510 Exam Preparation Study Material

7/29/2019 510 Exam Preparation Study Material

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INTRODUCTION

API 510 STUDY MATERIAL

HOW TO USE THESE BOOKS

These books can be used in a self-study or instructor led format. There are two volumes, the Text

and the Questions and Answers.

TEXTBOOK

The textbook table of contents follows the API 510 Body of Knowledge that was in effect at the

time of its writing. Each area can be studied as a stand alone module for those who do not intend to set for

the API 510 exam, but want to obtain a better understanding on a given Code subject.

The process found to most effective for general use is to study each subject of interest and

complete the quizzes at the end of that module. As regards calculations, after mastering the given material,

refer to the Advanced Material section to increase the depth of understanding. The Advanced Material

covers the calculations required for some actual circumstances that might be encountered in the field.

For those intending to sit for the API 510 examination, at this writing the exam candidate is

allowedto use the ASME Codes and

the API books on thefirst portion of the test only. No reference

material is allowed for the second half of the test! You are also allowed to hand write notes in the

margins of the Code and API books used for the test.

QUESTIONS AND ANSWERS BOOK

This portion contains questions from the API 510 Code and the Recommended Practices, titled

RPI 572 Inspection of Pressure Vessels, RPI 576 Pressure Relieving Devices and Chapter II -Conditions

Causing Deterioration and Failures. These questions are for memorization if the examination will be

taken!

Effective Publications for this Revision:

o API Standard 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, andAlteration, 9th Edition, June 2006.

o API Recommended Practice 571, Damage Mechanisms Affecting Fixed Equipment in theRefining Industry, 1st Edition, December 2003.

o API Recommended Practice 572,Inspection of Pressure Vessels, 3rd Edition, November 2009.o API Recommended Practice 576, Inspection of Pressure-Relieving Devices,. 3rd Edition,

November 2009.o API Recommended Practice 577 Welding Inspection and Metallurgy, 1st Edition, October

2004.

o Section V,Nondestructive Examination, Articles 1, 2, 6, 7 and 23 (Section SE-797 only)o Section VIII, Rules for Construction of Pressure Vessels, Division 1; Introduction (U), UG, UW,

UCS, UHT, Appendices 1-4, 6, 8 and 12

o Section IX, Welding and Brazing Qualifications, Welding only


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API 510 Module

Table of Contents

API CODES

API 510 Corrosion Rates and Inspection Intervals

Scope 5

Inspection Interval 9Metal loss including corrosion averaging 13

Corrosion rates 13

Remaining Corrosion Allowance 13

Remaining Service Life 13

Quiz # 1 14

API 576 Pressure Relieving Devices

Scope 17

Types of pressure relieving devices 17

Reasons for Inspection 17

Causes of Improper Performance 17

Frequency and Time of Inspection 17

Quiz # 2 21

Quiz # 3 22

API 572 Inspection of Pressure Vessels

Scope 23

Reasons for Inspection 24

Causes of Deterioration 24

Methods of Repairs 27

Inspection Records and Reports 32

Quiz # 4 34

Quiz # 5 35

Quiz # 6 36

Quiz # 7 37

Quiz # 8 38

IRE Chapter 2

Coverage from the API 510 Body OF Knowledge 39

Quiz # 9 43


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ASME Section VIII Div. 1

Joint Efficiencies

UW-3 Weld Categories 46

UW-51 RT Examination of Welded Joints 52

UW-52 Spot Examination of Welded Joints 53

UW-11 RT and UT Examinations 55

UW-12 Maximum Allowable Joint Efficiencies 65

Exercises UW s-3-11-12 ??,61,80Postweld Heat Treatment

UW-40 Procedures for Postweld Heat Treatment 82

UCS-56 Requirements for Postweld Heat Treatment 82

Vessels under Internal Pressure

UG-27 Thickness of Shells Under Internal Pressure 85

UG-32 Formulas and Rules for Using Formed Heads 96

UG-34 Unstayed Flat Heads and Covers (Circular) 101

Exercises UG s-27-32-34 ?, ?, 103

Cylinder under External Pressure

UG-28 Thickness of Shells and Tubes (External Pressure) 107

Exercise UG-28 109

Pressure Testing

UG-20 Design Temperature 110

UG-22 Loading 111

UG-25 Corrosion 111

UG-98 Maximum Allowable Working Pressure 112

UG-99 Hydrostatic Test Pressure and Procedure 113

UG-100 Pneumatic Test Pressure and Procedure 116UG-102 Test Gages 118

Exercises UG s 99-100-102 119

Minimum Requirements for Attachment Welds at Openings

UW-16 Weld Size Determination 120

Exercise UW-16 124

Reinforcement for Openings in Shells and Heads

UG-36 Openings in Vessels 125

UG-37 Reinforcement of Openings 126

UG-40 Limits of Reinforcement 126

UG-41 Requirements for Strength of Reinforcement 126UG-42 Reinforcement of Multiple Openings 128

Exercises UG s 40-41-42-45 129

Exercise Reinforcement for Openings in Shells and Heads 136


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Minimum Design Metal Temperature and Exemptions

From Impact Testing

UG-84 Charpy Impact Test Requirements 137

Exercise UG-84 139

UCS-66 Materials 140

UCS-67 Impact Testing of Welding Procedures 140

UCS-68 Design 140

Exercises UG 20UCS 6667 144

Practical Knowledge

UG-77 Material Identification 145

UG-93 Inspection of Materials 146

UG-116 Name Plate Markings 147

UG-119 Name Plates 148

UG-120 Data Reports 149

Section IX

Welding on Pressure Vessels (Section IX Overview)

Article I General Requirements 150

Article II Welding Procedure Qualifications 151

Article III Welding Performance Qualifications 152

Article IV Welding Data 153

Welding Documentation Review

Welding Procedure Specification (WPS) 154

Procedure Qualification Record (PQR) 158

Practice WPS/PQR reviews 161

Advanced Material Example Problems

Static Head of Water 167

Corrosion 180

Cylinders Under Internal Pressure 183

Heads Under Internal Pressure 185

Charpy Impact Test Evaluation WPS/PQR 189

Quiz Static Head Pressure 178

Advanced Exercise Problems

Internal Pressure Shell Calculations 191

Internal Pressure Head Calculations 192

Solutions for Advanced Exercises 193

Appendix

Solutions to Text Module Exercises 193

Practice WPS and PQR forms 212

External Pressure Charts 220


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API 510 Module

PRESSURE VESSEL INSPECTION CODE

Overview

Section 1

General

Scope:

The API 510 applies to pressure vessels in the petrochemical and refining industries after they have enteredservice. The ASME Code applies to the new construction of vessels. While it applies only to new

construction it is often the Code to which a vessel is repaired. There are other construction Codes to which

a vessel can be constructed, for instance the Department of Transportation (DOT) provides rules for the

construction of and shipping of compressed gas cylinders. The Code for the construction of storage tanks

is API 653 and so forth.

The API 510 exempts certain vessels such as:

a. Vessels on moveable structures tank cars, etc.

b. All vessels exempted by Section VIII DIV. 1 of the ASME Code

c. Vessels that do not exceed a given volume or pressure.

d. Section 8 Alternative Rules for Natural Resource Vessels.

Section 2

References:

A listing of the standards, codes, and specifications cited in API 510.

Section 3

Definitions:

In this section the terms used in the API 510 Code are defined such as Alteration, ASME Code, API

Authorized Inspector, Construction Code, Maximum Allowable Working Pressure, Minimum Allowable

Shell Thickness and On-Stream Inspections just to mention a few. Study this section carefully as many

questions on the Exam often come from here.

Section 4

Owner-User Inspection Organization

This section lists in detail the responsibilities of the owneruser as regards the following:

1. Responsible for control of the pressure vessel inspection program.2. Responsible for the function of an authorized inspection agency, in accordance with API 5103. Responsible for activities relating to the maintenance, inspection, rating, repair, and alteration of these

pressure vessels.

Also listed are the educational and experience requirements for Authorized Pressure Vessel Inspectors and

the detailed listing of a required quality assurance inspection manual.

API Authorized Pressure Vessel Inspector Responsibilities are listed in 4.4.

Multiple questions over areas of responsibility are frequently included on the examination. A fair amount

of study on these issues is highly recommended.


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Section 5

Inspection Practices

Preparatory Work:

Often questions are asked about what must be done before entry into a vessel. Isolation, draining, cleaning,

purging and gas testing also the warning of personnel in the area, both inside and outside the vessel, etc.

Checking of safety equipment is necessary as well as inspection tools.

Modes of Deterioration and Failure:

Some of the listed modes of deterioration are fatigue, creep, brittle fracture, general corrosion, stress

corrosion cracking, hydrogen attack, carburization, graphitization, and erosion. A general question may be

asked such as; list six modes of deterioration or a more specific question such as; what is creep dependent

upon.

Corrosion-Rate Determination:

One important aspect of vessel maintenance and operation is the determination of how frequently a vessel

needs to be inspected. This can be largely driven by the rate at which a vessel is corroding. There are

three methods recognized by API 510 for this determination.

a. A corrosion rate may be calculated from data collected by the owner/user on vessel providing

the same or similar service.

b. Corrosion rate may be estimated from published data or from the owner user's experience.

c. After 1,000 hours of service using corrosion tabs or, on-stream NDE measurements.

If the estimated rates are in error they must be adjusted to determine the next inspection date.

Maximum Allowable Working Pressure Determination:

The continued use of a pressure vessel must be based on calculations using the current edition of the

ASME Code or the edition the vessel was constructed to. A vessels MAWP may not be raised unless a

full rerating has been performed in accordance with section 5.3. In corrosive service the wall thickness

used in the calculations must be the actual thickness as determined by the inspection, but must not be

thicker than original thickness on the vessel's original material test report or Manufacturer's Data Report

minus twice the estimated corrosion loss before the next inspection.

Defect Inspection:

Careful visual examination is the most important and most universally accepted method of inspection.

Other methods that may be used to supplement visual inspection are magnetic particle, ultrasonics, eddy

current, radiographic, penetrant and hammer testing (when the vessel is not under pressure). Vessels shall

be checked visually for distortion. Internal surfaces should be prepared by an acceptable method of

cleaning, there is no hard and fast rule for cleaning. External surfaces may require the removal of parts of

the insulation in an area of suspected problems or to check the effectiveness of the insulating system.

Sometimes deposits inside a vessel act to protect its metal from attack. It can be necessary to clean

selected areas down to bare metal to inspect those areas if problems are suspected from past experience or

if some indication of a problem is present.


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Inspection of Parts:

a. The surfaces of shells and heads should be checked for cracks, blistering, bulges, or other signs

of deterioration. With particular attention paid to knuckle regions of heads and support

attachments.

b. Inspect welded joints and their heat -affected zones for cracks or other defects. Rivets in

vessels shall be inspected for general corrosion, shank corrosion. If shank corrosion is

suspected hammer testing or angle radiography can be used.

c. Examine sealing surfaces of manways, nozzles and other openings for distortion, cracks andother defects. Pay close attention to the welding used to make these attachments.

Corrosion and Minimum Thickness Evaluation:

Corrosion occurs in two ways, general(a fairly uniform wasting away of a surface area) or pitting (the

surface may have isolated or numerous pits, or may have a washboard like appearance in severe cases).

Uniform wasting may be difficult to detect visually and ultrasonic thickness measurements are normally

done for that reason. A pit may be deeper than it appears and should be investigated thoroughly to

determine its depth. The minimum actual thickness and maximum corrosion rate may be adjusted at any

inspection for any part of a vessel. When there is a doubt about the extent of corrosion the following

should be considered for adjusting the corrosion rates.

a. Nondestructive examination such ultrasonics or radiography. If after these examinations considerable

uncertainty still exists the drilling of test holes may be required.

b. If suitable openings exist readings may be taken through them.

c. The depth of corrosion can be gauged from uncorroded surfaces adjacent to the area of interest.

d. For an area of considerable size where circumferential stress governs 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 an inside diameter of 60 inches or less one-half the vessel diameter or

20 inches whichever is less.

2. For vessels with an inside diameter greater than 60 inches one third the vessel diameter

or 40 inches whichever is less.

e. Widely scattered pits may be ignored if the following are true:

1. No pit is greater than half the vessel wall thickness without adding corrosion

allowance into the wall thickness.

2. The total area of the pits does not exceed 7 square inches. in any 8 inch diameter

circle.

3. Thesum of their dimensionsalong any straight line with in the circle does not exceed

2 inches.

f. As an alternative to the above the thinning components may be evaluated using the rules of Section VIII

Division 2 Appendix 4 of the ASME Code. If this approach is used consulting with a engineerexperienced in pressure vessel design is required.

g. When corrosion is located at a weld with a joint efficiency less than 1.0 and also in the area adjacent to

the weld special consideration must be given to the calculations for minimum thickness. Two sets of

calculations must be performed to determine the maximum allowable working pressure; one for the weld

using its joint efficiency and one for the remote area using E equals 1.0 . For purposes of these

calculations the surface at the weld includes one (1) inch on either side of the weld or twice the minimum

thickness whichever is greater.


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h. When measuring a ellipsoidal or torispherical head the governing thickness may be as follows:

1. The thickness of the knuckle region with the head rating calculated using 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

using the Code formula for spherical shells.

The spherical segment of both ellipsoidal and torispherical heads shall be considered to be in an arealocated entirely in with 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. The radius of the spherical segment of ellipsoidal heads shall be

considered to be the equivalent spherical radius K1D, where D is the shell diameter (equal to the major

axis) andK1 is as given in Table 1.

Section 6

Inspection and Testing of Pressure Vessels

And Pressure-Relieving Devices

General:

Section 6 requires that pressure vessels be inspected at the time of installation unless a Manufacturer's Data

Report is available. Further all pressure vessels must be inspected at frequencies provided in Section 4.

These inspections may be internal or external and may require any number of nondestructive techniques.

The inspection may be made while the vessel is in operation as long as all the necessary information can be

provided using that method.

Risk-Based Inspection:

Risk based inspection includes the assessment of the likelihood of failure along with consequences of

failure. When chosen, RBI must be assessed using a systematic evaluation of all forms of degradation that

could be reasonably be expected to affect a vessel in any particular service. After a complete and well-

documented assessment the results can be used to formulate an appropriate vessel inspection plan.

External Inspection:

The frequency for the external inspection of above the ground vessels shall be every 5 years or at the same

interval as the internal or on-stream inspection, whichever is less. This inspection should be performed

when the vessel is in service if possible.

Things to be checked shall include but are not limited to the following:

a. Exterior insulation

b. Supports

c. Allowance for expansion

d. General alignment

e. Signs of leakage

Buried vessels shall be monitored to determine their surrounding environmental condition. The frequency

of inspection must be based on corrosion rate information obtained on surrounding piping or vessels in

similar service.

Vessels known to have a remaining life in excess of 10 years or have a very tight insulation systems against

external corrosion do not need to have the insulation removed for inspection however the insulation should

be inspected for its condition at least every 5 years.


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Internal and On-Stream Inspection Intervals:

The period between internal or on-stream inspections shall not exceed 10 years or one-half the estimated

remaining corrosion-rate life whichever is less. In cases where the remaining safe operating life is

estimated at less than 4 years the inspection may be the full remaining safe operating life up to a maximum

of 2 years. Internal inspection is the preferred method On Stream may be substituted if all of the following

are true.

When the corrosion rate is known to be less than 0.005 inch per year and the estimated remaining life isgreater than 10 years internal inspection of the vessel is unnecessary as long as the vessel remains in the

same service, complete external inspections are performed and all of the following are true:

The non-corrosive character of the contents has been proven over a five-year period. Nothing serious is

found during the externals. The operating temperature of the vessel does not exceed the lower temperature

limits for the creep-rupture range of the vessel metal. The vessel cannot be subject to accidental exposure

to corrosives. Size and configuration make internal inspection impossible. The vessel is not subject to

cracking or hydrogen damage. The vessel is not plate-lined or strip-lined.

Pressure Test:

Whenever a pressure test becomes necessary they are to be conducted in a manner in accordance with the

vessel's construction Code. The following concerns should be addressed when pressure testing a vessel.

a. The test temperature should be at least 30 oF, above the minimum design metal temperature for

vessels greater than 2 inches thick and 10 oF for vessels 2 inches in thickness or less, but not

greater than 120oF.

b. Pneumatic tests are permitted when hydrostatic testing is not possible.

The safety precautions of the ASME Code shall be used.

c. When the test pressure will exceed the set pressure of the lowest relief device, these devices

shall be protected by blinding, removal, or clamping (gags).

Pressure-Relieving Devices:

One of the major concerns for pressure relief devices is their repair. Pressure relief devices must be

repaired by qualified organizations having a fully documented written quality control system and repair

training program for repair personnel. No hard and fast rule is given for the testing of relief devices the

interval between tests is dependent on the service conditions of the device. There are minimum of 15 items

that should be addressed in the written quality control documentation. Such as a Title page, Revision log,

Contents Page, Statement of Authority, Organizational Chart, etc.

Records:

Pressure vessel owners and users must maintain permanent and progressive records on their pressure

vessels. Items that should be included are Manufacturer's Data Reports, vessel identification numbers, RV

information, results of inspection and any repairs or alterations performed.


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Section 7

Repairs, Alterations and Rerating of Pressure Vessels

General:

Section 5 covers repairs and alterations to pressure vessels by welding and the requirements that must be

met when performing such work. These repairs and alterations must be performed to the edition of the

ASME Code that the vessel was built to.

Authorization:

Prior to starting any repairs or alterations the approval of the API 510 Inspector and in some cases an

engineer experienced in pressure vessels must be obtained. The API 510 Inspector may give approval to

any routine repairs if the Inspector has satisfied himself that the repairs will not require pressure tests.

Approval:

The API Inspector must approve all repairs after inspection and after witnessing any required pressure

tests.

Defect Repairs:

No crack may be repaired without prior approval of the API Inspector. If such repairs are required in a

weld or plate they may be performed using a U- or V-shaped grove to the full depth and length of the

crack. The U or V is then filled with weld metal. If the repair will be to an area that is subject to serious

stress concentrations an engineer experienced in pressure vessel must be consulted. Corroded areas may be

built up after proper removal of surface irregularities. All welding for repairs must comply with Section

5.2 of this Code. The amount of NDE and inspection shall be included in the repair procedure.

Welding:

All repair and alteration welding must be in accordance with the applicable requirements of the ASME

Code, except as permitted in 7.2.11.

Procedure and Qualifications:

The repair organizations must use qualified welders and welding procedures in accordance with applicable

requirements of Section IX of the ASME Code.

Qualification Records:

Qualification Records must be maintained for all welding operations and must be available for review by

the API Inspector prior to all welding operations.

Heat Treatment-Preheating:

Alterations and repairs can be performed on vessels that were originally postweld heat treated by using

only preheating within specific limitations. Postweld heat treatment in these cases would not then be

required. This alternative applies to only P-Nos. 1 and P-Nos. 3 materials of the ASME Code and should

be used only after considering the original intent of the postweld heat treatment. In some services the

heat treatment was required due to the corrosive nature of the contents of the vessel. In such cases this

type of procedure may not restore the metallurgical condition needed to combat corrosion.

For this reason consulting with an engineer experienced with pressure vessels is required. Two techniques

for these types of repairs or alterations are described in Section 5.2.3 and are very similar to those found in

paragraph UCS-56 of Section VIII Division 1 of the ASME Code. The major differences are the minimum

preheat temperature and the holding time and temperature after the completion of the welded repair or

alteration. Details and applicability of these procedures will be discussed in detail during the coverage of

paragraph UCS-56 of the ASME Code.


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Temper-Bead Welding:

a. The weld areashall be preheated and maintained at a minimum temperature of 350 oF (175 oC) duringwelding. The maximum interpass temperature shall be 450 oF (230 oC).

b. The initial layer of weld metal shall be deposited over the entire area with 1/8 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 5/32-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 substantiallyflush 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 oF +or50 oF (260 oC +or28 oC) for a

minimum of 2 hours after completion of the weld repair.

e. The repair shall be witnessed by the A.I.f. The weld shall made using the SMAW process. The maximum bead width shall not be more than four

core diameters.

g. This technique is restricted meet the exemptions found in ASME Section VIII Div.1 UCS-56(f) (1)through (4).Local Postweld Heat Treatment:

The API 510 Code permits postweld heat treatment to be applied locally, this means that the entire vessel

circumference may not be required to be included in the heat treatment. Just as in the alternative to

postweld heat treatment above consideration to applying this local treatment must be made with regards to

service. It does not apply to all situations the following four steps must be applied prior to using this type

of heat treatment.

a. A qualified engineer must review the application.

b. Suitability of this type of procedure is reviewed and consideration is given to such things asbase metal thickness, hardness, and thermal gradients.

c. A preheat of 300 oF or higher is maintained during welding.

d. The distance included in postweld heat treatment temperature

on each side of the welded area shall be not less than two times the

base metal thickness as measured from the weld. At least two

thermocouples must be used. The shape and size of the area

will determine the size of the thermocouples required.

e. Heat must be applied to any nozzle or any attachment within the

local postweld heat treatment area.

Repairs to Stainless Steel Weld Overlay and Cladding:

Prior to the repair or replacement of corroded or missing clad material a repair procedure and must written.

Some of the concerns that must be addressed are as follows; out gassing of the base metals, hardening of

the base metal during repairs, preheating and interpass temperatures and postweld heat treatment.


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Design:

The design of welded joints included in the API 510 are in compliance with those of the appropriate code.

All butt joints shall be full penetration and must have complete fusion. Fillet weld patches may be allowed

as temporary repairs and can be applied to the inside or outside of vessels but require special

considerations. The jurisdiction where the vessel is operating may for instance prohibit their use. Patches to

the overlay in vessels must have rounded corners; this also true of flush (insert) patches.

Material:

All materials for repairs must conform to the ASME Code. Carbon or alloy steels with a carbon content

which exceeds 0.35 percent may not be used in welded construction.

Inspection:

The acceptance of welded repairs or alterations should include NDE that is in agreement with the ASME

Codes that apply. If the ASME Code methods are not possible or practical, alternative NDE may be used.

Testing:

After repairs a pressure test must be applied if the API Inspector believes one is needed. Normally

pressure tests are required after an alteration. If jurisdictional approval is required and it has been obtained

NDE may be substituted for a pressure test. If an alteration has been performed a pressure vessel engineer

must be consulted prior to using NDE in place of pressure test.

Filler Metal

In general the filler metal used in repairs must have a specified minimum tensile strength equal to or

exceeding that of the base material. The following shall also be met.

a. The repair thickness shall not be more than 50 percent of the required base metal thickness, excludingcorrosion allowance.

b. The thickness of the repair weld shall be increased by a ratio of minimum specified tensile strength ofthe base metal and minimum specified tensile of the filler 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

Rerating:

Rerating a pressure vessel by changing its temperature ratings or its maximum allowable working pressure

may be done only after meeting the requirements of API 510 given in this section. Calculations,

compliance to the current construction code, current inspection records indicating fitness, pressure testing

at some time for the proposed rerating and approval by the API Inspector are required. The rerating is only

complete when the Inspector has overseen the attachment of an additional nameplate with the required

information given in this section.


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API 510 Module

CORROSION RATES AND INSPECTION INTERVAL

Examples

Metal loss equals the previous thickness minus the present thickness.

Problem #1

Determine the metal loss for a tower shell course which measured .600" in during its last internalinspection in March of 1989. The present reading is .570" March 1993.

Metal loss = Previous thickness minus the present thickness .600" Previous

-.570" Present

.030"

Corrosion rate equals the metal loss per given unit of time, i.e., per year.

Problem #2

Using the data of Problem #1 calculate the corrosion rate of the tower.

Time

LossMetal=RateCorrosion

Therefore: March 1993-March 1989 = 4 years

yearin./per.0075Yrs.4

".030=RateCorrosion

Corrosion allowance equals the actual thickness minus the required thickness.

Problem #3

The tower shell course in Problem #1 has a minimum thickness required by Code of .500 in. Calculate the

corrosion allowance. The actual thickness is .570 in. as of March 1993.

.570" in actual thickness

-.500" required thickness

.070" corrosion allowance

Remaining service life equals the corrosion allowance divided by the corrosion rate.

Problem #4

Calculate the remaining service life of the tower of problem #1.

.070" corrosion allowance from Problem #3

.0075" corrosion rate from Problem #2

Yrs.9.33="0075.

"070.

Internal inspection equals half of the remaining service life, but not greater than ten (10) years.

Yrs.4.6=2

Yrs.33.9


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API 510 Module

SECTIONS 1, 2, AND 3

Find the answers to these questions by using the stated API 510 paragraph at the end of the question.

Quiz #1

1. What code covers maintenance inspection of petrochemical industry vessels?(1.1)

2. Define MAWP according to the API 510 Code.(3.9)

3. Define rerating.(3.17)

4. Which pressure vessels are exempt from API 510? (1.2.2)

5. Under what circumstances must an API 510 inspector re-certify?

(App. B Paragraph B.5)

6. In terms of creep, what must be considered? (5.2)

7. What is the most valuable method of vessel inspection? (5.5)

8. Describe the correct way to clean a vessel for inspection. (5.5)

9. What metals might be subject to brittle fracture even at ambient temperatures? (5.2)

10. Name five methods other than visual that might be used to inspect a vessel.(5.5)

11. When a new Code vessel is installed, must a first internal inspection be performed? (6.1)

12. A vessel was last inspected internally in July of 1983. During that inspection it was determined to have

a remaining life of 16 years. What is the latest date of the next internal inspection? (6.4)


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API 510 Module

RP 576 INSPECTION OF PRESSURE RELIEVING DEVICES

Overview

Scope:

This recommended practice covers automatic pressure relieving devices commonly used in the

petrochemical and oil refining industries. The recommendations found in RP 576 are not intended to

replace and regulations that may exist in a jurisdiction.

Types of Pressure Relief Valves:

The three major types of pressure relief valves are the safety valve, relief valve and the safety relief valve.

Pressure relief valves are classed based on their construction, operation and applications.

Safety Valves

A safety valve is a spring-loaded device containing a seat and disk arrangement. It also has a part just

above the disk referred to as a huddling chamber. When the static pressure beneath the disk has risen to a

point where the force exerted on the disk begins to overcome the springs downward force the disk slowly

opens. As this happens the pressure beneath the disk is exposed to the huddling chamber. The huddling

chamber adds a much greater area exposed to pressure than the disk alone. This results in a sudden rapid

opening to the venting systems releasing the pressure to safe point at which time the valve will close.

Safety valves have an open spring and usually have a lifting lever.

Safety valves are used for steam boiler drums and superheaters. They may also be used for general air and

steam services. The discharge piping may contain vented drip pan elbow or a short piping stack vented to

the atmosphere.

Safety valves are not fit for service in corrosive service, where vent-piping runs are long, in any back

pressure service or any service where loss of the fluid cannot be tolerated. They should not be used as a

pressure control or bypass valve and are not suited for liquid service.

Relief Valve

A relief valve is a spring-loaded device that is intended for liquid service. This type of valve begins

opening when the pressure beneath its seat and disk reaches the set pressure of the valve. The valve

continues to open as the liquid pressure increases until it is fully open. The relief valve closes at a pressure

lower than its set pressure for opening. Relief valves capacities are rated for an overpressure from 10% to

25% depending on their use. For instance a relief valve set at 100 psi might allow the system it is

protecting to rise to an ultimate pressure of between 110 psi to 125 psi. This should be considered when

choosing the relief valve set pressure. These types of valves have closed bonnets and may or may not have

lifting levers.

Relief valves are normally used for incompressible fluids. Relief valves are not intended for use with

steam, air, gas or vapor service. They should not be used in services piped to a closed header unless the

effects of any constant or variable back pressure have been accounted for. They are also not fit for use as a

pressure control or bypass valve.

Safety Relief Valves

A safety relief valve is a direct spring-loaded pressure relief valve that may be used as either safety or relief

valve depending on the application. A safety relief valve is normally full open at 10% over pressure when

in gas or vapor service. When installed in liquid service, full lift will be achieved at approximately 10% or

25% overpressure, depending on trim type.


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Conventional Safety Relief Valve

A conventional SRV is a direct spring loaded pressure relief valve whose operational characteristics

( opening pressure, closing pressure , and relieving capacity) are directly affected by changes in the back

pressure. A conventional has a bonnet that encloses the spring and forms a pressure-tight cavity. The

bonnet is cavity is vented to the discharge side of the valve.

Conventional SRVs should not be used in services where any built up back pressure exceeds the allowable

overpressure. Where the CDTP cannot be reduced to account for the effects of variable back pressure. On

ASME Section I steam boilers drums or ASME Section I superheaters. They should also not be used aspressure control or bypass valves.

Balanced Safety Relief Valves

A balanced SRV is a direct spring-loaded pressure relief valve that incorporates a bellows or other means

for minimizing the effect of back pressure on the operating characteristics of the valve. Whether it is

pressure tight on its downstream depends on its design.

Balanced SRVs are used in flammable, hot and/or toxic services where high back pressures are present at

the valve discharge. Balanced SRVs are found in service for gas, vapor, steam, air or liquids. Balanced

SRVs are also utilized in corrosive service to isolate and protect the spring, bonnet cavity and discharge

side of the valve from process material. They are also used when the discharge must be piped to remote

locations. They should not be used on ASME Section I steam boiler drums or superheaters or as pressure

control/bypass valves.

Pilot-Operated Safety Relief Valves

A pilot operated safety relief valve (POSRV) is a pressure relief valve whose main relieving valve is

controlled by a small spring loaded (self-actuated) pressure relief valve (pilot valve). It is a control for the

larger valve and may be mounted with the main valve or remote from the main valve. The ASME Code

requires that the main valve be capable of operating at the set pressure and capacity even if the smaller

fails.

Pilot operated relief valves are used under conditions where any of the following are true; a large relief

valve is required, low differential exists between the normal operating pressure and the set pressure of the

valve, very short blown down (time between opening and closing) is required, back pressures on the outlet

of the valve are very high, process service where their use is economical, process conditions require

sensing at a remote location.

POSRVs are not suited for service with dirty, viscous (thick) fluids or fluids that might polymerize

(harden) in the valve. Any of these conditions might plug the small openings of the pilot system. If the

operating temperatures might exceed the safe limit of the diaphragms or seals or if the operating fluids

might chemically attack these soft parts of the valve.

Pressure and/or Vacuum Vent Valves

A pressure and/or vacuum vent valve (also known as a pressure and/or vacuum relief valve) is an

automatic pressure or vacuum-relieving device actuated by pressure or vacuum in the protected equipment.

These valves fall into three basic categories, weight loaded pallet vent, pilot operated vent valve, and

spring weight loaded vent valve.

Pressure and/or vacuum vent valves are normally used to protect atmospheric and low-pressure storage

tanks against large enough pressure to damage the tank. Single units composed of both pressure vent

valves and vacuum vent valves are also known as conservation vent valves, and are normally used on

atmospheric storage tanks containing materials with a flash point below 100 o F. However, they may also

be used on tanks storing heavier oils. They are not normally used in applications requiring a set pressure

greater than 15 lbf/in2.


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Rupture Disk Device

The combination of a rupture disk holder and rupture disk is known as a rupture disk device. A rupture

disk device is a non re-closing pressure relief device actuated by the static pressure differential pressure

between the inlet and outlet of the device and designed to function by the bursting of a rupture disk.

Rupture disks fall into the following basic design categories, Conventional (uses a pre-bulged solid metal

disk designed to rupture when over pressured on its concave side), Scored Tension-Loaded (designed to

open along pre-scored lines), Composite Rupture Disk ( is flat or domed metallic or nonmetallic multi-

piece construction) Reverse-Acting (opposite of the conventional as it is designed to rupture on its convexside) and last the Graphite Rupture Disk (manufactured from graphite impregnated with a binder material

and designed to burst by bending or shearing).

Rupture disks devices are used to;

Protect the upstream side of pressure relief valves against corrosion. Protect RVs from plugging or clogging by thick fluids or polymerization products. Instead of RVs when the protected system can tolerate process interruptions. In place of RVs when extremely fast response is required. As a secondary pressure-relieving device when differential pressure between the operating pressure

and the rupture pressure is large, depending on the type of rupture disk selected.

To protect the downstream sides of pressure relief valves against downstream corrosion from headeror atmospheric corrosion.Rupture disk devices are limited to;

Use where pre-bulged disks are placed in systems that operate at 65 to 85% of the diskspredetermined rupture pressure, depending on the type of rupture disk.

Where the usual service life of one year for a pre-bulged can be tolerated.This has been a brief summary of pressure relieving devices.


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API 510 Module

RP 576 SECTIONS 1 AND 2

Find the answers to these questions by using the stated API 510/576 paragraphs at the end of the question.

Quiz #2

1. How often should a safety relief valve be tested? (API 510 6.6)

2. Welding is used to repair a vessel made of P No. 1 material one inch thick. The vessel was originally

postweld heat-treated. Describe the method used to avoid PWHT of the repair? (API 510 7.2.3.1)

3. What does the term Accumulation mean when referring to pressure relief devices? (RP 576 3.3.1)

4. Describe the types of pressure relief valves. (RP 576 4.1 to 4.8 and Section VIII UG-126)

5. You notice that a pressure relief device has a closed bonnet without a vent hole. What type of valve is

it? (RP 576 4.3)

6. While reviewing maintenance records you notice that bulged rupture disks in a unit are three years old.

Is this O.K.? (RP 576 4.9.3)

7. A pilot-operated safety valve has been installed in heavy crude service is this O.K. (RP 576 4.7.2)


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API 510 Module

RP 576 SECTIONS 3, 4, 5, 6, 7, and 8


Quiz #3

1. Describe a shop inspection of a relief device. (6.2)

2. Name three causes of improper performance of a pressure-relieving device. (RP 576 5.1 to 5.10)

3. The spring of a relief valve broke. What probably caused it to break? (RP 576 5.3)

4. The valve shop is setting safety relief valves using water is this acceptable? (RP 576 5.4)

5. You are asked to set a schedule for the inspection of relief devices; what will determine the time

between the setting of valves? (RP 576 6.4)

6. What should the operating history of a pressure relief device include? (RP 576 7.2)

7. You are asked to visually inspect an RV before it is taken to the shop. What should this inspection

cover? (6.2.9)

8. What are the applications of a pressure/vacuum vent valve on an atmospheric tank? (4.8.1)


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API 510 Module

API RP 572 INSPECTION OF PRESSURE VESSELS

Overview

Section 1

General

Scope:

This recommended practice addresses the following items; description of types of vessels, construction,

maintenance, reason for and method of inspection, causes of deterioration, repair methods and

records/reports.

Section 2

Types of Pressure Vessels

The definition of a pressure vessel per API 572 is a container that falls within the scope of the ASME Code

Section VIII Division 1 and is subjected to an external or internal design pressure greater than 15 psi.

Section VIII Division 1 should be consulted for the exact definition and exemptions. The definition of a

pressure vessel is found in the ASME Code Section VIII Division 1, page 1 in the first paragraph.

Pressure vessels can have many different shapes, they may be spheres (balls), a cylinder with various heads

attached such as flat or hemispherical and may consist of inner and outer shells (jacketed). Many methods

of construction are used. The most common is the cylindrical shell made of rolled plate and welded with

heads that are attached by welding. Riveting was used prior to the development of welding. Vessels are no

longer made using riveting, but some riveted vessels are still in service today. Vessels are also made of the

hot forging and multi-layer (cylinders inside of cylinders) techniques. Multi-layer vessels are found

primarily in high pressure service.

The vast majority of vessels are made of carbon steels. For special services the carbon steel may be lined,

clad or weld metal surfaced with corrosion resistant materials such as stainless steels. Some vessels are

constructed entirely of various metals such as monel, nickel, titanium, or stainless steel. The material

chosen will be determined by the required service conditions. Temperature, pressure and the fluids to be

contained are the primary concerns in material selection. For reasons of economy different parts of a vessel

may be made of different materials using only the most expensive where needed. Many pressure vessels

are simply containers and do not have internal equipment; others have internals such as catalyst bed

supports, trays, baffles, or pipe coils.

Section 3

Construction Standards

The first unfired pressure vessels were constructed to the design of the user or manufacturer. This was true

until about 1930 after that time the API/ASME Code or the American Society of Mechanical Engineers

Code (ASME) was used. In 1956 the API/ASME Code was discontinued and the ASME Code was

adopted as the standard for the construction pressure vessels within its scope. Section VIII Divisions 1 and

2 of the ASME Code are the unfired pressure vessel Codes. Section VIII Division 1 is the Code the vast

majority of vessels are built to; Section VIII Division 2 used for vessels in high-pressure service or where

lower factors of safety is desired. Division 2 has more restrictions on construction, materials, inspection

and nondestructive examination than Division 1. These restrictions usually result in a vessel that would be

thinner than that required by Division 1 and the resulting cost savings could be significant is some

instances. Heat exchangers are built using both the ASME Code and the Standards of Tubular Exchanger

Manufacturers Association (TEMA).


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Section 4

Maintenance Inspection

The basic rule for the maintenance of a vessel in service is to maintain it to the original design and the

edition of the Code it was constructed under. If the vessel is re-rated this is may done using the original or

latest edition of the Code. This implies that persons responsible should be familiar with the original

construction edition of the Code and the latest edition of the Code if a vessel has been re-rated. In addition

personnel responsible for these vessels must be familiar with any national, state, county or city regulations.

The ASME has minimum requirements for construction, inspection and testing of pressure vessels that willbe stamped with the Code Symbol however jurisdictions may have more restrictive requirements.

Compliance with ASME Code may not be enough to satisfy a jurisdiction's requirement.

Section 5

Reasons for Inspection

The main reason for inspection is to determine the physical condition of a vessel. With this information the

causes and rate of deterioration can be established and safe operations between shutdowns can be

determined. Correcting conditions causing deterioration and planning for repairs and replacement of

equipment can also be done using the inspection information. Scheduled shutdowns and internal

inspections can prevent emergency shutdowns and vessel failures. Periodic inspection allows the for the

forming of a well-planned maintenance program by using data such as corrosion rates to determine

replacement and repair needs. External visual inspections along with the thorough use of various

nondestructive examination techniques can reveal leaks, cracks, local thinning and unusual conditions.

Section 6

Causes of Deterioration

The causes of deterioration are many but fall into several general categories as follows: inorganic and

organic compounds, steam or contaminated water, atmospheric corrosion. These types of corrosive agents

fall into the class of chemical and electrochemical attack. Attack is also possible from erosion and, or

impingement. The attack could come from any combination of the above examples.

Corrosion is the prime cause of wear in pressure vessels. The most common internal corrodents are sulfur

and chloride compounds. Caustic, inorganic acids, organic acids and low pH water can also cause

corrosive attack in vessels.

Erosion is the wearing away of a surface that is being hit by solid particles or drops of liquid. It is similar

to sandblasting and is usually found where changes in direction or high-speed flow are present. It occurs in

such places as inlet nozzles and the vessel wall opposite the nozzle. Outlet nozzles are likely spots when

fast flowing products are in use. In some instances corrosion and erosion are foundtogether.

Metallurgical and physical changes can occur when a vessel material is exposed to fluids the vessel

contains. Elevated operating temperatures also contribute to these problems. The changes that take place

may be severe enough to result in cracking, graphitization, hydrogen attack, carbide precipitation,

intergranular corrosion, embrittlement and other changes.

Mechanicalforces such as thermal shock, cyclic temperature changes (higher to lower temperatures on a

frequent basis), vibrations, pressure surges, and external loads can cause sudden failures. Cracks, bulges

and torn internal components are often a result of mechanical forces.

Faulty materials can build in failure into a pressure vessel or one of its components. Bad materials can

result in leakage, blockage, cracks and even speed up corrosion in some cases. The selection of an

improper material for new construction of or for a repair to a vessel will often result in the same type of

failures as will proper materials that have manufacturing or fabrication defects.

Faulty fabrication includes poor welding, improper or lack of heat treatment, tolerances outside those

permitted by Codes and improper installation of internal equipment such as trays and the like. Any of these


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types of faulty fabrications may result in failures due to cracks or high stress concentrations, etc., in

vessels.


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Section 7

Frequency and Time of Inspection

Many things determine the frequency of inspection for pressure vessels. Chief among the reasons is

corrosion rates that are determined by the service environment. Unless there are insurance or legal reasons,

the frequency of inspection should be based on information from the first inspection performed, using

either on stream or internal methods. Normally inspection planning will allow for the next inspection to

occur when at least half the original corrosion allowance remains. Other factors such as a need for frequent

cleaning may provide an opportunity to shorten the inspection frequency. If the process fluids or operatingconditions change, shorter inspection frequencies may be needed to determine what effects the new

conditions may have had.

Opportunities for inspections will require the input of all groups involved; process, mechanical, and

inspection personnel. The opportunity may have to be made if any laws require a frequency or the

insurance company has a requirement for it in the policy written on the equipment. A convenient time for

inspections, of course, is any time equipment is removed from service for cleaning. Also if a vessel or

exchanger was removed for operational reasons, an inspection might then become needed to insure the

integrity of the equipment before returning it to service.

Another consideration for the inspection of vessels is the review of the in service operational records to

look for pressure drops and out of the ordinary conditions that might indicate a problem.

Section 8

Methods of Inspection and Limits

To perform a proper inspection it is important to know the history of the vessels to be inspected. Knowing

what repairs have been required in the past and inspecting the repair after it has been in service may help to

develop better repair methods. It may also help to locate similar problems. In every case, careful visual

inspection is a requirement. Knowing the service conditions of a vessel allows the concentration of efforts

in areas known to have problems in a particular service.

Safety precautions before entering a vessel are of the utmost importance. Vessels have small openings and

often many internal obstructions that make getting out of one quickly nearly impossible. The bottom line

is: make sure it is safe to enter a vessel. Such things as isolation of lines by blinding, purging and cleaning

along with gas testing prior to entry cannot be overlooked. In some cases protective clothing and air

supply systems are called for if entry is desired before cleaning to look at the vessel's existing conditions

for indications of problems. Always inform personnel inside and outside a vessel that inspection personnel

are entering the vessel. Loud noises made by inspection or maintenance might scare others, causing

injury.Preparatory work needed for vessel inspection should include checking in advance to make sure all

equipment is present and is in usable condition.

External inspections should start with ladders, stairways, platforms and walkways connected to the vessel.

Loose nuts, broken parts and corroded materials may be searched for by visual inspection and hammer

testing for tightness. Since corrosion is most likely to occur where water can collect, these areas should be

inspected carefully, using a pick or similar object. Slipping hazards such as slick treads should be looked

for and noted on the inspection report. Foundations and supports must be inspected for the condition of the

fireproofing. The settling of foundations, Spalling (flaking) and cracking of the fireproofing are always a

concern. In cases where equipment is supported by cradles, moisture between the cradle support and the

vessel may cause corrosion. If the area where a vessel and a cradle join has been sealed with a mastic

compound, the mastic seal should be checked gently with a pick to check its water tightness. Some settling

of any foundation is to be expected. However, if the settling is noticeable, the extent must be determined

for future reference.

Anchor bolts can be examined by scraping away and looking for corrosion. The soundness can be

determined with blow of a hammer to the side of the bolt or its nut. Checking the nuts for tightness and the

bolts with ultrasonics for breaks is sometimes appropriate. Any distortion of the bolts may indicate serious

foundation settlement.


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Concrete supports are inspected with same concerns as concrete foundations. Close attention to any seals

and the possibility of trapping moisture because of faulty seals should be investigated.

Steelsupports should be examined for corrosion, distortion, and cracking. If corrosion is severe, actual

measurements of the remaining thickness should be performed and a corrosion rate established just as in a

vessel. Wire brushing, picking and tapping with a hammer is a frequently used inspection technique. Most

of the time corrosion can be slowed or prevented by proper painting alone. Sometimes protective barriers

such as galvanizing are required. As part of steel support inspection, vessel lugs should be examined using

the same methods of wire brushing, etc., described above. Welds used to attach lugs can develop cracks

and some cracks can then run into the vessel's walls. If a vessel's steel supports are insulated and anindication of leakage is present, the insulation must be removed to determine if corrosion under insulation

has occurred.

Guy wires are cables that stretch from different points of a vessel to the ground where they are anchored to

underground concrete piers (dead men). Inspection of these guy wires must include checking the

connections for tightness and the cables for the correct tensions. The connections consist of turnbuckles

used for tightening and U bolt clips for securing. All connectors must be checked for proper installation

and the presence of corrosion. The cable must be checked for corrosion and for broken strands.

Nozzles and adjacent areas are subject to distortion if the vessel foundation has moved due to settling.

Excessive thermal expansion, internal explosions, earthquakes, and fires can cause damage to piping

connections. Flange faces should be checked for squareness to reveal any distortion. If evidence of

distortion is found cracks should be inspected for, using non-destructive examination. All inspections

should be external and internal whenever possible. Visible gasket seating surfaces must be inspected for

distortion and cuts in the metal seating surfaces. Wall thickness readings must also be taken on nozzles and

internal or external corrosion monitored.

Grounding connections must be inspected for proper electrical contact. The cable connections should be

tight and properly connected to the equipment and the grounding system. All grounding systems should be

checked for continuity (no breaks) and resistance to electrical flow. Continuity checks are usually made

using electrical test equipment such as an Ohm meter. The resistance readings are recommended to be

between 5 and 25 Ohms.

Auxiliary equipment such as gauge connections, sight glasses, and safety valves may be visually inspected

while the vessel is still in service. Inspection while a vessel is in service allows the presence of excessive

vibrations to be detected and noted. If excessive vibrations exist, engineering can determine if any

additional measures are required to prevent fatigue failures.

Protective coatings and insulation should be inspected for their condition. Rust spots or blistering are

common problems associated with paint and are easily found by visual inspection. Scraping away a loose

coating film will often reveal corrosion pits. These pits should be measured for depth and appropriate

action taken. Insulation can usually be effectively visually inspected. If an area of insulation is suspected,

samples may cut out and examined for its condition. Insulation supporting clips, angles, bands, and wires

should be examined.

Externalsurface corrosion appears in forms other than rust. Caustic embrittlement, hydrogen blistering and

soil corrosion are also found on the external surfaces of equipment. The area of a vessel that needs special

attention often depends on its contents. When caustic is stored or used in a vessel, the areas around

connections for internal heaters should be checked for caustic embrittlement. In caustic service, deposits of

white salts often are indications of leaks through a crack. Hydrogen blistering is normally found on the

inside of vessels, but can appear on the outside if a void in the vessel's material is close to the outer surface.

Unless readily visible, leaks in a vessel are best detected by pressure testing. Cracks in vessel are normally

associated with welding and can be found using close visual inspection. In some services nondestructive

testing to checks for cracks is justified and should be performed. Other concerns when performing external

inspection are bulges, gouges, and blistering. Hot spots when found in service should be monitored and

thoroughly evaluated by an engineer experienced in pressure vessels.


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Internal inspections should be prepared for by assembling all necessary inspection equipment such as

tools, ladders, and lights.

Surface preparation will depend on the type of problems that a vessel may have in a given service.

Ordinarily the cleanliness required by operations is all that is needed for many inspections. If better

cleaning is required, the inspector can scrape or wire brush a small area. If serious conditions are

suspected, water washing and solvent cleaning may not be enough to reveal problems. In these instances,

power wire brushing, abrasive grit blasting, etc., may be required.

Preliminary visual inspection should be preceded by a review of reports of previous inspections.

Preliminary inspection usually involves seeking out known problem areas based on inspection experience

and service. Many vessels are subject to a specific type of attack such as cracking in areas such as upper

shell and heads. Preliminary inspection may reveal a need for additional cleaning for a proper detailed

inspection.

Detailed internalinspections should start at one end of a vessel and progress to the other end. A systematic

approach such as an item checklist will help to prevent overlooking hidden but important areas. All parts of

vessel should be inspected for corrosion, hydrogen blistering, deformation, and cracking. In areas where

metal loss is serious, detailed thickness readings should be taken and recorded. If only general metal loss is

present, one thickness reading on each head and shell may be enough. Larger vessels require more

measurements.

Pitting corrosion will require local examination by first scraping the surface and then and measuring the pit

depth. Pit gauges allow for measuring pit depth if an uncorroded area adjacent to the pit is available to

gauge from. In the case of large pits or grooves, a straight edge and steel rule often will allow measurement

by spanning the large area and lowering the steel rule into the pit and measuring the depth.

Hammer testing is often a good method of finding thin areas. Experience is needed to interpret the sounds

made by hammering. Usually a dull thud will indicate a loss of metal or thick deposits. Hammer testing

must never be used for inspecting vessels or components under pressure. If cracks are suspected or found

their extent may be determined by cleaning and nondestructive testing.

Welded seams deserve close attention when in services where amine, wet hydrogen sulfide, caustic,

ammonia, cyclic, high temperature and other services. Welds in high strength steel (above 70,000 psi

tensile) and coarse grain steels, and low chrome alloys should always be checked carefully for cracking.

All of the above conditions promote cracking in welds and adjacent base metals. Nozzles should be

checked for corrosion and their welds for cracking at the time of the vessels internal inspection. Normally

ultrasonic thickness readings will reveal any loss of metal in nozzles and other openings in a vessel.

Internal equipment such as trays and their supports are visually inspected accompanied by light tapping

with a hammer to expose thin areas or loose attachments. Conditions of trays must be determined to check

for excessive leakage caused by poor gasket surfaces or holes from corrosion. Excessive leakage can cause

operational problems and may lead to poor performance of a vessel or unscheduled shut downs.

Inspection of metallic linings must determine if the lining has been subjected to service corrosive attack,

that linings are properly installed, and that no cracks or holes are present in the lining. Most problems with

linings are found by careful visual inspections. Tapping the lining lightly with a hammer can reveal loose

lining or corrosion. Welds around nozzles deserve special attention due to cracks or holes that are often

found in these areas. If the surfaces of the lining are smooth, thickness measurements using ultrasonic

techniques may be performed. If required, small sections of lining can be cut out and measured for

thickness. A very useful method of tracking the corrosion rate of linings is by the welding of small tabs at

right angles to the lining when the lining is first installed. These tabs are made of the same material and

thickness as the lining and can be easily measured at the time of installation and at the next inspection to

determine the rate of corrosion taking place in the vessel. Remember that both sides of the tab are exposed

to the corrosion and the lining's loss must be determined by dividing the tab's loss by two. A bulge in a

liner can be caused by a leak in the liner permitting a pressure or a product build-up between the liner and

the protected base metal.


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Nonmetallic liners are made of many different materials such as glass, plastic, rubber, ceramic, concrete,

refractory, and carbon block or brick liners. The primary purpose when inspecting these types of linings is

to insure that no breaks in the lining are present. These breaks are referred to as holidays. Bulging,

breaking, and chipping are all signs that a break is present in the lining. The spark tester method if very

effective in finding breaks in such nonmetallic linings as plastic, rubber, glass, and paint. The device uses a

high voltage with a low current to find openings in linings. The electrical circuit is grounded to the shell

and the positive lead is attached to a brush. As the brush is swept over the lining, if a break is present,

electricity is conducted and an alarm is sounded. A little warning: this is obviously not a device to be used

in aflammable or explosive atmosphere nor should the device have such a high voltage value that it canpenetrate through a sound lining. The spark tester is not useful for brick, concrete, tile, or refractory

linings. Remember linings can be damaged during a careless inspection; often just by dropping a tool.

Concrete and refractory linings often spall (flake away) or crack. This damage is readily detected during a

visual inspection. Minor cracks may take some gentle scraping to find. If bulging is obvious cracks may

also be present. If any break is present, fluid has probably leaked in between the lining and the outer shell

and may have caused corrosion. Light tapping with a hammer can reveal looseness that is normally

associated with leakage of linings.

Thickness measuring techniques such as ultrasonics, limited radiographic techniques, corrosion buttons,

and the drilling of test holes; are used to determine if any wall loss has occurred. The most common

technique is ultrasonics. Ultrasonics can detect flaws and determine thickness also. Its principle of

operation involves the sending of sound waves into the material and measuring the time it takes the soundto return to the sending unit, referred to as a transducer. Sound travels through a given material at a known

speed, and when properly calibrated, the UT equipment uses the known speed and time of travel to

determine the thickness in the area being tested.

In thickness measurements using radiographs, the placement of a device such as step gage (a device of a

known material and thickness) in the radiographic image is compared to the image of the piping or vessel

wall and the thickness determined by measurement.

Corrosion buttons are made of a material that are not expected to corrode in a given service and then

installed in pairs at specific locations in the vessel. Measurements are taken by placing a straight edge

across the two buttons and then gauging the depth with a steel rule or some other measuring device. When

corroded surfaces are very rough, test holes through the vessel may be used to measure the wall thickness.

A variation on test holes isdepth drilling

. In this technique, small holes are drilled to a known depth (notall the way through) in the new vessel wall, then plugged with corrosion resistant plugs to protect the

bottom of the hole from corrosion. During internal inspections the plugs are removed and depth readings

are taken. Any wall loss that has occurred is detected by the hole depth becoming more shallow than the

original reading.

Metallurgical change tests can be made using many of the same techniques described in mechanical

changes. Additional tests include hardness chemical spot, and magnetic tests. Portable harness testers

such as the Brinell will detect poor heat treatment, carburization and other problems that involve a change

in hardness. Chemical tests to a small portion of a metal will reveal the type of metal to determine if the

wrong metal has been installed possibly during a pervious repair. Magnetic tests are used to determine if a

material such as austenetic stainless steel; normally not magnetic, have become carburized, which will

allow the austenetic stainless to become attracted to a magnet.

Testing

Hammer testing used during visual inspection will reveal conditions such as; thin sections, tightness of

bolts and rivets, cracks in linings, lack of bond in refractory and concrete linings. The hammer is also used

to remove scale for spot inspection. Hammer testing is an art learned from experience and caution is

warranted whenever using this method. It is not smart to hammer on anything under pressure and

hammering on some piping systems can dislodge scale or debris and plug up a portion of the system such

as a catalyst bed.


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Pressure and/or vacuum tests are performed when a vessel is first built and then applied after entering

service if any serious problem has been disclosed, which brings into question the integrity of the vessel.

After major repair work, a pressure test is normally required. Some jurisdictions and company's policies

require tests on a time basis even if no repair work has been done. These types of tests often involve

raising the internal pressure above normal operating pressure and the possibility of damage to the vessel

from the test exists. Pressure tests should applied carefully by qualified personnel using calibrated gages

with positive control of the test equipment. The object is to reveal any problems, not to create one. Most

of the time these tests use water or some other fluid (hydrostatic) permitted by the Codes. During

hydrostatic testing of a vessel, pressure drop, leaks and deformation (bulging) in the vessel may berevealed. If the vessel's supports can not hold the weight of the fluid or the vessel cannot tolerate

contamination by the testing fluid, a gas test (pneumatic) may be used. Pneumatic testing, by its nature,

can be more dangerous than hydrostatic testing. Caution is always advisable during a pneumatic test, and it

is normally the last choice.

Vacuum tests are conducted by creating a vacuum inside the vessel and observing the vacuum gage for any

loss of vacuum that might occur. If the vacuum remains unchanged the assumption is made that no leak

exists.

Testing temperature can be very important with some pressure vessel materials due to the brittle

characteristics of these metals at low temperatures. The ASME recommends that the test temperature be at

least 30o

F above the minimum design metal temperature to prevent the risk of brittle fracture. A brittlefracture can be compared to glass breaking and shattering. For that reason every effort must be made to

prevent it. In combination with a pneumatic test and its stored energy; a brittle failure would be a

devastating bomb. For all materials, the general recommendation for test temperature is 70 oF minimum

and 120 oF maximum. For safety when conducting a pressure test, no unnecessary personnel should be

allowed in the area until the test is complete. Pneumatic tests must follow a procedure described in the

ASME Code that raises the pressure in small steps with short stops at each step.

Pressure testing of exchangers can be performed when they are first shut down and before bundle removal

in order detect any leaks that might have been present during recent service. If leaks are detected during

the initial test, partial disassembly can be performed and the test pressure reapplied to locate the source of

the leaks. Heat exchangers may also be disassembled and cleaned, inspected, repaired if needed, then

reassembled and tested. If a leak is detected in the exchanger after re-assembly, disassembly will again berequired to repair the leak. The method of testing an exchanger will depend on its design. Some can be

tested with their channel covers removed if of the fixed tube sheet design with the pressure applied to the

shell side. If a tube in the bundle is discovered to be leaking at other than the tube sheet roll, it may be

plugged with a tapered plug, which effectively removes that tube from service. If the leak is located where

the tube is rolled (expanded) into the tube sheet, an attempt to re-roll the tube is usually made and the test

pressure reapplied. Often tube bundles are tested out of their shells if of the floating head design. Leaks

are easily detected, but this approach requires a separate shell test. During pressure tests leaks in shells,

tubes, gasketed areas, and distortion are looked for in the exchanger parts.

Limits of thickness must be determined prior to inspection and must be known in order to perform an

effective inspection. The retiring thickness and the rate of deterioration are needed to determine the

appropriate action should a problem be uncovered during an inspection. The importance of inspection

records becomes obvious when it is required to make a decision whether to repair, replace, or just tocontinue the operation of a vessel. If the retiring thickness is known prior to the inspection, a plan of

action in the event of excessive wall loss can be prearranged. Almost all vessels, when new, will contain

excess thicknesses above what are required by the Codes.


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Methods of repair to vessels should be reviewed to insure that they comply with any Codes or standards

that may apply. Several jurisdictions recognize the minimum repair techniques of the API. Other

jurisdictions require that the repairs be made to the National Board of Boiler and Pressure Vessel

Inspectors (NBBPVI), National Board Inspection Code-23 (NBIC) and that the repair concern holds a

valid R (Repair) Stamp from the NBBPVI. In addition to using a concern holding the R Stamp an NBBPVI

Repair form R-1 may also be required. In some instances, Insurance Carriers will require that the NBIC be

followed and that an NBIC Authorized Inspector in their employ approves the repair. Repairs made to

vessels by welding will require visual inspection as a minimum and may also involve various

nondestructive examinations (NDE) methods based on the severity of the repair and the original NDE usedin the construction Code. Unless the Inspector can accept a sound technical argument against requiring a

pressure test after a major repair, one should be applied. If the repair to a vessel involves cracks special

preparation of repair area is required. The major concern in crack repairs is the complete removal of the

crack. Cracks may be removed by chipping. flame, arc, or mechanical gouging. Any crack removal

technique that uses high heat input to the affected area can cause the crack to grow, so caution must be

used with those techniques. In cases where many cracks are present it is normally better to replace the

entire section of the material. Shallow cracks may be removed by grinding using a blending method if the

final thickness does not fall below the minimum required.

Inspection records and reports are important and are required by most Codes and jurisdictions such as the

State, API, and the NBBPVI NB-23. These reports are of three types: Basic Data, Field Notes, and

Continuous File. The basic data includes original manufacturer's drawings and data reports as well as

design information. Field notes are notes about and measurements of the equipment and may be written or

entered into a computer database. Usually field notes are in the form of rough records inspections and

repairs required. Continuous files include all information about a vessel's operating history, previous

inspection reports, corrosion rate tables (if any) and records of repairs and replacements. Copies of reports

containing the location, extent, and reasons for any repairs should be sent to all management groups such

as Engineering, Operations, and Maintenance departments.

Heat Exchangers are used to transfer heat from one gas or liquid to another gas or liquid without the two

fluids mixing. Heat exchangers fall into classes: condensers and coolers. A condenser has the effect of

changing a gas fluid to a liquid or partial liquid fluid and ordinarily uses water as the coolant. Coolers

lower the temperature of a fluid and may use water or another process fluid of a lower temperature as the

coolant. Sometimes air is used to lower the temperature of a fluid. The equipment is then referred to as an

air cooler.

Shell and Tube-Bundle exchangers are made in several types. The tubes are installed into a tube sheet by

rolling (expanding) them into the tube sheet holes. In heat exchangers, after rolling tubes, the ends are

sometimes welded to the tube sheet for sealing purposes. In some cases the tubes are inserted into the tube

sheet and packing rings are installed to seal the area around the tube ends. The method of construction used

is dependent on the service intended for the exchanger. There are four basic design types of shell and tube

heat exchangers. They are: One Fixed Tube Sheet with a Floating Head (the most common), Two Fixed

Tube Sheets, One Fixed Tube Sheet with U-Tubes, and Double Tube Sheet (used when even the slightest

leak cannot be allowed).

Reboilers and Evaporators perform the opposite function of the condenser or cooler. They do what their

names imply boil and evaporate. In general they use steam, or a hotter fluid from a process to boil or

evaporate another fluid. The Reboiler is normally used to boost heat back up to a desired level at some

intermediate step of a process stream.

Some Other types of heat exchangers include Exposed Bundle, Storage Tank Heaters, Pipe Coils (either

single or double pipe), Box-Type Heater Coils, and Plate-Type.

Inspection of Exchanger Bundles should start with the establishment of any general corrosion patterns.

Inspecting an exchanger bundle when it is first removed can reveal the type(s) and locations of corrosion

and deposits. Visual inspection techniques include light scraping and hammering testing with a light ball

peen hammer (4 to 8 oz) to locate corrosion and thinning. The inside of the tubes may be partially

inspected using borescopes, fiber optics, and specialized probes. Since only the outside of tubes in the

outer portion of a bundle can be seen, inner tubes must be inspected using NDE techniques.


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API 510 Module

API RP 572 SECTIONS 1, 2, 3, 4, 5, and 6


Quiz #4

1. Name three shapes of pressure vessels. (572 2.1)

2. Describe multi-layer construction of a pressure vessel. (572 2.2)

3. When carbon steel will not resist corrosive fluids, what method of construction is normally used for

such a vessel? (572 2.3)

4. Name four types of internals found in pressure vessels. (572 2.4)

5. Prior to 1930, what specifications were unfired pressure vessels built to in refineries? (572 3.0)

6. Why is it important to have access to previous editions of the ASME Codes? (572 4.0)

7. Name three types of information gained from the inspection of a pressure vessel. (572 5.1)

8. List the basic forms of deterioration. Name the effects these basic forms have. (572

6.1,6.2,6.3,6.4,6.5,6.6,and 6.7)

9. What is the most important factor in determining the inspection frequency of a pressure vessel? (572

7.1)

10. Why are occasional checks of operating pressures while equipment is in operation important? (572

7.2)


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API 510 Module

API RP 572 SECTIONS 8.1 to 8.4.4


Quiz #5

1. What should an inspector be aware of before starting the inspection of a pressure vessel? (572 8.1)

2. Careful visual is important to determine what other types of inspections might be required. Name threeother types of inspection. (572 8.1)

3. Before an inspection starts in a vessel, who else besides the safety man should be informed? (572 8.2.1)

4. Name five tools an inspector should have to perform an inspection. (572 8.2.2)

5. List at least six items that should be inspected on the external of a pressure vessel. (572

8.3.2,.3,.4,.5,.6,.7,.8,.9,.10,.11,.12,.13)

6. Abrasive grit blasting, power wire brushing etc., are usually required under what conditions? (572

8.4.2)

7. If a vessel has had previous internal inspections, what should be done prior to your inspection? (572

8.4.3)

8. Where will most of cracks found in a pressure vessel be found? (572 8.4.3)

9. Why is a systematic procedure important when inspecting a pressure vessel? (572 8.4.4)

10. Under what operating conditions should weld seams in a pressure vessel be given special attention?

(572 8.4.4)


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API 510 Module

API RP 572 SECTIONS 8.4.5 to 8.5.2


Quiz #6

1. When examining linings, name the three most important conditions to check. (572 8.4.5)

2. Describe the spark tester method of inspecting nonmetallic linings. (572 8.4.6)

3. How may loose nonmetallic linings be found using a hammer? (572 8.4.6)

4. Where a corroded surface is very rough, what may be done to measure thickness? (572 8.4.7)

5. How may cracks be made to stand out from the surrounding areas being inspected? (572 8.4.8)

6. Who should make the decision to trepan metal from a vessel for metallurgical evaluation? (572 8.4.8)

7. How may carburized austenetic stainless steel sometimes be detected? (572 8.4.9)

8. What functions may an inspector's hammer serve? (572 8.5.1)

9. When testing a vessel pneumatically what should be on hand to aid in the visual examination? (572

8.5.2)

10. If it is possible to use internal pressure to test a vacuum vessel, what advantage does that method

offer? (572 8.5.2)


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API 510 Module

API RP 572 SECTIONS 8.5.3 to 10.2


Quiz #7

1. Why is it desirable to leak test an exchanger before disassembly? (572 8.5.3)

2. If a given exchanger be

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