API 510 Study Material-1

API 510 Page 1 of 310

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. TEXT BOOK The Text book's 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 sit 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 to 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, some helpful suggestions are contained in the back of the Text book. These include such things as what paragraphs to tab within the ASME Code books, and cross over subjects from the API to the ASME Codes. At this writing the exam candidate is allowed to use the ASME Code books and the API books on the first portion of the test only. No reference material is allowed for the second half of the test! QUESTIONS AND ANSWERS BOOK The Questions and Answers are divided into two types. The first portion covers the ASME Codes, Sections VIII Div. 1 Unfired Pressure Vessels, Section IX Welding, and Section V Nondestructive Testing. These questions are typical of previous National Board Authorized Inspector exams. These should be used to obtain a feel for the nature of the ASME Code questions. They are not for memorization. The second 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 of Failures. These questions are for memorization if the examination will be taken!


API 510 Module

Table of Contents API CODES

API 510 Corrosion Rates and Inspection Intervals Scope 6

Inspection Interval 10

Records and Test 11

Metal loss including corrosion averaging 15

Corrosion rates 15

Remaining Corrosion Allowance 16

Remaining Service Life 16

API 576 Pressure Relieving Devices

Scope 19

Types of pressure relieving devices 19

Reasons for Inspection 22

Causes of Improper Performance 23

Frequency and Time of Inspection 23

API 572 Inspection of Pressure Vessels

Scope 26

Reasons for Inspection 27

Causes of Deterioration 28

Methods of Inspection 29

Records and Reports 36

IRE Chapter 11

Coverage from the API 510 Body of Knowledge 43


ASME Section VIII Div. 1

Joint Efficiencies UW-3 Weld Categories 48

UW-51 RT Examination of Welded Joints 58

UW-52 Spot Examination of Welded Joints 59

UW- 11 RT and UT Examinations 61

UW-12 Maximum Allowable Joint Efficiencies 69

Postweld Heat Treatment

UW-40 Procedures for Postweld Heat Treatment 93

UCS-56 Requirements for Postweld Heat Treatment 94

Vessels Under Internal Pressure

UG-27 Thickness of Shells Under Internal Pressure 96

UG-32 Formulas and Rules for Using Formed Heads 107

UG-34 Unstayed Flat Heads and Covers (Circular) 113

Cylinder Under External Pressure

UG-28 Thickness of Shells and Tubes (External Pressure) 120

Pressure Testing UG-20 Design Temperature 127

UG-22 Loadings 129

UG-25 Corrosion 130

UG-98 Maximum Allowable Working Pressure 131

UG-99 Hydrostatic Test Pressure and Procedure 132

UG-100 Pneumatic Test Pressure and Procedure 135

UG-102 Test Gages 138

Minimum Requirements for Attachment Welds at Openings UW-16 Weld Size Determination 140


Reinforcement for Openings in Shells and Heads UG-36 Openings in Vessels 146

UG-37 Reinforcement of Openings 147

UG-40 Limits of Reinforcement 147

UG-41 Requirements for Strength of Reinforcement 147

UG-42 Reinforcement of Multiple Openings 148

Minimum Design Metal Temperature and Exemptions from Impact Testing

UG-84 Charpy Impact Test Requirements 161

UCS-66 Materials 164

UCS-67 Impact Testing of Welding Procedures 164

UCS-68 Design 164

Practical Knowledge

UG-77 Material Identification 170

UG-93 Inspection of Materials 171

UG- 116 Name Plate Markings 172

UG-119 Name Plates 174

UG- 120 Data Reports 175

Section IX

Welding on Pressure Vessels (Section IX Overview)

Article I General Requirements 176

Article II Welding Procedure Qualifications 177

Article III Welding Performance Qualifications 179

Article IV Welding Data 181

Welding Documentation Review

Welding Procedure Specification (WPS) 182

Procedure Qualification Record (PQR) 186

Practice WPS/PQR reviews 189


Section V (NDE Subsection A) Article 2 Radiography 195

Article 5 Ultrasonics 198

Article 6 Liquid Penetrant 199

Article 7 Magnetic Particle 201

Article 9 Visual Inspection 202

Advanced Material Example Problems

Static Head of Water 204

Corrosion 217

Cylinders Under Internal Pressure 220

Heads Under Internal Pressure 222

Charpy Impact Test Evaluation WPS/PQR 226

Advanced Exercise Problems

Internal Pressure Shell Calculations 228

Internal Pressure Head Calculations 229

Solutions for Advanced Exercises 230

Appendix

Helpful information for the API Exam Listing of where to find answers to API questions in Section VIII ASME 236

Instructions for the proper tabbing of ASME Code books 237

Practice WPS and PQR forms 240

Solutions to Text Module Exercises 248


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 entered service. 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 given volumes and pressures. Section 6 Alternative Rules for Natural Resource Vessels. Glossary of Terms: 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, Maximum 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 2 Owner-User Inspection Organization

The main thing of interest in this section is the qualifications required for an API 510 inspector. Here the experience and educational requirements are listed in detail. Questions over this section have been on several Exams.


Section 3

Inspection Practices Preparatory Work: Often questions are asked about what must be done before entry into a vessel. 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 or 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.


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 and other 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 as 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 may 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. The sum of their dimensions along any straight line within 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 an engineer experienced 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.

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 area located 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) and KI is as given in Table 1.

Section 4

Inspection and Testing or Pressure Vessels and Pressure-Relieving Devices

General: Section 4 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 way 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. External Inspection: The frequency for the external inspection of above the ground vessels shall be every 5 years or at the quarter corrosion rate life whichever is less. This inspection should be performed when the vessel is in service if possible. Things to be checked shall include 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. 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 is greater than 10 years internal inspection of the vessel is unnecessary as long as the vessel remains in the same service, complete external inspections are formed and all of the following are true: The non-corrosive character of the contents have 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. The remaining life calculation formula is given in Section 4 and will be demonstrated in a latter example problem along with the other formulas required for pressure vessels in accordance with API 510. 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. If the test will be hydrostatic the test temperature should he above 70F, but not greater than 120F.

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 clamps (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. . Previous Exams have required naming 6 of these 1 5 items. 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.

Section 5 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 vessels 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.


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.. Qualifications 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. 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. The application must be reviewed by a qualified engineer. b. Suitability of this type of procedure is reviewed and consideration is given to such

things as base metal thickness, hardness, and thermal gradients.

c. A preheat of 300F 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 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. Design: The design of welded joints included in the API 510 are in compliance with those of the ASME 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 is 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. 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 Section 5.3. 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 Section 5.3.


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 internal inspection in March of 1989. The present reading is .570" March 1993. Metal loss = Previous thickness minus the present thickness. .600" Previous -.570" Present .030" Answer: Metal Loss = .030 inch 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. Corrosion Rate = Metal Loss

Time Therefore: March 1993-March 1989 = 4 years Corrosion Rate = .030 = 0.0075 in./per year 4 Yrs. 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. Calculate the corrosion allowance. The actual thickness is .570 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

.070 " = 9.33 Yrs. .0075 Internal inspection equals half of the remaining service life, but not greater than ten (10) years.

9.33 Yrs. = 4.6 Yrs. 2


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. 1) 2. Define MAWP according to the API 510 Code.(1.2.8) [1997 3.8] 3. Define rerating. (1.2.14) [1997 3.11] 4. What is a pressure vessel?(1.2.11) Sect VIII U-1(a) [1996 3.11] 5. Under what circumstances must an API 510 inspector be re-certified? (App. B Paragraph B. 6) [1996 B4.1 App. B] 6. In terms of creep, what must be considered? (3.2) [1996 5.2] 7. What is the most valuable method of vessel inspection? (3.5) [1997 5.5] 8. Describe the correct way to clean a vessel for inspection. (3.5) [1997 5.2] 9. What metals might be subject to brittle fracture even at room temperature? (3.2)[1997 5 2] 10. Name five methods other than visual that might be used to inspect a vessel.(3.5) 11. When a new Code vessel is installed, must a first internal inspection be performed?(4.1) 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? (4.3) [1997 6.3]

Answers on next page.


ANSWERS TO QUIZ #1 1. answer: API-510 2. answer: is the maximum gauge pressure permitted at the top of a pressure vessel in

its operating position for a designated temperature. 3. answer: A change in either temperature rating or maximum allowable pressure of a

vessel or both. 4. answer: A container designed to withstand internal or external pressure by an

exterior source by the application of heat direct or indirect or both.

5. answer: Inspector who has not been actively engaged in an API inspection within the previous 3 years. Re-certify by written examination.

6. answer: Time, Temperature & Stress. 7. answer: Careful visual examination 8. answer: wire brushing, blasting, chipping, grinding(or combination) 9. answer: At ambient temperature, carbon, low alloy, and other Ferritic Steels. 10. answer: 1. Magnetic Particle 2. Dye Penetrant 3. Radiography 4. Ultrasonic

Thickness measurement. 5. Metallographic Examination 6. Acoustic Emission Testing 7. Hammer Test.

11. answer: No as long as manufacture report(Data) assures that the vessel is satisfactory for the intended use is available.

12. answer: 1991


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. When this has occurred 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 unto 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 for variable back pressure service unless equipped with a balancing bellows or piston. They also not fit for use as a pressure control or bypass valve. As of 1986 the ASME Code requires that they be stamped with a certified capacity.


Safety Relief Valves A safety relief valve is a spring-loaded valve that is capable as functioning as a relief valve in liquid service or as safety valve in gas or vapor service. Safety relief valves may be of the conventional, balanced or pilot operated types.

Conventional SRV A conventional SRV has its spring housing vented to the discharge side. Its opening pressure, closing pressure and relieving capacity are directly affected by changes in back pressure. Conventional SRVs are used in flammable, hot and toxic services. Usually they are piped to safe remote points of discharge such as a flare stack. Conventional SRVs are found in service for gas, vapor, steam, air or liquids. Conventional SRVs are also used in corrosive service. Conventional SRVs may not be used in services where any backpressure is constant or where any built-up backpressure exceeds 10% of its set pressure. They are not to be used on steam boilers, superheaters or as pressure control or bypass valves.

Balanced Safety Relief Valves A balanced SRV has a pressure-balancing bellows, piston or both. This arrangement is provided to minimize the effect of any backpressure on the operation of the balanced SRV. Whether it is pressure tight downstream depends on its design. It may have a lifting lever as an option. Balanced SRVs are used in flammable, hot and toxic services. Usually they are piped to safe remote points of discharge such as a flare stack. Balanced SRVs are found in service for gas, vapor, steam, air or liquids. Balanced SRVs are also utilized in corrosive service. They are not to be used on steam boilers, superheaters or as pressure control or bypass valves. Because balanced-type valves have vented bonnets and the vent may need to piped to a safe point. In the event that a bellows fails in such a valve the fluid will be discharged to the bonnet and out its vent.

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. 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 Pressure and/or vacuum vent valves are used for the protection of storage tanks and are categorized into three kinds; weight loaded, pilot operated or spring and weight loaded. These valves protect against an excessive differential in the outside pressure (atmospheric) and the inside pressure or vacuum. If while drawing down (draining) a storage tank where to develop a vacuum the tank might be crushed by atmospheric pressure. In the case where internal pressure where to exceed design pressure the tank might bulge or rupture. In cases where the tank might operate alternating between pressure and vacuum a breather type valve is used, this valve will both vent gas pressure and break any vacuum, which might develop during operations of the storage tank.

Rupture Disks A rupture disk (RD) is a thin plate (usually in the shape of a bulge) that may be made of various metals or of combinations or metals in thin layers. RDs may also be made of plastic-metal combinations or coated metals. Non-metallic RDs are manufactured from impervious graphite (usually flat) and other non-metallic materials. The rupture disks are held between specially made flanges and designed to rupture at predetermined pressure and are of course not capable of reclosing. Most rupture disks are designed to have the inside of the bulge facing pressure although some are made to have the outside of the bulge facing pressure, these are called reverse buckling RDs They may be used to protect against excessive internal pressure. If the service involves a vacuum, the rupture disk normally will use a vacuum support. A rupture disk in this service is designed to protect against an excessive internal pressure should it occur due to a failure of the system. Each type of RD has special considerations based on its design. A RD can be used alone or in combination with a pressure relief valve. Normal uses of RDs include all of the following; protections for the upstream side of PRVs against corrosion, protect RVs against plugging or clogging, in place of PRVs if nonreclosing is permitted, as additional backup over pressure protection, in outlets of vent piping to protect the PRV from corrosion and to minimize leakage of a PRV. Special handling for, storage, applications and the installation of RDs is required and the manufacturer's recommendations directions should be followed. A special consideration in the ASME Code is the relieving capacity rating of the safety relief valve if the RD is installed between the SRV and the vessel. For bulged metal rupture disks with the pressure exposed to the inside of the bulge and for flat RDs the operating pressure is usually limited to a range of from 65% to 85% or the design rupture pressure. The percentage used depends on the type of pressure service the rupture disk is in. The lower 65% is normally used when the service involves pulsating pressure or wide swings in pressure. The reasons for these limits include creep of the rupture disk material that can result in sudden rupture at normal operating pressures. This can occur rapidly if operating temperatures are high. For these and other reasons the service life of a RD is about one year. They are easily damaged by the handling involved in their removal and are best replaced during any maintenance activities.


Variations with Resilient Valve Seats When tighter sealing of PRVs is desired the valves are manufactured with 0 rings in the seating parts. The valves are similar to PRVs with metal to metal seating only but with soft parts to increase the seal tightness against leaking. The applications for these types of valves are numerous but fall into the following categories; corrosive service, toxic/flammable/expensive products, operating pressure very close to the set pressure, in vibrating minor pressure surges, hard foreign particles in fluid and in pulsating pressure or vibrating service. Care should taken when choosing the material that the soft parts, such as O-Rings, are made from. They must resist the chemicals and pressures they are exposed to in the intended service. Comparable service should serve as a guide when choosing materials, failing this information the valve manufacturers can be consulted.

Reasons for Inspections If a pressure relief valve fails to open overpressure could occur and cause serious damage and even loss of life. Protection of personnel and equipment may finally depend on the proper functioning of the safety relief device. For these reasons the general condition of the devices and the frequency of inspection must be established.

Causes of Improper Performance The primary causes of failure or improper performance fall into categories as listed in RP 576. They can be classified as follows; corrosion, damaged seating surfaces, failed springs, improper setting/adjustment, plugging/sticking, wrong materials for the service, installation in the wrong service or location. Rough handling during service and shipping or installation. Improper hydrostatic tests of discharge piping can cause damage to springs or to bellows of balanced relief valves.

Frequency and Time of Inspection Definite time intervals are required for the inspection, testing and repair of relief devices. Some services require more frequent inspection than others but the basic frequency must be based on safety not economics. API 510 establishes the maximum frequency to be 10 years but actual service may require a shorter interval between inspections. The ideal time for inspection is during a scheduled shut down of operations.


API 510 Module RP 576 SECTIONS 1 AND 2 Find the answers to these questions by using the stated API 576 paragraph at the end of the question. Quiz #2 1. How often should a safety relief valve be tested"? (4.5) 2. A vessel made of P-1 material one inch thick is being repaired by welding. The vessel was originally postweld heat-treated. Is there any method to avoid PWMT of the repair? (5.2.3) 3. Why are relief devices installed on pressure vessels? (RP 576 21.) 4. How many types of pressure relief valves are there? (RP 576 2.2.1.1 Section VIII UG-126) 5. You notice that a pressure relief device has a closed bonnet. What type of valve is it? (2.2.1.3.1) 6. While reviewing maintenance records you notice that bulged rupture disks in a unit are three years old. Is this okay? (2.2.3.3) 7. A pilot operated safety valve has been installed in heavy crude service. Is this okay? (2.2.1.5.3) 1. During s/ds or 10 years. (5.1.1) 2. yes 3. to protect personnel and plant equipment. 4. safety valve, relief valve, safety relief valve, pilot operated safety relief valve. 5. relief valve. 6. no 1 year 7. no


API 510 Module RP 576 SECTIONS 3, 4, 5, 6, 7, and 8 Find the answers to these questions by using the stated API 576 paragraph at the end of the question. Quiz #3 1. Describe a shop inspection of a relief device. (3.2) 2. Name three causes of improper performance of a pressure relieving device. (Titles of

Section 4 paragraphs) 3. The spring of a relief valve broke. What probably caused it to break? (4.3) 4. The valve shop is setting safety relief valves using water is this acceptable? (4.4) 5. You are ask to set a schedule for the inspection of relief devices; what will determine the time between the setting of valves? (5.1.1 the max. is 10 years per API 510) 6. You notice workers opening RV. discharge lines to the atmosphere. What precautions

should be taken? (6.1.1) 7. What should the operating history of a pressure valve include? (6.1.3) 8. You are asked to visually inspect an RV before it is taken to the shop. What is the

purpose of this and why is it important? (7.1.1) 9. What is the purpose of a pressure/vacuum vent valve on an atmospheric tank? (7.3.2) 10. Why are records kept for pressure relieving devices? (8.1) Answers Quiz#3 1. Check pop pressures, extend check for external conditions, and conform to specifications. 2. Corrosion, damage seat surfaces, and improper length of piping? (4.2) 3. Surface corrosion, stress corrosion. 4. No. 5. Performance of the devices in the particular service. 6. Precautions should be taken to prevent the release of hydrocarbons, hydrogen sulfide

7.(H2S), or other hazardous materials in the systems and to prevent the ignition of iron sulfides in the piping.

8. Average operation conditions, the number and severity of upsets and their effect on the valve, the extent of any leakage while in service and other evidence of malfunctioning.

9. To hole the deposits of corrosion the corrosion products and its importance because they may be loose and drop out during transportation & shop fabrication.

10. To vent air and vapor in tanks when filling and to admit air when air drawn down.


API 510 Module API RP 572 INSPECTION OF PRE SSURE 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), cylinders 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 by 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 VII Divisions 1 and 2 of the ASME Code are the unfired pressure vessel Codes. Section VII Division 1 is the Code the vast majority of vessels are built to; Section VII Division 2 used for vessels in high pressure service or where lower factors of safety are 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).

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 nations state, county or city regulations. The ASME has minimum requirements for construction, inspection and testing of pressure vessels that will be 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 is 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 found together. 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, intergrannular corrosion, embrittlement and other changes. Mechanical forces such as thermal shock, cyclic temperature changes (high to low temps 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. 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 types of faulty fabrications may result in failures due to cracks or high stress concentrations, etc., in vessels.

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 n 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 operating conditions 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 must 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 scaled 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.


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. Steel supports should be examined for corrosion, distortior4 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 frequently used inspection techniques. 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 an indication 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 (deadmen). 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. An 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. lie resistance readings are recommended to be between 5 and 25 Ohms. Auxiliary equipment such as gauge corrections, sight glasses, and safety valves may be visually inspected while the vessel is still in service. Inspection while a vessel is 'm service allows the presence of excessive vibrations to be detected and noted. If excessive vibrations exist, engineering (;an 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 be cut out and examined for its condition. Insulation supporting clips, angles, bands, and wires should be examined.


External surface corrosion appears in forms other than rust. Caustic embrittlement, hydrogen blistering and soil corrosion are also found on the external surfaces of equipment. Area of a vessel that need 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 though cracks. Hydrogen blistering is normally found on the inside of vessels, but can appear on the outside if a void in the vessels material is close to the outer surface. Unless readily visible, leaks in a vessel are best detected by pressure testing. Cracks in vessels are normally associated with welding and can he found using close visual inspection. In some services nondestructive tests to check 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. 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 internal inspections should start at one end of a vessel and progress to the other end. A systematic approach such as an item check list 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 tip between the liner and the protected base metal. 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 a flammable or explosive atmosphere nor should the device have such a high voltage value that it can penetrate 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 thicknesses also. Its principle of operation involves the sending of sound waves into the material and measuring the time it takes the sound to 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 is depth drilling. In this technique, small holes are drilled to a known depth (not all 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. Special methods of detecting mechanical changes include nondestructive techniques, acid etching small areas to find cracks, and sample removal. Acid etching requires abrasive cleaning and the application of an appropriate (for the metal) chemical usually acid. The etching approach allows fine cracks to stand out in contrast to the base metal. Sample involves the removal by mechanical cutting out a small portion of the area of interest and then analyzing it under a microscope. Often the filings created during the removal can be cleaned and then subjected to a chemical analysis. A weld repair to the site of sample removal will be required and should be made as carefully as any welded repair. 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. Pressure and/or vacuum tests are per-formed 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 be revealed. 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 of types. The reason for this is that gas that has been compressed has a great deal of stored energy, and if failure occurs, it will likely be explosive. Have you ever blown out a car tire? During a pneumatic test, a soap solution is often applied to weld seams and fittings and then, looking for bubbles, leaks can be revealed. Another method, sound detection, uses special listening devices to bear and locate the leaks. Another sound based device is Acoustic Emissions. As a vessel is pressurized, it emits sounds from any flaws present in the metal. By using several listening devices attached to different parts of the vessel, the location of a serious flaw is found by using triangulation. Some vacuum vessels can be tested with internal pressure rather than a vacuum. If a vacuum vessel can be pressure tested, it is the preferred method because it is easier to detect leaks with internal pressure. 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 30F above the minimum design metal temperature to prevent the risk of brittle fracture. A brittle fracture 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 70F minimum and 120F 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 exchanges 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 be required 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 shed 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 to continue 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 they were built to. Extra thickness can be required by the design as sacrificial metal (corrosion allowance) in the vessel parts. Extra thickness can be due to the nominal plate thickness as opposed to the actual thickness required by calculation, i.e., the shell has a required thickness of .435 " and .500 plate is used because .435" is not manufactured. Owners, Users or Codes may require that the metal cannot be less than a certain thickness in a particular service. Sometimes a reduction in pressure or temperature for a vessel will allow its continued service with thinner metal. 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 R1 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 used in 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 data base. 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 use 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.


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 very 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 such as Eddy Current or Ultrasonics. In some instances a tube may selected for removal and splitting for inspection. The results of this destructive examination can then be used to determine the probable general condition of the remaining tubes. Other portions of the exchanger such as the tube sheets, baffles, impingement plates, floating head, and channel covers will require visual inspection and may require measuring to determine their conditions.


API 510 Module API RP 572 SECTIONS 1, 2, 3, 4, 5 and 6 Find the answers to these questions by using the stated API 572 paragraph at the end of the question. Quiz #4 1. Name three shapes of pressure vessels. (2.1) 2. Describe multilayer construction of a pressure vessel. (2.2) 3. When carbon steel will not resist corrosive fluids, what method of construction is

normally used for such a vessel? (2.3) 4. Name four types of internals found in pressure vessels. (2.4) 5. Prior to 1930, what specifications were unfired pressure vessels built to in refineries?

(3.0) 6. Why is it important to have access to previous editions of the ASME Codes? (4.0) 7. Name three types of information gained from the inspection of a pressure vessel.(5. 1) 8. List the basic forms of deterioration. Name the effects these basic forms have. (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? (7. 1) 10. Why are occasional checks of operating pressures while equipment is in operation

important? (7.2) Answers to Quiz #4 1. Cylindrical, Spherical & Spheroidal 2. The cylindrical sector section is made up of a number of thin concentric cylinders

fabricated together one over the other until the obtained 3. It may be lined with other metals or non-metals 4. Demisiter pads, traps, baffles, spray nozzles 5. User or manufacturer 6. A pressure vessel has to be mentioned under the ASME code it was built to & codes are

revised constantly 7. Physical conditions, type, rate and causes of deterioration 8. Electrochemical, chemical, mechanical or combination of all three. Corrosion, erosion,

metallurgical, physical change, mechanical forces 9. Rate or corrosion remaining corrosion allowance 10. To detect defects and to measure wall thickness


API 5 1 0 Module API PP 572 SECTIONS 8.1 to 8.4.4 Find the answers to these questions by using the stated API 572 paragraph at the end of the question. Quiz #5 1. What should an inspector be aware of before starting the inspection of a pressure

vessel? (8.1) 2. Careful visual is important to determine what other types of inspections might be

required. Name three other types of inspection. (8.1) 3. Before an inspection starts in a vessel, who else besides the safety man should be

informed? (8.2.1) 4. Name five tools an inspector should have to perform an inspection. (8.2.2) 5. List at least six items that should be inspected on the external of a pressure vessel.

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

inspection? (8.4.3) 8. Where will most of cracks found in a pressure vessel be found? (8.4.3) 9. Why is a systematic procedure important when inspecting a pressure vessel? (8.4.4) 10. Under what operating conditions should weld seams in a pressure vessel be given special

attention? (8.4.4) Answers to Quiz #5 1. Pressure & temperature conditions under which the vessel has been operational since last

inspection contents & function of vessel serves in the process. 2. Magnetic particle-wet or dry, dye penetrant, ultrasonic shear wave 3. All persons working around the outside. The vessel that people will be working inside

the vessel. 4. Flashlight, scraper, plastic bags, & hammer 5. Ladders, walkways, platforms, external scratches, stairways(connected to vessel),

tightness of bolts, floor plates, nozzles & guy wires. 6. Type & location of deterioration 7. Review the previous records 8. Welded seams and adjacent areas, sharp change in shape, nozzles, & baffles. 9. To avoid overlooking but obscure important items 10. When the service of vessel is Amine, Wet Hydrogen Sulfide, Caustic Ammonia, Cyclic,

High Temperature or other services that may promote cracks.


API 510 Module API RP 572 SECTIONS 8.4.5 to 8.5.2 Find the answers to these questions

Documents

API 510 Study Material-1