API 510 Chapter 3 – Inspection Practices (Section 5)

API 510 Chapter 3 Inspection Practices (Section 5)

3.1 Introduction to API 510 section 5: inspection practices

Section 5 of API 510 contains many of the important principles on which the syllabus (and examination) is based. It is not really a stand-alone chapter; it relies on additional information included in sections 6 and 7 to give the full picture of what API considers is involved in the inspection of pressure vessels. Figure 3.1 shows the situation. This section has changed emphasis significantly since the previous API 510 edition; its main emphasis is now the existence and use of an inspection plan (written scheme of examination) linked with the application of risk-based inspection (RBI) techniques to help decide inspection scope and frequency. It also includes information on pressure testing, to link in with the requirements of ASME VIII.

3.2 Inspection types and planning

Section 5.1: inspection plans Have a quick look through this. It is mainly commonsense about what should go in a vessel inspection plan. There is nothing in here that should be new to engineers who have worked with written schemes of examination (WSEs). It is, however, a good area for closed-book exam questions.

Section 5.2: risk-based inspection This is a heavily expanded section compared to previous editions of API 510. Mention RBI in the world of inspection and it seems you just can’t go wrong. Notice the two fundamental points:

Inspection scope and frequency can be decided by

Figure 3.1 API 510 sections 5, 6 and 7
Figure 3.1 API 510 sections 5, 6 and 7

considering the risk that individual pressure vessels represent. . Risk is determined by considering both probability of failure (POF) and consequences of failure (COF).

The content of this section 5.2 is taken from the document API RP 580: Risk-Based Inspection. This document is not in the API 510 syllabus (it forms a supplementary examination and certificate in itself), but you are expected to know the summary of it that has been transplanted into section 5.2. Notice the breakdown:

  • POF assessment
  • COF assessment
  • Documentation
  • RBI assessment frequency

Section 5.3: preparatory work
Section 5.3 is mainly about good health and safety practice and commonsense. There is nothing in here that should be new to engineers who have worked on industrial sites. It is, however, a good area for an occasional closed-book exam question.

Section 5.4: Modes of deterioration and failure
This section is an introduction (only) to the types of failure and damage mechanisms (DMs) that can affect pressure vessels. As with so many of the API code clauses, it is a mixture of general descriptions and a few specifics. Note the general DM categories that are given in the list:

  • General/local metal loss
  • Surface-connected (breaking) cracking
  • Subsurface cracking
  • Microfissuring/microvoid formation
  • Metallurgical changes
  • Blistering
  • Dimensional changes
  • Material properties change

Most of these are covered in much more detail in API 571:Deterioration Mechanisms (this is part of the API 510 syllabus and we will be looking at it later in this book).

Section 5.5: general types of inspection and surveillance
This fairly general section introduces the different types of inspection that are commonly used for pressure vessels. In reality, there is very little information in here; most technical details come later in section 6. One clear requirement, however, is the need to assess the condition of linings and
claddings, to guide the inspector’s decision as to whether they need to be removed to inspect underneath.
Section 5.5.4: external inspection
This introduces the general requirements for external visual examination of pressure vessels. Note how it gives various different areas that should be assessed, including those for buried vessels. These are largely commonsense.

Section 5.5.6.1: CUI inspection
API codes like to warn against CUI (corrosion under insulation) and there are normally questions on it in the API 510 exam. They have recently revised the ‘at-risk’ temperatures for CUI to:

  • Low carbon/alloy steels: 10 °F to 350 °F
  • Austenitic stainless steels: 140 °F to 400 °F

Note that these are for systems that operate at a constant temperature. By inference, all systems that operate intermittently may be at risk from CUI whatever their temperature range.

Section 5.5.6.3: insulation removal

For vessels with external insulation, provided the insulation and cladding is intact and appears to be in good condition, API’s view is that it is not necessary to remove the coating. It is, however, often good practice to remove a small section to assess the condition of the metal underneath.

Note the list of aspects to take into account when considering insulation removal:

  • History
  • Visual condition and age of the insulation
  • Evidence of fluid leakage

This section introduces the principle that shell thicknesses in areas of CUI susceptibility (corrosion of the external surface) may be checked from the inside of a vessel during an internal inspection.

3.3 Condition monitoring locations (CMLs)

API 510 makes a huge fuss about CMLs (until recently referred to as thickness measurement locations (TMLs)). The change was made to recognize the fact that, in many systems, wall thinning alone is not the dominant damage mechanism. Other service-specific mechanisms such as stress chloride corrosion cracking (SCC) and high-temperature hydrogen attack (HTHA) are likely to be equally or more important.

Section 5.6 contains a page or so of commentary on good practice for selecting CMLs. Most NDE techniques are mentioned as being suitable, as long as their application is carefully chosen. This is followed by section 5.7.1, a welldefined list of NDE techniques and the type of defect they are best at finding. This is an important list for exam questions; the content also appears in other parts of the syllabus such as API 577 and ASME V.

Section 5.7.2: thickness measurement methods Simple compression-probe ultrasonic testing (UT) is generally explained to be the most accurate method of obtaining thickness measurements. Profile radiography may be used as an alternative and in reality is often more useful. Note the requirements of section 5.7.2.3, which requires compensation for measurement inaccuracies when taking thickness measurements at temperatures above 65 °C (150 °F). This is covered in more detail in ASME V article 23.

3.4 Section 5.8: pressure testing

The requirement for doing a pressure test is often misunderstood, not least because of the fact that the mandatory requirement for it has been softened over the past 20 years or so. The situation in the current 9th edition of 510 is fairly clear, as follows:

  • A pressure test is normally required after an alteration.
  • The inspector decides if a pressure test is required after a repair.
  • A pressure test is not normally required as part of a routine inspection.

API 510 gives no new requirements for test pressure; referring directly back to ASME VIII-I UG-98/99 requirements. Whereas in earlier editions (pre-1999 addendum) ASME VIII has used 1.5  MAWP as the standard multiplier for hydraulic test pressures, this was amended (1999 addendum and later) to the following:

Test pressure (hydraulic) = 1.3 MAWP ratio of material stress values .

Ratio of material= Allowable stress at test temperature
                               _____________________________
Stress Values      Allowable stress at design temperature

Remember that this test pressure is measured at the highest point of the vessel. The allowable stress values are given in ASME II(d). Note that where a vessel is constructed of different materials that have different allowable stress values, the lowest ratio of stress values is used. You will see this used later in ASME VIII worked examples.

Section 5.8.6: test temperature and brittle fracture US codes are showing an increasing awareness of the need to avoid brittle fracture when pressure testing of vessels. API 510 therefore now introduces the concept of transition temperature. To minimize the risk of brittle fracture, the test temperature should be at least 30 °F (17 °C) above the minimum design temperature (MDMT). There is no need to go above 120 °F (48 °C) as, above this, the risk of brittle fracture is minimal. The temperature limitation is to avoid the safety risks that arise from brittle fracture of a vessel under pressure. Even when a hydrostatic (rather than pneumatic) test is performed, there is still sufficient stored energy to cause ‘missile damage’ if the material fails by brittle fracture. Note also the requirement for temperature equalization; if the test temperature exceeds 120 8F, the test should be delayed until the test medium reaches the same temperature as the vessel itself (i.e. the temperatures have equalized out).

The hydrostatic test procedure ASME VIII UG-99 (g) gives requirements for the test procedure itself. This is a fertile area for closed-book examination questions. An important safety point is the requirement to fit vents at all high points to remove any air pockets. This avoids turning a hydrostatic test into a pneumatic test, with its dangers of stored energy.

Another key safety point is that a visual inspection of the vessel under pressure is not carried out at the test pressure. It must be reduced back to MAWP (actually defined in UG-99 (g) as test pressure/1.3) before approaching the vessel for inspection. If it was a high-temperature test (> 120 °F, 48 °C), the temperature must also be allowed to reduce to this, before approaching the vessel.

Once the pressure has been reduced, all joints and connections should be visually inspected. Note how this may be waived provided:

  • A leak test is carried out using a suitable gas.
  • Agreement is reached between the inspector and manufacturer to carry out some other form of leak test.
  • Welds that cannot be visually inspected on completion of the vessel were given visual examination prior to assembly (may be the case with some kinds of internal welds).
  • The contents of the vessel are not lethal.

In practice, use of these ‘inspection waiver points’ is not very common. Most vessels are tested and visually inspected fully, as per the first sentences of UG-99 (g).

A footnote to UG-99 (h) suggests that a PRV set to 133 % test pressure is used to limit any unintentional overpressure due to temperature increases. Surprisingly, no PRV set to test pressure is required by the ASME code. You just have to be careful not to exceed the calculated test pressure during the test.

Now try these familiarization questions.

3.5 API 510 section 5 familiarization questions

1.

Q1. API 510 section 5.10.3: inspection of in-service vessels
Which of these in-service weld defects can be assessed by the inspector alone?

 
 
 
 

2.

Q2. API 510 section 5.8.5: pressure testing
When would a pneumatic test be used instead of a hydrostatic test?

 
 
 
 

3.

Q3. API 510 section 5.8.2: test pressure
What is the minimum code hydrostatic test pressure in the ASME VIII Div 1 1999 Addendum edition?

 
 
 
 

4.

Q4. API 510 section 5.8.1.1: pressure testing
When is a pressure test normally required, without being specifically requested by an API inspector?

 
 
 
 

5.

Q5. API 510 section 5.7.1 (h): examination techniques
Acoustic emission techniques are used to detect:

 
 
 
 

6.

Q6. API 510 section 5.7.1 (a): examination techniques
Cracks and other elongated discontinuations can be found by:

 
 
 
 

7.

Q7. API 510 section 5.6.3.1: CML selection
CMLs should be distributed:

 
 
 
 

8.

Q8. API 510 section 5.5.6.3: CUI insulation removal
An externally lagged vessel has evidence of fluid leakage. Which of these is a viable option for an inspector who cannot insist that external lagging is removed?

 
 
 
 

9.

Q9. API 510 section 5.5.6.1: CUI susceptible temperature range

What is the CUI-susceptible temperature range of low alloy steel (e.g. 11 4% Cr)  vessels operating at constant (non-fluctuating) temperature?

 
 
 
 

10.

Q10. API 510 section 5.5.4.1.2: external inspection
External inspections are conducted to check for:

 
 
 
 

11.

Q11. API 510 section 5.5.3: on-stream inspection
All on-stream examinations should be conducted by:

 
 
 
 

12.

Q12. API 510 section 5.2.1: probability assessment
A probability assessment should be in accordance with:

 
 
 
 

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API 510- Chapter 2 An Introduction to API 510 (Sections 1–4)

API 510 Chapter 2 An Introduction to API 510 (Sections 1–4)

2.1 Introduction

This chapter is about learning to become familiar with the layout and contents of API 510. It forms a vital preliminary stage that will ultimately help you understand not only the content of API 510 but also its cross-references to the other relevant API and ASME codes.

API 510 is divided into nine sections (sections 1 to 9), five appendices (appendices A to E), one figure and two tables. Even when taken together, these are not sufficient to specify fully a methodology for the inspection, repair and re-rating of pressure vessels. To accomplish this, further information and guidance has to be drawn from other codes.

So that we can start to build up your familiarity with API 510, we are going to look at some of the definitions that form its basis. We can start to identify these by looking at the API 510 contents/index page. This is laid out broadly as shown in Fig. 2.1

2.2 Section 1: scope

This is a very short (one-page) part of the code. The main point is in section 1.1.1, which states that all refining and chemical process vessels are included in the scope of API 510 except those vessels that are specifically excluded from the coverage of API 510. Note that this list (look at section 1.2.2) links together with a longer list in appendix A (look near the back of the document). Essentially, vessels that are excluded from the coverage of API 510 are: 

  • Mobile plant .
  • Anything designed to other parts of ASME .
  • Fired heaters

An Introduction to API 510 | Figure 2.1 API 510 contents/index

THE CONTENTS OF API 510: 9th EDITION
1. SCOPE

  • 1.1 General application
  • 1.2 Specific applications
  • 1.3 Recognized technical concepts

2. REFERENCES

3. DEFINITIONS

4. OWNER/USER INSPECTION ORGANIZATION

  • 4.1 General
  • 4.2 Owner-User organization responsibilities

5. INSPECTION PRACTICES

  • 5.1 inspection plans
  • 5.2 RBI
  • 5.3 Preparation for inspection
  • 5.4 Inspection for damage mechanisms
  • 5.5 General inspection and surveillance
  • 5.6 Condition monitoring locations
  • 5.7 Condition monitoring methods
  • 5.8 Pressure testing
  • 5.9 Material verification and traceability
  • 5.10 Inspection of in-service welds and pints
  • 5.11 Inspection of flanged joints

6. INTERVAL/FREQUENCY AND EXTENT OF INSPECTION

  • 6,1 General
  • 6.2 Inspection during installation and service changes
  • 6.3 RBI
  • 6.4 External inspection
  • 6.5 Internal and on-stream inspection
  • 6.6 PRVs

7. INSPECTION DATA EVALUATION, ANALYSIS AND RECORDING

  • 7.1 Corrosion rate determination
  • 7.2 Remaining life calculations
  • 7.3 MAWP
  • 7.4 FFS analysis of corroded regions
  • 7.5 API RP 579 FFS evaluations
  • 7.6 Required thickness determination
  • 7.7 Evaluation of equipment with minimal documentation
  • 7.8 Reports and records

8. REPAIRS, ALTERATIONS AND RERATING OF PRESSURE VESSELS

  • 8.1 Repairs and alterations
  • 8 2 Rerating

9. ALTERNATIVE RULES FOR EXPLORATION/PRODUCTION VESSELS

  • Not in the API 510 exam syllabus

APPENDICES

  • APPENDIX A ASME CODE EXEMPTIONS
  • APPENDIX B INSPECTOR CERTIFICATION
  • APPENDIX C SAMPLE PRESSURE VESSEL INSPECTION RECORD
  • APPENDIX D SAMPLE ALTERATIONMERATING FORM
  • APPENDIX E TECHNICAL ENQUIRIES

Machinery, i.e. pumps, compressors, etc.

Pipes and fittings

There are also some specific exemptions on size. Read the list in appendix A and relate them to Figs 2.2 and 2.3 below.

Appendix A (b6) gives an overall pressure temperature

Figure 2.2 API 510 exemption: water under pressure
Figure 2.2 API 510 exemption: water under pressure
Figure 2.3 API 510 pressure–volume exemptions (appendix A (d))
Figure 2.3 API 510 pressure–volume exemptions (appendix A (d))

exemption for vessels that contain water (or water with air provided as a ‘cushion’ only, i.e. accumulators).

Appendix A (b7) covers hot water storage tanks.

Appendix A (b8) gives a more general exemption based on minimum pressures and diameters.

Finally: Appendix A (d) covers a further general exemption based on pressure and volume.

Remember, section 1.2.2 at the front of API 510 only gives you half the story about exemptions. You have to look at the detail given in API 510 appendix A to get a fuller picture.

2.3 Section 3: definitions

Section 3.2: alteration

An alteration is defined as a change that takes a pressure vessel or component outside of its documented design criteria envelope. What this really means is moving it outside the design parameters of its design code (ASME VIII).

Note also how adding some types of nozzle connections may not be classed as an alteration. It depends on the size and whether it has nozzle reinforcement (in practice, you would need to check this in ASME VIII).

Section 3.6: authorized inspection agency

This can be a bit confusing. The four definitions (a to d) shown in API 510 relate to the situation in the USA, where the authorized inspection agency has some kind of legal jurisdiction, although the situation varies between states. Note this term jurisdiction used throughout API codes and remember that it was written with the various states of the USA in mind.

The UK situation is completely different, as the Pressure Systems Safety Regulations (PSSRs) are the statutory requirement. The nearest match to the ‘authorized inspection agency’ in the UK is probably ‘The Competent Person’ (organization) as defined in the PSSRs. This can be an independent inspection body or the plant owner/user themselves

For API 510 exam purposes, assume that ‘The Competent person’ (organization) is taking the role of the authorized inspection agency mentioned in API 510 section 3.6.

Section 3.7: authorized pressure vessel inspector

This refers to the USA situation where, in many states, vessel inspectors have to be certified to API 510. There is no such legal requirement in the UK. Assume, however, that the authorized vessel inspector is someone who has passed the API 510 certification exam and can therefore perform competently the vessel inspection duties covered by API 510.

Section 3.9: condition monitoring locations (CMLs)

These are simply locations on a vessel where parameters such as wall thickness are measured. They used to be called thickness measurement locations (TMLs) but have now been renamed CMLs. CMLs pop up like spring flowers in a few places in API 510 and 572, with emphasis being placed on how many you need and where they should be.

Section 3.19: engineer

In previous editions of API 510, reference was made to the ‘pressure vessel engineer’ as someone to be consulted by the API inspector for detailed advice on vessel design. This person has now been renamed ‘The Engineer’. There’s progress for you.

Section 3.20: examiner

Don’t confuse this as anything to do with the examiner that oversees the API certification exams. This is the API terminology for the NDT technician who provides the NDT results for evaluation by the API-qualified pressure vessel inspector. API recognizes the NDT technician as a separate entity from the API authorized pressure vessel inspector.

API codes (in fact most American-based codes) refer to NDT (the European term) as NDE (non-destructive examination), so expect to see this used throughout the API 510 training programme and examination.

Section 3.37: MAWP

US pressure equipment codes mainly refer to MAWP (maximum allowable working pressure). It is, effectively, the maximum pressure that a component is designed for. European codes are more likely to call it design pressure. For the purpose of the API exam, they mean almost the same, so you can consider the terms interchangeable.

Note how API 510 section 3.37 defines two key things about MAWP:

  • It is the maximum gauge pressure permitted at the top of a vessel as it is installed (for a designated temperature). This means that at the bottom of a vessel the pressure will be slightly higher owing to the self-weight of the fluid (hydrostatic head). The difference is normally pretty small, but it makes for a good exam question.
  • MAWP is based on calculations using the minimum thickness, excluding the amount of the actual thickness designated as corrosion allowance.

A significant amount of the exam content (closed-book and open-book questions) involves either the calculation of MAWP for vessels with a given amount of corrosion or the calculation of the minimum allowable corroded thickness for a given MAWP.

Section 3.53: repair

This is a revised definition added in the latest edition of API 510. It is mainly concerned with making a corroded vessel suitable for a specified design condition. If an activity does not qualify as an alteration then, by default, it is classed as a repair.

Section 3.54: repair organizations

API 510 has specific ideas on who is allowed to carry out repairs to pressure vessels. Look how definition 3.54 specifies four possible types of organization, starting with an organization that holds an ASME ‘code stamp’ (certificate of authorization). This links in with the general philosophy of ASME VIII, requiring formal certification of companies who want to manufacture/repair ASME-stamped vessels.

Section 3.56: re-rating

The word re-rating appears frequently throughout API codes. Re-rating of the MAWP or MDMT (minimum design metal temperature) of pressure vessels is perfectly allowable under the requirements of API 510, as long as code compliance is maintained. In the USA, the API authorized
inspector is responsible for re-rating a pressure vessel, once happy with the results of thickness checks, change of process conditions, etc. In the European way of working, this is unlikely to be carried out by a single person (although, in theory, the API 510 qualification should qualify a vessel inspector to do it). Re-rating may be needed owing to any combination of four main reasons – we will look at this in detail in Chapter 5.

Section 3.62: transition temperature
API codes are showing increasing acceptance of the problem of brittle fracture of pressure equipment materials. The new API 510 9th edition introduces the well-established idea of transition temperature, the temperature at which a material changes from predominantly ductile to predominantly brittle. As a principle, it is not advisable to use a material at an MDMT below this transition temperature (although we will see that there are possible ‘get-outs’ in the ASME VIII part of the syllabus) .

2.4 Section 4: owner/user/inspection organizations

Figure 2.4 summarizes the situation as seen by API.
Sections 4.1–4.2: responsibilities of user/owners
These sections are quite wide-ranging in placing an eyewatering raft of organizational requirements on the user/ owner of a pressure vessel. This fits in well with the situation in other countries where the owner/user ends up being the predominant duty holder under the partially sighted eye of the law.

The idea is that the owner/user should have a maintained QA/inspection/repair management system covering . . . just about everything. There is nothing particularly new about the list of requirements of this (listed as section 4.2.1 a to s); they are much the same as would be included in an ISO 9000 audit or similar act of organizational theatre. They are also the same as those given in the API 570 Piping Inspection code. Note a couple of interesting ones, however.

Section 4.2.1(j): ensuring that all jurisdictional requirements for vessel inspection, repairs, alteration and re-rating are continuously met

Remember that the term jurisdiction relates to the legal requirements in different states of the USA. In the UK this would mean statutory regulations such as the PSSRs, HASAWA, COMAH, PUWER and suchlike.

Section 4.2.1(n): controls necessary so that only materials conforming to the applicable section of the ASME code are utilized for repairs and alterations

This is clear. It effectively says that only code-compliant material and procedures must be used for repairs and alterations if you want to comply with API 510. Note that (along with definition 3.3), it does not specify exclusively the ASME code; this is a significant change from previous API 510 editions which recognized only ASME as the ‘applicable code’. You can think of this as a way of trying to make API 510 more relevant to countries outside the US, but remember that API 510 does not actually say this. The exam paper will be about what is written in the code, not your view of how it fits into the inspection world in other countries.

Reminder: API 510 says that: only materials conforming to the applicable codes and specifications should be used for repairs and alterations.

Figure 2.4 The balance of power
Figure 2.4 The balance of power

Section 4.2.1(0): controls necessary so that only qualified nondestructive examination (NDE) personnel and procedures are utilized

This means that API 510 requires NDE technicians to be qualified, although it seems to stop short of actually excluding non-US NDE qualifications. Look at section 3.27 and see what you think.

Some plant owner/users who have not read API 510 (why should they, as they leave that to the inspector?) may need convincing that they are ultimately responsible for the long list of responsibilities in 4.2.1. However, they find out pretty quickly after a pressure-related incident.

Section 4.2.4: responsibilities of the API authorized pressure vessel inspector This section appears in many of the API codes. The overiding principle (see Fig. 2.5) is that the API-certified pressure vessel inspector is responsible to the owner/user for confirming that the requirements of API 510 have been met. You will see this

Figure 2.5 API inspector responsibilities
Figure 2.5 API inspector responsibilities

as a recurring theme throughout this book (and there will almost certainly be examination questions on it).

Section 4.2.4 places the requirements for candidates to have minimum qualifications and experience, before they are allowed to sit the API 510 exams (see appendix B where these requirements are listed).

Now, using your code, try to answer these familiarization questions.

2.5 API 510 sections 1–4 familiarization questions

Please go to API 510- Chapter 2 An Introduction to API 510 (Sections 1–4) to view the test

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API 510 -Chapter 1

API 510- Chapter 1 Interpreting ASME and API Codes, Chapter 2 An Introduction to API 510 (Sections 1–4)

API 510 -Chapter 1 Interpreting ASME and API Codes

Interpreting ASME and API Codes

Passing the API ICP examination is, unfortunately, all about interpreting codes. As with any other written form of words, codes are open to interpretation. To complicate the issue, different forms of interpretation exist between code types; API and ASME are separate organizations so their codes are structured differently, and written in quite different styles.

1.1 Codes and the real world

Both API and ASME codes are meant to apply to the real world, but in significantly different ways. The difficulty comes when, in using these codes in the context of the API ICP examinations, it is necessary to distil both approaches down to a single style of ICP examination question (always of multiple choice, single-answer format).

1.2 ASME construction codes

ASME construction codes (VIII, V and IX) represent the art of the possible, rather than the ultimate in fitness for service (FFS) criteria or technical perfection. They share the common feature that they are written entirely from a new construction viewpoint and hence are relevant up to the point of handover or putting into use of a piece of equipment. Strictly, they are not written with in-service inspection or repair in mind. This linking with the restricted activity of new construction means that these codes can be prescriptive, sharp-edged and in most cases fairly definitive about the technical requirements that they set. It is difficult to agree that their content is not black and white, even if you do not agree with the technical requirements or acceptance criteria, etc., that they impose.

Do not make the mistake of confusing the definitive requirements of construction codes as being the formal arbiter of FFS. It is technically possible, in fact common place, to use an item safely that is outside code requirements
as long as its integrity is demonstrated by a recognized FFS assessment method.

1.3 API inspection codes API inspection codes (e.g. API 510) and their supporting recommended practice documents (e.g. API RP 572 and 576) are very different. They are not construction codes and so do not share the prescriptive and ‘black and white’ approach of construction codes.

There are three reasons for this: 

  • They are based around accumulated expertise from a wide variety of equipment applications and situations.
  • The technical areas that they address (corrosion, equipment lifetimes, etc.) can be diverse and uncertain.
  • They deal with technical opinion, as well as fact.

Taken together, these make for technical documents that are more of a technical way of looking at the world than a solution, unique or otherwise, to a technical problem. In such a situation you can expect opinion to predominate.

Like other trade associations and institutions, API (and ASME) operate using a structure of technical committees. It is committees that decide the scope of codes, call for content, review submissions and review the pros and cons of what should be included in their content. It follows therefore that the content and flavour of the finalized code documents are the product of committees. The output of committees is no secret – they produce fairly well-informed opinion based on an accumulation of experience, tempered, so as not to appear too opinionated or controversial, by having the technical edges taken off. Within these constraints there is no doubt that API codes do provide sound and fairly balanced technical opinion. Do not be surprised, however, if this opinion does not necessarily match your own.

1.3.1 Terminology

API and ASME documents use terminology that occasionally differs from that used in European and other codes. Non-destructive examination (NDE), for example, is normally referred to as non-destructive testing (NDT) in Europe and API work on the concept that an operative who performs NDE is known as the examiner rather than by the term technician used in other countries. Most of the differences are not particularly significant in a technical sense – they just take a little getting used to.

In some cases, meanings can differ between ASME and API codes (pressure and leak testing are two examples). API codes benefit from their principle of having a separate section (see API 510 section 3) containing definitions. These definitions are selective rather than complete (try and find an accurate explanation of the difference between the terms approve and authorize, for example).

In some cases, meanings can differ between ASME and API codes (pressure and leak testing are two examples). API codes benefit from their principle of having a separate section (see API 510 section 3) containing definitions. These definitions are selective rather than complete (try and find an accurate explanation of the difference between the terms approve and authorize, for example).

                 Pressure(p) x Diameter (d)
Stress(s) =__________________________

                 2x thickness(t)

In SI units all the parameters would be stated in their base units, i.e.

Stress:  N/m2 (Pa)

Pressure:  N/m2 (Pa)

Diameter: m

Thickness: m

Compare this with the USCS system in which parameters may be expressed in several different ‘base’ units, combined with a multiplying factor. For example the equation for determining the minimum allowable corroded shell thickness of storage tanks is:

Where tmin is in inches, fill height (H) is in feet, tank diameter (D) is in feet, G is specific gravity, S is allowable stress and E is joint efficiency. Note how, instead of stating dimensions in a single base unit (e.g. inches) the dimensions are stated in the most convenient dimension for measurement, i.e. shell thickness in inches and tank diameter and fill height in feet. Remember that:

  • This gives the same answer; the difference is simply in the method of expression.
  • In many cases this can be easier to use than the more rigorous SI system – it avoids awkward exponential (106, 10—6,  etc.) factors that have to be written in and subsequently cancelled out.
  • The written terms tend to be smaller and more convenient.

1.3.3 Trends in code units

Until fairly recently, ASME and API codes were written exclusively in USCS units. The trend is increasing, however, to develop them to express all units in dual terms USCS(SI), i.e. the USCS term followed by the SI term in brackets. Note the results of this trend:

  • Not all codes have been converted at once; there is an inevitable process of progressive change.
  • ASME and API, being different organizations, will inevitably introduce their changes at different rates, as their codes are revised and updated to their own schedules.
  • Unit conversions bring with them the problem of rounding errors. The USCS system, unlike the SI system, has never adapted well to a consistent system of rounding (e.g. to one, two or three significant figures) so errors do creep in.

The results of all these is a small but significant effect on the form of examination questions used in the ICP examination and a few more opportunities for errors of expression, calculation and rounding to creep in. On balance, ICP examination questions seem to respond better to being treated using pure USCS units (for which they were intended). They do not respond particularly well to SI units, which can cause problems with conversion factors and rounding errors.

1.4 Code revisions

Both API and ASME review and amend their codes on a regular basis. There are various differences in their approach but the basic idea is that a code undergoes several addenda additions to the existing edition, before being reissued as a new edition. Timescales vary – some change regularly and others hardly at all.

Owing to the complexity of the interlinking and crossreferencing between codes (particularly referencing from API to ASME codes) occasional mismatches may exist temporarily. Mismatches are usually minor and unlikely to cause any problems in interpreting the codes.

It is rare that code revisions are very dramatic; think of them more as a general process of updating and correction. On occasion, fundamental changes are made to material allowable stresses (specified in ASME II-D), as a result of experience with material test results, failures or advances in manufacturing processes.

1.5 Code illustrations

The philosophy on figures and illustrations differs significantly between ASME and API codes as follows: . ASME codes (e.g. ASME VIII), being construction-based,contain numerous engineering-drawing style figures and tables. Their content is designed to be precise, leading to clear engineering interpretation.

API codes are not heavily illustrated, relying more on text. Both API 510 and its partner pipework inspection code, API 570, contain only a handful of illustrations between them.

API Recommended Practice (RP) documents are better illustrated than their associated API codes but tend to be less formal and rigorous in their approach. This makes sense, as they are intended to be used as technical information documents rather than strict codes, as such. API RP 572 is a typical example containing photographs, tables and drawings (sketch format) of a fairly general nature. In some cases this can actually make RP documents more practically useful than codes.

1.6 New construction versus repair activity

This is one of the more difficult areas to understand when dealing with ASME and API codes. The difficulty comes from the fact that, although ASME VIII was written exclusively from the viewpoint of new construction, it is referred to by API 510 in the context of in-service repair and, to a lesser extent, re-rating. The ground rules (set by API) to manage this potential contradiction are as follows (see Fig 1.1). .

  • For new construction, ASME VIII is used – and API 510 plays no part.
  • For repair, API 510 is the ‘driving’ code. In areas where it references ‘the construction codes’ (e.g. ASME VIII), this is followed when it can be (because API 510 has no content that contradicts it).
  • For repair activities where API 510 and ASME VIII contradict, then API 510 takes priority. Remember that these contradictions are to some extent false – they only exist because API 510 is dealing with on-site repairs, while
Figure 1.1 New construction versus inspection/repair: the ground rules
Figure 1.1 New construction versus inspection/repair: the ground rules

ASME VIII was not written with that in mind. Two areas where this is an issue are:

some types of repair weld specification (material, fillet size, electrode size, etc.); . how and when vessels are pressure tested.

1.7 Conclusion: interpreting API and ASME codes

In summary, then, the API and ASME set of codes are a fairly comprehensive technical resource, with direct application to plant and equipment used in the petroleum industry. They are perhaps far from perfect but, in reality, are much more comprehensive and technically consistent than many others. Most national trade associations and institutions do not have any in-service inspection codes at all, so industry has to rely on a fragmented collection from overseas sources or nothing at all.

The API ICP scheme relies on these ASME and API codes for its selection of subject matter (the so-called ‘body of knowledge’), multiple exam questions and their answers. One of the difficulties is shoe-horning the different approach and style of the ASME codes (V,VIII and IX) into the same style of questions and answers that fall out of the relevant API documents (in the case of the API 510 ICP these are API 571/

Figure 1.2 Codes in, questions out
Figure 1.2 Codes in, questions out

572/576/577). Figure 1.2 shows the situations. It reads differently, of course, depending on whether you are looking for reasons for difference or seeking some justification for similarity. You can see the effect of this in the style of many of the examination questions and their ‘correct’ answers.

Difficulties apart, there is no question that the API ICP examinations are all about understanding and interpreting the relevant ASME and API codes. Remember, again, that while these codes are based on engineering experience, do not expect that this experience necessarily has to coincide with your own. Accumulated experience is incredibly wide and complex, and yours is only a small part of it.

2.5 API 510 sections 1–4 familiarization questions

Please go to API 510 -Chapter 1 to view the test

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Click Here To Read Next API 510 Chapter 2 An Introduction to API 510 (Sections 1–4)

GTAW and TIG Welding Questions and Answers

Top 102 Latest GTAW and TIG Welding Questions and Answers

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1. The welding process is shown in fig. is…

a) TIG
b) MIG
c) SMAW
d) SAW

2. What is the boiling point of tungsten?

a) 4500°C
b) 5950°C
c) 6404°C
d) 3330°C

3. What is the melting point of tungsten?

a) 3380°C
b) 2000°C
c) 5404°C
d) 1404°C

4. What is meant by GTAW welding?

a) Gun tantalum arc welding
b) Gas tungsten arc welding
c) General tin arc welding

5. In TIG/GTAW welding, which type of electrodes is used?

a) Non-consumable electrode.
b) Cored electrode
c) Continuous consumable wire electrode
d) Stick electrode

6. Name the parts of the TIG welding torch? Identify the part ‘B’

a) Nozzle
b) Handle
c) Tungsten electrode
d) Gas hose

7. Which of the following arc welding processes does not use consumable electrodes?

a) GMAW
b) GTAW
c) SAW
d) SMAW

8. Which of the following is the odd out?

a) Neon
b) Xenon
c)Argon
d) Nitrogen.

9. In Gas tungsten arc welding (TIG) the following polarity is used for welding Aluminium?

a) Direct current straight polarity (DCSP)
b) Direct current reverse polarity (DCRP)
c) Alternating Current
d) All of the above

10. Argon is used in the welding of stainless steel because:

a) It is inert
b) It helps in melting the electrode
c) It prevents undercut
d) It is cheap

11. It is a non-consumable electrode having a high melting point. It is used in TIG welding. What is the name of this electrode?

a) Carbon electrode
b) Copper electrode
c) Aluminum electrode
d) Tungsten electrode

12. Which one of the following is a commonly used shielding gas in TIG welding?

a) Carbon dioxide
b) Nitrogen
c) Argon
d) Hydrogen

13. An inert gas cylinder is used in the TIG welding process. What is thecolor of the inert gas cylinder?

a) Black
b) Peacock blue
c) Maroon
d) Red

14. What are the two most commonly inert gases used in TIG welding?

a) Argon & carbon dioxide
b) Helium & carbon dioxide
c) Carbon dioxide & nitrogen
d) Argon & helium

15. What is the atomic weight of argonshielding gas?

a) 40
b) 4
c) 14
d) 44

16. What is the atomic weight of heliumshielding gas?

a) 40
b) 4
c) 14
d) 44

17. Which type of power source used in MIG/MAG welding?

a) Constant voltage type
b) Constant current type
c) Constant voltage or current type
d) None of the above

18. Down slope in TIG welding will helps to prevent…

a) Uneven cooling of weld pool
b) Undercut
c) cracks
d) Distortion

19. What is the name of electronic unit thathelps to initiate the arc in TIG weldingprocess?

a) Low frequency
b) Medium frequency
c) High frequency
d) Double frequency

20. What is the colour code of 2% thoriumadded tungsten electrodes?

a) Green
b) Blue
c) Red
d) White

21. What is the colour code of pure tungstenelectrode?

a) Green
b) Blue
c) Red
d) White

22. What is the function of post flow in TIGwelding?

a) To protect TIG welding torch
b) To protect the end of the weld
c) To protect the cooling down of tungsten
d) Both b and c

23. Helium shielding gas having higher flowrates as compared to argon because…

a) helium is extracted from natural gas
b) atomic weight is 40
c) helium is lighter than air
d) none of the above

24. Which of the following is not an inert gas?

a) Argon
b) Xenon
c) Carbon dioxide
d) Helium

25. Why is welding is shielded?

a) To eliminate hydrogen
b) To retard the cooling rate of the weld
c) To eliminate the atmospheric air
d) To ensure maximum heat input

26. What is the colour code of throiatedelectrode with a 0.9 – 1.2 % thorium oxide?

a) Orange
b) Black
c) Gray
d) Yellow

27. What does HF stand for in TIG welding?

a) High frequency
b) High free
c) Hydrogen frequency
d) Helium free

28. Argon shielding gas having lower flow ratesas compared to helium because…

a) obtained from the atmosphere by liquification of air
b) atomic weight is 4
c) argon is heavier than air
d) none of the above

29. In GTAW(TIG), which polarity is most widelyused:

a) Direct current straight polarity (DCSP)
b) Direct current reverse polarity (DCRP)
c) Alternating Current
d) All of the above

30. What is the colour code of Zirconiatedtungsten electrode with a 0.15 – 0.4 %zirconiumoxide?

a) Orange
b) Black
c) Brown
d) Yellow

31. Which tungsten electrode is used forwelding of non-alloyed & low alloyed steels aswell as stainless steels?

a) Thoriated tungsten electrode
b) Zirconated tungsten electrode
c) Pure tungsten electrode
d) None of the above

32. Which tungsten electrode is used forwelding of aluminium & magnesium alloys?

a) Thoriated tungsten electrode
b) Zirconated tungsten electrode
c) Pure tungsten electrode
d) Both b & c

33. Argon gas is best suited for welding thinnermetals because…

a) High arc voltage
b) Low gas volume
c) Low arc voltage
d) High gas volume

34. Helium gas is best suited for welding thickermetals because…

a) High arc voltage
b) Low gas volume
c) Low arc voltage
d) High gas volume

35. What is the type of shielding gas for GTAW (Gas Tungsten Arc Welding) used for carbonsteels only called?

a) Argon – H₂
b) Argon – CO₂
c) Argon – Helium
d) Helium

36. Argon gas is normally superior to helium gasbecause…

a) Lower cost
b) More availability
c) Better for welding dissimilar metals
d) All of the above

37. In pulsed TIG welding, the supply current is not constant and it is being fluctuated from low level to high level, which results in

a) Distortion effect is less
b) Distortion effect is more
c) Both a &b
d) None of the above

38. Argon shielding gas is better for welding at

a) Lower speed
b) Higher speed
c) Normal speed
d) Constant speed

39. The main disadvantage of TIG weldingprocess is…

a) No spattering
b) No post weld cleaning
c) Less Productivity
d) Narrow HAZ

40. Nozzle used in TIG welding is made up of…

a) Metallic
b) Plastic
c) Copper
d) Ceramic

41. Helium is _________ times lighter than argon

a) Six
b) Eight
c) Ten
d) Twelve

42. For higher duty cycle operations usingmaximum welding current upto 500 amps,whichtype of torch is required?

a) Air cooled
b) Ice cooled
c) Water cooled
d) Both a and C

43. What is the effect in welding of stainlesssteel if tungsten electrode is connected topositive terminal in TIG welding?

a) Lack of penetration
b) Poor penetration
c) Porosity
d) Crack

44. What is the shape of tip of then electrodeused in TIG welding for DC machine?

a) Spherical end
b) Pointed end
c) Flat end
d) Angle end

45. In TIG welding, what is the shape of the tipof tungsten electrode used for welding ofaluminium?

a) Pointed end
b) Flat end
c) Spherical end
d) Angular end

46. In TIG welding, what is the shape of the tipof tungsten electrode used for welding ofmild steel?

a) Flat end
b) Pointed end
c) Spherical end
d) Angular end

47. In TIG welding, what is the function of flowswitch in the water line?

a) To remove slag formation from the base metal
b) To shield the weld area
c) To initiate the arc without touching the work piece
d) To switch off the power supply, if any failurein the water circulation

48. In TIG welding, if the thickness of plate tobe welded increases, the size of torch andelectrode diameter must…

a) Decreases
b) Remains same
c) Increases
d) Neither increase nor decrease

49. What is the name of the defect, if the tungsten electrode tip melts & deposit insidetheweld bead?

a) Poor penetration
b) Undercut
c) Tungsten inclusion
d) Lack of fusion

50. Which of the following electrodes & current types may be used for the TIG welding of nickel & its alloys?

a) Zirconium electrode, AC
b) Thorium electrode, DC +ve
c) Cerium electrode, DC –ve
d) All of the above

51. What is the expansion of GTAW?

a) Gas tube arc welding
b) General tungsten arc welding
c) Gas Tungsten arc welding
d) Gas tip arc welding

52. What is the tungsten electrode used for carbon steel & low alloy steel TIG welding?

a) 5% thoriated tungsten electrode
b) 2% thoriated tungsten electrode
c) 5% zirconiated tungsten electrode
d) 2% zirconiated tungsten electrode

53. Inert gases which one produces the deepestpenetration in TIG welding process?

a) Oxygen
b) Helium
c) CO2
d) Argon

54. Out of the following inert gas produceswider penetration profile in TIG welding process?

a) Argon
b) Oxygen
c) Helium
d) CO2

55. At one end of the tungsten electrode colouridentification given for easy selection.What is the colour of 2% thorium addedtungsten electrode?

a) Green
b) Yellow
c) Red
d) Brown

56. At one end of the tungsten electrode, color identification is given for easy selection. What is the color identification of 1%zirconium added tungsten electrode?

a) Red
b) Brown
c) Green
d) Yellow

57. At one end of the tungsten electrode, color identification is given for easy selection. What is the color identification of pure tungsten electrode?

a) Red
b) Green
c) Yellow
d) Brown

58. What is the type of power source polarity is used to weld Aluminium, magnesium, and their alloys in TIG welding?

a) DC
b) AC/DC
c) AC
d) HWAC

59. The normal rage flow rate of shielding gas used in TIG welding is…

a) 1- 4 litres/minute
b) 2-7 litres/minute
c) 10-15 litres/minute
d) 15-20 litres/minute

60. Why alternating current is preferred for welding aluminum using TIG welding?

a) It gives stability and cleaning action
b) It allows high welding speed
c) It avoids weld cracks
d) It gives a good bead profile

61. What is the recommended type of current while welding with a zirconium added tungsten electrode?

a) AC
b) DC
c) AC/DC
d) All of the above

62. What is the recommended type of current while welding with thorium added tungsten electrode?

a) AC
b) DC
c) AC/DC
d) HWAC

63. Identify inert gases in the following list used for TIG welding process…

a) Oxygen
b) Nitrogen
c) Helium
d) Hydrogen

64. About the advantage of pulsed TIGwelding, which statement is correct?

a) Easy to use on thick metals
b) Less distortion
c) Parameter control is easy
d) Deep penetration can be obtained

65. The linear rate at which the arc moves along the joint is called…

a) Arc travel speed
b) Stick out
c) Arc length
d) Transfer

66. Which type of weld defect occurs on the joint due to less flow rate of shielding gas?

a) Crack
b) Undercut
c) Overlap
d) Porosity

67. During the TIG welding process, the tip of the electrode touched the base metal and blunted. What defect will present in Base metal?

a) Oxide inclusion
b) Slag inclusion
c) Tungsten inclusion
d) Porosity

68. What is the physical property of the property of argon gas?

a) Colourless & tasteless
b) Reactive
c) Burning
d) Supports burning

69. The arc temperature produced in the TIGwelding process is…

a) 6000°C
b) 10000°C
c) 20000°C
d) 3000°C

70. What is the type of starting method shown in figure?

a) Lift arc start
b) Scratch start
c) Dip start
d) High-frequency start

71. What is the upslope setting in TIG welding current control?

a) The gas reaching time
b) HF starting time
c) The time taken for welding current to reach the maximum
d) Gas flow rate

72. What is the post flow setting in TIG welding?

a) Time taken for shielding gas to stay after the current stopped.
b) The time taken for welding current to reach the maximum
c) The gas reaching time
d) HF starting time

73. What is the function of Collet as a part of the TIG welding torch?

a) To hold the tungsten electrode
b) To supply gas
c) To supply current
d) To supply cooling water

74. What is the reason for using the purging method in pipe welding?

a) To replace the air in the pipeline with inert gas
b) To Clean the pipe
c) To remove the moisture
d) To remove oxide

75. The reason for the formation of yellow color in ceramic Nozzle during TIG welding is…

a) Incorrect arc length
b) The shielding gas flow rate is too low
c) Contaminated filler rod
d) Excessive heating of torch

76. During TIG welding the tungsten starts melting. What is the reason?

a) Operating on electrode positive polarity
b) Insufficient shielding gas
c) The current is too high
d) Welding speed is fast

77. In DC TIG welding if you operate with electrode positive polarity, what will happen?

a) Electrode will starts melting
b) No welding will take place
c) The base plate will be contaminated
d) Current will stop

78. Why alternating current is preferred for welding aluminum using TIG welding?

a) It gives stability and cleaning action
b) It allows high welding speed
c) It avoids weld cracks
d) It gives a good bead profile

79. What is the recommended type of metal while welding with thorium added tungsten electrode?

a) Mild steel & alloy steels
b) Aluminum alloys
c) Magnesium alloys
d) Refractive metals

80. In the welding of the butt joint from one side, which of the following controls the profile of the root bead?

a) Root Face
b) Bevel Angle
c) Root Gap
d) One of the above

81. What is the recommended type of metal while welding with zirconium added tungsten electrode?

a) Mild steel & alloy steels
b) Aluminum & Magnesium alloys
c) Copper
d) Stainless Steel

82. As per the following figure, the taper shaped tungsten electrode grinding is recommended for what type of current?

a) AC
b) Both AC and DC
c) DC
d) HWDC

83. As per the following figure, ball end type tungsten electrode grinding is recommended for what type of metal?

a) Aluminum & Magnesium alloys
b) Both a & b
c) All of the above
d) Mild steel & alloy steels

84. The characteristics of the power source used in TIG welding is…

a) Constant current.
b) Constant voltage
c) CC/CV
d) None of the above

85. TIG welding is used where _________is more important than productivity.

a) Quality
b) Quantity
c) Mass production
d) Portability

86. What is the size of a gas nozzle for 1.5mm dia. tungsten electrode in TIG welding process?

a) 10 mm dia
b) 12 mm dia
c) 14 mm dia
d) 16 mm dia

87. Which defect would you expect to obtain in TIG welds in non-deoxidized steel?

a) Undercut
b) Porosity
c) Tungsten inclusions
d) Linear misalignment

88. The main reason for using a back purge when welding stainless steel with TIG welding process is to…

a) Improve positional welding
b) Prevent the possibility of porosity
c) Prevent excessive root penetration
d) Prevent the formation of dense oxide layer forming in the root

89. Which defect may occur in the weld bead, if the shielding gas is insufficient in TIG welding?

a) Porosity
b) Undercut
c) Tungsten inclusion
d) Cracking

90. Which defect may occur in the weld bead, if the edge preparation and current level is incorrect in TIG welding?

a) Cracking
b) Blowholes
c) Lack of penetration
d) Porosity

91. Choosing of correct current and electrode in TIG welding depends upon:

a) type & thickness of metal to be welded
b) type of shielding gas
c) diameter of electrode & type of electrode
d) all of the above

92. In TIG welding, if DC electrode positive (DCEP) is used for welding it results in…

a) More penetration
b) Oxide inclusion or lack of fusion
c) Undercut
d) poor penetration & overheating of the torch

93. Which of the following ray is not produced during welding?

a) Gamma rays
b) Visible light rays
c) Infrared ray
d) Ultraviolet rays

94. As per AWS classification of TIG welding electrode – EW Th-1, ‘W’ stands for

a) Electrode
b) Chemical formula of tungsten
c) Thoriated tungsten
d) Welding strength

95. For TIG welding, what benefit does current slop-out device have?

a) it reduces tungsten spatter
b) it reduces the risk of crater cracking
c) it reduces the risk of arc strikes
d) it reduces the inter pass temperature

96. The percentage of alloying element in tungsten electrode helps to…

a) Increases electrode life
b) Stabilizes the arc
c) Both a and b
d) None of the above

97. Which of the following defect occur, when welding metals like aluminum & magnesium with straight polarity?

a) Oxide inclusion or lack of fusion
b) Porosity
c) Incomplete fusion
d) Burn through

98. What is the heat balance in the arc using DCEN polarity in TIG welding?

a) 50% at work and 50% at the electrode
b) 70% at work and 30% at the electrode
c) 30% at work and 70% at the electrode
d) 90% at work and 10% at an electrode

99. While using AC in TIG welding, what is the heat balance in the arc?

a) 50% at work and 50% at the electrode
b) 70% at work and 30% at the electrode
c) 30% at work and 70% at the electrode
d) 90% at work and 10% at an electrode

100. Which of the following gas mixtures is not used in gas tungsten arc welding (TIG)?

a) Argon-Helium
b) Argon-Nitrogen
c) Argon-Hydrogen
d) Argon-Carbon dioxide

101. TIG welding is best suited for welding…

a) Aluminium
b) Mild steel
c) Copper alloys
d) Galvanized steel

102. Helium shielding gas is better for welding at

a) Lower speed
b) Higher speed
c) Normal speed
d) Constant speed

Top 41 Latest API 570 Exam Questions and Answers

Top 41 Latest API 570 Exam Questions and Answers – ALL QUESTIONS ARE CLOSE BOOK

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1. API 570 covers inspection of :

A. new construction
B. new tank construction
C. in-service piping
D. in-service vessels

2. CUI is the acronym for :

A. Corrosion Under Insulation
B. Cold under-ground In-service piping
C. Corrosion Under Inside flow
D. Crack under Insulation

3. A person who assists the inspector by performing specific NDE on piping systems is defined as

A. NDE Technician
B. Assistant Inspector
C. NDT Level II inspector
D. Examiner

4. The response or evidence resulting from the application of a nondestructive evaluation technique is termed:

A. A crack
B. Porosity
C. A leak
D. An indication

5. The MAWP is:

A. The maximum internal pressure permitted in the piping system.
B. The minimum external pressure permitted in the piping system.
C. The maximum external pressure permitted in the piping system.
D. None of the above

6. A selection of piping encompassed by flanges or other connecting fittings is called:

A. A flanged pipe
B. A ready to be installed pipe
C. A spooled piece
D. A fabricated piping assembly

7. If a person has a degree in engineering he is automatically qualified to be:

A. An Authorized Piping Inspector
B. A piping inspector
C. A NDE Level II or III in any technique
D. None of the above

8. A TML is:

A. Thickness Measurement Laboratory
B. The Maximum Limit for thickness
C. Thickness Measurement Location
D. Time Medium Length

9. The result of excessive cyclic stresses that are often well below the static yield strength of the material is termed as:

A. material failure
B. fatigue cracking
C. failure cracking
D. creep cracking

10. Thickness measurements may be taken by ultrasonic instruments or what other method:

A. AET
B. ET
C. MT
D. RT

11. Which of the following tests are not normally conducted as part of a routine inspection:

A. UT thickness
B. Visual inspection
C. Radiographic profile
D. Pressure tests

12. Thickness measurements are not routinely taken on in piping circuits.

A. valves
B. straight run pipe
C. fittings
D. deadlegs

13. During the installation of a flanged connection, the bolts should:

A. Extend two threads past their nuts
B. Extend completely through their nuts
C. Extend only half way through their nuts
D. Extend at least .5 inches (1.25 mm) past their nuts.

14. Services with the highest potential of resulting in an immediate emergency if a leak were to occur are in:

A. Class 3
B. Class 2
C. Class 1
D. Owner/user designated system

15. The classification that includes the majority of unit process piping is labeled:

A. Class 3
B. Class 2
C. Class I
D. Owner/user designated system

16. Services that are flammable but do not significantly vaporize when they leak and are not located in high activity areas:

A. Class 3
B. Class 2
C. Class I
D. Owner/user designated system

17. What is the remaining life in years of a piping system whose corrosion rate is 0.074 inches per year, the actual wall thickness is 0.370 inches and the minimum required thickness is 0.1 inches

A. 36.68 years
B. 364.8 years
C. 3.6 years
D. 3.6 months

18. What is the long term corrosion rate of a piping circuit that started at 0.475 inches and is now 0.2 inch, the measurements were taken over a five year period.

A. 0.055 inches per year
B. 0.005 inches per year
C. 0.550 inches per year
D. Not enough information given

19. What is the short term corrosion rate for the above piping circuit in Question 18.

A. 0.055 inches per year
B. 0.005 inches per year
C. 0.550 inches per year
D. Not enough information given

20. A longitudinal crack in an existing piping circuit may be repaired by:

A. installing a full encirclement welded split sleeve
B. welding a box over the cracked area
C. welding a box over the crack
D. using a full encirclement welded split sleeve, with the approval of the piping engineer.

21. Soil to air interface Zone of a partially buried pipe is defined as

A. 6 inches above and 12 inches below the soil surface
B. Pipe running parallel with the soil surface is also included
C. 12 inches below and 6 inches above the soil surface
D. A and B above

22. API 570 was developed for

A. Petroleum refining and chemical process industry
B. Ship building industry
C. Power plant industry
D. Construction Industry

23. API 570 shall be used as a substitute for the original construction requirement governing a piping system before it is placed in service wherever possible.

A. True
B. False

24. API 570 applies to the piping systems for

A. Process fluids
B. Hydrocarbons and similar flammable and toxic fluid service
C. Sour water and hazardous waste streams above threshold limit
D. All of the above
E. Only A and B

25. Excluded and Optional piping system to API 570 requirements are

A. Fire water system
B. Hazardous fluid service below the threshold limit as defined by jurisdictional requirement.
C. Steam and boiler feed water service
D. Category D fluid service
E. All of the above

26. A imperfection of a type or dimension exceeding the acceptable criteria is defined as

A. Defect
B. Discontinuity
C. Lack of continuity
D. All of the above

27. The test point area for a8 “ NPS pipe is

A. 3” Dia Circle
B. 2” Dia Circle
C. 5” Dia Circle
D. None of the above

28. Who shall control activities related the repair, rerating and alteration of the piping system

A. Owner or User
B. Authorized Inspection Agency
C. Approved Inspection Agency
D. Any authorized piping Inspector

29. Who shall control the inspection program, frequency and maintenance of the Piping System?

A. Owner or User
B. Authorized Inspection Agency
C. Approved Inspection Agency
D. Any authorized piping Inspector

30. Who shall be responsible for the functions of the authorized Inspection Agency?

A. Owner or User
B. Authorized Inspection Agency themselves
C. Approved Inspection Agency
D. Any authorized piping Inspector
E. Regulatory authority or Class

31. As regards dead legs in piping circuits, what is recommended to be done by API 570 when ever possible?

A. Dead legs should be monitored on a monthly basis.
B. The chief inspector and the unit engineer should designate dead legs to be inspected.
C. Dead legs should be monitored on a yearly basis
D. Consideration should be given to removing dead legs that serve no further process purpose.

32. Which of the following is an not an example of environmental cracking?

A. Chloride SCC of austenitic stainless steels
B. Polythionic acid SCC of sensitized austenitic alloy steels.
C. Carbonate SCC. D. Low Temperature SCC.

33. An example of where creep cracking has been experienced in the industry is in;

A. 2-114 Cr steels above 800°F.
B. 1-114 Cr steels above 900°F.
C. 2-114 Cr steels above 900°F.
D. Chrome Vanadium steels above 1000°F.

34. Rerating piping systems is defined as;

A. changing the temperature rating.
B. changing the MAWP.
C. changing the temperature rating or the MAWP.
D. re-painting the pipe with the correct pressure and temperature

35. WFMT is

A. Wet Ferro magnetic testing
B. Wet Flourescent Magnetic Particle testing
C. Buried piping testing
D. Special internal testing

36. When preparing to inspect a piping system inspection personnel should?

A. Consult with the piping engineer.
B. Briefly review the history of individual piping systems before making any of the inspections required by API 570.
C. Check that repair materials are available.
D. Check that the corrosion engineer has reviewed the inspection plan.

37. As regards dead legs in piping circuits, what is recommended to be done by API 570 when ever possible?

A. Dead legs should be monitored on a monthly basis.
B. The chief inspector and the unit engineer should designate dead legs to be inspected.
C. Dead legs should be monitored on a yearly basis
D. Consideration should be given to removing dead legs that serve no further process purpose.

38. When is it necessary to reevaluate the frequency of inspection for an existing piping system?

A. The API 570 authorized inspector suspects a problem.
B. The operations group desires an increase in inspection frequency.
C. The inspection interval must be reviewed and adjusted as necessary after each inspection or significant change in operating conditions.
D. More than one flange has started to leak.

39. The selection of TMLs within injection point circuits are established at four basic locations, three of which are:

 TMLs on appropriate fittings within the injection point circuit.
 TMLs on the pipe wall at the location of expected pipe wall impingement of injected fluid
 Establish TMLs at both the upstream and downstream limits of the injection point circuit.
What is the fourth consideration when selecting TMLs

A. TMLs at intermediate locations along the longer straight piping within the injection point circuit may be required
B. TMLs at extreme locations along the longer straight piping within the injection point circuit may be required
C. TMLs at pipe bends within the longer straight piping in the injection point circuit may be required
D. TMLs at pipe bends within the shorter straight piping in the injection point circuit may be required

40. When the inspector suspects or is advised that specific circuits may be susceptible to environmental cracking, the inspector should schedule supplemental inspections. What types of inspections may this include?

A. Radiography.
B. Wet Fluorescent Magnetic Particle NDE.
C. Ultrasonic NDE.
D. Radiography, Wet Fluorescent Magnetic Particle, and/or Ultrasonic examinations.

41. Suplemental inspection for piping systems are sometimes required. Which of the following may be considered supplements to normal inspection techniques?

A. Annual hydrostatic testing.
B. Eddy current testing.
C. Spool piece removal and visual inspection
D. Periodic use of radiography and/or thermography to check for fouling or internal plugging.

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1. The purpose of the WPS and PQR is to determine that:

A. The welder is qualified
B. The base metals are strong enough
C. The weldment has the desired properties
D. The skill of the welder

2. The WPS lists:

A. Non-essential variables
B. Essential variables
C. Ranges of a & b above
D. All of the above

3. The PQR must list:

A. essential variables
B. qualification test & examination results
C. supplementary essential variables (when notch toughness is required)

4. What is the earliest Edition of Section IX recognized by the current edition?

A. 1958
B. 1992
C. 1987
D. 1962

5. New Welding Procedure Specifications must meet the _________ Edition and Addenda of Section IX.

A. 1962
B. current
C. 1986
D. 1995

6. Each ___________ shall conduct the tests required by Section IX to qualify the WPS’s used during the construction, alteration, or repair.

A. Welder or welding operator
B. Manufacturer or contractor
C. Inspector
D. All of the above

7. The records of procedure, welder and welding operator qualification must be available to the __________.

A. Manufacturer
B. Welder
C. Authorised Inspector
D. Foreman

8. A welder qualifying with a groove weld in plate in the 4G position is qualified to weld groove welds in plate and pipe over 24”O.D. in at least the ________ positions.

A. Vertical
B. Flat & horizontal
C. Flat & overhead
D. Horizontal

9. A welder qualifying with plate fillet welds in the 3F and 4f positions is qualified to weld groove welds in plate in the ____________ positions.

A. Flat only
B. Flat and horizontal
C. Flat and vertical
D. None of the above

10. A welder qualifying by making a groove weld on pipe with an O.D. of ¾” in the 5G position is qualified to weld groove welds in:

A. ½” O.D. Pipe in the overhead position
B. 6” O.D. Pipe in the vertical position
C. ¾” O.D. pipe in the horizontal position
D. None of the above

11. In general, qualification on groove welds also qualifies a welder to make:

A. Stud welds
B. Overhand welds
C. Fillet welds
D. All of the above

12. Charpy V-notch tests are performed to determine a weldment’s

A. Tensile strength
B. Ductility
C. Notch toughness
D. All of above

13. A welder making a groove weld using the SAW process on P1 materials may be qualified using radiography.

A. True
B. False

14. When a tensile specimen breaks in the base metal outside of the weld or fusion line, the strength recorded may be at most ____ below the specified tensile and be accepted.

A. 3.5%
B. 0.5%
C. 5%
D. All of the above

15. Guided-bend specimens shall have no open defects in the weld or heat effected zone exceeding __________ measured in any direction on the convex surface of the specimen after bending.

A. 1/16”
B. 3/32”
C. 1/8”
D. None of the above

16. When using radiographs to qualify welder, the acceptance standards used are found in:

A. ASME Section V
B. ASME Section IX
C. ASME Section VII
D. The referencing code

17. A WPS must describe:

A. Essential variables
B. Nonessential variables
C. Supplementary essential variable when required for notch toughness
D. All of the above

18. A PQR must describe:

A. Nonessential variables
B. Essential variables
C. Results of Welder Qualification tests
D. Project description & NDE methods

19. The _______ must certify the PQR as accurate.

A. Inspector
B. Manufacturer or contractor
C. Welder
D. All of the above

20. For the SMAW process ____________ is an essential variables for the WPS.

A. Groove design
B. Post Weld Heat Treatment
C. Root spacing
D. Method of cleaning

21. For the SAW process ______________ is an essential variable for the WPS.

A. Supplemental powdered filler metal (if used)
B. Filler metal diameter
C. Preheat maintenance
D. Addition or deletion of peening

22. The basic purpose of testing a welder is to establish the welder’s _____________.

A. Knowledge of welding requirements
B. Ability to deposit sound weld metal
C. Mechanical ability to operate equipment
D. General attitude toward welding inspectors

23. The record of a welder’s performance test is called a _______.

A. PQR
B. WQR
C. WPS
D. WPQ

24. If a welder qualified with the SMAW process on Jan. 1, 1994 and last welded with SMAW on March 15, 1994, would he still be qualified on October 7, 1994?

A. Yes
B. No.

25. A welder qualifying with a groove weld welded from both sides is qualified to weld ________________.

A. Without backing
B. With all base metals
C. With backing only
D. With P1 backing only

26. Immediate retests of welders’ qualifications coupons:

A. Must use the same method
B. May use any method
C. Are not allowed
D. Require Inspector approval

27. Welder performance qualification records must describe all the ___________ variables specified.

A. Essential & nonessential
B. Nonessential
C. Essential
D. Brazing

28. A welder depositing ½” of weld metal with the SMAW process is qualified to deposit up to ____________ of weld metal.

A. 8”
B. Max to be welded
C. 1” D. ½”

29. “P” numbers are used to designate groups of:

A. Electrodes
B. Flux
C. Base metals
D. Joints

30. A welder qualifying by welding P-No. 21 to P-No.21 is qualified to weld:

A. P-1- P-11 to P-1 – P –11
B. P-8 – P8
C. P-21 – P-25 TO P-21-P-25
D. P21 to P21 only

31. Welding electrodes are grouped in Section IX by:

A. AWS class
B. ASME specification
C. SFA
D. “F” number

32. Ferrous weld metal chemical composition may be designated using:

A. “P” number
B. Welder I.D.
C. “A” number
D. Page number

33. For welder qualifications with the SMAW process _________ is an essential variable.

A. Base metal thickness
B. Peening
C. P-number
D. Electrode diameter

34. Each welder must be assigned a(n):

A. P number
B. Unique identifier
C. Hood & gloves
D. Inspector

35. May a welder, qualified in the 2G position on ¼ inch thick plate, weld a 1 inch outside diameter pipe, ¼ inch thick in the horizontal position without re-qualification?

A. Yes
B. No
C. Not enough information provided
D. Yes, provided pipe is carbon steel, P#1

36. What is the difference between gas metal arc-welding and gas tungsten arc-welding processes?

A. GMAW uses a continuously fed filler metal as electrode and GTAW a tungsten electrode
B. The SFA specification of the filler metal
C. The F-number of the filler metal
D. GTAW is run with gas; gas is optional with GMAW

37. A welder has been tested in the 6-G position, using as E-7018 F-4 electrode, on 6” Sch 160 (0.718” nom) SA 106B pipe. Is this welder qualified to weld a 2” 300# ANSI schedule 80 bore flange to a 2” Schedule 80 SA 106 B nozzle neck?

A. Yes
B. No
C. Not enough information provided
D. Yes, provided a backing strip is provided in the 2” weld.

38. May a welder who qualified using a doublegroove weld, make a single V-groove weld without backing?

A. Yes
B. No
C. Not enough information provided
D. Yes, because backing is not an essential variable for a welder

39. May a GTAW welder be qualified by radiography, in lieu of bend tests? The test coupon will be P-22 material and the production welds will be P-22 also.

A. Yes
B. No
C. Not enough information provided
D. Yes, provided the P-22 is welded with F22 fillers

40. Who is responsible for qualification of welding procedures, welders and welding operators?

A. The Inspector
B. The A.I.
C. The Shop Foreman
D. The Manufacturer of Contractor

41. A welding electrode has the marking E-6010. The “1” marking indicates:

A. Flat position only
B. Horizontal position only
C. All positions
D. Only good for heat treated welds

42. May a FCAW welder qualified using UT, be used to weld in production?

A. Yes, welder can be used
B. No welder cannot be used
C. Yes, if welder is using GMAW (Short Arc)
D. Yes, if welder is qualified with backing

43. A welder may deviate from the parameters specified in a WPS if they are a nonessential variable.

A. True
B. False

44. What is the number of transverse guided bend tests required for Performance Qualification in a 6G position?

A. 2
B. 4
C. 6
D. 3

45. What positions are necessary to qualify a welder for all position pipe welding?

A. 3G and 4G
B. 2G and 5G
C. 3G and 1G
D. 4G and 5G

46. What ASME Code Section has welding electrode storage requirements?

A. ASME IX
B. ASME VIII
C. ASME B31.1
D. ASME II Part C

47. A repair organization has a WPS which states it is qualified for P-8 to P-8 material welded with E308, E308L, E309, E316, electrodes (SMAW process). The PQR, supporting this WPS, states the weld test coupons were SA240 Type 304L material, welded with E308 electrodes. Is the WPS properly qualified for the base material listed?

A. Yes
B. No
C. Not enough information given
D. Yes, if properly heat treated

48. May a GMAW, short circuit transfer, welding procedure be qualified using realtime ultrasonics?

A. Yes
B. No C. Not enough information given
D. Yes, provided bend tests are done

49. Three arc-welding processes are:

A. BMAW, SMAW, EFGAW
B. FCAW, SAW, ESW
C. SMAW, GTAW, PAW
D. PTAW, SLAW, PEAW

50. A welder was qualified with a P-1 test coupon using SMAW E 7018 electrodes. May the welder weld P-4 material using E8028 electrodes with backing in production? (Assume the P-4 procedure using E8028 electrodes has been qualified)

A. Yes
B. No
C. Not enough information provided
D. None of the above

51. Is a welding procedure qualified under the 1965 ASME Code Section IX still applicable?

A. Yes
B. No, must be re-qualified
C. Is only applicable for 1965 pressure vessels
D. Cannot be used for new construction – repairs only

52. What are the various positions in which a welder may qualify for plate groove welds?

A. 1G
B. 3G
C. 4G
D. All of the above

53. You are reviewing a WPQ (QW-484) for a welder testing in the 6-G position, on SA-53 grade B pipe (TS-60,000 psi). The test results indicate the following: No.1 Tensile developed 51,000 psi, broke in the weld No.2 Tensile developed 56,900 psi, broke in base metal No.1 Transverse root bend satisfactory No.2 Transverse face bend satisfactory Will this test qualify the welder?

A. Yes
B. No
C. Not enough information given
D. Tension test is acceptable but No.1 is unacceptable

54. What are the primary classifications of guided-bend tests permitted by the Code?

A. Side and Transverse
B. Face and Root
C. Transverse and Longitudinal
D. Side and Face

55. A welder qualified by welding in the 5G position is qualified for what position on plate?

A. F,H,OH
B. F,V,OH
C. V,OH,SP
D. H,V,OH

56. Which of the following is a covered electrode?

A. E6010
B. E7018
C. E9028
D. All of the above

57. Applicable essential variables must be documented on which of the following?

A. The WPS
B. The PQR
C. The WPQ
D. All of the above

58. In performance qualification of pipe welds to ASME Section IX, which positions require more than two guided bend specimens for qualification?

A. 5G and 6G
B. 2G and 4F
C. 4G and 5G
D. None of the above

59. Name two defects that would cause visual rejection of a welder’s test pipe or plate?

A. Porosity, underfill
B. Lack of penetration/fusion
C. Slag, overlap D. Any of the above

60. A variable that, when changed will cause a change in the mechanical properties of the weldment is called a:

A. Essential variable
B. Non-essential variable
C. Supplementary essential variable
D. All of the above

61. The test that determines the ultimate strength of groove-weld joints is a:

A. Notch Toughness Test
B. Tension Test
C. Fillet Weld Test
D. Guided-Bend Test

62. The procedure qualification test is used to determine:

A. The skill of the welder
B. That the proposed production weldment is capable of having the required properties
C. The corrosion-resistance of the proposed weldment
D. None of the above

63. A change in a supplementary essential variable requires re-qualification, when notch-toughness is a consideration.

A. True
B. False

64. When using Macro-examination of fillet weld tests, the weld and the HAZ must not reveal cracks when magnified at:

A. 5X
B. 2X
C. 10X
D. No magnification is required – visual examination is required, only

65. A non-essential variable may be changes without re-qualification because:

A. Nobody cares about non-essential variables
B. The welder is allowed to change variables at his discretion
C. Non-essential variables do not affect the mechanical or notch-toughness properties
D. Non-essential variables cannot be changes without re-qualification

66. A WPS must only address essential and, if applicable, supplementary essential variables.

A. True
B. False

67. The data recorded on a PQR (non-editorial) may be changed provided :

A. The AI approves
B. The test data on a PQR is a record of what occurred and should never be changed. Only editorial information can be changed on a PQR.
C. The API 510 inspector approves
D. The date of the WPS is changed

68. Tension tests may be used in lieu of bend tests to qualify welders or welding operators.

A. True
B. False

69. A groove weld bend test reveals a linear indication on the face of the bend surface that measures exactly 1/8” long. No other indications are seen. Does this coupon pass or fail?

A. Pass
B. Fail

70. Unless notch-toughness is a consideration, a qualification in any position qualifies a welding procedure for all positions.

A. True
B. False

71. The purpose of a WPS and PQR is to determine if a welder has the skill necessary to make sound production welds.

A. True
B. False

72. Welders can be qualified by radiograph when using P 6X materials?

A. True
B. False

73. It is permissible to sub-contract welding of coupons as well as other work to prepare coupons.

A. yes
B. No

74. Variable QW 402.4 for SMAW procedure qualification is a ___________ variable.

A. Essential
B. Non-essential
C. Supplemental essential
D. None of the above

75. Variable QW 404.24 for SAW procedure qualification is an ____________variable.

A. Essential
B. Non-Essential
C. Supplemental essential
D. None of the above

76. Each manufacturer must certify the PQR (by signature) indicating that the information given is true and correct.

A. True
B. False

77. Welder variable QW-405.1 (for welder qualifying with the SMAW process) is a __________ variable.

A. Essential
B. Non-essential
C. Supplemental essential
D. None of the above

78. The purpose of a WPS and PQR is to determine if a proposed weldment to be used in construction is capable of providing the required properties for the intended application.

A. True
B. False

79. A qualification in a 4G position qualifies a welder for all groove weld positions.

A. True
B. False

80. A WPS must address all applicable nonessential variables.

A. True
B. False

81. Groove weld coupons shall be tested by macro-examination when qualifying a welding procedure.

A. True
B. False

82. A welding procedure must be qualified with impact tests only when required by the applicable construction code, such as ASME VIII Div.1.

A. True
B. False

83. A welder qualified to weld in the 2G position on pipe would have to be qualified in which of the additional positions to qualify for all position groove welding on pipe?

A. 1G
B. 2G
C. 5G
D. 6G
E. All of the above

84. The maximum preheat temperature decrease allowed without re-qualification of a GMAW groove weld procedure is:

A. 500F
B. 1000F
C. 1250F
D. 1500F
E. None of the above

85. A welder is qualified to weld all thicknesses of material when:

A. The test is any thickness above 3/8 inch
B. The test thickness was ½ inch
C. The test thickness was ¾ inch or over
D. The test pipe wall thickness was 5/8 inch and nominal pipe size was over ½ inches

86. What is the maximum defect permitted on the convex surface of a welder qualification bend test after bending except for corner cracks and corrosion resistant weld overlay?

A. ¼ inch
B. 1/8 inch
C. 1/16 inch
D. 3/16 inch
E. No defects are allowed

87. What period of inactivity from a given welding process requires the welder to requalify in that process?

A. 3 months
B. 6 months
C. 9 months
D. 12 months
E. As stated by the AI

88. Notch-toughness requirements are mandatory:

A. For heat treated metals
B. For quenched and tempered metals
C. For hardened and tempered metals
D. For annealed and tempered metals
E. When specified as required by the referencing Code Section

89. A welder qualified for SMAW using an E7018 electrode is also qualified to weld with:

A. E7015
B. E6011
C. E6010
D. E7024
E. All of the above

90. Macro examination of an etched fillet weld section for performance qualification is acceptable if the examination shows:

A. Complete fusion and freedom from cracks, excepting linear indication not exceeding 1/32 inch at the root.
B. Concavity or convexity no greater than 1/16 inch
C. Not more than 1/8” difference in leg lengths
D. All of the above
E. Both B and C above

91. Each manufacturer or contractor is responsible for the welding or brazing done by his organization. Whenever these words are used in Section IX, they shall include:

A. Designer or architect
B. Designer or installer
C. Architect or installer
D. Installer or assembler
E. Assembler or designer

92. For P-11 materials, weld grooves for thicknesses ___________ shall be prepared by thermal processes, when such processes are to be employed during fabrication.

A. Less than 5/8 inch
B. 5/8 inch C. 1 inch
D. 1 ¼ inches
E. None of the above

93. A SWPs may be used in lieu of a manufacturer qualified WPS when:

A. Approved by the Inspector’s Supervisor
B. Allowed by ASME V
C. One test coupon is tension tested per Article V
D. Compliance to Article V and Appendix E of ASME IX is shown

94. A change in a non-essential variable requires recertification of the PQR

A. True
B. False

95. Reduced-section tensile test specimens conforming to QW-462.1 (b) may be used on all thicknesses of pipe having an outside diameter greater than:

A. 2 inches
B. 21/2 inches
C. 3 inches
D. 31/2 inches
E. 4 inches

96. Groove weld test may be used for qualification of welders. Which of the following shall be used for evaluation?

A. Only bend tests
B. Only radiography
C. Both radiography and bend tests
D. Either bend tests or radiography
E. None of the above

97. Under which of the following conditions can a welder be qualified during production work?

A. A 6” length of the first production groove weld may be qualified by radiography
B. A bend test coupon may be cut from the first 12” length of weld
C. A macro examination may be taken from the first 3” of weld length
D. None of the above

98. Two plate tensile test specimens have been tested and found to be acceptable. The characteristics of each specimen are as follows: Specimen 1: Width of 0.752”; thickness of 0.875”; ultimate tensile value of 78.524 psi Specimen 2: Width of 0.702”; thickness of 0.852”; ultimate tensile value of 77,654 psi What is the ultimate load for each specimen that was reported on the laboratory report?

A. 51,668 & 46,445
B. 67,453 & 56,443
C. 78,524 & 77,654
D. None of the above

99. Which of the following welding processes are currently not permitted to be used with SWPs as referenced in Appendix E of ASME IX?

A. GMAW
B. SAW
C. PAW
D. All of the above

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1. In the Barlow formula for determining pipe thickness, the term S stands for:

a. Internal design gage pressure of the pipe in psi
b. Pressure design strength for internal pressure, in inches
c. Allowable unit stress at the design temperature, in psi 
d. Maximum strain at the average operating temperature, in psi

2. At low pressures and temperatures, the thickness determined by the Barlow formula may be so small that the pipe would have _______ structural strength.

a. Adequate
b. Insufficient 
c. Ample
d. Good

3. A seamless NPS 12, A-106 Grade A pipe operators at 300 degrees F and 941 psi. The allowable stress is 16000 psi. Using the Barlow Equation, determine the thickness required for these conditions.

a. 0.375” 
b. 0.750”
c. 0.353”
d. 0.706”

4. A seamless NPS6, A-106 Grade A pipe operators at 300 degrees F and 941 psi. The allowable stress is 16000 psi. The owneruser specified that the pipe must have 0.1” allowed for corrosion allowance. Using the Barlow Equation, determine the thickness required for these conditions:

a. 0.295” 
b. 0.195”
c. 0.277”
d. 0.706”

5. A seamless NPS 8, A-53 Grade B pipe operators at 700 degrees F and 700 psi. The allowable stress is 16500 psi. The pipe has been in service for 6 years. The original wall thickness of the pipe was 0.375”. The pipe wall now measures 0.30”. Considering no structural requirements, estimate how long the piping can continue to operate and not be below the minimum thickness.

a. 4.68 years
b. 9.8 years 
c. 0 years; pipe now below minimum
d. 10.42 years

6. An Inspector finds a thin area in the body of a NPS 8 (8.625” O.D.) 600# gate valve. The valve’s body is made from ASTM A216 WCB material. The system operates at 700 psi and 750 degrees F. Using a corrosion allowance of 0.125”, what thickness must be present in order to continue to safely operate? Round to nearest hundredth.

a. 0.48”
b. 0.38”
c. 0.51”
d. 0.43”

7. If corrosion or erosion is anticipated for a valve, what should be done prior to installing the valve?

a. Severance thickness determinations should be made when the valves are installed so that the fretting rate and metal ruination can be determined
b. Retirement thickness measurements should be made after installation so that the fatigue rate and metal loss can be determined
c. Reference thickness measurements should be made when the valves are installed so that the corrosion rate and metal loss can be determined 
d. Retina measurements of the macula should be made when the iris’ are installed so the optical rate and losses of perception can be determined

8. Which of the items listed below would NOT normally be contained in inspection records or piping?

a. Original date of installation, the specifications and strength levels of the materials used
b. Original vessel hydrotest pressures and conditions that the tests were performed under 
c. Original thickness measurements and the locations and dates of all subsequent readings
d. Calculated retirement thicknesses

9. Accurate records of a piping system make possible an evaluation of __________ on any piping, valve or fitting:

a. Computerisation
b. Security and continuity
c. Cost and competency
d. Service life 

10. You are working as an inspector. While reviewing a tabulation of thickness data on a section of piping in non-corrosive or very low corrosive service, you find the initial thickness reading of an inspection point to be 0.432” and marked nominal on a NPS 6 pipe. At the next inspection 12 months later you find a reading by ultrasonics of 0.378” at the same point. Twelve months later UT readings were taken and the thickness at the point was still 0.378”. What would this mean to you?

a. No measurement was taken originally, the nominal thickness was listed and the piping probably had an undertolerance of 12.5”
b. There was an error made by the inspector at the installation or the inspector who UT’d the piping at the next inspection made an error
c. The UT machine that the inspector used during the 12 month inspection after installation was defective and not reading correctly
d. The pipe contractor or the installer put the wrong schedule piping in service

11. You are working as an inspector. While reviewing a tabulation of thickness data on a section of piping, you find the letter “C” marked under a column headed by the word METHOD. What does the “C” indicate?

a. The inspection temperature of the pipe was COLD
b. The thickness measurement was made by an inspector with the I.D. OF “C”
c. The thickness measurement was taken with calipers
d. The thickness measurement was CONFIRMED by a second party

12. Which of the following is not an important function of an accurate sketch?

a. Assist in determining future locations that urgently require examinations
b. Identifying systems and circuits in terms of location, size, materials etc
c. Serve as field data sheets
d. None of the above

13. As soon as possible after completing an inspection, the Inspector should:

a. Review the inspection records and schedule the next inspection 
b. Always require a hydrotest
c. Sign all RT records
d. Notify the Piping Engineer, so he can wake up and go home

14. The Wenner 4-Pin methods, the soil bar, and the soil box do not represent methods of determining:

a. Holidays
b. Pipe-to-soil potentials
c. Cathodic protection acceptability
d. All of the above 

15. The total resistivity for a Wenner 4-Pin test that utilizes pins spaced 2 feet apart and a 6 “R” factor is:

a. 2298 ohm/cm 
b. 3500 ohm/cm
c. 6000 ohm/cm
d. 8000 ohm/cm

16. Which of the following is not a consideration when using a soil bar?

a. Using a standard prod bar
b. Avoiding the addition of water
c. Applying pressure on the soil bar after injection
d. None of the above 

17. Which of the following is a consideration when using a soil box:

a. Depth of Pins less than 4% of spacing
b. Ensuring the soil has dried out before testing
c. Avoiding contamination of the sample during handling and storage 
d. All of the above