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!
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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
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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
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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
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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
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API 510 Module PRESSURE VESSEL INSPECTION CODE
Overview Section 1 General Scope: The API 510 applies to pressure vessels in the petrochemical and refining industries after they have 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.
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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. API 510
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Inspection of Parts: a. The surfaces of shells and heads should be checked for cracks, blistering, bulges, or other signs of deterioration. With particular attention paid to knuckle regions of heads and support attachments. b. Inspect welded joints and their heat affected zones for cracks or other defects. Rivets in vessels shall be inspected for general corrosion, shank corrosion. If shank corrosion is suspected hammer testing or angle radiography can be used. c. Examine sealing surfaces of manways, nozzles and other openings for distortion, cracks 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. API 510
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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 API 510
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b. c. d. e.
Supports Allowance for expansion General alignment 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 70°F, but not greater than 120°F. 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).
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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. API 510
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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 300°F 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.
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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.
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API 510 Module CORROSION RATES AND INSPECTION INTERVAL
Examples Metal loss equals the previous thickness minus the present thickness. Problem #1 Determine the metal loss for a tower shell course which measured .600" in during its last 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.
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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
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API 510 Module SECTIONS 1, 2, and 3 Find the answers to these questions by using the stated API 510 paragraph at the end of the question. Quiz #1 1. What code covers maintenance inspection of petrochemical industry vessels? (1. 1. 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.
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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
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API 510 Module RP 576 INSPECTION OF PRESSURE RELIEVING DEVICES Overview Scope: This recommended practice covers automatic pressure relieving devices commonly used in the petrochemical and oil refining industries. The recommendations found in RP-576 are not intended to replace and regulations that may exist in a jurisdiction. Types of Pressure Relief Valves: The three major types of pressure relief valves are the safety valve, relief valve and the safety relief valve. Pressure relief valves are classed based on their construction, operation and applications. Safety Valves A safety valve is a spring-loaded device containing a seat and disk arrangement. It also has a part just above the disk referred to as a huddling chamber. When the static pressure beneath the disk has risen to a point where the force exerted on the disk begins to overcome the springs downward force the disk slowly opens. 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. API 510
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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. API 510
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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 plasticmetal 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.
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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.
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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 UG126) 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/d’s 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
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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
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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 multilayer (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.
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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.
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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. API 510
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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. API 510
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Concrete supports are inspected with same concerns as concrete foundations. Close attention to any seals and the possibility of trapping moisture because of faulty seals should be investigated. 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 nondestructive 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.
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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. API 510
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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, API 510
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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 API 510
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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 30°F 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 70°F minimum and 120°F 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 API 510
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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.
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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.
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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
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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.
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API 510 Module API RP 572 SECTIONS 8.4.5 to 8.5.2 Find the answers to these questions by using the stated API 572 paragraph at the end of the question. Quiz #6 1.
When examining linings, name the three most important conditions to check. (8.4.5)
2.
Describe the spark tester method of inspecting nonmetallic linings. (8.4.6)
3.
How may loose non-metallic fittings be found using a hammer? (8 4.6)
4.
Where a corroded surface is very rough, what may be done to measure thickness?(8.4.7)
5.
How may cracks be made to stand out from the surrounding areas being inspected? (8.4.8)
6.
Who should make the decision to trepan metal from a vessel for metallurgical evaluation? (8.4.8)
7.
How may carburized austenetic stainless steel sometimes be detected? (8.4.9)
8.
What functions may an inspector's hammer serve? (8.5.1),,
9.
When testing a vessel pneumatically what should be on hand to aid in the visual examination? (8.5.2)
10.
If it is possible to use internal pressure to test a vacuum vessel, what advantage does that method offer? (8.5.2)
Answers to Quiz #5 1. No corrosion, lining properly installed, no holes or cracks exist. 2. A high voltage low current electrode(brush type) is passed over the lining, the other end is attached to the end of the vessel. Electric arc will pass between electrode and the hole in the lining 3. A light tapping on lining will make lessor evident with sound & feel. 4. Drill test hole to determine thickness. 5. Etching method (acid) 6. By someone who knows how to analyze the problems related to the repair of sample house. 7. Magnetic Test 8. Supplement visual inspection e.g. thin walls in vessel, loose bolts & nuts, rivets, cracks in metallic linings, lack of bond in concrete to remove scale. 9. Soap solution, ultrasonic sound tester or both. 10. Leaks from an internal pressure are more easily located.
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API 510 Module API RP 572 SECTIONS 8.5.3 to 10.2 Find the answers to these questions by using the stated API 572 paragraph at the end of the question. Quiz #7 1. Why is it desirable to leak test an exchanger before disassembly? (8.5.3) 2.
If a given exchanger begins leaking for the first time in its service life, what should be done? (8.5.3)
3.
Before retiring a vessel, what should be consulted? (8.6)
4.
Before taking credit for excess thickness found in a vessel when doing calculations for retirement or rerating, what must also be considered? (8.6)
5.
What documents should be consulted prior to any repair? (9)
6.
When shall a pressure test be applied? (9)
7.
Why should care be taken when arc gouging a crack before a welded repair? (9)
8.
What must an inspector consider when recommending the filling of pits with an epoxy? (9)
9.
What does the continuous file contain? (10.2)
10.
Who should receive copies of all inspection reports? (10.2)
ANSWERS TO QUIZ #7 1. A leak may be detected by observing & point such as a disconnected nozzle or an open bleeder. 2. Inspection should be performed to determine the nature of deterioration 3. The code edition of that code it is rated under and whether any regularities of and allowable repairs must be determined. 4. Safety, Temperature & Pressure 5. Applicable code & standards under which it is to be rated should be studied to assure methods of repair will not violate appropriate requirements 6. For al major repairs 7. Because the heat will cause cracks to lengthen or 8. That the pits are not large enough or close enough together to represent a general thinning of the component. 9. All information on the vessel operating history description and measurement from previous inspections, corrosion rate tables(if any) and records of repair & replacement. 11. Operations, Maintenance & Engineering
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API 510 Module API RP 572 APPENDIX A Find the answers to these questions by using the stated API 572 paragraph at the end of the question. Quiz #8 1.
Explain the difference between condensers, coolers and air coolers. (A. 1)
2
Show by sketch what is meant by One Fixed Tube Sheet with Floating Head, Two Fixed Tube Sheets, One Fixed Tube Sheet with U Tubes. (A.2.2, 2.3, 2.4)
3.
When are Double Tube Sheet Exchangers used? (A.2.5)
4.
Name two types of water heaters. (A.2.7)
5.
What principle of cooling is used with exposed tube bundles? (A.3.2, 3.3)
6.
Name two types of Air-Cooled Exchangers. (A.5)
7.
Describe the construction of Double-Pipe coils. (A.6.2)
8.
Where are Flat-Type Heater Coils found? (A.6.3.4)
9.
Why is it important to inspect exchanger bundles when they are first pulled from a shell? (A.9. 1)
10.
Name the likely locations for corrosion in exchangers. (A.9.2)
ANSWERS TO QUIZ#8 1. Condensers transfer heat by vapors to another fluid Coolers cools hot by a lower temperature Air-coolers air is used to reduce temperature of fluid by air. 2. 3. Where minute leaks from one fluid to another cannot be tolerated 4. a.) fixed tube sheet type b.) u-tube type 5. Water flows or sprayed on bundles 6. Draft coolers-on top or below tube bank, forced draft coolers-below tube bank 7. They are in shape and of small diameter with minimum wall thickness 8. Bottom of storage tank 9. Because the color type location of scales and a. help to pinpoint corrosion problems 10. The outside surface of tubes opposite shell inlet nozzles, adjacent to the baffles are tube sheets
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API 510 MODULE API CHAPTER II CONDITIONS CAUSING DETERIOTATION OR FAILURES
Introduction Chapter II is under revision at this time, it is to be replaced with API RP 571, Recognition of Conditions Causing Deterioration or Failure at some future date. Accordingly our coverage of the subject will be based on the present API 510 Authorized Pressure Vessel Inspector Body of Knowledge dated August 1994. Of the information contained in Chapter II, only knowledge that pertains to pressure vessels may be included in the examination questions. This is per the published Body of Knowledge. The coverage of Chapter II will be limited to the required information on the test. Corrosion is a major source of expense in refinery and chemical plants. Many times a piece of equipment will corrode its way into retirement as opposed to simply wearing out. The three major groups of corrosion are corrosive products in crude oils, corrosion from chemicals used or processed, and environmental corrosion. Corrosive components found in crude oil that cause the most metal loss in pressure vessels are thought to be one or more of the following: Hydrogen chlorides and inorganic and organic chlorides, Hydrogen sulfide, mercaptans, and organic sulfur compounds, Carbon Dioxide, Organic acids, and Nitrogen compounds. Most of the above mentioned components attack the front end of a process system. Crude oils contain salt, which can never be totally removed. The salt will generate various chemical compounds when broken down in a processing system. Some of the compounds are: Hydrogen chloride and Organic and Inorganic chlorides. Such things as Magnesium and Calcium chloride, when dissolved in water and heated, attack the metal in the form of Hydrochloric acid, which is very corrosive. This process is called hydrolysis. Hydrogen sulfide is believed to be the most active of the sulfur compounds in causing corrosion. Some hydrogen sulfide is present in the crude oil, and more may be generated during the refining process. Outside of corrosion, the most serious problems caused by Hydrogen Sulfide are blistering and embrittlement. Carbon Dioxide, when combined with water, is corrosive. The water and carbon dioxide combine to form carbonic acid. The water will usually be introduced from two sources: the decomposition of bicarbonates in or added to crude oil or from steam used to aid in distillation of crude oil. Organic Acids, while not very corrosive at low temperatures, can be very corrosive at their boiling temperatures. When organic acids have corroded carbon steel, a very smooth surface is left and metal loss is not readily apparent during visual inspection. And Cyanide. These two chemicals, while not causing corrosion directly, contribute to it by breaking down a protective layer of scale which has formed on the metal leaving the metal subject to Hydrogen Blistering and other problems discussed in the above paragraphs. The Ammonia and Cyanide will directly cause pitting and worm-holing type attack in copper and brasses.
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Corrosive Materials added to the process add significantly to metal loss caused by corrodents already present in the crude oil that is being refined. Chemicals commonly added in refining processes are Sulfuric Acid and Hydrogen Fluoride, Phenol Phosphoric Acid, Caustic (sodium hydroxide), Mercury, Ammonia, Chlorine, and Aluminum. Alkylation Units utilize either Sulfuric Acid or Hydrofluoric Acid as a catalyst. Sulfuric Acid is the least corrosive of the two chemicals and corrosion occurring in equipment using Sulfuric Acid may be very erratic attacking particular points in the process stream Sulfuric acid is generally less corrosive at high concentrations of 85% or more. Hydrofluoric Acid is very corrosive to steel unless it is kept at concentrations above 65% Hydrogen Fluoride. Phenol (carbolic acid) is used in the manufacture of lubricating oils and aromatic hydrocarbons. At temperatures below 400°F and without water present, carbon steel is usually not severely corroded by Phenol. Above 400°F, carbon steel may corrode rapidly m Phenol service. Phosphoric Acid is used as a catalyst in polymerization units either in liquid or deposited as pentoxide on clay pellets. Unless water concentrations are above a certain level, corrosion is rare from Phosphoric Acid. When water is present in the required concentrations, Phosphoric Acid will attack carbon steel very aggressively. Penetration of ¼” carbon steel in 8 hours can occur. Caustic is used primarily for neutralization of acids and grease manufacture. Caustic can be used and stored in carbon steel vessels and is generally not corrosive as long as the vessel has been stress relieved and temperatures are kept at a safe level. At temperatures above 200°F, it will cause general corrosion in carbon steel. Mercury is found in instrumentation and can enter vessel by mishap. If the mercury enters it will cause stress corrosion attack in copper and monel. Ammonia is used for refrigeration and neutralizing acids in plants. If Ammonia is allowed to contact copper-based alloys in pH ranges of 8.0 and above, severe corrosion as general metal loss occurs, and stress corrosion cracking then occurs. Blue salt deposits on equipment are a clear indication of general corrosion by Ammonia. Chlorine is used to treat water for cooling towers and to manufacture Sodium Hypochlorite for treating oils. If water is not present, Chlorine corrosion of carbon steel is minor. Present. It will hydrolyze in water and form hydrochloric acid and cause severe pitting corrosion in carbon steel. Austenitic stainless steel under the above conditions will be subject to inter-granular corrosion and stress corrosion cracking. Environmental Corrosion in refineries most commonly affects carbon steel. The water and oxygen present in the atmosphere will cause severe corrosion on unprotected carbon steel. This type of corrosion is usually galvanic and can be severe if water is allowed to penetrate insulation. Important Corrosion types include Intergranular, Graphitic corrosion of cast iron, Stress Corrosion Cracking, Polythionic Acid, Dezincification, Galvanic, Contact Corrosion and Biological Corrosion. The following paragraphs give a general definition to the various types of corrosion.
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Intergranular Corrosion can occur in austenetic stainless steels when they are heated up to a range from 750°F to 1650°F and cooled down. In the temperature range mentioned above, complex carbides are formed of chrome and other elements which then migrate to grain boundaries leaving those areas lacking the chrome which is intended to help resist. This loss of chrome is followed by corrosive attack around grain boundaries and Intergranular Corrosion occurs. Graphitic Corrosion is the low-temperature corrosion of gray cast iron in which metallic iron is converted into corrosion products, leaving the graphite intact. Stress Corrosion Cracking is the spontaneous cracking of metals under the combined action of stress and corrosion. Polythionic Corrosion is a result of iron sulfide scale reacting with oxygen and water. This normally occurs at the time of shutdowns of vessels. Dezincification is a corrosion that occurs when copper-zinc alloys containing less than 85% copper are used in water service. It occurs in three forms: plug, layer, and intercrystalline. Galvanic Corrosion occurs between metals in contact with each other having different electrical potentials. It is the same type chemical exchange found in a common wet or dry cell battery. An electrolyte must be present for this type of corrosion to occur, and normally the electrolyte is water or acids. Contact Corrosion (crevice corrosion) happens at the contact surfaces between a piece of metal and another piece of metal or a piece of metal and a nonmetal. A corrodent such as water must present. Biological Corrosion is related to the presence of organisms (bugs) in a contact with a metal. They can be fairly large (macro) or very small (micro) organisms. An example of a macroorganism is a barnacle. Examples of microorganisms are bacteria, slime, and fungi. One of the primary places that microorganism biological corrosion is found is on electrolyte solution which speeds up contact or crevice corrosion. Erosion of metals is found frequently in vessels and piping of refineries and chemical plants. It amounts to a wearing away by the abrasive action of a moving stream of a liquid or gas. If solids are contained in the gas or liquid, the erosion will be accelerated and could be compared to blasting with a water and sand mixture. The Effects of High Temperature on Strength of a metal can result in the failure of the metal suddenly (stress rupture) or slowly (creep). Creep happens to metal held at high temperatures for long periods of time and is defined as the flow or plastic deformation at stresses that would not cause metal flow at a lower temperature. It is based on time at an elevated temperature and stress level. Stress Rupture is a brittle failure that gives very little warning, with little if any deformation, and is related to stress at high temperature. It can be considered the end result of creep in some metals.
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API 510 Module API CHAPTER II Find the answers to these questions by using the stated Chapter II paragraph at the end of the question. Quiz #9 1.
Name the three major groups of corrosion. (202)
2.
Name six corrosive components of crude oil. (202.021)
3.
What component do all crude oils contain? (202.022)
4.
Where does Hydrogen Chloride evolve from in a process stream? (202.022)
5.
What is the definition of pH? (202.022)
6.
May Hydrogen Sulfide cause corrosion even at low temperature? If so, where can it be found? (202.023)
7.
Where can Carbon Dioxide come from in process streams? (202.024)
8.
Name the corrosive materials added to processes. (202.023)
9.
Above what concentration is Sulfuric Acid not very corrosive? (202.032)
10.
Describe the following types of corrosion: Intergranular, Polythionic Acid, Dezincification, Galvanic, Crevice Corrosion and Biological. (202.06)
ANSWERS TO QUIZ #9 1. Corrosion from components in crude oil, chemicals used in refinery processes, environmental corrosion. 2. Hydrogen chloride, hydrogen sulfide, carbon dioxide, ---- oxygen and water, organic acids, nitrogen ---3. Salt 4. Hydrochloric acid 5. Dfl 6. Yes storage tanks 7. Crude oil-decomposition of bicarbonates, steam distillation 8. Sulfuric acid, hydrogen fluoride, phenol, caustic, phorous acid, mercury ammonia, chlorine, al 9. 85% or more. 10.
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ASME SECTION VIII DIV. 1 PART UW - WELDING
Objectives Student should understand and be capable of applying the following concepts: A.
Joint restrictions based on Service.
B.
Joint Categories.
C.
Joint Types.
D.
Butt Joint Radiography Requirements.
E.
Butt Joint Efficiencies.
F.
Requirements for Post Weld Heat Treatment.
G.
Application of Welded Repairs.
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API 510 Module PART UW - WELDING
Introduction Section VIII Division 1 has a system of identification for welds in vessels and vessel parts. This system assigns types to welds; the form of weld (double welded, etc.) determine its type. The locations of welds in a vessel or vessel part determine their category. In some instances the type will be mandatory based on Category and Service. In other cases it will be optional; the designer makes a choice from the acceptable Types. Radiography requirements also depend on Type, Service and Category. The Code also assigns a way of measuring the quality of a butt joint which is based on the Type and extent of radiography used.
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API 510 Module PART UW - WELDING Definitions The following are definitions for use in Part UW. Doing calculations on shells, heads, nozzles and the like will depend on knowing these definitions. Welded Joints 1.
Corner Welded Joint (called a fillet weld in Section IX)
2. Butt Welded Joint
Weld Types 3.
Type is the description of a welded joint. For example, a single-welded butt joint with backing that remains in place.
Weld Categories 4.
Determination of Category for a joint depends on the location of the joint in a vessel or vessel part. As an example the circumferential seam joining two shell courses is a Category of weld.
Shell Course
Shell Course
Category
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UW-2 Service Restrictions Service restrictions apply to four classes of vessels.
*
Lethal Service
*
Service below Certain Temperatures Given in UCS-68
*
Unfired Steam Boilers exceeding 50 psi
*
Vessels or Parts Subject to Direct Firing
For determination of a Butt joint's service restrictions by Types (how made) and Categories (locations) permitted in a vessel read UW-2. Vessels used to contain lethal substances require that all major butt welded Joints be fully radiographed (with some exceptions for heat exchangers). If they are Category A joints they must be of type No. (l) of Table UW-12. If they are Category B joints they must be of either Type No. (1) or Type No. (2). Similar restrictions apply to the other classes listed above.
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UW-3 Welded Joint Category A quick reference system for specifying joint requirements is the assigning of categories by location, to welds in a vessel. For instance for a vessel in lethal service the Code requires that butt joints be of a specific type based on their physical location in the vessel and that the butt welds be fully radiographed. A statement like "All category A joints shall be Type No. (1)." is a short hand way of saying the following: "All longitudinal welds within main shells, communicating chambers, transitions in diameter, or nozzles; any welded joint within a sphere, within a formed head, or within the side plates of a flat sided vessel, circumferential welded joints connecting hemispherical heads to main shells, to transitions in diameter, to nozzles, or to communicating chambers shall be Type No. (1).” As you read through the Code paragraphs think of how difficult it would be to restate a complete description every time you find a specified requirement based on Joint Category. The best way to understand and thereby learn joint category is by the use of graphics. Fig. UW-3 of Paragraph UW-3 provides a brief graphical representation. An expanded use of graphics for each Category follows.
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UW -3 Welded Joint Category Case Study 1 The term "Category" as used here in defines the location of a joint in a vessel, but not the type of joint. UW-3(a)(1) Category A. Longitudinal welded joints within the main shell, Communicating chambers, transitions in diameter, or nozzles; any welded joint within a sphere, within a formed or flat head, or within the side plates of a flat-sided vessel; circumferential welded joints connecting hemispherical heads to main shells, to transitions in diameter, to nozzles, or to communicating chambers.
CATEGORY A JOINTS HEMI HEAD
COMMUNICATIONS CHAMBER MAIN SHELL LONGITUDINAL SEAM SEAMS IN A SPHERE
HEMI HEAD TO TRANSISTION
NOZZLE LONGITUDINAL SEAM
TRANSISTIONS
SEAMS IN FLAT HEAD
HEMI HEAD TO NOZZLE
SEAMS IN FORMED HEADS SUCH AS TORISPHERICAL
FLAT SIDES OF VESSELS
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UW -3 Welded Joint Category Case Study 2 The term "Category" as used here in defines the location of a joint in a vessel, but not the type of joint.
UW-3(a)(2) Category B. Circumferential welded joints within the main shell, communicating chambers, nozzles, or transitions in diameter including joints between the transition and a cylinder at either the large or small end; circumferential welded joints connecting formed heads other than hemispherical to main shell, to transitions in diameter, to nozzles or to communicating chambers.
FORM HEAD TO SHELL
NOZZLE
MAIN SHELL
LARGE END OF TRANSISTION SMALL END OF TRANSISITION COMMUNICATIONG CHAMBER FORM HEAD TO COMMUNICATING CHAMBER
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API 510 Module PART UW - WELDING UW -3 Welded Joint Category Case Study 3 The term "Category" as used here in defines the location of a joint in a vessel, but not the type of joint.
UW-3 (a)(3) Category C. Welded joints connecting flanges. Van Stone laps, tubesheets, or flat heads to main shell, to formed heads, to transitions in diameter, to nozzles, or communicating chambers; any welded joint connecting one side plate to another side plate of a flat sided vessel.
NOZZLE
NOZZLE
VAN STONE LAP NOZZLW
CAT. C FILLET WELD
CAT. C BUTT WELD
CAT. C BUTT WELD
CATEGORY C
CATEGORY C BUTT WELD
CATEGORY C
FLAT HEAD TO SHELL
TUBE SHEET TO SHELL
SIDE PLATES C C CATEGORY
C C
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C
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FORGED FLAT HEAD TO SHELL OR NOZZLE
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UW -3 Welded Joint Category Case Study 4 The term "Category" as used here in defines the location of a joint in a vessel but not the type of joint. UW-3 (a)(3)Category D. Welded joints connecting communicating chambers or nozzles, to main shell, to spheres, to transitions in diameter, to heads, or to flat sided vessels, and those joints connecting nozzles to communicating chambers (for nozzles at the small end of a transition in diameter, see Category B). COMMUNICATING CHAMBER CAT. D FILLET
COMMUNICATING CHAMBER CAT. D BUTT WELD
MAIN SHELL
MAIN SHELL CAT. D FILLET NOZZLE
CAT. D BUTT WELD NOZZLE
TRANSISTION
NOZZLE TO SPHERE CATEGORY D
CATEGORY D
NOZZEL TO FLAT SIDE
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HEAD
CATEGORY D
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UW -3 Welded Joint Category Exercises 1.
The category of a joint depends on: a. b. c. d.
2.
A circumferential weld to attach a flange is what Category'? a. b. c. d.
3.
What kind of weld was made: fillet or butt. The process used to make the weld. Whether it is vertical or horizontal in the vessel None of the above.
D C E A
In the drawing below identify all of the of joints by Category.
D B
A
B
A A
C
B
B
B A
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A A
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UW-51 Radiographic and Radioscopic Examination of Welded Joints Overview In UW-51 the requirements for radiographic examination are detailed. When performing radiography to Section VIII Div. 1 of the Code your are directed to Article 2 of Section V for the techniques to be used. The following are highlights of the requirements: 1.
A complete set of radiographs shall be kept on file until the final acceptance of the inspector.
2.
Personnel performing and evaluating radiographs shall be qualified using SNT-TC- 1A as a guideline for written practices used in their qualification.
3.
That paragraph T-285 of Article 2 is a guide only and that final acceptance of radiographs is based on the ability to see the correct penetrameters image and the specified hole or wire size as applies.
4.
How repairs of defects shall be made in accordance with UW-35 and the techniques for re-inspecting the weld after repair. The repair need not be radiographed if prior to the repair it has been demonstrated to the inspector's satisfaction that Ultrasonic Testing can disclose the defect. In which case ultrasonics can be used to examine the repair for acceptance.
5.
That any indication on a radiographed characterized as a crack or zone of incomplete fusion or penetration is unacceptable.
6.
That the limits of elongated indications are based on the materials thickness.
7.
That unacceptable aligned indications are based on total length of a group and the material's thickness.
UW-51 contains the unacceptable indications for Full Radiography. Also definitions of nominal thicknesses for welded joints and weld repairs. Details of Spot Radiography are covered in UW-52.
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UW-52 Spot Examination of Welded Joints Overview Spot radiographs use the same techniques as those in UW-51, but of course are not for the full length of the weld. The basis for selecting Spot radiography is the desire to use a joint efficiency that will come from Column B of table UW-12. The small print note above the subparagraphs explains the Code's intent for the use of spot radiography. The following are highlights of the requirements for Spot Radiography. 1.
One spot radiograph for every 50 ft of weld or fraction thereof for a joint efficiency from column b of Table UW- 12.
2.
A sufficient number of spots shall be radiographed to examine each welder or welding operator in the 50 foot increment. In the case where welders weld on opposite sides of the same weld one shot will serve to examine both.
3.
The inspector chooses the location of the spot radiography. If the inspector approves and cannot be present the fabricator can then choose the location of the spot radiography. Notice that there is no specific location; the welders should never be able to predict the inspector's choice of location.
4.
The spot radiography used to pick a joint efficiency from column b of TableUW-12 will not satisfy the requirements of other paragraphs such as UW-11 (a)(5)(b); a spot radiograph required for the choosing of a joint efficiency from column A of Table 12.
5.
Spot radiographs must follow the same rules as full radiographs for techniques. The minimum length of the spot examined must be 6 inches.
6.
Indications described as cracks or zones of incomplete fusion or lack of penetration are unacceptable.
7.
Slag inclusion or cavity evaluation is based on the thickness of the weld excluding any weld reinforcement (cap). The thickness is based on thinner member if two different thickness that have been joined by a butt weld. If a fillet is welded over a full penetration weld its throat must be included in the thickness (t). Indications in a line are described with acceptance standards.
8.
Rounded indications are not a factor in the acceptability of welds not required to be fully radiographed.
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UW-52 Spot Examination of Welded Joints Overview 9.
When a spot radiograph is acceptable the entire weld increment represented is accepted. For example if a longitudinal weld has 65 feet of weld metal only the first 50 feet could be accepted by a single 6 inch spot radiograph. The remaining 15 feet is represented in the next declared 50 feet increment.
10.
If the first spot radiograph reveals welding that does not comply then two additional spots in the same weld increment away from the first spot shall be radiographed (tracers). The choosing of the two spots follow the same rule as the first spot radiograph.
11.
If the tracers pass then repair and radiography is allowed for the area that was rejected in the first spot radiograph.
12.
If either of the tracers fail there are two options. Cut out the entire increment, re-weld then applies spot radiography again or apply full radiography and repair all defects found.
The spot radiography described above is not applied to any specific Category of weld. In a given 50 feet of weld increment there may be Category A, B, C, and D butt welds. The inspector will choose the exact location of the spot radiograph. In cases where spot radiography is a specific requirement of another paragraph of the Code the location for the spot radiograph is stated within that paragraph. The spot radiography of UW-52 cannot serve double duty; it will not satisfy the spot radiography requirements of any other paragraph. It allows the use of a joint efficiency from column B of Table UW-12 for all categories of butt joints in that 50 feet increment. If the 50 feet increment were to stop in the middle of a joint the efficiency of that joint could not come from column B until the next 50 feet increment was spot radiographed.
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UW- 11 Radiographic and Ultrasonic Examination The Code demands 100 % Quality Assurance for some butt welds (Category A butt welds in Lethal Service is one example). In other services, choices for level of Quality Assurance for butt welded joints can range from 100 % down to 60 %. The Quality of a butt welded joint determines its Joint Efficiency in the Code. Joint Efficiency depends on the Type of butt joint and the amount of radiography applied. There are other Types of joints besides butt welded allowed in the Code. However they cannot produce Code acceptable radiographs. The term "Joint Efficiency" is a hold over from the days of riveted vessels. More will be said about this in the coverage of UW-12. There are three levels of radiography per Code. Full, Spot and None. The Code demands Full RT in some cases and allows Full RT, Spot RT or None at all in others. UW-11(a) Full Radiography specifies when Full Radiography must be performed. There are five instances sited. 1.
Butt welds in the shell and heads of vessels used to contain a lethal substance.
2.
When the least nominal thickness at a butt weld exceeds a limiting thickness, which is based on the type of material used in the vessels welded construction.
3.
Butt welds in the shells and heads of unfired steam boilers having an operating pressure greater than 50 psi.
4.
Butt welds in nozzles, communicating chambers, etc. in (1) or (3) above attached to vessels sections or heads that exceed certain limits on thickness or diameter.
5.
Categories A & D butt joints. Where full radiography is not mandatory; but desired to obtain a joint efficiency from column A of Table UW- 12. Spot radiography must also be applied to Category B and C butt joints.
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UW- 11 Radiographic and Ultrasonic Examination UW-11(b) Spot Radiography. The next option, if full radiography is not mandatory under 1 through 5 above, is spot radiography. This spot radiography can be applied to Category A, B, C, or D butt joints and will allow a joint efficiency from Column B of Table UW- 12. UW-11(c) No Radiography. If radiography is not mandatory under any Code requirements it may be omitted for butt welded joints. If this is the case the joint efficiency must come from Column C of Table UW- 12. UW-11 contains the when and where for radiography and ultrasonic examinations. The effect of the degree of radiography is reflected in paragraph UW- 12 with a resulting Joint Efficiency "E". The "E" will be used in the thickness required or pressure allowed calculations for shells, heads etc.. The following pages contain graphical representations of the UW-11.
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Radiographic and Ultrasonic Examination
(a) Full Radiography. The following welded joints shall be examined for their full length in a manner prescribed in UW- 51:
UW-11 (a)(1) All butt welds in the shells and heads of vessels used to contain lethal substances [see UW-2(a)]; [UW-2(a) limits Category A butt welds to Type 1 and Category B to Type 1 or 2 of Table UW- 12].
HEMI HEAD
ELLIPTICAL
LETHAL SERVICE MUST HAVE FULL RT
CATEGORY A TYPE 1 ONLY
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CATEGORY B TYPE 1 OR 2
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UW-11 Radiographic and Ultrasonic Examination (a)
Full Radiography. The following welded joints shall be examined for their full length in a manner prescribed in UW-51:
UW - 11 (a)(2) All butt welds in which the least nominal thickness at the welded joint exceeds 1 1/2 in. or exceeds the lesser thickness prescribed in UCS-57. Category B and C butt welds in nozzles and communicating chambers that neither exceed NPS 10 nor 1 1/8 in. wall thickness do not require any radiographic examination;
P-1 Material Per UCS-57 >1-1/4" Full RT
10" Category 1-1/4" thickness) C butt weld 1-1/8" thick No RT required
[Least
1 NO RT required 1-1/2" thick full RT required
24” Category A and C butt weld Full RT
NPS 20 Category 1-1/2" thick Full RT 2” thick Full RT
RT will change based on the P No. of the material used in construction. See UCS-57, UNF-57 etc., for mandatory Full RT based on thickness.
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Nominal
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UW-11 Radiographic and Ultrasonic Examination (a)
Full Radiography. The following welded joints shall be examined for their full length in a manner prescribed in UW-51:
UW- 11 (a)(3) All butt welds in the shells and heads of unfired steam boilers having a design pressure exceeding 50 psi, [see UW-2(c)]; [UW-2(c) limits Category A butt welds to Type 1 and Category B to Type 1 or 2 of Table UW- 12 ]. UNFIRED STEAM BOILER PRESSURE EXCEEDS 50 PSI
MUST HAVE FULL RT HEMI HEAD
ELLIPTICAL HEAD
Category A Type 1 Only
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Category B Type 1 or 2
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UW-11 Radiographic and Ultrasonic Examination (a) Full Radiography. The following welded joints shall be examined for their full length in a manner prescribed in UW-51. UW- 11 (a)(4) All butt welds in nozzles and communicating chambers, etc., attached to vessel sections or heads that are required to be fully radiographed under (1) or (3) above; however, except as required by UHT-57(a), Categories B and C butt welds in nozzles and communicating that neither exceed NPS 10 nor 1-1/8 in, wall thickness do not require any radiographic examination;
>NPS 10 Category B Type 1 or 2 FULL RT REQUIRED LETHAL SERVICE OR UNFIRED STEAM BOILER > 50 psi HEMI HEAD
ELLIPTICAL HEAD MUST HAVE FULL RT
Category A Type 1 Only
Category B Type l or 2
NPS 10 1-1/8” thick No RT required for Category C butt joint
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UW-11 Radiographic and Ultrasonic Examination (a)
Full Radiography. The following welded joints shall be examined for their full length in a manner prescribed in UW-51:
UW- 11 (a)(5) All Category A and D butt welds in vessel sections and heads where the design of the joint or part is based on joint efficiency by UW- 12 (a), in which case: (a)
Category A and B butt welds connecting the vessel sections or heads shall be of Type No. 1 or Type No. 2 of Table UW- 12;
(b)
Category B or C butt welds [but not including those in nozzles or communicating chambers except as required in (2) above] which intersect the Category A butt welds in vessel sections or heads or connect seamless vessel sections or heads shall, as a minimum, meet the requirements for spot radiography in accordance with UW-52, Spot radiographs required by this paragraph shall not be used to satisfy the spot radiography rules as applied to any other weld increment.
Cat. A Full RT Type 1 or 2
E= 1.0 or.90 For shell calcs. Spot RT Type l or 2 Cat. D Full RT
Type 1 E = 1.0 Type 2 E - .90 For hemi head and shell calculations only
Seamless Elliptical head see UW-12 (d)
Spot RT Type 1 or 2 per UW-11 (a) (5) (b)
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Exercises 1.
For a vessel in lethal service what butt joints must be radiographed in addition to all butt joints in the shell and heads? (\f by
2.
A joint efficiency from Column A of Table UW-12 is desired for a Category A butt joint in a shell, what extent of radiography must be applied to this Category A butt joint? What additional requirement must be met?
3.
If the least nominal thickness of a butt joint in a vessel exceeds a certain thickness based on the material used in its construction what amount of radiography must be applied?
4.
Full radiography is required by UW-11 (a)(2) may it be assumed that all butt joints have been fully radiographed? Why or why not?
5.
A vessel shell contains a Category A butt welded longitudinal joint and a Category D butt welded joint. Must both of these be fully radiographed to use a joint efficiency from Column A of Table UW-12?
ANSWERS TO UW-11 Exercises: 1.
Category A, B & C that exceed diameter 10” NPS or 1-1/8” thickness in nozzles and chamber
2.
Full RT and Spot RT
3.
Full RT for all Butt joints that exceed the specified thickness except B category joints that do not exceed 10" NPS or 1-1/8” thickness.
4.
No-Some thickness requirements may exceed the limit for the material used. It’s the thickness of the welded joint that determines the RT requirement.
5.
Yes by the requirement that both A & D butt welds shall be shot.
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API 510 Module PART UW - WELDING Allowable Stresses and Efficiencies Overview
There is a relationship between efficiencies and stresses the Code; that when understood, will allow making calculations with more confidence. What is joint efficiency? What is stress? STRESS Stress as it relates to internal pressure on a vessel is a load in the vessel's material. Stress is measured in pounds per square inch. Our examples use a material that will fail at 60,000 pounds per square inch.
ONE SQUARE INCH OF MATERIAL
15,000 LBS
STRESS EQUALS 15,000 POUNDS PER SQUARE INCH Ultimate Stress is the stress value at which a material breaks (fails) ULTIMATE STRESS ONE SQUARE INCH OF MATERIAL
60,000 LBS
ULTIMATE STRESS EQUALS 60,000 POUNDS PER SQUARE INCH
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Allowable Stresses and Efficiencies The Code allows the working stress in a material to be only a fraction of its Ultimate Stress. The term used is Maximum Allowable Stress. The Maximum Allowable Stress is about 25% of the Ultimate Stress for a given material. In the first example above the material is loaded to only 25% of the second example which failed at 60,000 pounds per square inch. The limiting of stress in the Code gives a safety factor of about 4 to 1. This is under ideal conditions with no known flaws in the vessel's material. This of course would be seamless materials properly inspected or a welded material joined by a Code approved method and fully radiographed as required in the Code. Most vessels are constructed using welding and welding will introduce flaws into the vessel material. How many and how bad are the flaws? This is answered by the use of nondestructive examination, primarily visual and radiographic. If a large enough flaw is present in the base material or the weld, failure can occur at a much lower value of stress. ONE SQUARE INCH CRACK IN WELD
OF MATERIAL
28,000 LBS.
FAILURE STRESS DUE TO FLAW 28,000 POUNDS PER SQUARE INCH In the Code formulas the Stress Allowed must be multiplied by the joint efficiency 'E'. So SE always appear in the formulas. The reason for using E is to make an adjustment for how certain it is that the welded joint is equal to a seamless piece of material. In the case of full radiography the conclusion that the material is as strong as seamless is made and an Efficiency for a Type No. 1 joint can be 1.0. For a Type No. 2 .90 can be used. Spot Radiography allows lower joint efficiencies and No Radiography still lower.
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Allowable Stresses and Efficiencies The previous examples showed heavy weights causing a stress in tension in one square inch of bar material. In a pressure vessel the stress in tension is caused by the internal pressure over an area. There will be a given amount of pounds per square inch over an area that has the same total effect as the heavy weights and a resulting stress is set up in the vessel's material. This force wants to tear the vessel apart and must be resisted by the cross sectional area of the vessel's wall. The Code limits the amount of stress that can be applied to a vessel's material and this will limit the pressure allowed or increase the thickness required. The stress in the material caused by the internal pressure is given special concern when there is a welded joint present in the vessel's wall. The expected strength of the material is known but how sure can we be if there is a potential flaw contained in a weld or its heat affected zone. Often the weld joint itself causes a change in the shape of what would otherwise be a uniform cylinder; this will cause what is referred to as a stress raiser. It is safe to say any weld will cause a stress riser to some extent. The Code deals with these stress raisers in two ways; by limiting the stress allowed in the material and by assigning joint efficiencies to welded joints and seamless components. The basis for the efficiency of a welded joint is its type and the amount of radiography it has received. The basis for a seamless component is the amount of radiography any intersecting welds have received. The assigning of joint efficiencies has a definite effect on the thickness of a vessel or component. The higher the efficiency allowed the thinner the material is required to be.
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ALLOWABLE STRESSES AND EFFICIENCIES. How Efficiency Affects the Construction of a Vessel If a vessel material has an allowable stress of 15,000 pounds per square inch and has a joint that allows an E of .85 (Type No. 1 Spot RT) the resulting thickness required will be more than that of seamless material; so the E of .85 is a stress multiplier and causes the allowable stress on the material to be lowered which will then drive up the required thickness. More of the material is required because we are only 85% sure that the welded material is as strong as seamless material or a Fully Radiographed Type No. 1 butt welded joint. SEAMLESS t = 1 INCH DOUBLE WELDED FULL RT t = 1 INCH DOUBLE WELDED SPOT RT t = 1.15 INCHES SE = 15,000 psi x .85 = 12,750 psi. The stress allowed in the calculation for thickness is now 12,750 psi and will result in the need for a thicker material in the vessel's construction. Welding is costly and the thicker the material the more costly both become. Radiography has a cost and a benefit. The direct cost is the cost of performing radiography. The indirect cost is the cost of repairing the rejectable conditions revealed by radiography. The benefit is the use of thinner material resulting in lower material and welding cost. Under certain conditions Full Radiography is required and the costs will be unavoidable. THE RT AFFECTS THE E WHICH IN TUEN AFFECTS THE t.
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UW-12 Joint Efficiencies The term joint efficiency as used in the Code is really a way of stating how close too in strength; after joining; the joint is to an equivalent seamless piece. The best available weld joint obtained by the arc or gas welding process is a Type No. 1 that has been fully radiographed. A Type No. 1 fully radiographed butt welded joint results in a part with a joint efficiency of 1.0. It may be considered as being as strong as a solid piece of the same material. Welded tension tests coupons normally fail in the base metal. UW- 12 states that the joint efficiency depends only on the type of joint and the degree of examination of the joint. The resulting joint efficiency shall be as given in Table UW- 12. The term Joint Efficiency as used today is really a measure of the quality of a joint. The term dates back to the days of riveted vessels and was a measure of how closely a particular riveted joint approached the strength of a seamless piece. Some believe that the term Joint Efficiency should be replaced with the term Quality Factor because it would be more reflective of what is really being determined by the modern Codes. After debate the Code Committee decided to leave things as they are in order to not create confusion in industry. The following graphics will help in understanding the concept.
SOLID MATERIAL
WELDED
RIVETED
In the case of a riveted shell a true circle could never be accomplished due to the natural offset in alignment. Still the term joint efficiency has hung on. Riveted construction was eliminated from the Code after 1971. As before we will utilize graphics to help in understanding joint efficiencies. Modified Table UW- 12 which follows with its graphics will explain joint types and the limits of radiography.
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Type 1-Category A, B, C & D
Type 2-Category A, B, C & D
CIRC. JOINTS ONLY
Type 3-Category A, B & C
Type 4-Category A
Type 5-Category B & C
Type 6-Category A & B
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MODIFIED TABLE UW-12 Butt Joints as attained by Column A double-welding or by other means which will obtain Full RT the same quality on the inside and outside. E = 1.0 Backing strip if used must be removed after welding is completed. Single-welded butt joint with backing strip which remains in place after E = .90 welding is completed. Limitations apply see Table UW-12. Single-welded butt joint without the use of a RT Not backing strip. Limitations Applicabl apply se Table UW-12. e
Double-full fillet lap joint. Limitations apply se Table UW-12.
Column B
Column C
Spot RT
No RT
E = .85
E = .70
E = .80
E = .65
RT Not Applicabl e
E = .60
RT Not Applicabl e
RT Not Applicabl e
E = .55
Single-full fillet lap joint with plug welds. Limitations apply se Table UW-12.
RT Not Applicabl e
RT Not Applicabl e
E = .50
Single-full fillet lap joint without plug welds. Limitations apply se Table UW-12.
RT Not Applicabl e
RT Not Applicabl e
E = .45
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UW-12 Joint Efficiencies UW-12 (b): A value of E not greater than that given in column (b) of Table UW-12 shall be used in the design calculations for spot radiographed butt welded joints [see UW-11 (b)]. Translation: If a joint efficiency from column b can be lived with and the Code does not require Full radiography, Spot RT can be used. Spot RT can be specified for the entire vessel per UW-11 (b), if it is, the miles of UW-52 must be followed. This means one 6 inch radiograph every 50 feet of weld metal; which must show the work of every welder or welding operator who has welded in the 50 foot increment. If two welders weld for instance; on opposite sides of a 50 foot weld one shot will do to prove both welders. Notice this Spot RT differs from that of UW-11 (a)(5)(b), UW-11 (a)(5)(b) is applied to circumferential joints only (B, C or an A that joins a Hemi Head). This RT may be applied to either longitudinal or circumferential joints or their intersections if so chosen by the inspector per UW-52 (b)(3).
Shell and Heads E = .85 50 Foot of Weld HEMI HEAD
ELLIPTICAL HEAD
SPOT RT TYPE 1 - CATEGORY A
SPOT RT TYPE 1 - CATEGORY B
The above example has 100 feet of weld total. All the welders are in the radiographs. Everybody got their picture taken. This vessel would be marked RT 3. Individual joints can be chosen for Spot RT and a joint efficiency from column b used for that component or joint. If that is done the marking becomes RT 4. All of this assumes Full RT is not mandatory.
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UW-12 Joint Efficiencies UW- 12 (c): A value of E not greater than that given in column (c) of Table UW-12 shall be used in design calculations for welded joints that are neither fully radiographed nor spot radiographed [see UW-11 (c) ]. Translation: If no radiography is performed all joint efficiencies come straight from table UW-12 column (c) based on the type of joint used. Of course this is not an option if Full RT is required by Code.
Shell and Head Joints E = .70 HEMI HEAD
ELLIPTICAL HEAD
TYPE 1-CATEGORY A
TYPE 1-CATEGORY B
The seamless elliptical head calculations in the above example would require an E of .85. This is per UW-12 (d). As you will see in UW-12 (d) seamless components are special cases.
UW-12 (d): Seamless vessel sections and heads shall be considered equivalent to welded parts of the same geometry in which all Category A welds are Type No. 1. For calculations involving circumferential stress in seamless vessel sections or for thickness of seamless heads E = 1.0 when the spot radiography requirements of UW-11 (a)(5)(b) are met. E = .85 when the spot radiography requirements are not met, or when the Category A or B welds connecting seamless vessel sections or heads are Type No. 3, 4, 5, or 6 of Table UW-12. Type No. 3, 4, 5 and 6 joints will not produce interpretable radiographs per the ASME Code. Therefore the E used to calculate a seamless component using one of these Types must be taken as .85 by default.
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API 510 Module PART UW - WELDING UW- 12 Joint Efficiencies Translation: UW-12 (d) requires the same action as UW-12 (a) except that the shell or head does not have Category A joints. The exception is a seamless hemispherical head without a flange. When welded on a shell it will have a Category A joint and therefore can never be seamless. In the part of UW-12 (d) that says "shall be considered equivalent to welded parts of the same geometry in which all Category A welds are Type No. 1" what it is implied but not directly stated, is that full radiography of the Category A Type 1 welds is required to make the two equals. Seamed Elliptical Hd Type No. 1 Full RT
Seamless Elliptical Hd
=
Seamed Shell Type No. 1 Full RT
Seamless Shell
=
When any of the above examples is joined to another component by a Type 1 or 2 joint then the Spot RT of UW-11 (a)(5)(b) must be performed to allow an E of 1.0 in their calculations. Examples: Categories, A (Hemi head) or B (head with skirt) or when any of the above examples is joined to another component by a type C (weld neck).
Category A Full RT Type 1 E = 1.0 Type 2 E = .90 For Shell Calculations
E = 1.0 For Head
Category A Full RT Type 1 or 2
E = 1.0 or .90 For Shell Calculations
Spot RT Type 1 or 2
Spot RT Type 1 or 2
E = 1.0 For Elliptical Head E = 1.0 For Shell
E = 1.0 For Shell Calculations Spot RT Type 1 or 2
Spot RT Type 1 or 2 API 510
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API 510 Module PART UW - WELDING
Determination Of Joint Efficiencies The most confusing part of doing Code calculation is the picking of a joint efficiency. The temptation to go straight to Table UW-12 and use one of the efficiencies listed there is automatic. That is a hit and miss proposition and will only on occasion yield the proper Joint E. First of all, the E has a double meaning that is not readily apparent. E in one sense applies to the welded joints and in the second it applies to a seamless component such as a seamless head or shell. There are three main types of stresses acting on a pressure vessel that are of concern. 1.
Circumferential Stress on shells (also called Hoop Stress).
2.
Longitudinal Stress on shells.
3.
Stress In heads.
Circumferential stress applies stress in a shell along its length. This stress acts to split a shell along its length and is often referred to as Hoop Stress. The shell may be seamless or may contain longitudinal seams. In either case failure in the circumference will usually occur similar to that shown in the drawing above. A Code calculation is required to determine the thickness required or pressure allowed on the shell for circumferential stress. There are two possible cases for a vessel's circumferential stress calculation with a single shell course. The shell is seamless or it has a longitudinal seam. The UG-27 circumferential formulas are used for calculation of thickness required or pressure allowed in both cases. The difference between the two conditions is in how the E is picked for use in the calculation. We will examine the two separately.
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Circumferential Stress / Seamless Shell E = 1.0 when the spot radiography of UW-11 (a)(5)(b) has been applied to the circumferential joint. This is per UW-12 (d). E = .85 when the spot radiography of UW-11 (a)(5)(b) has not been applied to the circumferential joint. This is per UW-12 (d). For a seamless shell course there are only two possibilities for the E when doing Hoop Stress Calculations. E = 1.0 or E = .85 TYPE No. 1 OR 2 CATEGORY B SPOT RT ELLIPTICAL HEAD SEAMLESS SHELL E = 1.0
TYPE No. 1 OR 2 CATEGORY 9 NO SPOT RT ELLIPTICAL HEAD SEAMLESS SHELL E = .85
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API 510 Module PART UW - WELDING
Circumferential Stress / Longitudinal Shell The E used for the calculation of a vessel with a butt welded longitudinal joint (seam) depends on several factors. 1.
What type of butt joint has been used to make the long joint? (Per Table UW-12 limitations only two are allowed) a. Type No. 1 or b. Type No. 2
2.
What is the extent of radiography on the long joint? a. Full b. Spot c. None
3.
Has the spot radiography of UW-11 (a)(5)(b) been applied to any intersecting Category A, B or C welds?
There are many combinations which can be made from the factors above, all resulting in different joint efficiencies. Examples of a few problems should help in the understanding of the other situations. In the following examples all vessels have less than 50 linear feet of welds total and were made by the same welder.
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API 510 Module PART UW - WELDING
Shells
Example A: Shell course with a Type No. 1 longitudinal seam that has been fully radiographed. The vessel has ellipsoidal heads on both ends and the Spot RT of UW-11 (a)(5)(b) has been applied.
TYPE NO- 1 OR 2 - CATEGORY 9 SPOT RT E = 1.0 TYPE NO.1 - CATEGORY A FULL RT
ELLIPTICAL HEAD
Fully radiographing the Type No. 1 Category A longitudinal seam and performing the Spot RT of UW-11 (a)(5)(b) allows the use of an E from column A of Table UW-12. The E from Column A, for a Type No. 1 is 1.0. This is in agreement with Paragraph UW-12 (a).
Example B: Shell course with a Type No. 2 longitudinal seam that has been fully radiographed. The vessel has ellipsoidal heads on both ends and the Spot RT of UW-11 (a)(5)(b) has been applied.
TYPE NO. 1 OR 2 - CATEGORY R SPOT RT E = .90 TYPE 2 - CATEGORY A FULL RT
Fully radiographing the Type No. 2 Category A longitudinal seam and performing the Spot RT of UW-11 (a)(5)(b) allows the rise of an E from column A of Table UW-12. The E from Column A , for a Type No. 2 is .90. This is also in agreement with Paragraph UW- 12(a).
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API 510 Module PART UW - WELDING
Shells Example C: Shell course with a Type No, 1 longitudinal seam that has been fully radiographed. The vessel has ellipsoidal heads on both ends and the Spot RT of UW-11 (a)(5)(b) has not been applied.
CATEGORY B NO SPOT RT E = .85 TYPE NO. 1 - CATEGORY A FULL RT
Fully radiographing the Type No. 1 Category A longitudinal seam but not performing the Spot RT of UW-11 (a)(5)(b) requires the use of an E from column B of Table UW-12. The E from Column B, for a Type No. 1 is .85. This is in agreement with Paragraph UW-12 (a). Example D: Shell course with a Type No. 2 longitudinal seam that has been fully radiographed. The vessel has ellipsoidal heads on both ends and the Spot RT of UW-11 (a)(5)(b) has not been applied CATEGORY B NO SPOT RT E = .80 TYPE NO.2 - CATEGORY A FULL RT
Fully radiographing the Type No. 2 Category A longitudinal seam but not performing the Spot RT of UW-11 (a)(5)(b) requires the use of an E from column B of Table UW-12. The E from Column B , for a Type No. 2 is .80. This is also in agreement with Paragraph UW- 12 (a).
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API 510 Module PART UW - WELDING
Shells The conclusion drawn from examples C and D above is that applying full radiography to the longitudinal joint offers no benefit unless accompanied by the Spot RT of UW-11 (a)(5)(b). The Type No. 1 joint E of example C is the same as if it was only Spot Radiographed since it's E must come from Column B of Table UW-12. This is also the case for the Type No. 2 of example D. These joints would have the same joint E if they had been spot radiographed. Full Radiography was a waste. The Code does this to discourage more than one level of radiography between butt welded joints. It is unlikely you will ever see actual cases like examples C and D. LONGITUDINAL STRESS / CIRCUMFERENTIAL JOINTS At this point we will begin discussing the Longitudinal Stress that causes stress around vessel walls and in Circumferential Joints. Commonly referred to as the girth.
Longitudinal stresses tend to tear the vessel into two pieces, separate shell courses or pop off the head. This is the second calculation required for a shell. For our examples we will use a vessel with two shell courses and ellipsoidal heads on both ends. Keep in mind that we are calculating the stresses on Circumferential Joints (Girth Joints); those which are affected by longitudinal stress. Longitudinal stress rarely determines the required thickness or allowed pressure on a shell. The reason is; the stress created by internal pressure in the longitudinal direction is only half that of in the circumferential direction. Normally circumferential stress governs and determines the required thickness or pressure allowed for a shell. The Joint Efficiency for these Categories of butt welds may be taken directly from Table UW-12 based on their Type. Radiography applies when they are of Type No. 1 or Type No. 2. RT does not apply to Types 3, 4, 5 and 6.
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API 510 Module PART UW - WELDING Shells Example A. Two seamless shell courses closed with ellipsoidal heads without radiography applied to circumferential Type No. 1 butt joints. The E used for longitudinal stress calculations of both shell courses is .70. E = .70
ALL JOINTS E = .70 CATEGORY B NO RT TYPE No- 1 E = .70
Example B: Two seamless shell courses closed with ellipsoidal heads with spot radiography applied to circumferential Type No. 1 butt joints. The E used for the calculations of both the shell courses is .85. ALL JOINTS CATEGORY B
E =. 85 E =. 85
SPOT RT TYPE No. 1 E = .85 49 FEET OF WELD TOTAL
Example C: Two seamless shell courses closed with ellipsoidal heads with full radiography applied to circumferential Type No. 1 butt joints. The E used for the calculations of both the shell courses is 1.0.
E = 1.0 E= 1.0
ALL JOINTS CATEGORY B RT TYPE No. 1 E= 1.0
If the above vessels had been made using Type No. 2 joints the joint efficiencies would be .65, .80 and .90 respectively based on the same radiography,
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API 510 Module PART UW - WELDING
Stress In Heads The last E to consider is the one used to calculate thickness required or pressure allowed for formed and forged heads. Internal pressure creates stress that acts to rupture the walls of heads.
Each kind of head has a Code formula for its calculations. Two classes of heads are joined to vessels by circumferential joints. One class is joined to the shell with a Category B or C circumferential butt joint; these are heads that have a flange. Some examples are Torispherical, Ellipsoidal and forged Flat heads. Forged Flat heads are joined by Category C circumferential joints and are treated the same for determining their E as the other two. The other class is joined to the shell with a Category A butt joint; it is a Hemispherical head with out a flange. The first examples have ellipsoidal heads that may be joined to the shell using a Type No. 1 or Type No. 2 joint. It is also representative of a torispherical head since both have a flange (skirt). The ellipsoidal head forms a Category B joint with the shell and is seamless. The second examples have formed hemispherical heads without a flange. The joint formed by the attachment of the hemispherical head to the shell is a circumferential Category A. Hemispherical heads may be joined using either a Type No. 1 or a Type No. 2 joint provided no service restriction from UW-2 applies. If a service restriction applies the Category A butt joint must be of Type No. 1. The shell used in all examples is over 24 inches in O.D. and over 5/8 inch thick. Per Table UW-12 only Type No. 1 or Type No. 2 joints are allowed for these conditions. When seamless heads, that have a flange (skirt), are attached to shells a Category B joint is created. This Category B joint will have a joint efficiency based on its Type and the amount of radiography that was applied.
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API 510 Module PART UW - WELDING
Stress In Heads
This joint efficiency will not be used in the calculation of the head's required thickness or its pressure allowed. This E is used in the longitudinal stress calculations for the shell. The Category B joint may be thought of as belonging to the shell. For a seamless head which is joined by a Category B butt joint there are only two possibilities for the E used in the head calculations. The E used will either be 1.0 or .85. The E is determined based on the requirements of UW-12 (d). The question then becomes has Spot RT been applied to the Category B butt joint. If it has the E is 1.0. If it has it not the E is .85. Example A: Category B butt joint of Type No. 1 or Type No. 2 has not received Spot RT. E = .85 for the head's thickness or pressure calculation. The shell's longitudinal stress calculation E will be .70 or .65 depending on which Type of joint was used. Shell E = .70 or .85 Category B No RT HEAD E = .85
Example B: Category B butt joint of Type No. 1 or Type No. 2 has received Spot RT. E = 1.0 for the head's thickness or pressure calculation. The shell's longitudinal stress calculation E will be .85 or. 80 depending on which Type of joint was used.
Shell E = .85 or .80 Category B Spot RT Head E = 1.0
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API 510 Module PART UW - WELDING
Heads The last case to consider for seamless heads that form a Category B or C joint with a shell is when the joint is of Type No. 3, 4, 5 or 6 of Table UW-12. Since these types are not considered radiographicable by the Code the Spot RT cannot be applied. UW-12 (d) states that the head under this condition shall always be calculated using E = .85. The shell's longitudinal calculations would use an E based on the Type No. of the joint and this E would then come directly from Table UW-12. The most common mistake in the calculation of seamless heads attached by Category B joints is the use of the E found in table UW-12 based on the type of joint. That E belongs in Longitudinal shell calculations. The E used for the seamless head is based only on the application of Spot RT. If Spot RT has not or cannot be performed (as is the case for Types 3, 4, 5, or 6) an E of .85 shall be used. If it can and has E = 1.0. END OF STORY. Until they change the Code again! The last formed head of concern is the Hemispherical. A hemispherical head formed from a solid piece of plate without a flange is only seamless as long as it is lying on the shop floor; when welded to another component such as a shell it now has a Category A joint. Read UW3 (a)(1) again to confirm this statement. The Category A joint formed after welding to a shell belongs to the hemispherical head. The rules regarding seamless shells and heads in UW- 12 (d) specify that the spot radiography of UW-11 (a)(5)(b) must be applied to use an E of 1.0 for a seamless head's thickness or a shell's circumferential stress calculation. Since our hemispherical head will always have a Category A joint (seam) the conditions of UW-12 (d) do not apply. The bottom line is that a formed hemispherical head without a flange can never be seamless. Spot radiography on the Category A joint does have a use if the hemispherical head is welded to a seamless shell or to a shell in which all Category A & D butt joints have been fully radiographed. The shell's circumferential stress could then be calculated using an E of 1.0.
ATTENTION - ATTENTION HEMISPHERICAL HEADS ONLY CONTAIN CATEGORY A JOINTS.
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API 510 Module PART UW - WELDING Heads The following examples will use a formed hemispherical head and a seamless shell. Example A: Seamless shell course with a hemispherical head. Spot RT has not been applied. The Category A joint may be a Type No. 1 or a Type No. 2 of Table UW-12. E =.65 or .70.
HEMI E =.70 Or E =.65
SEAMLESS SHELL E = .85 CATEGORY A NO RT
Example B: Seamless shell course with a hemispherical head. Spot RT has been applied. The Category A joint may be a Type No. 1 or a Type No. 2 of Table UW-12. E = .80 or .85.
HEMI E =.85 OR E =.80
SEAMLESS SHELL E =1.0 CATEGORY A TYPE No. 1 OR 2 SPOT RT
Example C: Seamless shell course with a hemispherical head. Full RT has been applied. The Category A joint may be a Type No. 1 or a Type No. 2 of Table UW-12. E =.90 or 1.0.
HEMI E = 1.0 OR E =.90
API 510
SEAMLESS SHELL E = 1.0 CATEGORY A TYPE 1 OR 2 FULL RT
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API 510 Module PART UW - WELDING
Summary Of Part UW The main points of Part UW for the API Exam are the following: 1.
Service Restrictions apply only to certain vessels.
2.
Joint category is based on where in a vessel a joint is located.
3.
Type of joint is based on how the joint was fabricated.
4.
There are three different applications for Efficiency A. Longitudinal Joint E, the only Joint E used for calculations in the Exam. B. Circumferential Joint E, not used for calculations in the Exam but often mistakenly used with seamless components. C. Seamless Component E (Heads, Shells and Nozzles) or their equivalent components which have had full RT applied to all of their Category A and D Type No. 1 butt joints.
The Spot RT described in UW-11 (a)(5)(b) is used for Seamless or equivalent components. This spot radiography is different than applying spot radiography to the entire vessel. Typically Exam problems will be stated in this manner 'A seamless torispherical head is being replaced due to corrosion. The head has an O.D. of 60 inches and is joined by a Type No. 1 joint . UW-11 (a)(5)(b) has been applied'. The statement that UW-11 (a)(5)(b) has been applied will be the only thing you need to determine the E to use in the head's calculation. This can also be stated as the vessel's Data plate is stamped RT 2. RT markings and their meanings will be explained in the coverage of Paragraph UG-116 REQUIRED MARKING. This will also serve as a review of paragraphs UW-11 and UW-12.
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API 510 Module PART UW - WELDING Exercises UW-12 Determine the efficiencies for calculation of the following vessel parts.
SEAMLESS SHELL HEMI
ELLIPTICAL CATEGORY D FILLET
SEAMLESS SPOT RT NO RT TYPE 2 - CATEGORY B TYPE 1 – CATEGORY A SPOT RT Torispherical
1. 2. 3. 4. 5. 6. 7.
API 510
Seamless Shell Circ. Stress Calculations E=1.0 Seamless Shell Long. Stress Calculations E=.80 Hemispherical Head Calculations E=.85 Seamless Ellipsoidal Head Calculations E=1.0 Seamless Torispherical Head Calculations E=.85 Seamless Communicating Chamber Circ. Stress Calculations E=.85 Seamless Communicating Chamber Long. Stress Calculations E=.65
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API 510 Module PART UW - WELDING
Exercises UW-12
HEMI
ELLIPTICAL CATEGORY D BUTT WELD FULL RT SPOT RT TYPE 2-CATEGORY B SPOT RT
TYPE 1-CATEGORY A FULL RT
Torispherical
1. 2. 3. 4. 5. 6. 7.
API 510
Seamed Shell Circ. Stress Calculations E = 1.0 Seamed Shell Long. Stress Calculations E = .80 Hemispherical Head Calculations E = 1.0 Seamless Ellipsoidal Head Calculations E = 1.0 Seamless Torispherical Head Calculations E = 1.0 Seamless Communicating Chamber Circ. Stress Calculations E = 1.0 Seamless Communicating Chamber Long. Stress Calculations E = .80
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API 510 Module PART UW - WELDING
UW-40 Procedures for Postweld Heat Treatment Paragraph UW-40 gives the particulars of postweld heat treatment required in the applicable part in Sub-section C. This paragraphs list the methods that are acceptable to the Code. For instance, UW-40 (a)(1) says that heating the vessel as a whole in an enclosed furnace is preferable and should be used if practical. Heating the vessel in more than one heat in a furnace can be done, but an overlap of the heated sections shall be at least five (5) feet. Also, the portion outside the furnace shall be shielded. Vessels can be heat treated as sections, joined then locally heat treated at the circumferential joints. Heat can be applied internally and the vessel externally insulated as long as the given considerations are met. The minimum temperatures for post-weld heat treatments are given in Table UCS-56. It must be remembered that this paragraph applies to the vessel 'm a shop new construction setting, Ale banding described here must be applied all the way around the vessel and include any nozzle's welds and the like. The API 5 1 0 allows the use of Local Post Weld Heat Treatment that does not require the entire circumference of the vessel be included in the heat treatment. This of course is aimed at field repairs. In the API 5 1 0 Code the procedure is required to be reviewed by a qualified engineer. There should be preheat applied in accordance with the material of construction. A distance of not less than two times the base metal thickness on each side of a welded repair is required to be locally post weld heat treated; it must include any nozzles or attachment welds in the local postweld heat treatment area. A suitable number of thermocouples (at least two) shall be used to monitor the temperature during treatment.
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UCS-56 Requirements for Postweld Heat Treatment In the beginning of this paragraph it is stipulated that before applying the content of the paragraph satisfactory weld procedure qualifications of the procedures to be used shall be performed in accordance with Section IX. Included are the requirements for the condition of postweld heat treatment or lack there of, in the weld procedure. The exemption given in tables UCS-56 and UCS-56.1 are not permitted under some circumstances. If post weld heat treatment is a service requirement as set forth in UCS-68 or welding is being done on ferritic materials greater than 1/8" thick by the electron beam process are two examples. Maximum furnace temperature at the time vessel or part is placed in it shall not exceed 800°F. The rate at which the heating shall be increased is specified. Variation in the part temperature shall be held at or above the specified temperature for the period of time given in Table UCS-56 or UCS-56.1. The furnace design cannot allow the flames to touch the part or vessel. The furnace must be cooled at a given rate. The next important aspect is welded repairs. Here repairs performed on P-No. 1 Groups Nos., 1, 2, and 3 materials and P-No 3 Groups Nos., 1, 2, and 3 materials and weld metals used to join these materials may be made after final PWHT, but prior to final hydrostatic test, without additional PWHT, provided PWHT is not a service requirement. The depth of the repair based on the material P-number is restricted, non-destructive testing after removal of the defect is required. An approved welding procedure is required and the repair must be made using the shielded metal arc process with low hydrogen electrodes. The electrodes must be properly handled and the weave bead used is restricted to four electrode core diameters. There are two repair techniques described. One method for P-1 materials. The second method can be used for P-No 1 or P-No 3 materials restricted to the stated group Nos. P-No 3 materials can only be repaired using the Half Bead weld repair and Weld Temper Bead reinforcement technique. The description of this procedure is almost identical to the one in the API 510 Code. Preheats temperatures and preheat maintenance times are some what different.
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PART UG GENERAL REQUIREMENTS API 510 Module PART UG - GENERAL REQUIREMENTS
Objectives Student should understand and be capable of applying the following concepts. A.
Calculate the required thickness or pressure allowed on cylindrical shells using formulas based on inside or outside radius (Part MAWP).
B.
Calculate the thickness required or pressure allowed for 2 to 1 Ellipsoidal, Standard Torispherical and Hemispherical heads (Part MAWP).
C.
Calculate the thickness required for Circular Unstayed Flat heads (Part MAWP).
D.
Calculate the Thickness of Shells and Tubes Under External Pressure.
E.
Determine Maximum Allowable Working Pressure for a Vessel.
F.
Calculate Hydrostatic and Pneumatic Test pressures. Describe Procedures for Tests.
G.
Size Fillet Welds at Openings.
H.
Determine if Reinforcement of an Openings is required.
1.
Requirements for Name Plates and their markings.
J.
Requirements for Material identification and Inspection.
K.
Types of Data Reports. information contained in Data Reports.
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-27 Internal Pressure Cylindrical Shells MATHEMATICAL PROOF OF THE FORMULAS BEING EQUIVALENT Example 1. Given a cylindrical vessel shell with the following variables, solve for pressure allowed in the cylinder using both formulas. P= T= S= E= R= Ro =
? 0.500" 15,000 psi 1.0 18.0" 18.5" SEt
UG-27(c)(1) P=
15,000 x 1.0 x 0.500
7500
=
=
= 409. 8
psi R + 0.6t
18.0 + (0.6 x 0.500)
SEt App 1 (1 - 1) P=
18.3
15,000 x 1.0 x 0.500 =
7500 =
=
409.8
psi R. - 0.4t
18.5 - (0.4 x 0.500)
18.3
If calculations for a thickness required are being made the same approach may be taken. The next step in this instruction will be to apply cases where this is an appropriate option. Our next example will deal with corrosion. Example 2. A cylindrical vessel shell has been found to have a minimum thickness of .353". Its original thickness was .375". May this vessel remain in service given the following variables? P= T= S= E= R=
300 psi 0.353" 13,800 psi .85 12.0” +(.375-.353) = 12.022 This adjusts is for the corroded inside
R=
12.0” +0.375 (orig. t)=12.375" This finds the original outside radius
radius
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API 510 Module PART UG - GENERAL REQUIREMENTS UG-27 Internal Pressure Cylindrical Shells Case 1. Inside Radius for pressure allowed using UG-27(c)(1). SEt UG-27(c)(1) P = psi
13,800 x .85 x .353 =
R+0.6t
4140.69 =
12.022 + (0.6 x .353)
=
338.46
=
338.46
12.2338
Case 2. Outside Radius for pressure allowed using App. 1 (1-1) SEt App 1 (1 - 1) P = psi
13,800 x .85 x .353 =
R 0 - 0.4t
4140.69 =
12.375 - (0.4 x .353)
12.2338
ANSWER: YES 338.46 psi > 300 psi
Important adjustments must be made for both approaches. The case of inside radius requires an increase of the inside radius due to corrosion. If the outside radius is not given, the original thickness must be added to the original inside radius to determine the outside radius; but the thickness used in the pressure allowed calculation of App: 1 (1 - 1) must be the existing thickness given in the stated problem. As can be seen from the above examples either method yields the same results as long as the rules are followed properly. The method you use is a matter of personal preference. These adjustments, along with others such as static head, add to the difficulty of otherwise simple arithmetic. In every case, careful work is a requirement for successful calculations. As a check on the calculations for pressure allowed, calculations for thickness required can be performed. Our next examples are used to determine if the vessel may operate at the 300 psi desired and be in compliance with the Code.
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UG-27 Internal Pressure Cylindrical Shells Example Using the same variables as Example 2 above, calculate the thickness required for the shell using 300 psi. Case 1. Inside Radius for thickness required using UG-27(c)(1). PR UG-27(c)(1)
t =
300 x 12.022 =
SE - 0.6P
3606.6 =
13,800 x .85 - (0.6 x 300)
= .3122" 11550
Case 2. Outside Radius for thickness required using App: 1 (1-1) PR 0 App 1: (1 - 1)
t =
300 x 12.375 =
SE+ 0.4P
3712.5 =
13,800 x .85 + (0.4 x 300)
= .3132” 11,850
ANSWER: .3122" <.353" or .3132" <.353" The slight difference in the thicknesses required has to do with the inside radius increasing to 12.022 inches from the original 12.0 inches due to corrosion. Both of the above answers are correct using 300 psi. By increasing the pressure used in the thickness calculations to 338.46, the thicknesses required are identical for both formulas. For the next part of our instruction we will begin doing some simple shell calculations using UG-27 Thickness of Shells under Internal Pressure. In this paragraph, formulas are given for the calculation of minimum thickness and maximum pressure for cylindrical and spherical shells. Special attention must be paid to circumferential stress within the cylindrical shell. This stress category normally will determine the minimum thickness or maximum working pressure of the vessel.
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Let's do a simple shell calculation now. We will use a shell which is seamless. You may find the following approach helpful in keeping track of the data. As the problems become more difficult, it becomes harder to track the variables if you are not organized. 1.
Make a simple drawing of the vessel or head you are calculating values for. This helps identify the variables the next step.
2.
List what is required to know. We will call these givens. These will come from the stated problem.
3.
State all the code paragraphs that apply, i.e., UG-27, UG-22, etc,
Drawing:
Givens: t= P= R= S= E= etc. Code Paragraph UG-27 (c) (1) SEt P =
Etc. R + 0.6 t
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UG-27 Internal Pressure Cylindrical Shells Problem # 1 Find the Maximum Allowable Working Pressure (MAWP) of a 12 inch inside diameter shell. This vessel will be subjected to an internal pressure and will operate at a temperature of 700 degrees F. This shell is seamless carbon steel and has an allowable stress value of 16,600 psi. Its wall thickness is .406”. No corrosion is expected. Circumferential welds are not considered in this problem. This is a demonstration of formula UG-27(c)(1) and does not reflect the choosing of a joint efficiency. Drawing: t=.406” I.D.=12.0”
Givens: P= ? t= .406* R= 6.0 Remember this formula uses Radius not Diameter. S= 16,600 psi E= 1.0 From UG-27 (c) (1) Circumferential Stress SEt P= R + 0.6 t 16,600 x 1.0 x.406 P=
6739.6 =
(6.0) + ( 0.6 x .406)
= 1079.44 psi 6.2436
*Mill Under tolerance must be considered when designing a vessel shell using pipe. For most pipe, it is ± 12.5 % of the nominal thickness. This will usually require ordering the next schedule up to meet a required thickness. The example above could arrive with a thickness of as little as .355”
API 510
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-27 Internal Pressure Cylindrical Shells Problem # 2 Find the minimum required thickness of a cylindrical shell designed for a working pressure of 100 psi at 350 degrees F. The shell's inside radius is 2'-0". The longitudinal joint is category A (UW-3), type 1 (table UW-12) - no radiography was performed. The shell is made of SA-515 grade 60 carbon steel rolled plate with an allowable stress of 15,000 psi. The vessel is in water service. Again, circumferential welds are not considered for the sake of simplicity. Drawing: t=? 48.0”
Givens: t= P= R= S= E=
Cat. A Type 1
? 100 psi 24" 15000 .70 (Table UW-12)
From UG-27 (c) (1)
Circumferential Stress
PR t= SE - 0.6 P 100 x 24
2400
t=
= (15,000 x .70)-(0.6 x 100)
= .2298” 10440
Use .250" per UG-25 (d), UCS-25?
API 510
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-27 Internal Pressure Cylindrical Shells We have now calculated the pressure allowed on a seamless shell in Problem #1. We have also found the thickness required of a seamed, rolled plate shell in Problem #2. To this point we have not considered a circumferential weld joint. The next problem will consider joining together two courses of seamed and rolled plate to make one shell. Problem # 3 Determine the minimum required thickness of a cylindrical shell designed for an internal pressure of 50 psi at a design temperature of 100 degrees F. No corrosion is expected. The shell is made of two courses butt welded circumferentially using Type 1 welds which have been spot radiographed per UW-11(a)(5)(b). The shell long joints are butt welded also and are Type 1, Category A fully radiographed. The material is SA-515 grade 70, stress allowable is 17,500 psi. The inside diameter is 10'-0". Both heads will later be joined to the shell and will have Spot RT in accordance with UW-12(a) and UW-11(a)(5). This problem will require us to consider two different cases in order to come to the solution. First we will work the problem to solve for the thickness required to resist longitudinal stresses. Second to resist circumferential stresses. Are you clear on the difference between the two? It's easy to be confused. The Longitudinal Stress is the stress that acts to pull apart two shell courses or pop a head off of the end of a vessel. It creates stress in the shell and welds around a vessel. Circumferential Stress can be thought of as trying to split a shell along its length. It creates stress in the shell and welds along the length of the vessel. Circumferential Stress is normally the controlling stress for thickness or pressure calculations.
API 510
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-27 Internal Pressure Cylindrical Shells Case Study 1 Circ. Joint (Longitudinal Stress) Drawing:
t=? 10’ 0” I.D.
Cat. B Type 1 Spot RT
Givens: t= ? P= 50 psi D= 10'-0" R= 5'-0" = 60” S= 17500 E= .85 from table UW-12 UG-27(C)(2) PR t = 2 SE + 0.4 P 50 x 60
3000
t =
= (2 x 17,500 x .85) + (0.4 x 50)
API 510
Page 98 of 310
= .1007 29770
API 510 Module PART UG - GENERAL REQUIREMENTS
UG-27 Internal Pressure Cylindrical Shells Case Study 2 Long Joint (Circumferential Stress) Drawing:
t=? 10’ 0” I.D.
Givens: t= ? P= 50 R= 60" S= 17500 E= 1.0 (UW-12(a) and UW-11(a)(5))
Cat. A Type 1 Full R.T.
From UG-27 (c) (1) PR t= SE - 0.6 P 50 x 60
3000
t=
= (17,500 x 1.0) - (0.6 x 50)
Q.
API 510
= .1717” 17470
The thickness required above is not double the thickness required for the Circumferential joint. Why?
Page 99 of 310
API 510 Module PART UG - GENERAL REQUIREMENTS
UG-27 Internal Pressure Cylindrical Shells Exercises Use the Over-view portion of UG-27 starting on page 7 to determine formulas and use the Part UW section to determine joint efficiencies. 1. Calculate the thickness required for a seamless shell made of SA-106 gr. B pipe. The 0.D. is 12.75 inches. UW-11(a)(5)(b) has been applied. The shell will operate at 500 psi. The stress allowed on the shell material is 15,000 psi. Givens: t= P= S= E= R or R 0 =
Drawing:
State Code Paragraph(s) and Formula(s):
2. What is the maximum allowed working pressure on a shell made of SA-515 gr. 60? The shells inside radius is 52 inches, and the shell's thickness is .850 inches. The allowable stress for the shells material is 15,000 psi at 500 °F. The joint efficiency of the shells Category A joints is 1.0 . Givens: t= P= S= E= R or R 0 =
Drawing:
State Code Paragraph(s) and Formula(s):
API 510
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API 510 Module PART UG - GENERAL REQUIRENIENTS UG-32 Internal Pressure On Formed Heads Overview There are three types of calculations for formed heads listed in the API 510 Body of Knowledge: Ellipsoidal, Torispherical and Hemispherical. The candidate is responsible for performing calculations for thickness required and pressure allowed in all cases. The formulas that will used will all come from paragraph UG-32. The variables change somewhat from type to type. A sketch and the formulas for thickness of each kind are below. ELLIPSOIDAL PD t= 2SE – 0.2P
I.D. of Skirt
TORISPHERICAL
0.885PL
Knuckle Radius
SE - 0.1P
Outside Radius
t=
L Inside Crown Radius
HEMISPHERICAL
L
PL t= 2SE - 0. 2P
API 510
Sperical Radius Inside Diameter
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API 510 Module PART UG - GENERAL REQUIREMENTS UG-32 Formed Heads Pressure On The Concave Side There are five geometry's listed in UG-32. You will be responsible for the calculations of three: Hemispherical, Ellipsoidal and Torispherical. Givens: P= S= E= E= L= L= O.D.= D= t=
The same pressure and stress values will be used for all heads.
100 psi 17500 SA-515 Gr70 plate 650 degrees F. .85 for spot RT of Hemispherical head joint to shell 1.0 for seamless heads ( Ellipsoidal and Torispherical) 48" for the inside spherical radius for the hemispherical head 96" for the inside crown radius of the torispherical head 96" for the torispherical head 96" inside diameter of the ellipsoidal and hemispherical heads Required wall thickness, inches
Problem # 1 Given the above data find the required thickness of a seamless ellipsoidal head. Drawing: ELLIPTICAL
From UG-32 (d) PD 96.0”
t= 2SE - 0.2 P 100 x 96
9600
t=
= (2 x 17,500 x 1.0) - (0.2 x 100)
API 510
= .2744” 34980
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-32 Formed Heads Pressure On The Concave Side Problem # 2 Using the same data, calculate the required thickness of a hemispherical head that does not have a straight flange.
Drawing: HEMISPHERICAL L 48” t=? 96” I.D.
From UG-32(f) PL t= 2SE - 0.2P
Solving for t:
100 x 48
4800
t=
= (2 x 17,500 x 0.85) - (0.2 x 100)
API 510
Page 103 of 310
= 0.1614” 29730
API 510 Module PART UG - GENERAL REQUIREMENTS
UG-32 Formed Heads Pressure On The Concave Side Problem # 3 Determine the required "t "of this torispherical head. (These are also called ASME flanged and dished heads, by the way). This head has an O. D. equal to its inside crown radius AND the knuckle radius is equal to 6% of its inside crown radius. Drawing: F&D (TORISPHERICAL)
L=96.0” t=?
From UG-32 (e)
O.D. 96.0”
0.885PL t= SE - 0.1P Solving for t: 0.885 x 100 x 96
8496
t=
= (17,500 x 1.0) - (0.1 x 100)
API 510
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= .4857” 17490
API 510 Module PART UG - GENERAL REQUIREMENTS UG-32 Exercises Use the overview portions of UG-32 to determine the formulas and use Part UW to determine the joint efficiencies. 1. Calculate the required thickness of a 2 to 1 Ellipsoidal head with an inside, diameter of 48 inches. The vessels will have a MAWP of 350 psi and will be in lethal service. The joint used to join the head to shell will be a Type No. 2 from Table UW-12. The stress allowed on the head's material will be 15,000 psi. Givens: t= ? P= S= E= D=
Drawing:
State Code Paragraph(s) and Formula(s):
2. A Torispherical head has corroded to a thickness of'.353”; its inside crown radius is 56 inches. The head's material has a stress allowable of 13,800 psi at 500°F. The shell is seamless and the spot radiography of UW-11 (a)(5)(b) has been applied to the vessel. Can this head remain in service at 100 psi per Code? Givens: t= ? P= S= E= L=
Drawing:
State Code Paragraph(s) and Formula(s):
API 510
Page 105 of 310
3. A Hemispherical head is being considered as a replacement on a vessel with a MAWP of 200 psi. The head's inside diameter will be 64 inches. What would be its required thickness if the head's material has a maximum allowable stress of 17,500 psi? The Category A type 1 joint that attaches the head will be spot radiographed. Givens: t= P= S= E= L=
Drawing:
State Code Paragraph(s) and Formula(s):
4. What would the required thickness for an Ellipsoidal head he given the same variables as used in Problem # 3 above? The Category B weld that will attach this head would not have UW-11 (a)(5)(b) applied. Givens: t= P= S= E= D=
Drawing:
State Code Paragraph(s) and Formula(s):
API 510
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-34 Unstayed Flat Heads And Covers (Circular) Overview Circular flat heads are the only kind of flat heads that are included in tile API 510 Exam. These types of heads are shown in Fig. UG-34. Only those attached by welding will be on the test. Only thickness calculations are presently required per the API 510 Body of Knowledge. Some flat heads are attached by fillet welds and some have a flange and are attached by butt welds. All attachment welds are of Category C per UW-3. The figures below represent only two of several allowed configurations. Forged Flat Head to Shell or Nozzle Cat. C Fillet Welds
Cat. C Butt Weld
Those attached by Fillet welds and those attached by other than Types Nos. 1 or 2 are not radiographical by the Code rules. Seamless circular flat heads which are butt welded must follow the rules for circumferential butt welds contained in UW-11 and UW-12(d) when choosing the Efficiency for their thickness calculations. These heads are treated in the same way as formed heads for their E used in calculations. If a flat head is attached using fillet welds. it cannot be radiographed, and if the flat head is seamless the E used to calculate its thickness will always be 1.0 .
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If the Circular Unstayed Flat Head were constructed of two half moon pieces using a butt weld, the head would then contain a Category A joint per UW-3. The Type of butt weld and the amount of radiography would determine the E; the resulting E would be the joint efficiency used in the head's thickness calculation.
Category A Butt Weld
The only formula that will be used for the calculations on the test is the one of UG-34(c)(2) #1. Thickness required will be the only type of problem asked according to the API 510 Body of Knowledge.
t=d
CP/SE
The definitions of the variables in the formula are shown in the figures of Figure UG-34. UG-34. The d is the inside diameter of a head or shell as given in each figure; the C is a factor that depends on the method of attachment, shell dimensions and other factors listed in UG-34 (d). The E was discussed above; t and P are thickness and pressure. The C can get a little tricky in figures (e), (f), (g) and (b-2) of Fig. UG-34. In these four figures there is a note that states: C = 0.33 x m; where in the other figures it is stated that C will equal a specific value, 0.17 etc. also all figures list a minimum C value. Figures (e), (f), (g) and (b-2) require an extra calculation to determine the C before the head's thickness can be calculated using the formula above. Again that calculation is C = 0.33 x m. The term m is defined in the nomenclature of UG-34 as being the thickness required of the shell divided by the actual thickness of the shell.
tr m= ts IF this type of problem is given, stating only the actual thickness of the shell, a thickness required calculation using the formula of UG-27 (c)(1) must be performed. The E used will be 1.0 for the shell’s required thickness calculation. The inside diameter of the shell will be equal to the d of the flat head, and the shell's material allowable stress must be given. The pressure will be the same as required for the flat head. The following examples will demonstrate the operations required.
API 510
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API 510 Module PART UG - GENERAL REQUIREMENTS UG-34 Unstayed Flat Heads And Covers (Circular) Problem # 1 A Seamless Flat Unstayed Circular Head having t diameter of 10 inches is attached to a cylindrical shell similar to Figure UG-34 (e). The vessel will have a MAWP of 100 psi at 400 degrees F; the head and shell are made of SA-515 Gr. 70 carbon steel with an allowable stress of 17500 psi. The shell's thickness is .375". Corrosion is not expected. Find the minimum thickness of this head. Shell t=.375” t=? Drawing: Givens: Shell t= Head t= P= d= S= E= C=
.375 ? 100 psi 10.0 in 17500 @ 450°F 1.0 For any seamless head attached by fillet welding. 0.33 x m
From: UG-34(c)(2)
t = d CP/SE
Step 1. Calculate the thickness required of the shell using the UG-27(c)(1) circumferential stress formula.
PR t= SE - 0.6 P 100 X 5 t = (17,500 x 1.0) -(0.6 x 100)
API 510
500 =
= .02866” 17,440
Page 109 of 310
Step 2. Calculate the value of m. tr .02866 m= = = .076 ts .375
Step 3. Calculate the value of C. C = 0.33 x in C = 0.33 x .076 =.025
Now since the minimum C can be per figs. (e) (f) and (g) is 0.20 use this in the calculation of the head. Step 4. Calculate the required thickness of the flat head using the formula of UG-34(c) (2).
t = d CP/SE t = 10
0.20x10 / l7500 X 1.0
t = 10
20 / 17500
t = 10 .0011428 t = 10 x .0338053 = .3380" ANSWER: t = .338" minimum Wasn't that fun
API 510
Page 110 of 310
API 510 Module PART UG – GENERAL REQUIREMENTS UG-34 Unstayed Flat Heads And Covers (Circular) Problem # 2 A Forged Flat Circular Unstayed Head has been attached to a shell similar to fig. (b- 1) of Fig.UG-34. The circumferential weld attaching the head to the shell is a single welded butt joint with a backing strip which remains in place, The Data Report for the vessel indicates that no radiography has been performed. The heads inside diameter is 26 inches. The vessel's name plate indicates a MAWP of 150 psi. The allowable stress of the forged heads material is 15,000 psi per the Data Report. Uniform corrosion has occurred to this head leaving the flat part with a minimum thickness of 1.252". Can this vessel remain in service without repair or replacement of the heads?
Drawing: Givens: t= ? P= 150 psi d= 26 " S= 15,000 psi E= .85 per UW-12(d). C= 0.17 per fig. (b-1) From UG-34(c)(2):
t = d CP/SE t = 26 0.17 x l50 / 15,000 x .85
t = 26
25.5 / 12,750
t = 26 .002 t = 26 x .0447213 = 1.16275” 1.252” > 1.16275" ANSWER: YES
API 510
Page 111 of 310
API 510 Module PART UG - GENERAL REQUIREMENTS
UG-34 Unstayed Flat Heads And Covers (Circular) Exercises Use UG-27, UG-34 and part UW to determine the formulas and efficiencies. 1. A flat head similar to the one in fig. (b-2) of Fig. UG-34 is attached to a shell using a double welded butt joint. The entire vessel meets the requirements of UW-11(a)(5)(b). The center portion of the flat head has corroded down to an unacceptable thickness. What will be the head's thickness required after build up by welding? The shell has a thickness of 1/2". The shell and head skirt have an inside diameter of 42 inches. The head's material has a maximum allowable stress of 13,800 psi and the shell's material has an allowed maximum stress of 15,000 psi. The vessel's Name Plate is marked with a MAWP of 75 psi @ 350°F. Givens:
Drawing:
ts= t= P= Ss= Sh = Es = Eh = D= State Code Paragraph(s) and Formula(s):
API 510
Page 112 of 310
2. The unit engineer has questioned the wisdom of repairing the head in Problem # 1 and thinks that a flat head attached similar to UG-34 (f) would offer some advantages for the future plans in the unit. His calculations specify that the new flat head would require a thickness of 1.375”. Do you agree?
Givens.
Drawing:
ts= t= P= Ss= Sh= Es= Eh = d= State Code Paragraph(s) and Formula(s):
API 510
Page 113 of 310
API 510 Module PART UG - GENERAL REQUIREMENTS UG-28 Thickness Of Shells And Tubes Under External Pressure Overview External calculations depart significantly from internal calculations simply because under external pressure the vessel is being crushed . Internal pressure wants to tear the vessel apart. Because of the crushing or buckling load, the Length the Outside Diameter and the Thickness of the vessel are important. External pressure problems are based on the thickness of the shell to the outside diameter ratios. There are two types of external pressure calculations required on the test; one type is when the O. D. (D o ) to thickness ratio (t) is greater than 10 and the other type when it is less than 10. This type of problem is best approached from the in-service standpoint with an existing vessel. In order to solve these types of problems two charts will be required. The first chart is used to find a value called Factor A and then Factor A is used to find a Factor B in the second chart. The value of Factor B found is the number needed to solve the problem using the formula given in paragraph UG-28 (c)(1) step 6. The charts will be supplied with the test question as they are not found in Section VIII Division 1. The following is the step by step solution to the Pressure Allowed on an existing vessel of a known thickness with a D o to t ratio greater than 10. Problem: A vessel is operating under an external pressure of 250 psi. The operating temperature is 500°F. The outside diameter of the vessel is 40 inches. Its length is 70 inches. The vessel's wall is 1.25 inches thick and is of SA-515 gr.70 plate. Its specified minimum yield is 38,000 psi. Does this thickness meet Code requirements? Givens: P= 250 psi Temp. = 500°F t= 1.25 L= 70 inches D o = 40 inches
API 510
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t = 1.25” 40” D o 70” LENGTH From UG-28 (c) Cylindrical Shells and Tubes. The required minimum thickness of a shell or a tube under external pressure, either seamless or with longitudinal butt joints, shall be determined by the following procedure. (1) Cylinders aving
D o values > 10 t Testing to see if this paragraph applies: Do = 40” t = 1.25” Do
40 =
t
= 32 1.25
Step 1. Our value of Do is 40 inches and L is 70 inches. We will use these to determine the ratio of: L
70 =
Do
= 1. 75 40
Step 2. Enter the Factor A chart at the value of 1.75 determined above. Step 3. Then move across horizontally to the curve Do / t = 32. Then down from this point to find the value of Factor A which is .0045. Step 4. Using our value of Factor A calculated in Step 3, enter the Factor B (CS-2) chart on the bottom. Then vertically to the material temperature line given in the stated problem (in our case 500°F). Step 5. Then across to find the value of Factor B. We find that Factor B is approximately 13000. Step 6. Using this value of Factor B, calculate the value of the maximum allowable external pressure Pa using the following formula: 4B Pa = 3(Dot) 4x13,000 Pa =
52,000 =
3(32)
= 541.66 psi 96
541.66 psi > 250 psi API 510
ANSWER: YES Page 115 of 310
API 510 Module PART UG - GENERAL REQUIREMENTS UG-28 Thickness Of Shells And Tubes Under External Pressure Overview UG-28(c)(2) For vessels having an Do /t < 10: Problem: A 78" long pipe of SA-106 Gr. B is going into service under external pressure. The pipe has a minimum yield of 35,000 psi and an allowable stress of 14,400 psi at design temperature. This pipe has an O. D. of 4.5" and a wall thickness of 0.531". The operating temperature will be 700°F with an external pressure of 1600 psi. Do these combinations of length, thickness, temperature and pressure meet Code requirements? Givens: P= 1600 psi emp. = 700°F t= .531” L= 78” Do= 4.5”
L =78”
Do = 4.5" t = .531” Check ratio of Do / t = 4.5 / 0.531 = 8.47 8.47<10 Do / t < 10 Therefore, use UG-28(c)(2) Step 1. Using the same procedure as given in UG-28(c)(1) obtain the value of B. Determine the ratio for and L / Do and Do / t L / Do = 78/ 4.5 = 17.33
Do / t = 4.5 / 0.531 = 8.47 [From UG-28(c)(1)]
Step l. Enter Fig. G at the value of L / Do ≈ 17.33 Step 2. Move horizontally to the line Do / t ≈ 8.47 from this point move vertically down to find Factor A ≈ 0.017. Step 3. Using Factor A enter Factor B chart CS-2 at the value of Factor A. Move up to the material / temperature curve for 700°F and across to the Factor B values. The factor B equals approximately 13,200.
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[From UG-28(c)(2)] Step 2. Using the value of B obtained above calculate the value Pa1 using the following formula:
Pa1 =
[[2.167 / D t] – 0.0833] B
Pa1 =
[[2.167 / 8.47] – 0.0833] 13,200 = 2277.5 psi
o
Step 3. Calculate the value of Pa2 where S is the lesser of 2 times the maximum allowable stress in tension at the design metal temperature from the stress tables or 0.9 times the yield strength of the material at design temperature. Values of the yield strength are obtained from the applicable material chart as follows: (a). For a given temperature curve determine the B value that corresponds to the right hand side termination point of the curve. (b). The yield strength is twice the B value obtained in (a) above. Use the Lesser of: 2 times the maximum stress allowed in tension or 0.9 times yield strength at temperature.
(Case 1.): 2 x 14,400 psi = 28,800 psi or (Case 2.): 2 x 13,900 psi = 27,800 psi x 0.9 = 25,020 psi So use 25,020 psi in the calculation of Pa2 Pa 2 =
2S
/
[
Dot 1 – 1 / Dot
[
Pa 2 = [2 x 25,020] / 8.47
[
]
] [1 – [1 / 8.47]]
]
Pa 2 = 5907.9 1 – 0.1180 = 5210 psi Step 4. Pa will equal the smaller of Pa l or Pa 2: Pa = 2275.5 psi 2277.5 psi > 1600 psi
API 510
ANSWER: Yes meets Code.
Page 117 of 310
API 510 Module PART UG - GENERAL REQUIREMENTS
UG-28 Thickness Of Shells And Tubes Under External Pressure Exercises Use the previous instructions as a model to work these problems. 1. A vessel under external pressure has been found to a thickness of 1.123 ". The vessels is 8'-2" long and operates at a temperature of 300°F. The vessel's outside diameter is 54 inches. It is made of a material with a minimum yield of 30,000 psi. Presently the external working pressure is 350 psi. May this vessel continue to operate in accordance with the Code? Show all work and quote code paragraphs used. Givens:
Drawing:
P= Temp. = t= L= Do= 2. A high pressure heat exchanger has experienced corrosion on the external surfaces of its tubes. A tube thickness was found to be .730" thick. This tube has a corroded minimum outside diameter of 5.98". The total external pressure is 900 psi at 800°F. The tubes are made of a material with a minimum yield of 38,000 psi, a maximum allowable stress at design temperature of 10,200 psi, and are 105 inches long. Will this tube's thickness allow continued operation at the present temperature and external pressure? Show all work and quote code paragraphs used,
Givens:
Drawing:
P= Temp.= t= L= Do=
API 510
Page 118 of 310
API 510 Module PART UG - GENERAL REQUIREMENTS
UG-20 Design Temperature (a) Maximum The maximum temperature used in design shall be not less than the mean metal temperature (through the thickness) expected under operating conditions for the part considered [see 31(g)]. If necessary, the metal temperature shall be determined by computation or by measurement from equipment in service under equivalent operating conditions. (b) Minimum The minimum metal temperature used in design shall be the lowest expected in service except when lower temperatures are permitted by the rules of this Division (see UCS-66). The minimum mean metal temperature shall be determined by the principles described in (a) above. Consideration shall include the lowest operating temperature, operational upsets, auto refrigeration, atmospheric temperature, and any other sources of cooling [except as permitted in (f)(3) below]. (c) Design temperatures listed in excess of the maximum temperatures listed in the tables of Subsection C are not permitted. In addition, design temperatures for vessels under external pressure shall not exceed the maximum temperatures given on the external pressure charts. (d) The design of zones with different metal temperatures may be based on their determined temperatures. (e) Suggested methods for obtaining the operating temperature of vessel walls in service are given in Appendix C. (f) Impact testing per UG-84 is not mandatory for pressure vessel materials which satisfy all of the following. (1) of:
The material shall be limited to P-No. 1, Gr. No. 1 or 2 and nominal thickness (a) (b)
API 510
1/2 inch for materials listed in Curve A of Figure UCS-66 1 inch for materials listed in Curve B, C, or D of Figure UCS-66
(2)
The completed vessel shall be hydrostatically tested per UG-99(b), (c), or (k).
(3)
Design temperature is no warmer than 650 degrees F and no colder than -20 degrees F' Occasional operating temperatures colder than -20 degrees F are acceptable when due to lower seasonal. atmospheric temperature.
(4)
The thermal or mechanical shock loadings are not a controlling design requirement. (See UG-22)
(5)
Cyclical loading is not a controlling design requirement. (See UG-22)
Page 119 of 310
API 510 Module PART UG - GENERAL REQUIREMENTS
UG- 22 Loadings The loadings to be considered in designing a vessel shall include those from: (a)
internal or external design pressure (as defined in UG-21);
(b)
weight of the vessel and normal contents under operating or test conditions (this includes additional pressure due to static head of liquids);
(c)
superimposed static reactions from weight of attached equipment, such as motors, machinery, other vessels, piping, linings, and insulation;
(d)
the attachment of: (1) (2)
API 510
internals (see Appendix D); vessel supports, such as lugs, rings, skirts, saddles, and legs (see Appendix G);
(e)
cyclic and dynamic reactions due to pressure or thermal variations, or from equipment mounted on a vessel, and mechanical loadings;
(f)
wind, snow, and seismic reactions, where required;
(g)
impact reactions such as those due to fluid shock;
(h)
temperature gradients and differential thermal expansion.
Page 120 of 310
API 510 Module PART UG - GENERAL REQUIREMENTS
UG-25 Corrosion The user or his designated agent (design engineering firm) shall specify allowances other than those allowed by the rules of this division. Any vessel subject to corrosion must have a suitable drain opening at the lowest practical point in the vessel.
API 510
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-98 Maximum Allowable Working Pressure Overview In the Code there are two types of Maximum Allowable Working Pressures (MAWP). One is for the vessel itself, the one most think of and refer to all the time. The other is the one for each part of a vessel referred to in UG-98 as the part MAWP. Think of it in this way: a vessel has a shell, heads, chambers, nozzles, etc., and pressure allowed or thickness required calculations must be performed for each one to determine the MAWP of the vessel. When doing these calculations, you cannot take credit for any extra thickness designed into the vessel as a corrosion allowance. The weakest of the vessels parts, considering loadings such as the static head of the contents, weight of insulation, wind, earthquakes, etc., will determine the MAWP of the entire vessel. It is the weakest link in the chain. The pressure referred to here can be internal or external. The MAWP of a vessel is the pressure allowed in a vessel at its top in its normal operating position and at its Maximum operating temperature. The MAWP can be determined for more than one designated operating temperature, using for each temperature the applicable allowable stress value. VESSEL MAWP P A R T M A W P Much More will be said about how to determine the vessel MAWP in the coverage of calculations for Static Head in a vessel.
API 510
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-99 Standard Hydrostatic / UG- 100 Pneumatic Test Overview The procedures for hydrostatic and pneumatic tests are contained in paragraphs UG-99 and UG-100. These procedures have many similarities and some important differences. Both of these tests can be applied to most vessels. The following are the highlights of each type of pressure test from the approach of a welded repair to a vessel that been in service. These highlights are not meant to replace reading the paragraphs.
1. 2. 3. 4. 5.
6.
1. 2. 3. 4. 5. 6.
7.
Hydrostatic If the test is required it shall be conducted after welded repairs. The test pressure must at least be 1 1/2 times the MAWP The test pressure shall be adjusted for lowest ratio of stresses. Any non-hazardous fluid may be used if below its boiling point. It is recommended that the metal temperature during hydro test be maintained at least 30°F above MDMT to minimize the risk of brittle fracture. Testing fluid must not exceed 120°F Following the application of hydro pressure a visual inspection shall be performed at 2/3 of the test pressure. Pneumatic If the test is required it shall be conducted after welded repairs. The welded repairs shall be subjected to the tests required by UW-50. The test pressure must at least be 1. 25 times the MAWP The test pressure shall be adjusted for lowest ratio of stresses. The metal must be maintained at least 30°F above MDMT to minimize the risk of brittle fracture. The test pressure shall be raised at a gradual rate to not more than 1/2 the test pressure and then raised by 1/10th of the test pressure until the test pressure is reached. A visual inspection must be made at 4/5ths the test pressure. The visual may be waived if the requirements listed in UG-100 are met.
The following written procedures will help to clarify the process. The ratio of stresses adjusts for the different strengths of materials at different temperatures. This will be explained during classroom instruction.
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API 510 Module PART UG - GENERAL REQUIREMENTS
API 510 4.4 / UG-98 / UG-99 / UG-102 HYDROSTATIC TEST PROCEDURE
API 510
1.
Calculate the test pressure using the rules of UG-98 and UG-99.
2.
Any fluid in compliance with UG-99 may be used. The temperature of the testing fluid and the vessel shell shall be as described in UG-99 and API 510.
3.
Isolate openings as required by blinding.
4.
Install a calibrated gage of the proper pressure range as described in UG-102 directly to the vessel. If the gage is not readily visible to the operator controlling the applied pressure, an additional gage shall be provided where it will be visible to the operator throughout the duration of the test.
5.
If the test pressure will exceed the setting of lowest relief device, relief devices shall be removed , blinded or have test clamps installed.
6.
Vents shall be provided at all high points to purge air while the vessel is being filled.
7.
Before applying pressure, inspect all test equipment to insure it is tight and that low pressure filling fines and other appurtenances that should not be subjected to the test pressure have been disconnected.
8.
Warn all personnel in the area.
9.
Slowly raise the vessel to the test pressure. Hold for an appropriate time based on vessel size.
10.
Lower the vessel to 2/3 the test pressure and make a visual inspection of all joints and connections.
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UG-99 Calculating Hydrostatic Test Pressure Problem:
Calculate the required hydro test pressure for a vessel using the following conditions.
Material Design Temp. Test Temp. MAWP
SA-516 Gr. 65 700°F 85°F 350 psi
Step 1: Determine the ratio of stresses for SA-516 gr. 65 for the test and design temperatures. (a).
From Table 1A Section II Part D. Stress allowed at 700°F = 15,500 psi Stress allowed at 85°F = 16,300 psi
(b)
Per UG-99 the ratio equals Stress at Test Temp. Stress at Design Temp. 16,300 = 1.05 15,500
Step 2: Per UG-99(b) Test pressure equals 1.5 x MAWP x
Stress at Test Temp. Stress at Design Temp.
1.5 x 350 psi x 1.05 = 551.25 psi Answer 551.25 psi at the top of the vessel.
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API 510 Module PART UG - GENERAL REQUIREMENTS API 510 4.4 / UG-98 / UG-99 / UG-102 PNEUMATIC TEST PROCEDURE
API 510
1.
Prior to administering a pneumatic test, insure that the NDE of UW-50 for welded repairs has been applied.
2.
Calculate the test pressure using the rules of UG-98 and UG-100.
3.
The metal temperature during pneumatic test shall be maintained at least 30°F above the minimum design metal temperature to minimize the risk of brittle fracture.
4.
Isolate openings as required by blinding.
5.
Install a calibrated gage of the proper pressure range as described in UG-102 directly to the vessel. If the gage is not readily visible to the operator controlling the applied pressure, an additional gage shall be provided where it will be visible to the operator throughout the duration of the test.
6.
If the test pressure will exceed the setting of lowest relief device, relief devices shall be removed, blinded or have test clamps installed.
7.
Before applying pressure inspect all test equipment to insure it is tight and that low pressure filling lines and other appurtenances that should not be subjected to the test pressure have been disconnected.
8.
Warn all personnel in the area.
9.
The pressure in the vessel shall be gradually raised to not more than one-half the test pressure. Thereafter, the test pressure shall be increased in steps of approximately one-tenth of the test pressure until the test pressure has been reached.
10.
Lower the vessel to four-fifths the test pressure and hold for a sufficient time to make a visual inspection of all joints and connections.
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UG-100 Calculating Pneumatic Test Pressure Problem: Calculate the required pneumatic test pressure for a vessel using the following conditions. Material Design Temp. Test Temp. MAWP
SA-516 Gr. 65 700°F 85°F 350 psi
Step 1: Determine the ratio of stresses for SA-516 gr. 65 for the test and design temperatures. (a). From Table 1A Section II Part D. Stress allowed at 700°F = 15,500 psi Stress allowed at 85°F = 16,300 psi (b)
Per UG-99 the ratio equals (c) Stress at Test Temp. Stress at Design Temp. 16,300 = 1.05 15,500
Step 2: Per UG-100(b) Test pressure equals
1.25 x MAWP x
Stress at Test Temp. Stress at Design Temp.
1.25 x 350 psi x 1.05 = 459.375 psi Answer 459.375 psi
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-100 Calculating Pneumatic Test Pressure PROCEDURE FOR PNEUMATIC TEST a.
Slowly raise the pressure to approximately one-half 459.375 psi which equals 229.6 psi.
b.
Raise the pressure in steps of one-tenth of the test pressure. 1.
229.6 + 45.9 = 275.5 psi
2.
275.5 + 45.9 = 321.4 psi
3.
321.4 + 45.9 = 367.3 psi
4.
367.3 + 45.9 = 413.2 psi
5.
413.2 + 45.9 = 459.1 psi
c. Lower the pressure to four-fifths = 367.2 psi The adjustment for test and design temperatures is the reason why inspection is not taking place at the MAWP of 350 psi, i.e. 1.05 x 350 = 367.5 psi.
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-102 Test Gages Overview The Code has some definite requirements for the selection and uses of gages for the tests described in UG-99 and UG-100. Directions for location, number of, range of and the calibration of the indicating gage(s) is located in UG-102. The high points of UG-102 are below. 1.
An indicating gage shall be connected directly to the vessel. If it is not readily visible to the operator of the test equipment an additional gage shall be used which is visible to operator for the duration of the test.
2.
When doing large vessel pressure tests it is recommended to have a recording gage in addition to the indicating gage.
3.
Dial type indicating gages shall have a range of about double the maximum test pressure, but in no case shall the range of the gage be less than 1 1/2 times nor more than 4 times the maximum test pressure.
4.
Digital gages having a wider range may be used as long as they provide the same or greater accuracy of the dial type.
5. All gages shall be calibrated against a standard dead-weight tester or a calibrated master gage. 6.
API 510
Gages must be calibrated any time their accuracy is in doubt.
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-99 / 100 / 102 Exercises 1. A vessel made of SA-240 304L plate is being hydrostatically tested after an alteration. The vessel's MAWP is 225 psi at 400°F. The allowable stress at operating is 14,700 psi and 16,700 psi at the test temperature. Answer the following. A. B. C.
2.
API 510
What is the required test pressure? What is the least pressure the vessel can be inspected at? In psi what is the minimum and maximum range of the test gage?
A pneumatic test of a vessel will be conducted to a pressure of 310 psi. Describe the steps for raising the vessel to the test pressure. At what pressure shall the visual examination take place?
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API 510 Module PART UG - GENERAL REQUIREMENTS
UW-16 Fillet Weld Sizing For Attachments At Openings The fillet weld sizing of UW-16 can be solved in either of two ways. That is, you may determine if a fillet weld leg size provides an adequate fillet weld throat size per Code or based on the thicknesses of the shell and nozzle determine the minimum throat size required and convert that to leg size. In the latter case, usually the leg size decimal value is rounded to the next fractional 1/16th inch. In these examples we will work it in both ways using the same shell and nozzle thicknesses. The examples will be restricted to only Fig UW-16.1 (i). Problem:
A nozzle is being attached to a shell as shown in Fig. UW-16.1 (i) using two equal size fillet welds. The shell's thickness is 7/8 in. and the nozzle's thickness is 1/2 inch. The fillet welds are 3/8 inch in leg size. Does this meet Code?
t1 7/8”
½”
t2
Leg Size 3/8” or .375” Throat Size
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Case l.: Determine the minimum throat size.
From Fig. UW-16.1 (i) we are given that: t1 + t2 > 1 1/4 tmin And t1 or t2 not less than the smaller of 1/4 in. or .707 tmin From the nomenclature of UW- 16 we are given the following definitions: tmin = the smaller of 3/4 in. or the thickness of the thinner of the two parts joined by a fillet weld. t1 and t2 are the throat sizes of the welds as depicted in Fig. UW-16.1(i).
t1 7/8”
½” t2
Step 1: Determine the throat size of a 3/8 in. leg size fillet weld.
Leg Size 3/8” or .375”
Throat Size Throat size equals .707 times leg size. 0.707 x 0.375” = .265” = t1 or t2
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Step 2: Determine tmin. tmin = the smaller of ½” or ¾” . So tmin. = ½”. Step 3: Determine if t1 + t2 ≥ 1 1/4 tmin
.265" + .265” ≥ 1.25 x .500" .530" ≥ .625" .530" is neither greater than or equal to .625". Therefore the first test fails and the throat size of the 3/8" leg fillet weld is too small,
We could stop here and answer the question with a No! But let's finish up with the second test of size required for an illustration of the technique required.
Step 4: Test to see if: t1 or t2 not less than the smaller of ¼” or .707 tmin Not less than the smaller of .250” or .707 x ½” .707 x .500" = .3535"
So not less than .250". Both t1 and t2 are .265". .265” > .250” Fillet welds are adequate in the second test. However a fillet weld size must pass both tests!
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Case 2.: Based on material thicknesses determine the minimum leg size of equal sized fillet welds to the next 1/16th inch. In our problem thicknesses are 7/8 inch (shell) and 1/2 inch (nozzle) . We have already determined that 3/8 inch leg fillet welds are too small. So let's determine what size of equal leg fillet welds are required rounded up to the next 1/16th inch. This is a case where you are really coming in through the back door; that is to say, you are not checking to see if an existing or proposed Fillet weld leg size is large enough. You are in fact. determining the minimum size for a thickness combination. The approach is to set up the formulas given in Fig. UW-16.1 (i) and determine the minimum values so as to make the shoe fit. Step 1: Determine tmin. tmin. = the smaller of ½” or ¾” So tmin = ½” Step 2.: Determine .707 tmin .707 x .500" = .353" Step 3.: Determine 1 1/4 tmin. 1.25 x .500" = .625" From Fig. UW- 16.1 (i) we are given that: t1 + t2 ≥ 1 1/4 tmin And t1 + t2 not less than the smaller of ¼” or .707 tmin Let's stop and examine the formulas given above to make sure we understand what is being said. First, this business of throat 1 plus throat 2 being greater than or at least equal to 1.25 times tmin. .If that's the case, then to figure out the minimum throat size of one equal sized fillet weld, we need only calculate 1.25 x tmin and divide it by two. Next, what is really is being said in " t1 or t2 not less than the smaller of ¼” or. 707 tmin." is that the Code does not allow a fillet welds with a throat smaller than 1/4". This is to prevent a very large fillet weld on one side and what amounts to a small seal weld on the other side. This keeps the heat input balanced across the parts joined. A 1/4" throat requires a leg size of .353" about 3/8”. A:
.625 / 2 = .3125 So .3125 + .3125 = 1 1/4 tmin.
B: C:
.3125 > .250 ( t1 or t2 minimum size is satisfied) To convert throat to leg, divide the throat by .707 .3125 / .707 = .4420 (Round up to the next 1/1 6th inch). 6 / 16th = .375 or 7/16th = .4375 or 8/16 = .500 .4375 < .4420 < .500 Answer: minimum leg size is 1/2 inch.
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API 510 Module PART UG - GENERAL REQUIREMENTS UW-16 Weld Size Determination Exercises 1.
A fillet weld has a leg size of 1 1/8". What is its throat size?
2. A fillet weld has a throat size of .600". What is its leg size rounded up to the next fractional 1/16"?
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API 510 Module PART UG - GENERAL REQUIREMENTS
Reinforcement For Openings In Shells And Heads Overview UG-36 Openings in Pressure Vessels The main things of interests in this paragraph to the API 510 inspector are the following: All references to dimensions apply to the finished construction after deduction for material added as corrosion allowance. Openings not subject to rapid fluctuations in pressure do not require reinforcement other than that inherent in the construction under the following conditions: The finished opening is not larger than. 3 ½” diameter in vessel shells or heads 3/8” or less in thickness. 2 3/8” diameter in vessel shells or heads over 3/8” in thickness. No two isolated unreinforced openings, in accordance with the above shall have their centers closer to each other than the sum of their diameters. Centers No Closer Than The Sum of their Diameters
5”
4”
3/8”
3 ½”
API 510
+
1 ½” = 5”
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5/8”
2 ½”
+
1 ½” =4”
UG-37 Reinforcement Required for Openings in Shells and Formed Heads For a good start on this paragraph you must become familiar with UG-37 (a) nomenclature. Read each of the given symbols. Then compare the symbols with the drawing of Fig. 37.1, Nomenclature and Formulas for Reinforced Openings. Classroom instructions if used, and example problems will address this lengthy subject. UG-40 Limits of Reinforcement This paragraph tells you how much distance in any direction you can count as reinforcement in your calculations. This means that if a vessel wall has excess metal above that required by calculation, how far on each side of the opening can you take credit for this extra metal as reinforcement. If a nozzle with excess thickness is inserted into the hole, how much of the excess thickness in the inside projection can be counted as helping add strength back to the vessel wall at the opening? Also considered is how much of the nozzle excess thickness above the hole in the vessel can be counted as reinforcement for the opening. UG-41 Strength of Reinforcement Where the Code specifies that if you add reinforcement, such as a pad, that the pad must have a strength that is equal to or greater than the material of the head or shell. If such metal is not available and a lower strength material is used, a stress reduction must be taken during the calculations for reinforcement. Repad Stress =Stress Reduction Vessel Stress
Example:
Repad 15,000 psi = .857 Vessel 17,500 psi
After the above calculation, the stress reduction factor is multiplied times the actual area of the repad, and the lesser area that is determined must be used in the calculations for reinforcement. Example:
Given: Repad cross-sectional area equals 2 square inches and the stress reduction factor equals .857. Find the area that may be used in reinforcement calculations. .857 x 2 = 1.714 square inches
However, if the material used is stronger than the material being reinforced, no credit may be taken for the higher strength material used as reinforcement. For the calculations you must use the strength of reinforcement as being the same as the vessel or head being reinforced.
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UG-42 Reinforcement of Multiple Openings This paragraph addresses cases where the limits of reinforcement for more than one opening overlap each other. Extra metal in a vessel above what is required to resist internal pressure can he counted toward reinforcing an opening. The distance counted as reinforcement on each side of an opening (parallel to it) is defined in UG-40. If two openings are close enough to each other that their limits overlap then special consideration must be given to the reinforcement of both openings. If two openings are spaced closer than two times their average diameters, it is not allowed to take double credit for extra wall thickness in the overlapped area. Nozzle
2”
2”
2”
4”
2”
3”
The extra wall thickness in the shaded area in the drawing above cannot be counted as helping reinforce both the openings. It can be counted for one or the other but not both. The minimum spacing for the openings above to avoid this situation is 4”. It must be divided between the two in proportion to the ratio of the two opening's diameters. In this case, 50/50. If the openings where different diameters the ratio of their openings would he calculated and the shade area split up accordingly. The next situation involves more than two openings spaced closely together. In that configuration, the minimum distance between any two of these openings shall be 1 1/3 times their average diameters and the area of reinforcement between any two openings must he at least equal to 50% of the total area required for the two openings. This means you are not allowed to set the openings too closely to each other and take any credit for the shaded areas.
3.333”
5.999” 3” 2” 6”
5.333”
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If the openings are closer together than permitted by UG-42(b), no credit is allowed for any of the metal between the openings, and the reinforcement calculations must be performed as given in UG-42 (c) as shown below. The nozzle wall thicknesses of the individual openings cannot be figured in as available reinforcement. The calculation becomes one for a single larger hole. Again no credit is allowed for metal between the individual openings or any of the nozzle thicknesses. Its just one big hole containing all the other openings and its reinforcement will be the one calculated.
2.5” 5” 3” 2” 6” 4.75”
D I A M E T E R
UG-45 Nozzle Neck Thickness Here we are given minimum thicknesses for nozzle walls. The basic premise for this paragraph is that a nozzle's wall thickness cannot be less than the smaller of the thickness required plus corrosion allowance of the shell or the head it is in or the minimum thickness (considering the mill under tolerance of 12 1/2 %) of standard wall pipe plus any corrosion allowance. The thickness calculations for the shell or head under internal pressure only will use an E= 1.0 for this purpose assuming the nozzle does not pass through any Category A joint with an efficiency of less than 1.0. However the nozzle may not be thinner than the minimum thicknesses given in UG-16(b). Read this paragraph with the intent of applying these rules case by case. Situations of internal and external pressure are also given. A notable rule is given in UG-45 (d) about thicknesses of standard wall pipe used as a nozzle pertains to the minimum thickness based on nominal (average) pipe size. Read the footnote given in this subparagraph.
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-40 / 41 / 42 / 45 Exercises 1.
A vessel opening is being reinforced with a pad. The pad has an allowable stress of 15,000 psi. The vessel's wall has an allowable stress of 14,800 psi. What is the resulting ratio of stress to be used in the pads area calculation?
2.
A 6 in. nozzle is being added in a vessel wall next to an existing 4 in. nozzle. What is the closest they may be placed together with out overlapping their areas of reinforcement?
3.
Three nozzles are to be installed such that they clustered so closely together that they are less than 1 1/3 their average diameters apart. How will the area of reinforcement be calculated?
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API 510 Module PART UG - GENERAL REQUIREMENTS
Reinforcement For Openings In Shells And Heads Openings that do not require reinforcement calculations are outlined in UG-36(c)(3). All other openings must have the rules of reinforcement applied. The rules of reinforcement are taken from paragraphs UG-36 through UG-43. The limits where these rules apply are taken from UG-36(b)(1). The following is an outline for an approach to the understanding of reinforcement calculations. First, the basic requirement is that around any opening in a vessel the vessel wall must be reinforced with an equal amount of metal as was removed from the vessel wall required for pressure (thickness required). This reinforcement may already exist in the form of excess wall thickness above that required to resist the pressure. It may be found in the nozzle wall excess thickness or in the attachment welds. If it does not meet the requirements considering the above mentioned excess thicknesses after corrosion allowance has been removed then a reinforcement pad will be required. At this point we are ready to begin applying all the rules which were given in the preceding paragraphs. The following graphics depict the various areas that must be considered when performing reinforcement calculations. Through this type of breakdown the concept can be better understood, this is of course an oversimplification. A. You may not need to replace all of the metal removed. GIVEN AS A: The dark cross hatched area is the diameter of the finished opening multiplied times the minimum thickness that is the required by the calculations of UG-27 for a shell or UG-32 if the opening is in a head, etc,
A
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B. The vessel and the nozzle walls usually have excess thickness above that required to resist pressure. This excess thickness is counted toward reinforcement. Corrosion allowance cannot be included in areas A1 or A2 below. GIVEN AS A1 and A2. The shaded areas are the extra metal. A1 A2
T required
C. If the nozzle extends inside the shell, within certain limits this nozzle metal can be counted, less any corrosion allowance. GIVEN AS A3
A3
D. The welds used to attach the nozzle to the shell count as area available for reinforcement. Interior weld area would be less corrosion allowance. GIVEN AS A4
A4
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E. All of this reinforcement must fall within certain limits. The extra metal in the shell and nozzle cannot be counted outside the calculated limits. X
Y
F. If any of the above mentioned reinforcement has a lower stress value than the vessel's wall its area counted toward reinforcement must be decreased proportionally. Example:
The vessel wall stress allowed is greater than that of the nozzle. Vessel material stress allowed = 17,500 Nozzle material stress allowed = 15,000
Nozzle Vessel
15,000 ---------- = .857 Stress Reduction Factor 17,500
If we had, for instance, 2.5 sq. in. of excess wall in the nozzle, we would multiply it by the stress reduction factor to find the area allowed to be used in the calculations .857 x 2.5 = 2.14 sq. in.. 2.14 sq. in. would be all that could be considered as counting, toward reinforcement. However, the reverse is not true if the nozzle has a greater stress value than the shell; no credit may be taken for it. All stress values would then he the same as the shell's.
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corrosion allowance deducted prior to the calculation of reinforcement available.
Corrosion Allowance H.
The area of reinforcement must be satisfied for all planes through the center of the opening and normal to the vessel wall.
NORMAL
ALL PLANES I. The required cross-sectional area shall be the area of the shell or head required to resist pressure which is given as A. If the sum of A1+A2+A3+A4 is equal to or greater than A the opening, is adequately reinforced. If not, more reinforcement must be added. Usually this be in the form of a reinforcement pad. Its area is found as follows. A - (A1+ A2+ A3 + A4)= Area required for the repad. REPAD A5
This type of problem can get complicated very quickly, mostly by the number of steps involved. However, the API 510 Exam Body of Knowledge has simplified the problems. This was done by limiting this type of problem as follows:
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a.
There will he no inward projection for the nozzle.
b.
The nozzle will enter at 90 degrees to the shell or head.
c.
The opening will not pass through a Category A weld.
d.
Nozzles and shell will be of the same strength.
e.
The required thicknesses of shells and nozzles will be given.
In the following example, the problem will be worked using those guidelines. Remember, this type of problem is worth no more than simplest Code calculation possible on the exam. Plan your study time with this in mind. Since the problem may not even be on the if you spend all your time studying these and nothing else, the outcome is obvious. Also, unless you are really comfortable with these problems, it is best to do them last. They eat up a lot of time and you could find yourself rushing through the remaining problems--not a desirable situation!
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API 510 Module PART UG - GENERAL REQUIREMENTS Reinforcement for Openings in Shells and Heads The API 510 Body of Knowledge has placed the following limits on reinforcement problems. The inspector should: a.
Understand the key concepts of reinforcement. -Replacement of strength removed -Limits of reinforcement -Credit can he taken for extra metal in the shell and nozzle
b.
Be able to calculate the required size of a reinforcement pad or to assure a designed pad is large enough. To simplify the problem: 1. 2. 3. 4. 5.
All fr = 1.0 All F = 1.0 All E = 1.0 All required thicknesses are given There will be no nozzle projecting inside the shell
The inspector should be able to compensate for corrosion allowance. Weld strength calculations are excluded. Although it has not been listed under reinforcement, sizing of the fillet welds will probably be required since it is elsewhere in the material. The best approach is to work a problem typical of what can be expected and explain each aspect above as it is required to solve the problem. Problem: A vessel made of SA-515-gr. 70 rolled and welded plate is having a 6 inch NPS schedule 80 seamless nozzle added similar to Fig. UW-16.1 (a) with a fillet weld of 1/2" in leg dimension. The shell's actual thickness is 7/8 inch. The nozzle's actual thickness is 0.432", and it has an O. D. of 6.625". A corrosion allowance of .125" is required.
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The following information has been provided by planning. Does this design require a repad? If so what is its required size? Givens: 1. 2. 3. 4. 5. 6.
The required thickness of the shell is .690" The required thickness of the nozzle Is .033" The nozzle will not pass through a vessel Category A weld : E = 1.0 The nozzle will enter the vessel normal to the vessel wall : F = 1.0 The nozzle and shell are of the same strength or the nozzle has a greater strength : fr = 1.0 A corrosion allowance of .125” is required.
Drawing: t = .432"
leg =.500" t=.875"
Step 1. Check the fillet weld throat size. The fillet weld throat in this Figure of UW-16 is indicated as tc. In the nomenclature of paragraph UW-16, tc is required to be not less than the smaller of 1/4" or 0.707 tmin. Our tmin is the nozzle which is .432". .707 x .432" = .305" So tc can be no smaller than 1/4"(.250"). Since the throat size of a fillet weld is determined by multiplying .707 times the leg size and our leg size is given as ½”. We calculate as follows. .707 x .500" = .353". This is larger than and the throat of the fillet weld is adequate. Step 2. Check to see if a corrosion allowance is specified. If so it must be deducted from the actual thickness of the shell and nozzle prior to calculations. Also the I. D. of the nozzle must be increased by two times the corrosion allowance. In our problem the corrosion allowance is .125". Shell actual t =.875" Corrosion .125' Shell t to be used .750" adjusted for corrosion
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Nozzle actual t Corrosion Nozzle t to be used Nozzle I.D. Nozzle I.D. Nozzle I.D. Nozzle I.D.
.432" -.125” .307" Adjusted for corrosion
O. D. -2(wall t - c.a.) 6.625-2(.432-.125) 6.625-2(.307) 6.625-.614 = 6.01 " Adjusted for corrosion
Step 3. Set up the formulas of UG-37 using Figure UG-37.1 A = d tr F +2tn tr F(1 -fr1) Area required = d(E1t-Ftr)-2tn(E1t- Ftr)(1-fr1) A1 use larger
OR
Area available in shell;
= 2(t+tn)( E1t-Ftr)- 2tn (E1t-Ftr)( 1-fr1) = 5(tn –trn) fr 2t A2
OR
Area available in the nozzle outward; use smaller = 5(tn –trn) fr 2tn
A41
2
= Outward nozzle weld = (leg) fr2 Area of outward fillet If A1 + A2 + A41 ≥ A Opening is adequately reinforced
If the sum of all the areas are not equal to or greater than A; the area required for the repad is found by subtracting the sum from A. A - (A1 + A2 + A41) = Area of Repad
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Step 4. Make A Drawing t noz. = .307”
c.a. =.125”
t shell = .750”
I.D. = 6.01”
c.a.
.125” All dimensions after corrosion allowance Step 5. List Givens Adjusted for corrosion: d= t= tr=
6.01 " diameter of the finished opening less corrosion .750" actual thickness of the shell less corrosion .690" thickness required in the shell per UG-27(c)(1
tn =
.307" actual thickness of the nozzle less corrosion
trn= E= F=
.033" thickness required in the nozzle per UG-27(c)(1) 1.0 nozzle does not pass through any weld seam 1.0 nozzle enters shell at 90 degrees to the shell
fr= Leg size =
1.0 nozzle and shell stress allowables the same . 500”
Step 6. Plug values into formulas and solve: A= 6.01" x .690" x 1.0 + 2 x .307" x .690" x 1.0 x (1-1) Area required A= 6.01" x .690" x 1.0 + 2 x .307" x .690" x 1.0 x (0) Area required A= 6.01" x .690" x 1.0 + 0 A= 6.01" x .690" x 1.0 = 4.1469 square inches Area required A1= 6.01" x ((1.0 x .750")-(1.0 x .690"))-2 tn (E1t- Ftr)(1-1) A1= 6.01" x ((1.0 x .750")- (1.0 x .690"))- 0 A1= 6.01" x (.750"- .690") = .3606 square inches OR A1= 2(.750"+ .307")((1.0 x .750")-(1.0 x .690"))- 2tn (E1t- Ftr)(1-1) A1= 2(.750"+.307")((1.0 x .750)"-(1.0 x .690"))-0 A1= 2(1.057")(.06) = .12684" A1=Area available in shell; use larger = .3606 square inches = 5(.307"- .033") 1.0 x .750" = 5(.274") x .750" = 1.0275 square inches A2= OR = 5(.307"- .033") 1.0 x .307" = 5(.274") x .307" = .42059 square inches
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=
API 510 Module PART UG - GENERAL REQUIREMENTS
Reinforcement For Openings In Shells And Heads Exercises 1. When calculating reinforcement, from what parts must a corrosion allowance be deducted (where)"
2. As regards reinforcement how is the area A found? State the formula.
How many points is a reinforcement calculation worth on the exam? How many points is a hydrostatic test calculation worth on the exam?
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API 510 Module PART UG - GENERAL REQUIREMENTS UG-84 Charpy Impact Tests Overview A major concern in vessel operations at low temperature is brittle failure of the material. This type of failure is considered more serious than a ductile failure simply because it is sudden, giving little warning (almost no bulging), and the material might shatter similar to broken glass. Impact testing is required to determine if a material thickness at a given temperature is likely to fail in that manner. Put more directly, the goal of impact tests is to prove it is unlikely to occur in the thickness/material combination being used at a design pressure and minimum design metal temperature (MDMT). The term Low Temperature can be misleading. When welded, 4 in. material thicknesses are considered in low temperature operation at 120°F. Again the first conclusion drawn from UG-84 must be that the tests are required. For the API-510 candidate, impact testing applies to Part UCS Carbon and Low Alloy Steels of Sub-Section C. These steels are susceptible to brittle fracture even at fairly high temperatures. It should be concluded that impact tests are required on these materials and their weldments. The only exemptions are given in part UG-84 of the General Requirements and UCS66, 67, 68 and in UG-20(f). The search for exemptions for a given problem start in UG-20(f) and then continue through paragraphs UCS-66, 67, and 68. This process will be covered in Part UCS of this course. UG-84 states that impact test shall conform to the paragraphs of SA-370. This is a reference to a standard listed at present on Table U-3 of Page 5 in Section VIII of Division 1, 1992 edition. Look up this table and read it; a question could come from here. It outlines the test apparatus and procedures. The only kind of impact test recognized by the Code is the Charpy V Notch type. The impact test specimens for a full size test are to be as shown in Fig. UG-84. The next consideration is that of the minimum absorbed energy for the impact test specimen. Figure UG-84.1 is used to determine the value of absorbed energy required for a test specimen made of carbon and low alloy steels. Notice it refers to those materials listed in Table UCS-23 and that the minimum specified yield strength and thickness of material or weld in inches are crucial for determining impact absorbed energy. The impact testing of the parts of a vessel falls into two general categories: materials and welds. A general statement can be made about these impact tests. If the base material being welded is required to be impact tested, the weld metal and its weld heat affected zone probably will he required to be tested also. The weld metal and heat affected zones performed using a production impact plate (an extension of a welded joint on part of the vessel which can later be cut off to make the impact specimens.).
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The impact test specimen test plates must be subjected to same heat treatments as the vessel. The location for removal of specimens from test plates are described in UG-84 (g). The thickness of a test plate determines the number of test specimens required and also the location of their removal from the test plate. For test plates 1 1/2 inch or less two sets of three (3) specimens must be taken. One set from the weld with the notch located in the weld as shown in Fig. UG-84 and one set from the heat affected zone (HAZ) with the notch located so that as much HAZ material as is possible is included in the resulting fracture. For test plates over 1 1/2 inch three sets of three (3) are required. One set from the weld metal and one from the HAZ. A third set is required to be taken from the weld metal as near as is possible to the center of the weld. The acceptance details for these impact tests is found in UG 84 (c)(5)(c)(6) and in the notes of Fig. UG-84.1. Figure UG-84.1 is used to determine the minimum acceptable absorbed energy for a set of test specimens. To use Figure UG-84.1, the material thickness is found along the bottom of the chart. From that point, move straight up to the line that represents the minimum yield of the material wider consideration, then left to the value of absorbed energy required to pass the test. Notice that this value is called an average. GENERAL NOTES at the bottom of the chart require that no one specimen shall have an absorbed energy value less than 2/3 of the average required for all three.
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API 510 Module PART UG - GENERAL REQUIREMENTS UG-84 Charpy Impact Tests Exercises 1.
What specification must impact testing procedures conform to?
2.
What type of Impact test does the Code recognize?
3.
What are the dimensions of a standard Charpy Impact specimen?
4.
How many specimens comprise a single set?
5. How many sets of specimens are required for a weld procedure test coupon 1 3/4 inches thick? 6. When welding a procedure test plate for impact testing what must the P No. and Group No. be? What type of heat treatment must be applied to the test plate? 7. Name the two types of test specimens required for all welding procedures. Hint,. Where do they come from?
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API 510 Module PART UG - GENERAL REQUIREMENTS UCS-66 Materials Low temperature should always be a consideration when designing a vessel of carbon and low alloy steels simply because low temperature is defined to be different temperatures for different metals and their respective thicknesses. Example UCS-66 (3) states that if the governing thickness of a non-welded part exceeds 6", and the minimum design metal temperature (MDMT) is colder than 120°F, impact tested materials shall be used. This example has been used to point out how relative the term low temperature is. Turn your attention to figure UCS-66 Impact Test Exemption Curves, In this figure you will find a graph and listing of carbon and low alloy steels. It is limited to 4 inches for welded construction. This is because above 4 inches, welded construction must be impact tested. A good essay or multiple choice question could be taken from this material. Understanding figure UCS-66 is essential. Figure UCS-66.1, titled Reduction of Minimum Design Metal 'Temperature (MDMT), without impact testing allows for the reduction of the MDMT when a material in tension is being used below the maximum allowable design stress of that material. UCS-67 Impact Testing Of Welding Procedures UCS-67 details three cases where impact tests shall be made on carbon and low alloy steel welds when qualifying a low temperature welding procedure. This is done if impact tests are required for the base metal. UCS-68 Design Design rules for carbon and low alloy steels stipulate requirements as to how construction will be performed. The main points are mandatory joint types, required post weld heat treatments below -50°F and their exemptions. Also notice a reduction of 30°F below that of Figure UCS-66 for P-1 materials if post welded heat treatment is performed when it is not otherwise required.
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API 510 Module PART UG GENERAL REQUIREMENTS
Impact Testing Exemptions Overview The first paragraph of UG-84 states that impact testing is required of all weldments, materials, etc., that required to be tested in Subsection C. From this point, the search begins to see if a material or weld is required to be impact tested. The goal is to find an exemption. The search will begin in UG20(f) and progress through UCS 66, 67 and 68. If no exemption is found impact tests are required. The best approach is to list these by steps. UG-20 Step 1. UG-20(f) UG-20(f) lists an exemption from impact testing for materials that meet all of the following requirements. 1.
Material is limited to P No. 1 Gr. No. 1 or 2 and the thicknesses don't exceed the following: (a) 1/2 in. for materials listed in Curve A of Figure UCS-66. (b) 1 in. for materials from Curve B. C or D of Figure UCS-66.
2.
The completed vessel shall be hydrostatically tested (Pneumatic test is not permitted for this exemption)
3.
Design temperature is no warmer than 650°F nor colder than -20°F.
4.
The thermal or mechanical shock loadings are not controlling design.
5.
Cyclical loading is not a controlling design requirement.
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UCS-66 Materials Step 2. UCS-66 (a) Turn your attention to Figure UCS-66 impact Test Exemption Curves and Table UCS-66. The Graph and Table are used to determine the minimum temperature a material thickness can be operated at without mandatory impact testing. The graph has four curves: A, B, C and D. In Figure UCS-66 along with the graph is a listing of carbon and low alloy steels. This listing of materials is used to determine the curve on the Graph or in the Table for a given material. After finding the curve for the material, there are two choices. Use the graph of Figure UCS 66 or the Table UCS 66 to determine the minimum temperature for a given thickness. It is recommended to use the Table. The Table and the Graph are the same. The Table is a lot easier to use with accuracy. USE THE TABLE. If the material thickness is operated at or above the temperature listed in Table UCS-66, impact tests are not required. If the material thickness is to operate below the given minimum temperature, impact testing is required. The temperature found in the table is the MDMT of that material thickness without Impact Testing being required. Step 3. UCS-66(b) When a material in tension is being used at some stress value below its allowable design stress at the MDMT, a reduction in temperature is permitted This reduction is subtracted from the given temperature for the material in Table UCS 66. If after taking the reduction. the resulting temperature is colder than the minimum design metal temperature desired for the vessel, impact testing is not required. This is called the coincident Ratio. When a material is operating at a relatively high temperature it has lower stress allowed than at room temperature. Many vessels operate alternating between elevated and low temperatures. The lower stress allowed at the elevated temperature will require thicker material than needed at the lowest temperature. The thicknesses required for the two temperatures can be different, and normally the thickness required for the vessel is determined using the higher temperature stress allowed. So if at the lower temperature and often lower pressure we have extra wall thickness we can take credit for. How much is determined by calculating the coincident Ratio, then entering Figure UCS-66.1 at the calculated Ratio? Normally on the API 510 Exam, the Ratio is stated, and then all that is required is to apply the graph of Figure UCS-66.1. If the vessel is in a fixed stationary position and its coincident Ratio is below 1.0, the reduction allowed by UCS-66(b) and Figure UCS-66.1 may be taken only when the following is true. (b)(1): The MDMT is - 50°F or warmer. If the MDMT is colder than - 50°F. (b)(2): Impact testing is required of all materials unless (b)(3) applies. If the MDMT is colder than - 50°F but no colder than -150°F and the coincident Ratio of stress is equal to or less than 0.4. (b)(3): Impact testing is not required.
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UCS-68 Design Step 4. UCS-69(a) Design rules for carbon and low alloy steels stipulate requirements about construction of the vessel or part. The main points are: mandatory joint types, required post weld heat treatments below -50°F unless the vessel is installed in a fixed (stationary) location, and the coincident Ratio of stress is less than 0.4. UCS-68(b) Welded Joints must be postweld heat treated when required by other rules of this Division or when the MDMT is colder than - 50°F and for vessel installed in a fixed (stationary) location the coincident Ratio is 0.4 or greater. UCS-68(c) Notice a reduction of 30°F below that of Figure UCS-66 for P-1 materials if post welded heat treatment is performed when it is not otherwise required in the Code. This means that 30°F can be subtracted from the temperature found in Table UCS-66. If the adjusted temperature is below that desire, Impact Tests are not required. It is exempt. If a statement about heat treatment is made in a particular problem the task becomes finding out if heat treatment was required or not. If it is not mentioned, it must be concluded that it was not performed and therefore the exemption cannot be taken. Givens: Material = Thickness = Min. Yield = MDMT= Coincident Ratio =
SA-516 Gr.70 normalized PLATE 2” 38 KSI -25°F .85
Step 1 Check for the exemptions of UG-20(f). Our material applies to Curve D of Figure UCS-66 and exceeds the 1 " limit for exemption. It also exceeds the upper and lower temperature limits of 650°F and -20°F. Step 2 Checking Table UCS-66 and entering at our thickness on the left and moving across to Curve D column, we find the MDMT of this thickness to be - 4°F. This exemption does not apply.
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Step 3 Check reduction or MDMT for coincident Ratio Enter the Figure UCS-66.1 at 0.85 and across to the curve, then done to read a temperature reduction permitted of 15°F. The reduction of MDMT is 15°F. -4°F -15°F -19°F New MDMT allowed without impact tests is -19°F. Our MDMT will need to be -25°F so we are not exempted. Step 4 Checking UCS-68, we find that we cannot take a reduction because PWHT is a requirement of UCS-56 for this material's thickness. Answer:
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Impact tests are required for the values of the MDMT of - 25°F.
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-20 / UCS-66 / 68 Exercises 1. Name four steps (paragraphs) when looking for exemptions from impact testing.
2.
When are impact tests always mandatory for welded joints?
3.
When are impact tests always mandatory for non-welded joints?
4.
What is the minimum design temperature allowed for a 1 ½” thick plate of SA-515 Gr. 70"
5.
If the coincident Ratio is 0.6 for the plate of question number 4 what is its new minimum temperature with out impact tests?
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-77 Material Identification Overview The material for pressure parts must be handled in a particular way per the Code. For instance, the Code specifies that materials for parts of a vessel should be laid out and marked in such a way as to easily maintain traceability after the vessel is completed. Several techniques for identification markings are allowed and are described in this paragraph. Stamping is the preferred method of marking vessel parts; however, as built drawings and tabulation sheets are also acceptable. The manufacturer must maintain traceability to the original markings. For instance, when cutting parts for the vessel from plate the heat number stamped on the piece of plate should be transferred prior to cutting the plate. They may be transferred immediately after cutting if a provision for control of such transfers has been made in the Manufacturer's Quality Control System. If a particular material should not be die stamped, plates must be made and attached with the required markings. A record of these markings must be maintained which will allow positive identification of the vessel parts after construction. If a Code vessel manufacturer buys parts that are formed, such as heads, from another manufacturer of the head shall transfer the markings as applies to the material specification that the part is made from. Only materials allowed by the Code can be used by the part manufacturer. In addition. the part Manufacturer must supply a Partial Data Report. A Manufacturer's Partial Data Report is not required if the part was formed or forged, etc., without the use of welding. The markings of the Part Manufacturer must be present on the part.
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API 510 Module PART UG - GENERAL RFEQUIREMENTS
UG-93 Inspection of Materials Overview The highlights of this paragraph are as follows: 1.
Plate is the only pressure vessel material that must always have a Mill Test Report (MTR)or Certificate of Compliance (C of C) provided. The inspector shall examine these documents for compliance to the material specification.
2.
All other product forms must be marked in accordance with their material specification. For examp1e, pipe marked SA- 106 gr. B.
3.
All materials to be used in a vessel must be inspected before fabrication to find as best as is possible defects which would affect the safety of the vessel. The following describes the inspections required.
API 510
a.
Cut edges of and parts made from rolled plate for serious laminations, shearing cracks, etc.
b.
Materials which will be impact tested must be examined for surface cracks.
c.
When forming a Category C corner joint as shown in figure UW-13.2 with flat plate thicker than ½”, the flat plate must be examined before welding by magnetic particle or dye penetrant nondestructive examination. Exceptions from this NDE are given for certain joints of figure UW-13.2 .
d.
The inspector must assure himself that thickness and other dimensions of the material comply with the requirements of this Division.
e.
The inspector must verify welded repairs to defects.
f.
The inspector must verify that all required tests have been performed and are acceptable (Impact tests, NDE, etc.).
g.
The inspector must confirm material I.D.'s have been properly transferred.
h.
The inspector must confirm that there are no dimensional or material defects, perform internal and external inspections and witness pressure tests.
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-116 Required Marking Overview The marking applied to a vessel's nameplate or directly to its shell are described in this paragraph. It is important information. Often a vessel's Data Report is lost and the only information that is available is that found on the Name Plate or the shell itself In some cases the Name Plate is missing or sand blasted and not readable. The following is a listing of what is required by the Code to be present on the Name Plate. 1.
The official Code U or UM symbol. If Inspected by the Owner/User of the vessel the word USER shall be marked on the vessel.
2.
Name of the manufacturer preceded by the words "Certified by”.
3.
Maximum allowable working pressure __________ psi at _______ °F.
4.
Minimum design metal temperature _______ °F at ___________ psi.
5.
Manufacturer's serial number.
6.
Year built.
7.
The type of construction used for the vessel must be marked directly under the Code symbol by the use of the appropriate letter as listed in the Code. Type of Construction
Letter(s)
Arc or gas welded Pressure welded (except resistance) Brazed Resistance welded
W P B RES
8.
If a vessel is built using more than one type of construction all shall be indicated.
9.
If a vessel is in a special service the lettering as shown below must be applied. Lethal Service L Unfired Steam Boiler UB Direct Firing DF Non-stationary Pressure Vessel NPV
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10.
The MAWP must be based on the most restrictive part of the vessel.
11.
When a complete vessel or parts of a vessel of welded construction have been radiographed in accordance with UW-11, the marking must be as follows:
“RT 1” When all pressure retaining butt welds, other than B and C associated with nozzles and communicating chambers that neither exceed NPS 10 nor 1 1/8” thickness have been radiographically examined for their full length in a manner prescribed in UW-51, full radiography of the above exempted Category B and C butt welds if performed, may be recorded on the Manufacturer' Data Report. “RT 2" Complete vessel satisfies UW-11 (a)(5) and UW-11 (a)(5)(b) applied. “RT 3” Complete vessel satisfies spot radiography of UW-11 (b). “RT 4” When only part of the vessel satisfies any of the above. *A separate section follows which is devoted to the meanings of RT markings: 12.
The letters HT must be used when the entire vessel has been postweld heat treated.
13.
The letter PHT when only part of the vessel has been postweld heat treated.
14.
Code symbol must be applied after hydro or pneumatic test.
15.
Parts of vessels for which Partial Data Report are required shall be marked by the parts manufacturer with the following: "PART" Name of the Manufacturer The manufacturer's serial number. These requirements do not apply to items like manhole covers, etc.
16.
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All required markings must be located in a conspicuous place on the vessel, preferably near a manhole or handhole.
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-119 Nameplates Overview In this paragraph are the details of nameplates, including such things as the size and methods of markings allowed. The nameplate must be located within 30” of the vessel and must be thick enough to resist distortion when stamping is applied. The types of acceptable attachment types include welding, brazing, and tamper resistant mechanical fasteners of metal construction. Adhesive attachments may be used if the provisions of Appendix 18 are met. An additional nameplate may be used if it is marked with the words " DUPLICATE ". On previous tests some essay or multiple choice questions have come from this paragraph. As with all paragraphs UG-119 should be read entirely. CODE SYMBOL
U
Certified by Johns Trailer and Vessel Welding 350 psi at 300°F
W RT 1 HT L
MAWP -20°F at 200 psi MDMT 0000001 S/N 1994 Year
You could be asked for the definition of any of these stampings.
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API 510 Module PART UG - GENERAL REQUIREMENTS
UG-120 Data Reports Overview Data Reports must prepared on form U-1 or U-1A for all vessels that the Code Symbol will be applied to. They must be signed by the Manufacturer and the Inspector. A single Data Report may represent all vessel made in the same day production run if they meet all of the requirements listed in UG-120. A copy of the Manufacturer's Data Report must be furnished to the User and upon request the Inspector. The Manufacturer must either keep a copy of the Data Report on file for 5 years or register the vessel and file the Data Report with the National Board of Boiler and Pressure Vessel Inspectors. A Manufacturer's Certificate of Compliance must be completed on form U-3 for all UM (unfired miniature) stamped vessels. A Partial Data Report form U-2 or U-2A must be completed for parts of a vessel that require one (parts bought from other manufacturers such as formed heads made with welding). These forms must be attached to forms U-1 or U-1A as applies for the vessel to be marked with the Code Symbol.. A Partial Data Report form U-2 or U-2A must be completed for parts of a vessel that are ordered to repair a User's vessel. If a vessel has any special service requirements (Lethal, Unfired Steam Boiler, etc.) compliance must be indicated on the appropriate "U" Form.
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SECTION IX PART QW Article I Welding General Requirements Overview Since this article covers the requirements in general terms it is often given just cursory attention or skipped altogether. This is a mistake for anyone wishing to be competent in applying this section of the ASME Code. It is mandatory to read every article of Section IX in order to apply the code rules and since many questions on an exam could come from this article alone, it should not be overlooked. As an example, the purpose of a welding procedure is given in paragraph QW-100.1. In the very given next paragraph, welders' performance qualification tests are addressed. In QW100.3 it is stated that a Welding Procedure Specification written and qualified in accordance with the rules of Section IX may be used in any construction built to the requirements of the ASME Boiler and Pressure Vessel Code or the ASME B-31 Code for Pressure Piping. In the next paragraph you are cautioned that other Sections of the Code state the conditions under which Section IX requirements are mandatory, in whole or in part. Also in QW-120, QW-130 and QW-132 of this article, test positions are listed with written definitions and references to Article IV where illustrations of these positions are to be found. Types and purposes of tests are addressed in the paragraphs of QW-141.1 through QW-141.5, and all the subsequent paragraphs contain explanations of the tests and examinations required. Acceptance criteria is listed for each type of test described. Beginning with QW-190, other types of tests and examinations are listed, most notable being radiographic and liquid penetrant examinations. Here you are referred to Section V, and then told the acceptance standards of QW-191.2 and QW-195.2 respectively shall be met.
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API 510 Module SECTION IX PART QW Article II. Welding Procedure Qualifications Overview In the QW-200.1 paragraphs you are given the definition of a Welding Procedure Specification (WPS); what its contents must consist of, as well as what changes may be made with out requalifying the WPS. Also, here you are directed that the format may be of any form desired as long as every essential, nonessential and supplementary essential variable (when required) is included or referenced as outlined in QW-250 through QW-265. In the paragraphs of QW-200.2 the same type of information for the Procedure Qualification Record (PQR) is listed as was given for a WPS in the previous paragraph, starting with the definition. As in the WPS, you are given the required contents for a PQR. We are told that changes in a PQR are not permitted except for editorial changes such as the recording of a PNumber incorrectly when filling out the original PQR. Addendum is permitted if it meets the definitions as given in this paragraph. Examples of permitted addendum are given to clarify its meaning. Finally, we are instructed that it is possible to have multiple WPS's with one PQR and also to have multiple PQR's with one WPS. QW-200.3 gives the purpose and an explanation of the use of P-Numbers. It is stated here that P-Numbers are assigned to base metals dependent on characteristics such as composition, weldabilty, and mechanical properties where it can logically be done. Group Numbers are introduced here, stating that Group Numbers are assigned among P-Numbers to classify the metals for procedure qualification where notch toughness requirements are specified. You are also cautioned here that these assignments do not imply that base metals within a PNumber may be indiscriminately substituted. The combination of welding procedures is permitted as given in paragraph QW-200.4. That is to say, more than one WPS can be used in a production joint, and they may include one or a combination of processes. QW-451 is referenced to make sure the reader is aware that limitations are placed on the base metal thickness and the deposited filler metal thickness of each procedure. The type of tests required to qualify a procedure are given in paragraphs QW-202.1 through QW-202.5. Referenced therein are mechanical tests, groove and fillet welds, weld repair, dissimilar base metal thickness and stud welding. In each of the paragraphs, other QW paragraphs are referenced for details and exceptions that might exist. QW-203 states that unless required otherwise by welding variables of QW-250, a qualification in any position qualifies the procedure for all positions. So, most PQR’s can be performed on plate since the goal is to prove that the metal or metals can be successfully joined as opposed to proving the skills of a welder or welding operator. The paragraphs QW-210 through QW-218 address requirements for preparation of test coupons, base and filler metals, special cases of P-No. 11 base materials, corrosion resistant weld metal overlays, hard facings, electron beam welding and joining of composites (clad metals). Beginning with QW-250, welding variables are specified with an explanation of each type. Please notice the definitions of essential and nonessential variables given in QW-251.2 and QW-251.3 Welding Variables Procedure Specifications (WPS) start at QW-252 and end at API 510
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QW-265. These paragraphs are in tabular form and cover some fourteen (14) different welding processes. Within these tables for each process are lists of variables, and whether or not they are essential, nonessential or supplementary essential. These paragraphs in tabular form also reference where in the other code paragraphs specific requirements and definitions can be found.
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API 510 Module SECTION IX PART QW
Article III. Welding Performance Qualifications Overview This article lists the welding processes separately, with the essential variables which apply to welder and welding operator performance qualifications. In QW-300.2, the responsibility for the qualification of welders and welding operators is placed on the manufacturer and/or contractor. One important fact given is that if two companies of different names are actually part of one organization, then one company may control the welder and welding operator qualifications. That is so long as this condition is included in the quality control system of the companies and all other requirements of Section IX are met. Starting with QW-301, tests required for welders and operators are addressed. This includes the intent of such tests, the extent of testing, identification of individual welders along with the records required for such tests. QW-302 calls out the type of tests. They are mechanical or radiographic, and in QW-302.3, the location and removal of pipe test coupons for mechanical tests are described. Next in this series is QW-303 where limits of qualified positions and diameters are located. You are immediately directed to QW-461 which has the graphics defining positions. QW-303.1 through QW-303.4 give details of groove and fillet weld positions and the limits of qualifications for each. Welder qualifications to weld to various WPS's and limitations on qualification by radiography are to be found in QW-304. Specifics of examination for welders begins in QW304.1. It says that welds made in test coupons may be radiographed or have bend tests performed. Alternatively, a six inch length of the first production weld made by the welder being examined may be qualified by radiography. In QW-304.2, failure to meet radiographic standards is discussed. If a production welder's test is flunked, the entire production weld made by the welder being tested must be radiographed and repaired by a welder who is qualified. QW-305 through QW-305.2 is a description of how welding operators are examined and qualified. It's essentially the same as QW-304, with the length of the production radiograph being 3 feet instead of 6 inches. In QW-305 the combining of welding processes requires that the welder be qualified either for each individual process or by the actual combining of the processes in one test coupon. Two or more welders can be qualified by a single test coupon each using the same or different processes. Each welder will be limited for thickness of deposited weld metal as given in QW-452. Failure of any portion of a combination test constituent’s failure of the entire combination. All this is to be found in QW-306. QW-310 to QW-310.3 are concerned with test coupons and welding groove welds with or with out backing. API 510
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In QW-320 retests and renewal of qualifications are divided into two categories. Immediate retest by mechanical or radiography means, and retest after further practice. QW-321.1 outlines the mechanical tests and basically says the welder will make two consecutive test coupons for every position he failed, all of which must pass the test requirements. Retest by radiography is laid out in QW-321.2. How to handle situations dealing with further training is found in QW-321.3. Renewal of a welder's qualification for a process is mandatory when he has not used the process for the time limits as given in QW-322.1 (a) and (b). The QW-350 paragraphs have all of the variables for welders and here you will find what changes to his essential variables will require a welder to requalify. QW-352 to QW-357 are in tabular form in order to easily determine the essential welders variables for each process. QW-360 to QW-364 have the essential variables for welding operators.
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API 510 Module SECTION IX PART QW
Article IV. Welding Data Overview This article contains within it all of data for the variables that pertain to Welding Procedure Specifications and Welder Performance. These include joints, base metals, filler metals, preheat, postweld heat treatment and electrical characteristics. By using the tabular paragraphs and reading the written paragraphs they reference, requirements for a welding procedure or a welder's performance test can be interpreted. Since metals are given P-Numbers and their P-Numbers greatly affect their applications, they are listed by P-Number; for qualification in the tabular forms of paragraph QW-422 which is 52 pages long. In QW-423.1, it is given that base material for welder's qualification to a WPS may be substituted with a different base material, and lists the permissible substitutions. QW-430 starts the F-numbers for electrodes and welding rods, these paragraphs are also in tabular form. QW-440 addresses weld metal chemical composition. As can be seen there are 12 ANumbers. As the A-Number must be listed on the WPS, one should become acquainted with these A-Numbers. The remaining paragraphs of Article IV deal with thickness 1imits for tension and bend tests, diameter limits, fillet welds, test specimens and their order of removal. Also given are the configurations of test jigs. In short, Article IV is where you will be constantly sent for the "how to's of welding in accordance with the ASME Code. Remember that it is possible to write a perfectly good welding procedure using Section IX that will not meet one of the construction codes. An important paragraph for understanding Section IX is QW-492 "Definitions". If in doubt go here first for clarification. Lastly, nonmandatory appendix A has sample forms that list the necessary information for the WPS, PQR and WPQ.
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API 510 Module SECTION IX PART QW
Welding Procedure Specification Overview In all welding procedures there are three (3) types of variables. The first is being the essential variable, which is a variable that if changed will cause a change in the mechanical properties of the weldment. Any time an essential variable is changed outside of the range given in the WPS, the procedure must be requalified by mechanical testing on the weld using the new values. The second type is the nonessential variable. Changes in these can be made without requalification of the WPS. HOWEVER, THE WPS MUST BE REVISED TO REFLECT THESE CHANGES. Lastly, the supplementary essential variables need only be given if the weld must have specific impact properties for low temperature service. If supplement essential variables are required they automatically become essential variables and must be handled the same as any other essential variable. That is to say all required testing (including impact testing) must be done to qualify the WPS. The purpose of this portion of instruction is not to teach every welding process recognized by the ASME Code. It is to concentrate on the Shielded Metal Arc Welding process, which will serve as an example for all of the procedures that could be on the API 510 exam. The way to understand how WPS’s are created is to turn to Article 11. In our case specifically to paragraph QW-253 (SMAW). Here the essential, supplementary essential and nonessential variables are given. As can be seen, there are several variables to be dealt with. When a WPS is written every variable listed must be included whether or not it is essential, supplementary essential (when required) or nonessential. Joints There are no essential or supplementary essential variables given for the joint category. However, we do have four (4) nonessential variables. As stated above, all variables (when required) must be included in the WPS. Our first variable, which pertains to joints, is groove design.
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Groove Design Looking in the box labeled joints, we see that information on grooves may be found in paragraph QW-402.1. A change in groove from double vee to single vee can be made with only a revision in the WPS. Here, why not enter All Joints in the WPS? Then you can legally use any you need now or later. If you specify "U" groove on the WPS, you must use only U grooves in production or revise the WPS to reflect the new groove. Also, you must use a U groove when performing the PQR. Although the PQR need not list any of the nonessential variables, the signature of the manufacturer's representative is testament to using one of the grooves listed on the WPS. Backing: The deletion of backing is a nonessential variable specified in QW-402.4. If we do not want to place unnecessary restrictions on ourselves we can state this variable as being "With Or Without Backing"; or simply place X's in both blocks.. Root Spacing: Here again this is a nonessential variable. possible. Do not leave this blank e.g. 1/32nd to 1/16th inches.
Give the widest range
Retainers: "With or Without" is appropriate. Don't leave it blank. If you are not going to use retainers you should so indicate. "No retainers used". Base Metals In this category there are no nonessential variables. There are only essential and supplementary essential variables. Supplementary essential variables apply only when impact properties are required. They put restrictions on the base metal material that can be qualified with any one PQR. It also puts restrictions on the base metal thickness range that can be qualified when running a PQR. Group Number: A change in a group number becomes an essential variable when impact properties are required of the base material. T Limits Impact: In QW-403.6 the minimum thickness ranges qualified by impact testing is called out. T/t Limits > 8 in.: This is the first essential variable in the base metal category. It becomes effective when trying to qualify welds greater than 8 inches in thickness. Change in T Qualified: Essentially it stipulates that the welding procedure depending on the thickness of the coupon used in the PQR is qualified for a range of base metal thickness. If base metal thickness goes beyond that qualified, a new PQR will be required. t Pass > 1/2 in.: This variable speaks to weld passes that deposit a weld metal layer greater than 1/2 inch in thickness. When weld metal is deposited in a thickness greater than 1/2 in., it has a different range than lesser thicknesses. A t pass greater than 1/2" limits the base metal qualified to 1.1 x T, where T is the thickness of the PQR test coupon. Change in P-No.: Any change in P-Numbers requires requalification of the procedure. Change in P-No 9 / 10: Here we find changing from P-No. 9A to P-No. 9B is considered a change but not the reverse. API 510
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Filler Metals In the filler metal category, all three types of variables apply. The first two have to do with chemistry and the types of electrodes used in the welding process. The F number is a grouping of electrodes that have similar characteristics in the way that they produce mechanical properties. Deposition is also similar among F Numbers. A-Numbers are chemical limitations and all electrodes that fall under the same A-Number have similar chemical properties. A-Numbers apply only to ferrous materials. Change in F-number: Requires requalification of the procedure. Change in A-Number: Requires requalification of the procedure, except as given in QW404.5, which says that A-No. 1 and A-No. 2 can be exchanged. Change in Diameter: Since this is a nonessential variable changing it does not demand requalification of the procedure. However, you should revise the WPS to reflect the change. Change in Diameter > 1/4 in.: This is used as a supplementary essential variable. It says that if impact properties are necessary and an electrode of greater than 1/4 inch is used, that size electrode must be qualified for impact properties in the weld. Change in AWS Class: Requires requalification as a supplementary variable if impact properties are required. This is an SFA number given in Section II of the ASME Code. Change in t: A change in the thickness of deposited weld metal beyond the range qualified. Change in AWS Class: This is a nonessential variable where impact properties are not required. It must be addressed on the WPS however. Position There are three (3) variables listed for position. Notice that unless impact properties are required position is a nonessential variable. Again when specifying position as a nonessential variable, don't box yourself in, Just say "all". Addition of a Position: Nonessential but the WPS must be revised if one position is given then another is used in production. Change in Position: A supplementary essential variable, which becomes essential when impact properties are required. Specifically when you change from any position to vertical uphill progression. Also if changing from a stringer bead in the vertical uphill to a weave bead. Either will require requalification of the procedure. Preheat There is one essential variable, one supplementary essential, and one nonessential variable listed in this category. Decrease > 100 degrees: If a procedure is qualified at a given preheat, a reduction of that preheat by greater than 100 degrees in production requires requalification of the WPS.
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Preheat Maintenance: This is the continuance of preheat temperature after the completion of welding. Will preheat be maintained for a given time or will the weld be allowed to cool in air and not monitored? Increase > 100 degrees:(interpass temp.): If the weld requires impact values using the Shielded Metal Arc process, the interpass temperature must be maintained below some maximum temperature. If the interpass temperature is increased by more than 100 degrees over what was qualified, the procedure must be requalified.
Post Weld Heat Treatment The first variable given is a change in postweld heat treatment. This is an essential variable. While it is not always necessary to postweld heat treat a material, a change in postweld heat treatment or the lack of is an essential variable and must be reflected on the WPS and the PQR. Change in PWHT: If PWHT will not be performed, this should be indicated on the WPS by entering the words: “No Postweld Heat Treatment" or simply “None". If PWHT is required and then changed from that specified on the WPS, the WPS must be requalified since it is an essential variable. PWHT (Time and Temperature Range): Again when impact properties are required of a weldment, a change in the time span of PWHT or the temperature range will require requalification of the procedure. Thickness Limits: As indicated, this is an essential variable. It deals with exceeding the upper transformation temperature of alloys. It says that if the test coupon being heat treated exceeds the upper transformation temperature of the alloy the maximum thickness qualified is 1.1 times the thickness of the test coupon as opposed to two times the coupon thickness allowed if the upper transformation has not been exceeded. See QW-451 for T limits.
Electrical Characteristics Change in Current or > Heat input: This is a supplementary essential variable that deals with impact properties. Here if the heat input due to welding is changed or the type of current is changed resulting in an increased deposition of weld metal the procedure must be requalified for impact values. Change in the Type of Current or a Change in the Current or Voltage Range: These are both nonessential, but if changed in the Shielded Metal Arc Process, the WPS must be revised to reflect the change.
Technique Change in String or Weave Bead: Nonessential, but if other than that qualified on the WPS, the WPS must be revised to reflect the change for production. Change in Method of Cleaning: Same as above. Change in Method of Back Gouge: Same as above. API 510
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Change in Manual or Automatic: Same as above. Addition or Deletion of Peening: Same as above.
Procedure Qualification Record The next document required by the ASME Code is the Procedure Qualification Record. Its purpose is to record the values of essential variables actually used during the qualification test and to report the mechanical properties obtained using the essential variables of the WPS. One should know that only a listing of the essential variables values used while welding the test specimen are required on the PQR. The suggested ASME forms provide spaces to list supplementary essential when required and nonessential variables if so desired. If these nonessential variables are listed they should be the values actually used to weld the test coupon. A range of thickness qualifications for base metal and deposited weld metal is allowed in the ASME Code. Let's say a test plate had a thickness of 1/4 inch. If the test coupons taken from it pass mechanical tests, the procedure would he good for base metals 1/6th inch minimum to a maximum of 1/2 inch. When qualifying welding procedures, make sure that the thickness used for the test coupon will cover the thickness used in production. Deposited weld metal should he given the same consideration as should the combination of weld processes. Always be sure the thickness used will cover your maximum production needs or you may be requalifying a procedure. The thickness qualified by the PQR may only support part of the range of thickness desired on the WPS. If that were the case, another PQR would be needed to finish out the range of T on the WPS and to weld all of WPS range in production Welder Performance Qualification Record This document lists all of the values used by the welder when performing his test weld coupon. It also gives the thickness ranges he is qualified for. To best understand the welder’s essential variables, turn to table QW-353 and review it. You will notice that the welder has four (4) categories of essential variables. Joints involve the addition or removal of backing. Base metals are concerned with P-Numbers. Filler metals address F number ranges and the thickness of deposited weld metal. Lastly, the addition of a more difficult position than the one originally tested for or a change in vertical progression from up to down or down to up. The change of one of these essential variables will require the welder to requalify. The ASME Codes place the responsibility on the manufacturer or contractor to insure all welders are qualified for production welds. Review of WPS's and PQR's On the examination, the API candidate will be given a WPS and a PQR and asked to identify the errors or unsupported requirements contained in these documents. This means that you should examine BOTH the WPS and the PQR. You will be told not to correct the deficiencies, only to identify them. When reviewing the WPS, look for information which has been omitted. Every Essential, Nonessential and when needed supplementary variable should be addressed. Also, common errors are made in such things as base metal classifications, base metal thicknesses. Remember the PQR test coupon T can and may only support part of the range desired by the WPS. API 510
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Backing is often over looked. Since the addition or deletion of backing is a nonessential variable the best course would be to state with or without in the WPS. Retainers and Root Gap must also be listed on the WPS. These should not be left blank. Sizes of electrodes are again nonessential and listing all sizes that are manufactured of a certain classification that will be used for production is wise. If a 1/32nd rod is given for WPS and 1/8th is used for production the WPS will need to be revised. Finally, check each category of variable required on the SMAW table QW-253 to see if it has been addressed on the WPS. If it is given as not applicable, make sure that it is a true statement. If it is left blank, by very definition, that is an error. Also, check the specifications to see that they are given correctly and match on the WPS and PQR. If we are given a E-7018 filler metal and it is listed as having a F-number of 3, is that correct? It is given in table QW-432 as having a F-No. of 4. To recap, if a variable; essential, nonessential and if needed supplementary essential variable is listed in the paragraph for a process, it must be addressed on the WPS. API 510 Body of Knowledge has a step by step procedure for the review or WPS's and PQR'S. The approach starts with the review of last page of the PQR. The following is a reproduction of that fist with added comments to help with clarification a. It must be determined if impact tests are present. The reason of course is because if impact tests are present, supplements essential variables do apply to the review. If they are present, it then becomes a bit more difficult to review the documents. b. At the bottom of the PQR is a signature line for the manufacturer. This line must contain a signature, not a typed name. c. Turn to the front of the WPS and verify that the WPS references the PQR’s number. The reverse is not true the PQR may or may not reference the WPS. A WPS can be written from a very old PQR and often is. d. Place the WPS and PQR side by side and verify that: 1. All essential (and supplementary essentials if present) variables are present have been addressed on the WPS and PQR. By using the paragraph in Section IX Article II, that applies to the process used, check each box in the WPS and PQR against the Code paragraph line by line. 2. The essential variables on the WPS must be supported by the PQR. Is the post weld heat treatment required on the WPS and is it present on the PQR, etc.? e. Review the WPS for the presence of all nonessential variables that are required of the welding process used. If peening is present in the Code paragraph that applies to the process, it should be mentioned directly in the WPS 'No Peening' for example. That line should not be blank or contain N/A . Peening is applicable or it would not be present in the Code paragraph. f. Look at the PQR. Are all the mechanical tests present? Are they of the correct types and of the correct number. g. Check for mistakes such as the wrong P number for a material, Wrong F number for a welding rod, etc. API 510
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Practice reviews of WPS's and PQR's Instructions Remove the practice WPS and PQR's and the Weld Procedure Check list from the Appendix of this book and place them along side this text. Follow along step by step as we review them together. Also remove the paragraph QW-253 from Section IX. This paragraph is a tabular listing of the variables that must be addressed for the SMAW process. It will be used as a check list to make sure that every thing that should be addressed has been. KEEP IN MIND THAT THERE CAN BE NO MORE THAN 5 MISTAKES. Begin with the WPS and PQR titled Confusion Welding. 1. Turn to the last page (the back of the PQR) and look at the block titled Toughness Tests QW-170. We observe that there are no Charpy notch toughness test results so we can ignore the supplementary variables of QW-253 for SMAW. 2. This PQR has a signature-no mistake here. 3. Turn to the front of the WPS and see if the Supporting PQR numbers match those on the PQR. The numbers match, so no mistake here. 4. Now using QW-253 we will do a block by block review beginning at the top of the WPS front page.
Front of the WPS •
Joints (QW-402) 1. Joint (groove) design is addressed, i.e. not blank. No mistake here. 2. Backing is addressed. The two x's are to indicate with or without backing. 3. Backing addressed as metal in the box below, however retainers are not addressed. This is the first mistake - RETAINERS NOT ADDRESSED 4. Root spacing has been addressed by the sketch.
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Base Metals (QW-403) 1. P-No. is addressed, no mistake here (by the way since no impact tests are present Group Numbers are not required. Also if this were to have P No. 1 addressed once, that is to say nothing appeared on the "to" line, then only P No. 1 materials could be joined with this WPS. It would not be called a mistake. You could only weld P No. 1 materials however. 2. Groove - the proposed production thickness range has been stated - no mistake. If it were blank it would be an omission and therefore and error.
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Filler Metals (QW-404) 1. SFA No. Listed as 5-1 instead of correctly given as 5.1, not a mistake an obvious typographical error. 2. AWS classification listed as E-7018, no mistake by omission. 3. F-No. Listed as # 3 all E-XX18 electrodes are F-No. 4 WRONG F NO. see OW-432.
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4. A-No. addressed as #1. This is correct for mild carbon steel electrodes, the A-No. will not change until an alpha numeric is added to the end of an electrode designation. For example if the electrode listed been listed as E-7018 B2, this would indicate that the deposited weld metal had a different chemistry and that its A-No. would be other than #1. There is no way to determine directly the A-No for these modified electrodes in Section IX. If the chemistry of such an electrode's deposited weld metal is known it may be compared that given for the various A-Nos. and identified in that way. The only thing known for sure is that it cannot be an A-No. 1 when it contains something like Al or C2 behind the AWS numbers. •
Weld Metal (QW-404) 1. Thickness Range - Since we are using only one electrode for production the weld metal thickness range will be same as the base metal thickness range. This means this could be left blank and would be answered by default. To better understand this, look at the WPS, notice we have spaces to list up to three electrodes. For example, say we used E-6010 and E-7018, then each would require a weld metal thickness range. 2. The remaining spaces are for information only and can be left blank if so desired in the case of the SMAW process. This would not be true if another process were used which required this information.
Reminder-All variables that apply to a given welding process must be addressed on the WPS (notice this is not true of the PQR). This includes Essential, Supplementary Essential (only when notch toughness applies), and Non-essential. Back of the WPS •
Positions (QW-405) 1. Positions are instructions to the user, that is what positions are permitted in the production of a weld using this WPS. It is a nonessential variable as listed in QW253. It has been addressed and therefore no mistake exists. Think about, it would rather be difficult to use a WPS that only allowed the 6G position. In most cases such a WPS would be revised or re-written to include more than a single position. This is not however a mistake, since the non-essential variable has been addressed.
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•
Preheat (QW-406) 1. The minimum preheat has been given as 60°F. Preheat becomes essential when welding is performed with a preheat greater than 100°F less than that stated on the WPS. In this WPS it would require that welding preheat be lowered to -39°F. Preheat must be stated on the WPS, it is needed to confirm that the PQR was not performed with a preheat more than 100°F below that stated for production welds on the WPS. There is not a mistake unless preheat is riot given. Some WPS's simply state ‘Warm to the touch’. 2. The interpass temp is listed, and that’s fine however it is not required on this WPS because there are no toughness test results present on the PQR. 3. Preheat maintenance is not addressed, this is an error by omission. All essential and nonessential variables listed for a given process must be listed. The important thing to remember is that preheat maintenance is listed in QW-253 for the SMAW process, and it must be addressed. The statement None would have been good enough.
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Postweld Heat Treatment (QW-407) 1. This one is easy. There will be NONE and that is all that is needed to address the item. Of course the PQR should not show Post Weld Heat Treatment in order to support this WPS.
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Gas (QW-408) 1. Shielding gas is not used with this process-ignore this block for SMAW
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Electrical Characteristics (QW-409) 1. Current AC or DC, Straight or Reverse, Amps and Volts must be addressed and can be totally wrong for a given electrode. If it is addressed it is not a mistake. Welders find many mistakes here because they know that it won't work. As far as the review for the test goes, if it is addressed right or wrong its good to go and there is no mistake here to list on the answer sheet. This is true of all non-essential variables. 2. The rest of the variables do not belong to the SMAW process and any thing placed on these lines can be and should be ignored for the test.
Technique (QW-410) 1. 2. 3. 4. 5. 6. 7. 8. •
String or weave is addressed Orifice or gas cup / (N/A) Not applicable to SMAW Cleaning addressed Back gouging addressed Oscillation N/A Contact Tube N/A Multiple or single pass, multiple or single electrodes, travel speed (all N/A) Peening called N/A THIS IS A MISTAKE Peening is applicable to SMAW!
Tabular form at the bottom of the back.
1. This form listing details of different process passes and filler metals. With only one filler metal and process such as we have in this WPS/PQR it is normally left blank. If it is not and any differences are found with it and the body of the WPS they are meaningless and should be ignored. DO NOT list any of these as mistakes on the answer sheet. API 510
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Recap of mistakes found on the WPS 1. 2. 3. 4.
Retainers not addressed Wrong F-No. for E-7018 electrode Preheat maintenance not addressed Peening addressed as Not Applicable (N/A), IT DOES APPLY TO SMAW! CHECK QW-253. What was probably meant when this statement was made? Peening will not be used. The correct approach would be to enter the word NONE. That is true of any nonessential on any process, for example, if you intend to use a closed joint and no root spacing, some correct ways to address this would be, Root Spacing None or ± 0. Some indication must be given for each non-essential variable. Review of PQR
The first statement to be made about review of a PQR is that PQR’s do not require nonessential variables be listed on them. Confirmation of this statement is found in paragraph QW-200.2. Since non-essential variables need not be recorded on the PQR they can be and should be totally ignored during the PQR review. There cannot be a mistake on a nonessential variable listed on a PQR. It is not required to be there and if it is, it cannot be wrong. WPS’s can be written from PQR’s that are very old, the interest in the PQR is in the essential variables that it supports. These include the P No., F No., base metal thickness, postweld heat treatment, and the rest of the essential variables for a given process. Front of the POR •
Joints (QW-402) 1. Blank not a mistake, doesn't need to be addressed (non-essential)
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Base Metal (QW-403) 1. Material specification is SA-53 grade B. The WPS states that P No. 1 materials are to be welded in production. SA-53 is a P No. 1 material so this PQR supports the WPS. Go to the material specs of QW-422 and look it up if you are not sure. 2. Thickness welded .500" this supports the upper range of thickness to be welded in production listed on the WPS as 1/16” to 1”. Looking at QW-451.1 we see that this coupon will support the range from 3/16” to 1”. If lower thickness’ are to be welded then a second PQR will be required. This is not a mistake on the PQR. This is hard to accept, but it is not. It would be tidier to have them match, but as long as no welding is done outside the range qualified by the PQR test specimen, no complaint can be made. Filler Metals (QW-404)
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1. 2. 3. 4.
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A No. 1 correct for E–XX18 Size of electrode could have been left blank (nonessential). F No. 4 correct for E-XX18 Other / deposited weld metal 1/2 in. Look at QW-253 paragraph QW-403 base metals, here it states that an increase in deposited weld metal to greater than 1/2 in. is an essential variable. This must be addressed. If a single pass greater than 1/2 in. is deposited the maximum range of the base metal thickness to be welded in production is reduced to 1.1 time the coupon thickness. This would change the range from the 2T found in QW-451.1. In this case the test coupon was 1/2 in. so this rule does not apply.
Positions (QW-405) non-essential anything or nothing (it can be blank).
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Preheat (QW-406) must be addressed and cannot be greater than 100°F below that stated to be used in production on the WPS, 50°F is not, so there is no mistake here.
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Postweld Heat Treatment (QW-407) addressed correctly as None.
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Gas (QW-408) not essential to the SMAW process Electrical (QW-409) nonessential anything or nothing here is ok
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Technique (QW-410) nonessential anything or nothing here is ok Back of PQR
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Tensile Test (QW-150)
Since there are two tensile specimens present and the test results indicate pass, there are no mistakes here. You can do the arithmetic to check and see if there is a mistake there. Multiply the width times the thickness and determine the area. Divide the area in to the ultimate load and this should yield the ultimate unit stress. Since this PQR does list the actual material used for the test coupon you can go to the P Nos. listed in Section IX and check for the ultimate strength of SA-53 gr. B. If QW-403 states only the P No. of the material used to make the coupon then there is no way to determine if the material failed at or below its specified minimum ultimate strength. Basically all that can be done is check to see if the math is correct and that two samples are present. •
Guided Bend Tests (QW-160) In this block we show four side bends, this is ok since coupons from 3/8 in. up to but not including 3/4 in. can be tested four side bends as an alternative to two face and two root bends. See QW-451.1 footnotes.
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Toughness tests have not been performed, fillet weld tests don't apply to groove weld procedures, and we have already checked for a signature. Second WPS/PQR review
Remove Wee Welders WPS and PQR from the appendix and review those for mistakes just as was done with Confusion Weldings WPS and PQR.
The mistakes are as follows see if YOU agree.
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Back of PQR • •
Toughness test results are not present so Supplementary Essential Variables do not apply during the review. The PQR has a typed name and not a signature. This is a mistake!
WPS • •
WPS references the PQR by number, no mistake here. Joints (QW-402) 1. Root gap not addressed 2. Retainers not addressed
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Filler Metals (QW-404) 1. E-7018 given F-No. of 3
PQR •
Filler Metals (QW-404) 1. E-7018 is not F-No. 3 (this mistake is present on the WPS and really does not need to be listed again).
The total mistakes between the WPS and PQR are 4.
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API 510 Module SECTION V (NDE Subsection A)
Article 2 Radiography General Overview The scope of this article states that when this Article is referenced by another code, the radiographic method described within, along with Article 1, shall be used. Compliance to the procedures in the Article can be met with or without a written procedure as outlined in T221.1 and T-221.2. Surface preparation is addressed in T-222. The three areas of concern are: materials T-222. 1, welds T-222.2, and surface finish T-222.3. Backscatter radiation indication is detailed in T223. A system of identification to maintain traceability of a radiograph as to its location, vessel and manufacturer are detailed on T-224. T-225 Monitoring Density Limitations of Radiographs allows for two methods of monitoring the density of film, a densitometer or a step wedge comparison film shall be used. T-231 requires that radiographs be made using industrial film. The processing for film is referenced to the appropriate standards in T-231.2 . T-232 says that intensifying screens may be used except if restricted by a referencing code. Imaging Quality Indicator design is designated to be the hole type penetrameters or the wire type in T-233. Facilities for the viewing of radiographs are described in T-234. Paragraph T-260 Calibration and its subparagraphs address verification of Source Size, Determination of Source Size and Step Wedge Film and Densitometers. T-270 covers examination starting with T-271 Radiographic Technique then T-271.1 Single Wall Technique. Lastly, T-271.2 details the Double Wall Technique. Selection of Radiation Energy begins with T-272. T-272.1 provides for maximum voltages when using X-Radiation. These are based on material and their thicknesses as in Figures T272.1 (a)(b)(c). In T-272.2 Gamma Radiation Recommended given minimum thickness limits are based on the subject material and the type of source being used. These limits on the minimum thickness are not mandatory if a procedure on thinner material can be proven by actual demonstration of penetrameter resolution as given in T-272.3.
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T-273 says that direction of the central beam should be centered on the area of interest. T-274 lists a formula for the determination of Geometric Unsharpness; each variable in the formula is explained. T-275 requires the use of location markers and that they be placed on the part and not the exposure holder/cassette. The graphics in Figure T-275 detail the different locations of the markers. T-275.1 Single Wall Viewing contains information on placement of location markers. There are three situations: Source Side markers, Film Side Markers and either Side Markers in this sub paragraph. Image Quality indicators are to be selected in accordance with T-276. You are referred to Table T-276 for both penetrameters hole type designation the essential hole and the wire size of Wire type indicators are listed. Table B-220 of Article 2, Non-mandatory Appendix B may be used to determine approximate equivalence between hole penetrameters and wire penetrameters. T-276.2 (a) Welds with Reinforcements states that the thickness of the penetrameters is based on the nominal single wall thickness plus the estimated weld reinforcement not to exceed the maximum allowed in the referencing Code Section. Backing rings or strips are not considered during penetrameter selection. T-277 begins the particulars of use for penetrameters. T-277.1 states where they are located. T-277.2 deals with how many penetrameters are required. T-277.3 limits shims placed between the hole type penetrameters and the part to a material radiographically similar to the weld metal, Shims shall exceed the penetrameter dimensions such that the outline of at least three sides of the penetrameters image shall be visible in the radiograph. T-280 Evaluations starts with T-281 Quality of radiographs. Contained in T-281 are such things as the condition of the radiograph. The film shall be free of mechanical, chemical or other blemishes so as not to mask or confuse the image in the area of interest. T-282.1 renders density limitations with the actual values listed. T-282.2 allows for variation of density through the area of interest. It is limited to minus 15% to plus 30% from the body of the hole penetrameter or adjacent to the designated wire of a wire type penetrameter. Also the exceptions for shim use are detailed. IQI Sensitivity requirements of T-283 are stated as being sufficient to display the hole penetrameter and its designated hole. Wire types shall display the designate wire size. Restrictions are in this sub-paragraph. T-284 Excessive Backscatter says that the letter "B" should not appear as described in T-223.
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T-285 Geometric Unsharpness Limitations as calculated using the formula of T-274 shall conform and not exceed those listed in this subparagraph based on material thickness. T-291 deals with documentation minimum requirements. T-292 states that the manufacturer shall examine and interpret the radiograph prior to submittal to the inspector. Nonmandatory Appendix A of Article 2 contains technique sketches for pipe or tube welds. Other techniques may be used. Appendix B compares hole wire sizes. Appendix C gives sketches for hole types penetrameter placement, again nonmandatory.
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API 510 Module SECTION V (NDE, Subsection A) Article 5 Ultrasonic Examination Overview T-510 the scope of Article 5 contains all of the basic technical and methodological for ultrasonic examination. It applies to welds, parts components. materials and thickness determinations. You are cautioned that when Article is referenced by another Code Section that the Code Section shall determine extent of examination, etc. T-522 requires that Ultrasonic Examination be performed to a written procedure. The minimum information to be contained in the procedure are listed. T-523 begins General Examination Requirements for other than thickness measurements. T-523.1 lists the amount and how the inspection will be performed. T-523.2 specifics a rate of movement for the search unit T-530 Equipment and Supplies deals with the frequency, screen height linearity, amplitude control linearity, checking and calibration of equipment, also search units. T-540 Applications and its subparagraph details the requirements for procedures with various product forms. Equipment, calibration and examination information are rendered in the text. T-542.7 Examination of Welds starts with surface preparation of base metal as well as weld metal. Scanning techniques for both straight beam and angle beams methods. Angle Beam is separated without reflectors oriented parallel to the weld. T-524.7.2.5. Evaluation sets limits on imperfections and the indications that are acceptable without further investigation. T-542.8 Ferritic Welds in Ferritic Pipe sets up basic calibration. T-542-8-1.1 describes a required calibration block made from a section of pipe of the same nominal size, schedule, heat treatment, and material specification or equivalent P-number grouping as one of the materials being examined. Figure T-542.1.1 illustrates such a calibration block. T-590 Reports and Records requires reports written and that they include the weld(s) or volume examined, the location of each recorded reflector, and the identification of the operator or operators who carried out the examination or part thereof. Article 5 mandatory appendixes gives specifics on screen height linearity and amplitude control linearity, You are referred to Figure I-1 for angle beam search unit placement. In each instance a procedure for verification of accuracy of the equipment is described.
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API 510 Module SECTION V (NDE Subsection A)
Article 6 Liquid Penetrant Examination Overview T-600 in the introduction of this article, Liquid Penetrant Examination, is described as an effective means of detecting discontinuities which are open to the surface. Discontinuities that can be detected and principles of operation are contained here. T-610 scope covers when this Article applies and where standards for Liquid Penetrant can be found. T-621.2 allows for revision to the procedure under the circumstances found in this subparagraph. Techniques of T-622 are given as either color contrast (visible) penetrant or a fluorescent penetrant. Three processes are included. They are: Water Washable, Post-Emulsifying and Solvent Removable. Combinations are allowed and can result in up to six liquid penetrant techniques. T-623 Penetrant materials is a definition of penetrant as it applies to this article. T-624 Prohibits a technique allowing the following of color contrast penetrant with a fluorescent penetrant exam. Intermixing of different families or manufacturers is prohibited. Control of contaminants T-625 states the user of this Article shall obtain certification of contamination content of all penetrants used on austenectic stainless steels, nickel based alloys and titanium. T-625 outlines the handling and requirements of the certification based on materials. T-626 permits surface preparation by grinding, machining or other methods. Prior to each exam the area to be examined and at least one inch adjacent shall be clean as described. T-627 puts forth three methods of drying after preparation (cleaning) which are acceptable prior to the penetrant exam. T-641 temperature ranges during a penetrant exam are listed as being not lower that 60°F nor above 120°F throughout the examination.
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Penetrant can be applied by any suitable means, such as dipping, brushing or spraying other techniques of application are also contained here in subparagraph T-642.
T-643 specifies Penetration Time (dwell) as critical and references the SE Standards given in T-610. T-644 Excess penetrant removal is required by this paragraph only after the specified penetration time. Methods of penetrant removal begins in T-644.1 with water washable. T-644.2 talks to Post Emulsifying and T-644.3 addressees Solvent Removable penetrant. Development of the penetrant shall be applied as soon as possible after penetrant removal according to T-646. The thickness of coating must be controlled so as to draw out any indications or conversely mask an indication. Information on the application of Dry and Wet Developers is contained in T-646.1 and T646.2 respectively. Interpretation of penetrant test directions begin in T-647.1. Final interpretation shall be made within seven (7) to thirty (30) minutes. The developing time is specified in T-646.3. Paragraphs T-647.2, T-647.3 and T-647.4 pertain to the particulars of interpretation.
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API 510 Module SECTION V (NDE Subsection A)
Article 7 Magnetic Particle Examination Overview In the introduction of T-700, the applications of Magnetic Particle Examination and a general description of the principles are given. The scope of Article 7 is contained in T-710. Article 7 is, in general, an agreement with SE-790 Standard Recommended Practice for Magnetic Particle Examination. T-721 describes what examination procedure shall be based on. Included are shapes and sizes of materials to be examined, magnetization techniques and other variables. The method of examination is provided in T-722. The examination shall be done using the continuous method of magnetization of the part or weld. That is, the magnetizing current will remain on during particle application or the removal of excess particles. T-723 has a description of techniques and materials acceptable to this article. Ferromagnetic Particles may be either wet or dry. Five (5) different magnetization techniques are listed. In T-724, acceptable methods of surface preparation are given as grinding or machining if surface irregularities could mask indications. Type and extent of cleaning is also found in this paragraph. T-725 contains references to T-722 and T-240 for a suitable means to produce the necessary magnetic flux. A description of acceptable ferromagnetic particles is in T-726. All supporting standards are quoted. Also contained are the requirements for black light usage with fluorescent particles. If magnetizing techniques are such that adequacy and direction of magnetic field are in question, a magnetic field indicator, as described and illustrated in T727, shall be used. In the remaining paragraphs this Article, direction of examination extent of coverage and five (5) acceptable techniques are detailed.
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API 510 Module SECTION V (NDE Subsection A)
Article 9 Visual Examination Overview T-910 the scope of this article states that the visual examination involved in interpretation of the various nondestructive examination methods is not intended to be included in this Article. Written procedures for visual examination are required by T-922. Its paragraphs explain the details of the content and the application of such a procedure. T-940 gives that such things as surface condition of the part, alignment of mating surfaces, shape or evidence of leaking are generally determined by visual examination. T-950 provides that all examinations shall be evaluated in terms of the referencing Code Section. A checklist shall be maintained to verify visual observations checklist shall establish minimum examination and inspection requirements and does not indicate the maximum exams a Manufacturer may perform.
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ADVANCED MATERIAL
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API 510 Module
Static Head of Water The static head of water is equal to 0.433 psi per vertical foot above the point where the pressure will measured. For example the static head of water at a point in a vessel with 10 feet of water above it is calculated by multiplying 10 x 0.433 psi.. 10 x 0.433 = 4.33psi The 4.33 psi is being exerted totally by the weight of the water. No other external pressure having been applied. If an external source of pressure is applied it would be added to the static head pressure of the water at any given point in the vessel. Suppose an external pressure from a pump of 100 psi is applied to the above vessel. This pressure would be added to the 4.33 psi that already exists from the static head for a total pressure at that point of 104.33 psi. From this simple principle the following concepts must be understood. •
Case 1. How do you determine static head based on a given elevation?
•
Case 2. When do you add the static head pressure in vessel calculations?
•
Case 3. When do you subtract the static head in vessel calculations?
•
Case 4. How do you calculate static head on ellipsoidal and hemi heads?
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Case 1. To determine static head based on an elevation from a stated problem it must be understood that elevations are normally taken from the ground level for an existing vessel including any base the vessel is on. You must subtract the GIVEN elevation form the TOTAL elevation to determine vertical feet of static head above the given elevation. Example: A vessel has an elevation of 18 feet and is mounted on a 3 foot base. What is the static head pressure of water at the 11 foot elevation which is located at the bottom of the top shell course?
7’ 11’ 18’
You must realize it is the number of vertical feet above the GIVEN elevation in question which causes the static head at that point. To find the static head you must subtract the elevation of the GIVEN point from the TOTAL elevation given for the vessel. 18' feet total -11' desired point 7' total static head Static head pressure at 11' elevation is: 7 x 0.433psi = 3.03 psi
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Case 2. Static head at a point in a vessel must be added to the pressure used (normally vessel MAWP) when calculating the required thickness of the vessel component at that elevation. Example: Determine the required thickness of the shell course in Case 1. The vessel's MAWP (Always measured at the top in the normal operating position) is 100 psi. The following variables apply: Givens: t=?
Circumferential stress From UG-27(c)(1) PR
P=100 psi + Static Head
t= SE - 0.6P
S= E= R=
15,000 psi 1.0 20”
Since the bottom of this shell course is at the 11 foot elevation the pressure it will see is 100 psi + the static head. or 100 + 3.03 = 103.03 psi 103.03x20
20606
t=
= (15,000 x l.0) - (0.6 x l03.03)
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= .1379" 14938.18
Case 3. You must subtract static head pressure when determining the MAWP of a vessel. If given a vessel of multiple parts and the MAWP for each of the parts, the MAWP of the entire vessel is determined by subtracting the static head pressure at the bottom of each part to find the part which limits the MAWP of the vessel. Example: A vessel has an elevation of 40 feet including a 4 foot base. The engineer has calculated the following part MAWP’s to the bottom of each part based on each part's minimum thickness and corroded diameter. Determine the MAWP of the vessel. Design pressure at the bottom of: Top Shell Course 28' Elev. 406.5 psi Middle Shell Course 16.5' Elev. 410.3 psi Bottom Shell Course 4' Elev. 422.8 psi
12’ 406.5 psi 28’ 40’
Bottom of top shell course: 40.0' elev. -28.0' elev. 12.0' head 12' x 0.433 psi =5.196 psi of Static Head
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406.5 psi 28’ 23.5’
40’ 410.3 psi 16.5’
Bottom of the middle shell course:
40.0' elev. -16.5' elev. 23.5' head
23.5' x 0.433 psi = 10.175 psi of Static Head
406.5 psi 28’ 36’
410.3 psi 16.5’ 422.8 psi 4’
Bottom of bottom shell course: 40.0' elev. -4.0' elev. 36.0' head 36' x 0.433 psi = 15.588 psi of Static Head
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The final step in determining the MAWP of the vessel at its top is to subtract the static head of water from the calculated MAWP'S at each given point. The lowest calculated pressure will be the maximum gage pressure permitted at the top of the vessel. Bottom of top shell course 406.5 – 5.196 = 401.3 psi Bottom of mid shell course 410.3 - 10.175 = 400.125 psi Bottom of btm shell course 422.8 - 15.588 = 407.212 psi Therefore the bottom of the middle shell course MAWP determines the MAWP of the entire vessel. 400.125 psi
Static Head 10.175 psi 410.3 psi 16.5’
40’
The MAWP of the vessel is 400.125 psi
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Case 4. As part of calculating hydrostatic head on a vessel you will be required to determine the depth of two types of heads, 2 to 1 ellipsoidal and hemispherical. You will be given only the diameter of the vessel and using this you must calculate the head's depth which in turn is used to find the hydrostatic head at the bottom of the head. Example: A vessel has an inside diameter of 48 inches. Determine the depth of a hemispherical and a 2 to 1 ellipsoidal head with a 2 inch straight flange. The approach here is based on the fact that the heads diameters will match the vessel's diameter and therefore will be the same. In this case 48 inches. Hemispherical Head Our hemispherical head has an inside diameter of 48 inches which means it has a radius of 24 inches. The radius is the depth of the Hemispherical head
Shell I.D. 48” Radius 24" Depth 24"
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2 to 1 Ellipsoidal Head An ellipsoidal head's I. D. will be the same as the shell’s. The inside diameter of an ellipsoidal head is also its major axis. This fact is the basis of finding the depth of a 2 to 1 ellipsoidal head. Notice that we are strictly talking about 2 to 1 ellipsoidal heads. The 2 to 1 refers to the ratio of the Major Axis to the Minor Axis of a ellipse which is used to form the head.
Major Axis 48" Minor Axis 24"
Of course only half of the Minor Axis is used for the head.
2 to 1 Major Axis 48" 1/2 Minor AXIS 12”
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Now add the 2 inch flange to the dish. 2 to 1 2” 12”
14” depth
Therefore our 2 to 1 Ellipsoidal head has a depth of 14 inches. Example: Calculate the hydrostatic head of water for the following heads on a vessel with a Total Elevation of 70'. The vessel's I. D. is 64 inches. The top head is a 2 to 1 ellipsoidal and has a 2 inch flange. The bottom head is a hemispherical and is welded to the shell at the 8 foot elevation.
?
70’
?
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8’
Step 1. Calculate the depth of the 2 to 1 ellipsoidal head on top. The I.D. of the head equals the Major Axis therefore: 64" is the Major Axis and the Minor axis equals 1/2 the Major Axis. 64" divided by 2 equals 32" which equals the entire Minor Axis However an ellipsoidal head uses only half the Minor axis for its dished portion. 32" divided by 2 equals 16". To this you must add the length of the straight flange 2". So the depth of our ellipsoidal head is 18 inches.
Step 2. Calculate the depth of the hemispherical head. The I.D. of the hemi head equals the I.D. of the vessel therefore: 64" equals the diameter and the radius is one-half of the diameter. 64" divided by 2 equals 32" which equals the radius of this head. The Radius is equal to the Depth of the hemi head or 32 inches.
Step 3. Calculate the static head pressure on each head. Depth of head x 0.433 psi = Static head pressure. Ellipsoidal Converting to feet: 18" divided by 12 = 1.5' x 0.433 psi - 0.6495 psi Hemispherical Converting to feet. 32" divided by 12 = 2.666' x 0.433 psi = 1.1543 psi
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To find the total hydrostatic head on the hemispherical head at its bottom you must add all of the head that exists above it including the shell and the ellipsoidal head. We calculate as follows. 70' total elevation -8’ to the top of hemi head 62' hydrostatic head + 2.666’ depth of hemi head 64.666 total feet head 64.666' x 0.433psi 28.0 psi to the bottom of the hemi head.
0.6495 psi
70’
8’ 28.0 psi
ANS: Static head for the: Ellipsoidal head equals 0.649 psi Hemispherical head equals 28.0 psi
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Quiz Static Head / UG-99
A.
A 100 foot tall column is being hydrostatically tested. The vessel's MAWP is 100 PSI at 750°F. The vessel's material has an allowable stress of 13,500 PSI at MAWP, its material allowable stress at 70°F, the test temperature is 15,000 PSI. What is the required hydrostatic test pressure?
B.
The vessel above is under full hydrostatic test pressure in an operating unit during the summer. A plant wide evacuation alarm sounds and all test personnel leave. Four hours later, upon the all clear, the test crew finds that the gauge pressure on vessel has risen to an unacceptable pressure. How could this have been avoided?
C.
The test gauge for the test above is located at the 30' elevation of the vessel what will be its gauge pressure during the test and at what pressure shall the visual inspection take place as read from the gage at the 30' elevation?
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ANS/UG-99 Solution A: Hydrostatic Test Pressure Per UG-99(b) 15,000 PSI x 1.5 x 100 = 166.66 PSI 13,500 PSI
Solution B:
Per UG-99(h), a relief valve set at 1 1/3 the pressure could have been installed.
Solution C:
2/3 x test pressure plus static head at 30' elevation. Per UG-99(g)
Test pressure at the top 166.66 Hydrostatic head + 30.31 Test pressure at 30' 196.97 2/3 x 166.66 = 111.106 + 30.31 = 141.416 psi (insp. psi read at 30'elev.) Drawing: 166.66 PSI 1.1 x 1.5 x MAWP 100’
100'- 30' = 70'
30'
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196.97
70' x 0.433 psi / ft = 30.31 psi
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Corrosion Example Problems
A 60 foot tower consisting of four (4) shell courses was found to have varying corrosion rates in each course. Minimum wall thickness readings were taken after 4 years and 6 months of service. All original wall thicknesses included a 1/8" corrosion allowance. The top course's original thickness was .3125". The present thickness is .3000". The second course downward had an original thickness of .375". During the inspection it was found to have a minimum wall thickness of .349". The third course was measured at .440" its original thickness was .500". The bottom course had an original thickness of .625" and measured to be 595". Determine the metal loss for the top course, the corrosion rate for the second course, the corrosion allowance remaining in the third course, the retirement date for the bottom course.
.300 .349 60’-0” .440 .595
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Solution A: TOP COURSE. Metal loss equals the previous thickness minus the present thickness. Previous .3125" Present -.3000" .0125” Metal Loss SECOND COURSE. Corrosion rate equals metal loss per given unit of time. Previous .3750" Present -.3490" .0260" Metal Loss Total loss 0.260" Corrosion Rate = --------- .006" / Per YR. Total time 4.5 Years THIRD COURSE. Remaining Corrosion Allowance equals the actual thickness minus the required thickness. Original Thickness .500" Original Corrosion Allowance -.125" Required Wall Thickness .375" Actual Wall Thickness Required Wall Remaining Corrosion Allowance
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.440" -.375" .065"
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BOTTOM COURSE. Remaining service life equals the remaining corrosion allowance decided by the corrosion rate. 1.
Required Thickness Original Thickness Original Corrosion Allowance Required Thickness
2.
.625” -.125” .500”
Remaining Corrosion Allowance Actual Wall Thickness Required Thickness Remaining Corrosion Allowance
3.
.595” -.500” .095”
Corrosion Rate Original Thickness Present Thickness Metal Loss
.625” -.595” .030”
Metal Loss
.030”
Time
=0067” / Year 4.5 Years Corrosion Rate = .0067” / Year
4.
Remaining Service Life Remaining Corrosion Allowance
.095” = 14.2 Years
Corrosion Rate
.0067” / Year Remaining Service Life = 14.2 Years
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Cylinder Under Internal Pressure Problem #1 Calculate the required thickness of a 60 inch I.D. cylindrical shell. It is constructed of SA516 Gr. 70 rolled steel plate. The vessel's Category A&D Type 1 joints are fully radiographed. All Category B joints are Type 1 also and have been spot radiographed per UW-11(a)(5)(b). The vessel MAWP must be 350 PSI at 450°F. The shell will see 11 psi of static head at its bottom. SOLUTION: DRAWING:
TYPE 1 CAT. A FULL RT
t=? 60”
TYPE 1 SPOT
CAT. B RT
Givens: tr = ? D = 60.0" R = 30" P = 350 + 11 psi static head S = 17,500 from stress table E = 1.0 per UW-12 (a) UG-27(c)(1) CIRCUMFERENTIAL STRESS PR t= SE - 0.6 P 361 x 30 t=
= .6266” (17,500 x 1.0) – (0.6 x 361) ANSWER T = .6266”
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Cylinder Under Internal Pressure Problem #2 A vessel is constructed using two courses of rolled and welded SA-515 Gr. 60 plate. The maximum design temperature is 750°F. All joints used in shell courses are Type 1 those used to join heads are Type 2. The vessel’s name plate is stamped with the following: HT, W, RT 3. The vessel is 48 inches O.D. and has a thickness of .500 inch. What would be the vessel's MAWP based on the MAWP of the shell? DRAWING:
Cat A Type 1 .500” t 40" O.D.
Givens: t= .500" P= ? S= 13,000 from stress table E=.85 RT 3 for Type 1 OD = 48.0" RO = 24.0" APPENDIX 1 SEt P= RO - 0.4t SOLUTION: 13,000 x .85 x .500 P=
= 232.24 psi (24.0) - (0.4 x .500)
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Heads Under Internal Pressure Problem #1 A hemispherical head formed from solid plate is 48.0 inches in inside diameter and has a thickness of .500 inch. This head will be attached to a seamless shell which has not had radiography on the Category A Type 1 weld that attaches the head to the shell. The vessel is horizontal and operates at 500 PSI water pressure with an allowable stress on the head's material of 15,000 PSI. Does the head's thickness meet Code? Show calculations. SOLUTION: DRAWING: HEMISPHERICAL NO RT L 24”
t=?
48”
Givens: t = .500" D = 48.0" L = 24.0" P = 500 PSI + (0.433 psi x 4') = 1.732 = 501.732 S = 15,000 E = .70
UG-32(f) PL t= 2SE - 0.2 P 501.732 x 24.0 tR =
= .5761 (2 x 15,000 x 0.7) - (0.2 x 501.732)
Answer: NO.
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Heads Under Internal Pressure Problem #2 An Ellipsoidal head of seamless construction is welded to a seamless shell. The weld joint was spot radiographed per UW-11(a)(5)(b). The head's inside diameter was originally 36 inches. Uniform corrosion has occurred on the internal surfaces of the head leaving a wall thickness of .240". The original thickness of the head was .375". The MAWP of the vessel is 175 PSIG at 450°F and the static head at the bottom of the head is 5.3 psi. The stress allowable on the head's material is 13,500 PSI. Does this meet Code? SOLUTION. DRAWING: original head dimensions
.375” 36”
Givens. t = .240" D = 36.0" + [(.375 -.240) x 2] = 36.0 + .270 + 36.270" adjusted for corrosion! P = 175 PSI + 5.3 psi static head = 180.3 psi S = 13,500 E= 1.0 from UW-12(d) UG-32(d) PD t= 2SE - 0.2P 180.3 x 36.270 tR =
= .242” (2 x 13,500 x 1.0) - (0.2 x 180.3) .240" < .242" Answer: NO
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Heads Under Internal Pressure Problem #3 A seamless circular flat head is attached to a 36 inch I. D. shell similar to Figure UG-34(e). The shell's required t is .375 inches. The shell's actual t is .500 inch. The flat head is .750 inch in thickness. The vessel is to operate at 300 PSIG. The head's material has a stress allowance of 15,000 PSI. The fillet welds are 0.7 ts. Is the head's thickness in compliance with the Code? SOLUTION: .750” DRAWING: .500” 36”
Givens: t = .750 ts = .500 tR = .375 P = 300 S = 15,000 D = 36.0" E = 1.0 Because the flat head is seamless. C= .33 x m = 33 x .375 = .33 x .750 = .247 .500 UG-34(c)(2) t=d
CP/SE
.247 x 300 t = 36.0 15,000 x 1.0 74. 1 t = 36.0 X
= 2.53 inch 15,000 Answer: NO.
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Heads Under Internal Pressure Problem #4 While pulling exchanger bundles, a contractor backed against a torispherical head on a vessel. As a result of the bump, a circular flat spot is left on the formed head. This head is .375 inch thick and the flat spot is 6 inches in diameter. The vessel has a MAWP of 150 PSI and the head's material has an allowable stress of 15,000 PSI. Does this head require repair? Per Formed Heads UG-32(o) and UG-34(c)(2) Drawing: 6”
.375” 36” Givens: t = .375 (formed head) P = 150 S = 15,000 E = 1.0 Seamless. Flat Head C = 0.25 per UG-32 (o) d = 6.0” t = d CP/SE (0.25)(150) t = 6.0
=0. 300” (15,000) (1.0) 0.375" > 0.300"
Answer: No repairs are required. The flat spot meets t required for an equivalent flat head. See UG-32 (o), found near the end of UG-32.
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API 510 Module UG-84 WPS Problem #1 Please evaluate the following Charpy Impact test results for a SMAW procedure. The plate is SA-516 grade 70 normalized, 1 3/4" thick. The WPS is being qualified for a range from 3/16" to 8" in thickness.
The max weld pass t = 1/2". The plate's specified minimum yield normalized is 38 KSI. Do the test results qualify this procedure for impact testing?
Specimen W-1 W-2 W-3 W-4 W-5 W-6 H-1 H-2 H-3
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Notch Location WELD WELD WELD WELD WELD WELD HAZ HAZ HAZ
Notch Type v v v v v v v v v
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Test Temp. -25°F -25°F -25°F -25°F -25°F -25°F -25°F -25°F -25°F
Value ft/lb's 21 20 15 22 22 14 19 19 20
UG-84 WPS SOLUTION: Step (1)
Determine the minimum impact energy for the test coupon.
Per UG-84(h)(2)(c) the test specimens must meet or exceed the values for the thickness of the range qualified in the welding procedure. Per QW-451.1 Section IX. This procedure will be qualified from 3/16 inch to 8 inches. Therefore:
T qualified = 8.0 inches.
Going to Table UG-84.1 and entering on the bottom line at any value greater than 3 inches, then moving up to the ≤38 KSI curve, then across to the minimum impact values on the left, we find a minimum impact value of 18 ft./lbs. Step (2)
Check test results.
(a)
Average impact value required per Figure UG-84.1 is 18 ft./ lbs.
(b)
Calculate averages
W-1 21 W-4 22 W-2 20 W-5 22 W-3 +15 W-6 +14 56 ÷3 = 18.6 58 ÷3= 19.3
H-1 19 H-2 19 H-3 +20 58 ÷3= 19.3
(c) Note (b) of Figure UG-84.1 states that one specimen shall not be less than 2/3 the average energy required for three specimens. Only one (1) specimen is allowed to fall below the min. avg. of three per UG-84(c)(6). The minimum acceptable value of a single specimen is as follows: Acceptance values = 2/3 x 18 = 12 Answer: All values meet minimums and the procedure's impact tests pass.
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INTERINAL PRESSURE (CYLINDERS) 1). A cylindrical shell has been discovered to have uniform external corrosion. The shells original thickness was 7/8 inch. It is presently .745 inch in thickness. The original O.D. of the shell was 30 inches. The vessel operates at 650°F with a stress allowable on the material of 15,000 psi. All joints were fully radiographed. All Joints are type 1. What is the vessel's present MAWP? 2). A vessel is fabricated from SA-516 gr. 70 plate material to operate at 600°F with an allowable stress of 17,500 psi. The vessel has an inside diameter of 36 inches and operates at 375 psi. The type 2 long seam has had full RT. The circumferential joints have met UW-11(a)(5)(b) and UW-12(d) requirements. What is its required thickness? 3.) A shell course is being replaced with the new course being 60 inches in inside diameter and 7/8 inches thick. The vessel course material is SA-515 gr. 60 plate at a design temperature of 650°F with an allowable stress of 13,000 psi. The vessel joints are all type 2 and the vessel is stamped RT-3. What is the MAWP of this shell course? 4.) What is the minimum required thickness of a vessel shell operating at 650 psi and 500°F? The vessel shell is fabricated of SA-516 gr. 60 plate, allowable stress of 15,000 psi. The inside diameter of the vessel shell is 50 inches. The vessel has received FULL RT on Category A joints. All of its category A Joints are type 1. The category B joints are type 2 and have met the requirements of UW-12(d) and UW-11(a)(5)(b). 5). A vessel shell is made from SA-515 Gr. 70. It has a design operating pressure of 200 psi at 750°F, allowable stress is 14,800 psi. The inside diameter is 14 feet. All joint efficiencies are 1.0. The shell has corroded down to 1.28 inches. Its original t was 1.375". May this vessel shell remain in service in accordance with rules of Section VIII Division 1?
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INTERNAL PRESSURE (HEADS) 1.) A seamless torispherical head made of SA-515 gr. 70 material with an allowable stress of 14,000 at 750°F is to operate at 250 psi. The knuckle radius is 6% of the outside diameter of the head skirt and the inside crown radius is equal to the outside diameter of the skirt. The outside diameter of the skirt is 50 inches. The vessel it is attached to meets the requirements of UW-12(d) and UW-11(a)(5)(b). What is the minimum required thickness of the head? 2.) A seamless ellipsoidial head with a 2 to 1 ratio of the major to the minor axis is to operate at 750°F with an internal pressure of 250 psi. The material has an allowable stress of 14,800 and the skirt has an inside diameter of 50 inches. All category B butt welds do not meet UW-11(a)(5)(b). What is the minimum required thickness for the head? 3.) A seamless hemispherical head is fabricated from a material with a calculated stress of 14,800 psi at operating temperature. All category B butt joints in the vessel meet UW-11(a)(5)(b) and all category A joints are type 1 and have had spot radiography. The vessel's design requires a maximum operating pressure of 250 psi. The corroded thickness of this head is .295". It has a corroded I.D. of 72.230". May this head continue in service?
4.) During the inspection of a horizontal 36 inch ID vessel in gas service a seamless circular flat head attached similar to Fig UG-34(e) @vas found to have corroded to a thickness of 1.948 inch minimum. The shell's required thickness was calculated based on 100% joint efficiency and an allowable stress of 17,500 psi. The shell's actual thickness is .505 inch and the vessel operates at 250 psi. The flat head's allowable stress is 15,500 psi. The fillet weld throat sizes are still in excess of .7 ts. May this flat head remain in service?
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Solutions for Internal Pressure Cylinders
1. From: Appendix 1-1
SEt P= R0 - 0.4t
Givens: t original = .875 " t present = .745 " P=? S = 15,000 psi E = 1.0
R0 = 14.87" R0 = 30/2 = 15-(.875-.745) = 15-0.13 = 14.87" this adjusts the o.d. wall loss
P= 15,000 x l.0 x .745 = 766.88 psi 14.87 - (0.4 x .745)
The trick here is knowing to adjust the outside radius for corrosion, remember it will decrease when there is external corrosion. The opposite is true for internal corrosion.
2. From: UG-27 (c)(1) SE - 0.6P Givens: t req. = ? P= 375 psi S= 17,500 psi E= .90
t=
PR
R = 36 / 2 = 18” 375 x 18 t=
=.4347" (17,500 x .90) - (0.6 x 375)
In order to take .90 for the E on the category A joint, it must have full RT and the circumferential joint must meet the spot RT required by UW-12(a),
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3.
From: UG-27 (c) (1)
P=
SEt R + 0.6t
Givens: t = .875 P= ? S= 13,000 psi E= .80 R= 60 / 2 = 30” 13,000 x .80 x .875 P=
= 298.11psi 30 + (0.6 x .875)
4.
From: UG-27 (c) (1)
t=
PR SE - 0.6P
t=? P = 650 psi S = 15,000 psi E = 1.0 R = 50 / 2 = 25” 650 x 25 t=
= 1.112” (15,000 x l.0) - (0.6 x 650)
Here you must remember that UW-12(a) will not allow the use of a joint E from column A unless the requirements of UW-11(a)(5) have been applied. If the spot RT had not been performed the E would be taken from column B and have a value of .85.
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5.
From: UG (c) (1) t =
PR or P = SEt SE - 0.6P R - 0.6t
Givens: t = 1.28” P = 200 PSI S = 14,800 psi E = 1.0 R = 14’ / 2 = 7' x 12 = 84" Inside radius corroded = 84 + (1.375 -1.28) = 84.095
t=
200 x 84.095 = 1.145" or P = 14,800 x l.0 x l.28 = 223.23psi (14,800 x 1.0) - (0.6 x 200) 84.095 + (0.6 x l.28)
The answer to the question is YES it may remain in service. Notice that since both pressure and thickness are known that either calculation can be made. It does not matter which is used.
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Solutions for Internal Pressure Heads 1. From: UG-32 (e)
t=
0.855PL SE - 0.1P
(Torispherical Formula)
Givens: t=? P = 250 psi S = 14,800 psi E = 1.0 L= 50" crown radius 0.855 x 250 x 50 t=
= .7487” (14,800 x l.0) - (0.1 x 250)
2.
From: UG-32 (d)
t=
PD 2SE - 0.2P
Givens: t=? P= 250 psi S= 14,800 psi E= .85 D = 50" inside diameter 250 x 50 t=
= .4978” (2 x14,800 x .85) - (0.2 x 250)
3.
From: UG-32 (f)
t=
PL 2SE - 0.2P
Givens: t=? P = 250 psi S = 14,800 psi E = .85 L = 36.115" inside spherical radius 250 x 36.115 t= = .3595” (2 x14,800 x .85) - (0.2 x 250) ANSWER: NO
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4. From: UG-34 (c) (2)
CP t=d SE
GIVENS: t=? t = .505" actual thickness of the shell P= 250 psi S =for head material 15.500 psi S =for shell material 17,500 psi d = for head 36" D = for shell 36" inside E = 1.0 for a seamless head C=? Step 1.
Calculate the Shell's required thickness
From: UG-27 (c) (1) we use the t = formula to find that the shell's required which is .259" remember to use the shell's material stress in this calculation. Step2.
Using the actual thickness of shell and its calculated reg. thickness find "m" tr
From: The definitions of variables in and fig. UG-34 (e)
m=
= ts
Step 3.
.259 = .51 .505
Calculate the value of C
From: Fig. UG-34 (e) C = .33 x m = .33 x .51 = .1683 Since the minimum that C is allowed to be in this geometry is .20 use C=.20 to solve. Step 4.
Calculate the required t of the flat head .20 x 250 t = 36 15,500 x 1.0 = 36 .0032258 = 36 x .0567961 = 2.044"
Answer No: 1.984" < 2.044"
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APPENDIX
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API answers found in Section VIII Div. 1 Many of the principles found in the API 510 Code were derived from the same engineering rules used in Section VIII of the ASME Code. Most are slightly modified to accommodate the in-service environment. The examples given below are meant to eliminate a large portion of the memorization for some of the more lengthy answers. Some of the references given are located in paragraphs of Section VIII which are not listed on the Body of Knowledge for the exam. However, since at this writing the ASME Code books are allowed to be used throughout the entire exam, these can be very valuable tips. Take note that there may be some differences in the values such at temperature, etc.. Remember these differences only the rest is in Section VIII. Also listed are a few tips for Sections IX and V. Tip 1: For listing the limits that corrosion can be averaged over go to paragraph UG-36. Here the maximum sizes of openings in vessels are listed. Notice these are the exact same dimensions as given in API 510 for corrosion averaging over an area. Tip 2: The footnotes of UG-126 list descriptions of RV’s, PRV’s etc.. A great deal more information about over pressure protection is also listed, such as mediums permitted for testing the various devices. Tip 3: In UCS-56 (f) a description of the Half-Bead/Temper-Bead technique of repair is given. Here we have only two basic differences, the temperatures and holding times at temperature. Tip 4: In UHA-102 a description of Intergranular Corrosion is given Tip 5: In UHA-103 Stress Corrosion is explained. Tip 6: URA-109 addresses 885°F embrittlement. Tip 7: Appendix 10 lists the required information for a Quality Control program for vessel construction. Much of this verbiage can be converted for use in addressing Quality Control programs for PRVS. Tip 8: Section IX contains definitions of different welding terms and welding processes such as GTAW, SMAW etc.. These are located in Article IV, QW-490. Tip 9: Section V has extensive information listed for specifics of different processes listed in the ASTM documents near the back of the book. One example is the construction of penetrameters. Information about how they are to be made can be located in these paragraphs. Tip 10: This is most important tip of all. Don't forget that Appendix L of Section VIII has a ton of sample calculations. If your are at loss as to how to perform a calculation, there is a chance a similar one can be found here.
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Placing Tabs in the ASME Code Books First off, let it be said that tabs are probably the most effective method for finding material both for the test and in actual field application of the Code. Suggestions for Tabbing 1.
Use full page dividers as tabs, these allow the turning of a large numbers of pages without difficulty. The stick on kind will tear out the page holes.
2.
Use the API Body of Knowledge and this text book to tab the important pages of all of the ASME Code books. Below is a listing of the minimum number of suggested tabs for each of the ASME Code books. Also write on both sides of the tabs in order to go back and forth easily.
Section VIII ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦
PV definition U-1 Mill Under Tolerance UG-16 Corrosion UG-25 Thickness of Shells UG-27 Formed Heads UG-32 Opening UG-36 Material UG-77 Markings UG-116 Service Restrictions UW-2 Joint Categories UW-3 Radiographic Exam UW-11 Joint Efficiencies UW-12 Attachment Welds UW-16 Procedures for PWHT UW-40 Heat Treatment Carbon and Low Alloys UCS-56 Impact Tests UCS-66, 67, 68 Appendix 1 (1-1) Formulas for OD calculations on shells Appendix L Example Calculations
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Section IX Article I 1. 2. 3. 4.
QW-100.1 Purpose or WPS and PQR QW-153 Acceptance Criteria for tension tests QW-163 Acceptance Criteria for bend tests QW-191 Radiographic Examination
Article II 5. 6. 7.
QW-200 definition of a WPS QW-202.2 definition of a PQR QW-251.1 definition of Variables
Article III 8. 9. 10. 11.
QW-300 General QW-301 Tests QW-320 Re-tests and Renewal QW-350 Welding Variables for Welders
Article IV 12. Weld data 13. P-Numbers 14. Alternate Base Metal 15. F- Numbers 16. Definitions Section V Article 2 Radiography 1. 2. 3. 4. 5. 6.
T-220 Procedure Requirements T-233 IQI s T-274 Geometric Unsharpness T-277 Use of IQI s Placement T-280 Evaluation T-284 Excessive Backscatter
Article 5 Ultrasonics 1. T-522 Written Procedures 2. T-534 Checking and Calibration 3. T-542.7 Examination of Welds 4. T-590 Reports and Records Article 6 Liquid Penetrant 1. 2. 3. 4. API 510
T-621 Procedure T-650 Procedure / Technique T-670 Examination T-676 Interpretation Page 227 of 310
Article 7 Magnetic Particle 1. 2. 3. 4.
T-720 General Requirements T-726 Examination Medium T-746 Yoke Technique T-750 Evaluation
Article 9 Visual Examination 1.
API 510
Article 9 is two pages in length, just tab the first page.
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QW-482 SUGGESTED FORMAT FOR WELDING PROCEDURE SPECIFICATIONS (WPS)
(See QW-200.1. Section IX. ASME Boiler and Pressure Vessel Code) See section IX for samples QW-482 SUGGESTED FORMAT FOR WELDING PROCEDURE SPECIFICATIONS (WPS)
(See QW-200.1. Section IX. ASME Boiler and Pressure Vessel Code)
See section IX for samples
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Solutions for ASME Module Exercises UW- 3 1. ans. D (it depends on the location in the vessel) 2. ans. B (it is a category C weld)
D B
B
A
B
A
C
API 510
B
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UW-11 1. Category A joints in nozzles and communicating chambers and category B joints in nozzles and chambers which exceed either 10” NPS or 1 - 1/8 wall thickness. 2. The category A joint must be fully radiographed and the spot radiography of UW-11 (a)(5)(b) must be applied per UW- 12 (a). 3. Full radiography for all butt joints which exceed the specified thickness, excluding the category B’s that do not exceed the 10" NPS or 1- 1/8 inch thickness. 4. It may not be assumed that all joints have been radiographed. The thickness of some joints may not exceed the limit for the material used. Remember it is the least nominal thickness at the welded joint which determines the requirement. 5. Both joints must be radiographed by the requirement that all A and D butt welds shall be shot. UW-12 # 1 page 91 1. 2. 3. 4. 5. 6. 7.
E= E= E= E= E= E= E=
1.0 per UW-12 (d) .80 based on the joint E from column B of the welded joint used for the head .85 based on the joint E from column B of the welded joint used for the head 1.0 per UW-12 (d) .85 no spot RT. per UW-12 (d) .85 no spot RT. per UW-12 (d) .65 based on the joint E from column B of the welded joint used for the head
UW-12 # 2 page 92 1. E = 1.0 based on full RT of all category A and D joints and the spot RT applied to the category B joint attaching the Ellipsoidal head (see UW-12 (a)). 2.
E = .80 based on the joint E from column B of the welded joint used for the Ellipsoidal head
3.
E = 1.0 Full RT on the category A joint in the hemispherical head.
4.
E = 1.0 per UW-12 (d)
5.
E = 1.0 per UW-12 (d)
6.
E = 1.0 per UW-12 (d)
7.
E = .80 based on the joint E from column B of the welded joint used for the head and spot RT.
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UG 27 1.
From: Appendix 1-1
t=
PR0 SE + 0.4P
Givens: t=? P = 500 psi S = 15,000 psi E= 1.0 per UW-12 (d) R0 = 12.75 / 2 = 6.375” 500 x 6.375 t=
= .2097” (15,000 x l.0) - (0.4 x 500)
ANSWER: the required t = .2097"
2.
From: UG-27 (c)(1)
t=
SEt R + 0.6t
Givens: t= P=
.850” ?
E= R=
1.0 52”
S=
15,000 psi
15,000 x 1.0 x .850 P=
= 242.81 psi 52 + (0.6 x .850)
ANSWER: MA WP is 242.81 psi
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UG 32 1.
From: UG-32 (d)
t=
PD 2SE - 0.2P
Givens: t= ? P= 350 psi S= 15,000 psi E= 1.0 full RT per UW-11 (a) (1) in butt joints in shells and heads D= 48" inside diameter 350 x 48 t= = .5613” (2 x 15,000 x l.0) - (0.2 x 350) ANSWER: required t = .5613"
2.
From: UG-32 (e)
t=
0.885PL SE - 0.1P
Givens: t= .353 P= 100 psi S= 13,800 psi E= 1.0 L= 56" crown radius 0.885 x 100 x 56 t=
= .3593” (13,800 x l.0) - (0.1 x 100)
ANSWER:
API 510
No the head may not remain in service.
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UG-32 3.
From: UG-32 (f)
t=
PL 2SE - 0.2P
Givens: t= ? P= 200 psi S= 17,500 psi E= Spot RT. 85 L= 32.0" inside spherical radius (D/2) 200 x 32.0 t=
= .2154” (2 x 17,500 x .85) - (0.2 x 200) ANSWER: the required thickness =.2154"
4.
From: UG-32 (d)
t=
PD 2SE - 0.2P
Givens: t= ? P= 200 psi S= 17,500 psi E= .85 No spot RT per UW-12(d) D= 64.0" 200 x 64 t=
= .4308” (2 x 17,500 x .85) - (0.2 x 200)
ANSWER: thickness required =.4308"
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UG-34 CP 1. 4. From: UG-34 (c)(2)
t=d SE
Givens: t=? t = .500" actual thickness of the shell P = 75 psi S = for head material 13,800 psi S = for shell material 15,000 psi d = for head 42" D = for shell 42" inside E = 1.0 for shell calculation (Shell E is always 1.0 for a flat head calculation) E = 1.0 per UW-12 (d), this is a forged head but is treated like a formed head. Read the paragraph for the Fig UG-34 (b-2) C= 0.33 x m = ? Step 1. Calculate the Shell's required thickness From: UG-27 (c) (1) we use the t = formula to find that the shell's required which is .1053" remember to use the shell's material stress in this calculation. Step 2. Using the actual thickness of shell and its calculated req. thickness find "m" tr
.1053
From; The definitions of variables and fig. UG-34 (e) in UG-34 m =
= ts
=.2106 .500
Step 3. Calculate the value of C From: Fig. UG-34 (c) C =.33 x m =.33 x .2106 =.0694 Since the minimum that C is allowed to be in this geometry is .20 use C = .20 to solve. Step 4. Calculate the required t of the flat head .20 x 75 t = 42 13,800 x l.0 = 42 .0010869 = 42 x .0329681
= 1.3846"
Answer: thickness required = 1.3846
2.
API 510
See answer #1. It is the exact same problem. The important aspect of these problems is how the C is arrived at. If the C is the same the answer will be the same if in fact it is a replacement head made of the same materials!!!
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UG-28 D0
values ≥ 10 t Testing to see if this paragraph applies.
(1)
Cylinders having
D0=54” 54
D0 = t
= 48.08
t =1.123”
1.123
Step 1. Our value of D0 is 54 inches and L is 98 inches. We will use these to determine the ratio of: L 98 = = 1.81 D0 54 Step 2. Enter the Factor A chart at the value of 1.8 determined above. Step 3. Then move across horizontally to the curve D0/t = 48. Then down from this point to find the value of Factor A which is approximately .0022 . Step 4. Using our value of Factor A calculated in Step 3, enter the Factor B (CS-2) chart on the bottom. Then vertically to the material temperature line given in the stated problem (in our case 300°F). Step 5. Then across to find the value of Factor B. We find that Factor B is approximately 15000. Note due to the variance in the reading of the charts answers and values may vary, but should be within a 5 % range of the solution. Step. 6 Using this value of Factor B, calculate the value of the maximum allowable external pressure Pa using the following formula: 4B Pa = 3(D0/t) 4 x 15,000 Pa =
60,000 =
3(48)
= 416.66 psi 144
416.66 psi > 350 psi ANSWER: YES, your answer may be slightly different +or5% due to the variation in reading the factor A and B charts. This is acceptable.
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2. L= 105” P= 900 psi emp. = 800°F t= .730” L= 105” D0 = 5.98" S= 10,200 psi
D0 =
5.98"
t = .730” Check ratio of D0/t
= 5.98/0.730 = 8.19 8.19<10 D0/t<10 Therefore, use UG - 28(c)(2)
Step 1. Using the same procedure as given in UG-28(c)(1) obtain the value of B. Determine the ratio for L/D0 and D0/t L/D0 = 105 / 5.98 = 17.55
D0/t = 598 / 0.730 = 8.19
[From UG-28(c)(1)]
Step 1. Enter Fig. G at the value of L / D0 ≈ 17.55 Step 2. Move horizontally to the line D0 / t ≈ 8.19 from this point move vertically down to find Factor A ≈ 0.019. Step 3. Using Factor A enter Factor B chart CS-2 at the value of Factor A. Move up to the material / temperature curve for 800°F and across to the Factor B values. The factor B equals approximately 11,800. [From UG-28(c)(2)]
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Step 2. Using the value of B obtained above calculate the value Pal using the following formula: 2.167 P al =
- 0.0833 B D0/t 2.167 Pal = 8.19 - 0.0833 11,800 = 2139.2 psi
Step 3. Calculate the value of Pa2 where S is the lesser of 2 times the maximum allowable stress in tension at the design metal temperature from the stress tables or 0.9 times the yield strength of the material at design temperature. Values of the yield strength are obtained from the applicable material chart as follows: (a).
For a given temperature curve determine the B value that corresponds to the right hand side termination point of the curve.
(b).
The yield strength is twice the B value obtained in (a) above. Use the Lesser of: 2 times the max. stress allowed in tension or 0.9 times yield strength at temperature (Case 1.): 2 x 10,200 psi = 20,400 psi or (Case 2.): 2 x 12,500 psi = 25,000 psi x 0.9 = 22,500 psi So use 20,400 psi in the calculation of Pa2
Pa2= 2S D0/t
1- 1 D0/t
Pa2= 2 x 20,400 8.19
1- 1 8.19
Pa2= 4981.6[1-0.1221] = 4373.34 psi Step 4.
Pa will equal the smaller of Pa1 or Pa2: Pa = 2139.2 psi 2139.2 psi > 900 psi
API 510
ANSWER.. Yes meets Code.
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UG-99 / 100 16,700 1. A.
1.5 x 225 x
= 383.41psi 14,700
B.
2 /3 x 383.41 = 255.61psi
C.
Minimum gage range 1-1/2 x 383.41 = 575 psi (use 600 psi) Maximum gage range 4 x 383.41 = 1533.64 psi (use 1500 psi) Of course the gage measure would be rounded up or down to closest standard range!
2. A. B.
API 510
Raise the Pressure to 1/2 the test pressure ½ x 310 psi = 155 psi Raise the pressure in steps of 1/10 of the ultimate test pressure 310 psi = 31 psi 1. 155+31 = 186 psi 2. 186+31 = 217 psi 3. 217+31 = 248 psi 4. 248+31 = 279 psi 5. 279+31 = 310 psi 6. 2/3 x 310 = 248 psi inspection pressure. Notice that this is the same pressure as found in step three on the way up to test pressure.
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UW-16 Throat = Leg Size x .707 Leg Size = Throat / .707 1.
1.125 x .707 = .7953" = throat size
2.
Leg Size = .600 / .707 = .8486 therefore the next 1/16 would be a 7/8 inch leg. 13 / 16< .8486 < 7/8 (14/16) or .8125<.8486<.875
UG-40 / 41 / 42 / 45 1.
Ratio = 15,000 / 14,800 = 1.0135 therefore use 1.0 credit cannot be taken for the higher strength of the pad's material, only the reverse is true, that is you must reduce the area that the pad provides if it is of a lower strength than the shell.
2.
The centers can be no closer than the sum of their diameters and still be considered isolated openings, in this case 6 + 4 = 10 inches. The answer is: their centers can be no closer than 10 inches with out the areas of reinforcement overlapping.
3.
The area of reinforcement must that of a hole which would contain all of the nozzles with in it. It is treated as if it were on large hole for reinforcement calculation.
UG-37 Reinforcement 1.
2. 3.
API 510
Corrosion allowance must be deducted from all surfaces in contact with the corrosive substance. A= d tr F +2tn tr F(1-frl) Area required Answer: 4 points for the reinforcement and 4 points for the hydrostatic calculations. Which one takes the most study time? Which one of these are you most likely to do in actual practice? Which one of these is the most likely to be on the exam?
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UG-84 1. 2. 3. 4. 5. 6. 7.
SA-370 (second paragraph of UG-84) Charpy V-notch(only one mentioned in UG-84, first paragraph UG-84 Charpy impact tests shall be performed) 2.165" long x 0.394" thick see Fig. UG-84 3 make a set 3 sets, two from the weld metal and one set of heat affected zone specimens. The P No. and the Group No. must be the same as will be welded in production. Weld Metal and Heat Affected Zone.
UG-20 / UCS-66 / 68 1. 2. 3. 4. 5.
Step 1. UG-20(f), Step 2. UCS-66(a) , Step 3. UCS-66(b) , Step 4. UCS-68(c) When the Welded thickness exceeds 4 inches and the MDMT is below 120°F. When the governing thickness exceeds 6 inches and the MDMT is below 120°F 88°F SA-515 gr. 70 is a curve A material 48°F a coincident Ratio of 0.6 will reduce any materials MDMT by 40°F from that in the curves / tables. Solutions for Internal Pressure Cylinders
1.
From: Appendix 1-1 P = Set / R0 - 0.4t Givens: toriginal = .875 " tpresent = .745 P= ? S= 15,000 psi E= 1.0 R0= 14.87” R0= 30 / 2 =15-(.875-.745) = 15-0.13 = 14.87” this adjusts the o.d. wall loss 15,000 x l.0 x .745 P=
= 766.88 psi 14.87 - (0.4 x .745)
The trick here is knowing to adjust the outside radius for corrosion, remember it will decrease when there is external corrosion. The opposite is true for internal corrosion.
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2.
From: UG-27 (c)(1) t =
PR SE - 0.6P
Givens: treq = ? P= 375 psi S= 17,500 psi E= .90 R= 36 / 2 = 18”
375 x 18 t=
= .4347” (17,500 x .90) - (0.6x 375)
In order to take .90 for the E on the category A joint, it must have full RT and the circumferential joint must meet the spot RT required by UW-12(a). 3.
From: UG-27(c)(1)
P=
SEt R + 0.6t
Givens: t= .875” P= ? S= 13,000 psi E= .80 R= 60 / 2 = 30” 13,000 x .80 x .875 P = 30 + (0.6 x .875) = 298.11 psi
4.
From: UG-27(c)(1)
t=
PR SE - 0.6P
Givens: t= ? P= 650 psi S= 15,000 psi E= 1.0 R= 50 / 2 = 25 650 x 25 t = (15,000 x l.0) - (0.6 x 650) = 1.112"
Here you must remember that UW-12(a) will not allow the use of a joint E from column A unless the requirements of UW-11(a)(5) have been applied. If the spot RT had not been performed the E would be taken from column B and have a value of .85.
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5.
From: UG-27(c)(1)
t=
PR SE - 0.6p
or P =
SEt R + 0.6t
Givens: t= 1.28” P= 200 psi S= 14,800 psi E= 1.0 R= 14' / 2 = 7' x 12 = 84" Inside radius corroded = 84+(1.375-1.28) 84.095 200 x 84.095
14,800 x l.0 x l.28 =1.145" or P =
(14,800 x l.0) - (0.6 x 200)
= 223.23psi 84.095 + (0.6 x l.28)
The answer to the question is YES it may remain in service. Notice that since both pressure and thickness are known that either calculation can be made. It does not matter which is used. Solutions for Internal Pressure Heads
1.
From: UG-32(e) t = 0.885PL (Torispherical Formula) SE - 0.1P Givens: t= P= S= E= L=
? 250 psi 14,800 psi 1.0 50" crown radius 0.885 x 250 x 50 t=
= .7487" (14,800 x l.0) - (0.1 x 250)
2.
From: UG-32(d) t =
PD 2SE - 0.2P
Givens: t= ? P= 250 psi S= 14,800 psi E= .85 D = 50" inside diameter 250 x 50 t=
= .4978” (2 x 14,800 x .85) - (0.2 x 250)
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3.
From: UG-32(f)
t=
PL 2SE - 0.2P
Givens: t= ? P= 250 psi S= 14,800 psi E= .85 L= 36.115" inside spherical radius 250 x 36.115 t=
= .3595” (2 x 14,800 x .85) - (0.2 x 250) ANSWER:
4.
From: UG-34(c)(2)
NO
CP t = d SE
Givens: t= ? t= .505" actual thickness of the shell P= 250 psi S= for head material 15,500 psi S= for shell material 17,500 psi d= for head 36" D = for shell 36" inside E= 1.0 for a seamless head C= ? Step 1. Calculate the Shell's required thickness From:
UG 27(c)(1) we use the t = formula to find that the shell's required which is .259" remember to use the shell's material stress in this calculation.
Step 2. Using the actual thickness of shell and its calculated required thickness find "m" From: The definitions of variables in and fig. UG-34(e) m = tr = .259 = .51 ts .505 Step 3. Calculate the value of C From: Fig. UG-34(e) C = .33 x m = .33 x .51 = .1683 Since the minimum that C is allowed to be in this geometry is .20 use C = .20 to solve. Step 4. Calculate the required t of the flat head t = 36 .20 x 250 = 36 .0032258 = 36 x .0567961 = 2.044” 15,500 x l.0 Answer No: 1.984" < 2.044” API 510
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API & ASME REVIEW QUESTIONS HOW TO USE THESE QUESTIONS
The following questions and answers on the API are for memorization. The API Code questions will be closed book. Practice remembering the key words as opposed to learning the answers totally The ASME Code questions are not for memorization. Use these questions to learn where to find the answers in the ASME Code books. These will be open book questions and there is no reason to commit them to memory. Study the API questions and answers first and see how many answers to the API questions can be found in the ASME Code books. You may be surprised at how many you can find, some will be slightly different. All API questions found in the ASME Codes need not be remembered; all that is required is to know is where they are located in the ASME Code.
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API 510 REVIEW QUESTIONS Section 1 - General 1. What does the acronym API stand for? (Cover of API 510) American Petroleum Institute 2.
What does the acronym ASME stand for? (Forward API 510) American Society of Mechanical Engineers
3.
The primary code for the inspection of pressure vessels after they enter service is? (1.1.1) API 510
4.
What equipment can be inspected by the alternative rules in Section 6 of the API 510 code? (1.1.2.1) All pressure vessels in NATURAL RESOURCE SERVICE such as drilling, production, gathering, transportation, lease processing, and treatment of liquid petroleum, natural gas, and associated salt water (brine).
5.
Relative to pressure vessels, when does API 510 apply? (1. 1. 1) Only applicable to vessels after they have been placed in service.
6.
What does the API inspection code cover? (1. 1. 1) Maintenance inspection, repair, alteration, and rerating procedures for pressure vessels used by petrochemical industries.
7.
Describe what is meant by an API "Section 6 vessel." (1.1.2.1) A vessel which is exempted from Section 4 requirements.
8.
What type of pressure vessels are exempt from periodic inspection requirements? (1.1.2.2) a. Pressure vessels on movable structures covered by other jurisdictional requirements. b. All classes listed for exemption from the inspection scope of the ASME Code Section VIII, Division 1. c. Pressure vessels that do not exceed specified volumes & pressures.
9.
What is an alteration? (1.2.1) A physical change in any component or a rerating which has design implications which affect pressure-containing capability beyond the scope of existing data reports.
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10.
What three situations should not be considered alterations? (1.2.1) a. b. c.
11.
Comparable or duplicate replacement Addition of reinforced nozzle less than or equal to existing reinforced nozzles Addition of nozzles not requiring reinforcement
ASME Boiler & Pressure Vessel Code is often abbreviated as what? (1.2.2) ASME Code
12.
In what situation would the term "applicable requirements of ASME Code" be used? (1.2.2) When an item is covered by requirements of a new construction code, or if there is a conflict between the two codes, the requirements of API 510 shall take precedent for vessels that have been placed in service. EXAMPLE of INTENT -- The phrase "applicable requirements of the ASME Code" has been used instead of the phrase "in accordance with the ASME Code”.
13.
What is an Authorized Inspector or Inspector? (1.2.3) An employee of an Authorized Inspection Agency who is qualified and certified to perform inspection under the API 510 inspection code.
14.
List 4 examples of an Authorized Inspection Agency. (1.2.4) a. b. c.
d.
15.
Inspection; organization of the jurisdiction in which the pressure vessel is used. Inspection organization of an insurance company which is licensed or registered to write and actually does write pressure vessel insurance. An owner or user of pressure vessels who maintains an inspection organization for activities relating only to his equipment and not for vessels intended for sale or resale. An independent organization or individual licensed or recognized by the jurisdiction in which the pressure vessel is used and employed by or acting under the direction of the owner or user.
Define "construction code". (1.2.5) The code or standard to which a vessel was originally built
16.
What does the term "inspection code" refer to in API 510? (1.2.6) API 510, Pressure Vessel Inspection Code
17. Define Jurisdiction. (1.2.7) A legally constituted government administration, which may adopt rules relating to pressure vessels.
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18. Define Maximum Allowable Working Pressure (MAWP) as it relates to API 510. (1.2.8)(Sect VIII UG-98) The maximum gage pressure permitted at the top of a pressure vessel in its operating position for a designated temperature that is based on calculations using the minimum (or average pitted) thickness for all critical vessel elements, not including corrosion allowance or loading other than pressure. 19.
When determining Minimum Allowable Shell Thickness, what must be considered when making calculations? (1.2.9) Temperature, pressure, and all loadings.
20.
What type of inspection…….the suitability of pressure vessels for continued operation? On-stream Inspection
21.
What is the key element of an On-stream inspection? (1.2.10)
Because the vessel may be in operation while an on-stream inspection is being carried out, the vessel is not entered for internal inspection. 22.
What is a Pressure Vessel? (1. 2. 11) (Sect VIII U-1 (a))
A container designed to withstand internal or external pressure which can be imposed by an external source, by the application of heat from a direct or indirect source, or by any combination thereof. 23.
What is a Repair? (1.2.12) The work necessary to restore a vessel to a condition suitable for safe operations at the design conditions. "IF" design temperature or pressure changes due to restoration, then rerating requirements shall also be satisfied.
24.
List the four examples of a Repair Organization. (1.2.13) a. The holder of a valid ASME Certificate of Authorization for the use of an appropriate ASME Code symbol stamp. b. An owner or user of pressure vessels who repairs his own equipment in accordance with the API 510 code. c. A contractor whose qualifications are acceptable to the owner or user of pressure vessels and makes repairs in accordance with API 510 code. d. One who is authorized by the legal jurisdiction.
25.
What is rerating? (1.2.14) A change in either or both temperature or MAWP of the vessel. Note: rerating is not an alteration unless a physical change to the vessel is made which requires additional mechanical tests.
26.
What is a permissible way to provide for corrosion? (1.2.14) Derating below original design conditions.
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Section 2 - Owner-User Inspection Organization 27.
28.
What are the education and experience requirements for becoming an inspector? (2.2) a.
Degree in engineering & 1 year experience in the design, construction, repair, operation, or inspection of boilers or pressure vessels.
b.
2-year certificate in engineering or technology from a technical college & 2 years of experience.
c.
Equivalent of a high school education plus 3 years of experience. (and).
d.
Certification by an agency as provided in API 510.
What documents will be covered in the certification test for inspectors? (Appendix B) The latest edition of API 510 and the applicable portions of Sections V, VIII, and IX of the latest edition of the ASME Code
29.
When will recertification be required? (Appendix B)
Recertfication by written test will be required for API authorized pressure vessel inspectors who have not been inspectors within the previous three years.
Section 3 - Inspection Practices 30.
Why are safety precautions important in pressure-vessel inspections? (3.1) Because of the limited access to and the confined spaces of pressure vessels.
31.
What must an inspector do before entering a vessel that has been in service? (3.1) a. Obtain an entry PERMIT from operations or safety. b. Assure that the vessel is properly secured - BLINDED. c. Assure that someone outside the vessel is designated to assist in the case of emergency. (STANDBY)
32.
Explain the safety precautions and procedures that should be taken when performing an internal inspection. (3.1) a. b. c. d. e. f. g.
API 510
Isolate vessel from all sources of liquids, gas or vapors. Drain, purge, clean and ventilate. Gas test. Wear protective equipment as required. Warn all persons working around the vessel that inspection personnel are inside. Warn all inside the vessel of work that is done outside the vessel. Cheek all tools and safety equipment needed before inspection.
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33.
Name several types or causes of Deterioration and Failure in pressure vessels. (3.2) a. b. c. d.
34.
Corrosion - contaminants in fluids react with metal Stress fatigue - high stress, frequent reversals, cyclic temperature & pressure changes Thermal fatigue - locations where metals with different thermal coefficients of expansion are welded together. Deterioration or creep - equipment is subjected to temperatures above those for which it is designed.
The actual or estimated levels of what three quantities must be used in any evaluation of Creep? (3.2) a. Time b. Temperature c. Stress
35.
At ambient temperatures carbon, low alloy and other ferritic steels may be susceptible to what? (3.2) Brittle Failure
36.
Define Temper Embrittlement. (3.2) A loss of ductility and notch toughness due to PWMT or high temperature service above 700 degrees F. (370 degrees C)
37.
What kinds of steels are prone to Temper Embrittlement? (3.2) Low alloy steels, especially 2 1/4-Cr- 1 Mo
38.
What three methods may be used to determine the probable rate of corrosion? (3-3) a. b. c.
39.
Calculate rate from data collected from same or similar service. Estimate rate from owner-user experience or from published data on comparable service. On-stream determination after 1000 hours of service using corrosion monitoring device or NDE thickness measurements (UT)
How (What should you use) should MAWP for the continued use of a pressure vessel be established? (3.4) By using the Code to which the vessel was fabricated or by using the appropriate formulas and requirements of a later edition of the ASME Code to establish the design temperature and pressure.
40.
What is the most important and the most universally accepted method of inspection? (3.5) Careful visual examination
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41.
What determines the parts of a vessel that should be inspected? (3.5) The type of vessel and its operating conditions.
42.
For proper visual examination what surface preparation is required? (3.5) The surface must be clean, there is no hard and fast rule for cleaning equipment.
43.
How would you check for distortion if observed on a vessel? (3.5) The overall dimensions of the vessel shall be checked to determine the extent and seriousness of distortion.
44.
List other methods that may be used to supplement visual inspection. (3.5) a. Magnetic-particle examination b. Fluorescent or dye-penetrant examination c. Radiographic examination d. Ultrasonic thickness measurement & flaw detection e. Eddy current examination f. Metallographic examination g. Acoustic emission testing h. Hammer testing i. Pressure testing
45.
List the inspections, which include the features that are common to most vessels and that are most important. (3.6) a. Examine the surfaces of shells and heads carefully for possible cracks, blisters, bulges, and other signs of deterioration. b. Examine welded joints and the adjacent heat-affected zones for service-induced cracks or other defects. c. Examine the surfaces of all manways, nozzles, and other openings for distortion, cracks, and other defects.
46.
Name two reasons why it is necessary for the API 510 inspector to examine flange faces. (3.6) a. To look for distortion b. To determine the condition of gasket-seating surfaces 47. Corrosion may cause what two forms of loss? (3.7) a. b. 48.
Uniform loss - a general, relatively even wastage of a surface area Pitted appearance - an obvious, irregular surface wastage
Name three ways the minimum thickness of a pressure vessel can be determined. (3.7) a. b. c.
API 510
Any suitable non-destructive examination Measurements taken through drilled test holes Gauging from uncorroded surfaces in the vicinity of the corroded are.
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49.
For a corroded area of considerable size in which the circumferential stresses govern, the least thickness along the most critical element of the area may be averaged over a length not exceeding what? (3.7) a. b.
For vessels with inside diameters less than or equal to 60 inches (1 50 centimeters), one half the vessel diameter or 20 inches (50 centimeters), whichever is less. For vessels with inside diameters greater than 60 inches, one third the vessel diameter or 40 inches (100 centimeters), whichever is less.
50.
When can widely scattered pits be ignored? (3.7.e) a. No pit depth is more than 1/2 the vessel wall thickness exclusive of corrosion allowance. b. Total area of pits does not exceed 7 sq. inches in any 8 inch diameter circle. c. Sum of pit dimensions along any straight line within the circle does not exceed 2 inches.
51.
When should the design by analysis methods of Section VIII, Division 2, Appendix 4, of the ASME Code be used? (3.7.) a. To determine if components with thinning walls, which are below the minimum required wall thickness’, are adequate for continued service. b. To evaluate blend ground areas where defects have been removed.
52.
What do you use to determine if the thickness at the weld or remote from the weld governs the allowable working pressure when the surface at the weld has a joint factor other than 1.0? (3.7.g) For this calculation, the surface at a weld includes 1” (2.5 centimeters) on either side of the weld, or twice the minimum thickness on either side of the weld, whichever is greater.
53.
Describe the governing thickness when measuring the corroded thickness of ellipsoidal and torispherical heads. (3.7.h) a. The thickness of the knuckle region with the head rating calculated by the appropriate head formula. b. The thickness of the central portion of the dished region, in which case the dished region may be considered a spherical segment whose allowable pressure is calculated by the code formula for spherical shells.
54.
What is the spherical segment of both ellipsoidal and torispherical heads? (3.7.h) That area located entirely within a circle whose center coincides with the center of the head and whose diameter is equal to 80% of the shell diameter.
55.
On torispherical heads, what is used as the radius of the spherical segment? (3.7.h) Radius of the dish
56.
The radius of the spherical segment of ellipsoidal heads shall be considered to be what? (3.7.h)
The equivalent spherical radius K1D, where D is the shell diameter (equal to the major axis) and K1 is given in Table 1. API 510
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Section 4 - Inspection and Testing of Pressure Vessels and Pressure-Relieving Devices 57.
When is an internal field inspection of new vessels not required? (4.1) When the manufactures' data report (U1) assuring that the vessels are satisfactory for their intended service is available.
58.
Name two factors to be considered when inspection intervals are being determined. (4.1) The risk associated with operational shutdown and start-up and the possibility of increased corrosion due to exposure of vessel surfaces to air and moisture.
59.
How often should each above ground vessel be given a visual external inspection? (4.2) At least every 5 years or at the quarter corrosion-rate life, whichever is less.
60.
When making an external inspection, what shall the inspection include? (4.2) a. b. c. d.
61.
Buried vessels shall be periodically monitored to determine their external environmental condition. What shall the inspection intervals be based on? (4.2) a. b. c. d.
62.
Condition of the exterior insulation Condition of the supports Allowance for expansion General alignment of the vessel on its supports
Corrosion rate information obtained during maintenance on adjacent connecting piping of similar material. Information from the interval examination of similarly buried corrosion test coupons of similar material. Information from representative portions of the actual vessel Information from a sample vessel in similar circumstances
What is the minimum interval for checking the insulating system or outer jacketing of vessels that are known to have a remaining life of over 10 years or that are protected against external corrosion? (4.2) 5years
63.
Question missing (4.3) The maximum period shall not exceed one half the estimated remaining corrosion rate life or 10 years, whichever is less.
64.
If the remaining safe operating life is less than 4 years, what is inspection interval? (43) Interval may be the full remaining safe operating life up to a maximum of 2 years.
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65.
Under what conditions would a vessel with corrosion rate less than 0.001 inch (0.025 millimeter) per year be exempt from an internal inspection? (4.3) a. b. c. d. e.
66.
Remains in the same service Complete external inspections are made Non corrosive character of the contents has been established by at least 5 years of comparable service No questionable condition is disclosed by the external inspection Operating temperature does not exceed lower temperature limits for creep-rupture range of the metal f. Vessel is installed so that the contents are not subject to inadvertent contamination by corrosives.
Write the corrosion rate formula to be used when determining the safe remaining life of a vessel. (4.3) t
actual -tminimum Remaining Life (years) = -------------------corrosion rate Where: tactual = the thickness, in inches millimeters), measured at the time of inspection for the limiting section used to determine the minimum allowable thickness. t minimum = the minimum allowable thickness, in inches (millimeters), for the limiting section or zone. 67.
The remaining life formula shall be reduced to recognize what? (4.3) Problems associated with external loading, faulty material, or fabrication.
68.
When conducting a pressure test as part of a periodic inspection, what shall the shell temperature be during the test? (4,4) Shell temperature shall not be less then recommended by the applicable section of ASME Code or 70 degrees F(20 C) and not greater than 120 degrees F (50 C).
69.
When should pneumatic testing be done and what are some of the considerations to be taken into account? (4.4) Pneumatic testing may be used when hydrostatic testing is impracticable because of temperature, foundation or process reasons, however, the potential personnel and property risks should be considered.
70.
Should safety relief valves ever be removed from a vessel? (4.4) Yes, if a pressure test is being conducted in which the test pressure will exceed the set pressure of the safety relief valve with the lowest setting.
71.
When a pressure relief valve requires repair, who shall make this repair? (4.5) Testing and repairs shall be made by a repair organization experienced in valve maintenance. The repair organization shall have a written quality control system with the minimum requirements as listed in 4.5 of the API 510 code and maintain a training program to insure the qualifications of the repair personnel.
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72.
How often shall a safety relief valve be tested? (4.5) At intervals necessary to verify their reliable performance, up to a maximum of 10 years.
73.
Pressure vessel owners and users are required to maintain permanent and progressive records of their pressure vessels. What things are included in these records? (4.6) a. b. c. d. e.
Copies of manufacturers' data reports and other pertinent data records. Vessel identification numbers Relief valve information. Forms on which the results of inspections, repairs, alterations, or reratings are recorded. Information on maintenance activities and events that affect vessel integrity.
Section 5 - Repairs, Alterations, and Rerating of Pressure Vessels 74.
What must be done before any repairs or alterations are performed? (5.1) All proposed methods of execution, all materials, and all welding procedures that are to be used must be approved by the API authorized pressure vessel inspector and, if necessary, by an engineer experienced in pressure vessel design, fabrication, or inspection.
75.
Can an inspector authorize repairs to ASME Section VIII, Division 2 vessels? (5.1.1) Yes, under the conditions that repairs are limited or routine repairs and he has assured himself that a pressure test will not be required. Otherwise, prior consultation with, and approval by, an engineer experienced in pressure vessel design is required.
76.
Who shall approve all specified repair and alteration work? (5.1.2) The API authorized pressure vessel inspector, after the work has been proven to be satisfactory and any required pressure test has been witnessed.
77.
What must be removed prior to welding materials? (5.1.3) Surface irregularities and contamination.
78.
All repair and alteration welding shall be in accordance with what code? (5.2) ASME Code
79.
What must be done before preheating is used in lieu of PWHT? (5.2.3) A metallurgical review must be conducted to determine if the vessel was postweld heat treated due to the characteristics of the fluid contained in it.
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80
When may preheating to not less than 300 degrees F be considered as an alternative to postweld heat treatment? (5.2.3) For alterations or repairs of vessels initially postweld heat treated as a code requirement and constructed of P-1 and P-3 steels listed in the ASME Code.
81.
List the essential facts of Temper Bead Welding. (5.2.4) a. b.
c. d. e. f.
g.
Preheat - 350 deg. F minimum & maintain during welding. Maximum interpass temp of 450 deg. F. Initial layer entire measuring 1/8" electrode. Remove 1/2 layer by grinding. Subsequent layers with 5/32" electrodes. Final layer removed substantially flush with surface of base material or previous weld layer. Heat input - control with specific current & voltage. After weld repair maintain temp of 500 deg F(± 50 deg.) for minimum 2 hours. Inspector to witness repairs welding. Weld metal deposited by the manual shielded metal arc process (SMAW) using low hydrogen electrodes. Maximum bead width 4 times electrode core diameter. Maximum depth of repair not greater than max. thickness exempt from PWHT in accordance with UCS 56, ASME SEC.VIII DIV 1.
82.
Can local postweld heat treatment (PWHT) be substituted for 360-degree banding? On what materials? (5.2.5) YES provided the following conditions are met: a. Application is reviewed and procedure developed by engineer experienced in pressure vessel design & PWHT requirements. b. In evaluating the suitability of a procedure, all applicable factors (base metal thickness, material properties, etc.) are considered. c. Preheat of 300 degree or higher per WPS is maintained. d. PWHT temperature is maintained for distance not less than 2 times base metal thickness measured from weld. Minimum of 2 thermocouples is used. e. Heat is applied to any nozzle or other attachment in PWHT area.
83.
Per API 510, state the design requirements for: Butt Joints, Replacement Parts New Connections, Fillet Weld Patches Overlay Patches, Flush patches (5.2-6) a. BUTT JOINTS - shall have complete penetration and fusion. b. REPLACEMENT PARTS - shall be fabricated in accordance with "Principles" of ASME Code. c. NEW CONNECTIONS - design, location, and method of attachment shall be according to "principles" of ASME code. d. FILLET WELDED PATCHES - require special design considerations, especially relating to efficiency. May be applied to internal or external surfaces of shells, heads or headers provided that the inspector judges that patch: 1. Patch provides equipment safety of repad. 2. Is designed to absorb membrane strain that complies with applicable section of ASME Code. e. OVERLAY PATCHES - shall have rounded corners. f. FLUSH (insert) PATCHES shall have rounded corners and be installed with full penetration butt joints.
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84.
Describe the material suitable for making repairs or alterations. (5.2.7) Shall conform to the applicable section of the ASME Code, be of known weldable quality and be compatible with the original material. Carbon or allow steel with a carbon content over 0.35 percent shall not be welded.
85.
When making a repair or alteration, what should the acceptance criteria include? (5.2.8) NDE techniques that are in accordance with the applicable sections of the ASME Code or another applicable vessel rating code.
86.
After repairs or alterations, is a pressure test required? (5.2.9) Repairs - pressure-test only applied if inspector believes one is necessary. Alterations - pressure test required.
87.
Can alternative procedures be substituted for a pressure test after completion of alterations? (5.2.9) Substituting nondestructive examination procedures for a pressure test may be done only after an engineer experienced in pressure vessel design and the API inspector have been consulted.
88.
89.
List the requirements associated with rerating a pressure vessel. (5.3) a. Calculations from either the manufacturer or an owner-user engineer experienced in pressure vessels shall justify rerating. b. Appropriate code requirements as established in accordance with the construction code. c. Inspection records verify the pressure vessel is satisfactory for the proposed service conditions and that the corrosion allowance provided is appropriate. d. Pressure test and/or NDE has at some time been performed in accordance with the new service conditions to verify vessel integrity. e. The pressure vessel inspection and rerating is acceptable to the API authorized pressure vessel inspector. When is the rerating considered complete? When the API authorized pressure vessel inspector oversees the attachment of an additional nameplate or additional stamping that carries the following information: Rerated by: Maximum Allowable Working Pressure psi at degrees F. Date Missing pages 20 through 30
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API RECONMENDED PRACTICE 572 FIRST EDITION, FEBRUARY 1992 REVIEW QUESTIONS Section 1 - General 1.
What are the main points covered in API RP 572? (1. 1) a. b. c. d. e. f. g.
Description of various types of pressure vessels Standards for construction Reasons for inspection Causes of deterioration Frequency & methods of inspection Methods of repair Preparation of records and reports
Section 5 - Reasons for Inspection 2.
What are the basic reasons for inspection? (5.1) a. b.
3.
To determine the physical condition of the vessel Determine the type, rate and causes of deterioration
List at least four additional reasons for inspections. (5.1) a. b. c. d.
Safety maintained Periods of operation without shutdown extended - well planned maintenance program Rate of deterioration often reduced Future repair and replacement requirements estimated
Section 6 - Causes of Deterioration 4.
List the 4 general forms of deterioration. (6.1) a. Electrochemical b. Chemical c. Mechanical d. Combination of all three
5.
List the 4 general classifications of things that cause deterioration upon coming into contact with a vessel surface. (6.1) a. Organic & inorganic compounds b. Contaminated or freshwater c. Steam d. Atmosphere
6.
Name 6 factors, which accelerate the rate of deterioration. (6.1) a. Temperature b. Stress c. Fatigue d. Impingement e. High velocity f. Irregularity of flow
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7.
What is the prime cause of deterioration in a pressure vessel? (6.2) Corrosion
8.
What are the most common internal corrodents in refineries? (6.2) a. b.
9.
Sulfur Chloride compounds
Define erosion. (6.3) The attrition of a surface from the impingement of solid particles or liquid drops on the surface.
10.
Where is erosion typically found? (6.3) a. b. c. d. e. f.
11.
Inlet and outlet nozzles Internal piping Grid or tray sections Vessel walls opposite inlet nozzles Internal support beams Impingement baffles pressure vessels? (6.4) missing part of question
Micro structural or metallurgical changes which may affect the mechanical properties resulting in cracking. 12.
Give examples of metallurgical and physical changes. (6.4) a. b. c. d. e.
13.
List examples of mechanical forces. (6.5) a. b. c. d. e.
14.
Graphitization High-temperature hydrogen attack Carbide precipitation Intergranular corrosion Embrittlement
Thermal shock Cyclic temperature changes Vibration Excessive pressure surges External loads
Cracks, bulges, distortion, and upset internal equipment are visual signs of what? (6.5) Application of mechanical forces
15.
Many of the problems that may develop in pressure vessels are traceable to what? (6.6) Faulty material or fabrication
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16.
Poor welding, improper heat treatment, fabrication with dimensions outside tolerances allowed by ASME Code, improper installation of internal equipment, and assembly of flanged or threaded joints are examples of what problem? (6.7.1) Faulty fabrication
17.
? a. b. c. d. e. f.
18.
missing question on copy
(6.7.2)
Incomplete penetration Lack of fusion Cracking Undercutting Slag inclusion Porous welds
High residual stresses near welds affecting the physical properties and corrosion resistance of the metal is caused by what? (6.7.3) Improper heat treatment
19.
Dimensional intolerance can lead to what? (6.7.3) Stress concentrations and subsequent failures
20.
What are the consequences of improper installation of internal equipment? (6.7.5) a. b. c.
21.
Inefficient operation Blockage of passages Displacement of internal equipment with pressure surges
Improper fitting or tightening of flanges or threaded joints may lead to what? Leaks and possible failure
Section 8 - Methods of Inspection and Limits 22.
Before starting inspection of a pressure vessel, what are some basic things the inspector should do? (8.1) a. b.
23.
Determine pressure and temperature conditions under which the vessel has operated since last inspection Ascertain the character of the vessel contents and the function the vessel serves in the process
Name at least 6 types of tools required by an inspector to inspect a pressure vessel. (8.2.2) a. b. c. d. e.
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f. g. h. i. j. 24.
Steel tape measure Hammer Notebooks and pencils Magnets Plastic bags
Where should the external inspection start? (8.3.2) External inspection should start with ladders, stairways, platforms, or walkways connected to or bearing on the vessel. The condition of most parts can be determined by hammering.
25.
What are most foundations constructed of? (8.3.3) Foundations for vessels are almost always constructed of steel-reinforced concrete structural steel fireproofed with concrete.
26.
Relative to concrete foundations, what causes spalling? (8.3.3) a. b. c. d.
27.
Excessive heat Mechanical shock Corrosion of reinforcing steel Freezing of entrapped moisture
How do you check for lack of bond between concrete fireproofing and the protected vessel? (8.3.3) Light tapping with a hammer and picking with a pointed scrapper.
28.
What is the proper way to check an anchor bolt on a piece of equipment? (8.3.4) A sideways blow with a hammer - to determine if the bolt is deteriorated below the base plate.
29.
Often corrosion of structural elements can be virtually eliminated by a simple procedure which is? (8.3.6) Proper painting
30.
What is one of the best methods for protecting steel structures? (8.3.6) Galvanizing
31.
Describe how you would determine the extent of bulging or buckling on a vessel in service. (8.3.6) They can be inspected visually with the aid of a straightedge or plumb line.
32.
What should you inspect guy wires for? (8.3.7) Tightness and correct tension - a visual inspection should be sufficient.
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33.
What type of corrosion are turnbuckles subject to? (8.3.7) Crevice corrosion
34.
Explain proper installation of wire clips on guy wires. (8.3.7) The clips should be attached to the cable with the base against the live or long end of the wire and U-bolt against the dead or short end of wire.
35.
What is the recommended resistance for grounding connections? (8.3.9) 5 ohms or less, not to exceed 25 ohms
36.
Unchecked vibrations on auxiliary equipment such as gauge connectors can cause what type of failure? (8.3.10) Fatigue failure
37.
What type of inspection is usually sufficient for protective coatings and insulation? (8.3.11) Visual
38.
When should insulation or protective coatings be removed? (8.3.11) When there is evidence of moisture or other corrosive agents have gotten through to the metal surface.
39.
What are the measurement requirements on external metal surfaces? (8.3.13) Under normal conditions, at least one measurement in each shell ring and one on each head. If no history exists for a vessel, then get a reading in each quadrant of each shell ring.
40.
What types of corrosion are found on external surfaces of vessel? (8.3.13) a. b. c. d.
41.
Atmospheric Caustic Embrittlement Hydrogen blistering Soil corrosion
Vessels containing acidic corrodents are subject to hydrogen blistering. Where would this be found in the vessel? (8.3.13) Those areas below the liquid level in vessels containing acidic corrodents are more likely than other areas to be subject to hydrogen blistering.
42.
What should a vessel be checked for if a caustic is stored in it? (8.3.13) If a caustic material is stored or used in a vessel, the vessel should be checked for caustic embrittlement.
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43.
Evidence of white salts seeping through cracks will indicate what type of material? (8.3.13) Caustic material
44.
Unless readily visible, leaks are best found by what means? (8.3.13) Pressure or Vacuum testing
45.
Describe how you would determine the extent of bulging or buckling on a vessel in service. (8.3.13) By measuring the changes in circumferences or by making profiles of the vessel wall. Profiles are made by taking measurements from a line parallel to the vessel wall. A surveyor's transit or a 180 degree optical plummet may also be used.
46.
The degree of surface preparation needed for internal inspection will vary with several factors. Foremost among these are: a. b.
47.
Type of deterioration expected Location of any deterioration
Cracks in vessels are most likely to occur where? (8.4.3) In places where there are sharp changes in shape or size or near welded seams, especially if a high stress is applied.
48.
What may preliminary inspections reveal? (8.4.3) Unsafe conditions, such as those due to loose internals that may fall or due to badly corroded or broken internal ladders or platforms.
49.
A detailed inspection should start at one end of the vessel and work toward the other end and include what? (8.4.4) A systematic procedure to avoid overlooking obscure but important items.
50.
What should all parts of a vessel be inspected for? (8.4.4) a. b. c. d. e.
51.
Corrosion Erosion Hydrogen blistering Cracking Laminations
Ultrasonic instruments can be used to obtain what kind of measurements? (8.4.4) Thickness measurements
52.
What types of methods are used for determining the extent of cracks? (8.4.4) a. Dye penetrant b. Magnetic-particle (wet or dry) c. Ultrasonic shear-wave
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53.
Explain the difference in appearance between erosion and corrosion. (8.4.4) Erosion is characterized by a smooth, bright appearance: marked by the absence of the erosion product; and metal loss, is usually confined to a clearly marked local area. Corroded areas are not often smooth or bright.
54.
What do the initials UT mean? (8.4.4) Ultrasonic Test
55.
How do you check for (a) small distortions, (b) bulging or buckling (c) out-of roundness or bulging? (8.4.4) a. b. c.
56.
Small distortions - by placing a straight edge against a vessel. Bulging/buckling - measuring the changes in circumference or by profile (measuring from a line strung parallel to the vessel). Out-of round/bulge - by measuring the minimum and maximum internal deviation at the cross sectional area and comparing the two.
What is the best method of locating suspected deformations? (8.4.4) Direct a flashlight beam parallel to the surface to check for shadows in depressions and on the unlighted sides of internal bulges.
57.
What is the most sensitive method of locating surface cracking? (8.4.4) Fluorescent Magnetic Particle Method
58.
What is the difference between cracks and laminations? (8.4.4) Laminations run at a slant to the plate surface. Cracks run at right angles to the surface.
59.
Name three important factors in the inspection of metallic linings. (8.4.5) a. b. c.
60.
That there is no corrosion That the linings are properly installed That no holes or cracks exist
Explain how the Corrosive Tab Method is used to determine the metal loss on vessel linings. (8.4.5) Small 1 by 2 inch tabs of lining that form a right angle are welded onto the lining with one leg extended into the vessel. During inspections the thickness of the protruding leg is measured, and, since both sides of the leg are exposed to corrosive action, the loss in thickness would be twice that of the lining.
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61.
What are principle methods used to inspect nonmetallic linings (glass, plastic, rubber, concrete, and carbon block or brick). (8.4.6) For the most part all of the above will be visually inspected for discontinuities or physical damage. Specific: For paint, glass, plastic, & rubber lining the spark tester method is used to locate holidays. For concrete, brick, tile, or refractory lining the hammer testing method is used to locate lack of bond.
62.
Name at least three factors for the selection of tools for thickness measurements. (8.4.7) a. b. c. d. e.
63.
Accessibility from both sides Desire for NDE methods Accuracy desired Time available Economy
What are the primary means of obtaining thickness measurements? (8.4.7) Ultrasonics instruments.
64.
To analyze defects in welded seams that are not visible on the surface of the metal, what two methods are used? (8.4.8) a. b.
65.
Radiography Shear-wave Ultrasonics
How does the Hammer Test function in supplementing visual examination of a stayed vessel for the inspector? (8.5.1) “Thin” Locate thin sections in vessel walls, heads, and attachments. "Tightness" Check for tightness of rivets, bolts, brackets, and the like. "Cracks and Lack of Bond" Check for cracks in metallic linings and lack of bond in concrete linings. "Scale" Remove scale accumulations for spot inspections.
66.
When is use of the Hammer Test not recommended? (8.5.1) a. b.
67.
When objects are under pressure On piping upstream from a catalyst bed
What is pressure testing? (8.5.2) Filling a vessel with liquid or gas and building up an internal pressure to a desired level.
68.
Which is the preferred method, pressure or vacuum testing, and why? (8.5.2) Pressure testing. Leaks from an internal pressure source are more easily located. With vacuum testing you will know if there are leaks, but the location is not evident.
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69.
Name the two most limits of corrosion or other deterioration that must be known by inspection. (8.6) a. b.
70.
The retiring thickness of the part considered The rate of deterioration
What is the prime factor affecting retiring thickness? (8.6) Safety
71.
Before determining the limiting or retiring thickness’ of parts of any pressure vessel, what must be known? (8.6) a. b.
Which Code and edition of that Code it is to be rated under. Are there specific regulations regarding limits and allowable repairs.
Section 10-Records and Reports 72.
A complete record file should contain what three types of information? (10. 1) a. b. c.
73.
Basic data - manufacturers drawings, data reports and specifications, design information, results of any material tests. Field notes - notes and measurements recorded on site including record of condition of all parts inspected and repairs required. Continuous file - all information on the vessel's operating history, previous inspections, corrosion rate tables, records of repairs and replacements.
When making reports recommending repairs, who should receive these reports? (10.2) All management groups. This would normally include engineering, operation, and maintenance departments. Reports should include the location, extent, and reasons for recommended repair.
Appendix A - Exchangers 74.
Why should bundles be checked when they are first pulled from the shells? (A.9. 1) The color, type, amount, and location of scales and deposits often help to pinpoint corrosion problems.
75.
A distinctive Prussian Blue on bundle tubes indicates the presence of what? (A.9.2) Ferriferro cyanide
76.
Coils in open condenser boxes and double-pipe exchanger shells should be inspected according to what API Recommended Practice? (A.1 0) RP574
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CHAPTER 11 CONDITIONS CAUSING DETERIORATION OR FAILURES SECOND EDITION, 1973 201 General 1.
What are the modes of failure that can be found in refinery equipment? (201.2) a. b.
c.
d. e.
Fatigue Failures - is caused by stress reversals. (In machinery these cracks start at the surface and progress with each stress reversal.) Distortion Failures - occur when equipment is subjected to temperatures above design temperature. At high temperatures the metal becomes weaker and distortion occurs which may result in failure. Brittle Fracture - carbon steels are susceptible to brittle fracture at ambient temperatures and below. A number of tank failures have been attributed to the brittle condition of steel at low temperatures, combined with high loads that have been imposed by thermal stress set up rapid temperature changes. Excessive Metal Loss - may result in failure if remaining wall thickness gets below safety valve settings. This is a rare occurrence. Wrong Material or Wrong Gaskets - may lead to failure.
202 - Corrosion 2.
Corrosion problems in refining operations can be, divided into three major groups. What are these groups? (202.1) a. b. c.
3.
Name the corrosion compounds found in crude oil. (202.01) a. b. c. d. e. f.
4.
Corrosion from components present in crude oil Corrosion from chemical used in refinery processes Environmental corrosion
Hydrogen Chloride and organic/inorganic chloride Hydrogen sulfide, mercaptans, & organic sulfur compounds Carbon dioxide Dissolved oxygen and water Organic acids Nitrogen compounds
What is hydrogen chloride? streams? (202.022)
When does it become corrosion problem in process
A dry hydrochloric acid (normally not corrosive in process streams). When water is available to form hydrochloric acid. 5.
What do all crude oils contain? (202.022)
6.
Salt What is the most active of the sulfur compounds in causing corrosion in refinery equipment? (202.023) Hydrogen Sulfide
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7.
At what temperature range does accelerated hydrogen sulfide corrosion occur in refinery equipment? (202.023) Between 450°F and 900°F
8.
What makes carbon dioxide corrosive? (202.024) When it combines with water, it then becomes carbonic acid.
9.
Where is corrosion by carbon dioxide found to most severe? (202.024) In hydrogen plants
10.
Dissolved oxygen and water is a corrosion problem in what equipment? (202.025) Storage tanks
11.
When are organic acids very corrosive? (202.026) At their boiling temperatures. condensation.
12.
The most severe form of corrosion occurs upon
What two forms of corrodents are formed when nitrogen is cracked in a cracking or catalytic cracking unit? (202.027) Ammonia & Cyanide
13.
What is phenol and what is it used for? (202.033) Carbolic acid - Used in refinery operations in the manufacture of lubricating oils and aromatics.
14.
What is caustic and what is it used for in refinery operations? (202.035) Sodium Hydroxide - Used for the neutralization of acid components and for grease manufacture.
15.
When ammonia is permitted of contact copper base alloys in pH ranges of 8.0 and above, severe corrosion in three form of general metal loss and stress corrosion cracking will occur. How may this attack be identified? (202.037) By the appearance of blue salt
16.
What is the primary use of ammonia in the refining industry? (202.037) a. b.
17.
As a refrigerant For neutralization of acidic components in overhead streams, from pipe stills, and catalytic cracking units
What materials is ammonia harmful to? (202.037) Copper base alloys
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18.
What is chlorine used for in refinery operations and when does it become very corrosive? (202.038) Used for treating cooling water and for the manufacture of sodium hypochlorite for treating oils. It becomes very corrosive in contact with small amounts of moisture
19.
Aluminum Chloride - What is it used for? What does it form in the presence of water? How does it affect carbon steel arid stainless steels? (202.039) Used as a catalyst in isomerization units. Forms hydrochloric acid in the presence of water. Hydrochloric acid causes severe pitting corrosion in carbon steel and Intergranular and stress corrosion cracking in stainless.
20.
What is the term applied to atmospheric corrosion? (202.041) Galvanic
21.
What is needed to prevent atmospheric corrosion? (202.041) Eliminate water from the surface of the metal by means of a protective barrier or coating.
22.
At what temperature does hidden corrosion take place under insulation and fireproofing if moisture penetrates through cracks in the insulation? (202.042) In vessels and piping operating below approximately 250°F.
23.
When does oxygen become destructive? (202.052) At high temperatures oxygen reacts with steel to cause scaling (iron oxide).
24.
Why may steam at high temperatures cause scaling? (202.053)
Because the steam may be decomposed to hydrogen and oxygen, and the free oxygen may cause severe scaling. 25.
Vanadium oxide corrosion does not take place below what temperature? (202.054) 1,100°F
26.
The extent of corrosive attack by hot sulfur compounds (sulfur dioxide, hydrogen sulfide) depends on what three things? (202.055) Concentration, temperature, and oxidizing power of the environment.
27.
At what temperature does all gray cast iron begin to deteriorate, resulting in extreme brittleness, loss of strength, scaling, and growth? (202.056) 800°F
28.
Growth of cast iron results from what two things? (202.056) Graphitization & infiltration of corrosive gases into the structure
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29.
What is graphitic corrosion? (202.063) Low temperature corrosion of gray cast irons in which metallic iron is converted into corrosion products, leaving the graphite intact.
30.
In what material do you find graphitic corrosion and at what temperature does it occur? (202.063) In cast iron at temperatures below the dew point of water.
31.
How can you recognize graphitic corrosion? (202.063) By the soft porous structure that remains in the areas where it occurs.
32.
What materials is mercury harmful to? (202.064) a. b.
33.
Monel and copper based alloys (stress corrosion cracking) Aluminum a1loys
Define Stress Corrosion Cracking. (202.064) The spontaneous failure of metals by cracking under the combined action of corrosion and tensile stress
34.
What is dezincification? (202.066) A type of corrosion that can occur in copper - zinc alloys (brasses) containing less than 85% of copper used in water service.
35.
What are three types of dezincification? (202.066) a. b. c.
36.
Plug - occurs in localized areas. Layer - covers large areas. Intercrystalline - occurs along grain boundaries.
What are inhibited brasses? (202.066) Brasses which have been alloyed with arsenic, antimony, or phosphorus to inhibit dezincification
37.
What is galvanic corrosion? (202.067) An electrochemical type corrosion that occurs when two different metals are electrically connected, either by direct contact or by an electrical conductor, and are in contact with an electrical solution called an "electrolyte".
38.
What is contact corrosion (crevice corrosion)? (202.068) A type of corrosion that occurs at the point of contact or in a crevice between a metal and non-metal or between two pieces of metal in the presence of a corrodent.
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39.
What is biological corrosion? (202.069) Corrosion influenced by primitive organisms.
40.
What are the most important micro-organisms that directly influence the rate of metallic corrosion? (202.069) Sulfate reducing bacteria found in many soils.
203 – Erosion 41.
Erosion is frequently a problem in equipment utilizing the fluid and solids principle. What is this principle? (203.02) If a gas stream of sufficient velocity is passed through a mass of finely divided solids, such as a powder, the mass of particles will behave very much like a true liquid.
42.
What method of deterioration does cavitation induce? (203.022) Erosion. Cavitation erosion is associated with the formation and collapse of cavities in a liquid at the metal to liquid interface.
204 - Effects of High Temperatures 43.
Define creep. (204.012) The flow or plastic deformation of metals held for long periods of time at stress lower than the normal yield strength.
44.
A stress - rupture is what type of failure? (204.013) A brittle type failure - stress rupture relates the time to failure with temperature and stress.
45.
When austenitic stainless steels are heated or cooled in the temperature range of 750°F to 1,650°F, what does this make the material susceptible to? (204.022) Intergranular corrosion
46.
When ferritic steels are heated above a certain temperature (above 1,100°F for mild steel), how does this affect the material? (204. 022) Leads to general lowering of the tensile strength.
47.
What is incipient melting (burning)? (204.022) When ferritic steels are heated above approximately 2,600°F, melting and oxidation will begin at the grain boundaries. The steel is called "burned" and will be very weak and brittle upon cooling.
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48.
What is Graphitization? (204.022) A structural change in certain ferritic steels that have operated for a long period of time between 825°F and 1,400°F. Carbide is unstable in that temperature range and may decompose into iron (ferrite) and graphite (carbon).
49.
What are the two general types of Graphitization? (204.022) Random Graphitization - graphite distributed uniformly throughout the steel. Localized Graphitization - graphite highly concentrated in local regions.
50.
What is Sensitization? What happens to sensitized steel when exposed to corrodents? (204.022) When austenitic stainless steels are exposed to temperatures of 750°F to 1650°F precipitation of a complex chromium carbide at the grain boundaries takes place. When the sensitized steel is exposed to corrodents, intergrannular corrosion takes place.
51.
What is decarburization? (204.034) The loss of carbon from the surface of a ferrous alloy as a result of heating in a medium that reacts with carbon. This results in lower tensile strength, hardness, and fatigue strength. It can only be found by metallurgical examination.
52.
At what temperature does hydrogen have a very destructive effect on steels? (204.035) Above 450°F
53.
What curve shows the different steel / temperature limits for hydrogen service? (204.035) Nelson Chart
205 - Subnormal and Ambient Temperature Effects 54.
Define notch toughness (a properly of metals). (205.01) The amount energy necessary to cause fractures in the presence of a sharp notch or stress concentrator.
55.
Brittle fracture can be recognized by several characteristics. What are these characteristics? (205.01) a. Cracks propagate at high speed. b. There may be a loud report or sharp rending sound. c. There is almost a complete lack of ductility. d. The fractured surfaces have a brittle or faceted surface.
206 - Excessive Pressure
56.
What is excessive pressure? (206.01) Those in excess of the MAWP of the equipment under consideration
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57.
Name four causes of excessive pressure.(206.021;206.022;206.023;206.024; 206.025) a. b. c. d.
Added heat in excess of normal operations Blocking off against a pressure source Thermal expansion of a trapped liquid Hydraulic hammer or resonant vibration
207 - Overloading 58.
What are some indications of overloading of equipment? (207.02) a. b. c.
Visible distortion Change of shape Change of position
Appendix 1 59.
Steel (ferrous alloy)is an alloy of iron and carbon. What is the carbon content range? (App 1.A) 0.01% to 1.7% (Max. carbon content of weldable steels for Code purposes is 0.35%)
60.
Usually for refinery construction steels have less than what percent carbon? (App 1. A) Less than 1%
61.
Steels for welding have a maximum of what percent carbon content? (App 1.A) 0.35%
62.
There are two general types of steels. What are these? (App 1. A) a. b.
63.
Ferritic Steel - ordinary carbon steel low and intermediate alloy steels, and high alloy steels (straight chromium). Austenitic - chromium - nickel stainless steels.
Non-ferrous metals and alloys contain what percent iron? (App 1 B) Less than 50%
64.
What is the only common copper - nickel alloy and what is it used for? (App 1 B) Monel it is used for relatively low temperature corrosion resistance.
65.
What are the major uses of commercially pure copper in refineries? (App 1 B) Electrical conductors, gaskets, and corrosion resistance
66.
What are the major uses of aluminum and its alloys in refineries? (App 1 B) Corrosion resistance and for structures where lightweight is a necessity.
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CORROSIVE MATERIALS ADDED TO CRUDE WHICH CAUSE CORROSION Sulfuric Acid and Hydrogen Fluoride - used in Alkylation units as a catalyst Concentrations 85% to 95% for sulfuric acid and above 65% for hydrogen fluoride Phenol (Carbolic Acid) - used for the manufacture of lubricating oils and aromatic hydrocarbons. Phosphoric Acid - used for a catalyst in polymerization units. Caustic (Sodium Hydroxide) - used for neutralization of acidic components Mercury - used in instruments Ammonia - used as a refrigerant and neutralization of acidic components. Chlorine - used to treat cooling tower water and manufacture of sodium hypochlorite for treating oils. Aluminum Chloride - used as a catalyst for isomerization units.
PREVIOUS NBIC QUESTIONS ON MATERIAL 1. What is in a mill test report (certified material report) and what is the authorized inspector's interest in this document? (Def. App 3 Sect VIII) It is a certified report from the material manufacturer attesting to the chemistry and physical properties of the material. In the case of plate steel, it shows the heat number, which is also stamped on the plate, and the chemical and physical specifications of the material. It is used to identify the material and to verify that its properties meet minimum Code specifications. This report must be in existence for most materials used in Code boiler and pressure vessel construction. 2.
When may an Authorized Representative of the pressure vessel manufacturer transfer the required markings on plate material? (Section VIII Division 1, UG-77) It is permissible for an Authorized Representative of the vessel manufacturer to transfer the markings on the plate provided a record is made of such markings. The procedure for making such transfer shall be acceptable to the Authorized Inspector.
3.
a. When must the identification markings be transferred, when cutting plate material into two or more parts? b.
What documentation is required for the transfer of material identification markings according to Section VIII of the ASME Code? (Section VIII Division 1, UG-77)
a. b.
After layout but prior to cutting the plate. Any record acceptable to the Authorized Inspector.
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4.
Under what conditions may surface defects in material be repaired by the manufacturer? (Section VIII Division 1, UG-78) Surface defects in materials may be repaired by the vessel manufacturer provided approval of the Authorized Inspector is first obtained for the method and extent of repair.
5.
What causes a plate when rolled and formed into a cylinder to retain its shape? The outer fibers of the material are stretched beyond the elastic limit.
6.
a. What is the permitted under tolerance for plate material in Section VIII provided the material specification permits plate to be furnished to an under tolerance? (Section VIII, UG-16) b. In ordering SA-53 pipe, what is the permitted manufacturer's under tolerance, which must be added to the calculated thickness if ordering to a nominal wall thickness? a. 0.01” b. The allowed manufacturing under tolerance as given in Section II of the ASME Code
7.
Name two chemical or structural factors, which affect the hardness of steel. a. Carbon content b. Heat treatment
8.
a. What objectionable characteristics would excessive percentages of phosphorus and sulfur be expected to impart to plate material used -in vessel shells or other pressure parts? b. As an authorized inspector checking incoming material for use in a boiler or pressure vessel, where would you look to find the percentages of the above elements in the material being checked? c. Where would you find the allowable percentages of these elements in a given material? a. High sulfur content causes surface cracks during the rolling process, which is attributed to the hot shortness of the metal. High phosphorus causes cold shortness. Both impart brittleness and decrease ductility and strength of the metal. b. This information would be located on the mill test report for the material in question. c. This information is contained in the ASME Code, Section II, and Material Specifications.
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9.
Define the following properties of steel and state in what units they are normally measured: a. b.
c. d. 10.
a. b. 1. 2. 3.
Ultimate Tensile Strength: In tensile testing, the ratio of maximum load to original cross sectional area. Measured in PSI. Yield point: Yield Point: The first stress in a material in which there is increased deformation under constant load. Measured in PSI. Elastic Limit: The point on the stress-strain curve beyond which if stress is removed, the material does not return to its original length. Measured in PSI. Elastic limit: The point on the stress-strain curve beyond which if stress is removed, the material does not return to its original length. Measured in PSI. Ductility: Ability to deform plastically without fracture. What is the maximum carbon content of carbon and low alloy steels to be used in welded construction or to be shaped by thermal cutting process? What objectionable qualities would excessive amount of the following impart to steel plate? Manganese Phosphorous Sulfur (Section VIII, UCS-5, API-510 5.2.7)
a. 0.35% b. High phosphorus content causes cold shortness. High sulfur content causes surface cracks during the rolling process, which is attributed to the hot shortness of the metal. All three increase brittleness and decrease ductility and strength of the metal. 11.
What is the purpose of aluminum being added to steel? At elevated temperatures, aluminum combines vigorously with oxygen. Accordingly, it is added to molten steel to remove impurities, resulting in a more ductile material.
12.
List at least six items, which can be found on a material mill test report. a. b. c. d. e. f.
13.
Mill or manufacturer of the material Chemistry of the material Physical properties of the material In the case of plate steel, it shows heat slab number from which the plate was made Specification Thickness of material
List the material product form(s), (pipe, bar, etc.) for which a Material Test Report is always required by Section VIII, Div. 1. Plate
14.
Is a material supplier's (not the original material manufacturer) material test report acceptable for Code pressure boundary plate material in lieu of the original material manufacturer's test report? (Section VIII, UG-93) No
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PREVIOUS NBIC QUESTIONS ON WELDING 1.
May a GMAW, short circuit transfer, welding procedure be qualified using radiography? (Section IX, QW-202.1) No, mechanical tests are required for WPS’s.
2.
A SAW welding operator is attempting to qualify by radiography on a 6-inch thick test coupon. Elongated slag inclusions are measured to be 0.2 inch long. Is the operator qualified? (Section IX, QW-191.2.2) Yes. Slag is less than 3/4"
3.
May a FCAW welder qualified using RT, be used to weld a Section VIII, Division 1 pressure vessel using FCAW, SFA 5.20? (Section IX, QW-191.2.2) Yes, welders and welding operators may be qualified by radiography on most materials
4.
May a welder, qualified on a 2G plate coupon with SMAW; without backing material, make a 6 inch circumferential pipe weld in the horizontal position using the SMAW process with a backing bar? (Assume no F or P number change.) (Section IX, QW-461.9, QW-353) Yes, flat and horizontal by note (2) QW-461.9. QW-363 considers addition of backing not an essential variable for a welder.
5.
A welder is qualified in the 2G position on plate with backing using the GTAW process. Is the welder qualified to use the following positions? (Section IX, QW-461) Pipe groove welds in the F and H position. Yes Plate groove welds in the H and V positions. No
6.
7.
8.
a.
b.
May a welder, qualified in the 2G position on ¼ inch -thick plate, weld a 1 inch outside diameter pipe, 1/4 inch thick in the horizontal position without requalification (Assume SMAW, F-1 electrode in both cases.) Why or why not (Section IX, QW-461.9)
a. b.
No Not qualified for small diameter pipe, 2-7/8"and over by note (2)
a. b.
What ASME Code Section has welding electrode storage requirements? Are they mandatory or recommended?
a. b.
Section II, Part C Recommended
What is a welder continuity log? (Section IX, QW-322) Document to maintain a welder's qualification for compliance to QW-322.
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9.
May a welder deviate from the parameters specified in a WPS if they are a nonessential variable? (Section IX, QW-200.1(c)) No, the WPS would need revision.
10.
May a welder who is qualified using a double-groove weld, make a single V-groove weld without backing on a Section VIII, Division 1 vessel without requalification? (Section IX, QW-200.1, QW-310.2) No, a double weld is the same as backing
11.
An SMAW WPS specifies an amperage range of 50-300 amps for E7018 electrodes. The welder wants to use 400 amps to weld a groove weld. (Section IX, QW-200.1(c), QW-253) a. Must the procedure be requalified? b. If not, what must be done as a minimum? If yes, why must it be requalified? a. b.
12.
a. A welder was qualified with a P-1 test coupon without backing (using SMAW E7018 electrodes). May the welder weld P-4 material using E8028 electrodes in production? (Assume the P-4 procedure using E8028 electrodes has been qualified with backing.) b. Why or why not? (Section IX, QW-403.18, QW-423.1)) a. b.
13.
No nonessential variable per QW-409.8 Revise WPS
a.
b.
Yes, Qualifying with a higher P-no. allows welding to a lower P-no. with backing. P-no.1 qualifies P1~11 and P-no. 4X May a GTAW welder be qualified by radiography on a production weld in lieu of bend tests? The test coupon will be P-22 material and the production welds will be P-22 also. If your answer is yes, what is the minimum test coupon length? If your answer is no, why not? (Section IX, QW-304, QW-304.1)
a. Yes b. 6” 14.
a.
b.
A repair organization has a WPS which states it is qualified for P-8 to P-8 material welds with either E308, E308L, E309, E316, electrodes (SMAW process). The PQR, supporting this WPS, states that the weld test coupons were SA-240 Type 304L material, welded with E308 electrodes. Is the WPS properly qualified for the base material listed? Explain your answer. (Section IX, QW-422)
a. b.
Yes SA-240 is P8 material.
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15.
A groove weld WPS is qualified using an 8 inch thick test coupon. The testing equipment for tensile and bends only accommodates 1 1/2 inch wide by 1 1/2 inch thick specimens (maximum size). Only one welding process, F-number and base material is used. How many and what type (i.e., side, face or root) of tests are required? (If none, put "none". Assume the minimum number of tests will be done. Show any calculations.) (Section IX, QW-451) a. Number of side bends b. Number of tensiles
6 x 4=24 6 x 2=12
8 / 6 = 1.33” Minimum number approximately equal 16.
May an individual using the automatic SAW process be qualified by radiography on a 6 inch production weld and meet Section IX requirements? (Section IX, QW-305.1) No, 3 feet; remember SAW requires a welding operator.
17.
One PQR qualified with GTAW and another PQR qualified with SMAW may be combined to qualify a WPS for GTAW and SMAW in combination. Give at least 4 items that will restrict the WPS. (Section IX, QW-200.4 (a)) a. b. c. d.
18.
P-number Base material number Heat treatment Weld deposit
A welder was qualified in 1972. The welder's qualifications have been maintained since that time. The requirement for small diameter qualifications (QW-452.3) did not appear until 1975. The welder was originally qualified on 6 inch diameter pipe. May the welder weld 1 inch NPS pipe today without requalification? The welding will be attaching a 1 inch sit-on fitting to the wall of a Section VIII, Division 1 pressure vessel. (Section IX, QW-100.3) Yes
19.
What are starting tabs and runoff tabs, how are they used and what are the advantages? Whenever it is necessary to weld to the very end of a joint, it is necessary to provide some means of restraining the metal so that it does not spill off the end. Run-off tabs are the most commonly used method. They are steel tabs tacked to the ends of the weld seam, having a joint similar to, and in alignment with the one being welded. An arc is started on a run-off tab that is tacked to the start end of the weld and is stopped on a second tab on the finish end of the weld. In addition to restraining the weld metal, these tabs also minimize the discontinuities in the weld seam associated with the starting and stopping of the welding process.
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20.
a. b. c.
a. b. c. 21. a. b. c. d.
Who is responsible for the quality of welding produced in Code manufacturer's shop? Who is responsible for qualification of welding procedures, welders and welding operators? Who may ask for the requalification of a welder? (Section IX, QW-322.1, Sect. VIII, UW-26) The manufacturer The manufacturer The authorized inspector What is a welding procedure specification? What is a welding procedure qualification? What is a performance qualification test? Who is responsible for preparing the foregoing and what are the requirements for documentation under the Code? (Section IX, QW-200, QW-300, QW-301)
a. A written procedure prepared in accordance with Section IX of the ASME Code to provide direction to the welder/welding operator while making production welds to Code requirements. It shall describe in detail all of the variables which are essential and non-essential to the welding processes employed in the procedure. b. Procedure qualification is the welding of test coupons in accordance with a written document known as a "Welding Procedure Specification." The coupons are then tested in accordance with Section IX of the ASME Code, and the welding data and test results are then recorded in a document known as a "Procedure Qualification Record." This documentation certifies that the procedure is capable of producing sound weldments in accordance with Section IX of the ASME Code. c. A performance qualification test is used to quality a welder, or welding operator, for each welding process to be used in production welding, in accordance with a qualified welding procedure specification. Performance qualification tests are intended to determine the ability of welders, and welding operators, to make sound welds. d. The manufacturer or contractor shall maintain a record of welding procedures and welders and welding operators employed by him showing the date and results of tests and the identification mark assigned to each welder. These records shall be certified to by the manufacturer or contractor and be accessible to the Authorized Inspector.
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22.
a. Who is responsible for conducting tests of welding procedures, welders and welding operators? (QW-103, QW-301.2) b. How long does a welder's qualification remain valid? (QW-322) c. Who maintains the qualification records of procedures, welders, and welding operators? (Section IX, QW-103.2) a. The manufacturer b. A welder's qualification remains in effect indefinitely except: 1. When he has not used the specific process for a period of six months or more. 2. When there is specific reason to question his ability to make welds that meet the specification. c. The manufacturer
23.
For welder qualification tests: a. Will passing test on pipe specimens quality welder on plate? b. Under what conditions may a welder be retested after one or more of his test specimens failed to meet requirements? c. How often should welders be required to make qualification tests? (Section IX, QW-303, QW-320, QW-322) a.
Qualification on pipe for any position shall qualify for plate for the same position. b. A welder who has failed the tests prescribed may be retested under the following conditions: 1. When an immediate retest is made, the welder shall make two consecutive tests welds for each position which he has failed, all of which shall pass the test requirements. 2. When the welder has had further training or practice, a complete retest shall be made for each position on which he failed to meet the requirements. c. Renewal of qualification of a performance specification is required: 1. When a welder has not used the specific, process for a period of six months. 2. When there is a specific reason to question his ability to make welds that meet the specification.
24.
Describe briefly the necessary steps in qualifying a welding procedure. (Section IX, QW-201) A welding procedure is qualified by making a weldment using a procedure which has been written in accordance with Section IX of the ASME Code. The weldment is then tested and evaluated in accordance with Section IX, and if the results are satisfactory, the procedure is "qualified".
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25.
a
Under what conditions has an Authorized Inspector the right to call for requalification of a welding procedure, a welding operator or welder?
b. Under what conditions may be Authorized Inspector require requalification of nondestructive examination procedures or personnel performing nondestructive examinations? (Section IX, Section V, T140) a. The inspector may request requalification when there is a specific reason to question the ability of the welding procedure, welding operator, or welder to produce sound welds. c. If there is a specific reason to question the procedure or the ability of personnel to perform the examination. 26.
What is a "backing strip" as used in metallic arc welding? It is a strip of metal usually of the same composition as the material being welded, and approximately 1/4" by 1" size. It is placed on the underside of the joint to be welded to enable the welder to obtain complete penetration throughout the entire thickness of the plate being welded.
27.
What is the purpose of a backing strip applied to a groove weld in plate or pipe? (Section IX, QW-492) It is used to enable the welder to obtain complete penetration through the entire thickness of the plate being welded from one side only.
28.
29.
Describe "Heat Affected Zone" and how can its effects be reduced? (Section VIII, UW-40; Section IX, QW-492) That portion of the base metal which has not been melted, but whose mechanical properties or microstructures have been altered by the heart of welding or cutting. Proper postweld heat treatment and control of heat input during the welding process can reduce the effects. What is meant by postweld heat treatment and how is it accomplished? (Section VIII, UW-40) Postweld heat treatment is the uniform heating of a structure or a portion thereof to a temperature sufficient to relieve the major portion of the residual stresses created by the welding process. The vessel is heated slowly to the temperature specified in Section VIII subsection C of the ASME Code and held for a specified time. The vessel is then allowed to cool slowly in a still atmosphere to a temperature not exceeding 800 degrees F. The vessel shall be postweld heat treated by any of the following methods: 1. 2.
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Heating the complete vessel as a unit. Heating sections of the vessel in which case, the heat treatment of the final girth joints shall be performed by heating uniformly a circumferential band having a specified width on each side of the welded joint in such a manner that the entire bank is brought up to the minimum holding temperature and held for the time specified.
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30.
What is meant by the terms "lack of fusion", "lack of penetration" and "slag inclusions"? How are they caused and how should such conditions be remedied? Lack of Fusion: The failure to fuse together adjacent layers of weld metal or weld metal and base metal. Causes: a. Improper current settings b. Improper welding technique c. Failure to prepare joint properly Remedies: a. Selection of proper welding current b. Deposit weld metal in such a manner as to insure good fusion between the plates; in weave welding be sure weave is wide enough to thoroughly melt the side of the joint. c. Ascertain that the surfaces to be welded are free of objectionable foreign material. Lack of Penetration: The failure of the filler metal and base metal to fuse integrally at the root of the weld. Causes: a. Inadequate joint preparation b. Insufficient welding current c. Too fast welding speed d. Electrode too large Remedies: a. Insure root opening and include angle of V-groove of proper dimensions; use of a backing strip. b. Increase welding current for proper fusion temperature. c. Selection of a slower welding speed. d. Proper selection of a welding electrode for the welding groove. Slag Inclusions: Non-metallic solids that are entrapped in the weld metal or between the weld metal and base metal. Causes: a. Stirring action of the arc which causes slag to be forced below the surface of the molten metal. b. Slag flowing ahead of the arc causing metal to be deposited over it. c. Improper joint preparation Remedies: a. Proper preparation of the groove to insure full penetration of the arc. b. Proper selection of electrode size. c. Preheat. d. High heat input.
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31.
When plate specification heat treatments are not performed by the mill, but by the fabricator, what additional steps must the fabricator do in regards to the mill plate markings? (Section VIII, UG-85) The heat treatments shall be performed by or under the control of the fabricator who shall then place the letter “T” following the letter "G" in the mill plate marking to indicate that the material specification heat treatments have been performed.
32.
The fabricator shall also show by a supplement to the appropriate mill test report that the specified heat treatment has been performed. a. How does a welder performing manual arc welding create an electric arc and maintain a circuit capable of melting a coated electrode and base metals together to form a welded joint? b. Name three arc welding processes. (Section IX, QW-492) a.
b.
33.
a. b. c. a.
b. c.
34.
The electric welding machine has a positive and negative cable. One is connected to the electrode holder and the other is attached to the part to be welded. When a welder touches the work, he completes an electrical circuit. When he pulls the electrode away slightly from the work the current continues to flow causing an arc to be made between the work and the rod. This arc is the source of heat which melts the base metal and filler metal, causing them to flow together. GMAW - Gas Metal Arc Welding a/k/a MIG GTAW - Gas Tungsten - Arc Welding a/k/a TIG SAW - Submerged Arc Welding FCAW - Flux Cored Arc Welding SMAW - Shielded Metal - Arc Welding a/k/a stick What is the basic difference between gas metal and gas tungsten arc welding processes? In submerged arc welding, what conducts the current between the electrode and the base metal? What is Shielded Metal Arc Welding? (Section IX, QW-492) The basic difference is that in gas metal arc welding a consumable electrode is used, and in gas tungsten arc welding a nonconsumable (tungsten) electrode is used. The flux in its molten state An arc welding process which produces coalescence of metals by heating them with an arc between a covered metal electrode and the work. Shielding is obtained from decomposition of the electrode covering. Pressure is not used and filler metal is obtained from the electrode.
What are two principal difficulties encountered in welding with heavily coated electrodes? Too much sidewall undercutting, slag inclusions, or excessive porosity.
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35.
What is a covered electrode? (Section IX, QW-492) A composite filler metal consisting of a core of bare electrode to which a covering sufficient to provide a slag layer on the weld metal has been applied. The covering may contain materials providing such functions as shielding from the atmosphere, deoxidization, and arc stabilization and can serve as a source of metallic additions to the weld.
36.
How must a welder identify the welding which he has performed in production and why is this necessary? (Section VIII, UW-37) The welder may stamp his mark adjacent to all welds made by him, or he may stamp adjacent to a continuous weld or series of similar joints made by him at intervals of not greater than 3 ft. or, in lieu of stamping, the manufacturer or contractor may keep a record of welded joints and the welders making the joints. Section VIII, ASME Code requires this identification of the welder.
37. Define distortion of a welded part and give two ways to control this distortion. During the welding operation stresses of high magnitude may result from thermal expansion and contraction, and remain in the weldment after the structure has cooled. Such stresses lend to cause distortion or warpage. Rigid fixtures and careful selection of welding sequence will minimize distortion. Peening, under controlled conditions, has also been used to reduce distortion. 38.
a. b.
What are "locked-in" stresses in a vessel and how are they caused? How are these stresses relieved? (Section VIII, UW-40)
a.
"Locked up stresses" are those internal stresses remaining in the weld metal and adjoining base metal when a weld has been made. They are caused by the fact that the weld metal and the base metal are of considerably different temperatures when the metal is made, and therefore do not expand and contract uniformly, thereby setting up internal stresses. b. Proper Postweld Heat Treatment 39. How should welded butt joints in a vessel be prepared for radiography? (Section V, T222.2 UW-35) The weld ripples or surface irregularities on both the inside (if accessible) and outside shall be removed by any suitable process to such a degree that the resulting radiographic image due to any irregularities cannot mask or be confused with the image of any discontinuity. 40.
Is it permissible to locate an opening in a shell or head, (such as a manway, nozzle, etc.) across a welded longitudinal or circumferential joint? (Section VIII, UG-37, UW-14) Yes, provided the opening meets the requirements for compensation.
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41.
a. b.
a.
What is the maximum allowable alignment tolerance or offset permitted at the welded longitudinal joint, using plates up to 2" thick? How should joints between plates of unequal thickness be prepared? (Section VIII, UW-9, UW-33) The maximum allowable alignment tolerance for welded longitudinal joints in Section VIII vessels is as follows:
Section Thickness, in. Up to 1/2 in., incl. Over 1/2 in. - 3/4 in., incl. Over 3/4 in.- 1 1/2 in., incl. Over 1 1/2 in.- 2 in., incl. Over 2 in. the lesser of Tolerance
Tolerance 1/4 t 1/8 in. 1/8 in. 1/8 in. 1/16 t or 3/8 in.
t = nominal thickness of the thinner section at the joint. b.
42.
Plates of different thickness’ by more than one fourth of the thickness of the thinner plate, or by more than 1/8" required a tapered transition section having a length not less than three times the offset between the adjoining surfaces.
Describe briefly the nature and extent of qualification tests of welders who are to be employed in the fabrication of boilers and pressure vessels.(Section IX, QW-300, QW452) Welders must qualify by welding a test specimen using a procedure which has been written in accordance with Section IX of the ASME Code. The test specimen is tested and evaluated in accordance with Section IX, and if the results are satisfactory, the welder is "qualified" under that particular welding procedure specification.
43.
a. b.
a.
b.
44.
What is the difference between a transverse face bend test and a transverse root bend test, in procedure or performance qualification tests of welding? Are tension tests required for qualification of 1. A welding procedure? 2. A manual welder? (Section IX, QW-161, QW-451, QW-452) A face bend applies to a test specimen which is bent so that the face of the weld becomes the convex surface of the bent specimen. A root bend applies to a specimen which is bent so that the root of the weld becomes the convex surface of the bent specimen. 1. Yes 2. No
What steps are necessary to qualify a welder for all position pipe welding? (Section IX, QW-303, QW-461.9) He must qualify in the fixed horizontal (2G) and the fixed vertical (5G), or the multiple position (6G).
45.
What are the two methods of guided-bend tests permitted by the Code? (Section IX, QW-162, QW-466) a. Bottom ejection method. b. Wrap around method.
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46.
List the various positions in which a welder may qualify for groove welds and describe each. (Section IX, QW-120) Plate Positions 1. Flat position (1G): Plate in a horizontal plane with the weld metal deposited from above. 2. Horizontal position (2G): Plate in a vertical plane with the axis of the weld horizontal. 3. Vertical position (3G): Plate in a vertical plane with the axis of the weld vertical. 4. Overhead position (4G): Plate in a horizontal plane with weld metal deposited from underneath. Pipe Positions 1. Position - 1G: Pipe with its axis horizontal and rolled during welding so that the weld metal is deposited from above. 2. Position - 2G: Pipe with its axis vertical and the axis of the weld in a horizontal plane. The pipe shall not be rotated during welding. 3. Position - 5G: Pipe with its axis horizontal and with the welding groove in a vertical plane. Welding shall be done without rotating the pipe. 4. Position - 6G: Pipe with its axis inclined at 45 degrees to the horizontal. Welding shall be done without rotating the pipe.
47.
In what position must the test plates be when a welder makes his test welds? (Section IX, QW-303)
Generally, the test plates should be in whatever position the welder will encounter in actual work. But, it is possible to qualify in one position and perform production work in other positions. For instance, for groove welds: a. Qualification in the 2G position shall also qualify for the 1G position. b. Qualification in the 5G position shall qualify for the 1G and 2G positions. c. Qualification in both the 2G and 5G positions or in the 6G position shall qualify for all positions. 48. What tests are required for examination of welds made for qualification of a welding procedure? (Section IX, QW-202, QW-451) Tension and transverse bend tests are required as followsa. Test plate thickness’ less than 3/8", two reduced section tension tests, two face bend tests and two root bend tests required. For thickness’ over 3/8" but less than 3/4", four side bend tests may be substituted for the face and root bend tests. b. Plate thickness 3/4" and over, two reduced section tension tests and four side bend tests are required.
49.
What are the type and number of tests required for Performance Qualification? (Section IX, QW-452 (note 7)) The following guided bend tests are required for performance qualification on plate. a. For test plate thickness less than 3/8", one face bend and one root bend are required. For thickness over 3/8" but less then 3/4", two side bend tests may be substituted for the required face and root bend tests. b. For test plate thickness’ 3/4" and over, two side bend tests are required.
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50.
What is an essential variable on a welding procedure specification?(Section IX, QW251.2) Essential variables are those in which a change, as described in the specific variables, is considered to affect the mechanical properties of the weldment, and shall require requalification of the welding procedure specification or the welder. The variables are listed in Section IX of the ASME Code.
51.
What is a nonessential variable on a welding procedure? (Section IX, QW-251.3) Nonessential variables are those in which a change, as described in the specific variables, may be made in the welding procedure specification without requalification.
52.
Name a defect that would cause you to reject a welder's test plate.(Section IX, QW163) Open defects exceeding 1/8" in the guided bend specimen.
53.
Who is responsible for conducting tests of welding procedures and for qualifying welding operators? (Section IX, QW-103) Each manufacturer or contractor is responsible for the welding and qualification tests done by his organization.
54.
Is a welding procedure qualified under the 1965 ASME Code Section IX still applicable? Why or why not? (QW-100.3) Yes. Procedure and performance qualifications made in accordance with the requirements of the 1962, or any later Edition of Section IX may be used in any construction.
55.
What is a fillet weld? (Section IX, QW-492) A weld of approximately triangular cross-section joining two surfaces approximately at right angles to each other in a lap joint, tee joint or corner joint.
56.
What is the throat of a weld? (Section IX, QW-492) The throat is the shortest distance from the root of a fillet weld to its face.
57.
What is porosity as used in welding? Porosity is the result of gases, produced during the welding process, being entrapped within the molten metal.
58.
What is the axis of a weld? (Section IX, QW-461) A line through the center of the weld, parallel to the sides of the weld.
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59.
a. b.
What is the maximum length of slag inclusion allowed in a welded seam, as seen on the radiograph for any thickness of plate? (App 12 Sect VIII) What is the maximum length of crack for the same plate thickness? (Section VIII, App 12)
a.
The maximum length of slag allowed in a welded seam is: ¼” for t up to ¾” 1/3t for t from 3/4" to 2 1/4" 3/4" for t over 2 1/4" Where t is the thickness of the weld. b. No crack, regardless of size, is allowed. 60.
How long must a set of radiographs be kept on file for a pressure vessel? (Section VIII, UW-51 (a)(1)) A complete set of radiographs and records for each vessel or part must be retained by the manufacturer until the data report is signed by the inspector.
61.
Should a qualified welder for one certificate holder be allowed to weld for another certificate holder? (Section VIII, QW-29 (e)) No. The performance qualification test for welders and welding operators conducted by one certificate holder shall not qualify a welder or welding operator to do work for any other certificate holder.
62.
Are welding operators who are to weld on ASME boiler and pressure vessels certified? No. The welding operators are not certified by anyone under the requirements of the ASME Code. The manufacturer certifies that the welding has been done by operators who have passed the required test, and that the same material and techniques were used in the tests as were employed in fabricating the boiler or vessel.
63.
Explain the difference between a guided bend test and a free bend test. A guided bend test is made by the use of a combination male and female jig in which the test specimen is "guided" to its Final U shape. In a free bend test the pressure is applied to the ends of the specimen, and the test specimen is allowed to bend freely at the weld line. Both tests are used to check ductility of the weld material.
64.
What is fusion welding? A group of processes in which metals are welded together by bringing them to the molten state at the surfaces to be joined, with or without the addition of filler metal, without the application of mechanical pressure or blows.
65.
In metallic welding, what is meant by the terms "weaving" and "beading"? The electrode is directed from side to side in the welding groove when depositing weld metal by "weaving”, and in a straight line when deposited metal by "beading".
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66.
In performance qualification of pipe groove welds to ASME Section IX, which position requires more than two guided bend specimens for qualification? (Section IX, QW-452 (note 4)) 5G and 6G
67.
What precautions are made before joining together by a butt weld a 7/8" head flange with a ½” shell plate? Why are these precautions necessary? (Section VIII, UW-9) A tapered transition section having a 1ength not less than three times the offset between the adjoining surfaces shall be provided. The transition section may be formed by any process that will provide a uniform taper. The weld may be partly or entirely in the tapered section or adjacent to it. The transition section is necessary to reduce the stress concentrations at the joint.
68.
What is the maximum reinforcement allowed on a welded seam? (Section VIII, UW35) Maximum Reinforcement, in inches Nominal Thickness, in Pipe and Tubing Less than 3/32 Over 3/32 to 3/16, incl. Over 3/16 to 1/2, incl. Over 1/2 to 1, incl. Over 1 to 2, incl. Over 2 to 3, incl. Over 3 to 4, incl. Over 4 to 5, incl. Over 5 5/16"
69.
Circumferential Joints 3/32 1/8 5/32 3/16 3/16 1/4 1/4 1/4
Other Welds 1/32 1/16 3/32 3/32 1/8 5/32 7/32 1/4 5/16
A welder may qualify for fillet welding of any diameter by taking a plate groove weld test in what position as a minimum? (Section IX, QW-303) Welders and welding operators who pass the required tests for groove welds in the test positions of QW-461.9 shall be qualified for the positions of the groove welds and fillet welds shown in QW-461.9. In addition, welders and welding operators who pass the required tests for groove welds shall also be qualified to make fillet welds in all thickness’ and pipe diameters of any size within the limits of the welding variables of QW-350 or QW-360, as applicable.
70.
Who certifies welding performed on vessels fabricated under Section VIII of the ASME Pressure Vessel Code? (Section VIII, UW-26) Each manufacturer (certificate of authorization holder) is responsible for the welding done by his organization and, shall establish the procedures and conduct the tests required in Section IX to qualify the welding procedures he uses in the construction of the weldments built under Section VIII and the performance tests of welders who apply these procedures.
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71.
A welder has been tested in the 6G position, using an E-7018 F4 electrode, on 6" schedule 160 (.718" nom.) SA-106B pipe. Is this welder qualified to weld a 2” 300# ANSI schedule 80 bore flange to a 2" schedule 60 SA-106B nozzle neck? Explain your answer. (Section IX, QW-452.3) No. Qualification in a pipe position in a diameter greater than 2 7/8" nominal only qualifies for groove and fillet welds in pipe 2 7/8" diameter and over.
72.
73.
You are reviewing a WPQ (QW-484) for a welder testing in the 6G position on SA-53 grade B pipe (TS 60,000 psi). The test results indicate the following: 1. 2.
Tensile developed 61,000 psi, broke in the weld. Tensile developed 66,000 psi, broke in base metal.
1. 2.
Transverse root bend satisfactory. Transverse face bend satisfactory.
a. b.
Would the test be acceptable? Explain your answer. (Section IX, QW-452.1, QW-302.3)
a. b.
No The performance qualification on the 6G position required 4 transverse bend tests, 2 root and 2 face or 4 side bends. The tension tests, while satisfactory, are not required.
For ASME welders' qualification tests: a.
b.
Will qualification on pipe for all positions also qualify the welder to weld all positions on plate? How may a welder who fails on one or more test specimens be retested immediately? (Section IX, QW-303, QW-318)
a.
Qualification on pipe for any position shall qualify for plate for the same position.
b.
When an immediate retest is made, the welder shall make two consecutive test welds for each position which he failed, and both of which shall pass the test requirements.
74.
A welding electrode has the marking F-6010. Explain what each letter and number represents. “E” Electrode “60” The minimum specified tensile strength / 1,000 “1” The recommended position and coating “0” Type of coating and recommended current
75.
A welder qualified by welding in the 5G position is also qualified for what other positions? (Section IX, QW-469.1) Qualification in the 5G position shall also qualify the welder in the I1G and 2G positions.
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PREVIOUS NBIC QUESTIONS ON NDE 1.
Section VIII, Division 1 magnetic particle nondestructive examination personnel shall be qualified in accordance with which of the following? a. b. c. d. e.
2.
Section VIII, Division 1 (Appendix) standards Section IX SNT-TC-1A-1980 ASME Code Section V SNT-TC-1A as a guide (Appendix 6, Paragraph 6)
When performing radiography in accordance with Section VIII, Division 1, must a written procedure be used? (Section VIII, UW-51) No
3.
Must manufacturer's personnel who inspect to Section VIII, Division 1 be qualified to Section V, Article 9 visual standards? (Sect V Art 9 & T-910) No
4.
Must a Section VIII, Division 1 Liquid Penetrant examination be performed using a written procedure? (Sect VIII Appendix 8) Yes
5.
Must the AI physically witness a Section VIII NDE procedure being qualified? Explain. No, but the manufacturer must satisfy the Inspector that it will work as intended.
6.
When subcontracting a nondestructive examination, which of the following lids the responsibility for assuring the acceptance criteria are met? (Sect V, T-150) a. b. c. d.
7.
Certificate Holder Inspector Level III Examiner Both a and b
Is Type 1 film the only one that can be used for radiographs that are to be in compliance with Section V? No
8.
In accordance with Section V, which is a true statement in regards to intensifying screens? (Sect V, T-232) a. Can always be used. b. Can be used unless restricted by the referencing Code. c. Can never be used. d. Can be used only with Type 1 film.
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9.
A single film technique was used to make a radiograph using a Cobalt-60 source. Which of the following is the minimum permitted density in the area of interest?(Section V, T-282.1) a. b. c. d.
10.
A radiograph is made using an X-ray source, and two films in each film holder. If the film is to be viewed, separately which of the following is the minimum permitted density? a. b. c. d.
11.
4.0 1.8 2.0 1.3
11.0 1.8(Section V, T-282.1) 2.0 1.3
When reviewing a radiograph, a dark image of the letter B can be seen on the film. Does this indicate an unacceptable radiograph? (Section V, T-284) No
12.
Which of the following is a device used to determine the image quality of a radiograph? (Sect V, T-233) a. b. c. d.
A step wedge comparison film. A densitometer A penetrameter All of the above.
13. A weld with a nominal thickness of 1.5 inch is to be radiographed using a film side penetrameter. The penetrameter designation should be which of the following? (Sect V Table T-276) a. b. c. 14.
25 30 35
Describe nondestructive examination of a welded joint and give three examples. (Section V, T110) An examination of a welded joint that will disclose surface and sub-surface discontinuities without physical harm to the welded joint. Such examinations can be conducted by radiography, ultrasonics, liquid penetrant or magnetic particle testing.
15.
What type of flaws can be detected by each of the following nondestructive methods? a. b. c. d.
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Surface discontinuities Surface and slight sub-surface discontinuities Surface and subsurface discontinuities Surface and sub-surface discontinuities Page 293 of 310
16.
Describe how a liquid penetrant examination should be performed in order to detect discontinuities which are open to the surface, per Article 6 of ASME Code Section V. (Section V-T600) The part is first thoroughly cleaned of oil, dirt, etc., then a liquid penetrant is applied to the surface to be examined and allowed to enter the discontinuities. All excess penetrant is then removed, the part is dried, and a developer is applied. The developer functions both as a blotter to absorb penetrant that has been trapped in discontinuities and as a contrasting background to enhance the visibility of penetrant indications. The dyes in penetrants are either color contrast (visible under white light) or fluorescent (visible under ultraviolet light).
17.
In magnetic particle examination of a welded joint, is alternating current or direct current normally used? Why? Direct current is normally used because it produces a field that penetrates deeper throughout the part it is more sensitive than alternating current for the detection of subsurface discontinuities.
18.
Which of the following is employed in magnetic particle examination? a. b. c. d.
19.
High voltage, low amperage High amperage, high voltage High amperage, low voltage Low voltage, low amperage
What is the advantage of dry type over wet type magnetic particle examination? Dry type magnetic particle examination will give a better indication of sub-surface discontinuities and the equipment is more portable.
20.
What is the difference between X-ray and gamma-ray radiography? X-rays are high energy rays produced by a machine. Gamma rays are energy emitted from radioactive isotopes by the process of decay. Other than the method by which they are produced and their wavelength, which is dependent on the energy level that produces them, there is no basic difference between the two. The energy level of Xrays may be varied or selected within the rating of the equipment, whereas the energy level of gamma rays is fixed and cannot be varied.
21.
22.
Give a brief description of the X-ray technique used in the inspection of welded joints in shells. (Section VIII, UW-51(a)(3), Section V T-283) All welded joints to be radiographed shall be by the X-ray or gamma-ray method in accordance with Article 2 of Section V of the Code. The radiographic examination shall be performed with a technique of sufficient sensitivity to display the penetrameter image and the specified hole. Describe the general shape of gas cavities on a radiograph and tell if these areas would be lighter or darker in contrast with areas of defect-free material? a. b.
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23.
24.
In a radiographic film of a vessel weld, how are the following characteristics measured or judged? (Section V, T282, T283) a. b.
Film sensitivity or quality Film density
a. b.
Penetrameter Densitometers or step-wedge comparison films
What are penetrameters and what are they used for? (Section V, T233, T262) A penetrameter is a small strip of material, fabricated or radiographically similar material to the object being inspected, and having a thickness of approximately 2% of the object being radiographed. The penetrameter has three holes in it. The sizes of these holes are 1T, 2T and 4T where “T” is the thickness of the penetrameter. The 2T is designated as the essential hole, i.e., the hole whose image must appear on the radiograph. Penetrameter thickness and essential hole size requirements are listed in tables in Section V of the ASME Code. The penetrameter is identified with a number made of lead, which is attached to the penetrameter. This number indicates the thickness of the penetrameter in thousandths of an inch. A penetrameter is used for evaluating radiographic technique in that it serves as an image quality indicator; proper technique should display the penetrameter image and the specified hole.
25.
From what type of material should shims be fabricated when they are to be used to radiograph welds in pressure vessels? (Section V, T277.3) A shim shall be fabricated of radiographically similar material to the object to be inspected.
26.
a. b.
If penetrameters are not placed adjacent to the welds, what rules apply? For materials being radiographed other than welds, where is the penetrameter placed? (Section V, T-277)
a.
The penetrameter should be placed on the source side of the material being radiographed. However, where inaccessibility prevents this, the penetrameter may be placed on the film side of the material being radiographed provided a lead letter "F" at least as high as the identification number is placed adjacent to the penetrameter. For material other than weld, a source side penetrameter shall be placed in the area of interest.
b.
27.
Under ASME Code Section VIII, what are the upper and lower densities acceptable for viewing if the density through the body of the penetrameter is 2.7? Assume single film viewing. (Section VIII, T-282.2) -15% = 2.295 +30% = 3.510
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28.
a. In radiography a butt welded joint of 1” thickness, on what side of the weld is the penetrameter normally placed? (Section V, T-277.1 (a), (b)) b. If found to be impractical to use the penetrameter in its normal position, what compensation must be made in penetrameter thickness for use on the opposite side of the object to be radiographed? c. What identification is required to indicate that a penetrameter is used in other than its normal location or side? a.
b. c.
29.
Give two ways radiography fails to give complete inspection information, even though properly performed. a. b.
30.
The penetrameter should be placed on the source side of the material being radiographed. However, where inaccessibility prevents this, the penetrameter may be placed on the film side of the material being radiographed. In accordance with Section V Table T-276, the next smaller penetrameter would be used. In lead letter “F” at least as high as the identification number shall be placed adjacent to the penetrameter.
Very tight cracks and/or discontinuities which are less than 2% of the material thickness may not be detected by radiographic methods. Radiography may not detect discontinuities that are perpendicular to the lines of radiation (laminar type discontinuities).
What is a radiograph? A radiograph is a shadow picture produced by the passage of X-rays or gamma rays through an object onto a film. When the rays pass through the object, part of the radiation penetrates the material and part is absorbed. The amount of radiation absorbed and the amount which penetrates are a function of the thickness of the material. Where a void or discontinuity exists, there is essentially less material to absorb the radiation. Therefore, more radiation will pass through this section and a dark spot corresponding to the projected position of the void will appear on the film.
31.
Name two radiation sources permitted for radiographic examination in the ASME Boiler and Pressure Vessel Code. (Section V, T-272) The two common radiographic sources in industrial use today are X-ray machines and artificially produced radioactive isotopes certain metallic elements.
32.
For Section VIII vessels, to what guidelines are UT requirements for examination of welds performed? (Section VIII, UW-53) Appendix l2 and Section V, Article 5
33.
Who has the responsibility of preparing an ultrasonic examination report? (Section VIII, Appendix 12) The manufacturer
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34.
How shall procedure requirements for ultrasonic examination of welds be performed? (Section V, T-150) Procedure requirements for ultrasonic examinations shall be performed to a written procedure which has been proven to the satisfaction of the Inspector.
35.
on a radiograph? (Section V, T-223, T-284) missing part of question. A check on back scattered radiation, a lead symbol “B” with minimum dimensions of ½” height and 1/16” thickness shall be attached to the back of each film holder. If a light image of the "B" appears on a darker background of the radiograph, protection from back scatter is insufficient and the radiograph shall be considered unacceptable. A dark image on a lighter background is not cause for rejection.
36.
What is a densitometer used to determine? (Section V, T-225, T-234, T-262) A densitometer (or step wedge comparison film) shall be used for judging film density requirements. Film density is a measure of overall readability.
37.
As a radiographer is removing cassettes (film holders) from a weld seam that has just been radiographed, you notice that there is nothing attached to the back of the cassettes. Would these radiographs be acceptable Explain your answer. (Section V, T-223, T-284) No, as a check on back-scattered radiation, a lead symbol "B" with minimum dimensions of ½” height and 1/16” thickness shall be attached to the back of each film holder. If a light image of the "B" appears on a darker background of the radiograph, protection from backscatter is insufficient and the radiograph shall be considered unacceptable. A dark image on a lighter background is not cause for rejection.
38.
Give two types of lighting for visual inspecting that can be safely used in a confined space. (NBIC) Low voltage lighting; either a battery powered flashlight or extension lights powered by isolation transformers at no more than 12 volts.
39.
How are ASME Code requirements for ultrasonic examination of welds properly transmitted to individuals performing the examination? (Section V, T-150) By the applicable procedure specification
40.
What does the Piezo material in the search unit do in the Ultrasonic testing method? Most transducers consist of a small piezoelectric element, which have the capability of converting the electrical signal generated in the test instrument into mechanical vibrations (or ultrasound). These elements act reversibly on echo signals.
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41.
a. Does Article 2 of Section V normally require penetrameters to be placed on the source side or the film side? b. For welds, does Section V permit penetrameter placement on the weld, adjacent to the weld, or both? c. Under what conditions may penetrameter identification numbers be placed in the area of interest? (Section V, T-277) a.
b. c.
42.
The penetrameter(s) shall be placed on the source side of the part being examined, except where inaccessibility prevents hand placing the penetrameter(s) on the source side, it shall be placed on the film side in contact with the part being examined. The penetrameter(s) may be placed adjacent to or on the weld. For materials other than welds, the penetrameter(s) with penetrameter identification may be placed in the area of interest.
List three items that may be requirements of the referencing Code Section or Section V, Artic1e 5, when Ultrasonic Examination is a requirement of the code. (Section V, T.521) Article 1, General Requirements, and Appendix A, Glossary of Terms used in Nondestructive Examination, apply when the use of this Article is required by a referencing Code section.
43.
Name three different methods of conducting "Visual Examinations” (VT). (Section V, T-940, T-942, T-943) a. b. c.
44.
45.
46.
Direct Indirect (or remote visual examination) Translucent
What purpose do lead intensifying screens serve in the X-ray examination process? (Section V, Article 22-9.1, SE-94) Lead foil intensifying screens used in the X-ray examination may be placed directly in front of the film. The screen provides an intensifying action and, in addition, the back one acts as a filter by preferentially absorbing back scattered radiation from the specimen thus improving image quality. What is the minimum allowable density through the image of the penetrameter for radiographs made with: a. A 2000 kv tube? b. Cobalt 60? (Section V, T-282.1) a. b. a. b. c.
1.8 - 4.0 (for any X-ray source) 2.0 - 4.0 (for any gamma ray source – anything besides a tube) What is the purpose of shims when performing radiography? Where are they placed? What kind of material may they be made from? (Section V, T-277.3)
a.
Shims may be used when necessary to produce a radiograph in which the radiographic density throughout the area of interest in no more than minus 15% from (lighter than) the radiographic density through the penetrameter. They are placed under the penetrameter. A radiographically similar material to that being examined.
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47.
On a set of cassettes containing film for a seam just radiographed, you notice the lead location markers (i.e., 1 to 2, 2 to 3, etc.) are taped to the cassettes. Would these radiographs be acceptable? (Section V, T-275, Article 22-15.2) No. Location markers that are to appear on the radiographic film should be placed on the part being examined and not on the cassettes.
48.
Name the four main factors governing the penetrating ability of an X-ray. a. b. c. d.
49.
50.
What is the minimum number of penetrameters required for the following? a. A complete girth seam containing 30 radiographs shot with a single exposure? b. Twelve radiographs on a longitudinal seam shot from the outside with a single exposure? (T-277.2(a)(1)) a. c.
Requires 3 spaced 120 degrees apart. Requires 12
a.
If the density through the penetrameter is 2.50, what would the maximum allowable density and minimum allowable be through the weld represented by this penny? If the density through the weld (area of interest) is uniform and measures 2.5, what is the maximum and minimum allowable density through the penetrameter? (Section V, T-282)
b.
a.
b.
51.
Energy level (kv) Material type Density of material Distance from material
Minus 15% to plus 30% allowed. 2.5 + 30% = 2.5 + .75 = 3.25 2.5 - 15% = 2.5 - .4 = 2.125 2.5 / 1.3 = 1.92 2.5 / .85 = 2.94
Describe how the following surfaces shall be prepared for Ultrasonic Examination. a. Contact surfaces b. Weld surfaces c. Base material (Section V, T-534) a.
b.
c.
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The finished contact surfaces shall be free from weld splatter and any roughness that would interfere with free movement of the search unit or impair the transmission of ultrasonic vibrations The weld surfaces shall be finished so they cannot mask or be confused with reflections from defects, and should merge smoothly into the surfaces of the adjacent base materials. The volume of base material through which the sound will travel in angle beam examination shall be completely scanned with a straight beam search unit to detect reflectors which might affect interpretation of' angle beam results.
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52.
What method of Ultrasonic Examination of welds is permitted by the Code? (Section V, T-531) Pulse-echo type
PREVIOUS NBIC QUESTIONS ON FABRICATION 1.
What is the maximum elongated slag inclusion acceptance criteria for 100% radiography of Section VIII, Division 1 vessels? The vessel is 1 inch thick carbon steel. (Section VIII, UW-51) 1/3(t); t = 1” Therefore, 1/3"
2.
When reviewing PWHT charts, name 4 items you would review to verify compliance with Section VIII, Division 1 heat treating requirements. The material is carbon steel material P-1. (Section VIII, UCS-56; Appendix 10-11) a. Heat up rate b. Time at temperature c. Cool down rate d. Calibration records e. PWHT records and signoffs
3.
Distinguish between witnessing and verifying a nondestructive examination. "Witnessing" - to observe the operation. "Verify" - review of records verify completion of an operation.
4.
A vessel designed for 1000 psi is to be hydrostatically tested at l500 psi. Is the inspector required to examine the vessel for defects at 1500 psi? (Section VIII, UG99g) NO. Vessel should never be examined at test pressure.
5.
6.
May a 1250 psi pneumatic test be substituted for a 1500 psi hydrostatic test if it is shown that the testing liquid weight, in the vessel, will be unsafe for the vessel design? (Design pressure is 1000 psi). (Section VIII, UG-100b) Yes Where are the QC program requirements described in Section VIII, Divisions 1? Appendix 10
7.
When fu11y radiographing a longitudinal seam in a vessel, must the weld always be ground flush (no weld reinforcement) for Section VIII, Division 1? An efficiency of 1.0 wi11 be used. (Section VIII, UW-35) No
8.
What is the acceptable maximum reinforcement Section VIII, Division 1 permits on each side of a 1 inch thick circumferential weld? (Section VIII, Table UW-35) 3/16"
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9.
Abutting edges of a circumferential head-to-shell seam in a vessel are misaligned by 3/8 inch. The shell is 2 1/4 inch thick. Corrosion allowance is 0.375 inches. Heads are F and D type. Is this fit-up within the Code permitted limits? (Show any calculations) (Section VIII, Table UW-33) No. Lesser of 1/8(t) or 3/4": 2.25/8 = .280; 3/8" greater than .280, therefore, do not accept.
10.
A vessel has a partial penetration, double "v" butt joint for a Category B joint. Shop drawings indicate the vessel wall is 2 inches thick. The measured reinforcement of the finished weld is found to be 1/8” on each face. Does this vessel comply with Section VIII, Division 1 requirements? (Section VIII, UW-35) No - must he full penetration.
11.
Must a vessel fabricated by welding 1 3/8 inch thick SA-335, grade P7 (5CR - 1/2 Mo alloy) material be fully radiographed? (Section VIII, UCS-57) Yes - P-5 material.
12.
A seamless shel1 (1 course) with two seamless elliptical heads are combined to form a vessel. No radiography is performed. The attaching welds are all Type 2. The vessel is constructed to the requirements of Section VIII, Division 1. What joint efficiency/quality factor must be used in the head and shell calculations (assume circumferential stress governs). (Section VIII, UW-12d) Head = .85 Shell = .85
13.
14.
A steam separator is fabricated from SA-53 seamless pipe, 3/16” inch thick. What if any, corrosion allowance is required as a minimum? (Section VIII, UG-25 & UCS-25) 1/16" A vessel data report has a specified corrosion allowance of ¼ inch. Does the Code require that, “means to drain the vessel be provided"? (Section VIII, UG-25) Yes
15.
A vessel manufacturer wants to install a 3 inch diameter nozzle through a vessel wall. The nozzle will be welded from the outside only using a full penetration weld. Is this permitted if no fillet weld is used on the outside? (Section VIII, Figure UW-16.2) No
16.
A carbon steel vessel is designated for lethal service. Is full radiography and postweld heat treatment required? (Section VIII, UW-2(a)) Yes, for CS and LA steels.
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17.
May non-pressure attachments be welded to the pressure boundary of a vessel after hydrostatic testing? Assume a new hydrostatic test will not be performed prior to stamping with the “U”. (UG-99) No welding after hydro
18.
Must an entire vessel satisfy UG-20 (f) in order to take the exemption for impact testing per UG-84? No, UG-20 (f) applies to vessel materials. Materials which cannot be exempted per UG-20 (f), must be checked per UCS-66.
19.
Can the design temperature go below -20 degrees F when applying the UG-20 (f) exemption? Yes, per UG-20 (f) (3) occasional temperature excursions below -20 degrees F due to seasonal weather changes are allowed.
20.
Can UG-20 (f) be used to exempt ERW pipe from impact? Yes. All product from pipe is considered Curve B material. Thus, if the governing thickness is less than 1" thick, the pipe is exempted from impacts.
21.
What is the maximum permissible distortion in the diameter of a cylindrical shell? (Section VIII, UG-81) The cylinder of a shel1 shall be circular at any section within a limit of 1% of the mean diameter.
22.
In the designing of a pressure vessel, what is meant by the term "inherent compensation" and where would this term be used in your calculations? (Section VIII, UG-36(c)(3)) "Inherent compensation" is reinforcement built-into the shell, heads, or nozzles through design. This built-in reinforcement is provided by additional thickness over and above the thickness required to resist pressure.
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PREVIOUS NBIC QUESTIONS ON HYDROSTATIC TESTING 1.
a. b. c.
a. b. c.
2.
On a pressure vessel of welded steel construction, why is the hydrostatic test limited to 1.5 times the maximum allowable working pressure? What is the purpose of this test? List the steps in carrying out a hydrostatic test on a 150 psi vessel. (Section VIII, UG-99) To prevent damage to the vessel as a result of exceeding the yield point of the material. Discloses leaks and gross errors in design. 1. Calculate hydrostatic test pressure (1.5 x 150 = 225 psi) 2. Blank off or properly gag the safety valve(s) (if applicable) 3. Fill with water at ambient temperature. Metal temperature shall be at least 30 degrees above minimum design metal temperature. (Vessel is vented of air) 4. Prior to the hydrostatic test, the test gauge shall be checked to see that it is calibrated correctly and functioning properly. 5. Warn all personnel in the area to stand clear. 6. Raise the pressure gradually to 1 1/2 times the maximum allowable working pressure as shown on the data report to be stamped on the boiler. The pressure shall be under control at all times. 7. Allow the hydrostatic test pressure to remain on the vessel for an appreciable length of time. Close visual inspection for leakage is not required at this time. 8. If-no pressure drop, reduce the pressure to the maximum allowable working pressure, and after a sufficient amount of time has lapsed, inspect the seams, nozzles, etc., for leakage. 9. Drain the vessel and open for an internal inspection for possible damaged parts.
What is a hydrostatic or pressure test and why is it used? The purpose of the hydrostatic test is to see that all welds, joints, and tube connections are tight and if there are gross errors in design. It is not a proof test. The hydrostatic test is also used on new construction, when repairs are made, or to determine the exact source of leakage or defect suspected in some part of the vessel.
3.
When the construction of a pressure vessel has been completed, should the hydrostatic test be applied with no regard to water temperature? What are the rules concerning temperature? (Section VIII, UG-99) Any non-hazardous liquid at any temperature may be used if below its boiling point. It is recommended that metal temperature be maintained at least 30 degrees F above the minimum design metal temperature. Test pressure shall not be applied until the vessel and contents are about the same temperature.
4.
When conducting a pressure test as part of a periodic inspection, what shall the shell temperature be during the test? (API-510 4.4) Shell temperature shall not be less than that recommended by the applicable section of the ASME Code or 70 degrees F and not more than 120 degrees F.
5.
a.
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b.
What is the maximum that the hydrostatic test pressure may be exceeded? (Section VIII, UG-99)
a.
Minimum of 70 degrees F maximum during close examination 120 degrees F (metal temperature) The pressure shall be under control at all times so that required test pressure is never exceeded by more than 6%, 29- for existing installations.
b.
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PART D - PROPERTIES Table 1A NOTES TO TABLE 1A (CONT'D) (B)
Section III Application (Cont'd)
B3:
I-8.1 (Cont'd)
(3)
These stress values include a 0.92 factor applied to structural plate quality and are based on 55.0 ksi maximum ultimate tensile strength. (4) For external pressure chart references, see Tables I.14.0. (5) Minimum thickness after forming any section subject to pressure shall be 3/16 in, (6) Nonwelded (7) Welded. (8) Not permitted for service temperature below –275 F. (9) Thickness over 0.580 in. through 0.750 in. (10) Thickness over 0.375 in. through 0.580 in. (11) Thickness 0.375 in. and less. (12) Material that conforms to Class 10, 13, 20, 23, 30, 33, 40, 43, 50, or 53 is not permitted when a weld efficiency factor of 1 00 is used in accordance with Note (3) above. (13) Material that conforms to Class 11 or 12 is not permitted.
B4: I-12.1
(1) (2) (3) (4) (C)
NOTES: Until rules for welding this material can be added to Section III, this material is not for welded construction. The following are the abbreviations used for product forms: (a) Wld.-Welded; (b) Smls.- Seamless. For the maximum thickness permitted by the material specification or 2 1/2, in-, whichever is less. For thickness’ greater than 2 1/2, in., but not to exceed the maximum thickness permitted by the material specification. Section VIII, Division 1 Application C1: UCS-23
(a) (b) (c) (d)
GENERAL NOTES: The stress values in this Table may be interpolated to determine values for intermediate temperatures. Stress values in restricted shear such as dowel bolts or similar construction in which the shearing member is so restricted that the section under consideration would fail without reduction of area shall be 0.80 times the values in the above Table. Stress values in bearing shall be 1.60 times the values in the above Table. Stress values may be for 100 F and lower if considerations are given to toughness requirements.
NOTES: See UCS-6 (b). These stress values are one-fourth the specified minimum tensile strength multiplied by a quality factor of 0.92, except for SA-283, Grade D, and SA-36. (3) See Part UCS, Nonmandatory Appendix CS. (4) Only killed steel shall be used above 850 F. (5) To these stress values a quality factor as specified in UG-24 shall be applied for castings. (6) These stress values apply to normalized and drawn material only. (7) These stress values are established from a consideration of strength only and will be satisfactory for average service. For bolted joints, where freedom from leakage over a long period of time without retightening is required, lower stress values may be necessary as determined from the relative flexibility of the flange and bolts, and corresponding relaxation properties. (8) Not permitted above 450 F; allowable stress value 7000 psi. (9) Between temperatures of 750 F and 1000 F, inclusive, the stress values for SA-515, Grade 70 may be used until high temperature test data become available. (10)... (11) For temperatures below 400 F, stress values equal to 20% of the specified minimum tensile strength will be permitted. (12) Stress values apply to normalized, or normalized and tempered or oil quenched and tempered material only, as per applicable specification. (13) Stress values apply to quenched and tempered material only, as per applicable specification. (14) Welding or brazing is not permitted when Carbon content exceeds 0.35% by ladle analysis except for limited types of welding as allowed in Part UF. 169 (1) (2)
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Table 1A 1992 SECTION II NOTES TO TABLE 1A (CONT'D) (C) Section VIII, Division 1 Application (Cont'd) C1: UCS-23 (Cont'd) (15) Maximum allowable stress values in ksi shall be as follows: Normalized or Normalized Type & & Tempered, °F Liquid Quenched and Tempered, °F Grade 650 100 200 300 400 500 600 I II III IV V2 V 3&4 V5 VIII (16) (17) (18) (19) (20) (21) (22) (23) (24) (25) (26) (27) (28)
15.0 18.8 22.5 26.3
15.0 18.8 22.5 26.3 30.0 30.0 30.0 33.7
15.0 18.8 22.5 25.1 29.1 30.0 30.0 32.3
650
24.6 28.5
24.6 28.3
24.6 28.2
24.6 27.8
24.6 26.8
30.0 32.1
30.0 31.9
30.0 31.6
30.0 31.4
29.8 30.0
This material shall not be used in thickness’ above 0.58 in. Upon prolonged exposure to temperatures above 800°F, the carbide phase of carbon steel may be converted to graphite. Upon prolonged exposure to temperatures above 875°F, the carbide phase of carbon-molybdenum steel may be converted to graphite The material shall not be used in thickness’ above 0.375 in. Where the fabricator performs the heat treatment, the requirements of UHT-81 shall be met. Section IX, QW-250 Variables QW-404.12, QW-406.3, QW-407.2, and QW-409.1 of QW-422 shall also apply to this material. These variables shall be applied in accordance with the rules for welding of Part UF of Division 1. The material shall not be used in thickness’ above 2 in. The material shall not be used in thickness’ above 2 1/2 in. The material shall not be used in thickness’ above 4 in. These stress values are permitted for open-hearth, basic oxygen or electric-furnace steels only. A factor of 0.85 has been applied in arriving at the maximum allowable stress values in tension for this material. Divide tabulated values by 0.85 for maximum allowable longitudinal tensile stress. Use of external pressure charts for material in the form of barstock is permitted for stiffening rings only. For temperatures above the maximum temperature shown on the external pressure chart for this material. Fig. CS-2 of Section II, Part D, Subpart 3 may be used for the design using this material.
(29) The maximum nominal plate thickness shall not exceed 0.58 in. (30) These stress values are based on expected minimum values of 45,000 psi tensile strength and yield strength of 20,000 psi resulting from loss of strength due to thermal treatment required for the glass coating operation. UG-85 does not apply. (31) The minimum tempering temperature shall be 800°F. (32) This material may be welded by the resistance technique. (33) Not permitted above 200°F; allowable stress values are 35.0 ksi for diameters of 1/2 in. or less, 33.8 ksi for diameters greater than 1/2 in. up to and including 4 in. (34) The user is cautioned that under certain conditions of temperature and environment, or fatigue conditions, stress corrosion of this material may be a problem. (35) Although External Pressure Chart title is listed for SA-537, use Class 1 curves for this specification. (36) Although External Pressure Chart title is listed for SA-537, use Class 2 curves for this specification. (37) ASTM A 234 fittings are considered equivalent to SA-234 fittings. (38) Minimum postweld heat treatment shall be 1300°F. (39) In welded construction for temperatures above 850°F, the weld metal shall have a carbon content of greater than 0.05%. (40) The following additional requirements apply to 3Cr-1Mo-1/4V-Ti-B material. (a) In fulfilling the requirements of UCS-85 (b), sufficient tensile tests shall be made to represent postweld heat treatment at both the minimum and maximum times at temperature, and impact tests shall be made to represent the minimum time at temperature. The results of the tensile tests shall meet the tensile requirements of the material specification. The impact tests shall meet a minimum average of 40ft-lbf at 0°F, with not more than one specimen below 40 ft-lbf and not lower than 35 ft-lbf. (b) Welding procedure qualification tensile tests shall meet both the minimum and maximum tensile strength requirements of the material specification. (c) Each heat or lot of consumable welding electrodes and each heat or lot of filler wire and flux combination shall be tested to meet the requirements of (a) above. (d) Welding shall be limited to the submerged-arc (SAW) and the shielded metal-arc (SMAW) processes. (41) For External Pressure Chart listing, use Class 1 curve. 170
API 510
Page 306 of 310
Table 1A
1992 SECTION II TABLE 1A (CONT’D)
A92
SECTION I, SECTION III, CLASS 2 AND 3;* AND SECTION VIII, DIVISION 1 MAXIMUM ALLOWABLE STRESS VALUES S FOR FERROUS MATERIALS (*See Maximum Temperature Limits for Restrictions on Class)
Nominal Composition
Product Form
Spec. No.
C-Si C-Si C C C
Cast pipe Cast Pipe Bar Bar Bar, rod
SA-660 SA 660 SA-675 SA-675 SA-675
C-Mn C-Mn-Si C-Mn-Si C-Mn-Si C-Si C-Si
Forgings Plate Plate Plate, sheet Plate Plate, sheet
C-Si C-Mn-Si C-Mn-Si C-Mn-Si C-Si
A92
A92 A92
A92
Alloy Class/ Desig./ Cond./ UNS No. Temper Size/Thickness
Group P-No.
No.
WCA WCA 60 60 60
1 1 1 1 1
1 1 1 1 1
SA-765 SA-442 SA-442 SA-442 SA-515 SA-515
1 60 60 60 60 60
1 1 1 1 1 1
1 1 1 1 1 1
Plate Plate Plate, sheet Plate Wld. pipe
SA-515 SA-516 SA-516 SA 516 SA-671
60 60 60 60 CB60
1 1 1 1 1
1 1 1 1 1
C-Mn-Si C-Mn-Si C-Si C-Mn-Si C-Mn-Si
Wld. pipe Wld. pipe Wld. pipe Wld. pipe Wld. pipe
SA 671 SA-671 SA-672 SA-672 SA.672
CC60 CE60 B60 C60 E60
1 1 1 1 1
1 1 1 1 1
C C C C C-Mn C-Mn
Wld. pipe Plate, sheet Bar, shapes Plate Wld. pipe Smls. pipe
SA-134 SA-283 SA-283 SA-283 SA-53 SA-53
A283D D D D B B
1 1 1 1 1 1
1 1 1 1 1 1
C-Mn C-Mn C-Mn C-Mn C-Mn C-Si
Wld. pipe Pipe Smls. pipe Wld. pipe Smls. pipe Smls. pipe
SA-53 SA-53 SA-53 SA-53 SA-53 SA-106
B B B E/B S/B B
1 1 1 1 1 1
1 1 1 1 1 1
C-Si C-Si C-Mn C-Si C-Si
Pipe Smls. pipe Pipe Fittings Fittings
SA-106 SA-106 SA-135 SA-234 SA-234
B B B WPB WPB
1 1 1 1 1
1 1 1 1 1
C-Si C-Si C-Mn-Si C-Mn-Si C-Mn-Si
Fittings Wld. fittings Pipe Wld. & smls. pipe Tube
SA-234 SA-234 SA-333 SA-333 SA-334
WPB WPBW 6 6 6
1 1 1 1 1
1 1 1 1 1
C-Mn-Si C-Mn-Si C-Si C-Mn C-Mn-Si
Wld. & smls, tube Forged pipe Forgings Plate, sheet Fittings
SA-334 SA-369 SA-372 SA-414 SA-420
6 FPB 1 D WPL6
1 1 1 1 1
1 1 1 1 1
Type/Grade
10
API 510
Page 307 of 310
PART D - PROPERTIES Table 1A TABLE 1A (CONT’D)
A92
SECTION I, SECTION III, CLASS 2 AND 3;* AND SECTION VIII, DIVISION 1 MAXIMUM ALLOWABLE STRESS VALUES S FOR FERROUS MATERIALS (*See Maximum Temperature Limits for Restrictions on Class)
A92
A92 A92
A92
Min. Tensile Strength, ksi
Min. Yield Strength ksi
Applic. and Max. Temp. Limits (NP = Not Permitted) (SPT = Supports Only) I III VIII.1
External Pressure Chart No.
60 60 60 60 60
30 30 30 30 30
1000 NP 850 NP NP
NP 700 NP 650(Cl. 3 only) 700(SPT)
NP NP NP 900 NP
60 60 60 60
30 32 32 32
NP 850 NP NP
NP NP 700 NP
650 NP NP 850
CS-2 CS-2
60 60
32 32
1000 NP
NP NP
NP 1000
CS-2 CS-2
A1:(1)(21)
60 60 60 60 60
32 32 32 32 32
NP 850 NP NP NP
700 NP NP 700 700
NP NP 1000 NP NP
CS-2 CS-2
A1:(1)(21)
60 60 60 60 60
32 32 32 32 32
NP NP NP NP NP
700 700 700 700 700
NP NP NP NP NP
60 60 60 60 60 60
33 33 33 33 35 35
NP NP NP NP NP 900
300(Cl. 3 only) NP NP 300(Cl. 3 only) NP NP
NP 650 650 NP 900 NP
60 60 60 60 60 60
35 35 35 35 35 35
900 NP NP NP NP 1000
NP NP 700(SPT) 300(Cl. 3 only) 300(Cl. 3 only) NP
NP 900 NP NP NP NP
CS-2 CS-2
60 60 60 60 60
35 35 35 35 35
NP NP NP 1000 NP
NP 700 NP NP NP
1000 NP 900 NP 1000
CS-2
60 60 60 60 60
35 35 35 35 35
NP NP NP NP NP
700 700 NP 700 NP
NP NP 1000 NP 650
60 60 60 60 60
35 35 35 35 35
NP 1000 NP NP NP
700 NP NP NP NP
650 NP 650 900 850
Notes Reference III
VIII-1
A1:(1)(5)(21)(27) B1:(4) A1:(1)(16)(21)(27) CS-2
C1:(3)(17)(27)
C1 A1:(1)(21) B1:(13)
CS-2
C1:(17)
C1:(17) B1:(13) C1:(17) B1:(13) B1:(1)(3)(13)(16)(17) B1:(1)(3)(13)(16)(17) B1:(1)(3)(13)(16)(17) B1:(1)(3)(13)(16)(17) B1:(1)(3)(13)(16)(17) B1:(1)(3)(13)(16)(17) B3:(1)(2)(3)(4)
CS-2 CS-2
C1:(1)(2) C1:(1) B3:(3)(4)
CS-2 CS-2
C1:(3)(25)(26)@32) A1:(1)(21) A1:(1)(7)(21) C1:(3)(4)(17) A.92 B4:(2) B3:(1)(2)(4) B3:(1)(4)
CS-2
A1:(1)(21) C1:(17) B1:(1)(13)
CS.2
C1:(3)(4)(26)(32) A1:(1)(20)(21)(21)
CS-2
C1:(18)(37) B1:(13) B1:(1)(3)(13)
CS-2
C1:(17) B1:(1)(3)(13)
CS.2
C1:(26)(32)
CS-2
B1:(3)(13)
C1
A1:(1)(21)(27) CS-2 CS-2 CS-3
11
API 510
I
Page 308 of 310
C1:(12)(15) C1:(3)(17) C1;(18)(37)
Table 1A
1992 SECTION II TABLE 1A (CONT’D) SECTION I, SECTION III, CLASS 2 AND 3;* AND SECTION VIII, DIVISION 1 MAXIMUM ALLOWABLE STRESS VALUES S FOR FERROUS MATERIALS (*See Maximum Temperature Limits for Restrictions on Class)
A92
Maximum Allowable Stress, ksi (Multiply by 1000 to Obtain psi) for Metal Temperature, °F, Not Exceeding
A92
A92 A92
A92
-20 to 100
150
300
400
500
600
650
700
750
800
850
900
950
15.0 15.0 15.0 15.0 15.0
200
15.0 15.0 15.0 15.0 15.0 15.0
250
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
14.4 14.3 14.4 14.4 14.4
13.0
10.8
7.8
5.0
3.0
13.0 12.9
10.8 10.8
7.8 7.8
5.0
15.0 15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0 15.0
14.4 14.3 14.4 14.4 14.4
13.0
10.8
7.8
13.0 13.0 13.0
10.8 10.8 10.8
8.7 7.8 8.7
5.0 6.5
3.0 4.5
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
14.3 14.4 14.4 14.3 14.3
13.0 13.0
10.8 10.8
7.8 8.7
6.5
4.5
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
15.0 15.0 15.0 15.0 15.0
14.3 14.3 14.3 14.3 14.3
12.6 12.7 12.7 12.6 12.8 15.0
12.6 12.7 12.7 12.7 12.7 12.6 12.8 12.8 15.0
12.6 12.7 12.7 12.6 12.8 15.0
12.7 12.7
12.7 12.7
12.7 12.7
12.7 12.7
12.8 15.0
12.8 15.0
12.8 15.0
12.8 15.0
12.2 14.4
11.0 13.0
9.2 10.8
7.4 7.8
5.5 5.0
12.8 15.0 15.0 15.0 15.0 15.0
12.8 15.0 15.0 15.0 15.0 15.0 15.0
12.8 15.0 15.0 15.0 15.0 15.0
12.8 15.0 15.0
12.8 15.0 15.0
12.8 15.0 15.0
12.8 15.0 15.0
12.2 14.4 14.3
11.0 13.0
9.2 10.8
6.7 8.7
4.3 6.5
15.0
15.0
15.0
15.0
14.4
13.0
10.8
7.8
5.0
3.0
15.0 15.0 12.8 15.0 15.0
15.0 15.0 15.0 12.8 12.8 15.0 15.0 15.0
15.0 15.0 12.8 15.0 15.0
15.0 15.0 12.8 15.0 15.0
15.0 15.0 12.8 15.0 15.0
15.0 15.0 12.8 15.0 15.0
15.0 15.0 12.8 15.0 15.0
14.4 14.3 12.2 14.4 14.4
13.0
10.8
8.7
6.5
4.5
11.0 13.0 13.0
9.2 10.8 10.8
7.4 7.8 8.7
5.5 5.0 6.6
3.0 4.6
15.0 15.0 15.0 15.0 12.8
15.0 15.0 15.0 15.0 15.0 12.8 12.8
15.0 15.0 15.0 15.0 12.8
15.0 15.0 15.0 15.0 12.8
15.0 15.0 15.0 15.0 12.8
15.0 15.0 15.0 15.0 12.8
15.0 15.0 15.0 15.0 12.8
14.3 14.3 14.4 14.3
13.0
10.8
7.8
5.0
3.0
15.0 15.0
15.0 15.0
15.0 15.0
15.0 15.0
15.0 15.0
15.0 15.0
14.3 14.4
13.0
10.8
7.8
5.0
3.0
15.0 15.0
15.0 15.0 15.0 15.0
15.0 15.0
15.0 15.0
15.0 15.0
15.0 15.0
15.0 15.0 15.0 15.0 15.0
14.3 14.4
12.9 13.0
10.8 10.8
8.6 8.7
6.5
12
API 510
Page 309 of 310
PART D - PROPERTIES Table IA A92
TABLE 1A (CONT'D) SECTION I; SECTION III, CLASS 2 AND 3;* AND SECTION VIII, DIVISION 1 MAXIMUM ALLOWABLE STRESS VALUES S FOR FERROUS MATERIALS (*See Maximum Temperature Limits for Restrictions on Class)
Maxirnurn Allowable Stress, ksi (Multiply by 1000 to Obtain psi), for Metal Tem;>erature, IF, Not Exceeding Type/ 1000 1050 1100 1150 1200 1250 1300 1350 1400 1450 1500 Grade 1.5
1.5 2.5
2.5
1.5 2.5
1.5 2.5
1.5
1.5
13
API 510
Page 310 of 310
Spec. No.
WCA WCA 60 60 60
SA-660 SA.660 SA-675 SA-675 SA-675
1 60 60 60 60 60
SA-765 SA-442 SA-442 SA-442 SA.515 SA-515
60 60 60 60 CB60
SA-515 SA-516 SA-516 SA-516 SA-671
CC60 CE60 B60 C60 E60
SA-671 SA-671 SA-672 SA-672 SA-672
A283D D D D B B
SA-134 SA-283 SA-283 SA-283 SA-53 SA-53
B B B E/B S/B B
SA.53 SA-53 SA-53 SA-53 SA-53 SA-106
B B B WPB WPB
SA-106 SA-106 SA-135 SA-234 SA-234
WPB WPBW 6 6 6
SA-234 SA.234 SA-333 SA-333 SA.334
6 FPB I D WPL6
SA-334 SA-369 SA-372 SA-414 SA-420
A92
A92 A92
A92
