1 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 allowed to use the ASME Codes and the API books on the first 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, and
Alteration, 9th Edition, June 2006.
o API Recommended Practice 571, Damage Mechanisms Affecting Fixed Equipment in the
Refining 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
2 API 510 Module
Table of Contents API CODES
API 510 Corrosion Rates and Inspection Intervals
Scope 5
Inspection Interval 9
Metal 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
3 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 ??,61,80
Postweld 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 116
UG-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 126
UG-42 Reinforcement of Multiple Openings 128
Exercises UG s 40-41-42-45 129
4 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 20 –UCS 66 – 67 144
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
5 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 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 owner–user 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 510
3. 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.
6 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 vessel‟s 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.
7 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 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. The sum of their dimensions along 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 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.
8 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 K1 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.
9 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 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.
10 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.
11 a. The weld area shall be preheated and maintained at a minimum temperature of 350 oF (175 oC) during
welding. 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 substantially flush with the surface of the base material or the previous weld layer.
c. Heat input shall be controlled within a specified range of welding current and voltage.
d. The weld area shall be maintained at a temperature of 500 oF +or – 50 oF (260 oC +or – 28 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 as base 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.
12 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, excluding corrosion allowance.
b. The thickness of the repair weld shall be increased by a ratio of minimum specified tensile strength of the base metal and minimum specified tensile of the filler metal used for the repair.
c. The increased thickness of the repair shall have rounded 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.
13 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" 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 Loss Metal = Rate Corrosion
Therefore: March 1993-March 1989 = 4 years
year in./per .0075 Yrs. 4 " .030 = Rate Corrosion
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
14 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)
15 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.
16 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 as pressure 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 .
17 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 convex side) 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 header or 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 disk‟s predetermined 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.
18 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)
19 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. (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)
20 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).
21 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 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 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 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, intergranular corrosion, embrittlement and other changes.
Mechanical forces 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
22 types of faulty fabrications may result in failures due to cracks or high stress concentrations, etc., in vessels.
23 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 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 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.
24 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, 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 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 (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.
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. 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.
25 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 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.
26 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 thickness 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.
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.