API 510 Study Material-1

August 15, 2017 | Author: C.NATARAJ | Category: Valve, Welding, Corrosion, Heat Treating, Pressure
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INTRODUCTION API 510 STUDY MATERIAL HOW TO USE THESE BOOKS These books can be used in a self-study or instructor led format. There are two volumes, the Text and the Questions and Answers. TEXT BOOK The Text book's table of contents follows the API 510 Body of Knowledge that was in effect at the time of its writing. Each area can be studied as a stand alone module for those who do not intend to sit for the API 510 exam, but want to obtain a better understanding on a given Code subject. The process found to most effective for general use is to study each subject of interest and complete the quizzes at the end of that module. As regards to calculations, after mastering the given material, refer to the Advanced Material section to increase the depth of understanding. The Advanced Material covers the calculations required for some actual circumstances that might be encountered in the field. For those intending to sit for the API 510 examination, some helpful suggestions are contained in the back of the Text book. These include such things as what paragraphs to tab within the ASME Code books, and cross over subjects from the API to the ASME Codes. At this writing the exam candidate is allowed to use the ASME Code books and the API books on the first portion of the test only. No reference material is allowed for the second half of the test! QUESTIONS AND ANSWERS BOOK The Questions and Answers are divided into two types. The first portion covers the ASME Codes, Sections VIII Div. 1 Unfired Pressure Vessels, Section IX Welding, and Section V Nondestructive Testing. These questions are typical of previous National Board Authorized Inspector exams. These should be used to obtain a feel for the nature of the ASME Code questions. They are not for memorization. The second portion contains questions from the API 510 Code and the Recommended Practices, titled RPI 572 Inspection of Pressure Vessels, RPI 576 Pressure Relieving Devices and Chapter II -Conditions Causing Deterioration of Failures. These questions are for memorization if the examination will be taken!

API 510

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API 510 Module

Table of Contents API CODES API 510 Corrosion Rates and Inspection Intervals Scope


Inspection Interval


Records and Test


Metal loss including corrosion averaging


Corrosion rates


Remaining Corrosion Allowance


Remaining Service Life


API 576 Pressure Relieving Devices Scope


Types of pressure relieving devices


Reasons for Inspection


Causes of Improper Performance


Frequency and Time of Inspection


API 572 Inspection of Pressure Vessels Scope


Reasons for Inspection


Causes of Deterioration


Methods of Inspection


Records and Reports

36 IRE Chapter 11

Coverage from the API 510 Body of Knowledge

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ASME Section VIII Div. 1 Joint Efficiencies UW-3 Weld Categories


UW-51 RT Examination of Welded Joints


UW-52 Spot Examination of Welded Joints


UW- 11 RT and UT Examinations


UW-12 Maximum Allowable Joint Efficiencies


Postweld Heat Treatment UW-40 Procedures for Postweld Heat Treatment


UCS-56 Requirements for Postweld Heat Treatment


Vessels Under Internal Pressure UG-27 Thickness of Shells Under Internal Pressure


UG-32 Formulas and Rules for Using Formed Heads


UG-34 Unstayed Flat Heads and Covers (Circular)


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


Pressure Testing UG-20 Design Temperature


UG-22 Loadings


UG-25 Corrosion


UG-98 Maximum Allowable Working Pressure


UG-99 Hydrostatic Test Pressure and Procedure


UG-100 Pneumatic Test Pressure and Procedure


UG-102 Test Gages


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


UG-37 Reinforcement of Openings


UG-40 Limits of Reinforcement


UG-41 Requirements for Strength of Reinforcement


UG-42 Reinforcement of Multiple Openings


Minimum Design Metal Temperature and Exemptions from Impact Testing UG-84 Charpy Impact Test Requirements


UCS-66 Materials


UCS-67 Impact Testing of Welding Procedures


UCS-68 Design

164 Practical Knowledge

UG-77 Material Identification


UG-93 Inspection of Materials


UG- 116 Name Plate Markings


UG-119 Name Plates


UG- 120 Data Reports

175 Section IX

Welding on Pressure Vessels (Section IX Overview) Article I General Requirements


Article II Welding Procedure Qualifications


Article III Welding Performance Qualifications


Article IV Welding Data

181 Welding Documentation Review

Welding Procedure Specification (WPS)


Procedure Qualification Record (PQR)


Practice WPS/PQR reviews


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Section V (NDE Subsection A) Article 2 Radiography


Article 5 Ultrasonics


Article 6 Liquid Penetrant


Article 7 Magnetic Particle


Article 9 Visual Inspection


Advanced Material Example Problems Static Head of Water




Cylinders Under Internal Pressure


Heads Under Internal Pressure


Charpy Impact Test Evaluation WPS/PQR


Advanced Exercise Problems Internal Pressure Shell Calculations


Internal Pressure Head Calculations


Solutions for Advanced Exercises


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


Instructions for the proper tabbing of ASME Code books


Practice WPS and PQR forms


Solutions to Text Module Exercises


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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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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)


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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answer: API-510


answer: is the maximum gauge pressure permitted at the top of a pressure vessel in its operating position for a designated temperature.


answer: A change in either temperature rating or maximum allowable pressure of a vessel or both.


answer: A container designed to withstand internal or external pressure by an exterior source by the application of heat direct or indirect or both.


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


answer: Time, Temperature & Stress.


answer: Careful visual examination


answer: wire brushing, blasting, chipping, grinding(or combination)


answer: At ambient temperature, carbon, low alloy, and other Ferritic Steels.


answer: 1. Magnetic Particle 2. Dye Penetrant 3. Radiography 4. Ultrasonic Thickness measurement. 5. Metallographic Examination 6. Acoustic Emission Testing 7. Hammer Test.


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


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 Section VIII UG126) 5. You notice that a pressure relief device has a closed bonnet. What type of valve is it? ( 6. While reviewing maintenance records you notice that bulged rupture disks in a unit are three years old. Is this okay? ( 7.

A pilot operated safety valve has been installed in heavy crude service. Is this okay? (

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)


Describe multilayer construction of a pressure vessel. (2.2)


When carbon steel will not resist corrosive fluids, what method of construction is normally used for such a vessel? (2.3)


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


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


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


Name three types of information gained from the inspection of a pressure vessel.(5. 1)


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)


What is the most important factor in determining the inspection frequency of a pressure vessel? (7. 1)


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)


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


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


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


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)


Abrasive grit blasting, power wire brushing etc., are usually required under what conditions? (8.4.2)


If a vessel has had previous internal inspections, what should be done prior to your inspection? (8.4.3)


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


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)


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


How may loose non-metallic fittings be found using a hammer? (8 4.6)


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


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


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


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


What functions may an inspector's hammer serve? (8.5.1),,


When testing a vessel pneumatically what should be on hand to aid in the visual examination? (8.5.2)


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)


Before retiring a vessel, what should be consulted? (8.6)


Before taking credit for excess thickness found in a vessel when doing calculations for retirement or rerating, what must also be considered? (8.6)


What documents should be consulted prior to any repair? (9)


When shall a pressure test be applied? (9)


Why should care be taken when arc gouging a crack before a welded repair? (9)


What must an inspector consider when recommending the filling of pits with an epoxy? (9)


What does the continuous file contain? (10.2)


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)


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)


When are Double Tube Sheet Exchangers used? (A.2.5)


Name two types of water heaters. (A.2.7)


What principle of cooling is used with exposed tube bundles? (A.3.2, 3.3)


Name two types of Air-Cooled Exchangers. (A.5)


Describe the construction of Double-Pipe coils. (A.6.2)


Where are Flat-Type Heater Coils found? (A.6.3.4)


Why is it important to inspect exchanger bundles when they are first pulled from a shell? (A.9. 1)


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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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)


Name six corrosive components of crude oil. (202.021)


What component do all crude oils contain? (202.022)


Where does Hydrogen Chloride evolve from in a process stream? (202.022)


What is the definition of pH? (202.022)


May Hydrogen Sulfide cause corrosion even at low temperature? If so, where can it be found? (202.023)


Where can Carbon Dioxide come from in process streams? (202.024)


Name the corrosive materials added to processes. (202.023)


Above what concentration is Sulfuric Acid not very corrosive? (202.032)


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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Objectives Student should understand and be capable of applying the following concepts: A.

Joint restrictions based on Service.


Joint Categories.


Joint Types.


Butt Joint Radiography Requirements.


Butt Joint Efficiencies.


Requirements for Post Weld Heat Treatment.


Application of Welded Repairs.

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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


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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.










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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.





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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.














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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









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UW -3 Welded Joint Category Exercises 1.

The category of a joint depends on: a. b. c. d.


A circumferential weld to attach a flange is what Category'? a. b. c. d.


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.


In the drawing below identify all of the of joints by Category.









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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.


Personnel performing and evaluating radiographs shall be qualified using SNT-TC- 1A as a guideline for written practices used in their qualification.


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.


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.


That any indication on a radiographed characterized as a crack or zone of incomplete fusion or penetration is unacceptable.


That the limits of elongated indications are based on the materials thickness.


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.


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.


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.


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.


Spot radiographs must follow the same rules as full radiographs for techniques. The minimum length of the spot examined must be 6 inches.


Indications described as cracks or zones of incomplete fusion or lack of penetration are unacceptable.


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.


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.


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.


If the tracers pass then repair and radiography is allowed for the area that was rejected in the first spot radiograph.


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.


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.


Butt welds in the shells and heads of unfired steam boilers having an operating pressure greater than 50 psi.


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.


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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API 510 Module PART UW - WELDING 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)(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].





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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


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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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



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;



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;


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


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?


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?


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?


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


Full RT and Spot RT


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.


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.


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.


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


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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


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.




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


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


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




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




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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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).


Longitudinal Stress on shells.


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


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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


What is the extent of radiography on the long joint? a. Full b. Spot c. None


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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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.



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.


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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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.


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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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


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


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


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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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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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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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.


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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


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


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

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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.


Joint category is based on where in a vessel a joint is located.


Type of joint is based on how the joint was fabricated.


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.




1. 2. 3. 4. 5. 6. 7.

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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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Exercises UW-12





1. 2. 3. 4. 5. 6. 7.

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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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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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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).


Calculate the thickness required or pressure allowed for 2 to 1 Ellipsoidal, Standard Torispherical and Hemispherical heads (Part MAWP).


Calculate the thickness required for Circular Unstayed Flat heads (Part MAWP).


Calculate the Thickness of Shells and Tubes Under External Pressure.


Determine Maximum Allowable Working Pressure for a Vessel.


Calculate Hydrostatic and Pneumatic Test pressures. Describe Procedures for Tests.


Size Fillet Welds at Openings.


Determine if Reinforcement of an Openings is required.


Requirements for Name Plates and their markings.


Requirements for Material identification and Inspection.


Types of Data Reports. information contained in Data Reports.

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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




= 409. 8

psi R + 0.6t

18.0 + (0.6 x 0.500)

SEt App 1 (1 - 1) P=


15,000 x 1.0 x 0.500 =

7500 =



psi R. - 0.4t

18.5 - (0.4 x 0.500)


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


12.0” +0.375 (orig. t)=12.375" This finds the original outside 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 =


4140.69 =

12.022 + (0.6 x .353)






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)


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" .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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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




3 ½”

API 510


1 ½” = 5”

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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


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







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.


5.999” 3” 2” 6”


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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”


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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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?


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?


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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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,


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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


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


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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


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.


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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There will he no inward projection for the nozzle.


The nozzle will enter at 90 degrees to the shell or head.


The opening will not pass through a Category A weld.


Nozzles and shell will be of the same strength.


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


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


Area available in shell;

= 2(t+tn)( E1t-Ftr)- 2tn (E1t-Ftr)( 1-fr1) = 5(tn –trn) fr 2t A2


Area available in the nozzle outward; use smaller = 5(tn –trn) fr 2tn



= 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”


.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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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?


What type of Impact test does the Code recognize?


What are the dimensions of a standard Charpy Impact specimen?


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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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.


The completed vessel shall be hydrostatically tested (Pneumatic test is not permitted for this exemption)


Design temperature is no warmer than 650°F nor colder than -20°F.


The thermal or mechanical shock loadings are not controlling design.


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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UG-20 / UCS-66 / 68 Exercises 1. Name four steps (paragraphs) when looking for exemptions from impact testing.


When are impact tests always mandatory for welded joints?


When are impact tests always mandatory for non-welded joints?


What is the minimum design temperature allowed for a 1 ½” thick plate of SA-515 Gr. 70"


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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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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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.


All other product forms must be marked in accordance with their material specification. For examp1e, pipe marked SA- 106 gr. B.


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.

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Cut edges of and parts made from rolled plate for serious laminations, shearing cracks, etc.


Materials which will be impact tested must be examined for surface cracks.


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 .


The inspector must assure himself that thickness and other dimensions of the material comply with the requirements of this Division.


The inspector must verify welded repairs to defects.


The inspector must verify that all required tests have been performed and are acceptable (Impact tests, NDE, etc.).


The inspector must confirm material I.D.'s have been properly transferred.


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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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.


Name of the manufacturer preceded by the words "Certified by”.


Maximum allowable working pressure __________ psi at _______ °F.


Minimum design metal temperature _______ °F at ___________ psi.


Manufacturer's serial number.


Year built.


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


Arc or gas welded Pressure welded (except resistance) Brazed Resistance welded



If a vessel is built using more than one type of construction all shall be indicated.


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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The MAWP must be based on the most restrictive part of the vessel.


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.


The letter PHT when only part of the vessel has been postweld heat treated.


Code symbol must be applied after hydro or pneumatic test.


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.


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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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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


Certified by Johns Trailer and Vessel Welding 350 psi at 300°F


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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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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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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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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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.

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.

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.

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.

Gas (QW-408) 1. Shielding gas is not used with this process-ignore this block for SMAW

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)

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)

1. 2. 3. 4.

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.

Postweld Heat Treatment (QW-407) addressed correctly as None.

• •

Gas (QW-408) not essential to the SMAW process Electrical (QW-409) nonessential anything or nothing here is ok

Technique (QW-410) nonessential anything or nothing here is ok Back of PQR

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.

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

Filler Metals (QW-404) 1. E-7018 given F-No. of 3


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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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



= (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’


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.




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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


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 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?


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?


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'


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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


.625” -.125” .500”

Remaining Corrosion Allowance Actual Wall Thickness Required Thickness Remaining Corrosion Allowance


.595” -.500” .095”

Corrosion Rate Original Thickness Present Thickness Metal Loss

.625” -.595” .030”

Metal Loss



=0067” / Year 4.5 Years Corrosion Rate = .0067” / Year


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:


t=? 60”



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”



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


.247 x 300 t = 36.0 15,000 x 1.0 74. 1 t = 36.0 X

= 2.53 inch 15,000 Answer: NO.

API 510

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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.

API 510

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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

API 510


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.


Average impact value required per Figure UG-84.1 is 18 ft./ lbs.


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



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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From: UG-27 (c) (1)


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)


From: UG-27 (c) (1)


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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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


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)


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)


From: UG-32 (d)


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)


From: UG-32 (f)


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)


= 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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API 510

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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.


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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(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)







API 510


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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


E = 1.0 Full RT on the category A joint in the hemispherical head.


E = 1.0 per UW-12 (d)


E = 1.0 per UW-12 (d)


E = 1.0 per UW-12 (d)


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


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"


From: UG-27 (c)(1)


SEt R + 0.6t

Givens: t= P=

.850” ?

E= R=

1.0 52”


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)


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"


From: UG-32 (e)


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)


API 510

No the head may not remain in service.

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UG-32 3.

From: UG-32 (f)


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"


From: UG-32 (d)


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


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


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.


Cylinders having

D0=54” 54

D0 = t

= 48.08

t =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 =


= 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 =


t = .730” Check ratio of D0/t

= 5.98/0.730 = 8.19 8.19
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