45, without
counting on the integrity of the original shell material covered
by the band. Where significant, the eccentricity effects of the
band relative to the original shell shall be considered in sizing
the band attachment welds. Other than visual examination,
fillet weld examination may be done at the next shutdown if
conditions and necessary access do not permit complete
examination at the time of an onstream repair.
e. Fatigue of the attachment welds, such as fatigue resulting
from differential expansion of the band relative to the vessel
shell, should be considered if applicable.
f. The band material and weld metal are suitable for contact
with the contained fluid at the design conditions and an
appropriate corrosion allowance is provided in the band.
g. The degradation mechanism leading to the need for repair
shall be considered in determining the need for any additional
monitoring and future inspection of the repair.
Non-penetrating nozzles (including pipe caps attached as
nozzles) may be used as long term repairs for other than
cracks when the design and method of attachment comply
with the applicable requirements of the appropriate code. The
design and reinforcement of such nozzles shall consider the
loss of the original shell material enclosed by the nozzle. The
nozzle material shall be suitable for contact with the contained fluid at the design conditions and an appropriate corrosion allowance shall be provided. The degradation
mechanism leading to the need for repair shall be considered
in determining the need for any additional monitoring and
future inspection of the repair.
For the purposes of future inspection, it may be necessary
to consider repair bands and non-penetrating nozzles to be
separate zones when addressing the on-stream inspection
requirements in 6.4.
PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
7.2.8 Material
The material used in making repairs or alterations shall
conform to the applicable section of the ASME Code. The
material shall be of known weldable quality and be compatible with the original material. Carbon or alloy steel with a
carbon content over 0.35 percent shall not be welded.
7.2.9 Inspection
Acceptance criteria for a welded repair or alteration should
include nondestructive examination techniques that are in
accordance with the applicable sections of the ASME Code or
another applicable vessel rating code. Where use of these
nondestructive examination techniques is not possible or
practical, alternative nondestructive examination methods
may be used provided they are approved by the pressure vessel engineer and the authorized pressure vessel inspector.
For vessels constructed of materials that may be subject to
brittle fracture (per API RP 579, or other analysis) from either
normal or abnormal service (including startup, shutdown, and
pressure testing), appropriate inspection should be considered
after welded repairs or alterations. Flaws, notches, or other
stress risers could initiate a brittle fracture in subsequent pressure testing or service. Magnetic particle testing and other
effective surface NDE methods should be considered. Inspection techniques should be designed to detect critical flaws as
determined by a fitness-for-service assessment.
7.2.1O Testing
o1
After repairs are completed, a pressure test shall be applied
if the authorized pressure vessel inspector believes that one is
necessary. A pressure test is normally required after an alteration. Subject to the approval of the jurisdiction (where the
jurisdiction's approval is required), appropriate nondestructive examinations shall be required where a pressure test is
not performed. Substituting nondestructive examination procedures for a pressure test after an alteration may be done
only after a pressure vessel engineer experienced in pressure
vessel design and the authorized pressure vessel inspector
have been consulted.
For cases where UT is substituted for radiographic
inspection, the owneríuser shall specify industry-qualified
UT shear wave examiners for closure welds that have not
been pressure tested and for weld repairs identified by the
pressure vessel engineer or authorized inspector. The
requirement for use of industry-qualified UT shear wave
examiners becomes effective two years after publication in
this code or addendum.
7.2.11 Filler Metal
The filler metal used for weld repairs should have minimum
specified tensile strength equal to or greater than the minimum
specified tensile strength of the base metal. If a filler metal is
used that has a minimum specified tensile strength lower than
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7-5
the minimum specified tensile strength of the base metal, the
compatibility of the íìller metal chemistry with the base metal
chemistry shall be considered regarding weldability and service degradation. In addition, the following shall be met:
a. The repair thickness shall not be more than 50 percent of the
required base metal thickness, excluding corrosion allowance.
b. The thickness of the repair weld shall be increased by a ratio
of minimum specified tensile strength of the base metal and
minimum specified tensile of the íìller metal used for the repair.
c. The increased thickness of the repair shall have rounded
corners and shall be blended into the base metal using a 3-to-1
taper.
d. The repair shall be made with a minimum of two passes.
7.3
RERATING
Rerating a pressure vessel by changing its temperature ratings or its maximum allowable working pressure may be done
only after all of the following requirements have been met:
a. Calculations from either the manufacturer or an owner-user
pressure vessel engineer (or his designated representative)
experienced in pressure vessel design, fabrication, or inspection shall justify rerating.
b. A rerating shall be established in accordance with the
requirements of the construction code to which the pressure
vessel was built or by computations that are determined using
the appropriate formulas in the latest edition of the ASME
Code if all of the essential details comply with the applicable
requirements of the code being used. If the vessel was
designed to an edition or addendum of the ASME Code earlier than the 1999 Addenda and was not designed to Code
Case 2290 or 2278, it may be rerated to the latest edition'
addendum of the ASME Code if permitted by Figure 7-1.
c. Current inspection records veri@ that the pressure vessel
is satisfactory for the proposed service conditions and that the
corrosion allowance provided is appropriate. An increase in
allowable working pressure or temperature shall be based on
thickness data obtained from a recent internal or on-stream
inspection.
d. If the pressure vessel has at some time been pressure tested
to a test pressure equal to or higher than the pressure test pressure required by the latest edition or addendum of the ASME
Code, or the vessel integrity is maintained by special nondestructive evaluation inspection techniques in lieu of testing, a
pressure test for the rerated condition is not required.
e. The pressure vessel inspection and rerating is acceptable
to the authorized pressure vessel inspector.
The pressure vessel rerating will be considered complete
when the authorized pressure vessel inspector oversees the
attachment of an additional nameplate or additional stamping
that carries the following information:
Rerated by
Maximum Allowable Working Pressure
Date
psi at -F"
O0
O0
API 510
7-6
Obtain original
vessel data
Notes:
I.
ASME Code identified as ASME Section VIII,
4
Div. 1
Yes
2. Vessel material(s) are defined as material
essential to the structural integrity of the
vessel.
Are vessel
vessel material
current specification?
Yes
I
vessel material
UGIO ofASME
code?
iNo
3. Material degradation due to operation is
defined as loss of material strength,
ductility, or toughness due to creep,
graphitization, temper embrittlement,
hydrogen attack, fatigue, etc., see API
RP 579.
the ASME Code
4
Yes
Is allowable
stress at rerate
temperature per the latest
editionladdendum of the ASME
Code higher than
original allowable
stress?
v
4
N
)-o{
No incentive to use the
latest editionladdendum of
the ASME Code allowable
stress for rerating.
O0
Yes
Review
operational history
ASME code?
4
A
Has the
material been
(see note 3)?
Can the
material specification?
Rerate vessel or
Code allowable stress.
f
editionladdei im of the ASME
Code allowable stress.
)
A
components satisfy
the impact toughness
for the rerated
Figure 7-I-Rerating Vessels Using the Latest Edition or Addendum of the ASME Code Allowable Stresses
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PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
8-1
SECTION 8-ALTERNATIVE RULES FOR EXPLORATION AND
PRODUCTION PRESSURE VESSELS
8.1 SCOPE AND SPECIFIC EXEMPTIONS
This section sets forth the minimum alternative inspection
rules for pressure vessels that are exempt from the rules set
forth in Section 6 except as referenced in paragraphs 8.4 and
8.5. Except for Section 6, all of the sections in this inspection
code are applicable to Exploration and Production (E&P)
pressure vessels. These rules are provided because of the
vastly different characteristics and needs of pressure vessels
used for E&P service. Typical E&P services are vessels associated with drilling, production, gathering, transportation, and
treatment of liquid petroleum, natural gas, natural gas liquids,
and associated salt water (brine).
The following are specific exemptions:
a. Portable pressure vessels and portable compressed gas
containers associated with construction machinery, pile drivers, drilling rigs, well-servicing rigs and equipment, compressors, trucks, ships, boats, and barges shall be treated, for
inspection and recording purposes, as a part of that machinery
and shall be subject to prevailing rules and regulations applicable to that specific type of machine or container.
b. Pressure vessels referenced in Appendix A are exempt
from the specific requirements of this inspection code.
8.2 GLOSSARY OF TERMS
8.2.1 class of vessels: Pressure vessels used in a common circumstance of service, pressure, and risk.
8.2.2 inspection: The external, internal, or on-stream
evaluation (or any combination of the three) of a pressure vessel’s condition.
a. external inspection: Evaluation performed from the
outside of a pressure vessel using visual procedures to establish the suitability of the vessel for continued operation. The
inspection may, or may not, be carried out while the vessel is
in operation.
b. internal inspection: Evaluation performed from the
inside of a pressure vessel using visual and/or nondestructive
examination procedures to establish the suitability of the vessel for continued operation.
c. on-stream inspection: Evaluation performed from the
outside of a pressure vessel using nondestructive examination
procedures to establish the suitability of the vessel for continued operation. The vessel may, or may not, be in operation
while the inspection is carried out.
d. progressive inspection: An inspection whose scope
(coverage, interval, technique, and so forth) is increased as a
result of inspection findings.
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8.2.3 Section 8 vessel: A pressure vessel which is
exempted from the rules set forth in Section 6 ofthis document.
8.3 INSPECTION PROGRAM
Each owner or user of Section 8 vessels shall have an
inspection program that will assure that the vessels have sufñcient integrity for the intended service. Each E&P owner or
user shall have the option of employing, within the limitations
of the jurisdiction in which the vessels are located, any appropriate engineering, inspection, classification, and recording
systems which meet the requirements of this document.
8.3.1 On-Stream or Internal Inspections
a. Either an on-stream inspection or an internal inspection
may be used interchangeably to satis@ inspection requirements. An internal inspection is required when the vessel
integrity cannot be established with an on-stream inspection.
When an on-stream inspection is used, a progressive inspection shall be employed.
b. In selecting the technique(s) to be utilized for the inspection of a pressure vessel, both the condition of the vessel and
the environment in which it operates should be taken into
consideration. The inspection may include any number of
nondestructive techniques, including visual inspection, as
deemed necessary by the owner-user.
c. At each on-stream or internal inspection, the remaining
corrosion-rate life shall be determined as described in 8.3.2.
8.3.2 Remaining Corrosion Rate Life
Determination
For a new vessel, a vessel for which service conditions are
being changed, or existing vessels, the remaining corrosion
rate life shall be determined for each vessel or estimated for a
class of vessels based on the following formula:
Remaining life (years)
=
~
trequlred
corrosion rate
[inches (mm) per year]
where
tactual= the actual thickness, in inches (millimeters),
measured at the time of inspection for a given
location or component.
trequlred= the required thickness, in inches (millimeters), at the same location or component as
the t,,tu,lmeasurement, obtained by one of the
following methods:
a. The nominal thickness in the uncorroded condition, less
the specified corrosion allowance.
8-2
API 510
b. The original measured thickness, if documented, in the
uncorroded condition, less the specified corrosion allowance.
c. Calculations in accordance with the requirements of the
construction code to which the pressure vessel was built, or
by computations that are determined using the appropriate
formulas in the latest edition of the ASME Code, if all of the
essential details comply with the applicable requirements of
the code being used.
corrosion rate = loss of metal thickness, in inches (millimeters), per year. For vessels in which the
corrosion rate is unknown, the corrosion rate
shall be determined by one of the following
methods:
1. A corrosion rate may be calculated from data collected by the owner or user on vessels in the same or similar service.
2. If data on vessels providing the same or similar service
is not available, a corrosion rate may be estimated from
the owner’s or user’s experience or from published data on
vessels providing comparable service.
3. If the probable corrosion rate cannot be determined by
either item a or item b above, on-stream determination
shall be made after approximately 1000 hours of service
by using suitable corrosion monitoring devices or actual
nondestructive thickness measurements of the vessel or
system. Subsequent determinations shall be made after
appropriate intervals until the corrosion rate is established.
The remaining life shall be determined by an individual
experienced in pressure vessel design and/or inspection. If it is
determined that an inaccurate assumption has been made for
either corrosion rate or thickness, the remaining life shall be
increased or decreased to agree with the actual rate or thickness.
Other failure mechanisms (stress corrosion, brittle fracture,
blistering, and so forth,) shall be taken into account in determining the remaining life of the vessel.
8.3.3 External Inspections
The following apply to external inspections:
a. The external visual inspection shall, at least, determine the
condition of the shell, heads, nozzles, exterior insulation, supports and structural parts, pressure-relieving devices, allowance for expansion, and general alignment of the vessel on its
supports. Any signs of leakage should be investigated so that
the sources can be established. It is not necessary to remove
insulation if the entire vessel shell is maintained at a temperature sufficiently low or sufficiently high to prevent the condensation of moisture. Refer to API Recommended Practice
572 for guidelines on external vessel inspections.
b. Buried sections of vessels shall be monitored to determine
their external environmental condition. This monitoring shall
be done at intervals that shall be established based on corrosion-rate information obtained during maintenance activity
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on adjacent connected piping of similar material, information
from the interval examination of similarly buried corrosion
test coupons of similar material, information from representative portions of the actual vessel, or information from a sample vessel in similar circumstances.
c. Vessels that are known to have a remaining life of over 10
years or that are protected against external corrosion-for
example, (1) vessels insulated effectively to preclude the
entrance of moisture, (2)jacketed cryogenic vessels, (3) vessels installed in a cold box in which the atmosphere is purged
with an inert gas, and (4) vessels in which the temperature
being maintained is sufficiently low or sufficiently high to
preclude the presence of w a t e r d o not need to have insulation removed for the external inspection; however, the condition of their insulating system or their outer jacketing, such as
the cold box shell, shall be observed at least every 5 years and
repaired if necessary.
8.3.4 Vessel Classifications
The pressure vessel owner or user shall have the option to
establish vessel inspection classes by grouping vessels into
common classes of service, pressure, and/or risk. Vessel classifications shall be determined by an individual(s) experienced in the criteria outlined in the following. If vessels are
grouped into classes (such as lower andor higher risk), at a
minimum, the following shall be considered to establish the
risk class:
a. Potential for vessel failure, such as, minimum design
metal temperature; potential for cracking, corrosion, and erosion; and the existence of mitigation factors.
b. Vessel history, design, and operating conditions, such as,
the type and history of repairs or alterations, age of vessel,
remaining corrosion allowance, properties of contained fluids,
operating pressure, and temperature relative to design limits.
c. Consequences of vessel failure, such as, location of vessel
relative to employees or the public, potential for equipment
damage, and environmental consequences.
8.3.5 Inspection Intervals
The following apply to inspection intervals:
a. Inspections shall be performed at intervals determined by
the vessel’s risk classification. The inspection intervals for the
two main risk classifications (lower and higher) are deíìned
below. When additional classes are established, inspection
and sampling intervals shall be set between the higher risk
and lower risk classes as determined by the owner or user. If
the owner or user decides to not classi@ vessels into risk
classes, the inspection requirements and intervals of higherrisk vessels shall be followed.
b. Lower-risk vessels shall be inspected as follows:
1. Inspections on a representative sample of vessels in
that class, or all vessels in that class, may be performed.
PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,
REPAIR,
AND ALTERATION
2. External inspections shall be performed when an onstream or internal inspection is performed or at shorter
intervals at the owner or user’s option.
3. On-stream or internal inspections shall be performed at
least every 15 years or %-remaining corrosion-rate life,
whichever is less.
4. Any signs of leakage or deterioration detected in the
interval between inspections shall require an on-stream or
internal inspection of that vessel and a reevaluation of the
inspection interval for that vessel class.
Higher-risk vessels shall be inspected as follows:
1. External inspections shall be performed when an onstream or internal inspection is performed or at shorter
intervals at the owner or user’s option.
2. On-stream or internal inspections shall be performed at
least every 10 years or %-remaining corrosion rate life,
which ever is less.
3. In cases where the remaining life is estimated to be less
than 4 years, the inspection interval may be the full
remaining life up to a maximum of 2 years. Consideration
should also be given to increasing the number of vessels
inspected within that class to improve the likelihood of
detecting the worst-case corrosion.
4. Any signs of leakage or deterioration detected in the
interval between inspections shall require an on-stream or
internal inspection of that vessel and a reevaluation of the
inspection interval for that vessel class.
Pressure vessels (whether grouped into classes or not)
shall be inspected at intervals sufficient to insure their fitness
for continued service. Operational conditions and vessel
integrity may require inspections at shorter intervals than the
intervals stated above.
e. If service conditions change, the maximum operating
temperature, pressure, and interval between inspections must
be reevaluated.
f. For large vessels with two or more zones of differing corrosion rates, each zone may be treated independently regarding the interval between inspections.
8.3.6 Additional Inspection Requirements
Additional inspection requirements, regardless of vessel
classification, exist for the following vessels:
a. Vessels that have changed ownership and location must
have an on-stream or internal inspection performed to estab-
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8-3
lish the next inspection interval and to assure that the vessel is
suitable for its intended service. Inspection of new vessels is
not required if a manufacturer’s data report is available.
b. If a vessel is transferred to a new location, and it has been
more than 5 years since the vessel’s last inspection, an onstream or internal inspection is required. (Vessels in truckmounted, skid-mounted, ship-mounted, or barge-mounted
equipment are not included.)
c. Air receivers (other than portable equipment) shall be
inspected at least every 5 years.
d. Portable or temporary pressure vessels that are employed
for the purpose of testing oil and gas wells during completion
or recompletion shall be inspected at least once during each
3-year period of use. More frequent inspections shall be conducted if vessels have been in severe corrosive environments.
8.4
PRESSURETEST
When a pressure test is conducted, the test shall be in
accordance with the procedures in 6.5.
I
98
8.5 SAFETY RELIEF DEVICES
Safety relief devices shall be inspected, tested, and repaired
in accordance with 6.6.
8.6 RECORDS
The following records requirements apply:
a. Pressure vessel owners and users shall maintain pressure
vessel records. The preferred method of record keeping is to
maintain data by individual vessel. Where vessels are grouped
into classes, data may be maintained by vessel class. When
inspections, repairs, or alterations are made on an individual
vessel, specific data shall be recorded for that vessel.
b. Examples of information that may be maintained are vessel identification numbers; safety relief device information;
and the forms on which results of inspections, repairs, alterations, or reratings are to be recorded. Any appropriate
forms may be used to record these results. A sample pressure
vessel inspection record is shown in Appendix C. A sample
alteration or rerating of pressure vessel form is shown in
Appendix D. Information on maintenance activities and
events that affect vessel integrity should be included in the
vessel records.
I
98
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APPENDIX A-ASME
CODE EXEMPTIONS
The following classes of containers and pressure vessels
are excluded from the specific requirements of this inspection code:
generally recognized as piping components or accessories.
6. A vessel for containing water under pressure, including
vessels containing air, the compression of which serves
only as a cushion, when the following limitations are not
exceeded:
(a) A design pressure of 300 pounds per square inch
(2067.7 kilopascals).
(b) A design temperature of 210°F (99°C).
7. A hot water supply storage tank heated by steam or any
other indirect means when the following limitations are
not exceeded:
(a) A heat input of 200,000 British thermal units (21 1 x
108joules) per hour.
(b) A water temperature of 210°F (99°C).
(c) A nominal water-containing capacity of 120 gallons
(455 liters).
8. Vessels with an internal or external operating pressure
not exceeding 15 pounds per square inch (103.4 kilopascals) but with no limitation on size.
9. Vessels with an inside diameter, width, height, or crosssection diagonal not exceeding 6 inches (15 centimeters)
but with no limitation on their length or pressure.
10. Pressure vessels for human occupancy.
c. Pressure vessels that do not exceed the following volumes
and pressures:
1. Five cubic feet (0.141 cubic meters) in volume and 250
pounds per square inch (1723.1 kilopascals) design pressure.
2. One-and-one-half cubic feet (0.042 cubic meters) in
volume and 600 pounds per square inch (4136.9 kilopascals) design pressure.
a. Pressure vessels on movable structures covered by jurisdictional regulations:
1. Cargo or volume tanks for trucks, ships, and barges.
2. Air receivers associated with brakmg systems of
mobile equipment.
3. Pressure vessels installed in ocean-going ships, barges,
and floating craft.
b. All classes of containers listed for exemption from the
scope of Section VIII, Division 1, of the ASME Code:
1. Those classes of containers within the scope of other
sections of the ASME Code other than Section VIII.
2. Fired process tubular heaters.
3. Pressure containers that are integral parts or components of rotating or reciprocating mechanical devices, such
as pumps, compressors, turbines, generators, engines, and
hydraulic or pneumatic cylinders where the primary design
considerations or stresses are derived from the functional
requirements of the device.
4. Any structure whose primary function is transporting
fluids from one location to another within a system of
which it is an integral part (that is, piping systems).
5. Piping components such as pipe, flanges, bolting, gaskets,
valves, expansionjoints, fittings, and the pressure-containing
parts of other components such as strainers and devices
which serve such purposes as mixing, separating, snubbing, distributing, and metering or controlling flow as long
as the pressure-containing parts of these components are
A- 1
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APPENDIX B-AUTHORIZED
B.l
98
PRESSUREVESSEL INSPECTOR CERTIFICATION
Examination
B.2.3 An API certificate for an authorized pressure vessel
inspector is valid for three years from its date of issuance.
A written examination to certi@ inspectors within the
scope of API 5 10, Pressure Vessel Inspection Code: Muintenunce Inspection, Rating, Rep&< und Alteration, shall be
admuiistered by API or a third party designated by API. The
examination shall be based on the current API 51O Inspector
Certijïcution Body of Knowledge as published by API.
B.2.4 An API 5 10 authorized pressure vessel inspector certification is valid in all jurisdictions and any other location
that accepts or otherwise does not prohibit the use of API 5 1O.
B.3 Certification Agency
The American Petroleum Institute shall be the certi@ing
agency.
B.2 Certification
B.2.1 An API 510 authorized pressure vessel inspector certificate will be issued when an applicant has successfully
passed the API 5 1O certification examination and satisfies the
criteria for education and experience. Hisíher education and
experience, when combined, shall be equal to at least one of
the following:
98
B.4 Retroactivity
The certification requirements of API 5 10 shall not be retroactive or interpreted as applying before 12 months after the
date of publication of this edition or addendum of API 510.
The recertification requirements of API 510 paragraph B.5.2
shall not be retroactive or interpreted as applying before 3
years after the date of publication of this edition or addendum
ofAPI 510.
a. A Bachelor of Science degree in engineering or technology, plus one year of experience in supervision of inspection
activities or performance of inspection activities as described
inAPI 510.
b. A two-year degree or certificate in engineering or technology, plus two years of experience in the design, construction,
repair, inspection, or operation of pressure vessels, of which
one year must be in supervision of inspection activities or
performance of inspection activities as described in API 5 10.
c. A high school diploma or equivalent, plus three years of
experience in the design, construction, repair, inspection, or
operation of pressure vessels, of which one year must be in
supervision of inspection activities or performance of inspection activities as described in API 5 10.
d. A minimum of five years of experience in the design, construction, repair, inspection, or operation of pressure vessels, of
which one year must be in supervision of inspection activities
or performance of inspection activities as describe in API 5 10.
98
B.5 Recertification
B.5.1 Recertification is required 3 years from the date of
issuance of the API 5 10 authorized pressure vessel inspector
certificate. Recertification by written test will be required for
authorized pressure vessel inspectors who have not been
actively engaged as authorized pressure vessel inspectors
within the previous 3 years. Exams will be in accordance with
all provisions contained in API 5 1O.
B.5.2 “Actively engaged as an authorized pressure vessel
inspector” shall be defined by one of the following provisions:
a. A minimum of 20% of time spent performing inspection
activities or supervision inspection activities as described in
the API 5 1O inspection code over the most recent 3-year certification period.
b. Performance of inspection activities or supervision of
inspection activities on 75 pressure vessels as described in
API 5 1O over the most recent 3-year certification period.
B.2.2 An API 5 10 authorized pressure vessel inspector certificate may be issued when an applicant provides documented evidence of passing the National Board of Boiler and
Pressure Vessel Inspectors examination and meets all requirements for education and experience of API 5 10.
Note: Inspection activities common to other API inspection documents
(NDE, record-keeping, review of welding documents, etc.) may be considered here.
B-1
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98
98
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APPENDIX C-SAMPLE
PRESSUREVESSEL INSPECTION RECORD
c-I
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PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION,
RATING,REPAIR,
AND ALTERATION
SAMPLE PRESSURE VESSEL
INSPECTION RECORD
c-3
Form Date
Form No.
Owner or User
Vessel Name
Description
Name of Process
Location
Internal Diameter
Tangent Length/Height
Shell Material Specification
Head Material Specification
Internal Materials
Nominal Shell Thickness
Nominal Head Thickness
Design Temperature
Maximum Allowable Working
Pressure
Maximum Tested Pressure
Design Pressure
Relief Valve Set Pressure
Contents
Special Conditions
Owner or User Number
Jurisdiction/NationaI Board Number
Manufacturer
Manufacturer's Serial No.
Date of Manufacture
Contractor
Drawing Numbers
Construction Code
Joint Efficiency
Type Heads
Type Joint
Flange Class
Coupling Class
Number of Manways
Weight
Thickness Measurements
Sketch or
Location
Description
Location
Number
Comments (See Note 2)
Method
Authorized Inspector
Notes:
1. Use additional sheets, as necessary.
2. The location that each comment relates to must be described
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Original
Thickness
Required Minimum
Thickness
Date
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APPENDIX D C A M P L E REPAIR, ALTERATION, OR RERATING
OF PRESSUREVESSEL FORM
D-I
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PRESSURE VESSEL INSPECTION CODE MAINTENANCE
INSPECTION, RATING, REPAIR,
AND ALTERATION
SAMPLE REPAIR ALTERATION OR
RERATING OF PRESSUREVESS”
-----
5. Original Construction Code
6. Original Maximum Allowable Working Pressure
7. Original Design Temperature
8. Original Minimum Design Metal Temperature
9. Original Test Pressure
D-3
Form Date
Form No.
Owner or User Name
Year Built
Year Built
At Pressure
Fluid
1O. Shell Material
Position
Head Material
I
~
11. Shell Thickness
12. Original Joint Efficiency
O
13. Original Radiography
O
14. Original PWHT
If yes,
Temp (“F)
15. Original Corrosion Allowance
O
16. Work on Vessel Classified as:
17. Organization Performing Work
18. Construction Code for Present Work
19. New Vessel Identification Number (if Applicable)
20. New Vessel Location (if Applicable)
21. New Maximum Allowable Working Pressure
22. New Design Temperature
23. New Minimum Design Metal Temperature
24. New PWHT
O
Temp (“F)
Head Thickness
Yes
Yes
O No
O No
Time (Hrs)
Repair
Yes
O Alteration
O Rerating
At Pressure
O No
Time (Hrs)
25. New Joint Efficiency, if Applicable E =
26. Type of Examination or Inspection Performed:
O radiographic
O ultrasonic
O magnetic particle
O penetrant
O visual
O other
Test Medium
27. New Pressure Test if Yes, Pressure
28. New Corrosion Allowance
29. Describe work performed (attach drawings, calculations, and other pertinent data):
Test Position
Statement of Compliance
We certify that the statements made in this report are correct and that all material and construction for and workmanship of this
O repair O alteration, O rerating conform to the requirements of the
Edition of API 510, Pressure Vessel Inspection Code.
(repair, alteration. or rerating organization)
Signed
Date
I
(authorized representative)
Statement of Inspection
I, the undersigned, an inspector employed by
, having inspected the work described above, state
that to the best of my knowledge, the work has been satisfactorily completed in accordance with the
Edition ofAPI 510,
Pressure Vessel Inspection Code.
Signed
API 510 Certification Number
Date
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APPENDIX E-TECHNICAL
E.1 Introduction
standard on the basis of new data or technology, Inquiries
shall be submitted in the following format:
API will consider written requests for interpretations of
API 510. API staff will make such interpretations in writing
after consultation, if necessary, with the appropriate committee officers and the committee membership. The API committee responsible for maintaining API 510 meets regularly to
consider written requests for interpretations and revisions and
to develop new criteria as dictated by technological development. The commiitee’s activities in this regard are limited
strictly to interpretations of the standard or to the consideration of revisions to the present standard on the basis of new
data or technology. As a matter of policy, API does not
approve, certify, rate, or endorse any item, construction, proprietary device, or activity; thus, accordingly, inquiries requiring such consideration will be reîurned. Moreover, API does
not act as a consultant on specific engineering problems or on
the general understanding or application of the rules. If, based
on the inquiry information submitted, it is the opinion of the
committee that the inquirer should seek assistance, the
inquiry will be returned with the recommendation that such
assistance be obtained.
All inquiries that cannot be understood because they lack
information will be returned.
a. Scope. The inquiry shall involve a single subject or closely
related subjects. An inquiry letter concerning unrelated subjects will be returned.
b. Background. The inquiry letter shall state the purpose of
the inquiry, which shall be either to obtain an interpretation of
the standard or to propose consideration of a revision to the
standard. The letter shall provide concisely the information
needed for complete understanding of the inquiry (with
sketches, as necessary). This information shall include reference to the applicable edition, revision, paragraphs, figures,
and tables.
c. Inquiry. The inquiry shall be stated in a condensed and
precise question format. Superfìuous background information
shall be omitted from the inquiry, and where appropriate, the
inquiry shall be composed so that “yes” or “no” (perhaps with
provisos) would be a suitable reply. This inquiry statement
should be technically and editorially correct. The inquirer
shall state what he believes the standard requires. If in his
opinion a revision to the standard is needed, he shall provide
recommended wording.
The inquiry should be typed; however, legible handwritten
inquiries will be considered. The name and the mailing
address of the inquirer must be included with the proposal.
The proposal shall be submitted to the following address:
director of the Standards Department, American Petroleum
Institute, 1220 L Street, N.W., Washington, D.C. 20005-4070,
[email protected].
E.2 Inquiry Format
Inquiries shall be limited strictly to requests for interpretation of the standard or to the consideration of revisions to the
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INQUIRIES
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Additional copies are available through Global Engineering
Documents at (800) 854-7179 or (303) 397-7956
Information about API Publications, Programs and Services is
available on the World Wide Web at: http://www.api.org
American
Petroleum
Institute
1220 L Street, Northwest
Washington, D.C. 20005-4070
202-682-8000
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Product No. C510A3
American
Petroleum
Institute
1220 L Street, Northwest
Washington, D.C. 20005-4070
202-682-8000
Date: December 2000
To: Purchasers of API 5 10, Pressure Vessel Inspection Code: Maintenance Inspection,
Rating, Repair, and Alteration, Eighth Edition
Re: Addendum 2
This package contains Addendum 2 of API 5 10, Pressure Vessel Inspection Code: Maintenance
Inspection, Rating, Repair, and Alteration, Eighth Edition. This package consists of the pages that have
changed since the December 1998 printing of API 510 Addendum 1.
To update your copy of API 5 10, replace the following pages as indicated:
Old Pages to be Replaced
front covers
New Pages
front cover and
inside front cover
back cover
back cover and
inside back cover
Title Page
title page and Special Notes page
title page and Special Notes page
Front Matter
iii-iv
iii-iv
Table of Contents
v-vi
v-vi
Section 2
2- 1
2-1 (+blank)
Section 3
3-1-3-2
3-1-3-2
Section 4
4- 1
4-1 (+blank)
Section 5
5-1-5-2
5-1-5-2
Section 6
6-3-6-5
6-3-6-5 (+blank)
Section 7
7-1-7-4
7-1-7-6
Part of Book Changed
Cover
The parts of the text, tables, and figures that contain changes are indicated by a vertical bar and a
small “00” in the margin.
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Pressure Vessel Inspection Code:
Maintenance Inspection, Rating,
Repair, and Alteration
API 510
EIGHTH EDITION, JUNE 1997
ADDENDUM 1, DECEMBER 1998
ADDENDUM 2, DECEMBER 2000
American
Petroleum
Institute
Helping You
Get The Job
Done Right?
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Pressure Vessel Inspection Code:
Maintenance Inspection, Rating,
Repair, and Alteration
Downstream Segment
API 510
EIGHTH EDITION, JUNE 1997
ADDENDUM 1, DECEMBER 1998
ADDENDUM 2, DECEMBER 2000
American
Petroleum
Institute
Helping You
Get The Job
Done Right..
COPYRIGHT American Petroleum Institute
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SPECIAL NOTES
API publications necessarily address problems of a general nature. With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed.
API is not undertaking to meet the duties of employers, manufacturers, or suppliers to
warn and properly train and equip their employees, and others exposed, Concerning health
and safety risks and precautions, nor undertaking their obligations under local, state, or
federal laws.
Information concerning safety and health risks and proper precautions with respect to particular materials and conditions should be obtained from the employer, the manufacturer or
supplier of that material, or the material safety data sheet.
Nothing contained in any API publication is to be construed as granting any right, by
implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent. Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent.
Generally,MI standards are reviewed and revised, reaffirmed, or withdrawn at least every
five years. Sometimes a one-time extension of up to two years will be added to this review
cycle. This publication will no longer be in effect five years after its publication date as an
operative API standard or, where an extension has been granted, upon republication. Status
of the publication can be ascertained from the API Authoring Department [telephone (202)
682-8000]. A catalog of API publications and materials is published annually and updated
quarterly by API, 1220 L Street, N.W., Washington, D.C. 20005.
This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API
standard. Questions Concerning the interpretation of the content of this standard or comments and questions concerning the procedures under which this standard was developed
should be directed in writing to the manager of the Standards Department, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. Requests for permission to
reproduce or translate all or any part of the material published herein should also be
addressed to the director.
API standards are published to facilitate the broad availability of proven, sound engineering and operating practices. These standards are not intended to obviate the need for applying sound engineering judgment regarding when and where these standards should be
utilized. The formulation and publication of API standards is not intended in any way to
inhibit anyone from using any other practices.
Any manufacturer marking equipment or materials in conformance with the marking
requirements of an API standard is solely responsible for complying with all the applicable
requirements of that standard. API does not represent, warrant, or guarantee that such products do in fact conform to the applicableM I standard.
All rights reserved. No part of this work may be reproduced, stored in a retrieval system, or
transmitted by any means, electronic, mechanical,photocopying, recording, or otherwise,
without prior written permissionfrom the publisher. Contact the Publisher,
API Publishing Services, 1220 L Street, N.W., Washington,D.C. 20005.
Copyright O 1997, 1998,2000American Petroleum Institute
COPYRIGHT American Petroleum Institute
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FOREWORD
98
In December i 93 i , API and the American Society of Mechanical Engineers (ASME) created the Joint APUASME Committee on Unfired Pressure Vessels. This committee was created to formulate and prepare for publication a code for safe practices in the design,
construction, inspection, and repair of pressure vessels to be used in the petroleum industry.
Entitled APUASME Code for Unjred Pressure Vesselsfor Petroleum Liquids and Gases
(commonly called the APIIASME Code for Unjred Pressure Vessels or APUASME Code),
the first edition of the code was approved for publication in 1934.
From its inception, the APUASME Code contained Section I, which covered recommended practices for vessel inspection and repair and for establishing allowable working
pressures for vessels in service. Section I recognized and afforded well-founded bases for
handling various problems associated with the inspection and rating of vessels subject to
corrosion. Although the provisions of Section I (like other parts of the APUASME Code)
were originally intended for pressure vessels installed in the plants of the petroleum industry,
especially those vessels containing petroleum gases and liquids, these provisions were actually considered to be applicable to pressure vessels in most services. ASME’s Boiler and
Pressure Vessel Committee adopted substantially identical provisions and published them as
a nonmandatory appendix in the 1950, 1952,1956, and 1959 editions of Section V U of the
ASME Boiler and Pressure Vessel Code.
After the API/ASME Code was discontinued in 1956, a demand arose for the issuance of
Section I as a separate publication, applicable not only to vessels built in accordance with
any edition of the APUASME Code but also to vessels built in accordance with any edition
of Section VI11 of the ASME Code. Such a publication appeared to be necessary to assure
industry that the trend toward uniform maintenance and inspection practices afforded by
Section I of the API/ASME Code would be preserved. API 510, first published in 1958, is
intended to satisfy this need.
The procedures in Section I of the 1951 edition of the APUASME Code, as amended by
the March 16, 1954 addenda, have been updated and revised in API 510. Section I of the
APUASME Code contained references to certain design or construction provisions, so these
references have been changed to refer to provisions in the ASME Code. Since the release of
the 1960 edition of the National Board Inspection Code, elements of the APUASME Code
have also been carried by the National Board Inspection Code.
It is the intent of API to keep this publication up to date. All pressure vessel owners and
operators are invited to report their experiences in the inspection and repair of pressure vesseis whenever such experiences may suggest a need for revising or expanding the practices
set forth in API 510.
This edition of API 510 supersedes all previous editions of M I 510, Pressure Vessel
Inspection Code: Maintenance Inspection, Rating, and Repair of Pressure Vessels. Each edition, revision, or addenda to this API standard may be used beginning with the date of issuance shown on the cover page for that edition, revision, or addenda. Each edition, revision,
or addenda to this API standard becomes effective 6 months after the date of issuance for
equipment that is rerated, reconstructed, relocated, repaired, modified (altered), inspected,
and tested per this standard. During the 6-month time between the date of issuance of the
edition, revision, or addenda and the effective date, the user shall specify to which edition,
revision, or addenda, and the equipment is to be rerated, reconstructed, relocated, repaired,
modified (altered), inspected and tested.
API publications may be used by anyone desiring to do so. Every effort has been made by
the Institute to assure the accuracy and reliability of the data contained in them; however, the
Institute makes no representation, warranty, or guarantee in connection with this publication
and hereby expressly disclaims any liability or responsibility for loss or damage resulting
from its use or for the violation of any federal, state, or municipal regulation with which this
publication may conflict.
Suggested revisions are invited and should be submitted to the standardization manager,
American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005-4070.
iii
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IMPORTANT INFORMATIONCONCERNING USE OF ASBESTOS
OR ALTERNATIVE MATERIALS
Asbestos is specified or referenced for certain components of the equipment described in
some N I standards. It has been of extreme usefulness in minimizing fire hazards associated
with petroleum processing. It has also been a universal sealing material, compatible with
most refining fluid services.
Certain serious adverse health effects are associated with asbestos, among them the senous and often fatal diseases of lung cancer, asbestosis, and mesothelioma (a cancer of the
chest and abdominal linings). The degree of exposure to asbestos varies with the product and
the work practices involved.
Consult the most recent edition of the Occupational Safety and Health Administration
(OSHA), U.S. Department of Labor, Occupational Safety and Health Standard for Asbestos,
Tremolite, Anthophyllite, and Actinolite, 29 Code of Federal Regulations Section
1910.1001; the U.S. Environmental Protection Agency, National Emission Standard for
Asbestos, 40 Code of Federal Regulations Sections 61.140 through 61.156; and the U.S.
Environmental Protection Agency (EPA) rule on labeling requirements and phased banning
of asbestos products, published at 54 Federal Register 29460 (July 12,1989).
There are currently in use and under development a number of substitute materials to
replace asbestos in certain applications. Manufacturers and users are encouraged to develop
and use effective substitute materials that can meet the specifications for, and operating
requirements of, the equipment to which they would apply.
SAFETY AND HEALTH INFORMATION WITH RESPECT TO PARTICULAR
PRODUCTS OR MATERIALS CAN BE OBTAINED FROM THE EMPLOYER, THE
MANUFACTURER OR SUPPLIER OF THAT PRODUCT OR MATERIAL, OR THE
MATERIAL SAFETY DATA SHEET.
iv
COPYRIGHT American Petroleum Institute
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CONTENTS
Page
1
SCOPE............................................................................................................................
1.1 General Application ....................................................................................................
1.2 SpecificApplications...................................................................................................
1-1
1-1
1-1
00
I
2 REFERENCES...............................................................................................................
2-1
00
I
3 DEFINITIONS ...............................................................................................................
3-1
4 OWNER-USER INSPECTION ORGANIZATION .....................................................
4.1 General ......................................
.................................................
98
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98
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00
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98
I
4-1
4-1
4.2 API Authorized Pressure Vessel Inspector Qualification and Certification ............... 4-1
4.3 Owner-User Organization Responsibilities......... .................................................
4-1
4-1
4.4 API Authorized Pressure Vessel Inspector Duty . .................................................
5 INSPECTION PRACTICES........
....................................................................
5.1 Preparatory Work .....................
....................................................................
.................................................
5.2 Modes of Deterioration and Fa¡
5.3 Corrosion-Rate Determination........
...............................................................
5.4 Maximum Allowable Working Pres
termination ............................................
5.5 Defect Inspection.......................
...............................................................
5.6 Inspection of Parts ........................
....................................................................
5.7 Corrosion and Minimum Thickness Evaluation .........................................................
5-1
5-1
5-1
5-1
5-1
5-2
5-2
5-3
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6 INSPECTION AND TESTING OF PRESSURE VESSELS AND
PRESSURE-RELIEVINGDEVICES...........................................................................
6.1 General ........................................................................................................................
6.2 Risk-Based Inspection.................................................................................................
6.3 External Inspection......................................................................................................
6.4 Internal and On-Stream Inspection .............................................................................
6.5 Pressure Test ................................................................................................................
6.6 Pressure-Relieving Devices ........................................................................................
6.7 Records ........................................................................................................................
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7 REPAIRS. ALTERATIONS. AND RERATING OF PRESSURE VESSELS ............. 7-1
7.1 General .........................................................
.......................................................... 7-1
7.2 Welding.........................................................
.......................................................... 7-1
7.3 Rerating .......................................................................................................................
7-3
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98
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6-1
6-1
6-1
6-1
6-1
6-3
6-3
6-4
8 ALTERNATIVE RULES FOR EXPLORATION AND PRODUCTION
PRESSURE VESSELS ..................................................................................................
8.1 Scope and SpecificExemptions..................................................................................
8.2 Glossary of Terms .......................................................................................................
8.3 Inspection Program ................
...............................................................
8.4 Pressure Test ...............................
...............................................................
8.5 Safety Relief Devices .............
................................................
8.6 Records ...................................
...............................................................
8-1
8-1
8-1
8-1
8-3
8-3
8-3
APPENDIX A- ASME CODE EXFiMJTIONS ...............................................................
A- 1
COPYRIGHT American Petroleum Institute
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CONTENTS
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I
APPENDIX B -AUTHORIZED PRESSURE VESSEL INSPECTOR
CERTIFICATION....................................................................................
B- i
APPENDIX C- SAMPLE PRESSURE VESSEL INSPECTION RECORD ................. C- 1
APPENDIX D-SAMPLE REPAIR, ALTERATION, OR RERATING OF
PRESSURE VESSEL FORM .................................................................
D-1
APPENDIX E-TECHNICAL INQUIRIES.....................................................................
E-1
Table
5-1 -Values of Spherical Radius Factor K .....................................................................
5-4
Figure
7-1 -Rerating Vessels Using the Latest Edition or Addendum of the ASME
Code Allowable Stresses......................................................................................................
7-5
,
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vi
COPYRIGHT American Petroleum Institute
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PRESSURE
VESSELINSPECTION
CODE.
MAINTENANCE
INSPECTION,
2 References
The most recent editions of the following standards, codes,
and specifications are cited in this inspection code.
98
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98
I
API
RP 572
RP 574
RP 576
RP 579
Pub1 2201
Inspection of Pressure Vessels
Inspection of Piping System Components
Inspection of Pressure-RelievingDevices
Fitness-For-Service
Proceduresfor Welding or Hot Tapping on
Equipment in Service
API 510
Inspector Cert$cation Examination Body
of Knowledge
Guide for Inspection of Rejnery Equipment, Chapter II,
“Conditions Causing Deterioration or
Failures”
Note: This publication is out of print. To obtain
a copy please inform the person taking your
order that you require this publication for the
API 510 Inspector Certification Exam.
RATING,
REPAIR,AND ALTERATION
2-1
ASME’
Boiler and Pressure Vessel Code, Section V, Section VI,
Section VII, Section VIU, Section
Section XI
NACE2
RP 0472
MR O175
IX,and
Methods and Controls to Prevent In-Service Environmental Cracking of Carbon
Steel Weldments In Corrosive Petroleum
Refining Environments
Standard Materials Requirements, SuIJide
Stress Cracking Resistant Metallic Materials for Oi@eldEquipment
National Board3
NB-23
National Board Inspection Code
WRC4
Bulletin 412
Challenges and Solutions in Repair Welding for Power and Processing Plants
ASN?
CP-189
Standard for Qualijîcation and Certijcation of Nondestructive Testing Personnel
Recommended Practice SNT-TC-1 A
IASME International, Three Park Avenue, New York, NY 100165990, www.asme.org.
*NACE International, P.O. Box 218340, Houston, Texas, 772188340, www.nace.org.
3National Board of Boiler and Pressure Vessel Inspectors, 1055
Crupper Avenue, Columbus, Ohio 43229, www.nationalboard.com.
4The Welding Research Council,3 Park Avenue, 27th Floor, New
York, NY 10016-5902, www.forengineers.org.
5American Society for Nondestructive Testing, Inc., 1711 Adingate
Lane, P.O. Box 28518, Columbus, Ohio, 43228-0518, www.asnt.org.
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PRESSURE
VESSELINSPECTION
CODE:MAINTENANCE
INSPECTION.
3 Definitions
For the purposes of this standard, the following definitions
apply.
3.1 alteration: A physical change in any component or a
rerating that has design implications that affect the pressure-containing capability of a pressure vessel beyond the
scope of the items described in existing data reports. The
following should not be considered alterations: any comparabie or duplicate replacement, the addition of any reinforced nozzle less than or equal to the size of existing
reinforced nozzles, and the addition of nozzles not requiring
reinforcement.
3.2 ASME C0de:Abbreviation and shortened title for the
ASME Boiler and Pressure Vessel Code. This abbreviated
title includes the addenda and code cases of the ASME Boiler
and Pressure Vessel Code.
The ASME Code is written for new construction; however, most of the technical requirements for design, welding, examination, and materiais can be applied in the
maintenance inspection, rating, repair, and alteration of
operating pressure vessels. When the ASME Code cannot be
followed because of its new construction orientation (new or
revised material specifications, inspection requirements,
certain heat treatments and pressure tests, and stamping and
inspection requirements), the engineer or inspector shall
conform to this inspection code rather than to the ASME
Code. If an item is covered by requirements in the ASME
Code and this inspection code or if there is a conflict
between the two codes, for vessels that have been placed in
service, the requirements of this inspection code shall take
precedence over the ASME Code. As an example of the
intent of this inspection code, the phrase “applicable
requirements of the ASME Code” has been used in this
inspection code instead of the phrase “in accordance with
the ASME Code.”
3.3 authorized pressure vessel inspector: An
employee of an authorized inspection agency who is qualified and certified to perform inspections under this inspection code.
3.4 authorized inspection agency:Any one of the following:
a. The inspection organization of the jurisdiction in which
the pressure vessel is used.
b. The inspection organization of an insurance company that
is licensed or registered to write and actually does write pressure vessel insurance.
c. The inspection organization of an owner or user of pressure vessels who maintains an inspection organization for his
equipment only and not for vessels intended for sale or resale.
d. An independent organization or individual that is under
contract to and under the direction of an owner-user and that
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RATING,
REPAIR,AND ALTERATION
3-1
is recognized or otherwise not prohibited by the jurisdiction
in which the pressure vessel is used. The owner-user’s inspection program shall provide the controls that are necessary
when contract inspectors are used.
3.5 construction code: The code or standard to which a
vessel was originally built, such as APVASME, MI, or State
Speciaünon-ASME.
3.6 inspection code: Shortened title for API 510 used in
this publication.
3.7 inspector: Refers to an authorized pressure vessel
inspector in this document.
3.8 jurisdiction: A legally constituted government administration that may adopt rules relating to pressure vessels.
3.9 maximum allowable working pressure: The
maximum gauge pressure permitted at the top of a pressure
vessel in its operating position for a designated temperature. This pressure is based on calculations using the minimum (or average pitted) thickness for all critical vessel
elements, exclusive of thickness designated for corrosion
and loadings other than pressure.
3.10 minimum allowable shell thickness: The thickness required for each element of a vessel. The minimum
allowable shell thickness is based on calculations that consider temperature, pressure, and all loadings.
3.11 on-stream inspection: The inspection used to
establish the suitability of a pressure vessel for continued
operation. Nondestructive examination (NDE) procedures are
used to establish the suitability of the vessel, and the vessel
may or may not be in operation while the inspection is being
carried out. Because a vessel may be in operation while an
on-stream inspection is being carried out, an on-stream
inspection means essentially that the vessel is not entered for
internal inspection.
3.12 pressurevessel: A container designed to withstand
internal or external pressure. This pressure may be imposed
by an external source, by the application of heat from a direct
or indirect source, or by any combination thereof. This definition includes unfired steam generators and other vapor generating vessels which use heat from the operation of a
processing system or other indirect heat source. (Specific limits and exemptions of equipment covered by this inspection
code are given in Section 1 and Appendix A.)
3.13 pressure vessel engineer: Shall be one or more
persons or organizations acceptable to the owner-user who
are knowledgeable and experienced in the engineering disciplines associated with evaluating mechanical and material
characteristics which affect the integrity and reliability of
pressure vessels. The pressure vessel engineer, by consult-
3-2
API 510
ing with appropriate specialists, should be regarded as a
composite of all entities needed to properly assess the technical requirements.
3.14 quality assurance: All planned, systematic, and
preventative actions required to determine if materials, equipment, or services will meet specified requirements so that
equipment will perform satisfactorily in service. The contents
of a quality assurance inspection manual are outlined in 4.3.
3.15 repair: The work necessary to restore a vessel to a
condition suitable for safe operation at the design conditions.
If any repair changes the design temperature or pressure, the
requirements for rerating shall be satisfied. A repair can be
the addition or replacement of pressure or nonpressure parts
that do not change the rating of the vessel.
3.16 repair organization:Any one of the following:
a. The holder of a valid ASME Certificate of Authorization
that authorizes the use of an appropriate ASME Code symbol stamp.
b. An owner or user of pressure vessels who repairs his or her
own equipment in accordance with this inspection code.
c. A contractor whose qualifications are acceptable to the
pressure-vessel owner or user and who makes repairs in
accordance with this inspection code.
d. An individual or organization that is authorized by the
legal jurisdiction.
3.17 rerating: A change in either the temperature ratings
or the maximum allowable working pressure rating of a
vessel, or a change in both. The maximum allowable working temperature and pressure of a vessel may be increased
or decreased because of a rerating, and sometimes a rerating requires a combination of changes. Derating below
original design conditions is a permissible way to provide
for corrosion. When a rerating is conducted in which the
maximum allowable working pressure or temperature is
increased or the minimum temperature is decreased so that
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additional mechanical tests are required, it shall be considered an alteration.
3.18 examiner: A person who assists the API authorized
pressure vessel inspector by performing specific NDE on
pressure vessels but does not evaluate the results of those
examinations in accordance with API 510, unless specifically
trained and authorized to do so by the owner or user. The
examiner need not be certified in accordance with API 510 or
be an employee of the owner or user but shall be trained and
competent in the applicable procedures in which the examiner is involved. In some cases, the examiner may be required
to hold other certifications as necessary to satisfy the owner or
user requirements. Examples of other certification that may
be required are ASNT SNT-TC-IA, or CP189, or American
Welding SocietyhWelding Inspector Certification. The examiner's employer shall maintain certification records of the
examiners employed, including dates and results of personnel
qualifications and shall make them available to the API authorized pressure vessel inspector.
3.19 controlled-deposition welding: Any welding
technique used to obtain controlled grain refinement and tempering of the underlying heat affected zone (HAZ) in the base
metal. Various controlled-deposition techniques, such as temper-bead (tempering of the layer below the current bead being
deposited) and half-bead (requiring removal of one-half of
the first layer), are included. Controlled-deposition welding
requires control of the entire welding procedure including the
joint detail, preheating and post heating, welding technique,
and welding parameters. Refer to supporting technical information found in Welding Research Council Bulletin 412.
6American Welding Society, 550 N.W. LeJeune Road, Miami, F'L 33135.
www.aws.org.
PRESSURE
VESSELINSPECTION
CODE:MAINTENANCE
INSPECTION,
4 Owner-User Inspection Organization
4.1
98
An owner-user of pressure equipment shall exercise control
of the pressure vessel inspection program, inspection frequencies, and maintenance. The owner-user is responsible for the
function of an authorized inspection agency in accordance with
the provisions of API 5 10.The owner-user inspection organization shall control activities relating to the maintenance inspection, rating, repair, and alteration of these pressure vessels.
4.2
98
GENERAL
API AUTHORIZED PRESSUREVESSEL
INSPECTOR QUALIFICATION AND
CERTIFICATION
Authorized pressure vessel inspectors shall have education
and experience in accordance with Appendix B of this inspection code. Authorized pressure vessel inspectors shall be certified by the American Petroleum Institute in accordance with
the provisions of Appendix B.
4.3 OWNER-USER ORGANIZATION
RESPONSIBILITIES
An owner-user organization is responsible for developing,
documenting, implementing, executing, and assessing presprocedures that
sure vesse1 inspection systems and
will meet the requirements of this inspection code. These systems and procedures will be contained in a quality assurance
inspection manual and shall include the following:
a. Organization and reports of structurefor inspection personnel.
b. Documentation and maintenance of inspection and quality
assurance procedures.
c. Documentation and reports of inspection and test results.
d. Corrective action for inspection and test results.
e. Internai audits for compliance with the quality assurance
inspection manual.
f. Review and approval of drawings, design calculations, and
specifications for repairs, alterations, and reratings.
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RATING,REPAIRAND ALTERATION
4-1
g. Assurance that all jurisdictional requirements for pressure
vessel inspection, repairs, alterations, and rerating are continuously met.
h. Reports to the authorized pressure vessel inspector any
process changes that could affect pressure vessel integrity.
i. Training requirements for inspection personnel regarding
inspection tools, techniques, and technical knowledge base.
j. Controls necessary so that only qualified welders and procedures are used for all repairs and alterations.
k. Controls necessary so that only qualified nondestructive
examination (NDE) personnel and procedures are utilized.
1. Controls necessary so that only materials conforming to
the applicable section of the ASME Code are utilized for
repairs and alterations.
test equipment are properly maintained and calibrated.
n. Controls necessary so that the work of contract inspection
or repair organizations meet the same inspection requirements as the owner-user organization.
tem for pressure-relieving devices.
4.4 API AUTHORIZED PRESSUREVESSEL
INSPECTOR RESPONSIBILITIES
When inspections, repairs, or alterations are being conducted on pressure vessels, an API authorized pressure vessel inspector shall be responsible to the owner-user for
determining that the requirements ofAP1510 on inspection,
examination, and testing are met, and shall be directly
involved in the inspection activities. The API authorized
pressure vessel inspector may be assisted in performingvisual inspections by other properly trained and qualified
individuals, who may or may not be certified vessel inspectors. Personnel performing nondestructive examinations
shall meet the qualifications identified in 3.18 but need not
be API authorized pressure vessel inspectors. However, all
examination results must be evaluated and accepted by the
API authorized pressure vessel inspector.
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PRESSURE VESSEL INSPECTION CODE:
5
MAINTENANCE
INSPECTION.
Inspection Practices
5.1 PREPARATORY WORK
Safety precautions are important in pressure vessel inspection because of the limited access to and the confined spaces
of pressure vessels. Occupational Safety and Health Administration (OSHA) regulations pertaining to confined spaces and
any other OSHA safety rules should be reviewed and followed, where applicable.
For an internal inspection, the vessel should be isolated by
blinds or other positive methods from ail sources of liquids,
gases, or vapors. The vessel should be drained, purged,
cleaned, ventilated, and gas tested before it is entered. Where
required, protective equipment should be worn that will protect the eyes, lungs, and other parts of the body from specific
hazards that may exist in the vessel.
The nondestructive testing equipment used for the inspection is subject to the safety requirements customarily followed in a gaseous atmosphere. Before the inspection is
started, all persons working around the vessel should be
informed that people are going to be working inside it. People
working inside the vessel should be informed when any work
is going to be done on the exterior of it.
The tools and personnel safety equipment needed for the
vessel inspection should be checked before the inspection.
Other equipment that might be needed for the inspection,
such as planking, scaffolding, bosun's chairs, and portable
ladders, should be available if needed.
5.2
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98
MODES OF DETERIORATIONAND FAILURE
Contaminants in fluids handled in pressure vessels, such as
sulfur, chlorine, hydrogen sulfide, hydrogen, carbon, cyanides,
acids, water, or other corroding species may react with metals
and cause corrosion. Significant stress fluctuationsor reversals
in parts of equipment are common, particularly at points of
high secondary stress. If stresses are high and reversals are frequent, failure of parts may occur because of fatigue. Fatigue
failures in pressure vessels may also occur because of cyclic
temperature and pressure changes. Locations where metals
with different thermal coefficients of expansion are welded
together may be susceptible to thermal fatigue.
Deterioration or creep may occur if equipment is subjected
to temperatures above those for which it is designed. Since
metals weaken at higher temperatures, such deterioration may
cause failures, particularly at points of stress concentration.
Creep is dependent on time, temperature, stress, and material
creep strength, so the actual or estimated levels of these quantities should be used in any evaluations. At elevated temperatures, other metallurgical changes may also take place that
may permanently affect equipment.
For developing an inspection plan for equipment operating
at elevated temperatures [generally starting in the range of
750"-1000"F (400"-540"C), depending on operating condi-
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RATING,
REPAIRAND ALTERATION
5-1
tions and alloy], the following should be considered in assessing the remaining life:
a. Creep deformation and stress rupture.
b. Creep crack growth.
c. Effect of hydrogen on creep.
d. Interaction of creep and fatigue.
e. Possible metallurgical effects, including a reduction in
ductility.
Numerous NDE techniques can be applied to find and
characterize elevated temperature damage. These techniques
include visual, surface, and volumetric examination. Additionally, if desired or warranted, samples can be removed for
laboratory analysis.
The inspection plan should be prepared in consultation
with an engineer having knowledge of elevated temperature
and metallurgical effects on pressure vessel materials of construction.
At subfreezing temperatures, water and some chemicals
handled in pressure vessels may freeze and cause failure.
At ambient temperatures, carbon, low-alloy, and other ferritic steels may be susceptible to brittle failure. A number of
failures have been attributed to brittle fracture of steels that
were exposed to temperatures below their transition temperature and to pressures greater than 20 percent of the required
hydrostatic test pressure; most brittle fractures, however, have
occurred on the first application of a particular stress level (the
first hydrotest or overload). Although the potential for a brittle
failure because of excessive operating conditions below the
transition temperature shall be evaluated, the potential for a
brittle failure because of rehydrotesting or pneumatic testing of
equipmentor the addition of any other additional loadings shall
also be evaluated. Special attention should be given to lowalloy steels (especially 2% Cr-1Mo) because they may be
prone to temper embrittlement. [Temper embrittlement is a loss
of ductility and notch toughness due to postweld heat treatment
or high-temperatureservice (above 700'F) (37o"C).]
Other forms of deterioration, such as stress corrosion
cracking, hydrogen attack, carburization, graphitization, and
erosion, may also occur under special circumstances. These
forms of deterioration are more fully discussed in Chapter II
of the API Guidefor Inspection for Refinery Equipment.
5.3 CORROSION RATE DETERMINATION
For a new vessel or for a vessel for which service conditions are being changed, one of the following methods shall
be employed to determine the vessel's probable corrosion
rate. The remaining wall thickness at the time of the next
inspection can be estimated from this rate.
a. A corrosion rate may be calculated from data collected
by the owner or user on vessels providing the same or similar service.
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b. If data on vessels providing the same or similar service are
not available, a corrosion rate may be estimated from the
owner’s or user’s experience or from published data on vessels providing comparable service.
c. If the probable corrosion rate cannot be determined by
either item a or item b above, on-stream determinations shall
be made after approximately 1000 hours of service by using
suitable corrosion monitoring devices or actual nondestnictive thickness measurements of the vessel or system. Subsequent determinations shall be made after appropriate intervals
until the corrosion rate is established.
If it is determined that an inaccurate corrosion rate has
been assumed, the rate to be used for the next period shall be
increased or may be decreased to agree with the actual rate.
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inspection (see 5.7) minus twice the estimated corrosion loss
before the date of the next inspection, except as modified in
6.4. If the actual thickness determined by inspection is greater
than the thickness reported in the material test report or the
manufacturer’s data report, it must be confirmed by multiple
thickness measurements, taken at areas where the thickness of
the component in question was most likely affected by the
thinning due to forming. The thicnkess measurement procedure shall be approved by the authorized pressure vessel
inspector. Allowance shall be made for other loads in accor-
recommended inspection practices for pressure vessels, see
API Recommended Practice 572.)
Careful visual examination is the most important and the
most universally accepted method of inspection. Other methods that may be used to supplement visual inspection include
(a) magnetic-particle examination for cracks and other elongated discontinuities in magnetic materials; (b) fluorescent or
dye-penetrant examination for disclosing cracks, porosity, or
pin holes that extend to the surface of the material and for
outlining other surface imperfections, especially in nonmagnetic materials; (c) radiographic examination; (d) ultrasonic
thickness measurement and -flaw detection; (e) eddy current
examination; (0 metallographic examination; (8) acoustic
emission testing; hammer testing while not under pressure;
and (h) pressure testing. (Section V of the ASME Code can
be used as a guide for many of the nondestructive examination techniques.)
Adequate surface preparation is important for proper visual
examination and for the satisfactory application of any auxiliary procedures, such as those mentioned above. The type of
surface preparations required depends on the individual circumstances, but surface preparations such as wire brushing,
blasting, chipping, grinding, or a combination of these preparations may be required.
If extemal or internal coverings, such as insulation, refractory protective linings, and corrosion-resistant linings, are in
good condition and there is no reason to suspect that an
unsafe condition is behind them, it is not necessary to remove
them for inspection of the vessel; however, it may be advisable to remove small portions of the coverings to investigate
their condition and effectiveness and the condition of the
metal underneath them.
Where operating deposits, such as coke, are normally permitted to remain on a vessel surface, it is particularly important to determine whether such deposits adequately protect
the vessel surface from deterioration. To determine this, spot
examinations in which the deposit is thoroughly removed
from selected critical areas may be required.
Where vessels are equipped with removable intemals,
the intemals need not be removed completely as long as
reasonable assurance exists that deterioration in regions
rendered inaccessible by the intemals is not occurring to
an extent beyond that found in more accessible parts of
the vessel.
5.5 DEFECT INSPECTION
5.6 INSPECTION OF PARTS
Vessels shall be examined for visual indications of distortion. If any distortion of a vessel is suspected or observed, the
overall dimensions of the vessel shall be checked to confirm
whether or not the vessel is distorted and, if it is distorted, to
determine the extent and seriousness of the distortion. The
parts of the vessel that should be inspected most carefully
depend on the type of vessel and its operating conditions. The
authorized pressure vessel inspector should be familiar with
the operating conditions of the vessel and with the causes and
characteristics of potential defects and deterioration. (For
The following inspections are not all inclusive for every
vessel, but they do include the features that are common to
most vessels and that are most important. Authorized pressure vessel inspectors must supplement this list with any
additional items necessary for the particular vessel or vessels involved.
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a. Examine the surfaces of shells and heads carefully for possible cracks, blisters, bulges, and other signs of deterioration.
Pay particular attention to the skirt and to support-attachment
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resentative sample of vessel nozzles should be measured and
recorded, and the remaining life and next inspection interval
should be calculated for the limiting component. A decision on
the number and location of the thickness measurements should
consider results from previous inspections, if available, and the
potential consequence of loss of containment. Measurementsat
a number of thickness measurement locations (TMLs) are
intended to establish general and localized corrosion rates in
different sections of the vessel. A minimal number of TMLs are
acceptable when the established rate of corrosion is low and
not localized. For pressure vessels susceptible to localized corrosion, it is vital that those knowledgeable in localized corrosion mechanisms be consulted about the appropriate placement
and number of Th4Ls. Additionally, for localized corrosion, it
is important that inspections are conducted using scanning
methods such as profile radiography, scanning ultrasonics, and
or other suitable NDE methods that will reveal the scope and
extent of localized corrosion.
The remaining life of the vessel shall be calculated from
the following formula:
Remaining life (years) =
tactual - tminimum
corrosion rate
[inches (millimeters) per year]
Where:
tacma,
=
the thickness, in inches (millimeters), recorded
at the time of inspection for a given location or
component.
tmini,,, = minimum allowable thickness, in inches (millimeters), for a given location or component.
Corrosion rate =
tpreviuus - t,,,",I
years between tprevious
and taclual
tPKvi,, = the thickness, in inches (millimeters), at the same
location as tacmai
measured during a previous
inspection.
A statistical analysis may be used in the corrosion rate and
remaining life calculations for the pressure vessel sections.
This statistical approach may be applied for assessment of
substituting an internal inspection (item b in the preceding),
or for determining the intemal inspection interval. Care must
be taken to ensure that the statistical treatment of data results
reflects the actual condition of the vessel section. Statistical
analysis is not applicable to vessels with significant localized corrosion.
The determination of corrosion rate may include thickness
data collected at more than two different times. Suitable use
of short-term versus long-term corrosion rates shall be determined by the authorized pressure vessel inspector. When
there is a discrepancy between short-term and long-term corrosion rates, a pressure vessel engineer experienced in corro-
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RATING,REPAIR.
AND ALTERATION
6-3
sion may need to be consulted about the use of these rates, at
the discretion of the inspector, for calculating the remaining
life and next inspection date.
For a large vessel with two or more zones of differing
corrosion rates, each zone may be treated independently
regarding the interval between inspections or for substituting the internal inspection with an on-stream inspection. If a
multi-zone analysis is used, the zone with the shortest
remaining half-life shall be used as the limiting case for setting the internal inspection interval or for substituting the
internal inspection with an on-stream inspection.
An alternative method to establish the required inspection
interval based on remaining life is by calculation of the projected maximum allowable working pressure (MAW) of
each vessel component as described in 5.4. This procedure
may be iterative involving selection of an inspection interval,
determination of the corrosion loss expected over the interval,
and calculation of the projected MAW. The inspection interval is within the maximum permitted as long as the projected
M A W of the limiting component is not less than the lower
of the name plate or rerated MAW. The maximum inspection interval using this method is also 10 years.
When problems are experienced with external loading,
faulty material, or fabrication the remaining life as determined above shall be reduced to recognize those conditions.
If deterioration due to conditions such as those mentioned
in 5.2 is detected, the inspection interval must be appropriately adjusted.
If the service conditions of a vessel are changed, the maximum operating pressure, the maximum and minimum operating temperature, and the period of operation until the next
inspection shall be established for the new service conditions.
If both the ownership and the location of a vessel are
changed, the vessel shall be internally and externally
inspected before it is reused, and the allowable conditions of
service and the next period of inspection shall be established
for the new service.
6.5
PRESSURETEST
When the authorized pressure vessel inspector believes that
a pressure test is necessary or when, after certain repairs or
alterations, the inspector believes that one is necessary (see
7.2.9), the test shall be conducted at a pressure in accordance
with the construction code used for determining the maximum allowable working pressure. To minimize the risk of
brittle fracture during the test, the metal temperature should
be maintained at least 30°F (17°C) above the minimum
design metal temperature for vessels that are more than 2
inches (5 centimeters) thick, or 10°F (6°C) above for vessels
that have a thickness of 2 inches (5 centimeters) or less. The
test temperature need not exceed 120°F (50°C) unless there is
information on the brittle characteristics of the vessel material
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indicating that a lower test temperature is acceptable or a
higher test temperature is needed.5
Pneumatic testing may be used when hydrostatic testing is
impracticable because of temperature, foundation, refractory
lining, or process reasons; however, the potential personnel
and property risks of pneumatic testing shall be considered
before such testing is carried out. As a minimum, the inspection precautions contained in the ASME Code shall be
applied in any pneumatic testing. Before applying a hydrostatic test to equipment, consideration should be given to the
supporting structure and the foundation design.
When a pressure test is to be conducted in which the test
pressure will exceed the set pressure of the safety relief valve
with the lowest setting, the safety relief valve or valves should
be removed. An alternative to removing the safety relief
valves is to use test clamps to hold down the valve disks.
Applying an additional load to the valve spring by turning the
compression screw is not recommended. Other appurtenances, such as gauge glasses, pressure gauges, and rupture
disks, that may be incapable of withstanding the test pressure
should also be removed or should be blanked off or vented.
When the pressure test has been completed, pressure relief
devices of the proper settings and other appurtenances
removed or made inoperable during the pressure test shall be
reinstalled or reactivated.
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6.6
PRESSURE-RELIEVINGDEVICES
Pressure relief valves shall be tested and repaired by repair
organizations experienced in valve maintenance. Each repair
organization shall have a fully documented quality control
system. As a minimum, the following requirements and
pieces of documentation should be included in the quality
control system:
a. Title page.
b. Revision log.
C. Contents page.
d. Statement of authority and responsibility.
e. Organizational chart.
f. Scope of work.
g. Drawings and specification controls.
h. Material and part control.
1. Repair and inspection program.
j. Welding, nondestructive examination, and heat treatment
procedures.
k. Valve testing, setting, leak testing, and sealing.
1. General example of the valve repair nameplate.
m. Procedures for calibrating measurement and test gauges.
n. Controlled copies of the manual.
o. Sample forms.
p. Repair personnel training or qualifications.
'For vessels without minimum design metal temperature, the minimum
acceptable operating temperature should be used in lieu of the minimum
design metal temperature.
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Each repair organization shall also have a fully documented training program that shall ensure that repair personnel are qualified within the scope of the repairs.
Pressure relief valves shall be tested at intervals that are
frequent enough to verify that the valves perform reliably.
This may include testing pressure relief valves on newly
installed equipment. Pressure-relieving devices should be
tested and maintained in accordance with API Recommended
Practice 576. Other pressure-relieving devices, such as mpture disks and vacuum-breaker valves, shall be thoroughly
examined at intervals determined on the basis of service.
The intervals between pressure-relieving-device testing or
inspection should be determined by the performance of the
devices in the particular service concerned. Test or inspection
intervals on pressure-relieving devices in typical process services should not exceed 5 years, unless service experience
indicates that a longer interval is acceptable. For clean
(nonfouling), noncorrosive services, maximum intervals
may be increased to 10 years. When service records indicate
that a pressure-relieving device was heavily fouled or stuck in
the last inspection or test, the service interval shall be reduced
if the review shows that the device may not perform reliably
in the future. The review should include an effort to determine
the cause of the fouling or the reasons for the relief device not
operating properly.
6.7 RECORDS
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Pressure vessel owners and users shall maintain permanent
and progressive records of their pressure vessels. Permanent
records will be maintained throughout the service life of each
vessel; progressive records will be regularly updated to
include new information pertinent to the operation, inspection, and maintenance history of the vessel.
Pressure vessel records shall contain three types of vessel
information pertinent to mechanical integrity as follows:
a. Construction and design information. For example,
equipment serial number or other identifier, manufacturers'
data reports (MDRs), design specification data, design calculations (where MDRs are unavailable), and construction
drawings. For pressure vessels that have no nameplate and
minimal or no design and construction documentation, the
following steps may be used to verify operating integrity:
i. Perform inspection to determine condition of the vessel. Make any necessary repairs.
i¡. Define design parameters and prepare drawings and
calculations.
iii. Base calculations on applicable codes and standards
and condition of the vessel following any repairs. Do not
use allowable stress values based on design factor of 3.5.
See ASME Code Section VIII, Division 1, paragraph
UG-lO(c) for guidance on evaluation of unidentified
materials. If UG-10 (c) is not followed, then for carbon
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steels, use allowable stresses for SA-283 Grade C; and for
alloy and nonferrous materials, use xray fluorescence
analysis to determine material type on which to base
allowable stress values.
When extent of radiography originally performed is not
known, use joint factor of 0.7 for butt welds, or consider
performing radiography if a higher joint factor is required.
(Recognize that performing radiography on welds in a
vessel with minimal or no design and construction documentation may result in the need for a fitness-for-service
assessment and significant repairs.)
iv. Attach a nameplate or stamping showing the maximum allowable working pressure and temperature, minimum allowable temperature, and date.
v. Perform pressure test as soon as practical, as required
by code of construction used for design calculations.
mechanical integrity, inspection reports, and data for each
type of inspection conducted (for example, internal, external, thickness measurements), and inspection recommendations for repair. See Appendix C for sample pressure vessel
inspection records. Inspection reports shall document the
date of each inspection andor test, the date of the next
scheduled inspection, the name of the person who performed
the inspection andor test, the serial number or other identifier of the equipment inspected, a description of the inspection and/or test performed, and the results of the inspection
and/or test.
b. Operating and inspection history. For example, operating
conditions, including process upsets that may affect
rerating documentation (including rerating calculations, new
design conditions, and evidence of stamping).
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c. Repair, alteration, and rerating information. For example,
(i) repair and alteration forms like that shown in Appendix D,
(2)reports indicating that equipment still in-service with identified deficiencies or recommendations for repair are suitable
for continued service until repairs can be completed, and (3)
PRESSURE VESSEL INSPECTION CODE: MAINTENANCE
INSPECTION. RATING,
7 Repairs, Alterations, and Rerating of
PressureVessels
7.1 GENERAL
This section covers repairs and alterations to pressure vessels by welding. The requirements that must be met before
pressure vessels can be rerated are also covered in this section. When repairs or alterations have to be performed, the
applicable requirements of the ASME Code, the codes to
which the vessels were built, or other specific pressure vessel
rating codes shall be followed. Before any repairs or alterations are performed, ali proposed methods of execution, all
materials, and all welding procedures that are to be used must
be approved by the authorized pressure vessel inspector and,
if necessary, by a pressure vessel engineer experienced in
pressure vessel design, fabrication, or inspection.
7.1.1 Authorization
All repair and alteration work must be authorized by the
authorized pressure vessel inspector before the work is started
by a repair organization (see 3.13). Authorization for alterations to pressure vessels that comply with Section VIII,
Divisions 1 and 2, of the ASME Code and for repairs to pressure vessels that comply with Section VID, Division 2, of the
ASME Code may not be given until a pressure vessel engineer experienced in pressure vessel design has been consulted
about the alterations and repairs and has approved them. The
authorized pressure vessel inspector will designate the fabrication approvals that are required. The authorized pressure
vessel inspector may give prior general authorization for limited or routine repairs as long as the inspector is sure that the
repairs are the kind that will not require pressure tests.
7.1.2 Approval
The authorized pressure vessel inspector shall approve all
specified repair and alteration work after an inspection of the
work has proven the work to be satisfactory and any required
pressure test has been witnessed.
7.1.3 Defect Repairs
A crack in a welded joint and a defect in a plate may be
repaired by preparing a U- or V-shaped groove to the full
depth and length of the crack and then filling the groove with
weid metal deposited in accordance with 7.2. No crack shall
be repaired without authorization from the authorized pressure vessel inspector. Repairing a crack at a discontinuity,
where stress concentrations may be serious, should not be
attempted without prior consultation with a pressure vessel
engineer experienced in pressure vessel design.
Corroded areas, as defined by 5.7, may be restored with
weld metal deposited in accordance with 7.2. Surface irregularities and contamination shall be removed before welding.
The nondestructive examination and inspection appropriate
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REPAIRAND ALTERATION
7- 1
for the extent of restoration being performed shall be specified in the repair procedure.
7.2 WELDING
All repair and alteration welding shall be in accordance
with the applicable requirements of the ASME Code, except
as permitted in 7.2.11.
7.2.1 Procedures and Qualifications
The repair organization shall use qualified welders and
welding procedures qualified in accordance with the applicable requirements of Section IX of the ASME Code.
7.2.2 QualificationRecords
The repair organization shall maintain records of its qualified welding procedures and its welding performance qualifications. These records shall be available to the inspector prior
to the start of welding. The repair organization’s qualified
welding procedures and welding performance qualifications
shall be in accord with the appropriate code.
7.2.3 Preheat or Controlled DepositionWelding
Methods as Alternatives to Postweld Heat
Treatment
Preheat and controlled deposition welding, as described in
7.2.3.1 and 7.2.3.2, may be used in lieu of postweld heat
treatment (PWHT) where PWHT is inadvisable or mechanically unnecessary. Prior to using any alternative method, a
metallurgical review conducted by a pressure vessel engineer
shall be performed to assess whether the proposed alternative
is suitable for the application. The review should consider
factors such as the reason for the original PWHT of the
equipment, susceptibility of the service to promote stress corrosion cracking, stresses in the location of the weld, susceptibility to high temperature hydrogen attack, susceptibility to
creep, etc.
Selection of the welding method used shall be based on the
rules of the construction code applicable to the work planned
along with technical consideration of the adequacy of the
weld in the as-welded condition at operating and pressure test
conditions.
When reference is made in this section to materiais by the
ASME designation, P-Number and Group Number, the
requirements of this section apply to the applicable materiais
of the original code of construction, either ASME or other,
which conform by chemical composition and mechanical
properties to the ASME P-Number and Group Number designations.
Vessels constructed of steels other than those listed in
7.2.3.1 and 7.2.3.2 that initially required PWHT shall be
postweld heat treated if alterations or repairs involving pressure boundary welding are performed. When one of the fol-
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lowing methods is used as an alternative to PWHT, the
PWHT joint efficiency factor may be continued if the factor
has been used in the currently rated design.
7.2.3.1 Preheating Method (NotchToughness
Testing Not Required)
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a. Notch toughness testing is not required when this welding
method is used.
b. The materials shall be limited to P-No. 1 , Group 1, 2, and
3, and to P-No. 3, Group 1 and 2 (excluding Mn-Mo steels in
Group 2).
c. The welding shall be limited to the shielded-metal-arc
welding (SMAW), gas-metal-arc welding (GMAW), and gastungsten-arc welding (GTAW) processes.
d. The weid area shall be preheated and maintained at a minimum temperature of 300°F (150°C) during welding. The
300°F (15OOC) temperature should be checked to assure that
4 in. (10 mm) of the material or four times the material thickness (whichever is greater) on each side of the groove is
maintained at the minimum temperature during welding. The
maximum interpass temperature shall not exceed 600°F
(315°C). When the weld does not penetrate through the full
thickness of the material, the minimum preheat and maximum interpass temperatures need only be maintained at a distance of 4 in. (10 mm) or four times the depth of the repair
weid, whichever is greater on each side of the joint.
7.2.3.2 Controlled-DepositionWelding Method
(NotchToughnessTesting Required)
a. Notch toughness testing, such as that established by
ASME Code Section VIII - Division 1, parts UG-84 and
UCS-66, is necessary when impact tests are required by the
original code of construction or the construction code applicable to the work planned.
b. The materials shall be limited to P-No. 1, P-No. 3, and PNo. 4 steels.
c. The welding shall be limited to the shielded-metal-arc
welding (SMAW), gas-metal-arc welding (GMAW), and gastungsten-arc welding (GTAW) processes.
d. A weid procedure specification shall be developed and
qualified for each application. The welding procedure shall
define the preheat temperature and interpass temperature and
include the post heating temperature requirement in f (1)
below. The qualification thickness for the test plates and
repair grooves shall be in accordance with Table 7-1.
The test material for the welding procedure qualification
shall be of the same material specification (including specification type, grade, class and condition of heat treatment) as
the original material specification for the repair. If the original
material specification is obsolete, the test material used
should conform as much as possible to the material used for
construction, but in no case shall the material be lower in
strength or have a carbon content of more than 0.35%.
e. When impact tests are required by the construction code
applicable to the work planned, the PQR shall include sufficient tests to determine if the toughness of the weid metal and
the heat-affected zone of the base metal in the as-welded condition is adequate at the minimum design metal temperature
(such as the criteria used in ASME Code Section VIII - Division 1, parts UG-84 and UCS 66). If special hardness limits
are necessary (for example, as set forth in NACE RP 0472,
and MR 0175) for corrosion resistance, the PQR shall include
hardness tests as well.
f. The WPS shall include the following additional requirements:
1. The supplementary essential variables of ASME Code,
Section IX,paragraph QW-250, shall apply;
2. The maximum weld heat input for each layer shall not
exceed that used in the procedure qualification test;
3. The minimum preheat temperature for welding shall
not be less than that used in the procedure qualification
test;
4. The maximum interpass temperature for welding shall
not be greater than that used in the procedure qualification
test;
5. The preheat temperature shall be checked to assure that
4 in. (10 mm) of the material or four times the material
thickness (whichever is greater) on each side of the weld
joint will be maintained at the minimum temperature during welding. When the weid does not penetrate through
the full thickness of the material, the minimum preheat
temperature need only be maintained at a distance of 4 in.
(10 mm) or four times the depth of the repair weid, whichever is greater on each side of the joint;
Table 7-l-Welding Methods as Alternatives to Postweld Heat Treatment
QualificationThickneeses For Test Plates and Repair Grooves
Depth t of Test
Groove Welded"
t
t
Repair Groove
Depth Qualified
<t
<t
Thickness T of Test
Coupon Welded
<2 in. (50mm)
>2 in. (50mm)
Thickness of Base Metal
Qualified
<T
2 in. (50mm) to unlimited
T h e depth of the groove used for procedure qualification must be deep enough to allow removal of the required test specimens.
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6. For the welding processes in 7.2.3.2 (c). use only electrodes and filler metals that are classified by the filler
metal specification with an optional supplemental diffusible-hydrogen designator of H8 or lower. When shielding
gases are used with a process, the gas shall exhibit a dew
point that is no higher than -60°F (-50°C). Surfaces on
which welding will be done shall be maintained in a dry
condition during welding and free of rust, mill scale and
hydrogen producing contaminants such as oil, grease and
other organic materiais;
7. The welding technique shall be a controlled-deposition, temper-bead or half-bead technique. The specific
technique shall be used in the procedure qualification test;
8. For welds made by SMAW, after completion of welding and without allowing the weldment to cool below the
minimum preheat temperature, the temperature of the
weldment shall be raised to a temperature of 500°F f 50°F
(260°C 30°C) for a minimum period of two hours to
assist out-gassing diffusion of any weld metal hydrogen
picked up during welding. This hydrogen bake-out treatment may be omitted provided the electrode used is classified by the filler metal specification with an optional
supplemental diffusable-hydrogen designator of H4 (such
as E7018-H4); and
9. After the finished repair weid has cooled to ambient
temperature, the final temper bead reinforcement layer
shall be removed substantially flush with the surface of the
base material.
7.2.4 Nondestructive Examination of Welds
oc
Prior to welding, the area prepared for welding shall be
examined using either the magnetic particle (MT) or the liquid penetrant (PT)examination method to determine that no
defects exist. After the weld is completed, it shall be examined again by either of the above methods to determine that
no defects exist using acceptance standards acceptable to the
Inspector or code of construction most applicable to the work
planned. In addition, welds in a pressure vessel that was originally required to be radiographed by the rules of the original
code of consiruction, shall be radiographically examined. In
situations where it is not practical to perform radiography the
accessible surfaces of each non-radiographed repair weld
shall be fully examined using the most appropriate nondestructive examination method to determine that no defects
exist, and the maximum allowable working pressure andor
allowable temperature shall be reevaluated to the satisfaction
of the authorized pressure vessel inspector and jurisdiction at
the location of installation.
7.2.5 Local Postweld HeatTreatment
Note: Before local postweld heat treatment is used, a metallurgical review
must be conducted to determine if the vessel was postweld heat treated due to
the characteristics of the fluid contained in it.
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RATING,REPAIR.AND ALTERATION
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Local postweld heat treatment (PWHT) may be substituted
for 360-degree banding on local repairs on all materials, provided that the following precautions are taken and requirements are met:
a. The application is reviewed, and a procedure is developed
by pressure vessel engineers experienced in the appropriate
engineering specialties.
b. The suitability of the procedure is evaluated. In evaluating
the suitability of the procedure, the following shall be considered: applicable factors, such as base metal thickness, decay
thermal gradients, and material properties (hardness, constituents, strength, and the like); changes due to local postweld
heat treatment; the need for full penetration welds; and surface and volumetric examinations after local postweld heat
treatment. In evaluating and developing local postweld heat
treatment procedures, the overall and local strains and distortions resulting from the heating of a local restrained area of
the pressure vessel shell shall be considered.
c. A preheat of 300°F (150°C) or higher, as specified by specific welding procedures, is maintained during welding.
d. The required local postweld heat treatment temperature
shall be maintained for a distance of not less than two times
the base metal thickness measured from the weld. The local
postweld heat treatment temperature shall be monitored by a
suitable number of thermocouples (at least two). (When
determining the number of thermocouples necessary, the size
and shape of the area being heat treated should be considered.)
Heat shall be applied to any nozzle or any attachment
within the local postweld heat treatment area.
7.2.6 Repairs to Stainless SteelWeld Overlay and
Cladding
The repair procedure(s) to restore removed, corroded, or
missing clad or overlay areas shall be reviewed and endorsed
prior to implementation by the pressure vessel engineer and
authorized by the inspector.
Consideration shall be given to factors which may augment
the repair sequence such as stress level, P number of base
material, service environment, possible previously dissolved
hydrogen, type of lining, deterioration of base metal properties (by temper embrittlement of chromium-molybdenum
alloys), minimum pressurization temperatures, and a need for
future periodic examination.
For equipment which is in hydrogen service at an elevated
temperature or which has exposed base metal areas open to
corrosion which could result in a significant atomic hydrogen
migration in the base metal, the repair must additionally be
considered by the pressure vessel engineer for factors affecting the following:
a. Outgassing base metal.
b. Hardening of base metal due, to welding, grinding, or arc
gouging.
API 510
7-4
c. Preheat and interpass temperature control.
d. Postweld heat treatment to reduce hardness and restore
mechanical properties.
Repairs shall be monitored by an inspector to assure compliance to repair requirements. After cooling to ambient temperatures, the repair shall be inspected by the liquid penetrant
method, according to ASME Code, Section VIII, Division 1,
Appendix 8.
For vessels constructed with P-3, P-4, or P-5 base materiais, the base metal in the area of repair should be examined
for cracking by the ultrasonic examination in accordance with
ASME Code, Section V, Article 5, paragraph T-543. This
inspection is most appropriately accomplished following a
delay of at least 24 hours after completed repairs for equipment in hydrogen service and for chromium-molybdenum
alloys that could be affected by delayed cracking.
7.2.7
O0
I
Design
Butt joints shall have complete penetration and fusion.
Parts should be replaced when repairing them is likely to be
inadequate. Part replacements shall be fabricated according to
the applicable requirements of the appropriate code. New
connections may be installed on vessels as long as the design,
location, and method of attachment comply with the applicable requirements of the appropriate code.
Fillet-welded patches require special design considerations, especially relating to efficiency. Fiìiet-welded patches
may be used to make temporary repairs, and the use of filletwelded patches may be subject to the patches’ acceptance in
the jurisdiction in which they are required. Temporary repairs
using filiet-welded patches shall be approved by the authorized pressure vessel inspector and a pressure vessel engineer
competent in pressure vessel design; and the-temporary
repairs should be removed and replaced with suitable permanent repairs at the next available maintenance opportunity.
Temporary repairs may remain in place for a longer period of
time only if evaluated, approved, and documented by the
pressure vessel engineer and the authorized API pressure vessel inspector. Fillet-welded patches may be applied to the
internal or external surfaces of shells, heads, and headers
as long as, in the judgment of the authorized pressure vessei inspector, either of the following is true:
a. The fillet-welded patches provide design safety equivalent
to reinforced openings designed according to the applicable
section of the ASME Code.
b. The fillet-welded patches are designed to absorb the membrane strain of the parts so that in accordance with the rules of
the applicable section of the ASME Code, the following
result:
1. The allowable membrane stress is not exceeded in the
vessel parts or the patches.
2. The strain in the patches does not result in fillet-weld
stresses that exceed allowable stresses for such welds.
COPYRIGHT American Petroleum Institute
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Overlay patches shall have rounded comers. Flush (insert)
patches shall also have rounded comers, and they shall be
installed with full-penetration butt joints.
Refer to API Publication 2201 when making on-stream
repairs.
A full encirclement lap band repair may be considered a
long term repair if the design is approved , and documented
by the pressure vessel engineer and the authorized API pressure vessel inspector and the following requirements are met:
a. The repair is not being made to a crack in the vessel shell.
b. The band alone is designed to contain the full design pressure.
c. All longitudinal seams in the repair band are full penetration butt welds with the design joint efficiency and inspection
consistent with the appropriate code.
d. The circumferential fillet welds attaching the band to the
vessel shell are designed to transfer the full longitudinal load
in the vessel shell, using a joint efficiency of 0.45, without
counting on the integrity of the original shell material covered
by the band. Where significant, the eccentricity effects of the
band relative to the original shell shall be considered in sizing
the band attachment welds. Other than visual examination,
fillet weid examination may be done at the next shutdown if
conditions and necessary access do not permit complete
examination at the time of an onstream repair.
e. Fatigue of the attachment welds, such as fatigue resulting
from differential expansion of the band relative to the vessel
shell, should be considered if applicable.
f. The band material and weld metal are suitable for contact
with the contained fluid at the design conditions and an
appropriate corrosion allowance is provided in the band.
g. The degradation mechanism leading to the need for repair
shall be considered in determining the need for any additional
monitoring and future inspection of the repair.
Non-penetrating nozzles (including pipe caps attached as
nozzles) may be used as long term repairs for other than
cracks when the design and method of attachment comply
with the applicable requirements of the appropriate code. The
design and reinforcement of such nozzles shall consider the
loss of the original shell material enclosed by the nozzle. The
nozzle material shall be suitable for contact with the contained fluid at the design conditions and an appropriate corrosion allowance shall be provided. The degradation
mechanism leading to the need for repair shall be considered
in determining the need for any additional monitoring and
future inspection of the repair.
For the purposes of future inspection, it may be necessary
to consider repair bands and non-penetrating nozzles to be
separate zones when addressing the on-stream inspection
requirements in 6.4.
O0
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PRESSURE
VESSELINSPECTION
CODE:MAINTENANCEINSPECTION,
7.2.8 Material
The material used in making repairs or alterations shall
conform to the applicable section of the ASME Code. The
material shall be of known weldable quality and be compatible with the original material. Carbon or alloy steel with a
carbon content over 0.35 percent shall not be welded.
7.2.9 Inspection
Acceptance criteria for a welded repair or alteration should
include nondestructive examination techniques that are in
accordance with the applicable sections of the ASME Code or
another applicable vessel rating code. Where use of these
nondestnictive examination techniques is not possible or
practical, alternative nondestructive examination methods
may be used.
7.2.10 Testing
After repairs are completed, a pressure test shall be applied
if the authorized pressure vessel inspector believes that one is
necessary. A pressure test is normally required after an alteration. Subject to the approval of the jurisdiction (where the
jurisdiction's approval is required), appropriate nondestructive examinations shall be required where a pressure test is
not performed. Substituting nondestructive examination procedures for a pressure test after an alteration may be done
only after a pressure vessel engineer experienced in pressure
vessel design and the authorized pressure vessel inspector
have been consulted.
7.2.11 Filler Metal
The filler metal used for weld repairs should have minimum specified tensile strength equal to or greater than the
minimum specified tensile strength of the base metal. If a
filler metal is used that has a minimum specified tensile
strength lower than the minimum specified tensile strength of
the base metal, the compatibility of the filler metal chemistry
with the base metal chemistry shall be considered regarding
weldability and service degradation. In addition, the following shall be met:
a. The repair thickness shall not be more than 50 percent of the
required base metal thickness, excluding corrosion allowance.
b. The thickness of the repair weld shall be increased by a
ratio of minimum specified tensile strength of the base metal
and minimum specified tensile of the filler metal used for
the repair.
COPYRIGHT American Petroleum Institute
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RATING,REPAIR,AND ALTERATION
7-5
c. The increased thickness of the repair shall have rounded
comers and shall be blended into the base metal using a 3-to1 taper.
d. The repair shall be made with a minimum of two passes.
7.3 RERATING
Rerating a pressure vessel by changing its temperature ratings or its maximum allowable working pressure may be done
only after ail of the following requirements have been met:
a. Calculations from either the manufacturer or an owner-user
pressure vessel engineer (or his designated representative)
experienced in pressure vessel design, fabrication, or inspection shall justify rerating.
b. A rerating shall be established in accordance with the
requirements of the construction code to which the pressure
vessel was built or by computations that are determined using
the appropriate formulas in the latest edition of the ASME
Code if all of the essential details comply with the applicable
requirements of the code being used. If the vessel was
designed to an edition or addendum of the ASME Code earlier than the 1999 Addenda and was not designed to Code
Case 2290 or 2278, it may be rerated to the latest edition/
addendum of the ASME Code if permitted by Figure 7- 1.
c. Current inspection records verify that the pressure vessel
is satisfactory for the proposed service conditions and that the
corrosion allowance provided is appropriate. An increase in
allowable working pressure or temperature shall be based on
thickness data obtained from a recent intemal or on-stream
inspection.
d. If the pressure vessel has at some time been pressure
tested to a test pressure equal to or higher than the pressure
test pressure required by the latest edition or addendum of the
ASME Code, or the vessel integrity is maintained by special
nondestructive evaluation inspection techniques in lieu of
testing, a pressure test for the rerated condition is not
required.
e. The pressure vessel inspection and rerating is acceptable
to the authorized pressure vessel inspector.
The pressure vessel rerating will be considered complete
when the authorized pressure vessel inspector oversees the
attachment of an additional nameplate or additional stamping
that carries the following information:
Rerated by
Maximum Allowable Working Pressure
Date
psi at-F"
O0
O0
I
O0
API 510
7-6
Obtain original
vessel data.
t
Votes:
4
I . ASME Code identified as ASME Section VIII,
Div. 1.
Yes
2. Vessel material(s) are defined as material
essential to the structural integrity of the
vessel.
Are vessel
vessel material
3. Material degradation due to operation is
defined as loss of material strength,
ductility, or toughness due to creep,
graphitization, temper embrittlement,
hydrogen attack, fatigue, etc., see API
RP 579.
current specification?
stress at rerate
vessel material
UG10 ofASME
latest editionladdendum of
the ASME Code allowable
Code higher than
code?
1".
A
I
l
1Yes
I
T
1
Review
operational history.
component using the latest
for the rerated
Figure 7-I-Rerating Vessels Using the Latest Edition or Addendum of the ASME Code Allowable Stresses
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
O0
12/00
COPYRIGHT American Petroleum Institute
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Additional copies available from API Publications and Distribution:
(202) 682-8375
Information about API Publications, Programs and Services is
available on the World Wide Web at: http://www.api.org
American
PetrOkUm
Institute
1220 L Street, Northwest
Washington, D.C. 20005-4070
202-682-8000
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Order No. C51OA2
American
Petroleum
Institute
1220 L Street, Northwest
Washington, D.C. 20005-4070
202-682-8000
Date: January 26, 1999
To:
Purchasers of API 5 10, Pressure Vessel Inspection Code: Maintenance Inspection,
Rating, Repail; and Alteration, Eighth Edition
Re: Addendum 1 Errata
This errata contains a correction to Section 6.4, Internal and On-Stream Inspection, on page 6-2.
The new text added in the seventh paragraph in this section currently reads:
If the requirements of item b above are not met, as a result of conditions
noted during the scheduled on-stream inspection, the next scheduled
inspection shall be an internal inspection. When a vessel has been internally inspected, the results of this inspection can be used to determine
whether an on-stream inspection can be substituted for an internal inspection on a similar vessel operating in the same service and conditions.
The correct text should read as follows:
If the requirements of item b above are not met, as a result of conditions
noted during the scheduled on-stream inspection, the next scheduled
inspection shall be an internal inspection. When a vessel has been internally inspected, the results of a current inspection can be used to determine
whether an on-stream inspection can be substituted for an internal inspection on a similar vessel operating in the same service and conditions.
Please replace pages 6-1 and 6-2 with the attached corrected pages.
.
COPYRIGHT American Petroleum Institute
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6 Inspection and Testing of Pressure
Vessels and Pressure-Relieving
Devices
6.1 GENERAL
98
I
Pressure vessels shall be inspected at the time of installation. Internal field inspections of new vessels are not required
as long as a manufacturer’s data report assuring that the vessels are satisfactory for their intended service is available. To
ensure vessel integrity, all pressure vessels shall be inspected
at the frequencies provided in this section.
In selecting the technique(s) to be used for the inspection of
a pressure vessel, both the condition of the vessel and the environment in which it operates should be taken into consideration. The inspection, as deemed necessary by the authorized
pressure vessel inspector, may include many of a number of
nondestructive techniques, including visual inspection. Internal inspection is preferred because process side degradation
(corrosion, erosion, and environmental cracking) can be nonuniform throughout the vessel and, therefore, difficult to locate
by external NDE. On-stream inspection may be acceptable in
lieu of internal inspection for vessels under the specificcircumstances defined in 6.4. In situations where on-stream inspection
is acceptable, such inspection may be conducted either while
the vessel is out of service and depressurized or on stream and
under pressure. Except in response to an apparent need, such as
when environmental cracking (see Guide for Inspection of
Rejìnery Equipment, Chapter II) is suspected, inspection techniques exceeding the examination requirements used in the
design and fabrication of the vessel are not required.
The appropriate inspection must provide the information
necessary to determine that all of the essential sections or components of the vessel are safe to operate until the next scheduled
inspection. The risks associated with operational shutdown and
start-up and the possibility of increased corrosion due to exposure of vessel surfaces to air and moisture should be evaluated
when an intemal inspection is being planned.
6.2
RISK-BASED INSPECTION
Identifying and evaluating potential degradation mecha-
nisms are important steps in an assessment of the likelihood
98
of a pressure vessel failure. However, adjustments to inspection strategy and tactics to account for consequences of a
failure should also be considered. Combining the assessment
of likelihood of failure and the consequence of failure are
essential elements of risk-based inspection (RBI).
When an owneduser chooses to conduct a RBI assessment,
it must include a systematic evaluation of both the likelihood of
failure and the associated consequence of failure. The likelihood assessment must be based on all forms of degradation
that could reasonably be expected to affect a vessel in any particular service. Examples of those degradation mechanisms
include: internal or external metal loss from an identified form
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
of corrosion (localized or general), all forms of cracking,
including hydrogen assisted and stress corrosion cracking
(from the inside or outside surfaces of a vessel), and any other
forms of metallurgical, corrosion, or mechanical degradation,
such as fatigue, embrittlement, creep, etc. Additionally, the
effectiveness of the inspection practices, tools, and techniques
utilized for finding the expected and potential degradation
mechanisms must be evaluated. This likelihood of failure
assessment should be repeated each time equipment or process
changes are made that could significantly af€ect degradation
rates or cause premature failure of the vessel.
Other factors that should be considered in a RBI assessment include: appropriateness of the materials of construction; vessel design conditions, relative to operating
conditions; appropriateness of the design codes and standards utilized; effectiveness of corrosion monitoring progr,ams; and the quality of maintenance and inspection
quality assurance/quality control programs. Equipment failure data and information will also be important information
for this assessment. The consequence assessment must consider the potential incidents that may occur as a result of
fluid release, including explosion, fire, toxic exposure, environmental impact, and other health effects associated with a
failure of a vessel.
It is essential that all RBI assessments be thoroughly documented, clearly defining all the factors contributing to both the
likelihood and consequence of a failure of the vessel.
After an effective RBI assessment is conducted, the
results can be used to establish a vessel inspection strategy
and more specifically better define the following:
a. The most appropriate inspection methods, scope, tools and
techniques to be utilized based on the expected forms of degradation.
b. The appropriate frequency for internal, external, and onstream inspections.
c. The need for pressure testing after damage has been
incurred or after repairs or modifications have been completed.
d. The prevention and mitigation steps to reduce the likelihood and consequence of a vessel failure.
An RBI assessment may be used to increase or decrease
the 10-year inspection limit described in Section 6.4. When
used to increase the IO-year limit, RBI assessment shall be
reviewed and approved by a pressure vessel engineer and
authorized pressure vessel inspector at intervals not to exceed
10 years, or more often if warranted by process, equipment,
or consequence changes.
6.3 EXTERNAL INSPECTION
Each vessel aboveground shall be given a visual external
inspection, preferably while in operation, at least every 5 years
or at the same interval as the required internal or on-stream
inspection, whichever is less. The inspection shall, at the least,
determine the condition of the exterior insulation, the condition of the supports, the allowance for expansion, and the general alignment of the vessel on its supports. Any signs of
leakage should be investigated so that the sources can be
established. Inspection for corrosion under insulation (CUI)
shall be considered for externally-insulated vessels subject to
moisture ingress and that operate between 25°F ( 4 ° C ) and
250'F (12OoC), or are in intermittent service. This inspection
may require removal of some insulation. It is not normally
necessary to remove insulation if the entire vessel shell is
always operated at a temperature sufficiently low [below 25°F
(4"C)l or sufficiently high [above 250°F (12O"C)]to prevent
the presence or condensation of moisture under the insulation.
Alternatively, shell thickness measurements done internally at
typical problem areas (for example, stiffening rings, around
nozzles, and other locations which tend to trap moisture or
allow moisture ingress) may be performed during
internal inspections.
Buried vessels shall be inspected to determine their external environmental condition. The inspection interval shall be
based on corrosion-rate information obtained from one or
more of the following methods: (a) during maintenance activity on adjacent connecting piping of similar material; (b)
from the interval examination (specified in the paragraph
above) of similarly buried corrosion test coupons of similar
material; (c) from representative portions of the actual vessel;
or (d) from a vessel in similar circumstances.
Vessels that are known to have a remaining life of over 10
years or that are protected against external corrosion-for
example, (a) vessels insulated effectively to preclude the
entrance of moisture, (b)jacketed cryogenic vessels, (c) vessels installed in a cold box in which the atmosphere is purged
with an inert gas, and (d) vessels in which the temperature
being maintained is sufficiently low or sufficiently high to
preclude the presence of water-do not need to have insulation removed for the external inspection. However, the condition of their insulating system or thejr outer jacketing, such as
the cold box shell, shall be observed at least every 5 years and
repaired if necessq.
6.4
INTERNAL AND ON-STREAM INSPECTION
The period between internal or on-stream inspections shall
not exceed one half the estimated remaining life of the vessel
based on corrosion rate or 10 years, whichever is less. In
cases where the remaining safe operating life is estimated to
be less than 4 years, the inspection interval may be the full
remaining safe operating life up to a maximum of 2 years.
For pressure vessels that are in noncontinuous service and
are isolated from the process fluids such that they are not
exposed to corrosive environments (such as inert gas purged
or filled with noncorrosive hydrocarbons), the 10 years shall
be the 10 years of actual service exposed life. Equipment
that is not adequately protected from corrosive environ-
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
ments may experience significant internal corrosion while
idle and should be carefully reviewed when setting inspection intervals. In no case should these exceed one-half the
estimated remaining corrosion-rate life, or 10 years since
the last inspection. External inspections for vessels in noncontinuous service remain the same as for continuous service, as outlined in 6.3.
Except as noted below, internai inspection is normally the
preferred method of inspection and shall be conducted on
vessels subject to significant localized corrosion and other
types of damage. At the discretion of the authorized pressure
vessel inspector, on-stream inspection may be substituted for
intemal inspection in the following situations:
a. When size, configuration, or lack of access makes vessel
entry for internal inspection physically impossible.
b. When the general corrosion rate of a vessel is known to be
less than 0.005 inch (0.125 millimeter) per year and the estimated remaining life is greater than 10 years, and all of the
following conditions are met:
1. The corrosive character of the contents, including the
effect of trace components, has been established by at
least 5 years of the same or comparable service experience
with the type of contents being handled.
2. No questionable condition is disclosed by the external
inspection specified in 6.3.
3. The operating temperature of the steel vessel shell
does not exceed the lower temperature limits for the
creep-rupture range of the vessel material.
4. The vessel is not considered to be subject to environmental cracking or hydrogen damage from the fluid being
handled.
5. The vessel is not strip-lined or plate-lined.
If the requirements of item b above are not met, as a result of
conditions noted during the scheduled on-stream inspection, the
next scheduled inspection shall be an internal inspection. When
a vessel has been internally inspected, the results of a current
inspection can be used to determine whether an on-stream
inspection can be substituted for an internal inspection on a
similar vessel operating in the same service and conditions.
When an on-stream inspection is conducted in lieu of an
internal inspection, a thorough examination shall be performed using ultrasonic thickness measurements, or radiography, or other appropriate means of NDE to measure metal
thicknesses and/or assess the integrity of the metal and welds.
If an on-stream inspection is conducted, the authorized pressure vessel inspector shall be given sufficient access to all
parts of the vessel (heads, shell, and nozzles) so that the
inspector is satisfied that an accurate assessment of the vessel
condition can be made.
A representative number of thickness measurements must be
conducted on each vessel to satisfy the requirements for an
internai or on-stream inspection. For example, the thickness for
all major components (shells, heads, cone sections) and a r e p
I
98
I 98
98
American
Petroleum
Institute
1220 L Street, Northwest
Washington, D.C. 20005-4070
202-682-8000
Date: December 1998
To: Purchasers of API 510, Pressure Vessel Inspection Code: Maintenance Inspection,
Rating, Repair; and Alteration, Eighth Edition
Re: Addendum 1
This package contains Addendum 1 of API 5 10, Pressure Vessel Inspection Code: Maintenance
Inspection, Rating, Repair; and Alteration, Eighth Edition. This package consists of the pages that have
changed since the June 1997 printing of API 510.
To update your copy of API 510, replace the following pages as indicated:
Part of Book Changed
Old Parres to be Replaced
front covers
New Pages
front cover and
inside front cover
back cover
back cover and
inside back cover
Title Page
title page and Special Notes page
title page and Special Notes page
Foreword
iii-vi
iii-v (+ blank)
Table of Contents
vii-viii
vii-viii
Section 2
2- 1
2-1 (+blank)
Section 3
3-1-3-2
3-1-3-2
Section 4
4- 1
4-1 (+blank)
Section 5
5-1-5-4
5-1-5-4
Section 6
6- 1-6-4
6-1-6-5 (+blank)
Section 8
8-3
8-3 (+blank)
Appendix B
B- 1
B-1 (+blank)
Cover
The parts of the text, tables, and figures that contain changes are indicated by a vertical bar and a
small “98” in the margin.
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~
STD.API/PETRO A P I 510-ENGL 1 7 7 7 M 0 7 3 2 2 9 0 Ob13732 ô 3 0 M
Pressure Vessel Inspection Code:
Maintenance Inspection, Rating,
Repair, and Alteration
API 510
EIGHTH EDITION, JUNE 1997
ADDENDUM 1, DECEMBER 1998
American
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S T D * A P I / P E T R O A P I 510-ENGL
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#b-
Strategiesfir Today's
Environmental Purtnmhip
API ENVIRONMENTAL, HEALTH AND SAFETY MISSION
AND GUIDING PRINCIPLES
The members of the American Petroleum Institute are dedicated to continuous efforts to
improve the compatibility of our operations with the environment while economically
developing energy resources and supplying high quality products and services to consumers. We recognize our responsibility to work with the public, the government, and others to
develop and to use natural resources in an environmentally sound manner while protecting
the health and safety of our employees and the public. To meet these responsibilities, AEI'
members pledge to manage our businesses according to the following principles using
sound science to prioritize risks and to implement cost-effective management practices:
o
To recognize and to respond to community concerns about our raw materials, products and operations.
o To operate our plants and facilities, and to handle our raw materials and products in a
manner that protects the environment, and the safety and health of our employees
and the public.
o
To make safety, health and environmental considerations a priority in our planning,
and our development of new products and processes.
o To advise promptly, appropriate officiais, employees, customers and the public of
information on significant industry-related safety, health and environmental hazards,
and to recommend protective measures.
o To counsel customers, transporters and others in the safe use, transportation and dis-
posal of our raw materials, products and waste materials.
o To economically develop and produce natural resources and to conserve those
resources by using energy efficiently.
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To extend knowledge by conducting or supporting research on the safety, health and
environmental effects of our raw materials, products, processes and'waste materials.
To commit to reduce overall emissions and waste generation.
To work with others to resolve problems created by handling and disposal of hazardous substances from our operations.
o To participate with government and others in creating responsible laws, regulations
and standards to safeguard the community, workplace and environment.
o
To promote these principies and practices by sharing experiences and offering assistance to others who produce, handle, use, transport or dispose of similar raw materials, petroleum products and wastes.
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S T D - A P I / P E T R O A P I 510-ENGL I997
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0732290 Ob13934 b o 3 E
Pressure Vessel Inspection Code:
Maintenance Inspection, Rating,
Repair, and Alteration
Manufacturing, Distribution and Marketing Department
API 510
EIGHTH EDITION, JUNE 1997
ADDENDUM 1, DECEMBER 1998
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SPECIAL NOTES
API publications necessarily address problems of a general nature. With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed.
API is not undertaking to meet the duties of employers, manufacturers, or suppliers to
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and safety risks and precautions, nor undertaking their obligations under local, state, or
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supplier of that material, or the material safety data sheet.
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implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent. Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent.
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Copyright Q 1997 American Peuoleum institute
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FOREWORD
98
This edition of API 510 supersedes all previous editions of API 510, Pressure Vessel
Inspection Code: Maintenance Inspection, Rating, and Repair of Pressure Vessels.Each edition, revision, or addenda to this API standard may be used beginning with the date of issuance shown on the cover page for that edition, revision, or addenda. Each edition, revision,
or addenda to this API standard becomes effective 6 months after the date of issuance for
equipment that is rerated, reconstructed, relocated, repaired, modified (altered), inspected,
and tested per this síandard. During the &month time between the date of issuance of the
edition, revision, or addenda and the effective date, the user shall specify to which edition,
revision, or addenda, and the equipment is to be rerated, reconstructed, relocated, repaired,
modified (altered), inspected and tested.
iii
COPYRIGHT American Petroleum Institute
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Suggested revisions are invited and should be submitted to the director of the Manufacturing, Distribution and Marketing Department, American Petroleum Institute, 1220 L Street,
N.W., Washington, D.C. 20005-4070.
iv
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
IMPORTANT INFORMATION CONCERNING USE OF ASBESTOS
OR ALTERNATIVE MATERIALS
Asbestos is specified or referenced for certain components of the equipment described in
some API standards. It has been of extreme usefulness in minimizing fire hazards associated
with petroleum processing. It has also been a universal sealing material, compatible with
most refining fluid services.
Certain serious adverse health effects are associated with asbestos, among them the serious and often fatal diseases of lung cancer, asbestosis, and mesothelioma (a cancer of the
chest and abdominal linings). The degree of exposure to asbestos varies with the product and
the work practices involved.
Consult the most recent edition of the Occupational Safety and Health Administration
(OSHA), U.S. Department of Labor, Occupational Safety and Health Standard for Asbestos,
Tremolite, Anthophyllite, and Actinolite, 29 Code of Federal Regulations Section
1910.1001; the U.S. Environmental Protection Agency, National Emission Standard for
Asbestos, 40 Code of Federal Regulations Sections 61.140 through 61.156; and the US.
Environmental Protection Agency @PA) rule on labeling requirements and phased banning
of asbestos products, published at 54 Federal Register 29460 (July 12, 1989).
There are currently in use and under development a number of substitute materials to
replace asbestos in certain applications. Manufacturers and users are encouraged to develop
and use effective substitute materials that can meet the specifications for, and operating
requirements of, the equipment to which they would apply.
SAFETY AND HEALTH INFORMATION WITH RESPECT TO PARTICULAR
PRODUCTS OR MATERIALS CAN BE OBTAINED FROM THE EMPLOYER, THE
MANUFACTURER OR SUPPLIER OF THAT PRODUCT OR MATERIAL, OR THE
MATERIAL SAFETY DATA SHEET.
V
COPYRIGHT American Petroleum Institute
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CONTENTS
Page
98
I
1 SCOPE............................................................................................................................
1.1 General Application ....................................................................................................
1.2 Specific Applications ...................................................................................................
1-1
1.1
1-1
2 REFERENCES...............................................................................................................
2-1
DEFINITIONS ...............................................................................................................
3-1
4 OWNER-USER INSPECTION ORGANIZATION.....................................................
4.1 General ........................................................................................................................
4.2 API Authorized Pressure Vessel Inspector Qualification and Certification ...............
4.3 Owner-User Organization Responsibilities ................................................................
4.4 API Authorized Pressure Vessel Inspector Duty ........................................................
4-1
4-1
4-1
5 INSPECTION PRACTICES ..........................................................................................
5-1
3
98
98
98
I
98
I
98
1
5.1 Preparatory Work ........................................................................................................
5.2 Modes of Deterioration and Failure ............................................................................
5.3 Corrosion-Rate Determination ....................................................................................
5.4 Maximum Allowable Working Pressure Determination ............................................
5.5 Defect Inspection .........................................................................................................
5.6 Inspection of Parts.......................................................................................................
5.7 Corrosion and Minimum Thickness Evaluation .........................................................
6 INSPECTION AND TESTING OF PRESSURE VESSELS AND
PRESSURE-RELIEVING DEVICES...........................................................................
6.1 General ........................................................................................................................
6.2 Risk-Based Inspection .................................................................................................
6.3 External Inspection ......................................................................................................
6.4 Intenial and On-Stream Inspection .............................................................................
6.5 Pressure Test ................................................................................................................
6.6 Pressure-Relieving Devices ........................................................................................
6.7 Records ........................................................................................................................
98
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4-1
5-1
5-1
5-1
5-1
5-2
5-2
5-3
6-1
6-1
6-1
6-1
6-1
6-3
6-3
6-4
7 REPAIRS. ALEMTIONS. AND RERA'TING OF PRESSURE VESSELS .............7-1
7.1 General ........................................................................................................................ 7-1
7.2 Welding........................................................................................................................ 7-1
7.3 Rerating .......................................................................................................................
98
I
8 ALTERNATIVE RULES FOR EXPLORATION AND PRODUCTION
PRESSURE VESSELS ..................................................................................................
8.1 Scope and Specific Exemptions ..................................................................................
8.2 Glossary of Terms .......................................................................................................
8.3 Inspection Program .....................................................................................................
8.4 Pressure Test ...............................................................................................................
8.5 Safety Relief Devices ..................................................................................................
8.6 Records ........................................................................................................................
APPENDIX A-ASME
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
CODE EXEMPTIONS...............................................................
7-3
8-1
8-1
8-1
8-1
8-3
8-3
8-3
A- 1
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CI732270 Rb137i.Ia
page
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APPENDIX B-AUTHORIZED PRESSUREVESSEL INSPECTOR
CERTIFICATON ....................................................................................
APPENDIX C-SAMPLE PRESSURE VESSEL INSPECTION RECORD
B-1
................. C-1
APPEmIX D-SAMPLE REPATR, ALTERATION, OR =TING
OF
PRESSURE VESSEL FORM .................................................................
D-1
APPFNIM EGTECHNICAL, INQUIRES .....................................................................
E- 1
Table
1-Values of Spherical Radius Factor Ki ........................................................................
5-4
viii
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
PRESSURE
VESSELINSPECTION
CODE:MAINTENANCE
INSPECTION,
RATING,REPAIR,AND ALTERATION
2 References
The most recent editions of the following standards, codes,
and specifications are cited in this inspectioncode.
API
RP 572 Inspection of Fressure Vessels
98
I
Rp 574
RP 576
98
I
Inspection of Piping System Components
Inspection of Pressure-Relieving Devices
API 51O Inspector CertijîcationExamination
Body of Knowledge
2-i
Guide for Inspection of RejìneT Equipment, Chapter II,
?ConditionsCausing Deteriorationor Failures?
Note: This publication is out of print. To obtain a copy please inform the person taking your order that you require this publication for the API 510
Inspector Certification Exam.
ASME?
Boiler and Pressure Vessel Code, Section V, Section VI,
Section W, Section VIU, SectionE,and SectionXI
National Board2
National Board Inspection Code
?ASME International, Three Park Avenue, New York, NY 10016-5990.
2National Board of Boiler and Pressure Vessel Inspectors, 1055 Cruppe~
Avenue, Columbus, Ohio 43229.
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
_
_
_
STD.API/PETRO
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A P I 510-ENGL
1997 I O 7 3 2 2 9 0 ObL39q2 7 8 T
PRESSURE
VESSELINSPECTION
CODE:MAINTENANCE
INSPECTION,
RATING,
REPAIR,AND ALTERATION
3 Definitions
For the purposes of this standard, the following definitions
apply-
3.1 alteration: A physical change in any component or a
rerating that has design implications that affect the pressure-containing capability of a pressure vessel beyond the
scope of the items described in existing data reports. The
following should not be considered alterations: any comparable or duplicate replacement, the addition of any reinforced nozzle less than or equal to the size of existing
reinforced nozzles, and the addition of nozzles not requiring
reinforcement.
3.2 ASME Code: Abbreviation and shortened title for the
ASME Boiler and Pressure Vessel Code. This abbreviated
title includes the addenda and code cases of the ASME Boiler
and Pressure Vessel Code.
The ASME Code is written for new construction; however, most of the technical requirements for design, welding, examination, and materials can be applied in the
maintenance inspection, rating, repair, and alteration of
operating pressure vessels. When the ASME Code cannot be
followed because of its new construction orientation (new or
revised material specifications, inspection requirements,
certain heat treatments and pressure tests, and stamping and
inspection requirements), the engineer or inspector shall
conform to this inspection code rather than to the ASME
Code. If an item is covered by requirements in the ASME
Code and this inspection code or if there is a conflict
between the two codes, for vessels that have been placed in
service, the requirements of this inspection code shall take
precedence over the ASME Code. As an example of the
intent of this inspection code, the phrase “applicable
requirements of the ASME Code” has been used in this
inspection code instead of the phrase “in accordance with
the ASME Code.”
3.3 authorized pressure vessel inspector: An
employee of an authorized inspection agency who is qualified and certified to perform inspections under this inspection code.
3.4 authorized inspection agency: Any one of the following:
a. The inspection organization of the jurisdiction in which
the pressure vessel is used.
b. The inspection organization of an insurance company that
is licensed or registered to write and actually does write pressure vessel insurance.
c. The inspection organization of an owner or user of pressure vessels who maintains an inspection organization for his
equipment only and not for vessels intended for sale or resale.
d. An independent organization or individual that is under
contract to and under the direction of an owner-user and that
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3-1
is recognized or otherwise not prohibited by the jurisdiction
in which the pressure vessel is used. The owner-user’s inspection program shall provide the controls that are necessary
when contract inspectors are used.
3.5 construction code: The code or standard to which a
vessel was originally built, such as APVASME, MI, or State
Specidnon-ASME.
3.6 inspection code: Shortened title for API 510 used in
this publication.
3.7 inspector: Refers to an authorized pressure vessel
inspector in this document.
3.8 jurisdiction: A legally constituted government administration that may adopt rules relating to pressure vessels.
3.9 maximum allowable working pressure: The
maximum gauge pressure permitted at the top of a pressure
vessel in its operating position for a designated temperature. This pressure is based on calculations using the minimum (or average pitted) thickness for all critical vessel
elements, exclusive of thickness designated for corrosion
and loadings other than pressure.
3.10 minimum allowable shell thickness: The thickness required for each element of a vessel. The minimum
allowable shell thickness is based on calculations that consider temperature, pressure, and all loadings.
3.11 on-stream inspection: The inspection used to
establish the suitability of a pressure vessel for continued
operation. Nondestructive examination (NDE) procedures are
used to establish the suitability of the vessel, and the vessel
may or may not be in operation while the inspection is being
carried out. Because a vessel may be in operation while an
on-siream inspection is being carried out, an on-stream
inspection means essentially that the vessel is not entered for
internal inspection.
3.12 pressure vessel: A container designed to withstand
internal or external pressure. “his pressure m y be imposed
by an external source, by the application of heat from a direct
or indirect source, or by any combination thereof. This definition includes unfired steam generators and other vapor generating vessels which use heat from the operation of a
processing system or other indirect heat source. (Specific limits and exemptions of equipment covered by this inspection
code are given in Section 1 and Appendix A.)
3.13 pressure vessel engineer: Shall be one or more
persons or organizations acceptable to the owner-user who
are knowledgeable and experienced in the engineering disciplines associated with evaluating mechanical and material
characteristics which affect the integrity and reliability of
pressure vessels. The pressure vessel engineer, by consult-
I
API 510
3-2
ing with appropriate specialists, should be regarded as a
composite of all entities needed to properly assess the technicai requirements.
3.14 quality
Al1 Planned sYskmatic~
and
preventative actions required to determine if materials, equipment, or services will meet specified requirements so that
equipment will perform satisfactorily in service. The contents
of a quality
assirance inspection minual are outlined in 4.3.
-~
3.15 repair: The work necessary to restore a vessel to a
condition suitable for safe operation at the design conditions.
If any repair changes the design temperature or pressure, the
requirements for rerating shall be satisfied. A repair can be
the addition or replacement of pressure or nonpressure parts
that do not change the rating of the vessel.
3.16
repair organization: Any one of the foliowing:
a. The holder of a valid ASME Certificate of Authorization
that authorizes the use of an appropriate ASME Code symbol stamp.
b. An owner or user of pressure vessels who repairs his or her
own equipment in accordance with this inspection code.
c. A contractor whose qualifications are acceptable to the
pressure-vessel owner or user and who makes repairs in
accordance with this inspection code.
d. An individual or organization that is authorized by the
legal jurisdiction.
3.17 reratha: A change in either the temDerature ratings
ing temperature and pressure of a vessel may be increased
or decreased because of a rerating, and sometimes a rerat-
COPYRIGHT American Petroleum Institute
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ing requires a combination of changes. Derating below
original design conditions is a permissible way to provide
for corrosion. When a rerating is conducted in which the
maximum allowable working pressure or temperature is
increased or the
temperature is decreased so that
additional mechanical tests are required, it shall be consid-
eredmalteration.
3.18 examiner: A person who assists the API authorized
pressure vessel inspector by performing specific NDE on
pressure vessels but does not evaluate the results of those
examinations in accordance with MI 5 10, unless specifically
trained and authorized to do so by the owner or user. The
examiner need not be certified in accordance with API 510 or
be an employee of the owner or user but shall be trained and
competent in the applicable procedures in which the examiner is involved. In some cases, the examiner may be required
to hold other certifications as necessary to satisfy the owner or
user requirements. Examples of other certification that may
be required are American Society for Nondestructive Testing3
SNT-TC-lA, or (3'189, or American Welding Society" Welding Inspector Certification. The examiner's employer shall
maintain certification records of the examiners employed,
including dates and results of personnel qualifications and
shall make them available to the MI authorized pressure vessel inspector.
3AmericanSocietv for Nondestructive Testing. hc.. 1711 Arlin~ateh e .
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0 7 3 2 2 9 0 ObL39LiLi 5 5 2
PRESSURE VESSEL INSPECTIONCODE: MAINTENANCE
INSPECTION. RATING,REPAIR,AND ALTERATION
4 Owner-User Inspection Organization
4.1
GENERAL
An owner-user of pressure equipment shall exercise control
of the pressure vessel inspection program, inspection frequencies, and maintenance. The owner-user is responsible for the
fünction of an authorized inspection agency in accordance with
the provisions of API 5 10. The owner-user inspection organization shaü conúol activities relating to the maintenance inspection, rating, repair, and alteration of these pressure vessels.
4.2 API AUTHORIZED PRESSUREVESSEL
INSPECTOR QUALIFICATION AND
CERTIFICATION
Authoriz~dpressure vessel inspectors shall have education
and experience in accordance with Appendix B of this inspection code. Authorized pressure vessel inspectors shall be certified by the American Petroleum Institute in accordance with
the provisions of Appendix B.
4.3 OWNER-USER ORGANIZATION
RESPONSIBILITIES
An owner-user organization is responsible for developing,
documenting, implementing, executing, and assessing pressure vessel inspection systems and inspection procedures that
will meet the requirements of this inspection code. These system and procedures wiil be contained in a quality assurance
inspection manual and shall include the following:
a organizaton and reports of stmcúue for inspection personnel.
b. Documentation and maintenance of inspection and quality
assurance procedures.
c. Documentation and reports of inspection and test results.
d. Corrective action for inspection and test results.
e. Internal audits for compliance with the quality assurance
inspection manual.
f. Review and approval of drawings, design calculations, and
specifications for repairs, alterations, and reratings.
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4-1
g. Assurance that all jurisdictional requirements for pressure
vessel inspection, repairs, alterations, and rerating are continuously met.
h. Reports to the authorized pressure vessel inspector any
process changes that could affect pressure vessel integrity.
i. Training requirements for inspection personnel regarding
inspection tools, techniques, and technical knowledge base.
j. Controls necessary so that only qualified welders and procedures are used for all repairs and alterations.
k. Controls necessary so that only qualified nondestructive
examination @DE) personnel and procedures are utilized.
1. Controls necessary so that only materials conforming to
the applicable section of the ASME Code are utilized for
repairs and alterations.
m. Controls necessary so that all inspection measurement and
test equipment are properly maintained and calibrated.
n. Controls necessary so that the work of contract inspection
or repair organizations meet the same inspection requirements as the owner-user organization.
o. Internal auditing requirements for the quality control system for pressure-relieving devices.
4.4
API AUTHORIZED PRESSURE VESSEL
INSPECTOR RESPONSIBILITIES
When inspections, repairs, or alterations are being conducted on pressure vessels, an MI authorized pressure vessel inspector shall be responsible to the owner-user for
determining that the requirements of API 510 on inspection,
examination, and testing are met, and shall be directly
involved in the inspection activities. The API authorized
pressure vessel inspector may be assisted in performingvisual inspections by other properly trained and qualified
individuals, who may or may not be certified vessel inspectors. Personnel performing nondestructive examinations
shall meet the qualifications identified in 3.17 but need not
be API authorized pressure vessel inspectors. However, all
examination results must be evaluated and accepted by the
MI authorized pressure vessel inspector.
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S T D - A P I / P E T R O API 510-ENGL 1997
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0 7 3 2 2 9 0 Ob137Y5 9 9 9
PRESSURE
VESSELINSPECTION
CODE:MAINTENANCE
INSPECTION,
RATING,REPAIR.
AND ALTERATION
5 Inspection Practices
5.1 PREPARATORYWORK
Safety precautions are important in pressure vessel inspection because of the limited access to and the confined spaces
of pressure vessels. Occupational Safety and Health Administration (OSHA) regulations pertaining to confined spaces and
any other OSHA safety rules should be reviewed and followed, where applicable.
For an internal inspection, the vessel should be isolated by
blinds or other positive methods from all sources of liquids,
gases, or vapors. The vessel should be drained, purged,
cleaned, ventilated, and gas tested before it is entered. Where
required, protective equipment should be worn that will protect the eyes, lungs, and other parts of the body from specific
hazards that may exist in the vessel.
The nondestructive testing equipment used for the inspection is subject to the safety requirements customarily followed in a gaseous atmosphere. Before the inspection is
started, all persons working around the vessel should be
informed that people are going to be working inside it. People
working inside the vessel should be informed when any work
is going to be done on the exterior of it.
The tools and personnel safety equipment needed for the
vessel inspection should be checked before the inspection.
Other equipment that might be needed for the inspection,
such as planking, scaffolding, bosun's chairs, and portable
ladders, should be available if needed.
5.2
MODES OF DETERIORATION AND FAILURE
Contaminants in fluids handled in pressure vessels, such as
sulfur, chlorine, hydrogen sulfide, hydrogen, carbon, cyanides,
acids, water, or other corroding species may react with metals
and cause corrosion. Significant stress fluctuations or reversals
in parts of equipment are common, particularly at points of
high secondary stress. If stresses are high and reversals are frequent, failure of parts may occur because of fatigue. Fatigue
failures in pressure vessels may also occur because of cyclic
temperature and pressure changes. Locations where metals
with different thermal coefficients of expansion are welded
together may be susceptibleto thermal fatigue.
Deterioration or creep may occur if equipment is subjected
to temperatures above those for which it is designed. Since
metals weaken at higher temperatures, such deterioration may
cause failures, particularly at points of stress concentration.
Creep is dependent on time, temperature, stress, and material
creep strength, so the actual or estimated levels of these quantities should be used in any evaluations. At elevated temperatures, other metallurgical changes may also take place that
may permanently affect equipment.
For developing an inspection plan for equipment operating
at elevated temperatures [generally starting in the range of
750"-1000"F (400"-540°C),depending on operating condi-
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
5-1
tions and alloy], the following should be considered in assessing the remaining life:
a. Creep deformation and stress rupture.
b. Creep crack growth.
c. Effect of hydrogen on creep.
d. Interaction of creep and fatigue.
e. Possible metallurgical effects, including a reduction in
ductility.
Numerous NDE techniques can be applied to find and
characterize elevated temperature damage. These techniques
include visual, surface, and volumetric examination. Additionally, if desired or warranted, samples can be removed for
laboratory analysis.
The inspection plan should be prepared in consultation
with an engineer having knowledge of elevated temperature
and metallurgical effects on pressure vessel materials of construction.
At subfreezing temperatures, water and some chemicals
handled in pressure vessels may freeze and cause failure.
At ambient temperatures, carbon, low-alloy, and other ferritic steels may be susceptible to brittle failure. A number of
failures have been attributed to bride fracture of steels that
were exposed to temperatures below their transition temperature and to pressures greater than 20 percent of the required
hydrostatic test pressure; most brittle fractures, however, have
occurred on the first application of a particular stress level (the
first hydrotest or overload). Although the potential for a brittle
failure because of excessive operating conditions below the
transition temperature shall be evaluated, the potential for a
brittle failure because of rehydrotesting or pneumatic testing of
equipment or the addition of any other additional loadings shall
also be evaluated. Special attention should be given to lowalloy steels (especially 2% Cr-1Mo) because they may be
prone to temper embrittlement. [Temper embrittlement is a loss
of ductility and notch toughness due to postweld heat treatment
or high-temperature service (above 700°F)(370°C).1
Other forms of deterioration, such as stress corrosion
cracking, hydrogen attack, carburization, graphitization, and
erosion, may also occur under special circumstances. These
forms of deterioration are more fully discussed in Chapter II
of the API Guidefor Inspection for Rejinery Equipment.
5.3 CORROSION RATE DETERMINATION
For a new vessel or for a vessel for which service conditions are being changed, one of the following methods shall
be employed to determine the vessel's probable corrosion
rate. The remaining wall thickness at the time of the next
inspection can be estimated from this rate.
a. A corrosion rate may be calculated from data collected
by the owner or user on vessels providing the same or similar service.
STD.API/PETRO
A P I 510-ENGL 1997
=
API 510
5-2
b. if data on vessels providing the same or similar service are
not available, a corrosion rate may be estimated from the
owner’s or user’s experience or from published data on vessels providing comparable service.
c. If the probable corrosion rate cannot be determined by
either item a or item b above, on-stream determinations shall
be made after approximately loo0 hours of service by using
suitable corrosion monitoring devices or actual nondestructive thickness measurements of the vessel or system. Subsequent determinationsshall be made after appropriate intervals
until the corrosion rate is established.
if it is determined that an inaccurate corrosion rate has
been assumed, the rate to be used for the next period shaii be
increased or may be decreased to agree with the actual rate.
5.4
0732290 Ob137Vb 325
MAXIMUM ALLOWABLE WORKING
PRESSURE DETERMINATION
The maximum allowable working pressure for the continued use of a pressure vessel shall be based on computations
that are determined using the latest edition of the ASME
Code or the construction code to which the vessel was built.
The resulting maximum allowable working pressure from
these computations shall not be greater than the original maximum allowable working pressure unless a rerating is performed in accordance with 7.3.
Computations may be made only if the foliowing essential
details comply with the applicable requirements of the code
being used: head, shell, and nozzle reinforcement designs;
material specifications; allowable stresses; weld efficiencies;
inspection acceptance criteria; and cyclical service requirements. In corrosive service, the wall thickness used in these
computations shall be the actual thickness as determined by
inspection (see 5.7) but shall not be greater than the thickness
reported in the material test report or the manufacturer’s data
report, where available, minus twice the estimated corrosion
loss before the date of the next inspection, except as modified
in 6.4. Allowance shall be made for the other loadings in
accordance with the applicable provisions of the ASME Code.
5.5 DEFECT INSPECTION
Vessels shall be examined for visual indications of distortion. If any distortion of a vessel is suspected or observed, the
overall dimensions of the vessel shall be checked to confirm
whether or not the vessel is distorted and, if it is distorted, to
determine the extent and seriousness of the distortion. The
parts of the vessel that should be inspected most carefully
depend on the type of vessel and its operating conditions. The
authorized pressure vessel inspector should be familiar with
the operating
- conditions of the vessel and with the causes and
characteristics of potential defects and deterioration. (For
recommended inspection practices for pressure vessels, see
API Recommended Practice 572.)
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
Careful visual examination is the most important and the
most universally accepted method of inspection. Other methods that may be used to supplement visual inspection include
(a) magnetic-particle examination for cracks and other elongated discontinuities in magnetic materials; (b) fluorescent or
dye-penetrant examination for disclosing cracks, porosity, or
pin holes that extend to the surface of the material and for
outlining other surface imperfections, especially in nonmagnetic materials; (c) radiographic examination; (d) ultrasonic
thickness measurement and flaw detection; (e) eddy current
examination; (f) metallographic examination; (g) acoustic
emission testing; hammer testing while not under pressure;
and (h) pressure testing. (Section V of the ASME Code can
be used as a guide for many of the nondestructive examination techniques.)
Adequate surface preparation is important for proper visual
examination and for the satisfactory application of any auxiliary procedures, such as those mentioned above. The type of
surface preparations required depends on the individual circumstances, but surface preparations such as wire brushing,
blasting, chipping, grinding, or a combination of these preparations may be required.
If external or internal coverings, such as insulation, refractory protective linings, and corrosion-resistant linings, are in
good condition and there is no reason to suspect that an
unsafe condition is behind them, it is not necessary to remove
them for inspection of the vessel; however, it may be advisable to remove small portions of the coverings to investigate
their condition and effectiveness and the condition of the
metal underneath them.
Where operating deposits, such as coke, are normally permitted to remain on a vessel surface, it is particularly important to determine whether such deposits adequately protect
the vessel surface from deterioration. To determine this, spot
examinations in which the deposit is thoroughly removed
from selected critical areas may be required.
Where vessels are equipped with removable intemals,
the internals need not be removed completely as long as
reasonable assurance exists that deterioration in regions
rendered inaccessible by the internals is not occurring to
an extent beyond that found in more accessible parts of
the vessel.
5.6
INSPECTION OF PARTS
The following inspections are not all inclusive for every
vessel, but they do include the features that are common to
most vessels and that are most important. Authorized pressure vessel inspectors must supplement this list with any
additional items necessary for the particular vessel or vessels involved.
a. Examine the surfaces of shells and heads carefully for possible cracks, blisters, bulges, and other signs of deterioration.
Pay particular attention to the skirt and to support-attachent
~~~~~
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S T D - A P I / P E T R O API 520-ENGL 1997 I0 7 3 2 2 9 0 Ob13947 261
PRESSURE
VESSELINSPECTION
CODEMAINTENANCE
INSPECTION.
RATING,REPAIR,
AND ALTERATION
and knuckle regions of the heads. If evidence of distortion is
found, it may be necessary to make a detailed check of the
actual contours or principal dimensions of the vessel and to
compare those contours and dimensions with the original
design details.
b. Examine welded joints and the adjacent heat-affected
zones for service-induced cracks or other defects. On riveted
vessels, examine rivet head, butt strap, plate, and caulked
edge conditions. If rivet-shank corrosion is suspected, hammer testing or spot radiography at an angle to the shank axis
may be useful.
c. Examine the surfaces of ail manways, nozzles, and other
openings for distortion, cracks, and other defects, paying particular attention to the welding used to attach the parts and
their reinforcements. Normally, weep holes in reinforcing
plates should remain open to provide visual evidence of leakage as weil as to prevent pressure build-up in the cavity.
Examine accessible flange faces for distortion and determine
the condition of gasket-seating surfaces.
API Recommended Practice 574 provides more information on the inspection of piping, valves, and fittings associated with pressure vessels. MI Recommended Practice 572
provides more information on pressure vessel inspection.
5.7 CORROSION AND MINIMUMTHICKNESS
EVALUATION
Corrosion may cause a uniform loss (a general, relatively
even wastage of a surface area) or may cause a pitted appearance (an obvious, irregular surface wastage). Uniform corrosion may be difñcult to detect visually, and thickness readings
may be necessary to determine its extent. Pitted surfaces may
be thinner than they appear visually, and when there is uncertainty about the original surface location, thickness determinations may also be necessary.
The minimum actual thickness and maximum corrosion rate
for any part of a vessel may be adjusted at any inspection. When
the minimumactual thickness or maximum corrosion rate is to
be adjusted, one of the following should be considered:
a. Any suitable nondestructive examination, such as ultrasonic or radiographic examination, that will not affect the
safety of the vessel may be used as long as it will provide
minimum thickness determinations. When a measurement
method produces considerable uncertainty, test holes may
be drilled, or other nondestructive techniques, such as
ultrasonic A-scan, B-scan, or C-scan, may be employed.
Profile radiography may be also employed.
b. If suitable openings are available, measurements may be
taken through them.
c. The depth of corrosion may be determined by gauging the
uncorroded surfaces within the vessel when such surfaces are
in the vicinity of the corroded area.
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
5-3
d. For a corroded area of considerable size in which the circumferential stresses govem, the least thickness along the
most critical element of the area may be averaged over a
length not exceeding the following:
1. For vessels with inside diameters less than or equal to
60 inches (150 centimeters), one-half the vessel diameter
or 20 inches (50 centimeters), whichever is less.
2. For vessels with inside diameters greater than 60
inches (150 centimeters), one-third the vessel diameter or
40 inches (100 centimeters), whichever is less.
When the area contains an opening, the distance on either
side of the opening within which the thicknesses are averaged shall not extend beyond the limits of the reinforcement
as defined in the ASME Code. If, because of wind loads or
other factors, the longitudinal stresses govern, the least
thickness in a similarly determined length of arc in the most
critical plane perpendicular to the axis of the vessel also
shall be averaged for computation of the longitudinal
stresses. The thickness used for determining corrosion rates
at the respective locations shall be the average thickness
determined as in the preceding. For the purposes of 5.4, the
actual thickness as determined by inspection shall be understood to mean the most critical value of the average thickness that has been determined.
e. Widely scattered pits may be ignored as long as the following are true:
1. No pit depth is greater than one-half the vessel wall
thickness exclusive of the corrosion allowance.
2. The total area of the pits does not exceed 7 square inches
(45 square centimeters) within any 8-inch (20-centimeter)
diameter circle.
3. The sum of their dimensions along any straight line
within the circle does not exceed 2 inches (5 centimeters).
f. As an alternative to the procedures just described, any
components with thinning walls that, because of corrosion or
other wastage, are below the minimum required wall thicknesses may be evaluated to determine if they are adequate for
continued service. The thinning components may be evaluated by employing the design by analysis methods of Section
WI, Division 2, Appendix 4, of the ASME Code. These
methods may also be used to evaluate blend ground areas
where defects have been removed. It is important to ensure
that there are no sharp comers in blend ground areas to minimize stress concentration effects.
When using this criteria, the stress value used in the original pressure vessel design shall be substituted for the S, value
of Division 2 if the design stress is less than or equal to %specified minimum yield strength (SMYS) at temperature. If
the original design stress is greater than %-specified minimum yield strength at temperature, then %-specified minimum yield strength shall be substituted for s,. When this
approach is to be used, consulting with a pressure vessel engineer experienced in pressure vessel design is required.
5-4
API 510
g. When the surface at a weld with ajoint factor of other than
1.0, as well as surfaces remote from the weld, is corroded, an
independent calculation using the appropriate weld joint factor
must be made to determine if the thickness at the weld or
remote from the weld governs the allowable working pressure.
For this calculation, the surface at a weld includes 1 inch (2.5
centimeters) on either side of the weld or twice the minimum
thickness on either side of the weld, whichever is greater.
h. When measuring the corroded thickness of ellipsoidal and
torisphericai heads, the governing thickness may be as follows:
1. The thickness of the knuckle region with the head rating calculated by the appropriate head formuia.
2. The thickness of the central portion of the dished
region, in which case the dished region may be considered
a spherical segment whose allowable pressure is caiculated by the code formula for spherical shells.
The spherical segment of both ellipsoidal and torispherical
heads shall be consided to be that area located entirely
within a circle whose center coincides with the center of the
head and whose diameter is equal to 80 percent of the shell
diameter. The radius of the dish of tonspherical heads is to be
used as the radius of the spherical segment (equal to the diameter of the shell for standard heads, though other radii have
been permitted). The radius of the spherical segment of eilip
soidai heads shall be considered to be the equivalent spherical
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
radius KID, where D is the shell diameter (equal to the major
axis) and Kl is given in Table 1. In Table 1, h is one-haif the
length of the minor axis [equal to the inside depth of the eiiip
soidal head measured f?om the tangent line (headbend line)].
For many ellipsoidal heads, D/2h equals 2.0.
Table 1-Values
of Spherical Radius Factor K,
%u,
Kl
3.0
1.36
2.8
1.27
2.6
1.18
2.4
2.2
1.o8
0.99
2.0
0.90
1.8
0.81
1.6
1.4
0.73
0.65
12
0.57
1.o
0.50
Note: The equivalentspherical radius equals KID; the axis ratio equals D/u,.
Interpolation is permitted for intermediate values.
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S T D - A P I I P E T R O A P I S L O - E N G L 1997 E 0732290 0613947 O 3 4 E
PRESSURE
VESSELINSPECTION
CODE:MAINTENANCE
INSPECTION,
RATING,REPAIR,
AND ALTERATION
6
Inspection and Testing of Pressure
Vessels and Pressure-Relieving
Devices
6.1 GENERAL
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Pressure vessels shall be inspected at the time of installation. Internal field inspections of new vessels are not required
as long as a manufacturer’s data report assuring that the vessels are satisfactory for their intended service is available. To
ensure vessel integrity, all pressure vessels shall be inspected
at the frequencies provided in this section.
In selecting the technique(s) to be used for the inspection of
a pressure vessel, both the condition of the vessel and the environment in which it operates should be taken into consideration. The inspection, as deemed necessary by the authorized
pressure vessel inspector, may include many of a number of
nondestructive techniques, including visual inspection. Internal inspection is preferred because process side degradation
(corrosion, erosion, and environmental cracking) can be nonuniform îhroughout the vessel and, therefore, difficult to locate
by external NDE. On-stream inspection may be acceptable in
lieu of internal inspection for vessels under the specific circumstances defined in 6.4.In situations where on-stream inspection
is acceptable, such inspection may be conducted either while
the vessel is out of service and depressuized or on stream and
under pressure. Except in response to an apparent need, such as
when environmental cracking (see Guide for Inspection of.
Refinery Equipment, Chapter II) is suspected, inspection techniques exceeding the examination requirements used in the
design and fabrication of the vessel are not required.
The appropriate inspection must provide the information
necessary to determine that all of the essential sections or components of the vessel are safe to operate until the next scheduled
inspection. The risks associated with operational shutdown and
start-up and the possibility of increased corrosion due to exposure of vessel surfaces to air and moisture should be evaluated
when an internal inspection is being planned.
6.2
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RISK-BASED INSPECTION
Identifying and evaluating potential degradation mechanisms are important steps in an assessment of the likelihood
of a pressure vessel failure. However, adjustments to inspection strategy and tactics to account for consequences of a
failure should also be considered. Combining the assessment
of likelihood of failure and the consequence of failure are
essential elements of risk-based inspection (RBI).
When an ownerhser chooses to conduct a RBI assessment,
it must include a systematic evaluation of both the likelihood of
failure and the associated consequence of failure. The likelihood assessment must be based on all forms of degradation
that could reasonably be expected to affect a vessel in any particular service. Examples of those degradation mechanisms
include: internal or external metal loss from an identified form
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
6-1
of corrosion (localized or general), all forms of cracking,
including hydrogen assisted and stress corrosion cracking
(from the inside or outside surfaces of a vessel), and any other
f o m of metallurgical, corrosion, or mechanical degradation,
such as fatigue, embrittlement, creep, etc. Additionally, the
effectiveness of the inspection practices, tools, and techniques
utilized for finding the expected and potential degradation
mechanisms must be evaluated. This i i k e í i h d of failure
assessment should be repeated each time equipment or process
changes are made that could significantly affect degradation
rates or cause premature failure of the vessel.
Other factors that should be considered in a RBI assessment include: appropriateness of the materials of construction; vessel design conditions, relative to operating
conditions; appropriateness of the design codes and standards utilized; effectiveness of corrosion monitoring programs; and the quality of maintenance and inspection
quality assurance/quality control programs. Equipment failure data and information will also be important information
for this assessment. The consequence assessment must consider the potential incidents that may occur as a result of
fluid release, including explosion, fire, toxic exposure, environmental impact, and other health effects associated with a
failure of a vessel.
It is essential that all RBI assessments be thoroughly documented, clearly defining all the factors contributing to both the
likeliìid and consequence of a failure of the vessel.
After an effective RBI assessment is conducted, the
results can be used to establish a vessel inspection strategy
and more specifically better define the following:
a. The most appropriate inspection methods, scope, tools and
techniques to be utilized based on the expected forms of degradation.
b. The appropriate frequency for internal, external, and onstream inspections.
c. The need for pressure testing after damage has been
incurred or after repairs or modifications have been completed.
d. The prevention and mitigation steps to reduce the likelihocd and consequence of a vessel failure.
An RBI assessment may be used to increase or decrease
the 10-year inspection limit described in Section 6.4. When
used to increase the 10-year limit, RBI assessment shall be
reviewed and approved by a pressure vessel engineer and
authorized pressure vessel inspector at intervals not to exceed
10 years, or more often if warranted by process, equipment,
or consequence changes.
6.3
EXTERNAL INSPECTION
Each vessel aboveground shall be given a visual extemal
inspection, preferably while in operation, at least every 5 years
or at the same interval as the required internal or on-stream
inspection, whichever is less. The inspection shall, at the least,
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determine the condition of the exterior insulation, the condition of the supports, the allowance for expansion, and the general alignment of the vessel on its supports. Any signs of
leakage should be investigated so that the sources can be
established. Inspection for corrosion under insulation (CUI)
shall be considered for externally-insulated vessels subject to
moisture ingress and that operate between 25°F ( 4 ° C ) and
250°F (120"C), or are in intermittent service. This inspection
may require removal of some insulation. It is not normally
necessary to remove insulation if the entire vessel shell is
always operated at a temperature sufficiently low [below 25°F
(4"C)l or sufficiently high [above 250°F (120"C)l to prevent
the presence or condensation of moisture under the insulation.
Alternatively, shell thickness measurements done internaliy at
typical problem areas (for example, stiffening rings, around
nozzles, and other locations which tend to trap moisture or
allow moisture ingress) may be performed during
internal inspections.
Buried vessels shall be inspected to determine their external environmental condition. The inspection interval shall be
based on corrosion-rate information obtained from one or
more of the following methods: (a) during maintenance activity on adjacent connecting piping of similar materi& (b)
from the interval examination (specified in the paragraph
above) of similarly buried corrosion test coupons of similar
material; (c) from representative portions of the actual vessel;
or (d) from a vessel in similar circumstances.
Vessels that are known to have a remaining life of over 10
years or that are protected against external corrosion-for
example, (a) vessels insulated effectively to preclude the
entrance of moisture, (5)jacketed cryogenic vessels, (c) vessels installed in a cold box in which the atmosphere is purged
with an inert gas, and (d) vessels in which the temperature
being maintained is sufficiently low or Sufficiently high to
preclude the presence of w a t e r d o not need to have insulation removed for the external inspection. However, the condition of their insulating system or their outer jacketing, such as
the cold box shell, shall be observed at least every 5 years and
repaired if necessary.
6.4 INTERNAL AND ON-STREAM INSPECTION
The period between internal or on-stream inspections shall
not exceed one haif the estimated remaining life of the vessel
based on corrosion rate or 10 years, whichever is less. In
cases where the remaining safe operating life is estimated to
be less than 4 years, the inspection interval may be the full
remaining safe operating life up to a maximum of 2 years.
For pressure vessels that are in noncontinuous service and
are isolated from the process fluids such that they are not
exposed to corrosive environments (such as inert gas purged
or filled with noncorrosive hydrocarbons), the 10 years shall
be the 10 years of actual service exposed life. Equipment
that is not adequately protected from corrosive environ-
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
ments may experience significant intemal corrosion while
idle and should be carefully reviewed when setting inspection intervals. In no case should these exceed one-half the
estimated remaining corrosion-rate life, or 10 years since
the last inspection. External inspections for vessels in noncontinuous service remain the same as for continuous service, as outlined in 6.3.
Except as noted below, internal inspection is normally the
preferred method of inspection and shall be conducted on
vessels subject to significant localized corrosion and other
types of damage. At the discretion of the authorized pressure
vessel inspector, on-stream inspection may be substituted for
internal inspection in the following situations:
a. When size, configuration, or lack of access makes vessel
entry for internal inspection physically impossible.
b. When the general corrosion rate of a vessel is known to be
less than 0.005 inch (0.125 millimeter) per year and the estimated remaining life is greater than 10 years, and all of the
following conditions are met:
1. The corrosive character of the contents, including the
effect of trace components, has been established by at
least 5 years of the same or comparable service experience
with the t@e of contents being handled.
2. No questionable condition is disclosed by the external
inspection specified in 6.3.
3. The operating temperature of the steel vessel shell
does not exceed the lower temperature limits for the
creeprupture range of the vessel material.
4. The vessel is not considered to be subject to environmental cracking or hydrogen damage from the fluid being
handled.
5. The vessel is not striplined or plate-lined.
If the requirements of item b above are not met, as a result of
conditions noted during the scheduled on-stream inspection,
the next scheduled inspection shall be an internal inspection.
When a vessel has been internaliy inspected, the results of this
inspection can be used to determine whether an on-stream
inspection can be substituted for an internai inspection on a
similar vessel operating in the same service and conditions.
When an on-stream inspection is conducted in lieu of an
internal inspection, a thorough examination shall be performed using ultrasonic thickness measurements, or radiogaphy, or other appropriate means of NDE to measure metal
thicknesses andor assess the integrity of the metal and welds.
If an on-stream inspection is conducted, the authorized pressure vessel inspector shall be given sufficient access to all
parts of the vessel (heads, sheli, and nozzles) so that the
inspector is satisfied that an accurate assessment of the vessel
condition can be made.
A representative number of thickness measurements must be
conducted on each vessel to satisfy the requirements for an
internal or on-stream inspection. For example, the thickness for
all major components (shells, heads, cone sections) and a rep-
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VESSELINSPECTION
CODE:MAINTENANCE
INSPECTION,
RATING,REPAIR,
AND ALTERATION
resentative sample of vessel nozzles should be measured and
recorded, and the remaining life and next inspection interval
should be calculated for the limiting component. A decision on
the number and location of the thickness measurements should
consider results from previous inspections, if available, and the
potential consequenceof loss of containment. Measurements at
a number of thickness measurement locations (TMLs) are
intended to establish general and localized corrosion rates in
different sections of the vessel. A minimal number of TMLs are
acceptable when the established rate of corrosion is low and
not localized. For pressure vessels susceptible to localized corrosion, it is vital that those knowledgeable in localized corrosion mechanisms be consulted about the appropriate placement
and number of TMLs. Additionally, for localized corrosion, it
is important that inspections are conducted using scanning
methods such as profile radiography, scanning ultrasonics, a n d
or other suitable NDE methods that will reveal the scope and
extent of localized corrosion.
The remaining life of the vessel shall be calculated from
the following formula:
tactuai
Remaining life (years) =
-
fminimum
corrosion rate
[inches (miliimeters) per year]
where:
t-
tem
= the thickness, in inches (millimeters), recorded
at the time of inspection for a given location or
component.
= minimum allowable thickness, in inches (millimeters), for a given location or component.
tpreviaus
Corrosion rate =
y e u s betwen
- tactual
tprevious
and
tactual
tviaU = the thickness, in inches (millimeters), at the same
location as tinspection.
measured during a previous
A statistical analysis may be used in the corrosion rate and
remaining life calculations for the pressure vessel sections.
This statistical approach may be applied for assessment of
substituting an internal inspection (item b in the preceding),
or for determining the internal inspection interval. Care must
be taken to ensure that the statistical treatment of data results
reflects the actual condition of the vessel section. Statistical
analysis is not applicable to vessels with significant localized corrosion.
The determination of corrosion rate may include thickness
data collected at more than two different times. Suitable use
of short-term versus long-term corrosion rates shall be determined by the authorized pressure vessel inspector. When
there is a discrepancy between short-term and long-term corrosion rates, a pressure vessel engineer experienced in corrosion may need to be consulted about the use of these rates, at
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
6-3
the discretion of the inspector, for calculating the remaining
life and next inspection date.
For a large vessel with two or more zones of differing
corrosion rates, each zone may be treated independently
regarding the interval between inspections or for substituting the internal inspection with an on-stream inspection. If a
multi-zone analysis is used, the zone with the shortest
remaining half-life shall be used as the limiting case for setting the internal inspection interval or for substituting the
internal inspection with an on-stream inspection.
An alternative method to establish the required inspection
interval based on remaining life is by calculation of the projected maximum allowable working pressure (MAW) of
each vessel component as described in 5.4. This procedure
may be iterative involving selection of an inspection interval,
determination of the corrosion loss expected over the interval,
and calculation of the projected M A W . The inspection interval is within the maximum permitted as long as the projected
MAW of the limiting component is not less than the lower
of the name plate or rerated MAW. The maximum inspection interval using this method is also 10 years.
When problems are experienced with external loading,
faulty material, or fabrication the remaining life as determined above shall be reduced to recognize those conditions.
If deterioration due to conditions such as those mentioned
in 5.2 is detected, the inspection interval must be appropriately adjusted.
If the service conditions of a vessel are changed, the maximum operating pressure, the maximum and minimum operating temperature, and the period of operation until the next
inspection shall be established for the new service conditions.
If both the ownership and the location of a vessel are
changed, the vessel shall be internally and externally
inspected before it is reused, and the allowable conditions of
service and the next period of inspection shall be established
for the new service.
6.5
PRESSURETEST
When the authorized pressure vessel inspector believes that
a pressure test is necessary or when, after certain repairs or
alterations, the inspector believes that one is necessary (see
7.2.9), the test shall be conducted at a pressure in accordance
with the construction code used for determining the maximum allowable working pressure. To minimize the risk of
brittle fracture during the test, the metal temperature should
be maintained at least 30°F (17°C) above the minimum
design metal temperature for vessels that are more than 2
inches (5 centimeters) thick, or 10°F (6°C) above for vessels
that have a thickness of 2 inches (5 centimeters) or less. The
test temperature need not exceed 120°F (50°C) unless there is
information on the brittle characteristics of the vessel material
indicating that a lower test temperature is acceptable or a
higher test temperature is needed?
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S T D - A P I / P E T R O API 5 1 0 - E N G L 1997
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API 510
Pneumatic testing may be used when hydrostatic testing is
impracticable because of temperature, foundation, refractory
lining, or process reasons; however, the potential personnel
and property risks of pneumatic testing shall be considered
before such testing is carried out. As a minimum, the inspection precautions contained in the ASME Code shall be
applied in any pneumatic testing. Before applying a hydrostatic test to equipment, consideration should be given to the
supporting structure and the foundation design.
When a pressure test is to be conducted in which the test
pressure will exceed the set pressure of the safety relief valve
with the lowest setting, the safety relief valve or valves should
be removed. An alternative to removing the safety relief
valves is to use test clamps to hold down the valve disks.
Applying an additional load to the valve spring by turning the
compression screw is not recommended. other appurtenances, such as gauge glasses, pressure gauges, and rupture
disks, that may be incapable of withstanding the test pressure
should also be removed or should be blanked off or vented.
When the pressure test has been completed, pressure relief
devices of the proper settings and other appurtenances
removed or made inoperable during the pressure test shall be
reinstalled or reactivated.
6.6 PRESSURE-RELIEVING DEVICES
Pressure relief valves shall be tested and repaired by repair
organizations experienced in valve maintenance. Each repair
organization shall have a fully documented quality control
system. As a minimum, the following requirements and
pieces of documentation should be included in the quality
control system:
a.
b.
c.
d.
e.
f.
g.
h.
i.
Titiepage.
Revision log.
Contents page.
Statement of authority and responsibility.
Organizational chart.
Scope of work.
Drawings and specification controls.
Material and part control.
Repair and inspection program.
j. Welding, nondestructive examination, and heat treatment
procedures.
k. Valve testing, setting, leak testing, and sealing.
1. General example of the valve repair nameplate.
m. Procedures for calibrating measurement and test gauges.
n. Controlled copies of the manual.
o. Sample forms.
p. Repair personnel training or qualifications.
5F0r vessels without minimum design metai temperam, the minimum
acceptable operating temperam should be used in lieu of the minimum
design metal temperature.
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
0732290 Ob23952 b29
Each repair organization shall also have a fully documented training program that shall ensure that repair personnel are qualified within the scope of the repairs.
Pressure relief valves shall be tested at intervals that are
frequent enough to verify that the valves perform reliably.
This may include testing pressure relief valves on newly
inslalied equipment. Pressure-relieving devices should be
tested and maintained in accordance with N
I Recommended
Practice 576. Other pressure-relieving devices, such as rupture disks and vacuum-breaker valves, shall be thoroughly
examined at intervals determined on the basis of service.
The intervals between pressure-relieving-device testing or
inspection should be determined by the performance of the
devices in the particular service concerned. Test or inspection
intervals on pressure-relieving devices in typical process services should not exceed 5 years, unless service experience
indicates that a longer interval is acceptable. For clean
(nonfouling), noncorrosive services, maximum intervals
may be increased to 10 years. When service records indicate
that a pressure-relieving device was heavily fouled or stuck in
the last inspection or test, the service interval shail be reduced
if the review shows that the device may not perform reliably
in the future.The review should include an effort to determine
the cause of the fouling or the reasons for the relief device not
operating properly.
6.7 RECORDS
Pressure vessel owners and users shall maintain permanent
and progressive records of their pressure vessels. Permanent
records will be maintained throughout the service life of each
vessel; progressive records will be regularly updated to
include new information pertinent to the operation, inspection, and maintenance history of the vessel.
Pressure vessel records shall contain three types of vessel
information pertinent to mechanical integrity as follows:
a. Construction and design information. For example,
equipment serial number or other identifier, manufacturers’
data reports (MDRs), design specification data, design calculations (where MDRs are unavailable), and construction
drawings.
b. Operating and inspection history. For example, operating
conditions, including process upsets that may affect
mechanical integrity, inspection reports, and data for each
type of inspection conducted (for example, internal, external, thickness measurements), and inspection recommendations for repair. See Appendix C for sample pressure vessel
inspection records. Inspection reports shall document the
date of each inspection and/or test, the date of the next
scheduled inspection,the name of the person who performed
the inspection and/or test, the serial number or other identifier of the equipment inspected, a description of the inspec-
PRESSURE
VESSELINSPECTION
CODE:MAINTENANCE
INSPECTION,
RATING,REPAIR,
AND ALTERATION
tion and/or test performed, and the results of the inspection
and/or test.
c. Repair, alteration, and rerating information. For example,
(1) repair and alteration f o m like that shown in Appendix D,
(2) reports indicating that equipment still in-service with iden-
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
6-5
tified deficiencies or recommendations for repair are suitable
for continued service until repairs can be completed, and (3)
rerating documentation (including rerating calculations, new
design conditions, and evidence of stamping).
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S T D - A P I I P E T R O API 5LO-ENGL 1777 I O 7 3 2 2 9 0 O L L 3 9 5 4 4TL
PRESSURE VESSEL INSPECTION CODE: MAINTENANCE
INSPECTION,
2. External inspections shall be performed when an onstream or internal inspection is performed or at shorter
intervals at the owner or user’s option.
3. ûn-stream or internal inspections shall be performed at
least every 15 years or %-remaining corrosion-rate life,
whichever is less.
4. Any signs of leakage or deterioration detected in the
interval between inspections shall require an on-stream or
internal inspection of that vessel and a reevaluation of the
inspection interval for that vessel class.
Higher-risk vessels shall be inspected as follows:
1. External inpections shall be performed when an onstream or internal inspection is performed or at shorter
intervals at the owner or user’s option.
2. On-stream or internal inspections shall be performed at
least every 10 years or %-remaining corrosion rate life,
which ever is less.
3. In cases where the remaining life is estimated to be less
than 4 years, the inspection interval may be the fuli
remaining life up to a maximum of 2 years. Consideration
should also be given to increasing the number of vessels
inspected within that class to improve the likelihood of
detecting the worst-case corrosion.
4. Any signs of leakage or deterioration detected in the
interval between inspections shall require an on-stream or
internal inspection of that vessel and a reevaluation of the
inspection interval for that vessel class.
Pressure vessels (whether grouped into classes or not)
shall be inspected at intervals sufficient to insure their fitness
for continued service. Operational conditions and vessel integrity may require inspections at shorter intervals than the
intervals stated above.
e. If service conditions change, the maximum operating
temperature, pressure, and interval between inspections must
be reevaluated.
f. For large vessels with two or more zones of differing corrosion rates, each zone may be treated independently regarding the interval between inspections.
8.3.6
Additional Inspection Requirements
Additional inspection requirements, regardless of vessel
classification, exist for the following vessels:
a. Vessels that have changed ownership and location must
have an on-stream or internal inspection performed to estab-
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
RATING,REPAIR,
AND ALTERATION
8-3
lish the next inspection interval and to assure that the vessel is
suitable for its intended service. Inspection of new vessels is
not required if a manufacturer’s data report is available.
b. If a vessel is transferred to a new location, and it has been
more than 5 years since the vessel’s last inspection, an onstream or internal inspection is required. (Vessels in truckmounted, skid-mounted, ship-mounted, or barge-mounted
equipment are not included.)
c. Air receivers (other than portable equipment) shall be
inspected at least every 5 years.
d. Portable or temporary pressure vessels that are employed
for the purpose of testing oil and gas wells during completion
or recompletion shall be inspected at least once during each
3-year period of use. More frequent inspections shall be conducted if vessels have been in severe corrosive environments.
8.4
PRESSURE TEST
When a pressure test is conducted, the test shall be in
accordance with the procedures in 6.5.
8.5 SAFETY RELIEF DEVICES
Safety relief devices shall be inspected, tested, and repaired
in accordance with 6.6.
8.6 RECORDS
The foliowing records requirements apply:
a. Pressure vessel owners and users shall maintain pressure
vessel records. The preferred method of record keeping is to
maintain data by individual vessel. Where vessels are grouped
into classes, data may be maintained by vessel class. When
inspections, repairs, or alterations are made on an individual
vessel, specific data shall be recorded for that vessel.
b. Examples of information that may be maintained are vessel identification numbers; safety relief device information;
and the forms on which results of inspections, repairs, alterations, or reratings are to be recorded. Any appropriate
forms may be used to record these results. A sample pressure
vessel inspection record is shown in Appendix C . A sample
alteration or rerating of pressure vessel form is shown in
Appendix D. Information on maintenance activities and
events that affect vessel integrity should be included in the
vessel records.
S T D * A P I / P E T R O API 510-ENGL 1777
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APPENDIX B-AUTHORIZED PRESSUREVESSEL INSPECTOR CERTIFICATION
B.l
98
B.2.3 An API certificate for an authorized pressure vessel
inspector is valid for three years from its date of issuance.
Examination
A written examination to certify inspectors within the
scope of API 510, Pressure Vessel Inspection Code: Maintenunce Inspection, Rating, Repail; and Alteration, shall be
administered by API or a third party designated by MI. The
examination shall be based on the current APZ 51O Znspector
CertiJicationBody of Knowledge as published by API.
B.2.4 An API 510 authorized pressure vessel inspector certification is valid in all jurisdictions and any other location
that accepts or otherwise does not prohibit the use of MI 5 10.
B.3 Certification Agency
The American Petroleum Institute shall be the certifying
agency.
8.2 Certification
B.2.1 An API 5 10 authorized pressure vessel inspector cer-
The certification requirements of API 5 10 shall not be retroactive or interpreted as applying before 12 months after the
date of publication of this edition or addendum of API 510.
The recertification requirements of API 510 paragraph B.5.2
shall not be retroactive or interpreted as applying before 3
years after the date of publication of this edition or addendum
O f M I 510.
a. A Bachelor of Science degree in engineering or technology, plus one year of experience in supervision of inspection
activities or performance of inspection activities as described
inAP1510.
b. A two-year degree or certificate in engineering or technology, plus two years of experience in the design, construction,
B.5
98
Recertification
B.5.1 Recertification is required 3 years from the date of
issuance of the M I 5 10 authorized pressure vessel inspector
certificate. Recertification by written test will be required for
authorized pressure vessel inspectors who have not been
actively engaged as authorized pressure vessel inspectors
within the previous 3 years. Exams will be in accordance with
all provisions contained in API 5 10.
repair, inspection, or operation of pressure vessels, of which
one year must be in supervision of inspection activities or
performance of inspection activities as described in API 5 10.
c. A high school diploma or equivalent, plus three years of
experience in the design, construction, repair, inspection, or
Operation of pressure vessels, of which one year must be in
supervision of inspection activities or performance of inspection activities as described in API 510.
d. A minimum of five years of experience in the design, constniction,repair, inspection,or operation of pressure vessels, of
which one year must be in supervision of inspection activities
or performance of inspection activities as describe in API 5 10.
B.5.2 "Actively engaged as an authorized pressure vessel
inspector" shall be defined by one of the following provisions:
a. A minimum of 20% of time spent performing inspection
activities or supervision inspection activities as described in
the API 510 inspection code over the most recent 3-year certification period.
b. Performance of inspection activities or supervision of
inspection activities on 75 pressure vessels as described in
API 5 10 over the most recent 3-year certification period.
B.2.2 An API 5 10 authorized pressure vessel inspector certificate may be issued when an applicant provides documented evidence of passing the National Board of Boiler and
Pressure Vessel Inspectors examination and meets ali requirements for education and experience of API 5 1O.
Note: inspection activities common to other API inspection documents
(NDE, record-keeping, review of welding documents, etc.) may be considered here.
B-1
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98
B.4 Retroactivity
tificate will be issued when an applicant has successfully
passed the API 5 10 certification examination and satisfies the
criteria for education and experience. Hisher education and
experience, when combined, shall be equal to at least one of
the following:
w
98
98
Additional copies available from API Publicationsand Distribution:
(202) 682-8375
Information about API Publications, Programs and Services is
available on the World Wide Web at: httpYíwww.api.org
American
Peholeum
Institute
1220 L Street, Northwest
Washington, D.C. 20005-4070
202-682-8000
COPYRIGHT American Petroleum Institute
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Order No.C51OAl
S T D - A P I I P E T R O S T D 510-ENGL 1997
0732290 05b7558 724
=
Pressure Vessel Inspection Code:
Maintenance Inspection, Rating,
Repair, and Alteration
API 510
EIGHTH EDITION, JUNE 1997
American
Petroleum
Institute
COPYRIGHT American Petroleum Institute
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S T D - A P I I P E T R O STD 510-ENGL 1797 m U732270 0 5 b 7 5 5 7 bbO m
Pressure Vessel Inspection Code:
Maintenance Inspection, Rating,
Repair, and Alteration
Manufacturing, Distribution and Marketing Department
API 510
EIGHTH EDITION, JUNE 1997
American
Petroleum
Institute
COPYRIGHT American Petroleum Institute
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S T D * A P I / P E T R O S T D 510-ENGL 1777
0732290 0 5 b 7 5 b 0 3 8 2
SPECIAL NOTES
API publications necessarily address problems of a general nature. With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed.
API is not undertaking to meet the duties of employers, manufacturers, or suppliers to
warn and properly train and equip their employees, and others exposed, concerning health
and safety risks and precautions, nor undertaking their obligations under local, state, or
federal laws.
Information concerning safety and health risks and proper precautions with respect to particular materials and conditions should be obtained from the employer, the manufacturer or
supplier of that material, or the material safety data sheet.
Nothing contained in any API publication is to be construed as granting any right, by
implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent. Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent.
Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every
five years. Sometimes a one-time extension of up to two years will be added to this review
cycle. This publication will no longer be in effect five years after its publication date as an
operative API standard or, where an extension has been granted, upon republication. Status
of the publication can be ascertained from the API Authoring Department [telephone (202)
682-8000]. A catalog of API publications and materials is published annually and updated
quarterly by API, 1220 L Street, N.W., Washington, D.C. 20005.
This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API
standard. Questions concerning the interpretation of the content of this standard or comments and questions concerning the procedures under which this standard was developed
should be directed in writing to the director of the Authoring Department (shown on the title
page of this document), American Petroleum Institute, 1220 L Street, N.W., Washington,
D.C. 20005. Requests for permission to reproduce or translate all or any part of the material
published herein should also be addressed to the director.
API standards are published to facilitate the broad availability of proven, sound engineering and operating practices. These standards are not intended to obviate the need for applying sound engineering judgment regarding when and where these standards should be
utilized. The formulation and publication of API standards is not intended in any way to
inhibit anyone from using any other practices.
Any manufacturer marking equipment or materials in conformance with the marking
requirements of an API standard is solely responsible for complying with all the applicable
requirements of that standard. API does not represent, warrant, or guarantee that such products do in fact conform to the applicable API standard.
All rights reserved. No pari of this work may be reproduced, stored in a retrieval system, or
transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise,
without prior written permission from the publishel: Contact the Publisher;
API Publishing Services, 1220 L Street, N. i??,
Washington, D.C. 20005.
Copyright O 1997 American Petroleum Institute
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S T D - A P I / P E T R O S T D 5 1 0 - E N G L 1777 m 0 7 3 2 2 9 0 0 5 b 7 5 b 1 217
m
FOREWORD
In December 1931, API and the American Society of Mechanical Engineers (ASME) created the Joint APVASME Committee on Unfired Pressure Vessels. This committee was created to formulate and prepare for publication a code for safe practices in the design,
construction, inspection, and repair of pressure vessels to be used in the petroleum industry.
Entitled APVASME Code for Unfîred Pressure Vessels for Petroleum Liquids and Gases
(commonly called the APVASME Code for Unfîred Pressure Vessels or APVASME Code),
the first edition of the code was approved for publication in 1934.
From its inception, the APVASME Code contained Section I, which covered recommended practices for vessel inspection and repair and for establishing allowable working
pressures for vessels in service. Section I recognized and afforded well-founded bases for
handling various problems associated with the inspection and rating of vessels subject to
corrosion. Although the provisions of Section I (like other parts of the APVASME Code)
were originally intended for pressure vessels installed in the plants of the petroleum industry,
especially those vessels containing petroleum gases and liquids, these provisions were actually considered to be applicable to pressure vessels in most services. ASME’s Boiler and
Pressure Vessel Committee adopted substantially identical provisions and published them as
a nonmandatory appendix in the 1950, 1952, 1956, and 1959 editions of Section VI11 of the
ASME Boiler and Pressure Vessel Code.
After the APVASME Code was discontinued in 1956, a demand arose for the issuance of
Section I as a separate publication, applicable not only to vessels built in accordance with
any edition of the APVASME Code but also to vessels built in accordance with any edition
of Section VI11 of the ASME Code. Such a publication appeared to be necessary to assure
industry that the trend toward uniform maintenance and inspection practices afforded by
Section I of the APVASME Code would be preserved. API 510, first published in 1958, is
intended to satisfy this need.
The procedures in Section I of the 1951 edition of the APVASME Code, as amended by
the March 16, 1954 addenda, have been updated and revised in API 510. Section I of the
APVASME Code contained references to certain design or construction provisions, so these
references have been changed to refer to provisions in the ASME Code. Since the release of
the 1960 edition of the National Board Inspection Code, elements of the APVASME Code
have also been carried by the Narional Board Inspection Code.
It is the intent of API to keep this publication up to date. All pressure vessel owners and
operators are invited to report their experiences in the inspection and repair of pressure vessels whenever such experiences may suggest a need for revising or expanding the practices
set forth in API 5 10.
This edition of API 510 supersedes all previous editions of API 510, Pressure Vessel
Inspection Code: Maintenance Inspection, Rating, and Repair of Pressure Vessels.
API publications may be used by anyone desiring to do so. Every effort has been made by
the Institute to assure the accuracy and reliability of the data contained in them; however, the
Institute makes no representation, warranty, or guarantee in connection with this publication
and hereby expressly disclaims any liability or responsibility for loss or damage resulting
from its use or for the violation of any federal, state, or municipal regulation with which this
publication may conflict.
Suggested revisions are invited and should be submitted to the director of the Manufacturing, Distribution and Marketing Department, American Petroleum Institute, 1220 L Street,
N.W., Washington, D.C. 20005-4070.
iii
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STD.API/PETRO STD 510-ENGL 2777 9 0732290 0 5 b 7 5 b 2 155
IMPORTANT INFORMATION CONCERNING USE OF ASBESTOS
OR ALTERNATIVE MATERIALS
Asbestos is specified or referenced for certain components of the equipment described in
some API standards. It has been of extreme usefulness in minimizing fire hazards associated
with petroleum processing. It has also been a universal sealing material, compatible with
most refining fluid services.
Certain serious adverse health effects are associated with asbestos, among them the serious and often fatal diseases of lung cancer, asbestosis, and mesothelioma (a cancer of the
chest and abdominal linings). The degree of exposure to asbestos varies with the product and
the work practices involved.
Consult the most recent edition of the Occupational Safety and Health Administration
(OSHA), U.S. Department of Labor, Occupational Safety and Health Standard for Asbestos,
Tremolite, Anthophyllite, and Actinolite, 29 Code of Federal Regulations Section
1910.1001 ; the U.S. Environmental Protection Agency, National Emission Standard for
Asbestos, 40 Code of Federal Regulations Sections 61.140 through 61.156; and the U.S.
Environmental Protection Agency (EPA) rule on labeling requirements and phased banning
of asbestos products, published at 54 Federal Register 29460 (July 12, 1989).
There are currently in use and under development a number of substitute materials to
replace asbestos in certain applications. Manufacturers and users are encouraged to develop
and use effective substitute materials that can meet the specifications for, and operating
requirements of, the equipment to which they would apply.
SAFETY AND HEALTH INFORMATION WITH RESPECT TO PARTICULAR
PRODUCTS OR MATERIALS CAN BE OBTAINED FROM THE EMPLOYER, THE
MANUFACTURER OR SUPPLIER OF THAT PRODUCT OR MATERIAL, OR THE
MATERIAL SAFETY DATA SHEET.
iv
COPYRIGHT American Petroleum Institute
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S T D - A P I / P E T R O S T D 510-ENGL I1777 W 0 7 3 2 2 9 0 05b75b3 O71
CONTENTS
Page
1 SCOPE ............................................................................................................................
1.1 General Application ....................................................................................................
1.2 Specific Applications...................................................................................................
1-1
1-1
1-1
2 REFERENCES...............................................................................................................
2-1
3 DEFINITIONS ...............................................................................................................
3-1
4 OWNER-USER INSPECTION ORGANIZATION .....................................................
4-1
4.1 General ........................................................................................................................
4-1
4.2 API Authorized Pressure Vessel Inspector Qualification and Certification ...............4-1
4.3 Owner-User Organization Responsibilities ................................................................ 4-1
4.4 API Authorized Pressure Vessel Inspector Duty ........................................................ 4-1
5 INSPECTION PRACTICES ..........................................................................................
5.1 Preparatory Work ...........................................
...............
5.2 Modes of Deterioration and Failure.............
5.3 Corrosion-Rate Determination.....................
5.4 Maximum Allowable Working Pressure Det
5.5 Defect Inspection.........................................................................................................
..............................................................................
5.6 Inspection of Parts .............
5.7 Corrosion and Minimum Thickness Evaluation.........................................................
5-1
5-2
5-2
5-3
6 INSPECTION AND TESTING OF PRESSURE VESSELS AND
PRESSURE-RELIEVING DEVICES..............................
..... 6-1
6.1 General ........................................................................................................................
6-1
6.2 External Inspection......................................................................................................
6-1
6.3 Internal and On-Stream Inspection .............................................................................
6-1
6-3
6.4 Pressure Test ................................................................................................................
.................................... 6-3
6.5 Pressure-Relieving Devices ..............................
6.6 Records ........................................................................................................................
6-4
7 REPAIRS. ALTERATIONS. AND RERATING OF PRESSURE VESSELS .............7-1
7.1 General ........................................................................................................................
7-1
7.2 Welding........................................................................................................................
7-1
7.3 Rerating .......................................................................................................................
7-3
8 ALTERNATIVE RULES FOR EXPLORATION AND PRODUCTION
PRESSURE VESSELS ..................................................................................................
8.1 Scope and Specific Exemptions ..................................................................................
8.2 Glossary of Terms .......................................................................................................
8.3 Inspection Program .....................................................................................................
8.4 Pressure Test ...............................................................................................................
8.5 Safety Relief Devices ..................................................................................................
8.6 Records ........................................................................................................................
APPENDIX A-ASME
CODE EXEMPTIONS ...............................................................
V
COPYRIGHT American Petroleum Institute
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8-1
8-1
8-1
8-1
8-3
8-3
8-3
A- 1
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Page
APPENDIX B-AUTHORIZED PRESSURE VESSEL INSPECTOR
CERTIFICATION....................................................................................
APPENDIX C-SAMPLE
PRESSURE VESSEL INSPECTION RECORD
B- 1
................. C-1
APPENDIX D-SAMPLE REPAIR, ALTERATION, OR RERATING OF
PRESSURE VESSEL FORM .................................................................
D- i
INQUIRIES .....................................................................
E- 1
of Spherical Radius Factor K, ........................................................................
5-4
APPENDIX E-TECHNICAL
Table
I-Values
vi
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Pressure Vessel Inspection Code:
Maintenance Inspection, Rating, Repair, and Alteration
1 Scope
1.2 SPECIFIC APPLICATIONS
1.1 GENERAL APPLICATION
1.2.1 All pressure vessels used for Exploration and Production (E&P) service [for example, drilling, producing, gathering, transporting, lease processing, and treating liquid
petroleum, natural gas, and associated salt water (brine)] may
be inspected under the alternative rules set forth in Section 8.
Except for Section 6, all of the sections in this inspection code
are applicable to pressure vessels in E&P service. The alternative rules in Section 8 are intended for services that may be
regulated under safety, spill, emission, or transportation controls by the U S . Coast Guard; the Office of Hazardous Materials Transportation of the U.S. Department of Transportation
(DOT) and other units of DOT; the Minerals Management
Service of the U.S. Department of the Interior; state and local
oil and gas agencies; or any other regulatory commission.
This inspection code covers the maintenance inspection,
repair, alteration, and rerating procedures for pressure vessels
used by the petroleum and chemical process industries. The
application of this inspection code is restricted to organizations that employ or have access to an authorized inspection
agency as defined in 3.4. Except as provided in 1.2, the use of
this inspection code is restricted to organizations that employ
or have access to engineering and inspection personnel or
organizations that are technically qualified to maintain,
inspect, repair, alter, or rerate pressure vessels. Pressure vessel inspectors are to be certified as stated in this inspection
code. Since other codes that cover specific industries and general service applications already exist (for example, Sections
1.2.2 The following are excluded from the specific requirements of this inspection
and
Of the
and
Code and the National Board inspection Code), the industries
that fit within the restrictions above have developed this
inspection code to fulfill their own specific requirements.
This inspection code applies to vessels constructed in
accordance with the APUASME Code for Unfired Pressure
Vesselsfor Petroleum Liquids and Gases, Section VI11 of the
ASME Code, and other recognized pressure vessel codes; to
nonstandard vessels; and to other vessels constructed noncode or approved as jurisdictional special. This inspection
code is only applicable to vessels that have been placed in
service (including items further described in 1.2) and have
been inspected by an authorized inspection agency or
repaired by a repair organization as defined in 3.15.
Adoption and use of this inspection code does not permit
its use in conflict with any prevailing regulatory requirements.
' ' 9
a. Pressure vessels on movable structures covered by other
jurisdictional regulations (see Appendix A).
b. All classes of containers listed for exemption from construction in the scope of Section VIII, Division 1, of the
ASME Code (see Appendix A).
c. Pressure vessels that do not exceed the following volumes
and pressures:
1. Five cubic feet (0.141 cubic meters) in volume and 250
pounds per square inch (1723.1 kilopascals) design pressure.
2. One and a half cubic feet (0.042 cubic meters) in volume and 600 pounds per square inch (4136.9 hlopascals)
design pressure (see Appendix A).
1-1
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S T D - A P I / P E T R O STD 510-ENGL 1997
= 0732290
05b75bb 8TO
PRESSURE
VESSELINSPECTION
CODEMAINTENANCE
INSPECTION,RATING,REPAIR,AND ALTERATION
2 References
The most recent editions of the following standards, codes,
and specifications are cited in this inspection code.
API
RP 572 Inspection of Pressure Vessels
RP 574 Inspection of Piping, Tubing, Valves,and Fit-
=
2-1
ASME’
Boiler and Pressure Vessel Code, Section V, Section VI,
Section VII, Section VIII, Section IX, and Section XI
National Board2
National Board Inspection Code
tings
RP 576 Inspection of Pressure-Relieving Devices
Guide for Inspection of Refinery Equipment, Chapter II,
“Conditions Causing Deterioration or Failures”
Note: This publication is out of print. To obtain a copy please inform the person taking your order that you require this publication for the API 510
Inspector Certification Exam.
COPYRIGHT American Petroleum Institute
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’American Society of Mechanical Engineers, 345 East 47th Street, New
York, NY 10017.
’National Board of Boiler and Pressure Vessel Inspectors, 1055 Crupper
Avenue, Columbus, Ohio 43229.
S T D * A P I / P E T R O STD 520-ENGL 2997
0732290 05b75b7 737
PRESSUREVESSEL INSPECTION CODE: MAINTENANCE
INSPECTION, RATING,REPAIR. AND ALTERATION
3 Definitions
For the purposes of this standard, the following definitions
apply.
3.1 alteration: A physical change in any component or a
rerating that has design implications that affect the
pressure-containing capability of a pressure vessel beyond
the scope of the items described in existing data reports. The
following should not be considered alterations: any comparable or duplicate replacement, the addition of any reinforced nozzle less than or equal to the size of existing
reinforced nozzles, and the addition of nozzles not requiring
reinforcement.
3.2 ASME Code: Abbreviation and shortened title for the
ASME Boiler and Pressure Vessel Code. This abbreviated
title includes the addenda and code cases of the ASME Boiler
and Pressure Vessel Code.
The ASME Code is written for new construction; however, most of the technical requirements for design, welding, examination, and materials can be applied in the
maintenance inspection, rating, repair, and alteration of
operating pressure vessels. When the ASME Code cannot be
followed because of its new construction orientation (new or
revised material specifications, inspection requirements,
certain heat treatments and pressure tests, and stamping and
inspection requirements), the engineer or inspector shall
conform to this inspection code rather than to the ASME
Code. If an item is covered by requirements in the ASME
Code and this inspection code or if there is a conflict
between the two codes, for vessels that have been placed in
service, the requirements of this inspection code shall take
precedence over the ASME Code. As an example of the
intent of this inspection code, the phrase “applicable
requirements of the ASME Code” has been used in this
inspection code instead of the phrase “in accordance with
the ASMECode.”
3.3 authorized pressure vessel inspector: An
employee of an authorized inspection agency who is qualified and certified to perform inspections under this inspection code.
3.4 authorized inspection agency: Any one of the following:
a. The inspection organization of the jurisdiction in which
the pressure vessel is used.
b. The inspection organization of an insurance company that
is licensed or registered to write and actually does write pressure vessel insurance.
c. The inspection organization of an owner or user of pressure vessels who maintains an inspection organization for his
equipment only and not for vessels intended for sale or resale.
d. An independent organization or individual that is under
contract to and under the direction of an owner-user and that
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3-1
is recognized or otherwise not prohibited by the jurisdiction
in which the pressure vessel is used. The owner-user’s inspection program shall provide the controls that are necessary
when contract inspectors are used.
3.5 construction code: The code or standard to which a
vessel was originally built, such as APUASME, API, or State
Speciallnon-ASME.
3.6 inspection code: Shortened title for API 510 used in
this publication.
3.7 jurisdiction: A legally constituted government administration that may adopt rules relating to pressure vessels.
3.8 maximum allowable working pressure: The
maximum gauge pressure permitted at the top of a pressure
vessel in its operating position for a designated temperature. This pressure is based on calculations using the minimum (or average pitted) thickness for all critical vessel
elements, exclusive of thickness designated for corrosion
and loadings other than pressure.
3.9 minimum allowable shell thickness: The thickness required for each element of a vessel. The minimum
allowable shell thickness is based on calculations that consider temperature, pressure, and all loadings.
3.10 on-stream inspection: The inspection used to
establish the suitability of a pressure vessel for continued
operation. Nondestructive examination (NDE) procedures are
used to establish the suitability of the vessel, and the vessel
may or may not be in operation while the inspection is being
carried out. Because a vessel may be in operation while an
on-stream inspection is being carried out, an on-stream
inspection means essentially that the vessel is not entered for
internal inspection.
3.11 pressure vessel: A container designed to withstand
internal or external pressure. This pressure may be imposed
by an external source, by the application of heat from a direct
or indirect source, or by any combination thereof. This definition includes unfired steam generators and other vapor generating vessels which use heat from the operation of a
processing system or other indirect heat source. (Specific limits and exemptions of equipment covered by this inspection
code are given in Section 1 and Appendix A.)
3.12 pressure vessel engineer: Shall be one or more
persons or organizations acceptable to the owner-user who
are knowledgeable and experienced in the engineering disciplines associated with evaluating mechanical and material
characteristics which affect the integrity and reliability of
pressure vessels. The pressure vessel engineer, by consulting with appropriate specialists, should be regarded as a
composite of all entities needed to properly assess the technical requirements.
~
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3-2
3.13 quality assurance: All planned, systematic, and
preventative actions required to determine if materials, equipment, or services will meet specified requirements so that
equipment will perform satisfactorily in service. The contents
of a quality assurance inspection manual are outlined in 4.3.
3.14 repair: The work necessary to restore a vessel to a
condition suitable for safe operation at the design conditions.
If any repair changes the design temperature or pressure, the
requirements for rerating shall be satisfied. A repair can be
the addition or replacement of pressure or nonpressure parts
that do not change the rating of the vessel.
3.15
0 7 3 2 2 7 0 0 5 b 7 5 b 8 b73
repair organization:Any one of the following:
a. The holder of a valid ASME Certificate of Authorization
that authorizes the use of an appropriate ASME Code symbol stamp.
b. An owner or user of pressure vessels who repairs his or her
own equipment in accordance with this inspection code.
c. A contractor whose qualifications are acceptable to the
pressure-vessel owner or user and who makes repairs in
accordance with this inspection code.
d. An individual or organization that is authorized by the
legal jurisdiction.
3.16 rerating: A change in either the temperature ratings
or the maximum allowable working pressure rating of a
vessel, or a change in both. The maximum allowable working temperature and pressure of a vessel may be increased
or decreased because of a rerating, and sometimes a rerating requires a combination of changes. Derating below
COPYRIGHT American Petroleum Institute
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original design conditions is a permissible way to provide
for corrosion. When a rerating is conducted in which the
maximum allowable working pressure or temperature is
increased or the minimum temperature is decreased so that
additional mechanical tests are required, it shall be considered an alteration.
3.17 examiner: A person who assists the API authorized
pressure vessel inspector by performing specific NDE on
pressure vessels but does not evaluate the results of those
examinations in accordance with API 5 10, unless specifically
trained and authorized to do so by the owner or user. The
examiner need not be certified in accordance with API 510 or
be an employee of the owner or user but shall be trained and
competent in the applicable procedures in which the examiner is involved. In some cases, the examiner may be required
to hold other certifications as necessary to satisfy the owner or
user requirements. Examples of other certification that may
be required are American Society for Nondestructive Testing3
SNT-TC-1A, or CPl89, or American Welding Society4Welding Inspector Certification. The examiner’s employer shall
maintain certification records of the examiners employed,
including dates and results of personnel qualifications and
shall make them available to the API authorized pressure vessel inspector.
3American Society for Nondestructive Testing, Inc., 17 1 1 Arlingate Lane,
P.O. Box 28518, Columbus, Ohio, 43228-051 8.
4American Welding Society, 550 N.W. LeJeune Road, Miami, FL 33135.
S T D - A P I I P E T R O STD 510-ENGL 1777 W 0732270 05b75b7 5 0 T H
PRESSUREVESSEL INSPECTION CODE: MAINTENANCE
INSPECTION. RATING,REPAIR. AND ALTERATION
4 Owner-User Inspection Organization
4.1
GENERAL
An owner or user of pressure vessels who controls the frequency of the inspections of the pressure vessels or the maintenance of them is responsible for the functions of an
authorized inspection agency, as stated in the provisions of
this inspection code. This owner-user inspection organization
may also control activities relating to the maintenance inspection, rating, repair, and alteration of these pressure vessels.
4.2 API AUTHORIZED PRESSUREVESSEL
INSPECTOR QUALIFICATION AND
CERTIFICATION
An authorized pressure vessel inspector employed by or
under contract to and under the direction of an owner-user
inspection organization shall be educated and experienced.
His education and experience, when combined, shall be equal
to at least one of the following:
a. A degree in engineering plus 1 year of experience in the
design, construction, repair, operation, or inspection of boilers or pressure vessels.
b. A 2-year certificate in engineering or technology from a
technical college plus 2 years of experience in the design,
construction, repair, operation, or inspection of boilers or
pressure vessels.
c. The equivalent of a high school education plus 3 years of
experience in the construction, repair, operation, or inspection
of boilers or pressure vessels.
d. Five years of experience in the inspection of boilers or
pressure vessels.
In addition, the authorized pressure vessel inspector shall
be certified by an agency as provided in this inspection code
(see Appendix B).
4.3 OWNER-USER ORGANIZATION
RESPONSIBILITIES
An owner-user organization is responsible for developing,
documenting, implementing, executing, and assessing pressure vessel 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 manual and shall include the following:
a. Organization and reports of structure for inspection personnel.
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4-1
b. Documentation and maintenance of inspection and quality
assurance procedures.
c. Documentation and reports of inspection and test results,
d. Corrective action for inspection and test results.
e. Internal audits for compliance with the quality assurance
inspection manual.
f. Review and approval of drawings, design calculations, and
specifications for repairs, alterations, and reratings.
g. Assurance that all jurisdictional requirements for pressure
vessel inspection, repairs, alterations, and rerating are continuously met.
h. Reports to the authorized pressure vessel inspector any
process changes that could affect pressure vessel integrity.
i. Training requirements for inspection personnel regarding inspection tools, techniques, and technical knowledge
base.
j. Controls necessary so that only qualified welders and procedures are used for all repairs and alterations.
k. Controls necessary so that only qualified nondestructive
examination (NDE) personnel and procedures are utilized.
1. Controls necessary so that only materials conforming to
the applicable section of the ASME Code are utilized for
repairs and alterations.
m. Controls necessary so that all inspection measurement and
test equipment are properly maintained and calibrated.
n. Controls necessary so that the work of contract inspection
or repair organizations meet the same inspection requirements as the owner-user organization.
o. Internal auditing requirements for the quality control system for pressure-relieving devices.
4.4
API AUTHORIZED PRESSUREVESSEL
INSPECTOR DUTY
When inspections, repairs, or alterations are being conducted on pressure vessels, an API authorized pressure vessel
inspector shall be responsible to the owner-user for determining that the requirements of API 5 10 on inspection, examination, and testing are met, and shall be directly involved in the
inspection activities. The API authorized pressure vessel
inspector may be assisted in performing-visual inspections by
other properly trained and qualified individuals, who may or
may not be certified vessel inspectors. Personnel performing
nondestructive examinations shall meet the qualifications
identified in 3.17 but need not be M I authorized pressure
vessel inspectors. However, all examination results must be
evaluated and accepted by the API authorized pressure vessel inspector.
S T D - A P I I P E T R O STD 510-ENGL
1997 W 0732290 0 5 b 7 5 7 0 2 2 1 W
PRESSURE
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COM: MAINTENANCE
~NSPECTION.RATING,REPAIRAND ALTERATION
5 Inspection Practices
5.1
PREPARATORY WORK
Safety precautions are important in pressure vessel inspection because of the limited access to and the confined spaces
of pressure vessels. Occupational Safety and Health Administration (OSHA) regulations pertaining to confined spaces and
any other OSHA safety rules should be reviewed and followed, where applicable.
For an internal inspection, the vessel should be isolated by
blinds or other positive methods from all sources of liquids,
gases, or vapors. The vessel should be drained, purged,
cleaned, ventilated, and gas tested before it is entered. Where
required, protective equipment should be worn that will protect the eyes, lungs, and other parts of the body from specific
hazards that may exist in the vessel.
The nondestructive testing equipment used for the inspection is subject to the safety requirements customarily followed in a gaseous atmosphere. Before the inspection is
started, all persons working around the vessel should be
informed that people are going to be working inside it. People
working inside the vessel should be informed when any work
is going to be done on the exterior of it.
The tools and personnel safety equipment needed for the
vessel inspection should be checked before the inspection.
Other equipment that might be needed for the inspection,
such as planking, scaffolding, bosun's chairs, and portable
ladders, should be available if needed.
5.2 MODES OF DETERIORATION AND FAILURE
Contaminants in fluids handled in pressure vessels may
react with metals and cause corrosion. Stress reversals in
parts of equipment are common, particularly at points of high
secondary stress. If stresses are high and reversals are frequent, failure of parts may occur because of fatigue. Fatigue
failures in pressure vessels may also occur because of cyclic
temperature and pressure changes. Locations where metals
with different thermal coefficients of expansion are welded
together may be susceptible to thermal fatigue.
Deterioration or creep may occur if equipment is subjected
to temperatures above those for which it is designed. Since
metals weaken at higher temperatures, such distortion may
cause failures, particularly at points of stress concentration. If
excessive temperatures are encountered, structural-property
and chemical changes in metals may take place that may permanently weaken equipment. Creep is dependent on time,
temperature, and stress, so the actual or estimated levels of
these quantities shall be used in any evaluations.
At subfreezing temperatures, water and some chemicals
handled in pressure vessels may freeze and cause failure.
At ambient temperatures, carbon, low-alloy, and other ferritic steels may be susceptible to brittle failure. A number of
failures have been attributed to brittle fracture of steels that
were exposed to temperatures below their transition tempera-
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5-1
ture and to pressures greater than 20 percent of the required
hydrostatic test pressure; most brittle fractures, however, have
occurred on the first application of a particular stress level
(the first hydrotest or overload). Although the potential for a
brittle failure because of excessive operating conditions
below the transition temperature shall be evaluated, the
potential for a brittle failure because of rehydrotesting or
pneumatic testing of equipment or the addition of any other
additional loadings shall also be evaluated. Special attention
should be given to low-alloy steels (especially Z1/4 Cr-IMO)
because they may be prone to temper embrittlement. [Temper
embrittlement is a loss of ductility and notch toughness due to
postweld heat treatment or high-temperature service (above
700°F) (37O"C).]
Other forms of deterioration, such as stress corrosion
cracking, hydrogen attack, carburization, graphitization, and
erosion, may also occur under special circumstances. These
forms of deterioration are more fully discussed in Chapter II
of the API Guide for Inspection for Refinery Equipment.
5.3 CORROSION-RATE DETERMINATION
For a new vessel or for a vessel for which service conditions are being changed, one of the following methods shall
be employed to determine the vessel's probable corrosion
rate. The remaining wall thickness at the time of the next
inspection can be estimated from this rate.
a. A corrosion rate may be calculated from data collected
by the owner or user on vessels providing the same or similar service.
b. If data on vessels providing the same or similar service are
not available, a corrosion rate may be estimated from the
owner's or user's experience or from published data on vessels providing comparable service.
c. If the probable corrosion rate cannot be determined by
either item a or item b above, on-stream determinations shall
be made after approximately lo00 hours of service by using
suitable corrosion monitoring devices or actual nondestructive thickness measurements of the vessel or system. Subsequent determinationsshall be made after appropriate intervals
until the corrosion rate is established.
If it is determined that an inaccurate corrosion rate has
been assumed, the rate to be used for the next period shall be
increased or may be decreased to agree with the actual rate.
5.4
MAXIMUM ALLOWABLE WORKING
PRESSURE DETERMINATION
The maximum allowable working pressure for the continued use of a pressure vessel shall be based on computations
that are determined using the latest edition of the ASME
Code or the construction code to which the vessel was built.
The resulting maximum allowable working pressure from
these computations shall not be greater than the original max-
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¡mum allowable working pressure unless a rerating is per-
formed in accordance with 7.3.
Computations may be made only if the following essential
details comply with the applicable requirements of the code
being used: head, shell, and nozzle reinforcement designs;
material specifications; allowable stresses; weld efficiencies;
inspection acceptance criteria; and cyclical service requirements. In corrosive service, the wall thickness used in these
computations shall be the actual thickness as determined by
inspection (see 5.7) but shall not be greater than the thickness
reported in the material test report or the manufacturer’s data
report, where available, minus twice the estimated corrosion
loss before the date of the next inspection, except as modified
in 6.3. Allowance shall be made for the other loadings in
accordance with the applicable provisions of the ASME Code.
5.5
DEFECT INSPECTION
Vessels shall be examined for visual indications of distortion. If any distortion of a vessel is suspected or observed, the
overall dimensions of the vessel shall be checked to confirm
whether or not the vessel is distorted and, if it is distorted, to
determine the extent and seriousness of the distortion. The
parts of the vessel that should be inspected most carefully
depend on the type of vessel and its operating conditions. The
authorized pressure vessel inspector should be familiar with
the operating conditions of the vessel and with the causes and
characteristics of potential defects and deterioration. (For
recommended inspection practices for pressure vessels, see
API Recommended Practice 572.)
Careful visual examination is the most important and the
most universally accepted method of inspection. Other methods that may be used to supplement visual inspection include
(a) magnetic-particle examination for cracks and other elongated discontinuities in magnetic materials; (b) fluorescent or
dye-penetrant examination for disclosing cracks, porosity, or
pin holes that extend to the surface of the material and for
outlining other surface imperfections, especially in nonmagnetic materials; (c) radiographic examination; (d) ultrasonic
thickness measurement and flaw detection; (e) eddy current
examination; (f) metallographic examination; (g) acoustic
emission testing; hammer testing while not under pressure;
and (h) pressure testing. (Section V of the ASME Code can
be used as a guide for many of the nondestructive examination techniques.)
Adequate surface preparation is important for proper visual
examination and for the satisfactory application of any auxiliary procedures, such as those mentioned above. The type of
surface preparations required depends on the individual circumstances, but surface preparations such as wire brushing,
blasting, chipping, grinding, or a combination of these preparations may be required.
If external or internal coverings, such as insulation, refractory protective linings, and corrosion-resistant linings, are in
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good condition and there is no reason to suspect that an
unsafe condition is behind them, it is not necessary to remove
them for inspection of the vessel; however, it may be advisable to remove small portions of the coverings to investigate
their condition and effectiveness and the condition of the
metal underneath them.
Where operating deposits, such as coke, are normally permitted to remain on a vessel surface, it is particularly important to determine whether such deposits adequately protect
the vessel surface from deterioration. To determine this, spot
examinations in which the deposit is thoroughly removed
from selected critical areas may be required.
Where vessels are equipped with removable internals,
the internals need not be removed completely as long as
reasonable assurance exists that deterioration in regions
rendered inaccessible by the internals is not occurring to
an extent beyond that found in more accessible parts of
the vessel.
5.6
INSPECTION OF PARTS
The following inspections are not all inclusive for every
vessel, but they do include the features that are common to
most vessels and that are most important. Authorized pressure vessel inspectors must supplement this list with any
additional items necessary for the particular vessel or vessels involved.
a. Examine the surfaces of shells and heads carefully for possible cracks, blisters, bulges, and other signs of deterioration.
Pay particular attention to the skirt and to support-attachment
and knuckle regions of the heads. If evidence of distortion is
found, it may be necessary to make a detailed check of the
actual contours or principal dimensions of the vessel and to
compare those contours and dimensions with the original
design details.
b. Examine welded joints and the adjacent heat-affected
zones for service-induced cracks or other defects. On riveted
vessels, examine rivet head, butt strap, plate, and caulked
edge conditions. If rivet-shank corrosion is suspected, hammer testing or spot radiography at an angle to the shank axis
may be useful.
c. Examine the surfaces of all manways, nozzles, and other
openings for distortion, cracks, and other defects, paying particular attention to the welding used to attach the parts and
their reinforcements. Normally, weep holes in reinforcing
plates should remain open to provide visual evidence of leakage as well as to prevent pressure build-up in the cavity.
Examine accessible flange faces for distortion and determine
the condition of gasket-seating surfaces.
API Recommended Practice 574 can provide more information on the inspection of piping, valves, and fittings associated with pressure vessels. API Recommended Practice 572
can provide more information on pressure vessel inspection.
S T D - A P I I P E T R O S T D 5LO-ENGL 1977
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CODE:MAINTENANCE
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RATING,REPAIR,AND ALTERATION
5.7 CORROSION AND MINIMUMTHICKNESS
EVALUATION
Corrosion may cause a uniform loss (a general, relatively
even wastage of a surface area) or may cause a pitted appearance (an obvious, irregular surface wastage). Uniform corrosion may be difficult to detect visually, and thickness readings
may be necessary to determine its extent. Pitted surfaces may
be thinner than they appear visually, and when there is uncertainty about the original surface location, thickness determinations may also be necessary.
The minimum actual thickness and maximum corrosion rate
for any part of a vessel may be adjusted at any inspection. When
the minimum actual thickness or maximum corrosion rate is to
be adjusted, one of the following should be considered:
a. Any suitable nondestructive examination, such as ultrasonic or radiographic examination, that will not affect the
safety of the vessel may be used as long as it will provide
minimum thickness determinations. When a measurement
method produces considerable uncertainty, test holes may
be drilled, or other nondestructive techniques, such as
ultrasonic A-scan, B-scan, or C-scan, may be employed.
Profile radiography may be also employed.
b. If suitable openings are available, measurements may be
taken through them.
c. The depth of corrosion may be determined by gauging the
uncorroded surfaces within the vessel when such surfaces are
in the vicinity of the corroded area.
d. For a corroded area of considerable size in which the circumferential stresses govern, the least thickness along the
most critical element of the area may be averaged over a
length not exceeding the following:
1 . For vessels with inside diameters less than or equal to
60 inches (150 centimeters), one-half the vessel diameter
or 20 inches (50 centimeters), whichever is less.
2. For vessels with inside diameters greater than 60
inches (150 centimeters), one-third the vessel diameter or
40 inches (100 centimeters), whichever is less,
When the area contains an opening, the distance on either
side of the opening within which the thicknesses are averaged shall not extend beyond the limits of the reinforcement
as defined in the ASME Code. If, because of wind loads or
other factors, the longitudinal stresses govern, the least
thickness in a similarly determined length of arc in the most
critical plane perpendicular to the axis of the vessel also
shall be averaged for computation of the longitudinal
stresses. The thickness used for determining corrosion rates
at the respective locations shall be the average thickness
determined as in the preceding. For the purposes of 5.4, the
actual thickness as determined by inspection shall be understood to mean the most critical value of the average thickness that has been determined.
e. Widely scattered pits may be ignored as long as the following are true:
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5-3
1. No pit depth is greater than one-half the vessel wall
thickness exclusive of the corrosion allowance.
2. The total area of the pits does not exceed 7 square inches
(45 square centimeters) within any 8-inch (2Gcentimeter)
diameter circle.
3. The sum of their dimensions along any straight line
within the circle does not exceed 2 inches (5 centimeters).
f. As an alternative to the procedures just described, any
components with thinning walls that, because of corrosion or
other wastage, are below the minimum required wall thicknesses may be evaluated to determine if they are adequate for
continued service. The thinning components may be evaluated by employing the design by analysis methods of Section
VIII, Division 2, Appendix 4, of the ASME Code, These
methods may also be used to evaluate blend ground areas
where defects have been removed. It is important to ensure
that there are no sharp corners in blend ground areas to minimize stress concentration effects.
When using this criteria, the stress value used in the original pressure vessel design shall be substituted for the S , value
of Division 2 if the design stress is less than or equal to %specified minimum yield strength (SMYS) at temperature. If
the original design stress is greater than %-specified minimum yield strength at temperature, then %-specified minimum yield strength shall be substituted for s,. When this
approach is to be used, consulting with a pressure vessel engineer experienced in pressure vessel design is required.
g. When the surface at a weld with a joint factor of other
than 1.0, as well as surfaces remote from the weld, is corroded, an independent calculation using the appropriate weld
joint factor must be made to determine if the thickness at the
weld or remote from the weld governs the allowable working
pressure. For this calculation, the surface at a weld includes
1 inch (2.5 centimeters) on either side of the weld or twice
the minimum thickness on either side of the weld, whichever
is greater.
h. When measuring the corroded thickness of ellipsoidal and
torispherical heads, the governing thickness may be as follows:
1. The thickness of the knuckle region with the head rating calculated by the appropriate head formula.
2. The thickness of the central portion of the dished
region, in which case the dished region may be considered
a spherical segment whose allowable pressure is caiculated by the code formula for spherical shells.
The spherical segment of both ellipsoidal and torisphencal
heads shall be considered to be that area located entirely
within a circle whose center coincides with the center of the
head and whose diameter is equal to 80 percent of the shell
diameter. The radius of the dish of torispherical heads is to be
used as the radius of the spherical segment (equal to the diameter of the shell for standard heads, though other radii have
been permitted). The radius of the spherical segment of ellip
soidal heads shall be considered to be the equivalent spherical
radius K I D ,where D is the shell diameter (equal to the major
~
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axis) and K,is given in Table 1. In Table 1 , h is one-haif the
length of the minor axis [equal to the inside depth of the ellipsoidal head measured from the tangent line (headbend line)].
For many ellipsoidal heads, D/2h equals 2.0.
Table 1-Values
of Spherical Radius Factor K,
D/ut
KI
3.0
1.36
2.8
I .27
2.6
1.1s
2.4
I .os
2.2
2.0
I .8
0.99
0.90
1.6
0.73
I .4
0.65
I .2
0.57
I .o
0.50
0.8 1
Note: The equivalent spherical radius equals KID;
the axis ratio equals D/ut.
Interpolation is permitted for intermediate values.
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S T D - A P I / P E T R O S T D 5 1 0 - E N G L 1777
0 7 3 2 2 7 0 05b757Li 777
=
PRESSURE VESSEL INSPECTION CODE: MAINTENANCE
INSPECTION. RATING,REPAIR,AND ALTERATION
6 Inspection and Testing of Pressure
Vessels and Pressure-Relieving
Devices
6.1 GENERAL
Pressure vessels shall be inspected at the time of installation. Internal field inspections of new vessels are not required
as long as a manufacturer's data report assuring that the vessels are satisfactory for their intended service is available. To
ensure vessel integrity, all pressure vessels shall be inspected
at the frequencies provided in this section.
In selecting the technique(s) to be used for the inspection of
a pressure vessel, both the condition of the vessel and the environment in which it operates should be taken into consideration. The inspection, as deemed necessary by the authorized
pressure vessel inspector, may include many of a num-ber of
nondestructive techniques, including visual inspection. Internal inspection is preferred because process side degradation
(corrosion, erosion, and environmental cracking) can be nonuniform throughout the vessel and, therefore, difficult to locate
by external NDE. On-stream inspection may be acceptable in
lieu of internal inspection for vessels under the specific circumstances defined in 6.3.In situations where on-stream inspection
is acceptable, such inspection may be conducted either while
the vessel is out of service and depressurized or on stream and
under pressure. Except in response to an apparent need, such as
when environmental cracking (see Guide for inspection of
Refinery Equipment, Chapter II) is suspected, inspection techniques exceeding the examination requirements used in the
design and fabrication of the vessel are not required.
The appropriate inspection must provide the information
necessary to determine that all of the essential sections or
components of the vessel are safe to operate until the next
scheduled inspection. The risks associated with operational
shutdown and start-up and the possibility of increased corrosion due to exposure of vessel surfaces to air and moisture should be evaluated when an internal inspection is
being planned.
6.2
EXTERNAL INSPECTION
Each vessel aboveground shall be given a visual external
inspection, preferably while in operation, at least every 5
years or at the same interval as the required internal or onstream inspection, whichever is less. The inspection shall, at
the least, determine the condition of the exterior insulation,
the condition of the supports, the allowance for expansion,
and the general alignment of the vessel on its supports. Any
signs of leakage should be investigated so that the sources can
be established. Inspection for corrosion under insulation
(CUI) shall be considered for externally-insulated vessels
subject to moisture ingress and that operate between -4°C
and 120"C, or are in intermittent service. This inspection may
require removal of some insulation. It is not normally neces-
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6-1
sary to remove insulation if the entire vessel shell is always
operated at a temperature sufficiently low (below 4 ° C ) or
sufficiently high (above 120°C) to prevent the presence or
condensation of moisture under the insulation. Alternatively,
shell thickness measurements done internally at typical problem areas (for example, stiffening rings, around nozzles, and
other locations which tend to trap moisture or allow moisture
ingress) may be performed during internal inspections.
Buried vessels shall be inspected to determine their external environmental condition. The inspection interval shall be
based on corrosion-rate information obtained from one or
more of the following methods: (a) during maintenance activity on adjacent connecting piping of similar material; (b)
from the interval examination (specified in the paragraph
above) of similarly buried corrosion test coupons of similar
material; (c) from representative portions of the actual vessel;
or (d) from a vessel in similar circumstances.
Vessels that are known to have a remaining life of over 10
years or that are protected against external corrosion-for
example, (a) vessels insulated effectively to preclude the
entrance of moisture, (b) jacketed cryogenic vessels, (c) vessels installed in a cold box in which the atmosphere is purged
with an inert gas, and (d) vessels in which the temperature
being maintained is sufficiently low or sufficiently high to
preclude the presence of water-do not need to have insulation removed for the external inspection. However, the condition of their insulating system or their outer jacketing, such as
the cold box shell, shall be observed at least every 5 years and
repaired if necessary.
6.3
INTERNAL AND ON-STREAM INSPECTION
The period between internal or on-stream inspections shall
not exceed one half the estimated remaining life of the vessel
based on corrosion rate or 10 years, whichever is less. In
cases where the remaining safe operating life is estimated to
be less than 4 years, the inspection interval may be the full
remaining safe operating life up to a maximum of 2 years.
For pressure vessels that are in noncontinuous service and
are isolated from the process fluids such that they are not
exposed to corrosive environments (such as inert gas purged
or filled with noncorrosive hydrocarbons), the 10 years shall
be the 10 years of actual service exposed life. Equipment
that is not adequately protected from corrosive environments may experience significant internal corrosion while
idle and should be carefully reviewed when setting inspection intervals. In no case should these exceed one-half the
estimated remaining corrosion-rate life, or 10 years since
the last inspection. External inspections for vessels in noncontinuous service remain the same as for continuous service, as outlined in 6.2.
Except as noted below, internal inspection is normally the
preferred method of inspection and shall be conducted on
vessels subject to significant localized corrosion and other
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types of damage. At the discretion of the authorized pressure
vessel inspector, on-stream inspection may be substituted for
internal inspection in the following
- situations:
a. When size, configuration, or lack of access makes vessel
entry for internal inspection physically impossible.
b. When the general corrosion rate of a vessel is known to be
less than 0.005 inch (O. 125 millimeter) per year and the estimated remaining life is greater than 10 years, and all of the
following conditions are met:
1. The corrosive character of the contents, including the
effect of trace components, has been established by at
least 5 years of the same or comparable service experience
with the type of contents being handled.
2. No questionable condition is disclosed by the external
inspection specified in 6.2.
3. The operating temperature of the steel vessel shell
does not exceed the lower temperature limits for the
creep-rupture range of the vessel material.
4. The vessel is not considered to be subject to environmental cracking or hydrogen damage from the fluid being
handled.
5. The vessel is not ship-lined or plate-lined.
If the requirements of item b above are not met, as a
result of conditions noted during the scheduled on-stream
inspection, the next scheduled inspection shall be an internal inspection.
When an on-stream inspection is conducted in lieu of an
internal inspection, a thorough examination shall be performed using ultrasonic thickness measurements, or radiography, or other appropriate means of NDE to measure metal
thicknesses and/or assess the integrity of the metal and welds.
If an on-stream inspection is conducted, the authorized pressure vessel inspector shall be given sufficient access to all
parts of the vessel (heads, shell, and nozzles) so that the
inspector is satisfied that an accurate assessment of the vessel
condition can be made.
A representative number of thickness measurements must
be conducted on each vessel to satisfy the requirements for an
internal or on-stream inspection. For example, the thickness
for all major components (shells, heads, cone sections) and a
representative sample of vessel nozzles should be measured
and recorded, and the remaining life and next inspection
interval should be calculated for the limiting component. A
decision on the number and location of the thickness measurements should consider results from previous inspections,
if available, and the potential consequence of loss of containment. Measurements at a number of thickness measurement
locations (TMLs) are intended to establish general and localized corrosion rates in different sections of the vessel. A minimal number of TMLs are acceptable when the established
rate of corrosion is low and not localized. For pressure vessels
susceptible to localized corrosion, it is vital that those knowledgeable in localized corrosion mechanisms be consulted
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0732270 0 5 b 7 5 7 5 A O 3
about the appropriate placement and number of TMLs. Additionally, for localized corrosion, it is important that inspections are conducted using scanning methods such as profile
radiography, scanning ultrasonics, and/or other suitable NDE
methods that will reveal the scope and extent of localized corrosion.
The remaining life of the vessel shall be calculated from
the following
Remaining life (years) =
tactuai
- fminimum
corrosion rate
[inches (millimeters) per year]
Where:
tactual= the thickness, in inches (millimeters), recorded
at the time of inspection for a given location or
component.
tminimum
= minimum allowable thickness, in inches (millimeters), for a given location or component.
Corrosion rate =
tprevious
- tactual
years between tprevious
and tactual
tprevious
= the thickness, in inches (millimeters),at the same
location as tactuai
measured during a previous
inspection.
A statistical analysis may be used in the corrosion rate and
remaining life calculations for the pressure vessel sections.
This statistical approach may be applied for assessment of
substituting an internal inspection (item b in the preceding),
or for determining the internal inspection interval. Care must
be taken to ensure that the statistical treatment of data results
reflects the actual condition of the vessel section. Statistical
analysis is not applicable to vessels with significant localized corrosion.
The determination of corrosion rate may include thickness
data collected at more than two different times. Suitable use
of short-term versus long-term corrosion rates shall be determined by the authorized pressure vessel inspector. When
there is a discrepancy between short-term and long-term corrosion rates, a pressure vessel engineer experienced in corrosion may need to be consulted about the use of these rates, at
the discretion of the inspector, for calculating the remaining
life and next inspection date.
For a large vessel with two or more zones of differing corrosion rates, each zone may be treated independently regarding the interval between inspections or for substituting the
intemal inspection with an on-stream inspection. If a multizone analysis is used, the zone with the shortest remaining
half-life shall be used as the limiting case for setting the internal inspection interval or for substituting the internal inspection with an on-stream inspection.
An alternative method to establish the required inspection
interval based on remaining life is by calculation of the projected maximum allowable working pressure ( M A W ) of
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each vessel component as described in 5.4. This procedure
may be iterative involving selection of an inspection interval,
determination of the corrosion loss expected over the interval,
and calculation of the projected MAWP. The inspection interval is within the maximum permitted as long as the projected
MAWP of the limiting component is not less than the lower
of the name plate or rerated MAWP. The maximum inspection interval using this method is also 1O years.
When problems are experienced with external loading,
faulty material, or fabrication the remaining life as determined above shall be reduced to recognize those conditions.
If deterioration due to conditions such as those mentioned
in 5.2 is detected, the inspection interval must be appropriately adjusted.
If the service conditions of a vessel are changed, the maximum operating pressure, the maximum and minimum operating temperature, and the period of operation until the next
inspection shall be established for the new service conditions.
If both the ownership and the location of a vessel are
changed, the vessel shall be internally and externally
inspected before it is reused, and the allowable conditions of
service and the next period of inspection shall be established
for the new service.
6.4
PRESSURETEST
When the authorized pressure vessel inspector believes that
a pressure test is necessary or when, after certain repairs or
alterations, the inspector believes that one is necessary (see
7.2.9), the test shall be conducted at a pressure in accordance
with the construction code used for determining the maximum allowable working pressure. To minimize the risk of
brittle fracture during the test, the metal temperature should
be maintained at least 30°F(-1°C) above the minimum design
metal temperature for vessels that are more than 2 inches
thick, or 10°F(-12'C) above for vessels that have a thickness
of 2 inches or less. The test temperature need not exceed
120°F (50°C)unless there is information on the brittle characteristics of the vessel material indicating that a lower test temperature is acceptable or a higher test temperature is needed.5
Pneumatic testing may be used when hydrostatic testing is
impracticable because of temperature, foundation, refractory
lining, or process reasons; however, the potential personnel
and property risks of pneumatic testing shall be considered
before such testing is carried out. As a minimum, the inspection precautions contained in the ASME Code shall be
applied in any pneumatic testing. Before applying a hydrostatic test to equipment, consideration should be given to the
supporting structure and the foundation design.
When a pressure test is to be conducted in which the test
pressure will exceed the set pressure of the safety relief valve
'For vessels without minimum design metal temperature, the minimum
acceptable operating temperature should be used in lieu of the minimum
design metal temperature.
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RATING,
REPAIR,
AND ALTERATION
6-3
with the lowest setting, the safety relief valve or valves should
be removed. An alternative to removing the safety relief
valves is to use test clamps to hold down the valve disks.
Applying an additional load to the valve spring by turning the
compression screw is not recommended. Other appurtenances, such as gauge glasses, pressure gauges, and rupture
disks, that may be incapable of withstanding the test pressure
should also be removed or should be blanked off or vented.
When the pressure test has been completed, pressure relief
devices of the proper settings and other appurtenances
removed or made inoperable during the pressure test shall be
reinstalled or reactivated.
6.5
PRESSURE-RELIEVING DEVICES
Pressure relief valves shall be tested and repaired by repair
organizations experienced in valve maintenance. Each repair
organization shall have a fully documented quality control
system. As a minimum, the following requirements and
pieces of documentation should be included in the quality
control system:
a. Title page.
b. Revision log.
C. Contents page.
d. Statement of authority and responsibility.
e. Organizational chart.
f. Scope of work.
g. Drawings and specification controls.
h. Material and part control.
1. Repair and inspection program.
j. Welding, nondestructive examination, and heat treatment
procedures.
k. Valve testing, setting, leak testing, and sealing.
1. General example of the valve repair nameplate.
m. Procedures for calibrating measurement and test gauges.
n. Controlled copies of the manual.
o. Sample forms.
p. Repair personnel training or qualifications.
Each repair organization shall also have a fully documented training program that shall ensure that repair personnel are qualified within the scope of the repairs.
Pressure relief valves shall be tested at intervals that are
frequent enough to verify that the valves perform reliably.
This may include testing pressure relief valves on newly
installed equipment. Pressure-relieving devices should be
tested and maintained in accordance with API Recommended
Practice 576, which replaces Chapter XVI of the API Guide
for Inspection of Rejînery Equipment. Other pressure-relieving
devices, such as rupture disks and vacuum-breaker valves,
shall be thoroughly examined at intervals determined on the
basis of service.
The intervals between pressure-relieving-device testing or
inspection should be determined by the performance of the
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devices in the particular service concerned. Test or inspection
intervals on pressure-relieving devices in typical process services should not exceed 5 years, unless service experience
indicates that a longer interval is acceptable. For clean
(nonfouling), noncorrosive services, maximum intervals
may be increased to 10 years. When service records indicate
that a pressure-relieving device was heavily fouled or stuck in
the last inspection or test, the service interval shall be reduced
if the review shows that the device may not perform reliably
in the future. The review should include an effort to determine
the cause of the fouling or the reasons for the relief device not
operating properly.
6.6 RECORDS
Pressure vessel owners and users shall maintain permanent
2nd progressive records of their pressure vessels. Permanent
cords will be maintained throughout the service life of each
vessel; progressive records will be regularly updated to
include new information pertinent to the operation, inspection, and maintenance history of the vessel.
Pressure vessel records shall contain three types of vessel
information pertinent to mechanical integrity as follows:
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= 0732270
a. Construction and design information. For example, equip
ment serial number or other identifier, manufacturers’ data
reports (MDRs), design specification data, design calculations
(where MDRs are unavailable), and construction drawings.
b. Operating and inspection history. For example, operating
conditions, including process upsets that may affect mechanical integrity, inspection reports, and data for each type of
inspection conducted (for example, internal, external, thickness measurements), and inspection recommendations for
repair. See Appendix C for sample pressure vessel inspection
records. Inspection reports shall document the date of each
inspection and/or test, the date of the next scheduled inspection, the name of the person who performed the inspection
and/or test, the serial number or other identifier of the equipment inspected, a description of the inspection and/or test
performed, and the results of the inspection and/or test.
c. Repair, alteration, and rerating information. For example,
(1) repair and alteration forms like that shown in Appendix D,
(2) reports indicating that equipment still in-service with identified deficiencies or recommendations for repair are suitable
for continued service until repairs can be completed, and (3)
rerating documentation (including rerating calculations, new
design conditions, and evidence of stamping).
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PRESSURE
VESSEL INSPECTION
7.1 GENERAL
This section covers repairs and alterations to pressure vessels by welding. The requirements that must be met before
pressure vessels can be rerated are also covered in this section. When repairs or alterations have to be performed, the
applicable requirements of the ASME Code, the codes to
which the vessels were built, or other specific pressure vessel
rating codes shall be followed. Before any repairs or alterations are performed, all proposed methods of execution, all
materials, and all welding procedures that are to be used must
be approved by the authorized pressure vessel inspector and,
if necessary, by a pressure vessel engineer experienced in
pressure vessel design, fabrication, or inspection.
7.1.1 Authorization
All repair and alteration work must be authorized by the
authorized pressure vessel inspector before the work is started
by a repair organization (see 3.13). Authorization for alterations to pressure vessels that comply with Section VIII,
Divisions 1 and 2, of the ASME Code and for repairs to pressure vessels that comply with Section VIII, Division 2, of the
ASME Code may not be given until a pressure vessel engineer experienced in pressure vessel design has been consulted
about the alterations and repairs and has approved them. The
authorized pressure vessel inspector will designate the fabrication approvals that are required. The authorized pressure
vessel inspector may give prior general authorization for limited or routine repairs as long as the inspector is sure that the
repairs are the kind that will not require pressure tests.
7.1.2 Approval
The authorized pressure vessel inspector shall approve all
specified repair and alteration work after an inspection of the
work has proven the work to be satisfactory and any required
pressure test has been witnessed.
Defect Repairs
A crack in a welded joint and a defect in a plate may be
repaired by preparing a U- or V-shaped groove to the full
depth and length of the crack and then filling the groove with
weld metal deposited in accordance with 7.2. No crack shall
be repaired without authorization from the authorized pressure vessel inspector. Repairing a crack at a discontinuity,
where stress concentrations may be serious, should not be
attempted without prior consultation with a pressure vessel
engineer experienced in pressure vessel design.
Corroded areas, as defined by 5.7, may be restored with
weld metal deposited in accordance with 7.2. Surface irregularities and contamination shall be removed before welding.
The nondestructive examination and inspection appropriate
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0732290 0 5 b 7 5 7 8 512
CODEMAINTENANCE
INSPECTION,
7 Repairs, Alterations, and Rerating of
PressureVessels
7.1.3
m
m
RATING,
REPAIRAND ALTERATION
7-1
for the extent of restoration being performed shall be specified in the repair procedure.
7.2 WELDING
All repair and alteration welding shall be in accordance
with the applicable requirements of the ASME Code, except
as permitted in 7.2.1 1.
7.2.1
Procedures and Qualifications
The repair organization shall use qualified welders and
welding procedures qualified in accordance with the applicable requirements of Section IX of the ASME Code.
7.2.2
Qualification Records
The repair organization shall maintain records of its qualified welding procedures and its welding performance qualifications. These records shall be available to the inspector prior
to the start of welding. The repair organization’s qualified
welding procedures and welding performance qualifications
shall be in accord with the appropriate code.
7.2.3
Heat Treatment-Preheating
Note: Before preheating is used, a metallurgical review must be conducted to
determine if the vessel was postweld heat treated due to the characteristics of
the fluid contained in it.
For alterations or repairs of vessels initially postweld heat
treated as a code requirement and constructed of P- 1 and P-3
steels listed in the ASME Code, preheating to not less than
300°F (150°C) may be considered as an alternative to postweld heat treatment. The use of this minimum preheat alternative is to be restricted to preheating those steels that meet
the exemption criteria found in UCS-56(f) (1) through (4) of
Section VIII, Division 1, of the ASME Code. If the depth of
the weld exceeds the maximum thickness exempt from
postweld heat treatment, the repair weld or alteration shall be
postweld heat treated in accordance with the applicable
requirements of the ASME Code.
Vessels constructed of other steels that initially required
postweld heat treatment shall normally be postweld heat
treated if alterations or repairs involving strength welding are
performed. When the preheat or temper-bead alternative is
used as an alternative to postweld heat treatment, the
postweld heat treatment joint efficiency factor may be continued if the factor has been used in the currently rated design
(see note). Consulting with a pressure vessel engineer experienced in pressure vessel design is required if the preheat or
temper-bead alternative is desired.
7.2.4 Temper-Bead Welding
Note: Before temper-bead welding is used, a metallurgical review must be
conducted to determine if the vessel was postweld heat-treated due to the
characteristics of the fluid contained in it.
~
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7-2
For weld repairs of vessels originally postweld heat treated
as a code requirement and constructed of P-1 and P-3 steels
listed in the ASME Code, a temper-bead welding technique
may be used in lieu of postweld heat treatment. If a
temper-bead welding technique is to be used, the following
requirements must be met:
a. The weld area shall be preheated and maintained at a minimum temperature of 350°F(175°C) during welding. The maximum interpass temperature shall be 450°F (230°C).
b. The initial layer of weld metal shall be deposited over the
entire area with %-inch (3-millimeter) maximum diameter
electrodes.Approximately one-half the thickness of this layer
shall be removed by grinding before subsequent layers are
deposited. Subsequent layers shall be deposited with %inch
(4-millimeter) maximum diameter electrodes in a manner to
ensure tempering of the prior beads and their heat-affected
zones. The final temper-bead reinforcement layer shall be
removed substantially flush with the surface of the base material or the previous weld layer.
c. Heat input shall be controlled within a specified range of
welding current and voltage.
d. The weld area shall be maintained at a temperature of
500°F f50"F (260°C f28"C) for a minimum of 2 hours after
completion of the weld repair.
e. The repair welding shall be witnessed by the authorized
pressure vessel inspector.
f. The weld metal shall be deposited by the manual
shielded metal arc process using low-hydrogen electrodes.
The maximum bead width shall be four times the electrode
core diameter.
g. The use of the temper-bead welding technique is to be
restricted to temper-bead welding those steels that meet the
postweld heat treatment exemption criteria found in
UCS-56(f) (1) through (4) of Section VIII, Division 1, of the
ASME Code. If the depth of the repair exceeds the maximum
thickness exempt from local postweld heat treatment, the
repair weld shall be postweld heat-treated in accordance with
the applicable requirements of the ASME Code.
7.2.5
Local Postweld Heat Treatment
Note: Before local postweld heat treatment is used, a metallurgical review
must be conducted to determine if the vessel was postweld heat treated due to
the characteristics of the fluid contained in it.
Local postweld heat treatment (PWHT) may be substituted
for 360-degree banding on local repairs on all materials, provided that the following precautions are taken and requirements are met:
a. The application is reviewed, and a procedure is developed
by pressure vessel engineers experienced in the appropriate
engineering specialties.
b. The suitability of the procedure is evaluated. In evaluating
the suitability of the procedure, the following shall be considered: applicable factors, such as base metal thickness, decay
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thermal gradients, and material properties (hardness, constituents, strength, and the like); changes due to local postweld
heat treatment; the need for full penetration welds; and surface and volumetric examinations after local postweld heat
treatment. In evaluating and developing local postweld heat
treatment procedures, the overall and local strains and distortions resulting from the heating of a local restrained area of
the pressure vessel shell shall be considered.
c. A preheat of 300°F (150°C) or higher, as specified by specific welding procedures, is maintained during welding.
d. The required local postweld heat treatment temperature
shall be maintained for a distance of not less than two times
the base metal thickness measured from the weld. The local
postweld heat treatment temperature shall be monitored by a
suitable number of thermocouples (at least two). (When
determining the number of thermocouples necessary, the size
and shape of the area being heat treated should be considered.)
e. Heat shall be applied to any nozzle or any attachment
within the local postweld heat treatment area.
7.2.6 Repairs to Stainless Steel Weld Overlay and
Cladding
The repair procedure(s) to restore removed, corroded, or
missing clad or overlay areas shall be reviewed and endorsed
prior to implementation by the pressure vessel engineer and
authorized by the inspector.
Consideration shall be given to factors which may augment
the repair sequence such as stress level, P number of base
material, service environment, possible previously dissolved
hydrogen, type of lining, deterioration of base metal properties (by temper embrittlement of chromium-molybdenum
alloys), minimum pressurization temperatures, and a need for
future periodic examination.
For equipment which is in hydrogen service at an elevated
temperature or which has exposed base metal areas open to
corrosion which could result in a significant atomic hydrogen
migration in the base metal, the repair must additionally be
considered by the pressure vessel engineer for factors affecting the following:
a. Outgassing base metal.
b. Hardening of base metal due to welding, grinding, or arc
gouging.
c. Preheat and interpass temperature control.
d. Postweld heat treatment to reduce hardness and restore
mechanical properties.
Repairs shall be monitored by an inspector to assure compliance to repair requirements. After cooling to ambient temperatures, the repair shall be inspected by the liquid penetrant
method, according to ASME Code, Section VIII, Division 1,
Appendix 8.
For vessels constructed with P-3,P-4,or P-5 base matenals, the base metal in the area of repair should be examined
for cracking by the ultrasonic examination in accordance with
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PRESSURE
VESSEL INSPECTION CODE. MAINTENANCE
INSPECTION. RATING,
REPAIR.
AND ALTERATION
ASME Code, Section V, Article 5, paragraph T-543. This
inspection is most appropriately accomplished following a
delay of at least 24 hours after completed repairs for equipment in hydrogen service and for chromium-molybdenum
alloys that could be affected by delayed cracking.
7.2.7
Design
Butt joints shall have complete penetration and fusion.
Parts should be replaced when repairing them is likely to be
inadequate. Part replacements shall be fabricated according to
the applicable requirements of the appropriate code. New
connectionsmay be installed on vessels as long as the design,
location, and method of attachment comply with the applicable requirements of the appropriate code.
Fillet-welded patches require special design considerations, especially relating to efficiency. Fillet-welded patches
may be used to make temporary repairs, and the use of filletwelded patches may be subject to the patches’ acceptance in
the jurisdiction in which they are required. Temporary repairs
using fillet-welded patches shall be approved by a pressure
vessel engineer competent in pressure vessel design; and the
temporary repairs should be removed and replaced with suitable permanent repairs at the next available maintenance
opportunity. Temporary repairs may remain in place for a
longer period of time only if evaluated, approved, and documented by the pressure vessel engineer and the authorized
API pressure vessel inspector. Fillet-welded patches may be
applied to the internal or external surfaces of shells,
heads, and headers as long as, in the judgment of the
authorized pressure vessel inspector, either of the following is true:
a. The fillet-welded patches provide design safety equivalent
to reinforced openings designed according to the applicable
section of the ASME Code.
b. The fillet-welded patches are designed to absorb the membrane strain of the parts so that in accordance with the rules of
the applicable section of the ASME Code, the following
result:
1. The allowable membrane stress is not exceeded in the
vessel parts or the patches.
2. The strain in the patches does not result in fillet-weld
stresses that exceed allowable stresses for such welds.
Overlay patches shall have rounded corners. Flush (insert)
patches shall also have rounded corners, and they shall be
installed with full-penetration butt joints.
7.2.8 Material
The material used in making repairs or alterations shall
conform to the applicable section of the ASME Code. The
material shall be of known weldable quality and be compatible with the original material. Carbon or alloy steel with a
carbon content over 0.35 percent shall not be welded.
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7.2.9
7-3
Inspection
Acceptance criteria for a welded repair or alteration should
include nondestructive examination techniques that are in
accordance with the applicable sections of the ASME Code or
another applicable vessel rating code. Where use of these
nondestructive examination techniques is not possible or
practical, alternative nondestnictive examination methods
may be used.
7.2.1 O Testing
After repairs are completed, a pressure test shall be applied
if the authorized pressure vessel inspector believes that one is
necessary. A pressure test is normally required after an alteration. Subject to the approval of the jurisdiction (where the
jurisdiction’s approval is required), appropriate nondestructive examinations shall be required where a pressure test is
not performed. Substituting nondestructive examination procedures for a pressure test after an alteration may be done
only after a pressure vessel engineer experienced in pressure
vessel design and the authorized pressure vessel inspector
have been consulted.
7.2.1 1 Filler Metal
The filler metal used for weld repairs should have minimum specified tensile strength equal to or greater than the
minimum specified tensile strength of the base metal. If a
filler metal is used that has a minimum specified tensile
strength lower than the minimum specified tensile strength of
the base metal, the compatibility of the filler metal chemistry
with the base metal chemistry shall be considered regarding
weldability and service degradation. In addition,.the following shall be met:
a. The repair thickness shall not be more than 50 percent of the
required base metal thickness, excluding corrosion allowance.
b. The thickness of the repair weld shall be increased by a
ratio of minimum specified tensile strength of the base metal
and minimum specified tensile of the filler metal used for
the repair.
c. The increased thickness of the repair shall have rounded
comers and shall be blended into the base metal using a 3-to1 taper.
d. The repair shall be made with a minimum of two passes.
7.3 RERATING
Rerating a pressure vessel by changing its temperature ratings or its maximum allowable working pressure may be done
only after all of the following requirements have been met:
a. Calculations from either the manufacturer or an owner-user
pressure vessel engineer (or his designated representative)
experienced in pressure vessel design, fabrication, or inspection shall justify rerating.
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b. A rerating shall be established in accordance with the
requirements of the construction code to which the pressure
vessel was built or by computations that are determined using
the appropriate formulas in the latest edition of the ASME
Code if all of the essential details comply with the applicable
requirements of the code being used.
c. Current inspection records verify that the pressure vessel
is satisfactory for the proposed service conditions and that the
corrosion allowance provided is appropriate. An increase in
allowable working pressure or temperature shall be based on
thickness data obtained from a recent internal or on-stream
inspection.
d. The pressure vessel has at some time been pressure tested
in accordance with the new service conditions, or the vessel
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0732290 0 5 b 7 5 8 1 007
integrity is maintained by special nondestructive evaluation
inspection techniques in lieu of testing.
e. The pressure vessel inspection and rerating is acceptable
to the authorized pressure vessel inspector.
The pressure vessel rerating will be considered complete
when the authorized pressure vessel inspector oversees the
attachment of an additional nameplate or additional stamping
that carries the following information:
Rerated by
Maximum Allowable Working Pressure
Date
psi at
-Fo
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PRESSURE
VESSEL INSPECTION
SCOPE AND SPECIFIC EXEMPTIONS
This section sets forth the minimum alternative inspection
rules for pressure vessels that are exempt from the rules set
forth in Section 6 except as referenced in paragraphs 8.4 and
8.5. Except for Section 6, all of the sections in this inspection
code are applicable to Exploration and Production (E&P)
pressure vessels. These rules are provided because of the
vastly different characteristics and needs of pressure vessels
used for E&P service. Typical E&P services are vessels associated with drilling, production, gathering, transportation, and
treatment of liquid petroleum, natural gas, natural gas liquids,
and associated salt water (brine).
The following are specific exemptions:
a. Portable pressure vessels and portable compressed gas
containers associated with construction machinery, pile drivers, drilling rigs, well-servicing rigs and equipment, compressors, trucks, ships, boats, and barges shall be treated, for
inspection and recording purposes, as a part of that machinery
and shall be subject to prevailing rules and regulations applicable to that specific type of machine or container.
b. Pressure vessels referenced in Appendix A are exempt
from the specific requirements of this inspection code.
8.2 GLOSSARY OF TERMS
8.2.1 class of vessels: Pressure vessels used in a common circumstance of service, pressure, and risk.
8.2.2 inspection: The external, internai, or on-stream
evaluation (or any combination of the three) of a pressure vessel's condition.
a. external inspection: Evaluation performed from the
outside of a pressure vessel using visual procedures to establish the suitability of the vessel for continued operation. The
inspection may, or may not, be carried out while the vessel is
in operation.
b. internal inspection: Evaluation performed from the
inside of a pressure vessel using visual and/or nondestructive
examination procedures to establish the suitability of the vessel for continued operation.
c. on-stream inspection: Evaluation performed from the
outside of a pressure vessel using nondestructive examination
procedures to establish the suitability of the vessel for continued operation. The vessel may, or may not, be in operation
while the inspection is carried out.
d. progressive inspection: An inspection whose scope
(coverage, interval, technique, and so forth) is increased as a
result of inspection findings.
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RATING,REPAIR,
AND ALTERATION
CODEMAINTENANCE
INSPECTION,
8 Alternative Rules for Exploration and
Production Pressure Vessels
8.1
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8.2.3 Section 8 vessel: A pressure vessel which is
exempted from the rules set forth in Section 6 of this document.
8.3 INSPECTION PROGRAM
Each owner or user of Section 8 vessels shall have an
inspection program that will assure that the vessels have sufficient integrity for the intended service. Each E&P owner or
user shall have the option of employing, within the limitations
of the jurisdiction in which the vessels are located, any appropriate engineering, inspection, classification, and recording
systems which meet the requirements of this document.
8.3.1
On-Stream or Internal Inspections
a. Either an on-stream inspection or an internal inspection
may be used interchangeably to satisfy inspection requirements. An internal inspection is required when the vessel
integrity cannot be established with an on-stream inspection.
When an on-stream inspection is used, a progressive inspection shall be employed.
b. In selecting the technique(s) to be utilized for the inspection of a pressure vessel, both the condition of the vessel and
the environment in which it operates should be taken into
consideration. The inspection may include any number of
nondestructive techniques, including visual inspection, as
deemed necessary by the owner-user.
c. At each on-stream or internal inspection, the remaining
corrosion-rate life shall be determined as described in 8.3.2.
8.3.2
Remaining Corrosion Rate Life
Determination:
For a new vessel, a vessel for which service conditions are
being changed, or existing vessels, the remaining corrosion
rate life shall be determined for each vessel or estimated for a
class of vessels based on the following formula:
factual
Remaining life (years) =
- t,,",rn"rn
corrosion rate
[inches (millimeters) per year]
Where:
taciUA= the thickness, in
t,,,,,,,
inches (millimeters), measured at the time of inspection for a given
location or component used to determine
the minimum allowable thickness.
= the minimum required thickness, excluding corrosion allowance.
zn,inimumcan be obtained by any one of the following:
a. The nominal thickness in the uncorroded condition, less
the specified corrosion allowance.
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8-2
b. The original measured thickness, if documented, in the
uncorroded condition, less the specified corrosion allowance.
c. Calculations in accordance with the requirements of the
construction code to which the pressure vessel was built, or
by computations that are determined using the appropriate
formulas in the latest edition of the ASME Code, if all of the
essential details comply with the applicable requirements of
the code being used.
corrosion rate = loss of metal thickness, in inches (millimeters), per year. For vessels in which the
corrosion rate is unknown, the corrosion rate
shall be determined by one of the following
methods:
1. A corrosion rate may be calculated from data collected by the owner or user on vessels in the same or similar service.
2. If data on vessels providing the same or similar service
is not available, a corrosion rate may be estimated from
the owner’s or user’s experience or from published data on
vessels providing comparable service.
3. If the probable corrosion rate cannot be determined by
either item a or item b above, on-stream determination
shall be made after approximately loo0 hours of service
by using suitable corrosion monitoring devices or actual
nondestructive thickness measurements of the vessel or
system. Subsequent determinations shall be made after
appropriate intervals until the corrosion rate is established.
The remaining life shall be determined by an individual
experienced in pressure vessel design and/or inspection. If it is
determined that an inaccurate assumption has been made for
either corrosion rate or thickness, the remaining life shall be
increased or decreased to agree with the actual rate or thickness.
Other failure mechanisms (stress corrosion, brittle fracture,
blistering, and so forth,) shall be taken into account in determining the remaining life of the vessel.
8.3.3
External inspections
The following apply to external inspections:
a. The external visual inspection shall, at least, determine the
condition of the shell, heads, nozzles, exterior insulation, supports and structural parts, pressure-relieving devices, allowance for expansion, and general alignment of the vessel on its
supports. Any signs of leakage should be investigated so that
the sources can be established. It is not necessary to remove
insulation if the entire vessel shell is maintained at a temperature sufficiently low or sufficiently high to prevent the condensation of moisture. Refer to API Recommended Practice
572 for guidelines on external vessel inspections.
b. Buried sections of vessels shall be monitored to determine
their external environmental condition. This monitoring shall
be done at intervals that shall be established based on corrosion-rate information obtained during maintenance activity
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on adjacent connected piping of similar material, information
from the interval examination of similarly buried corrosion
test coupons of similar material, information from representative portions of the actual vessel, or information from a sample vessel in similar circumstances.
c. Vessels that are known to have a remaining life of over 10
years or that are protected against external corrosion-for
example, (1) vessels insulated effectively to preclude the
entrance of moisture, (2) jacketed cryogenic vessels, (3) vessels installed in a cold box in which the atmosphere is purged
with an inert gas, and (4) vessels in which the temperature
being maintained is sufficiently low or sufficiently high to
preclude the presence of water-do not need to have insulation removed for the external inspection; however, the condition of their insulating system or their outer jacketing, such as
the cold box shell, shall be observed at least every 5 years and
repaired if necessary.
8.3.4
Vessel Classifications
The pressure vessel owner or user shall have the option to
establish vessel inspection classes by grouping vessels into
common classes of service, pressure, and/or risk. Vessel classifications shall be determined by an individual(s) experienced in the criteria outlined in the following. If vessels are
grouped into classes (such as lower and/or higher risk), at a
minimum, the following shall be considered to establish the
risk class:
a. Potential for vessel failure, such as, minimum design
metal temperature; potential for cracking, corrosion, and erosion; and the existence of mitigation factors.
b. Vessel history, design, and operating conditions, such as,
the type and history of repairs or alterations, age of vessel,
remaining corrosion allowance, properties of contained fluids,
operating pressure, and temperature relative to design limits.
c. Consequences of vessel failure, such as, location of vessel
relative to employees or the public, potential for equipment
damage, and environmental consequences.
8.3.5
Inspection Intervals
The following apply to inspection intervals:
a. Inspections shall be performed at intervals determined by
the vessel’s risk classification.The inspection intervals for the
two main risk classifications (lower and higher) are defined
below. When additional classes are established, inspection
and sampling intervals shall be set between the higher risk
and lower risk classes as determined by the owner or user. If
the owner or user decides to not classify vessels into risk
classes, the inspection requirements and intervals of higherrisk vessels shall be followed.
b. Lower-risk vessels shall be inspected as follows:
1. Inspections on a representative sample of vessels in
that class, or all vessels in that class, may be performed.
S T D * A P I / P E T R O S T D 510-ENGL 1997
PRESSURE
VESSELINSPECTION
CODEMAINTENANCE
INSPECTION.
2. External inspections shall be performed when an onstream or internal inspection is performed or at shorter
intervals at the owner or user?s option,
3. On-stream or internal inspections shall be performed at
least every 15 years or %-remaining corrosion-rate life,
whichever is less.
4. Any signs of leakage or deterioration detected in the
interval between inspections shall require an on-stream or
internal inspection of that vessel and a reevaluation of the
inspection interval for that vessel class.
C. Higher-risk vessels shall be inspected as follows:
1. External inpections shall be performed when an onstream or internal inspection is performed or at shorter
intervals at the owner or user?s option.
2. On-stream or internal inspections shall be performed at
least every 10 years or %-remaining corrosion rate life,
which ever is less.
3. In cases where the remaining life is estimated to be less
than 4 years, the inspection interval may be the full
remaining life up to a maximum of 2 years. Consideration
should also be given to increasing the number of vessels
inspected within that class to improve the likelihood of
detecting the worst-case corrosion.
4. Any signs of leakage or deterioration detected in the
interval between inspections shall require an on-stream or
internal inspection of that vessel and a reevaluation of the
inspection interval for that vessel class.
d. Pressure vessels (whether grouped into classes or not)
shall be inspected at intervals sufficient to insure their fitness
for continued service. Operational conditions and vessel integrity may require inspections at shorter intervals than the
intervals stated above.
e. If service conditions change, the maximum operating
temperature, pressure, and interval between inspections must
be reevaluated.
f. For large vessels with two or more zones of differing corrosion rates, each zone may be treated independently regarding the interval between inspections.
8.3.6 Additional Inspection Requirements
Additional inspection requirements, regardless of vessel
classification, exist for the following vessels:
a. Vessels that have changed ownership and location must
have an on-stream or internal inspection performed to estab-
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= 0732290 05b758Li BLb W
RATING,REPAIR,AND ALTERATION
8-3
lish the next inspection interval and to assure that the vessel is
suitable for its intended service. Inspection of new vessels is
not required if a manufacturer?sdata report is available.
b. If a vessel is transferred to a new location, and it has been
more than 5 years since the vessel?s last inspection, an onstream or internal inspection is required. (Vessels in truckmounted, skid-mounted, ship-mounted, or barge-mounted
equipment are not included.)
c. Air receivers (other than portable equipment) shall be
inspected at least every 5 years.
d. Portable or temporary pressure vessels that are employed
for the purpose of testing oil and gas wells during completion
or recompletion shall be inspected at least once during each
3-year period of use. More frequent inspections shall be conducted if vessels have been in severe corrosive environments.
8.4
PRESSURETEST
When a pressure test is conducted, the test shall be in
accordance with the procedures in 6.4.
8.5 SAFETY RELIEF DEVICES
Safety relief devices shall be inspected, tested, and repaired
in accordance with 6.5.
8.6
RECORDS
The following records requirements apply:
a. Pressure vessel owners and users shall maintain pressure
vessel records. The preferred method of record keeping is to
maintain data by individual vessel. Where vessels are grouped
into classes, data may be maintained by vessel class. When
inspections, repairs, or alterations are made on an individual
vessel, specific data shall be recorded for that vessel.
b. Examples of information that may be maintained are vessel identification numbers; safety relief device information;
and the forms on which results of inspections, repairs, alterations, or reratings are to be recorded. Any appropriate
forms may be used to record these results. A sample pressure
vessel inspection record is shown in Appendix C. A sample
alteration or rerating of pressure vessel form is shown in
Appendix D. Information on maintenance activities and
events that affect vessel integrity should be included in the
vessel records.
STD.API/PETRO S T D 510-ENGL 1777
APPENDIX A-ASME
CODE EXEMPTIONS
The following classes of containers and pressure vessels
are excluded from the specific requirements of this inspection code:
generally recognized as piping components or accessories.
6. A vessel for containing water under pressure, including
vessels containing air, the compression of which serves
only as a cushion, when the following limitations are not
exceeded:
(a) A design pressure of 300 pounds per square inch
(2067.7 kilopascals).
(b) A design temperature of 210°F (99°C).
7. A hot water supply storage tank heated by steam or any
other indirect means when the following limitations are
not exceeded:
(a) A heat input of 200,000 British thermal units (21 1 x
108joules) per hour.
(b) A water temperature of 210°F (99°C).
(c) A nominal water-containing capacity of 120 gallons
(455 liters).
8. Vessels with an internal or external operating pressure
not exceeding 15 pounds per square inch (103.4 kilopascals) but with no limitation on size.
9. Vessels with an inside diameter, width, height, or crosssection diagonal not exceeding 6 inches (1 5 centimeters)
but with no limitation on their length or pressure.
10. Pressure vessels for human occupancy.
c. Pressure vessels that do not exceed the following volumes
and pressures:
1. Five cubic feet (0.141 cubic meters) in volume and 250
pounds per square inch (1723.1 kilopascals) design pressure.
2. One-and-one-half cubic feet (0.042 cubic meters) in
volume and 600 pounds per square inch (4136.9 kilopascals) design pressure.
a. Pressure vessels on movable structures covered by jurisdictional regulations:
1. Cargo or volume tanks for trucks, ships, and barges.
2. Air receivers associated with braking systems of
mobile equipment.
3. Pressure vessels installed in ocean-going ships, barges,
and floating craft.
b. All classes of containers listed for exemption from the
scope of Section VIII, Division 1, of the ASME Code:
1. Those classes of containers within the scope of other
sections of the ASME Code other than Section VIII.
2. Fired process tubular heaters.
3. Pressure containers that are integral parts or components of rotating or reciprocating mechanical devices, such
as pumps, compressors, turbines, generators, engines, and
hydraulic or pneumatic cylinders where the primary design
considerations or stresses are derived from the functional
requirements of the device.
4. Any structure whose primary function is transporting
fluids from one location to another within a system of
which it is an integral part (that is, piping systems).
5. Piping components such as pipe, flanges, bolting, gaskets,
valves, expansion joints, fittings, and the pressure-containing
parts of other components such as strainers and devices
which serve such purposes as mixing, separating, snubbing, distributing, and metering or controlling flow as long
as the pressure-containing parts of these components are
A-1
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0732270 05b7585 7 5 2
S T D - A P I / P E T R O S T D 510-ENGL 1797
APPENDIX B-AUTHORIZED
0732270 0 5 b 7 5 8 b b 7 9
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PRESSURE VESSEL INSPECTOR CERTIFICATION
8.1 Examination
8.2.2 Subject to the approval of the appropriatejurisdiction
during the first twelve months after the original June 1989
date of this appendix, owner-user inspectors who were
employed full time as pressure equipment inspectors in the
industry were eligible for a special one-time certification.
Documentation of satisfactory performance on the job for the
previous five years was required.
To qualis an inspector within the scope of API 510, a written examination shall be administered to the inspector by a
third party acceptable to API and the jurisdiction. This examination shall be based on the content of the latest edition of
API 5 i0 and the applicable portions of Sections V, VIII, and
IX of the latest edition of the ASME Code.
8.2.3 An API certificate for an authorized pressure vessel
inspector is valid for three years from its date of issuance.
B.2 Certification
B.2.1 An API certificate will be issued when an applicant is
B.2.4 An API inspector certification is valid in all 50 states
and in any other location that accepts API 510.
in compliance with API 510; however, if an applicant possesses an owner-user certification or commission for inspection of pressure vessels (as indicated below), it will be
recognized as long as the applicant meets the experience and
education requirements of API 510. An API 510 inspector
certification may be issued when proof of one of the following is presented:
8.3 Retroactivity
Except as provided in B.2.1, the certification requirements
of API 510 shall not be retroactive or interpreted as applying
before the June 1989 date.
8.4
a. A jurisdictional agency certification. The applicant must
have qualified by written examination under the laws, rules,
and regulations of a jurisdiction.
b. A National Board of Boiler and Pressure Vessel Inspectors
commission or owner-user commission. The applicant must
be qualified by written examination under the rules and regulations of the National Board.
Recertification
B.4.1 Recertification by written test will be required for
authorized pressure vessel inspectors who have not been
actively engaged as authorized pressure vessel inspectors
within the previous three years.
8.4.2 Recertification tests will be in accordance with ali of
the provisions contained in API 510.
B-1
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m
STD.API/PETRO S T D 510-ENGL 1777
APPENDIX C-SAMPLE
0732270 0 5 b 7 5 8 7 5 2 5
PRESSURE VESSEL INSPECTION RECORD
c-1
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
S T D * A P I / P E T R O STD 5 L D - E N G L 1777 m 0 7 3 2 2 9 0 05b7588 YbL m
PRESSURE VESSEL INSPECTION CODE MAINTENANCE
INSPECTION. RATING,
REPAIR.
AND
ALTERATION
c-3
Form Date
SAMPLE PRESSURE VESSEL
INSPECTION RECORD
Form No.
Owner or User
Vessel Name
Description
dame of Process
Owner or User Number
.ocation
JurisdictioníNational Board Number
nternal Diameter
Manufacturer
rangent LengthtHeight
shell Material Specification
Manufacturer's Serial No.
Date of Manufacture
-lead Material Specification
Contractor
nternal Materials
Vomina1 Shell Thickness
Vominal Head Thickness
Drawing Numbers
3esign Temperature
Joint Efficiency
Maximum Allowable Working
Pressure
Maximum Tested Pressure
Type Heads
Type Joint
Flange Class
Design Pressure
Relief Valve Set Pressure
Contents
Coupling Class
Number of Manways
Weight
Construction Code
Special Conditions
Thickness Measurements
Sketch or
Location
Description
Location
Number
I
Required Minimum
Thickness
Original
Thickness
I
Date
I
Comments (See Note 2)
i
Method
Authorized Inspector
Notes:
1. Use additional sheets, as necessary.
2.The location that each comment relates to must be described.
COPYRIGHT American Petroleum Institute
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S T D s A P I i P E T R O STD 510-ENGL 1997
m
0732290 0 5 b 7 5 8 4 3 T B
m
APPENDIX D-SAMPLE REPAIR, ALTERATION, OR RERATING
OF PRESSUREVESSEL FORM
D- 1
COPYRIGHT American Petroleum Institute
Licensed by Information Handling Services
0732290 0 5 b 7 5 7 0 O L T
STD*API/PETRO STD 510-ENGL 1977
PRESSURE
VESSEL
INSPECTION
CODEMAINTENANCE
INSPECTION.
RATING,REPAIR.AND ALTERATION
SAMPLE REPAIR ALTERATION OR
RERATING OF PRESSURE VESSEL FORM
1. Original Vessel Identification Number
2. Original Vessel Location
3. Manufacturer
4. See attachments for additional data?
5. Original Construction Code
6. Original Maximum Allowable Working Pressure
7. Original Design Temperature
8. Original Minimum Design Metal Temperature
9. Original Test Pressure
D-3
Form Date
Form No.
Owner or User Name
Vessel Name
Serial No.
P Yes
O No
Year Built
Year Built
At Pressure
Fluid
Head Material
1O. Shell Material
11. Shell Thickness
12. Original Joint Efticiency
13. Original Radiography
O
14. Original PWHT
P
If yes,
Temp (“F)
15. Original Corrosion Allowance
O
16. Work on Vessel Classified as:
17. Organization Performing Work
18. Construction Code for Present Work
19. New Vessel Identification Number (if Applicable)
20. New Vessel Location (if Applicable)
21. New Maximum Allowable Working Pressure
22. New Design Temperature
23. New Minimum Design Metal Temperature
24. New PWHT
O
Temp (“F)
Position
Head Thickness
Yes
Yes
P No
c1 No
Time (Hrs)
Repair
Yes
O Alteration
O Rerating
At Pressure
P No
Time (Hrs)
25. New Joint Efficiency, if Applicable E =
26. Type of Examination or Inspection Performed:
O ultrasonic
D radiographic
P magnetic particle
O penetrant
O visual
0 other
Test Medium
27.New Pressure Test if Yes, Pressure
28. New Corrosion Allowance
29. Describe work performed (attach drawings, calculations, and other pertinent data):
Test Position
Statement of Compliance
We certify that the statements made in this report are correct and that all material and construction for and workmanship of this
Edition of API 51O, Pressure Vessel Inspection Code.
0 repair D alteration, O rerating conform to the requirements of the
(repair, alteraticn, or rerating organization)
Signed
(authorized representative)
Date
Statement of Inspection
, having inspected the work described above, state
I, the undersigned, an inspector employed by
Edition of API 51O
that to the best of my knowledge, the work has been satisfactorily completed in accordance with the
Pressure Vessel Inspection Code.
Signed
API 510 Certification Number
Date
COPYRIGHT American Petroleum Institute
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STD.API/PETRO S T D 510-ENGL 1997
0732290 0 5 b 7 5 7 1 T 5 b
APPENDIX E-TECHNICAL
E.l
Introduction
API will consider written requests for interpretations of
API 510. API staff will make such interpretations in writing
after consultation, if necessary, with the appropriate committee officers and the committee membership. The API committee responsible for maintaining API 510 meets regularly to
consider written requests for interpretations and revisions and
to develop new criteria as dictated by technological development. The committee’s activities in this regard are limited
strictly to interpretations of the standard or to the consideration of revisions to the present standard on the basis of new
data or technology. As a matter of policy, API does not
approve, certify, rate, or endorse any item, construction, proprietary device, or activity; thus, accordingly, inquiries requiring such consideration will be returned. Moreover, API does
not act as a consultant on specific engineering problems or on
the general understanding or application of the rules. If, based
on the inquiry information submitted, it is the opinion of the
committee that the inquirer should seek assistance, the
inquiry will be returned with the recommendation that such
assistance be obtained.
All inquiries that cannot be understood because they lack
information will be returned.
E.2 Inquiry Format
Inquiries shall be limited strictly to requests for interpretation of the standard or to the consideration of revisions to the
standard on the basis of new data or technology. Inquiries
shall be submitted in the following format:
a. Scope. The inquiry shall involve a single subject or closely
related subjects. An inquiry letter concerning unrelated subjects will be returned.
b. Background. The inquiry letter shall state the purpose of the
inquiry, which shall be either to obtain an interpretation of the
standard or to propose consideration of a revision to the standard. The letter shall provide concisely the information needed
for complete understanding of the inquiry (with sketches, as
necessary). This information shall include reference to the
applicable edition, revision, paragraphs, figures, and tables.
c. Inquiry. The inquiry shall be stated in a condensed and
precise question format. Superfluous background information
shall be omitted from the inquiry, and where appropriate, the
inquiry shall be composed so that “yes” or “no” (perhaps with
provisos) would be a suitable reply. This inquiry statement
should be technically and editorially correct. The inquirer
shall state what he believes the standard requires. If in his
opinion a revision to the standard is needed, he shall provide
recommended wording.
The inquiry should be typed; however, legible handwritten
inquiries will be considered. The name and the mailing
address of the inquirer must be included with the proposal.
The proposal shall be submitted to the following address:
Director, Manufacturing, Distribution and Marketing Department, American Petroleum Institute, 1220 L Street, N.W.,
Washington, D.C. 20005-4070.
E-1
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INQUIRIES
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(202) 682-8375
Information about API Publications, Programs and Services is
available on the World Wide Web at: http://www.api.org
American
Petroleum
Institute
1220 L Street, Northwest
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