API 653 Exam Chapter 8

API 653 Exam Chapter 8 – Tank Non-destructive Examination

Non-destructive examination (NDE) of storage tanks is a subject of direct relevance to tank inspections. Although an API inspector would rarely perform NDE themselves (the NDE technician or API-termed ‘examiner’ does that) it is the role of the inspector to specify the scope, check the technique, and evaluate the results. In the context of the API 653 ICP, NDE questions form a sizeable chunk of the body of knowledge (BOK) and appear, fairly predictably, as exam questions of several sorts.

Let us start with these points about the NDE coverage of API 653:

The NDE content of API 653 nearly all relates to tank repairs.

The requirements supplement the fuller coverage in the tank construction code API 650. They are necessary to fill in the gaps, as API 650 is about new construction, so does not cover in-service repairs.

There are two, almost completely separate, parts to storage tank NDE. The techniques and technical details (covered in ASME V), and scope or extent of NDE that is required, which is found in API 653 itself.

The NDE content of API 653 is separated into two parts. More than 90% is found in section 12: Examination and Testing, catalogued by area of the tank. This is then summarized by techniques (VT, PT, UT, etc.) in Annex F: NDE Requirements Summary near the back of the code.

Figure 8.1 below summarizes the situation. Note how strictly (as clearly stated in API 653 (12.1.1.1)) the source code for NDE compliance is actually the new construction code API 650. In practice, this tends mainly to influence tanks that are being reconstructed (cut up and reassembled somewhere else), as these are effectively treated as if they are new-build

Figure 8.1 The tank NDE scope of API 653 and 650
Figure 8.1 The tank NDE scope of API 653 and 650

tanks. In most practical in-service inspection/repair/alteration scenarios the relevant NDE requirements are not fully covered in API 650, and API 653 steps in to take over (and take priority).

8.1 The ideas behind API 653 section 12: examination and testing

Although API 653 section 12.1 is set out as a long list of uninspiring ‘100% NDE’ text clauses (with no diagrams) the overall technical ideas behind it are quite straightforward.

Visual inspection. Almost all welding activity requires visual testing (VT) at stages before, during and after the welding.

Crack detection. Completed fillet welds (patches, reinforcing plates, etc.) are checked for cracks by PT/MT, as well as the usual VT.

Butt welds. Used for shell insert patches, plate replacement and similar, these require volumetric NDE to check for cracks and other defects inside the weld.

Parent material. This will be welded and must be free of defects. The main scenarios are:

  • After removal of attachments: visual/PT/MT for surface cracks (12.1.4.1, 12.1.2.2, 12.1.8.2, etc.) 
  • Before welding penetrations: shell requires UT for laminations (12.1.2.1, 12.1.8.1).
  • After grinding out of defects and backgouging the cavities: need visual/PT/MT for surface cracks (12.1.3.1).

These fairly general points actually consume quite a lot of the text clauses of API 653 section 12.1. It is probably easier to remember their principles (have a look at Figs 8.2 and 8.3) than the fragmented way they are set out in section 12.1. Remember that they are also repeated in API 653 Annex F.

8.2 Weld leak testing

API 653 section 12 explains four methods of leak testing in repaired/new welds. The purpose of these is to make sure there are no leak paths existing through the welds that would cause a leak when the tank is put into service. Note two important points about these tests:

They are in addition to the usual VT/PT/MT surface crack detection used on (mainly fillet) welds.

They are designed to be more searching than the hydrostatic test. Water is notoriously poor at finding its way through tight or staggered cracks, and will often not

Figure 8.2 API 653: NDE content
Figure 8.2 API 653: NDE content

show leaks that are easily detectable using more searching methods.

API 653 section 12 is quite careful in the way in which it recommends each of the techniques for the application to which it is best suited. The way in which this is presented in the code text does not exactly make it jump out at you, but it

Figure 8.3 Some general principles of tank repair/NDE
Figure 8.3 Some general principles of tank repair/NDE

is there. Figure 8.4 shows the idea and Fig. 8.5 shows the techniques in more detail.

8.2.1 Vacuum box testing (F5)

This is done using a right-angled box surrounded by rubber seals. It is placed over repair welds and a vacuum drawn inside the box. Any air leaking in through weld cracks soon shows up as an increase in pressure. See API 650 (8.6.1) for procedure details.

Figure 8.4 Weld testing methods
Figure 8.4 Weld testing methods

8.2.2 Diesel oil ‘wicking’ test (F7)

API 650 sees this as an alternative to a vacuum box test. Section 12.1.6 is a good example – it specifies either a vacuum box or diesel oil test on a completed shell-to-bottom fillet weld. This works by simply painting diesel oil on to one side of a weld and seeing if, over a minimum period of 4 hours, it creeps through to the other side by capillary ‘wicking’ action though penetrating cracks or other defects. Spreading chalk or similar powder on the weld helps show when the diesel oil is creeping through.

Figure 8.5 Weld leak testing techniques
Figure 8.5 Weld leak testing techniques

8.2.3 Tracer gas testing (F6)

This is an extra-sensitive technique (again, an alternative to vacuum box testing) which can be used on new tank bottom welds. The gas (usually helium) is inserted under the tank bottom and sniffer detectors used to detect any leakage through to the top surface. Owing to the difficulty of constraining the gas to one side of the weld, this technique is normally only used for tank bottoms. It is such a sensitive technique that it can be very difficult to get welds totally leak free

8.2.4 Air leak testing (F8)

The main purpose of this test is for testing new nozzles/shell penetrations when they are fitted with reinforcing (compensation) pads. Air is introduced between the two plates, hence testing whether there are any leak paths in the fillet weld(s). Threaded air connection/bleed nipple holes are installed for this purpose.

As a special case the air test can be used as an alternative to diesel oil testing of the first pass of a new (or repaired) shell-to-bottom fillet weld. Figure 8.4 shows the details – note how weld ‘blockages’ need to be installed to isolate the area under test and how the air entry point and pressure sensing points must be at opposite ends of the part of the annulus being tested.

8.2.5 Weld radiography

API and ASME codes have long preferred RT to other volumetric methods such as shear-wave (angle probe) UT. This is probably partly because of the fact that RT gives a permanent record and partly for historical reasons, rather then necessarily its effectiveness in finding defects. In reality, doing RT on a plant where repairs are being carried out can be awkward owing to health and safety requirements so many operators prefer UT. In recent years, API codes have become more open to replacement of RT with UT, although their equivalent (ASME and API) construction codes have been slower to follow.

Fundamentally, the RT required by API 653 section 12 starts with that specified in API 650. Note where it says this in API 653 (12.2.1). This is then supplemented (added to) by the clauses of API 653 (12.2) – catering for repair and replacement activities that are not covered by API 650 (which is only about new construction). While the code clauses are not particularly memorable, the principle makes sense – site repair welds are rarely done under optimum conditions, so extra RT is a good idea to find any defects that may be caused as a result.

8.3 How much RT does API 650 require?

It all depends on the thickness of the shell. API 650 section 8.1.2: Number and Location of Radiographs sets out three scenarios: for shell plate material up to 10 mm, 10 mm to 25 mm and above 25 mm thick. It differentiates between vertical, horizontal and intersections and shows the requirements fairly clearly in the code Fig 8-1. For shells up to 10 mm thick in particular, the requirements are not that obvious, i.e.: .

For vertical welds: one spot RT in the first 10 ft and in each 100 ft thereafter, 25 % of which need to be at intersections. and .

For horizontal welds: one spot RT in the first 10 ft and in each 200 ft thereafter.

Look at API 650 Fig 8-1 for the full details.

8.4 How much RT does API 653 require?

You can be excused for being a little confused about this. While straightforward in concept, the clauses API 653 (12.2.1.1) to (12.2.1.6) look a bit daunting. To simplify it, think of shell plate welds as being of the following types:

  • ‘New construction’ type welds: i.e. new welds between new plates. This is exactly the same as new construction, so just follow API 650 (8.1.2) as API 653 has no additional requirements.
  • ‘Repair’ welds. These may be between either new-toexisting plates or existing-to-existing plates. Treat these as repair welds (with a higher risk), so they need some additional RT.

8.4.1 Key point – the difference between new plates and replacement plates

Do not get confused by this one:

  • 12.2.1.1 to 12.2.1.4 are about the situation where new shell plates are installed in a shell, to replace corroded ones. Figure 8.6 covers this scenario.
  • 12.2.1.6 and its subsection. This is about when plates are cut out to provide access doors (to allow work to be carried out inside the tank) and then rewelded up afterwards.

Figure 8.7 below shows this situation. Note how one less vertical weld RT shot is required than when fitting a new shell plate (i.e. 12.2.1.1b).

For thicker materials > 1 in the additional chance of defects means that full RT is required on vertical seams. In some cases, it is easier to cut out circular access doors than rectangular ones. This only requires 1 RT shot (see 12.2.1.6.1) unless, again, it is more than 1 in thick, when full RT is required.

Figure 8.8 shows what to do about reconstructed tanks.

8.4.2 What about exam questions?

It is easy to get overly excited about exam questions on RT. Surprisingly there are generally not that many about the required scope of RT for the multiple possible permutations of vertical, horizontal, intersection, new and repaired welds. One or two pop up in the open-book question section, typically one from API 650 and one from API 653. More common are questions from ASME V article 2 and API 577. These are of a more generic nature and often less technically rigorous than you might expect.

8.4.3 NDE procedures and qualifications

API codes (and their ICP exams) are littered with stuff about who needs to be qualified to what level and which procedures they should be working to. NDE activities are no exception.

Figure 8.6 RT of shell plate repairs
Figure 8.6 RT of shell plate repairs

These statements reflect a fairly consistent API view of the inspection world, but there is absolutely no reason why they should fit your situation.

API 653 Annex F provides the best summary of this information. Note how all NDE scopes from other chapters

Figure 8.7 RT of access door sheets
Figure 8.7 RT of access door sheets

are compiled together at the end of each subsection. Figure 8.9 is another way of presenting this.

Figure 8.8 RT of reconstructed tanks
Figure 8.8 RT of reconstructed tanks
Figure 8.9 NDE procedure requirements
Figure 8.9 NDE procedure requirements

Now try these practice questions.

8.5 Tank NDE: practice questions

1.

Q1. API 653: shell penetrations
What NDE must always be carried out before adding a hot tap connection to a shell plate?

 
 
 
 

2.

Q2. API 653: shell penetrations
A hot tap connection to a shell plate has been examined by PT. Under what circumstances should the use of UT or fluorescent MT also be considered?

 
 
 
 

3.

Q3. API 653: shell penetrations
What NDE is required on the completed welds of stress relieved assemblies?

 
 
 
 

4.

Q4. API 653: repaired weld flaws
What is the minimum level of NDE required on a completed butt weld repair?

 
 
 
 

5.

Q5. API 653: temporary and permanent shell attachments
How must completed permanent attachment welds be examined?

 
 
 
 

6.

Q6. API 653: shell to bottom weld
A welded-on patch plate is to be placed over a shell to the bottom weld. If the plate will cover 16 inches of the bottom weld, what length of the shell to bottom plate weld needs to be inspected before the patch is applied?

 
 
 
 

7.

Q7. API 653: bottoms
In addition to PT or MT, what testing is required for areas of bottom plates repaired by welding?

 
 
 
 

8.

Q8. API 653: number and location of radiographs
A new shell plate has been welded into an existing tank. The RT requirement is in accordance with API 650. What additional radiography will be required?

 
 
 
 

9.

Q9. API 653: acceptance criteria for existing shell plate welds
An intersection between a new and old weld contains defects unacceptable to the new standard. The defects are, however, acceptable to the original construction standard. Must they be repaired?

 
 
 
 

10.

Q10. API 653: marking and identification of radiographs
What does the letter R mean on a weld radiograph?

 
 
 
 

Click Here To Read Next API 653 Exam Chapter 9 –Tank Repairs and Alterations

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API 653 Exam Chapter 7

API 653 Exam Chapter 7- API 650: Tank Design

7.1 Reminder: the API 653 body of knowledge (BOK)

Strictly, the API 653 BOK and examination are about the in service life of storage tanks, i.e. that period after construction when relevant approvals and certification requirements have been completed. This is the same philosophy as the other two major ICPs: API 510 (vessels) and API 570 (pipework). The practical situation is a bit different. Whereas API 653 provides good coverage of inspection, repair, alteration and reconstruction (its title) it only contains a limited amount of technical data on shell and nozzle design. This is often needed for alteration and (particularly) reconstruction; hence there is a need for the BOK to fall back on the new tank construction code: API 650.

7.1.1 How much of API 650 is in the API 653 BOK?

This depends on how you look at it. API 650 is a good code, full of technical details. Its 400+ pages divide roughly 50:50 between the body of the code (sections 1 to 10) and a long procession of appendices (A to X) (see Fig. 7.1). It would be next to impossible to learn all of this volume of material. The API published BOK is not particularly useful in helping you decide which bits of API 650 you need to learn. The necessary information is there, but it does not exactly jump out of the page at you. To confuse the matter, part of it lists what is not in the BOK and then lists exclusions from these exclusions. Fortunately, the situation is simpler than it appears. Look at these guidance points:

Almost all of the exam questions sourced from API 650 appear in the open-book section of the exam. They have to, if you think about it, or candidates would need to learn all

Figure 7.1 The contents of API 650 11th edition: tank construction code
Figure 7.1 The contents of API 650 11th edition: tank construction code

of API 650, 400+ pages, most of which is fairly peripheral to the API 653 BOK.

Exam questions tend to be chosen from a few selected areas of API 650. They are surprisingly predictable – most are about:

  • Toughness requirements of materials
  • Allowable stresses in shell material and the resulting shell thickness
  • Arrangement and dimensions of shell nozzles/connections (particularly welds), roof fittings or foundations
  • A few specific bits in the appendices about elevated temperature tanks, stainless steel tanks or floating roofs.

Figures 7.2 and 7.3 below summarize the situation. Taken together these two figures show almost all of the exam question subjects that are sourced from API 650. Remember:

  • They are likely to be open-book questions.
  • The questions will either be about reconstructed tanks (API 653 section 10) or specifically mention new tanks.
  • There will be little technical interpretation involved – it is simply a case of picking bits of information from arrangement drawings or tables.

To help you anticipate the questions that can appear in the exam, we will look at the technical aspects in turn. Remember, again, that there is no great technical depth to the exam question content. Getting the correct answer is simply a matter of knowing where to look in the main sections or few relevant appendices of API 650.

7.2 API 650: material allowable stresses

We first saw this idea back in Chapter 6 of this book. All feasible shell materials are allocated an allowable stress value S, which is then used in a simple equation to calculate the minimum required thickness. There are two possible options

Figure 7.2 API 650 BOK content (1)
Figure 7.2 API 650 BOK content (1)

to choose from for each material – a slightly higher S value being used if the tank is to be hydrotested.

For calculating tmin for corroded existing tanks the table of S values in API 653 Table 4-1 is used. This makes sense as the tank is already built and no new shell components are being added. For new or reconstructed tanks, however (reconstruction is treated the same as a new build), Table 5-2 (a or b

Figure 7.3 API 650 BOK content (2)
Figure 7.3 API 650 BOK content (2)

of API 650 is used. This contains much the same range of material in a similar format to Table 4-1 of API 653 but the values are different.

7.2.1 Why do API 653 and 650 have different allowable stress (S) values?

Simply because they are different scenarios. API 650 is for new build, when the objective is to specify an S value that allows for a certain ‘factor of safety’. API 653 then takes over for the assessment of corroded tanks where the objective is to keep the tank in operation. It does this by using up some of the margin that was previously provided by the API 650 S value. Hence the S values in API 653 Table 4-1 are higher, by about 10–20 %, depending on the material.

Here it is again, so you do not get confused:

API 650 Table 5-2 contains S values to be used for new build or reconstructed tank calculations. The figures come from the percentages of yield (Y) and tensile (T) values specified by API 650 (5.6.2.1), i.e. 66 % Y or 40% T, whichever is less. They are the same for all shell courses.

API 653 Table 4-1 contains S values to be used for the assessment of existing corroded tanks. The figures come from the higher percentages of yield (Y) and tensile (T) values specified by API 653 (4.3.3.1). They are the smaller of 80 % Y or 42.9 % T for the lower two shell courses and the smaller of 88 % Y or 47.2% T for all the other courses.

Look back at Fig. 6.5 of this book and you can see this comparison expressed in a table.

Figure 7.4 shows how both API 650 and 653 present this S data. Most API 653 exams contain questions that require you to pick out S values from one of these tables, so just use this guideline: 

If the question refers to the evaluation of existing corroded tanks, use the S values from API 653 (Table 4-1) and note which shell courses are referred to but .

If the question mentions reconstructed or newbuild tanks, use the S values from API 650 (Table 5-2) and always .

Watch for whether the question mentions a hydrotest or not, as that will affect the values to use.

Figure 7.4 S values from API 650 and 653
Figure 7.4 S values from API 650 and 653

7.3 API 650: material toughness requirements

As well as strength, API codes are always concerned with material toughness. It is toughness (not ductility), that provides the resistance to brittle fracture either during hydrotest or in cold conditions. API 653 section 5 has its own crude assessment of the risk of brittle fracture during hydrotest but API 650 covers it in more detail for use at the newbuild or reconstruction stage.

In common with most other API (and ASME) codes, API 650 uses a straightforward routine for assessing toughness. It is based on the premise that some combinations of material, thickness and minimum design temperature do not require impact testing because previous experience dictates that there will be no problem with brittle fracture; i.e. toughness is adequate. Conversely, if the material/thickness/temperature combination does not meet the necessary threshold levels, then impact testing is required to test whether the material has sufficient toughness or not. Impact (Charpy) specimens are tested in groups of three specimens and the results compared with minimum single and average reading requirements given in a table in the code.

The API 650 method (see Fig 7.5 below) is set out in section 4 of the code and is as follows:

Step 1. For a given material, identify its group number (I to VI) from API 650 Table 4-4(a or b). Be careful to note if the material is ‘killed’ and/or normalized as this can affect its group. Watch out for information given in the notes at the bottom of the table also.

Step 2. For a given location in the USA determine the lowest one day mean (average) temperature (LODMAT) from the map in API 650 Fig. 4-2.

Step 3. Go to the graphs in API 650 Fig. 4-1 and plot the LODMAT temperature against the thickness of the material in question, then compare it with the line on the graph for the current material group. .

Step 4. If the plot point on the API 650 Fig. 4-1 graph falls above the line for the material group, impact tests are not needed as brittle fracture is not considered likely.

Step 5. If the plot point on the Fig. 4-1 graph falls below the line for the material group then the material must be impact tested to see whether it has adequate toughness or not. The acceptance values are shown in Table 4-5 of API 650 and range from 20 to 68 J (15–50 ft-lb) depending on material group, thickness and the orientation of the

Figure 7.5 API 650 brittle fracture assessment
Figure 7.5 API 650 brittle fracture assessment

specimen taken from the parent metal plate. All test results are calculated from the average of three test specimens

7.4 Tank component arrangement and sizes

The second API 650 topic that is included in the API 653 BOK covers acceptable material/weld sizes and arrangements for some of the major tank components. As a construction code, API 650 contains a lot of detailed technical requirements about how to attach nozzles and other fittings to the shell, roof and bottom. There are several thousand of these requirements, compressed into a family of full-page arrangement drawings, many further qualified by referenced tables of data. These tables mainly cover material thickness, pipe schedules, minimum weld sizes and such like. Fortunately, not all are in the API 653 BOK. The main ones that are included are:

  • Shell manholes API 650 Fig. 5-7 and Tables 5-3 to 5-5
  • Shell nozzles API 650 Fig. 5-8 and Tables 5-6 to 5-9
  • Shell nozzles near weld seams API 650 Fig. 5-14
  • Minimum spacing of welds API 650 Fig. 5-9
  • Shell connections flush with the bottom API 650 Fig. 5-14
  • Draw-off sumps API 650 Fig. 5-21 and Table 5-16
  • Clean-out fittings API 650 Fig. 5-12 and Table 5-9
  • Roof manholes API 650 Fig. 5-6 and Table 5-13
  • Roof rectangular hatches API 650 Fig. 5-17
  • Flanged roof nozzles API 650 Fig. 5-19
  • Threaded roof nozzles API 650 Fig 5-20

7.5 Some tips on exam questions

The API 653 examination frequently contains questions taken from the long list of figures and tables above. There are normally only a handful, however, and the exam questions that can be asked are constrained by:

  • The exam questions do not reproduce drawings from API 650, so they have to rely on text or data tables to get their questions.
  • It is surprisingly difficult to ask a question, in text form, about something on a drawing unless it is kept very simple. Questions are commonly therefore about material thickness, weld size or some angle or other that can be picked out of one of the API 650 figures without too much chance of misinterpretation.

7.6 Finally: bits and pieces from the API 650 appendices

Very little of the content of all the API 650 appendices ever appears in the API 653 exam. There is far too much of it, most of which is of little practical necessity to API 653 storage tank inspection. Picking through the published API body of knowledge (BOK) reveals the few bits of the appendices that are included:

Appendix A: Optional design small tank

  • B: Tank foundations
  • C: External floating roofs
  • H: Internal floating roofs
  • N: Unidentified materials
  • U: UT in lieu of RT
  • X: Duplex stainless steel tanks

Appendix G1 (only): Geodesic dome roof

  • I1, I2 (only): Underfloor leak protection
  • M1 (only): Elevated temperature tanks
  • O1, O2 (only): Under-bottom connections
  • S1 (only): Stainless steel tanks

It is difficult to see any great underlying pattern in this selection. The good news is that they are not a major source of exam questions – perhaps one or two from the 50 open book questions in the exam. They are nearly always very straightforward – as long as you can find the correct appendix, you should be able to pick out the answer. Figure 7.6 shows some points from these appendices that make good subjects for exam questions.

Figure 7.6 Some useful BOK points from the API 650 appendices
Figure 7.6 Some useful BOK points from the API 650 appendices

Click Here To Read Next API 653 Exam Chapter 8 –Tank Non-destructive Examination

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API 653 Exam Chapter 6

API 653 Exam Chapter 6 – Evaluation of Corroded Tanks

6.1 Introduction

Most of the calculations in API 653 reside in section 4: Suitability for Service. This is about what to do with tanks that are corroded or damaged in some way. It provides practical methods of determining whether a corroded tank complies with the well-established requirements of API 653, giving a viewpoint on whether it is safe for continued use.

For both practical and API 653 exam purposes it is important to understand the relationship between three codes involved in calculations of tank integrity: API 653, API 650 and API 579. Figure 6.1 shows the situation. API 650 is a pure construction code so its calculations and the parameters

Figure 6.1 Relationships between tank assessment codes
Figure 6.1 Relationships between tank assessment codes

they use are for new tanks. You can think of the objective of API 650 as being to produce a tank that will successfully pass its initial hydrostatic test, before being put into service. At this point, its job is done and API 653 takes over.

In dealing with in-service tanks that have undergone some degradation, API 653 overrides some of the integrity-related requirements of API 650. You can think of API 653 in three ways:

  • As an ‘out-of-design code’ assessment.
  • As a more realistic assessment, based on the realities of tank operation in use.
  • As a less conservative assessment, using up some of the margins hidden away in the design code that are not required, once it has passed its initial hydrostatic test.

All of these are correct, in their own way. A common technical thread running through all three, however, is the way that API 653 sees the issue of tank failure. Although not entirely unconcerned with leaks and environmental issues, the calculation routines of API 653 centre mainly around the objective of preventing structural failure and collapse of the tank. Leaks are undesirable, but they can be contained and/ or repaired. This same priority is shown by other API in service inspection codes, and those from other bodies also, so it is probably correct.

In practice it is easily possible for a tank with heavy and unsightly corrosion to pass an API 653 calculation assessment. Some people would therefore offer the view that API 653 is more interested in integrity rather than cosmetic appearance. If a tank fails the corrosion evaluation methods in API 653 the question of what to do gets wider. The options are:

  • Repair it to API 653/650.
  • Rerate it (by lowering the fill height of the tank) to API 653.
  • Do a fitness-for-service (FFS) assessment to API 579.

Figure 6.2 The section numbers of API 579
Figure 6.2 The section numbers of API 579

Looking at Fig. 6.2 you can see the context of API 579. It is a large detailed document containing many sections of detailed assessment methods for corrosion, bulging, weld problems and various other damage mechanisms that can affect tanks. Its use is not limited to tanks, but it fits well with the mechanical characteristics of atmospheric tanks of straight forward construction. An API 579 assessment is an out of (design) code assessment so, as such, carries an element of risk and even technical controversy, even though its methods are fairly robust and well-proven.

The detailed context of API 579 is, thankfully, not included in the API 653 exam body of knowledge. We will therefore concentrate on the evaluation methods of API 653 section 4: Suitability for Service.

6.1.1 The anticipated failure mechanisms

The evaluation methodologies of API 653 section 4 are almost exclusively concerned with preventing ductile failure. This is the main failure mode of corroded tanks in service. Do not confuse this with the competing mechanism of brittle fracture – related to material properties at low temperatures. This is primarily of interest for new tanks under hydrotest and is covered in a different section of API 653 (section 5).

6.2 The contents of API 653 section 4: suitability for service

Figure 6.3 shows the breakdown of the content of section 4: Suitability for Service and its partner Annex B: Evaluation of Bottom Settlement. Taken together, these provide good coverage on how to assess a corroded or damaged tank. Remember the key points about the calculation methods employed:

  • They are based on the design calculations of the tank construction code API 650 but include various overrides.
  • Areas in which API 653 clauses override the design requirements of API 650 are a fertile source of exam questions, as they are at the centre of the actual idea of API 653.
  • Only the simpler parts of Annex B: Evaluation of Bottom Settlement ever appear as exam questions. Some of the topics listed in the BOK never appear.

6.3 Tank roof evaluation

This comprises little more than a list of checkpoints. A few that arise as exam questions are:

Figure 6.3 Tank evaluation: the breakdown of API 653 section 4
Figure 6.3 Tank evaluation: the breakdown of API 653 section 4

Roof plates containing holes must be repaired or replaced. . Roof plates corroded to an average thickness of less than 0.09 in in any 100 in2 must also be repaired or replaced.

Note also these related safety points from API RP 575 (2.9):

  • When walking on a tank roof it is safer to walk on the weld seams than between them.
  • If planks are used as roof walkways they must span at least two rafters.
  • Watch out for blocked roof drains. Corrosion tends to be worse where water gathers in pools.
  • Tank vent valves fitted on the roof need to be checked for blockage.

There are generally no calculation questions related to roofs in the exam.

6.4 Shell evaluation

Evaluation of corroded shells is a major part of the API 653 body of knowledge. There are enough variations on the method to make for a fairly wide choice of exam questions. It also combines a useful group of principles that, in themselves, also turn up regularly in exam questions. Figure 6.4 shows these principles and we will look at them individually now.

6.4.1 Material strength

For tanks, this is straightforward. Construction steels are divided into well-established designations (‘grades’), each of which has a minimum specified yield strength (SY) and ultimate tensile strength ST (sometimes just abbreviated to Y and T). Remember that these are the minimum values the material has to meet to qualify for its designated grade – in practice it will almost certainly be stronger. Now look at Fig. 6.5, to see how these strength values are actually incorporated into tank design and repair.

Look at the principles highlighted in this figure. Although the rated yield (Y) and ultimate tensile strength (T) for any material are fixed, the percentage of this strength that is used to decide the value of allowable stress (S) to be used in the calculations varies depending on four things:

1. Whether it is a new-build/reconstructed tank or an existing one being assessed in its corroded condition.

2. Will the tank (in the future) only see its (lighter than water) petroleum product or will it be filled with water during a hydrotest?

Figure 6.4 Tank shell evaluation: the principles
Figure 6.4 Tank shell evaluation: the principles

The location of the actual shell course under consideration.

4. Whether it is an elevated temperature tank, designed for operation above 200 o F (for low carbon steel).

Referring to the table in Fig. 6.5 you can see how these parameters all affect the allowable stress value to be used. Note the key principles involved in deciding the S value:

Figure 6.5 Tank shell material strengths
Figure 6.5 Tank shell material strengths

It is normally the lowest of a percentage of Y (yield) or T (tensile) strength. There is no fixed rule as to which takes priority; you have to calculate both options and use the lowest value.

A higher S value is allowed if a tank is to be hydrotested. This is acceptable on the basis that the tank shell will only see the increased stress once, so any increased risk is small.

A higher S value is allowed for existing tanks (API 653) than for new or reconstructed tanks (to API 650). Again, a little more risk is acceptable with an existing tank because it has proved itself by passing its original hydrotest and has not fallen down since.

For existing tanks only, a higher S value is allowed in the upper areas of the shell than in the bottom two courses. This is because the upper courses are under less stress from the product weight, so are a bit less important from an integrity point of view.

If a tank is likely to see elevated temperatures (above 200 ℉) then a bit of extra caution is required. This takes the form of a stress reduction factor to allow for the fact that materials get weaker as temperature rises.

6.4.2 The principle of stress averaging

The stress on a tank shell is very simple. It is almost entirely pure hoop stress acting on the vertical plane, attempting to split the tank open from top to bottom. Simplistically, for an uncorroded tank, the hoop stress is calculated using the simple formula below:

                                 Pd

Hoop stress S =______________

                                  2SE

or rearranging to express it in terms of minimum required thickness (t)

                Pd

t =______________

                2SE

where

p = pressure (from the head of liquid)

d = diameter of the tank

S = allowable stress

E = weld joint efficiency (a type of safety factor

Using this equation it is easy to find the stress (S) or minimum required thickness (t) at any vertical position in the tank shell. The difficulty comes when you start to apply this

Figure 6.6 Tank hoop stress and averaging
Figure 6.6 Tank hoop stress and averaging

to a tank shell that is corroded along the vertical plane. Figure 6.6 shows the situation. In an uncorroded shell plate of uniform thickness the hoop stress is resisted by the uniform ‘thickness’ area of the plate and averaging is not an issue. Once the plate is corroded then the area resisting the hoop stress starts to vary from place to place; thinner areas of plate have less area to resist the force so the hoop stress value is higher. Some method is therefore needed to decide how to deal with this varying stress level.

The problem of averaging The danger with simple arithmetic averages is that they can be misleading. Look at the two examples in Fig. 6.6. Profile (a) is clearly more likely to fail than profile (b) but both have the same calculated arithmetic average.

API 653 attempts to neutralize this weakness by defining a calculated averaging length. This gives a length over which it is assumed (simplistically) that the hoop stresses on a corroded plane ‘average themselves out’. Figure 6.6 shows the calculation. Note how it is related to tank diameter (D) and minimum (spot) wall thickness (called, rather confusingly, t2), and how the square root sign reduces the sensitivity of L to large changes in D and t2.

6.4.3 Weld joint efficiency (E)

Weld joint efficiency (symbol E) is a concept found in several API and ASME codes. Crudely, it acts as a design margin that increases the minimum required shell thickness. In other design codes, joint efficiency is affected by the weld location, its configuration (single groove, double groove, etc.), amount of NDE and a more general, somewhat hidden, consideration of construction ‘quality’. For storage tanks the situation is simpler, being mainly governed by the design code and year edition to which it is built. You can see this in Table 4-2 of API 653.

Is joint efficiency (E) real?

Yes, as long as you think of it in the following way:

E is mainly for use in new tank design. Its purpose is to make sure a tank is strong enough to pass its initial hydrotest.

Once a tank is corroding in use its E is still relevant, however; if the corrosion is not near a weld it can be ignored (by making E = 1). This is a low-risk assumption acceptable to API 653.

Figure 6.7 summarizes the joint efficiency information contained in API 653 Table 4-2. Note how E is much lower

Figure 6.7 Shell joint efficiencies E
Figure 6.7 Shell joint efficiencies E

for tanks built to older design codes. This reflects the uncertainties and variability of material control and uncertain manufactured ‘quality’ prevalent in earlier times.

Joint efficiency for riveted shells

There are a lot of older riveted tanks still in use in the USA, so you can expect a couple of API exam questions about them. The principles are fairly straightforward:

For corroded areas near riveted seams, E varies from 0.45 to 0.92; the latter for a total of 12 rows of rivets (6 either side of the joint centreline). See API 653 Table 4-3.

As with welded seams, if corrosion is located well clear (6 inches away) from the nearest rivets the joint efficiency can be relaxed to E = 1.

6.4.4 Hydrostatic head consideration

An atmospheric storage tank shell is a good example of a very straightforward stress regime. If we conveniently ignore wind loading, the tensile stress on any point of the shell (at least above the bottom few inches where it meets the bottom annular plate) is an almost pure example of hoop stress. In turn, this hoop stress at any vertical location is directly proportional to the height of liquid (h) above it. We can see this from the hydrostatic head equation:

6.4.4 Hydrostatic head consideration
6.4.4 Hydrostatic head consideration

For a tank shell of uniform plate thickness over its full height, the hoop stress varies directly with height, as shown in Fig. 6.8. This will also apply if we just consider a single shell course. In practice, shell plate thickness normally

Figure 6.8 Hoop stress and height
Figure 6.8 Hoop stress and height

increases from top to bottom, modifying the situation slightly.

In assessing corroded shell plates, API 653 uses simple adaptations of the hoop stress equation. This changes slightly in practice although, importantly, not in principle, depending on the amount of corrosion in the specific plate course being considered. This can be explained by referring to it as the socalled ‘one-foot rule’.

Figure 6.9 The one-foot rule
Figure 6.9 The one-foot rule

6.4.5 The one-foot rule Figure 6.9 shows the equation to be used to calculate the minimum acceptable thickness. There are two options:

The corroded area is sufficiently large to warrant conducting the assessment of a full shell course plate. .

The corroded area is much more localized within a plate.

Note the difference between the equations used; they differ only by their use of either the term (H) or (H – 1) within the equation (hence the one-foot rule name). In practice, it can be difficult to decide exactly which to use, as people’s opinions will vary on whether a corroded patch is extensive enough to warrant a full course assessment or not. For API 653 examination purposes the question will tell you which assessment to use. Looking at the example in Fig. 6.9 you can also anticipate that the answers obtained from both methods do not vary by very much, particularly for larger tanks. The same principle is used when rerating tanks or calculating a safe full height for a tank that has a corroded shell.

6.4.6 What do we do about pitting?

In the world of API, pitting is seen as a very different thing to wall thinning. Although they may (and generally do) occur together, they are seen as separate for assessment purposes. The principles of dealing with pitting are common to several API in-service inspection codes. The points listed below summarize the approach of API 653 (4.3.2.2) to pitting:

As a matter of principle, widely scattered pits in a tank shell can be ignored. This is because they are unlikely to result in structural failure of the tank.

The definition of widely scattered is (practically at least) defined by the content of Fig 6.10 taken from API 653 Fig. 4-2. Note the reference to 2 inches in 8 inches – cumulative lengths of pitting greater than this are considered too concentrated to be isolated and so must be assessed as a corroded area instead. Strangely, no depth of this pitting is defined – so pitting is pitting.

To restrict the allowable depth of pits, API 653 (4.3.2.2a) prohibits any pit from being so deep that it leaves less than 50% of the calculated tmin for that location in the shell. In assessing this, make sure to add any future corrosion allowance (the amount that may suddenly or gradually disappear before the next scheduled inspection).

Figure 6.10 Pitting evaluation: API 653 (4.3.2.2 b)
Figure 6.10 Pitting evaluation: API 653 (4.3.2.2 b)

The end result of applying these criteria to pitting is either that it can be ignored or that it is serious enough to be treated as a corroded area, using the main corrosion assessment method. We will look at this next.

6.4.7 Corrosion assessment – the big principle

Figure 6.11 shows the big principle of API corrosion assessment. This appears, with minor variations, in most API assessment codes for tanks, vessels and pipework and in API 579 – the advanced fitness-for-service (FFS) code relevant to them all. Note the key issues:

Figure 6.11 API 653 (4.3.2.1e) pitting assessment
Figure 6.11 API 653 (4.3.2.1e) pitting assessment

It is a double-barrelled assessment. meaning .

There are two separate assessments, and you have to pass both to be acceptable. and .

One assessment relates to the average thinning (on the assumption that this is what causes failure). 

The other assessment relates to the thinnest ‘spot’ reading (as long as it is not isolated pitting of course), under the assumption that this is what is going to cause the problems.

Looked at individually, each of these assessments is perfectly capable of providing a misleading picture of the integrity of the shell. Taken together, however (when you have to pass both), they provide a much better and balanced assessment. Figure 6.12 shows a sample (simplified) shell assessment.

6.5 API 653 (4.4): tank bottom evaluation

Tank bottoms cause most of the problems with the integrity of storage tanks. Over time, they are likely to suffer from a variety of problems of settlement, corrosion or even cracking, leading to leaks. API 653 provides a full list of causes of bottom failure in section 4.4.2. Figure 6.13 shows the major causes; note how most of them relate, either directly or indirectly, to corrosion of some sort.

6.5.1 Release prevention systems (RPSs)

API 653 (4.4.3) goes into some detail about so-called release prevention systems (RPSs). This generic term refers to any method (either a physical feature or an action that can assist in maintaining the integrity of the tank bottom, i.e. preventing a leak from happening) They are:

  • Internal inspection of the tank bottom
  • A leak detection system

Figure 6.12 Typical (simplified) shell assessment
Figure 6.12 Typical (simplified) shell assessment

Leak testing (to find problems in advance)

Cathodic protection of the underside of the tank bottom

Internal lining of the tank bottom

API 653 (4.4.3) does not go so far as recommending which of these is likely to be the best method – it simply reports that they exist, with a brief description of what they are. Do not expect lots of exam questions on this. In contrast to RPSs, release prevention barriers (RPBs) are used to contain or otherwise mitigate a bottom leak once it

Figure 6.13 Causes of tank bottom failure: API 653 (4.4.2)
Figure 6.13 Causes of tank bottom failure: API 653 (4.4.2)

has happened. Tank bunds, earthwork liners and drainage channels are the classic RPBs. There is a lot more detail in API 650 appendices I1 and I2, which are in the API 653 BOK.

6.5.2 Bottom evaluation – general principles

Tank bottom evaluation is subdivided into the three main elements that make up the tank bottom. .

The bottom plates themselves (4.4.5) are the main plates, normally overlapped and lap welded inside the tank.

The annular ring (4.4.6) is a thicker ring of fairly narrow plates, butt welded together in an annulus located under (and welded to) the lower shell plate course. The annular ring therefore supports almost all of the steelwork weight of the shell and its attachments. Older tanks may not always have this thicker annular ring but most modern ones do.

The critical zone is not a separate set of floor plates but simply the annular area extending 3 inches inward from the shell, all round the tank. You can think of it as just a particular critical region of the annular ring. It appears in API 653 (4.4.5.4) and the definition section (3.10).

Not all of the technical points in these sections of API 653 get universal agreement. Some tank codes from other countries take different views on the risk of operating with quite thin bottom plates and annular rings, and so prefer to specify a greater minimum acceptable corroded thickness in preference to relying on an RPS/RPB as a last line of defence. Differences of opinion apart, API 653 does provide consistent and easy-to-follow acceptance levels, which many tank operators follow quite successfully.

6.5.3 Bottom plate minimum thickness API 653 (4.4.5) and Table 4-4

This is one of the more difficult equations of API 653 to understand. There is nothing wrong with the principles behind it; it is simply written using odd symbols and in a strange way. Part of the problem comes from the fact that it tries to incorporate scenarios in which a bottom may have already been repaired and/or have had a lining applied to arrest corrosion before it is assessed.

Note a key point about this equation, which we will call the MRT equation:

The ‘MRT’ equation just tells you how to calculate the remaining thickness of the bottom plates at the next

inspection. It does not actually give you a minimum acceptable value. That is given in API 653 Table 4-4. Here is what the equation in 4.4.5.1 looks like, with some slightly simplified English:

6.5.3 Bottom plate minimum thickness API 653 (4.4.5) and Table 4-4

If you can fight your way through the confusing wording (and ignore all the stuff on repairs which may or may not have been done) this actually makes reasonable sense. It simply says:

MRT = current thickness – (time to next inspection  corrosion rate)

Qualify this by the following couple of points and you can see the equation for what it really is – a complicated way of expressing a simple idea:

  • The corrosion rate consists of the internal corrosion rate plus the external corrosion rate (as the tank bottom has an inside and an outside).
  • If the tank has an internal lining, just assume that the internal corrosion rate = 0.
  • If this tank has cathodic protection (CP), just assume that the external corrosion rate = 0. 
  • If either the internal or external surfaces have been repaired, the original corrosion rate that necessitated the repairs must be assumed to be still in force, unless you have evidence that it has changed (e.g. gone to zero if a lining has been applied after the repairs).

6.5.4 Minimum acceptable bottom plate thickness

Once you have calculated the remaining bottom thickness at the next inspection, the idea is that you then compare the results with Table 4-4 (reproduced in Fig. 6.14). This allows a basic minimum thickness of 0.1 in (2.5 mm), but can be reduced to half that (0.05 in or 1.25 mm) if the tank has either an internal lining or some method of containment to catch leaks if they do occur. These thicknesses are quite low,

Figure 6.14 Bottom plate minimum thickness: from API 653 Table 4-4
Figure 6.14 Bottom plate minimum thickness: from API 653 Table 4-4

and of course can be overruled either way by an RBI assessment.

6.5.5 What about the critical zone?

The 3 in wide critical zone (defined in API 653 definition 3.10 remember) may be either part of the annular ring (if the tank has one) or the bottom plate, if it does not. Figure 6.15 shows this specific requirement, a hybrid limit of the lower of:

Figure 6.15 Tank bottom limits: critical zone API 653 (4.4.5.4)
Figure 6.15 Tank bottom limits: critical zone API 653 (4.4.5.4)

50% of actual original bottom thickness (excluding any corrosion allowance) or

50% of tmin of the lower-shell plate course but

It must not be less than 0.1 in (2.5 mm), excluding isolated pitting as usual.

If the tank does have an annular ring, then this restriction on the minimum thickness of the critical zone still applies; it just falls within the annular ring rather than the bottom plates.

6.5.6 Minimum thickness of the annular plate ring (4.4.6)

The minimum acceptable thickness of the annular ring needs to be greater than that of the bottom plates, as it is under more stress from supporting the weight of the shell (plus sometimes bending from foundation settlement or other sources). The thicknesses are shown in API 653 Table 4-5 and summarized in Fig. 6.16. Note how three additional factors (that did not affect the main bottom plates) come into play:

  • The thickness of the first shell course
  • The actual ‘product’ stress in the first shell course
  • Whether or not the specific gravity of the product is greater than 1 (heavier than fresh water)

Owing to the fact that the condition of a tank bottom is one of the most important life-limiting factors and the main reason for actually doing internal inspections, the above subjects appear regularly as both open- and closed-book exam questions. The calculations are normally straightforward and you can see some typical examples at the end of this chapter.

6.6 Foundation evaluation: API 653 (4.5)

This short section situated at the end of section 4 contains a few general points on the condition of concrete foundations

Figure 6.16 Bottom limits: annular ring API 653 Table 4-5
Figure 6.16 Bottom limits: annular ring API 653 Table 4-5

but nothing about the main foundation-induced problem, which is that of settlement. This is physical movement of part of or all of the foundations, causing stresses and distortion of the tank structure above it. This is covered in API 653 Annex B, which we will look at next. Although physically separated in different parts of the code, section 4: Suitability for Service and Annex B: Evaluation of Tank Bottom Settlement are closely related to each other and should be considered together when assessing tank bottoms.

6.7 Bottom settlement: API 653 Annex B

Exactly how much of Annex B is in the API 653 examination body of knowledge (BOK) is open to some interpretation. This annex contains a lot of quite detailed information that maps well on to the way that tank settlement assessments are actually done in the field. Some of it, however, is far too complicated to be suitable for the API 653 exam. The BOK partly addresses this by mentioning a few exclusions, but at first reading it is not particularly easy to translate this into which part of Annex B you need, or need not, study.

Fortunately, the reality is fairly straightforward – most of the content of Annex B does not appear as exam questions, either because it is too complicated or it does not fit well into the multichoice exam question format. This means that there are generally fewer settlement-related questions than perhaps you might expect, given its importance. They are mainly predictable open-book questions and not too difficult. We will look at the most popular subjects and then at some simple questions at the end of this chapter.

Annex B is set out along fairly logical guidelines as follows:

The different types of bottom settlement, categorized predominantly by the way that they affect the shell. The types are uniform, planar and differential.

Measurement of various types of bottom settlement. The three clear types included in the BOK are: –

Edge settlement (B-2.3)

Bottom settlement near the shell

Bottom settlement remote from the shell nearer the centre of the tank floor.

Evaluation of the types of settlement against acceptable limits, given in the form of graphs or simple linear formulae.

Decisions based on the results of the evaluation about performing additional NDE or repair. Details of the repairs themselves are not included in Annex B-2, as they are fully covered in API 653 section 9.

6.7.1 Types of settlement

The problem with storage tanks is that they are structures that have little rigidity. Most have no cross-bracings supporting the shell, leaving only the hoop strength of the thin shell to support the load exerted by the product liquid. Even the margins in material thickness are small, compared to those used in pressure vessels and pipework. To make things worse many older tanks were built on either simple rubble foundations or low quality concrete.

The result is that when tanks move (or ‘settle’) on their foundations, the uniform hoop stress regime in the shell is soon disturbed, leading to unpredictable stresses, strains and distortion. This can soon lead to cracking and leaks, or, in extreme cases, collapse of the tank. To try and avoid this tank owners should take regular measurements of tank settlements over time.

Distortion of a tank shell involves a rather complicated three-dimensional geometry that is not easy to measure, or even describe in simple terms. Measurement and analysis is therefore generally left to specialist contractors. Quite a bit of API 653 Annex B is devoted to describing these specialist techniques – the good news is that they are not really included in the BOK, and are too complicated to appear in the form of API exam questions. For exam purposes, you can think of the types of tank settlement as being simplied into three separate components as follows (see Fig. 6.17):

Uniform settlement. This is ‘sinking’ of the tank perfectly vertically downwards, with no tilting, twisting, buckling or any other type of distortion whatsoever. It rarely happens exactly like this in practice, but you can think of it as one of the components of any real settlement pattern.

Planar tilt. You can think of this as the tank shell and bottom assembly simply tilting over to one side. Again, it does this in a perfectly even and uniform manner – the shell remains perfectly circular without it buckling or kinking. Owing to the tilting there is a small, usually insignificant, increase in vertical liquid height, and therefore in the hoop stress at the bottom of the shell. Looking at Fig. 6.17 you can see how the shape of a uniformally tilted tank can be represented by a perfect cosine wave.

Figure 6.17 Tank settlement: API 653 Annex Fig B-3
Figure 6.17 Tank settlement: API 653 Annex Fig B-3

Non-planar differential settlement. This is the one that causes the real problems in use. The fact that a tank is a very thin shell structure means that as it settles and tilts, it nearly always distorts as well. This causes extra shell stresses, sticking of floating roofs and breakage of support columns, girders and connecting nozzles and pipework.

Is non-planar differential settlement in the exam?

Probably not. Quite a lot of API 653 Annex B is devoted to the measurement and description of differential settlement. It is done by measuring the difference between the actual shape of the settled tank compared to that of the planar-tilted ideal cosine curve. The greater the difference, the greater is the differential distortion and the larger the resulting stresses. You can see the principle explained in API 653 (2.2.4) and Figs B-4 and B-5 – described as the ‘least-squares fit method’. Fortunately, this is far too complicated to make an API exam question so the calculation will not appear in the exam. You can maybe expect a question on the principles of tilting and distortion and their effects but no calculations.

To repeat: you do not need to learn the specific details and equations of ‘out-of-plane’ differential settlement. They will not be in the closed-book exam.

6.7.2 Edge settlement

The various types of tank settlement that we have just looked at are not, in themselves, the problem. It is their distortion effects that are important. API 653 Annex B-2 divides these into two separate situations – settlement distortion under, or very near, the edge of the tank (‘edge settlement’) and that well away from the edge nearer the centre of the tank (‘bottom settlement’). Unlike shell distortions, these are easy to assess using simple graphs and calculations, and so appear in the API 653 BOK. Expect one or two exam questions to appear on this subject, but no more.

Edge settlement is when the tank bottom settles sharply around the edge of the tank often caused by ‘washout’ or crumbling of foundations. Looking at Fig. 6.18 (see also Fig. B-6 in API 653) you can see how this results in sharp deformations of both the bottom and shell steelwork, causing serious bending stresses. The API 653 Annex B assessment uses a simple ratio of the (vertical) length of edge settlement to its length (in the tank radial direction). It then divides this into two separate scenarios as follows:

If the edge settlement is an area where the tank bottom

Figure 6.18 Tank bottom edge settlement: (API 653 Annex B-2.3)
Figure 6.18 Tank bottom edge settlement: (API 653 Annex B-2.3)

plate welds run near-parallel (±20o ) to the shell, the extent of edge settlement is called Bew.

If the edge settlement is in an area where the tank bottom plate welds run near-perpendicular (±20o ) to the shell, the extent of edge settlement is called Be.

Note how both of the above cases refer to the vertical amount of settlement (B); they are simply renamed Bew or Be, depending on which way the local tank bottom plate welds are orientated.

Assessment against the edge settlement graphs Once the edge settlement measurements are available, the assessment is easy. Figure 6.19 summarizes the content of API 653 Figs B-11 and B-12.

To use the graph, simply enter the graph on the horizontal axis with the measured radius (R) of the settled area. Remember that this is not actually a true radius, as such, but the length of the settled area measured in the tank radial

Figure 6.19 Edge settlement assessment: API 653 B-11 and B-12
Figure 6.19 Edge settlement assessment: API 653 B-11 and B-12

direction. Then, using the relevant curve for the tank diameter in question, read off Bew (or Be) from the vertical axis. This is the maximum allowed dimension of Bew (or Be) acceptable to API 653. Any more than this needs repair or further specialized evaluation.

API 653 exam papers do not like to contain a lot of figures or graphs, so exam questions tend to be limited to code clauses that do not require use of the graphs. Note the following key points: 

Bew, when bottom welds are (±20° ) parallel to the shell, is more conservative than Be so it is normal to do this assessment first (B-2.3.4).

When Bew or Be are ≥75 % of their limit (and larger than 2 in) the welds in the region should be inspected with PT/ MT to check for cracking (API 653 Figs B-11 and B-12). . Any bottom plate exhibiting a strain (permanent plastic deformation) of more the 2–3 % should be replaced (B-4.2).

The settlement graphs were originally developed for 1 4 in thick tank bottoms but can also be applied with reasonable accuracy for thicknesses between 5/16 in and 3/8 in.

In general, settlement occurs fairly slowly over the first few years of service (B-3.4.5).

Watch out for the edge settlement clause B-3.4.6 (a to d). There are possible exam questions in here.

6.7.3 Bottom settlement

Remember that this is assessed differently depending on whether the settlement is near the shell or further away, towards the centre. The methods are very similar, using a simple equation based on the depth (BB) of the settlement (bulge) compared to its radius (R). Figure 6.20 shows the situation. Note how the simple linear graph in API 653 Fig. B-10 contains absolutely nothing new; it is simply the equation BB = 0.37R shown in a different way.

As with edge settlement, the limits of bottom settlement

Figure 6.20 Assessing bottom bulges: API 653 B-2.4 and B-2.5
Figure 6.20 Assessing bottom bulges: API 653 B-2.4 and B-2.5

are there to prevent the floor plates being bent too sharply, which would cause risk of cracking of the lap welds. It may still be technically possible to operate the tank with a settlement in excess of these limits, but an engineer’s assessment would be required. As bottom settlement limits can be determined without using graphs (i.e. using the BB = 0.37R equation) this subject can appear as an (open-book) exam question.

The presentation in the code is a little confusing, mainly because the combination of equations and graphs (meaning exactly the same) makes this subject more complicated than it actually is.

Figure 6.21 gives a summary of code formulae used in a tank evaluation.

Now try these practice questions.

6.8 API 653 section 4: evaluation: practice questions (set 1)

Please go to API 653 Exam Chapter 6 to view the test

Click Here To Read Next API 653 Exam Chapter 7 –API 650: Tank Design

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API 653 Exam Chapter 5

API 653 Exam Chapter 5 – Inspection Practices and Frequency

This chapter is about code recommendations on how to inspect a tank and how often you should do it. They are of course separate subjects and the two codes that address them, API 653 and API 575, approach them from slightly different viewpoints. API 653 divides inspections into different types and addresses inspection interval (or frequency) in its section 6. It also introduces the way in which a tank inspection interval can be based around a risk-based inspection (RBI) assessment. It seems to like this idea. The baton then passes across to API 575 section 7, which confirms the method of corrosion rate calculation and then launches into a detailed methodology of how to inspect the various parts of a tank inside and outside, when it is in or out of service. This API RP 575 section is a major source of exam questions (open and closed book) and, looking objectively, gives excellent experienced-based guidance on how to inspect tanks.

We will look at these relevant sections of API 653 and API RP 575 in turn.

5.1 API 653 section 6: inspection

First the good news about section 6. A lot of information about what to inspect during a tank inspection has been separated out into API 653 Annex C – a hugely detailed inspection checklist of nearly 20 pages. Its content is excellent but the good news is that it is next to impossible to transform such checklist data into multiple choice exam questions. This goes for all checklists – you just cannot get many API-style exam questions out of them, no matter how hard you try.

The remaining content of API 653 section 6 is logically structured, if a little unbalanced. Figure 5.1 shows its breakdown. Note the way in which it divides inspection into four discrete types, routine external, full external, ultrasonic testing (UT) thickness and interval. As you can

Figure 5.1 The contents of API 653 section 6: inspection
Figure 5.1 The contents of API 653 section 6: inspection

see from Fig. 5.1, the main technical content of section 6 is about putting limits on the intervals for internal inspections. This has changed significantly since the previous edition of API 653. The main points are now:

  • There are different maximum intervals for the first internal inspection after putting into service, and subsequent ones.
  • Both sets are, loosely, RBI-based.
  • First inspection intervals range from 12 to 25 years (6.4.2.1). This is shorter than those for subsequent intervals which extend from 20 to 30 years (6.4.2.2).

Figure 5.2 shows the idea. Note the story behind the allowable spread of these intervals. In both categories the existence of a release prevention barrier (RPB), i.e. a bund or some similar method to contain spills, allows a significantly longer interval to be used. There is nothing particularly earth-shattering about this – it simply reflects the fact that an

Figure 5.2 The API 653 tank inspection types
Figure 5.2 The API 653 tank inspection types

RPB reduces the consequences of failure (COF) if the tank leaks. Note two other key points: . Viscous substances such as tar are classed as low risk products and are exempted from both the ‘maximum’ interval tables (it says so in 6.4.2.6).

Section 6.4.2.5(c) explains how to adapt these maximum interval tables (newly introduced into API 653: 2009 edition remember) to tanks where different RBI-based intervals have been set before 2009. Figure 5.3 shows how this works. Read this in conjunction with section 6.4.2.5(c) and you should not find it too difficult.

5.2 API 653 section 6: view of RBI

API 653 section 6 does not go into huge detail on RBI. It accepts and supports the activity, as long as it follows the good-sense guidelines mentioned in 6.4.2.4. These are:

The RBI has been carried out to the guidance of API RP 580 with systematic attention given to both probability and consequences of failure (POF and COF).

It was performed by a knowledgeable group.

The assessment (and conclusions presumably) were approved by an API-authorized inspector and a storage tank engineer.

It has been reassessed after all failures or service changes, and at least every 10 years to make sure it is still relevant.

These points are fundamental to API code views on RBI, so watch out for them in exam questions – open or closed book.

5.2.1 Any there other possible exam questions on RBI?

Yes. The two new individual checklists on probability (called likelihood) factor (6.4.2.4.1) and consequence (6.4.2.4.2) are good, but difficult to turn into multichoice exam questions. More likely are questions that check your appreciation of which factors should be in which list, to test if you really

Figure 5.3 Dealing with historical inspection intervals
Figure 5.3 Dealing with historical inspection intervals

understand the fundamental difference between POF and COF. These are generally straightforward; just watch out for the occasional convoluted wording or questions phrased as a negative: e.g. which of the following factors does not have an effect on POF? Watch out for these awkward ‘not questions’ in all API ICP exams (you will not be disappointed).

5.2.2 Reports and recommendations (section 6.9)

Owners/users have an ongoing battle getting tank inspectors to write sufficiently detailed inspection reports. Many are short on detail, carefully indecisive in their conclusions and diplomatically vacant about what should be done next. API 653 section 6.9.2 (another newly added section) is an attempt to improve this. Look at what it requires:

Inspection reports must recommend repairs and/or future monitoring, and give reasons why (6.9.3.1).

They must give the maximum next inspection interval and show where it comes from (by corrosion rate calculation or reference to API 653 clauses).

However, note that the precise repair scope and timing is the responsibility of the owner/user. Figure 5.4 shows this in a visual way.

5.3 API 575 section 6: inspection frequency and scheduling

Do not expect anything new on inspection frequency in API RP 575; it just cross-refers to API 653, as you would expect. It does, however, add the requirement for the monthly routine inspection. Note also the suggestion made in API 575 (6.1) that external inspection be carried out after unusual events such as:

  • Obvious settlement
  • High winds, rain or lightning
  • Seismic movements

Of these, seismic events are perhaps the most important, particularly on floating roof tanks. Any ground movement at all can cause the tank shell to distort, particularly near the top, causing a floating roof to stick.

5.3.1 Corrosion rate

All API in-service inspection codes place great importance on determining a corrosion rate. This is covered in section 6.2 of

Figure 5.4 Inspection reports and recommendations
Figure 5.4 Inspection reports and recommendations

API RP 575. It is not repeated in API 653, but it is needed to be able to work to API 653, as it governs the life of a tank. Determining an accurate corrosion rate is not easy – tank components normally corrode at different rates and there can be big differences within a component. In tank floors, areas around heating coils, drain sumps and the shell-to-floor weld can have dramatically different (normally higher) corrosion rates than areas only 100–200 mm away. Shells, similarly, are likely to corrode more quickly around the product/air interface, or at the top if vapours are corrosive, or at the bottom if the product is such to encourage a corrosive water layer here.

With externally lagged tanks the situation is worse because CUI almost never happens uniformly. You can expect to find more seriously corroded areas around water traps such as wind-girders or, more randomly, wherever the cladding allows rain water in, ensuring that the lagging material remains wet.

Practicalities apart, API RP 575 (6.2) takes a fairly simplistic view of the corrosion rate, assuming it is real, predictable and conveniently uniform and linear, for any particular product service. Figure 5.5 shows the situation – the calculations are fairly simple. Remember that for exam questions these can be done in either USCS or SI units, but you would be well advised to use USCS (inches) units if you want to avoid conversion and rounding errors.

5.3.2 Changing corrosion rate

API exam questions like to check whether you appreciate that corrosion rates do not necessarily remain constant through time. This is particularly important for multiproduct storage tank farms, which may contain many different types of product during their life. The idea of a changing corrosion rate is shown in API RP 575 Fig. 32 with the long-winded title, Hypothetical Corrosion Rate Curve for the Top Course of a Storage Tank. There is nothing difficult about this figure; it just has its axes oriented in a rather bizarre way. To understand it, simply turn the page 90 degrees anticlockwise and it will all make sense – with the years on the horizontal axis and shell thickness on the vertical axis. Remember that the idea is all a little hypothetical, but you can expect real exam questions about it. Figure 5.6 shows a better interpretation of this idea.

Figure 5.5 Corrosion rate: a simple concept
Figure 5.5 Corrosion rate: a simple concept

5.4 API RP 575: inspection practices

Whereas API 653 is a little thin on actual tank inspection practice, API RP 575 is full of information. Packed into dense narrative passages (not the easiest to read) are hundreds of valid points and instructions on how to inspect a tank. There is some very good information here, built up by an army of unknown inspection warriors over many years. Firstly, look at the structure. Figure 5.7 shows how the

Figure 5.6 Changing corrosion rate
Figure 5.6 Changing corrosion rate

chapter breaks down into the three main inspection types: (7.2) external (tank in-service), (7.3) external (tank out-of service) and (7.4) internal (empty and out-of-service). To save repetition a lot of the information relevant to all three types is included in the first section 7.1. You can expect about 10% of the API exam questions to come from this section (some

Figure 5.7 Methods of inspection: what is in API RP 575 (section 7)
Figure 5.7 Methods of inspection: what is in API RP 575 (section 7)

picked out of the text word-for-word) so we will look at each of these sections in turn.

5.4.1 Preparation for inspection (7.1)

There are two aspects to this: safety aspects and tools for inspection. The safety aspects of storage tank entry are of course based on statutory codes and rules applicable to the USA. Requirements will be different in other countries although the principles will be much the same, being based

Figure 5.8 Tank inspection: safety precautions: API RP 575 (7.1)
Figure 5.8 Tank inspection: safety precautions: API RP 575 (7.1)

on experience and common sense. Figure 5.8 summarizes the major points that pop up as exam questions.

Inspection tools is a strange subject for exam questions, but there are a few common exam questions built around them. Their mention is also scattered about other subsections of section 7.1. Figure 5.9 picks out the main points. Note that there is a separate API individual certificate programme

Figure 5.9a Tank inspection tools
Figure 5.9a Tank inspection tools

(ICP) for tank entry supervisors (TES). This is entirely based on US legislation and so has limited applicability in other countries.

5.4.2 External inspection of an in-service tank (7.2)

Section 7.2 provides a fairly well-structured list of items to check during an external inspection of a tank that is still in use.

Figure 5.9b Tank inspection tools (continued)
Figure 5.9b Tank inspection tools (continued)

5.4.3 Ladders, platforms, walkway inspection (7.2.1– 7.2.2)

Figure 5.10 shows points to check on ladders, platforms and walkways. On tanks situated in dirty or corrosive environments (steelworks for example) these components present a bigger personal safety risk than the tank itself, so they are important inspection items. Do not expect a lot of exam questions on them though – the answers would be too obvious to make a good exam question.

5.4.4 Foundation inspection (7.2.3)

Note the two important points here:

  • Foundation settlement causes floor settlement – a subject
Figure 5.10 External inspections: ladders, platforms and walkways
Figure 5.10 External inspections: ladders, platforms and walkways

covered not in API RP 575 but in API 653 Annex B. We will look at this in detail later.

Check the mastic seal between the bottom of a tank and its foundation. If the joint is unsealed, water will get in and corrode the bottom.

5.4.5 Anchor bolts and earth connections (7.2.4– 7.2.5)

There are a few straightforward points here that occasionally appear as rather uninspiring exam questions:

  • A simple hammer test on anchor bolts can show if they are loose or heavily corroded (if they break).
  • Tank earthing (‘grounding’) connections should be visually checked for corrosion where they enter the soil. Watch for the exam question that asks what the maximum earth resistance should be (the answer is 25 ohms).

5.4.6 Tank shell inspection (7.2.8)

The main content of API RP 575 section 7.2 is in here. A lot of effort goes into inspecting tanks shells as they are easily accessible, even though it is still often the tank bottom that governs the tank life. Both this and later sections 7.3 and 7.4 contain information about tank inspection, much of which is related to finding shell plate thickness using some types of UT measurement. Figure 5.11 shows the key points.

5.4.7 Shell UT thickness checks

The key point about shell UT thickness readings is that there must be sufficient accurate readings available to feed the evaluation calculation that we will look at later, in API 653 section 6. Five points per corroded (vertical) plane are required as an absolute minimum for any averaging calculation. For light or fairly regular corrosion this can often be achieved by individual UT (pulse-echo) thickness gauge readings. If the corrosion is more widespread, or serious, then full scanning is normally required, of individual shell plates or the entire shell. It all depends on the severity.

Figure 5.11 Tank shell inspection: general points from API RP 575 (7.2, 7.3, 7.6)
Figure 5.11 Tank shell inspection: general points from API RP 575 (7.2, 7.3, 7.6)

API RP 575 seems to favour full scanning (also called ‘corrosion mapping’). Scanning techniques themselves are not part of the API 653 BOK; you just need to know that it exists and what it does.

The recommended periodicity of shell UT thickness checks is an interesting one. API 653 sees UT thickness checking as being a totally separate activity from a tank external inspection, even though, in reality, it will often be carried out at the same time. It sets a maximum periodicity of:

Periodicity of shell UT thickness checking = half the remaining corrosion life (to a maximum of 15 years).

This is a popular examination question. Expect it to come up almost every time.

5.4.8 Tank bottom inspection (7.4)

Unless you have access to robotic equipment, most tank floor inspections are carried out during the internal inspection programme after the tank has been emptied and cleaned. The bottom is normally inspected last, for safety reasons, after the condition of the roof and shell have been confirmed. Tank bottom problems divide squarely into two: soil-side and product-side. In older tanks laid on a soil or rubble base, soil-side problems are often the worst. Soil-side galvanic and/ or crevice corrosion is notoriously unpredictable and localized, and often remains hidden until it is serious enough to cause leakage or serious structural problems.

The extent of floor inspection tends to be decided by the level of test equipment available. Simple pulse-echo UT meters can check for soil-side thinning in selected areas but is a hit-and-miss affair at best. Floor scanning equipment using ultrasonic or magnetic floor leakage (MFL) gives much more reliable coverage, and more detailed UT can be done on areas of concern that have been found.

From an API examination question perspective, there are a few technical points that are worth remembering:

Statistical analysis of scanning results can be done on data samples of 0.2–10 % of the bottom area. Its anyone’s guess where the 0.2% figure came from.

Statistical analysis is less reliable once significant corrosion (usually soil-side) has actually been detected. If this happens 100% scanning is the best.

Bottom corrosion is made worse by bottom settlement. API 653 Annex B covers settlement in detail. We will look at this later in chapter 6 of this book.

Figure 5.12 Tank floor inspections: API RP 575 (7.4.4)
Figure 5.12 Tank floor inspections: API RP 575 (7.4.4)

Figure 5.12 shows some other key points for floor inspection. They are all good exam question material.

5.4.9 Tank roof inspection (7.4.8)

The inspection of a tank roof can be split into those activities applicable to fixed and floating roof tanks. Before inspecting either, note the general safety points outlined in Fig. 5.13.

Figure 5.13 Tank roof inspection: API RP 575 (7.2.5)
Figure 5.13 Tank roof inspection: API RP 575 (7.2.5)

5.4.10 Fixed roof inspection

Figure 5.13 shows some areas of inspection on a fixed roof tank. Most are to do with thickness checking, normally just by a simple pulse-echo UT meter, pit gauge or calipers. The following points regularly appear as exam questions:

  • Structural members, rafters and columns can corrode from both sides, resulting in a high (double) corrosion rate.
  • Corrosion is normally more serious in dents or depressions where rainwater has been standing.
  • Evaluation of roof corrosion is not covered in API RP

575. It is covered by API 653 section 6 so we will look at it later in chapter 6 of this book.

5.4.11 Floating roof inspection

Floating roofs have more problems than fixed roofs. They have a more involved structure (so corrode more) and are complicated by seals and articulated drain arrangements. These suffer from mechanical problems (sticking, distortion or broken parts) as well as corrosion. Figure 5.13 shows some points; see also the detailed checklists in API 653 Annex C.

5.4.12 Inspection of auxiliary equipment (7.10)

Auxiliary equipment fitted to tanks (connected pipework, valves, drains, flame arrestors, level gauges and similar) are responsible for their fair share of problems and inspection findings. They do not fit particularly well into the API exam questions about inspection practices however. Surprisingly, they appear more often as questions linked to the design aspects of API 650: the tank construction code. The questions are not particularly difficult and relate mainly to a few specific drawings of design features.

Now try these practice questions.

5.5 API 653: inspection intervals: practice questions

Please go to API 653 Exam Chapter 5 to view the test

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API 653 Exam Chapter 4

API 653 Exam Chapter 4 -Reasons for Inspection: DamageMechanisms

First of all, what exactly is the point of tank inspections? Granted, some leak or catch fire, and there are no doubt a small number of major failures, but the everyday world is not exactly full of catastrophic tank disasters.

On the face of it, API codes are quite clear on the subject – their objective is to achieve tank integrity (it says so in API 653 section 1). Integrity must surely mean structural integrity, i.e. the avoidance of catastrophic failure or major collapse leading to total loss of the tank contents.

All right. What about leaks? Clearly, leaks are undesirable and published codes have quite a bit to say about avoiding them. API 575 starts the ball rolling in its section 5: Reasons for inspection and causes of deterioration. It mentions the objective of avoiding holes in all areas of a tank, to avoid the risk of hazards from flammable leaks or environmental pollution. The situation elsewhere in the codes is not quite so straightforward – it is a long-standing principle of API codes that fairly deep isolated pits are unlikely to lead to structural failure. For tanks, this is balanced by API 653’s approach to repairs; patch plates, flush insert repairs or hot taps are really no problem as far as API 653 is concerned, so leaks from isolated pitting can be repaired if or when they occur.

4.1 The approach to damage mechanisms (DMs) API 653 and its associated codes have a well thought-out approach to DMs. It is better organized than equivalent pipework and vessel codes; a little less fragmented and hence easier to understand. In essence, most of the information on DMs has been relegated out of API 653 into API 571 Damage Mechanisms. Awkwardly, quite a lot of the introductory information remains in API 575. These relatively short sections are a frequent source of exam questions, many taken word-for-word from the rather dense narrative paragraphs. It is fair to say that the key points don’t exactly jump out of the pages at you. Let’s see what they are.

4.2 API 575 section 5: reasons for inspection

API 575 takes a logical approach to this:

Section 5.2 identifies corrosion as the prime cause of deterioration of tanks. This is then subdivided into section 5.2.1 external corrosion and Section 5.2.2 internal corrosion.

For external corrosion, the emphasis is heavily on corrosion of the tank bottom being the main problem. This fits with the overall approach of API 653. External shell corrosion is not covered in detail in API 575 section 5.2.1. API 653 deals with that in detail later.

For internal corrosion, API 575 section 5.2.2 simply reinforces the idea that it is the tank product that generally causes the corrosion. It also mentions bottom sediment and water (BS&W) – a common examination question.

Section 5.4 is about leaks, cracks and mechanical deterioration, i.e. just about anything that is not classed as corrosion. Note these API value judgement points that appear in this section: 

  • The most critical place for crack-like flaws is at the shell-to-bottom weld, owing to the high stresses. 
  • Settlement underneath the tank bottom caused by freezing and thawing can trap water and cause bottom corrosion.

Section 5.5 is about auxiliary equipment such as tank vents, drains, structural steelwork and ladders. It mainly cross-references annex C in API 653 – a long checklist of tank inspection items. This is a very comprehensive checklist, but thankfully next to impossible to use as the subject of multichoice examination questions.

4.2.1 Similar service

Once you start to consider the reasons for inspecting (or conversely, not inspecting) a tank, the issue of similar service raises its head. There is no great difficulty about the principle – it simply means that instead of going to all the trouble of measuring the corrosion rate of a tank, you just assume it is the same as that already determined from another tank in similar service. This is a great idea, as long as you actually believe it.

This idea of similar service is growing in acceptance in the API codes – API 653: 2009 now contains a complete new Annex H about it, and there is also a simpler introduction in API 575 Annex B. We will look at this in detail later; just remember for the moment that it can be used as the justification for not inspecting a tank, rather than the justification for inspecting it.

4.2.2 Reasons for inspection

Both API 575 and 653 infer that the condition of a tank bottom is mainly what drives the need for inspection. They don’t exclude the shell and roof but, on balance, it is the corrosion of bottoms that causes the problems. API RP 651: Cathodic Protection takes a similar view, concentrating mainly on the soil side with its differential aeration and resulting corrosion currents.

In API 575, discussion of the reasons for inspection soon give way to the actual techniques of inspection, and their frequency. Sections 7.2 and 7.3 cover external inspection and section 7.4 internal inspections. API 653 explains the reasons for inspection in various fragments of sections 4 and 6 but is fairly resolute at not going into specific technical details of damage mechanisms. This makes sense – API 571 deals exclusively with DMs (corrosion-based and other types) and is a much better way of presenting them than a piecemeal coverage in API 653. As it develops, API 653 maintains its reputation as a set of good practical engineering guidelines rather than a corrosion handbook.

4.2.3 The link with API 571 damage mechanisms

API exam question setters seem to like API 571. Divided into neat packages of damage mechanisms, each package contains a fairly logical structure of description, appearance, critical factors, affected equipment, inspection and mitigation for each DM in turn. This stuff is just made for exam questions; either closed-book questions on subjects requiring a bit of reasoning or open-book questions based on little more than the verbatim wording with the odd paraphrase thrown in for good measure.

In terms of extent, the API 653 BOK contains only a few of the full range of DMs contained in API 571. This reflects the fact that storage tanks are less likely to see such a wide variety of DMs as refinery vessels or pipework, which can come into contact with high temperatures, aggressive catalysts, sour (H2S) fluids and similar.

Remember the background to API 653 – it exists to anticipate, monitor and ultimately repair the effects of the DMs that attack tanks, so API 571 will always remain a key part of the BOK, and a well-used source of exam questions.

4.3 API 571: introduction

API 571 was added some years ago to the BOK for the API examinations and replaces what used to be included in an old group of documents dating from the 1960s entitled IRE (Inspection of Refinery Equipment). The first point to note is that the API 571 sections covered in the API 653 ICP exam syllabus are only an extract of ten DMs from the full version of API 571.

4.3.1 The ten damage mechanisms

Your API 653 exam copy of API 571 contains (among other things) descriptions of ten damage mechanisms. Here they are in Fig. 4.1.

Remember that these are all DMs that are found in the petrochemical/refining industry (because that is what API 571 is about), so they may or may not be found in other

Figure 4.1 The ten tank damage mechanisms from API 571
Figure 4.1 The ten tank damage mechanisms from API 571

industries. Some, such as brittle fracture and fatigue, are commonly found in non-refinery plant whereas others, such as sulphuric acid corrosion and microbiological-induced corrosion (MIC), are more common in tanks containing petroleum products. In reality, storage tank farms are rarely just limited to refinery products so the boundaries are less well defined than for pressure vessels and pipework.

4.3.2 Are these DMs in some kind of precise logical order?

Yes, more or less. The list contains a mixture of corrosion and non-corrosion DMs, some of which affect plain carbon steels more than alloy or stainless steels and vice versa. There are also various subdivisions and a bit of repetition thrown in for good measure. None of this is worth worrying about, as the order in which they appear is not important.

In order to make the DMs easier to remember you can think of them as being separated into three groups. There is no code significance in this rearrangement at all; it is simply to make them easier to remember. Figure 4.2 shows the revised order.

One important feature of API 571 is that it describes each DM in some detail, with the text for each one subdivided into

Figure 4.2 Tank damage mechanisms: the revised order
Figure 4.2 Tank damage mechanisms: the revised order

six subsections. Figure 4.3 shows the subsections and the order in which they appear.

These six subsections are important as they form the subject matter from which the API examination questions are taken. As there are no calculations in API 571 and only a few tables of detailed information, you can expect most of the API examination questions to be closed book, i.e. a test of your understanding and short-term memory of the DMs. The questions could come from any of the six subsections as shown in Fig. 4.3.

4.4 The first group of DMs

Figures 4.4 and 4.5 relate to the first two DMs extracted from API 571: brittle fracture and mechanical fatigue. Note that these are not corrosion mechanisms but damage mechanisms, with a mechanical basis. When looking through these figures, try to cross-reference them to the content of the relevant sections of API 571.

Figure 4.3 API 571 coverage of DMs
Figure 4.3 API 571 coverage of DMs

Figure 4.4 Brittle fracture
Figure 4.4 Brittle fracture

Figure 4.5 Mechanical fatigue
Figure 4.5 Mechanical fatigue

Now try this first set of self-test questions covering the first two DMs.

4.5 API 571 practice questions (set 1)

Please go to API 653 Exam Chapter 4 to view the test

4.6 The second group of DMs Figures 4.6 to 4.8 relate to the second group of DMs: atmospheric corrosion, CUI and soil corrosion. Note how these DMs tend to be related to the environment outside the

Figure 4.6 Atmospheric corrosion
Figure 4.6 Atmospheric corrosion

Figure 4.7 Corrosion under insulation (CUI)
Figure 4.7 Corrosion under insulation (CUI)

Figure 4.8 Soil corrosion
Figure 4.8 Soil corrosion

storage tank. Remember to identify the six separate subsections in the text for each DM. Try these practice questions.

4.7 API 571 practice questions (set 2)

Please go to API 653 Exam Chapter 4 to view the test

4.8 The third group of API 571 DMs

Now look through Figs 4.9 to 4.12 covering the final group of five DMs: MIC, caustic corrosion, chloride SCC, caustic SCC and sulphuric acid corrosion. These relate predominantly to corrosive conditions on the product side (i.e. inside) of a tank. Again, remember to identify the six separate subsections in the text for each DM, trying to anticipate the type of examination questions that could result from the content.

Figure 4.9 Microbial-induced corrosion (MIC)
Figure 4.9 Microbial-induced corrosion (MIC)

4.8.1 Finally: specific DMs of API 652

For historical reasons the ten DMs extracted into the BOK from API 571 exclude one of the most important ones, corrosion caused by sulphate reducing bacteria (SRB). Discussion of this is hidden away in API RP 652: Lining of Above Ground Storage Tank Bottoms. All of this code is included in the BOK so SRBs need to be added to the DMs considered from API 571. API 652 section 4.5 provides a detailed, if slightly contradictory, explanation of the effect of SRBs. They are basically a facilitation mechanism for concentration cell pitting rather than a separate DM by themselves.

Figure 4.13 summarizes the situation. Read this figure as a clue to the content of API exam questions rather than a detailed technical treatise on the subject. Look carefully at

Figure 4.10 Chloride stress corrosion cracking (SCC)
Figure 4.10 Chloride stress corrosion cracking (SCC)

the form of words used – and do not be surprised if they pop up as exam questions.

Now attempt the final set of self-test questions covering these DMs (start on p. 53).

Figure 4.11 Caustic stress corrosion cracking (SCC)
Figure 4.11 Caustic stress corrosion cracking (SCC)

Figure 4.12 Sulphuric acid corrosion (SCC)
Figure 4.12 Sulphuric acid corrosion (SCC)

Figure 4.13 Sulphate reducing bacteria (SRB): some key points
Figure 4.13 Sulphate reducing bacteria (SRB): some key points

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API 653 Exam Chapter 3

API 653 Exam Chapter 3 – An Introduction to API RP 575

This chapter is about learning to become familiar with the layout and contents of API RP 575: Guidelines and Methods for Inspection of Existing Atmospheric and Low-Pressure Storage Tanks. API RP 575 is a well-established document (it has only recently changed from its first edition to the current 2005 2nd edition) with its roots in earlier documents published by the American refining industry. It is more a technical guide document rather than a code, as such, but it performs a useful function in supporting the content of API 653.

Note the following five points about API RP 575.

3.1 Scope

It has a very wide scope (evidenced by its title), which specifically includes all types of atmospheric and low pressure tanks. This wide scope is evident once you start to read the content; it refers to all types of storage tanks and the design features, inspection methods and damage mechanisms that go with them.

3.1.1 Damage mechanisms

API 575 introduces various corrosion and degradation mechanisms. As expected, these are heavily biased towards the refining industry with continued emphasis on petroleumrelated corrosion mechanisms and cracking. In general, although it provides a description and discussions on corrosion, API RP 575 acts only as an introduction to these corrosion mechanisms, leaving most of the detail to be covered in API RP 571.

3.1.2 Equipment

It is downstream oil industry orientated (not surprising as it is an API document). Its main reference is to the downstream oil sector, a term commonly used to refer to the part of the 25 industry involved in the refining, selling and distribution of products derived from crude oil (gas, petrol, diesel, etc.).

The types of equipment covered by the code can therefore include oil refineries, petrochemical plants, petroleum products distributors, retail outlets and natural gas distribution companies. These can involve thousands of products such as gasoline, diesel, jet fuel, heating oil, asphalt, lubricants, synthetic rubber, plastics, fertilizers, antifreeze, pesticides, pharmaceuticals, natural gas, propane and many others.

3.1.3 Related codes

API RP 575 refers to a lot of related codes that are not in the API 653 exam BOK. Examples are the out-of-print API 12 series and multiple documents in the API 300 series, API RP 307, 315, 322, etc., and others; see API 575 section 2 on page 1 of the document. These provide technical details on specific subjects and problems. Do not worry about these referenced documents; you need to know that they exist but you do not need to study them for the API 653 examination.

 3.1.4 Exam content

API 575 is all text and technical descriptions, accompanied by explanatory photographs of a fairly general nature. It contains few calculations. The only calculations it does contain of any significance are the ones on corrosion rates and inspection periods in section 6. These are important but will be covered later in API 653. In practice, most examination questions about API 575 in the API 653 certification exam are closed book. The downside to this is that API 575 contains several thousand separate technical facts, giving a large scope for the choice of exam questions.

All this means that you need to develop a working familiarity with the technical content of API 575 treating it as essential background knowledge for the API 653 syllabus, rather than as a separate ‘standalone’ code in itself. We will look at some of the more important areas as we work through the document.

3.2 API 575 sections 1 and 2: scope and references

These sections are little more than general information on where the document sits in relation to other API publications. Note however the reference to the older (superseded) API 12A and 12C specifications. There are obviously storage tanks still around that were made to these codes, rather than API 650 and 620: the codes that replaced them.

3.3 API 575 section 3: definitions

API 575 section 3 bears a startling resemblance to the equivalent section in API 653. This is a feature of API codes in general; there is repetition between them, although hopefully no (or, at least, not much) actual contradiction. Most of the definitions in this section (alteration/repair/ reconstruction, etc.) are exactly the same as given in API 653 and therefore do not need further study. There are, however, a couple of new ones.

Definition 3.3: atmospheric pressure

This used to feature in API 653 but has recently been taken out of several parts of the code. The important point is how it defines an atmospheric tank as one that is actually designed to withstand an internal pressure of up to 2.5 psi (18 kPa) gauge pressure (i.e. above atmospheric).

Definition 3.8: examiner

This is a concept that features in API 570 and 510 for pipes and vessels but is mysteriously absent from API 653, appearing, instead, here in API 575. Do not confuse this as anything to do with the examiner who 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 storage tank inspector. API recognizes the NDT technician as a separate entity from the API-authorized storage tank 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 653 examination. Other countries’ codes are not actually prohibited, but are not mentioned either. Welcome to America.

API codes only really recognize US NDE qualifications, hence the reference to SNT-TC-1A, etc., qualifications for NDE ‘examiners’ (that term again).

Definition 3.13: reconstruction

The term reconstruction means dismantling a tank and then reassembling it on a new site. Visualize a large tank on the back of a 48-wheel trailer holding you up on the motorway and you get the picture. Do not confuse this with tank repair (definition 3.15), which does not involve moving the tank to a new site.

All the other definitions are the same (more or less) as in API 653 and are nothing to get excited about, unless you have a particularly low excitement threshold.

3.4 API 575 section 4: types of storage tanks

Although it looks fairly complicated, API 575 section 4 only covers two generic types of storage tank: atmospheric tanks and low pressure tanks. The definitions are simple:

Atmospheric tanks (API 650) are designed to a gauge pressure of ≤ 2 1/2 psi.

Low pressure tanks (API 620) are designed to a gauge pressure of 2 1/2 -15 psi.

Most of the API examination questions will be about the atmospheric type of tanks since API 620 is (strictly) not in the BOK.

Note in API 575 section (4.2.2) the definition of vapour pressure. This is defined as the pressure existing on the surface of a confined liquid caused by the vapours given off by the liquid. It is the value of this vapour pressure that determines whether a fluid can be stored in an atmospheric tank or requires a (low) pressurized tank.

Section 4.2.3: types of atmospheric storage tank roofs

Atmospheric tank designs are differentiated mainly by their type of roof. There are several different designs of shell (flanged, ribbed, spiral-wound, etc.) but they are not covered in the scope of API 575. The two main generic types are fixed roof and floating roof. Floating roofs are used when there is a need to avoid the accumulation of flammable/explosive vapours in the space above the fluid.

Look at section 4.2.3 and highlight the main points of the descriptions of the following roof types:

  • Fixed cone roof
  • (Fixed) umbrella roof
  • (Fixed) dome roof
  • Pan-type (floating) roof
  • Pontoon (floating) roof
  • Double-deck (floating) roof

Have a look also at the type that has a floating roof, but with an additional fixed roof above it (Fig. 13 of API 575). This is to isolate the floating roof from the weather and/or to ensure that particularly hazardous vapours are not released into the atmosphere. Two other (fairly rare) atmospheric types are the breather type and balloon type (Fig. 15)

Section 4 also shows various types of seals that are used on floating roof tanks (see the figures in section 4). These are fairly straightforward and do not give great scope for exam questions.

Section 4.3: low pressure storage tanks

Low pressure tanks do not form a major part of the API 653 syllabus and they are not covered in much detail in API 575. Note the few significant points about them, however, in section 4.3.2:

They are constructed to API 620, not API 650.

They are necessary when the vapour pressure of the stored fluid exceeds the 2 1/2 psi limit of API 650-type atmospheric tanks. Volatile products such as light crude, some petrol products and liquid oxygen/nitrogen fall into this category.

There are various designs, some of them quite elaborate domed shapes, but many are now made spherical, as this is the best shape for retaining pressure and they are not too difficult to make.

Have a look at the various figures in API 575, highlighting the design features of storage tanks.

Now try these questions on types of tanks and their construction features.

3.5 API RP 575: practice questions

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API 653 Exam Chapter 2

API 653 Exam Chapter 2 – An Introduction to API 653 2009 and its Related Codes

API codes, and the way in which they are written, are an acquired taste. As with all tastes that develop over time, some people eventually acquire it, some pretend to (because it sounds good) and others do not, but just put up with it. API codes are written from the viewpoint of the US refinery industry, so if you are not in the US refinery industry you may find some of the concepts and terminology different. In particular, the system of personnel responsibilities (what the inspector has responsibility for) bears little resemblance to the way that things work in many tank operator companies in the Middle East , Australia, Canada, Undited State, UK and Europe.

This chapter is about learning to become familiar with the layout and contents of API 653. It forms a vital preliminary stage that will ultimately help you understand not only the content of API 653 but also its cross-references to the other relevant API and ASME codes.

API 653 is divided into 13 sections (sections 1 to 13) and nine annexes followed by a large group of figures and 12 tables. Even when taken together, these are not sufficient to specify fully a methodology for the inspection, repair and alteration and reconstruction of storage tanks. To accomplish this, other information and guidance has to be drawn from the other codes included in the API 653 body of knowledge (BOK).

Figure 2.1 shows how all these codes work together So that we can start to build up your familiarity with API 653, 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 653 contents/index page. This is laid out broadly as shown in Fig. 2.1.

Figure 2.1 The API 653 body of knowledge (BOK) codes
Figure 2.1 The API 653 body of knowledge (BOK) codes

2.1 Section 1: scope

This is a very short (one-page) part of the code. Unlike some other API codes (and earlier versions of this one), this section does not give a list of types of tanks that are specifically included or excluded from the coverage of API 653. The main emphasis is on the principle that API 653 can be used in relation to tanks that were built to the construction code API 650, or any other tank construction code (e.g. BS 2654).

Note also how the fitness-for-service (US terminology for fitness-for-purpose) document API RP 579 is cross-referenced for the source of more detailed assessment procedures than are given in API 653. As with all the API Certified An Introduction to API 653: 2009 and its Related Codes

Figure 2.2 The contents of API 653
Figure 2.2 The contents of API 653

Figure 2.2 The contents of API 653 (continued)
Figure 2.2 The contents of API 653 (continued)

Inspector examination scopes, the actual content of API 579 is not in the exam syllabus; you just need to know of its existence, and broadly what it covers.

Section 1.2: compliance

The overriding principle of this section is identifying the party with the ultimate responsibility for compliance with API 653 as the user/owner of the storage tanks (not the APIcertified inspector). There is an inference in this section that all other involved parties should have responsibilities for their own actions, but the overriding responsibility still lies with the user/owner. Again, this is a principle common to all the API in-service inspection codes.

Section 1.4: safe working practices

Strictly, API codes are not health and safety (H&S) documents. There does seem to be a trend, however, as new editions are published, to cross-reference various H&S documents that have an influence in various ‘jurisdictions’ in the USA or related API documents that contain H&S information.

Note how this section references API 2015 (safe entry to tanks), API 2016 (entering and cleaning tanks) and API 2217A (work in confined spaces). They also appear in the list of referenced codes shown in section 2 of API 653. Questions on H&S requirements often appear in the closed-book section of the API exam paper. They are invariably of a fairly general nature and relate mainly to avoiding the danger of confined spaces or explosive atmospheres in empty tanks.

2.2 Section 3: definitions

This section of API 653 is smaller than the equivalent one in API 570 or API 510. Although it has been expanded in this latest 2009 edition of the code, it contains fewer technical definitions than is usual, mainly because a lot of the technical details on storage tank subjects are presented in API 575, rather than in API 653 itself. We will look at the content and major technical points of API 575 later.

There are a few specific definitions listed in API 653 that you need to understand at this stage.

Section 3.1: alteration

An alteration is defined in API 653 as any work on a tank that changes its physical dimensions or configuration. Note how this is a much broader definition than in API 510/570 where an alteration is more specifically defined as a change that takes a component outside the documented design criteria of its design code. There is probably no hidden reason behind the differences in approach (other than they were written by different people).

This definition leads on to one of the main thrusts of the content of API 653 – that of tank repair and reconstruction. The whole concept behind API 653 seems to be that a storage tank inspector is going to spend their life looking at tanks that resemble rust-buckets and need imminent repair to stop them leaking or falling down. This would suggest that some probably do.

Section 3.3: authorized inspection agency

Again, this can be a bit confusing. The four definitions (a to d) shown in API 653 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 control of major accident hazards (COMAH) and other H&S legislation form the statutory requirement. For atmospheric storage tanks, the nearest match to the ‘authorized inspection agency’ in the UK is probably the Health and Safety Executive (HSE). It is different with pressure equipment, where the Pressure System Safety Regulations (PSSRs) and their ‘Competent Person’ inspection body occupy the nearest role to the ‘authorized inspection agency’ position.

Section 3.4: authorized inspector

This refers to the USA situation where, in many states, storage tank inspectors have to be certified to API 653. There is no such legal requirement in the UK (but don’t tell anyone). Assume, for this book, that the authorized inspector is someone who has passed the API 653 certification exam and can therefore perform competently the storage tank inspection duties covered by API 653. Note this difference to other API codes:

API 653 is noticeably different to API 510 (vessels) and 570 (pipework) in that it does not spend lots of time trying to list the numerous responsibilities of the authorized inspector. This may be because API are trying to make their codes more relevant to non-US situations where the responsibilities are different. Instead, API 653 concentrates much more on the technical aspects of tank inspections. This is good news, because this is what codes are supposed to be for. No one consults the stultified content of codes when working out job descriptions or contract wording.

Figure 2.3 summarizes how API 653 sees the duties and responsibilities of the tank owner/user and API-certified tank inspector.

Section 3.7: change in service

Changes in service of storage tanks are perfectly allowable under the requirements of API 653, as long as code compliance is maintained. In the USA, the API-authorized inspector is responsible for accepting changes of service, once he is happy with the results of thickness checks, change of process conditions, etc. In the UK way of working, this is unlikely to be carried out by a single person (although, in theory, the API 653 qualification should qualify an inspector to do it).

Figure 2.3 Roles and duties
Figure 2.3 Roles and duties

Section 3.19: owner/operator

This section appears in many of the API codes. Sometimes it refers to the owner/user, rather than owner/operator. The overriding principle is that the API-certified storage tank inspector is responsible to the owner/user for confirming that the requirements of API 653 have been met. You will see this as a recurring theme throughout this code (and there will almost certainly be examination questions on it).

Section 3.23: reconstruction organization

Surprisingly, API 653 exerts little control on who is allowed to carry out repairs to storage tanks. Contrast this to the API approach on pressure vessels, where organizations that hold an ASME ‘code stamp’ (certificate of authorization) are seen as the main participants.

Section 3.24: repair

API 653 places great importance on the activities of repair and reconstruction of storage tanks. To this end, definition 3.24 specifies four broad definitions of repair activities. These are:

  • Replacement of bits of tank roof, shell or bottom
  • Re-levelling and/or jacking of bits of a tank
  • Adding reinforcement plates to existing shell penetrations
  • Repairing defects by grinding-out and welding

The key aspects of this are not the repair activities themselves (they are fairly obvious), but what happens after the repair is completed. Look back to API 653 definition 3.2 ‘as-built standard’ and read what it says. Three things should become apparent:

In the USA, great emphasis is obviously placed on what edition of the code a tank was built to (originally) and repaired to (after it has developed rust-bucket status). This is not necessarily of such interest in other countries but API and ASME codes clearly revolve around it.

The main US code for both construction and repair is actually API 650, rather than 653.You can see this from the list of revisions in API 653 Annex A. Note how API 650 was preceded by the older code API 12C. In the most recent edition of API 653 it is clear that API are keen to recognize other tank construction codes, as well as API 650. This explains the use of the generic term ‘as-built standard’ instead of assuming that all tanks have to be built to API 650.

It is possible for a repaired tank to be rated to several

Figure 2.4 API 653 definitions of major repairs (MR) and major alterations (MA)
Figure 2.4 API 653 definitions of major repairs (MR) and major alterations (MA)

separate construction code editions, one for the original construction and one for the re-rating, each time it is repaired or altered. Note the sections of definition 3.2 where it says this. Note also the statements in the section where it gives the situation if the original code edition, or the actual construction date, are not known.

Section 3.18: major alteration/repair

As a related section to section 3.24, section 3.18 specifies what API 653 considers a major alteration/repair. These definitions have some implications as to the applicability of other sections in the code. Figure 2.4 summarizes the eight definitions.

Section 3.21: recognized toughness

This rather strangely titled definition is in recognition of a link to section 5 of API 653 which covers the avoidance of brittle fracture in storage tanks (both new and repaired). Brittle fracture at low ambient temperature is one of the few catastrophic failure mechanisms that can affect storage tanks so API 653 contains quite a bit of content aimed at avoiding it. It is purely a function of material choice, so mitigation measures are fairly predictable. We will see these covered later in API 653 section 5 and API 571.

Now try these introductory questions on the scope and definitions of API 653: 2009. The answers are in the back of this book.

2.3 API 653 scope and definitions: practice questions

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API 653 Exam Chapter 1

API 653 Exam Chapter 1- Interpreting API and ASME Codes

It would help if things were different, but passing any API Inspector Certification Programme (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 further, 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 (only sections V and IX are included in the API 653 ICP body of knowledge) 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 653) and their supporting recommended practice document (API RP 575: Guidelines and Methods for Inspection of Existing Atmospheric and Low Pressure Storage Tanks) are very different. Recommended practice (RP) documents are not formal 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 tank 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 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 occasional cases, meanings can differ between ASME and API. This is actually less of an issue in the API 653 ICP than in the other ICPs because, unlike pressure vessels, the construction code for tanks is an API one: API 650. In general however, API codes benefit from their principle of having a separate section (see API 653 section 3) containing definitions. These definitions are selective rather than complete (try to find an accurate explanation of the difference between the terms approve and authorize, for example).

Questions from the ICP examination papers are based solely on the terminology and definitions understood by the referenced codes. That is the end of the matter.

1.3.2 Calculations

Historically, both API and ASME codes were based on the United States Customary System (USCS) family of units. There are practical differences between this and the European SI system of units.

SI is a consistent system of units, in which equations are expressed using a combination of base units. For example, a generic hoop stress equation broadly applicable to pressure vessels or tank shells is

                       pressure(P) x diameter (d)

Stress (S) =  _____________________________

                             2x Thikness(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

tmin = 2.6 (H -1 DG)

         _____________  
                SE

. 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 approaches 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, 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 often not heavily illustrated, relying more on text. For storage tanks, however, the situation is a little different. Both API 653 and its partner recommended practice API RP 575 contain quite a lot of figures, tables and photographs. This makes them easier to read than, for example, the equivalent API codes for pipework or pressure vessels.

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 575 is a typical example containing photographs, tables and drawings (sketch format) of a fairly detailed 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. One difficulty comes from the fact that, although ASME V (NDE) and ASME IX

(welder qualifications) were written exclusively from the viewpoint of new construction, they are both referred to by API 653 in the context of in-service repair and, to a lesser extent, re-rating. The main problem with storage tanks, however, is competition between API codes, as both the construction code API 650 and the in-service inspection code API 653 are of course both API documents The ground rules (set by API) to manage this potential contradiction are as follows (see Fig. 1.1).

  • For new tank construction, API 650 is used – API 653 plays no part.
  • For tank repair, API 653 is the ‘driving’ code. In areas where it references ‘the construction code’ (e.g. API 650), then this is followed when it can be (because API 653 has no content that contradicts it).

Figure 1.1 New construction versus repair
Figure 1.1 New construction versus repair

For tank repair activities where API 653 and API 650 contradict, then API 653 takes priority. Remember that these contradictions are to some extent false – they only exist because API 653 is dealing with on-site repairs, while API 650 was not written with that in mind. Three areas where this is an issue are:

  • Some types of repair weld specification (material, fillet size, electrode size, etc.);
  • Decisions on whether a tank requires pressure testing;
  • Assumptions on material strength and impact test requirements.

For tank reconstruction (cutting a tank up and reassembling it somewhere else) API 653 is, strictly, the driving code, so if there were any contradictions between API 653 and API 650, then API 653 would take priority. In practice, API 653 actively cross-refers to API 650 in most areas, so the problem rarely exists.

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 approaches and styles of the ASME codes (V and IX) into the same style of questions and answers that fall out of the relevant API documents (in the case of the API 653 ICP these are API 651, 652, 575, 650 and 653). Figure 1.2 shows the situation. It

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

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.

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1. API Recommended Practice 574, Inspection of Piping, Tubing Valves, and Fittings, does not cover.

a. Control valves.
b. Piping smaller than 2” NPS
c. Tubing smaller than 1.5” diameter
d. Fittings smaller than 2” NPS

2. The refining industry generally uses what type piping for severe service?

a. Brass
b. Cast
c. Seamless
d. Longitudinal seam welded

3. Piping made by rolling plates to size and welding the seams is larger than_____ inches outside diameter.

a. 10
b. 16
c. 14
d. 12

4. Steel and alloy piping are also manufactured to standard dimensions in nominal pipe sizes up to _____inches.

a. 24
b. 36
c. 48
d. 50

5. Steel and alloy piping are also manufactured to standard thicknesses designated as schedules in nominal pipe sizes up to _____inches.

a. 24
b. 36
c. 48
d. 50

6. The actual thickness of wrought piping may vary from its nominal thickness by a manufacturing under tolerance of as much as______ percent.

a. 12.5
b. 12.0
c. 10.0
d. 10.5

7. Cast piping has thickness tolerance of +___inch and – ____inch.

a. 1/16,0
b. 1/16, 1/16
c. 1/32, 1/32
d. 3/64, 0

8. For all nominal pipe sizes of ____ inches and smaller, the size refers to the nominal inside diameter.

a. 10
b. 12
c. 14
d. 16

9. Under tolerance of welded pipe often used in refinery service is _____ inch.

a. 0.125
b. 0.050
c. 0.010
d. 0.005

10. For what service is cast iron piping normally used?

a. Non-hazardous service, such as lube oils.
b. Non-hazardous service, such as water.
c. Corrosive service, such as acids.
d. Non-corrosive service, such as low temperature caustic.

11. Tubing is generally seamless drawn, but it may be welded. Its stated size is its actual:

a. Outside radius
b. Inside diameter
c. Outside diameter
d. Inside radius

12. There are many type valves. Which is incorrect valve type listed below?

a. Style valve
b. Gate valve
c. Check valve
d. Globe valve

13. What type valve is normally used in a fully open or fully closed position?

a. Gate
b. Globe
c. Slide
d. Plug

14. What type gate valves have body and port openings that are smaller than the valves’ end opening.

a. Borda tube gate valves
b. Reduced-port gate valves
c. Weir gate valves
d. Sluice gate valves

15. What type of gate valve should not be used as block valves associated with pressure relief devices?

a. It is normally used as block valve
b. It is commonly used to regulate fluid flow
c. It is ordinarily used to measure pressure drop
d. It is frequently used in place of a slide valve.

16. What is a globe valve used for?

a. Sluice gate valves
b. Weir gate valves
c. Borda tube gate valves
d. Reduced-port gate valves

17. A plug valve consists:

a. Of a slide or slides that operate perpendicularly to the flow and move on rail guides to interrupt flow.
b. Of a ball with a hole in it that fits into the valve body and interrupts the flow of material.
c. Of a circular gate that operates in and out in the body to interrupt flow.
d. Of a tapered or cylindrical truncated cone with a slot fitting into a correspondingly shaped seat.

18. What type of valve depends upon a spherical type gate has a hole in it and is rotated to open or close it?

a. Diaphragm valve
b. Plug valve
c. Globe valve
d. Ball valve

19. What are check valves normally used for?

a. They are generally used in erosive or high-temperature service.
b. They are used to automatically prevent backflow.
c. They are commonly used to regulate fluid flow.
d. They are used for conditions that require quick on/off or bubble tight service.

20. What are slide valves generally used for?

a. They are used to automatically prevent backflow.
b. They are used for conditions that require quick on/off or bubbletight service.
c. They are generally used in erosive or high-temperature service.
d. They are commonly used to regulate fluid flow.

21. What type of joint listed below would you NOT used in a 300 psi pipe system?

a. Lap-joint flanged
b. Welded
c. Bell-and-spigot
d. Weld-neck flanged

22. What type of pipe joint is generally limited to piping in non-critical service and has a nominal size of 2 inches or smaller?

a. Flanged joint
b. Threaded joint
c. Socket-weld joint
d. Butt-welded joint

23. Socket welded joints are usually used in nominal pipe size of _______ or smaller.

a. 4”
b. 3”
c. 2.5”
d. 2”

24. Which of the joints listed is the most common found in the petroleum industry?

a. Compression joints
b. Butt-welded joints
c. Bell-and-spigot joints
d. Sleeve joints

25. The primary purpose of piping inspection is to:

a. Satisfy the requirements of jurisdictional regulations.
b. Achieve ate the lowest cost, piping that is reliable and has the desired quality.
c. Ensure plant safety and reliability; also achieve desired quality assurance.
d. Produce a piping system that meets minimum design and serviceability requirements.

26. Adequate inspection is a prerequisite for maintaining piping:

a. In a leak free condition
b. Satisfactory to the owner-user
c. In a satisfactory operating condition
d. In a safe, operable condition

27. OSHA 1910.119 mandates that:

a. Piping be inspected to a code or standard such as API 570.
b. Owner/user adopt API 570.
c. Water piping be inspected the same as chemical piping.
d. The owner/user immediately shut down corroded piping system.

28. Regularly requirements usually cover only those conditions that affect:

a. Pollution
b. Operations
c. Safety
d. Maintainance

29. The single most frequent reason for replacing piping is:

a. An over-zealous Inspector
b. In-service cracking
c. H2S deterioration and erosion
d. Thinning due to corrosion

30. On piping that is operating, the key to effective monitoring of piping corrosion is identifying and establishing __________________.

a. L.O.L’s
b. J.L.G’s
c. T.M.L’s
d. C.U.I’s

31. You are asked to recommended a method for determining the thickness of a pipe that has 1.5” of insulation, with a vapour barrier, and aluminium jacketing on it. Problems can occur when tightening bolts to correct leaking flanges in-service. Which of the below is not one of these problems?

a. Bolt interactions
b. Yielding due to overload
c. Flange deflection
d. None of the above

32. Which one of the following is not a factor for consideration when establishing corrosionmonitoring programs?

a. Accessibility
b. Circuitisation
c. Transducer diameter
d. Risk classification

33. A greater loss in metal thickness will usually be observed near a restriction or change in direction in a pipe line. What usually causes this?

a. The effects of turbulence or velocity
b. The effects of stagnation or fretting
c. The effects of corrosion or declination
d. The effects of oxidation or waning

34. What type of problem would you expect to find in catalyst, flue-gas, and slurry piping on a Fluid Catalytic Cracking Unit.

a. Embrittlement
b. Cracking
c. Corrosion
d. Erosion

35. Stainless steel such as type 304 18 Chr.-8 Ni in the presence of temperature above 100° F. may crack because of the presence of:

a. Nitrates
b. Sulphides
c. Chlorides
d. Dissolved oxygen

36. A 2” diameter line is injecting a product into an 8” diameter pipe. What type of deterioration would you expect to take place?

a. Accelerated corrosion or erosion
b. Long term corrosion
c. Chloride cracking
d. Dissolved oxygen pitting.

37. An inspector is checking a piping system that has had problems with isolated corrosion at or near the welds of piping shoes. Without knowing what product is in the line, what would be the best answer below for the problem?

a. The shoes are at high stress points and thus leaks occur.
b. The welds of the shoes to the pipe were too large.
c. The welds of the shoes to the pipe burned nearly through the pipe.
d. The shoes are acting as cooling fins and causing localized temperature differences.

38. What type of problem would you expect in piping containing Amine?

a. Dissolved oxygen cracking
b. Stress corrosion cracking
c. Galvanic corrosion
d. Crevice corrosion

39. What area do you consider to be of most concern when inspecting a piping system?

a. Underneath insulation on lines operating at temperatures above 2000F.
b. In a straight run pipe containing motor oil
c. At and/or downstream of a chemical injection point.
d. Underneath insulation on lines operating below 250F.

40. Leaks in utility piping (water, steam etc.) are:

a. Only of minor concern and may be disregarded.
b. Always dangerous but losses are negligible.
c. Seldom hazardous but they do result in losses.
d. Usually hazardous and losses result.

41. Where do many (maybe the majority) of leaks occur in pipelines?

a. Straight runs of piping
b. Flanges or packing glands
c. Changes of direction of piping
d. Downstream of injection points

42. The prompt repair of __________ will often prevent serious corrosion or erosion of gasket surface or packing glands.

a. Supports
b. Leaks
c. Guides
d. Welds

43. The deformation of a vessel wall in the vicinity of a pipe attachment; expansion joints that are not performing properly; a pipe dislodged from its support; etc are evidence of:

a. Misalignment
b. Leaks
c. Weld problems
d. Drips

44. Spring hanger loading should be checked under:

a. Elevated temperature conditions
b. Both cold and hot conditions
c. Sub-zero temperature conditions
d. Ambient temperature conditions

45. An inspector finds concrete fireproofing around a structural steel column with openings (cracks). The inspector suspects that water may be entering. What should the inspector do?

a. The inspector should ask his supervisor what he should do.
b. All the fireproofing should be stripped from the column.
c. Enough fireproofing should be removed to determine the extent of the problem.
d. No action should be taken.

46. If a steel column in a pipe support rack is corroded. What should the inspector do?

a. Have the corrosion products cleaned off and have the column painted
b. No action is required
c. Thickness measurements should be taken to determine whether enough metal is left to safely support the load.
d. Call a piping engineer.

47. How do you inspect non-destructively for loose or broken foundation bolts?

a. Break out the concrete around the foundation bolt.
b. Hammer the bolts vertically with a hammer.
c. Lightly rap the bolts sideways with a hammer while holding a finger against the opposite side.
d. Radiograph the foundation.

48. If you find a slotted hole in a base-plate, what would this indicate to you?

a. It indicates that the craftsman making the hole was not sure of it exact location.
b. It indicates that the base-plate may have been designed to accommodate expansion.
c. It indicates that the base-plate was possibly made to be used in multiple locations.
d. It indicates that the base-plate had two holes side by side punched in it by mistake.

49. As an inspector, you find a 6” diameter pipe line that is vibrating and swaying. What is one of the most important things you would check for and where would you check?

a. Fireproofing on the supports should be checked for spalling and breaking.
b. Welds should be inspected for cracks, particularly at points of restraint.
c. Base-plates of the pipe supports should be checked to see if the bolts are tight.
d. Valves in the system should be checked to insure they are not vibrating open/closed.

50. An insulated pipe shows evidence of defects in the jacketing covering the insulation. You suspect that water may be getting in through the defects. What you would do?

a. Strip the pipe line complete to allow 100% inspection and renewal of the insulation.
b. If no discoloration is present to indicate corrosion (rust), no action is required
c. Strip enough insulation to determine the extent and severity of possible corrosion.
d. Strip at least 50% of the insulation from the pipe to allow examination.

51. While inspecting an underground pipe line right-of-way, you find a discolored spot on the ground near a road that crosses the right-ofway. Which of the items below would be the course you would follow?

a. The inspector should make a note for the records and have the area checked at some future time for possible leakage.
b. It is not unusual to have discoloration on pipe line right-of-ways. If the discoloration is not wet and there is no evidence of leakage, no action is required.
c. The inspector picks up material from the discolored area. If it smells okay and no there is no reaction on the skin, the area should pose no problem.
d. The discoloration should be investigated as a possible spill. Soil or liquid samples should be checked to see if it is corrosive to the underground.

52. An increase in pump pressure at the pump accompanied by a decrease in flow in a pipe line downstream is an indication of _________.

a. Leakage
b. A broken line
c. Effluence
d. Fouling

53. Ultrasonic instruments are widely used for thickness measurements and are used extensively by inspection organizations. If a transducer is not equipped with “high temperature” delay-line material, it can be damaged by temperatures over ________ °F.

a. 150
b. 1000
c. 250
d. 300

54. What would you expect to happen if you were taking UT readings on piping that was operating higher than 2000F?

a. The thickness readings could be at least 10% higher or lower.
b. The thickness readings would not be influenced.
c. The thickness readings could be about 1% to 5% higher depending on the temperature.
d. The thickness readings would be 15% higher or lower.

55. An insulated piping system needs to have its pipe wall thickness checked. The owner-user does no want holes cut in the insulation for UT measurements and they do not want to shut down. What would you do to obtain thickness readings?

a. AE
b. MT
c. ET
d. RT

56. Reduction of strength of the metal in a pipe, scaling, bulging, metal deterioration or complete failure are all symptoms of:

a. Excessive pressure
b. Low temperature
c. Excessive temperature
d. Blocked effluent

57. Points of probable external corrosion of underground piping can be located by a series of measurements of the:

a. Electrical resistance of surrounding soil or by measurement of pipe-to-soil electrical potential
b. Wattage of the surrounding piping or by measurement of pipe-to-conduit electrical resistance.
c. Potential of the cathodic protection or by wattage of the pipe-to-soil electrical resistance.
d. Volt-amps readings of the surrounding soil or by measurement of pipe-to-pipe electrical potential.

58. One of the most important things that an inspector must do before he actually goes out to make an inspection is:

a. Make sure all electrical potentials have been checked and shut off where necessary to prevent contact.
b. Check all lines to just before the point they enter the unit limits to make sure only the unit lines are inspected.
c. Review the condition of transportation (cars, trucks, scooters, bicycles etc.) to make sure transportation is not interrupted.
d. Review the records of previous inspections and of inspections conducted during the current operating period.

59. When making a visual internal inspection of a pipe and fouling is found, what should the inspector do?

a. Make a note to include in the records; another inspector at the next period may want to investigate further.
b. Check with the operators to see if it is causing problems, if no problems no further action is necessary.
c. Cleaning should be considered, also, the deposits should be checked to find their origin.
d. Have the line cleaned completely immediately, make a complete write up for records.

60. The locations on piping most susceptible to cracking are:

a. Changes of directions
b. Welds
c. Straight runs
d. Flange bolts

61. When checking austentic materials for cracks using PT methods only liquid penetrants:

a. With low or no nitrides should be used.
b. With low or no carbides should be used.
c. With high or medium chlorides should be used.
d. With low or no chlorides should be used.

62. What type of defect would you expect to find at the problem of a groove of a ring joint flange made from ASTM-347 Stainless Steel?

a. pits
b. cracks
c. hydrogen blisters
d. fouling

63. Valves should be dismantled at specified intervals to permit examination of all internal parts. Body thickness should be measured at locations that were inaccessible before dismantling, particularly at:

a. The disk seating surfaces
b. Flange where the bonnet is attached.
c. Locations that show evidence of corrosion or erosion.
d. Random locations throughout the valve.

64. Bodies of valves that operate in severe cyclic temperature service should be checked internally for:

a. Erosion
b. Fouling
c. Cracks
d. Pitting

65. Gate valves should be measured for thickness between the seats, since serious deterioration may have occurred because of:

a. Cracks
b. Turbulence
c. Fouling
d. Corrosion

66. Why is the area between the seats of a gate valve a weak location?

a. Pitting can occur at this location while the valve is operating open.
b. Fouling can occur at this location where there is a possibility of high velocity.
c. The body of the valve is thinner in this location.
d. The wedging action of the disk when is seats causes strain in this area.

67. After a valve has been inspected, repaired, and reassembled, what should be done next?

a. It should be plasited inside to prevent corrosion and returned for reinstallation.
b. It should be returned to the job for reinstallation
c. It should be painted and the inlet and outlet capped.
d. It should be tested to API 598 requirements.

68. In addition to checking the gasket surfaces of flanges for defects, and checking for corrosion and erosion, which of the following additional checks:

a. The rating of the flanges must be checked to make sure that they are both class 150 and they both have the same number of bolt holes.
b. The bolts should be checked for proper specification, stretching and corrosion. The gasket must be of the proper type and material.
c. The flange bolt holes must match and at least one flange must be a class 15 or 30.
d. The bolts should be machine grade and brand-new. The gasket must be a minimum of a spiral wound grafoil filled.

69. A weld is being made in carbon steel piping carrying Amine (MEA). What should the inspector check in addition to insuring that the weld is proper and meets specification?

a. The class of the piping, i.e. 150,300,600 etc should be verified.
b. Amine can cause environmental cracking; the weld should be checked for hardness.
c. Welds on the weld hangers should be made checked and the results recorded.
d. Check the seating surface and lightness of the joint by WFMT.

70. Welded joints in carbon steel and carbonmolybdenum steel exposed to elevated temperatures of 8000 F or over may be subject to:

a. Hydrogen attack
b. Graphitization
c. Environmental cracking
d. Graphitic corrosion

71. Which one of the listed is not a cause for a threaded joint leak?

a. Use of the proper lubricant
b. Improper assembly or loose threads
c. Corrosion or poor fabrication
d. Cross threading or dirty threads at assembly

72. Why should a leaking threaded joint not be tightened while the system is in service under pressure?

a. An undetected crack in a thread root might fail and cause a release of product.
b. Tightening may exacerbate the hardness of the threads and cause leaks.
c. The pressure on the gasket may be so great that it causes a failure and thus leaks.
d. Supports may fail if the threaded joint is lightened-tension on the supports.

73. What type of pipe joint must not be used without adequate axial restraint on the piping?

a. Threaded joints
b. Flanged joints
c. Clamped joints
d. Welded joints

74. Which of the following is not a cause of misalignment?

a. Inadequate provision for expansion or broken and/or defective anchors or guides.
b. Too many bolts in the flanges or bolts with the wrong material.
c. Excessive friction on sliding saddles or broken or corroded rollers.
d. Excessive operating temperatures or broken or improperly adjusted hangers.

75. Where excessive vibration or swaying was noted in a piping system during operation, an inspection should be made for points of _________ and __________ _________ and for cracks in welds at locations that could not be inspected during operation.

a. Graphitization, graphitic corrosion
b. Scaling, internal oxidation
c. Abrasion, external wear
d. Rusting, hydrogen blisters

76. Piping that has been in service or had hot spots of 8000F and above should be checked for creep or deformation with time under stress by:

a. Using a transit to establish correct alignment and elevation or plumbness.
b. Measuring the outside diameter of the pipe and comparing established data for life.
c. Pressure testing the piping to ensure it is serviceable.
d. Examining the piping with acoustic emission equipment.

77. Special attention should be given to small connections such as vents, bleeders, any type of small nipple. One method for successfully checking the condition and the thickness of nipples is the use of:

a. RT
b. AE
c. MT
d. PT

78. A pressure test for piping, in most cases is a:

a. Leak test
b. Stress test
c. Ebullition test
d. Strength test

79. Any system being tested needs to be completely isolated to:

a. Prevent the testing medium from the entering connecting lines.
b. Insure only the system in question is tested.
c. Minimize the amount of work by limiting the lines in the test.
d. Stop the testing medium from being contaminated with material from other lines.

80. If a pressure test is conducted with air or if excess air is trapped in a system that is being hydrostatically tested, a failure of the system will be:

a. Less violent than in a totally liquid filled system because it does not expand as rapidly as a hydraulic medium.
b. Easy to manage because the air will prevent liquid from being spread of the area and possibly causing an environmental incident.
c. More violent than in a totally liquid filled system because of the expansion of the compressible medium.
d. Of little consequence since it the failure will be similar to air leaking from a nail hole in a motor car tire inner tube.

81. Which of the following materials NOT be commonly used for a pressure test?

a. Water with or without an inhibitor, freezing-point depressant, or wetting agent.
b. Hydrogen, hydrogen sulphide, gasoline, liquid propane or weak hydrogen chloride.
c. Liquid products normally carried in the system, if the are not toxic or likely to cause a fire in the event of a leak or failure.
d. Steam, air, carbon dioxide, nitrogen, helium or another inert gas.

82. In which of the following systems would water be a questionable test medium?

a. Gasoline reflux lines, propane piping, and butane systems.
b. Diesel fuel systems, gas oil systems, and kerosene systems.
c. Acid lines, cryogenic systems, and air drier systems.
d. Reboiler oil systems, boiler piping, and steam turbine lines.

83. What should be considered when testing carbon steel piping during cold weather or if cold fluids are used in the testing?

a. The transition temperature of the steel should be considered to prevent brittle failure.
b. The test medium may freeze if it escapes during test.
c. The transition temperature of the medium should be considered for brittle cracking.
d. The translation temperature of the test medium may freeze the test gages.

84. What is the preferred medium for a pneumatic test?

a. A flammable gas
b. An inert gas.
c. Hydrogen gas
d. Propane gas

85. What type of piping usually has a pressure recorder attached in which a permanent record of the test is made?

a. Boiler piping
b. Underground piping
c. Light hydrocarbon unit piping
d. Operating unit piping

86. Which of the following piping should NOT be hammer tested?

a. Pipe made from steel on a Fluid Catalytic Cracking Unit.
b. Steel pipe and lines off a crude tower on a crude still.
c. Cast iron and stress-relieved lines in caustic and corrosive service.
d. ASTM A-106 Grade A pipe on a catalytic Reforming Unit.

87. New construction piping should meet the requirements of __________ as a minimum.

a. API 571
b. ASTM A-53
c. ASME B-31.3
d. ASME Std 607

88. When ASME B31.3 cannot be followed because of its new construction orientation, which document should guide the Engineer/Inspector?

a. API 574
b. API 575
c. ASME VIII
d. None of the above

89. A piping Engineer must be:

a. A degreed Mechanical Engineer
b. Acceptable to the owner/user
c. Qualified as an API 570 Inspector
d. A single entity(i.e., cannot be more than one person)

90. Which of the following is not a re-rating?

a. A “scab” patch causing a decrease in design pressure.
b. A de-rating for corrosion.
c. A change in materials to a lower stress value.
d. An increase in the MAWP of the system.

91. A “piping system” does not include which of the following items?

a. Piping supports
b. Fittings
c. Dents
d. Valves

92. The boundary of a piping circuit should be sized:

a. By the inspector.
b. To provide for accurate record-keeping and field inspection
c. To minimize TML’s
d. To remove the threat of CUI

93. When using statistical methods to assess corrosion in piping, it is very important to ________.

a. Properly select components to
b. Hydrotest all piping
c. Ensure an adequate number of TML’s are placed.
d. Both a & c, above.

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1. What is the minimum wall schedule that can be used in a male threaded joint in normal fluid servicif22e, carbon steel (notch-sensitive) and NPS 1.5 a nd smaller?

a. Sch 10
b. Sch 40
c. Sch 80
d. Sch 160

2. What is an example of a straight-threaded joint?

a. Threads (male) of threaded piping
b. Threads (female) on a threaded valve
c. An union comprising male and female ends joined with a threaded union nut
d. A joint used in instrument tubing

3. Determine the linear expansion (in/100ft) of a carbon steel pipe between 70°F. and 450°F.

a. 3.04” per 100 ft
b. 3.39” per 100 ft
c. 2.93” per 100 ft
d. 3.16” per 100 ft

4. A 20’ long carbon steel pipe is heated uniformly to 450°F from 70°F. Determine its length after heating.

a. 20.052’
b. 20.263’
c. 20.210’
d. 20.250’

5. If 4 materials, carbon steel, 18Chr-8Ni, Monel, Aluminium are heated from 70°F. to 550°F.which one will expand more?

a. 18 Chr-8Ni
b. Monel
c. Aluminium
d. Carbon Steel

6. What is the modulus of elasticity of carbon steel material (carbon content ≤ 0.3) at 700°F?

a. 25,500,000 psi
b. 25,300,000 psi
c. 26,700,000 psi
d. 29,500,000 psi

7. Poisson’s ratio may be taken as ________ at all temperatures for all metals.

a. 0.30
b. 0.31
c. 0.32
d. 0.33

8. Stop valves are allowed on the inlet and outlet side of a pressure-relieving device, provided:

a. The valves are approved by the jurisdiction
b. They are approved by the inspector
c. They can be locked or sealed in both the open and closed position
d. The valves are non-rising stem valves

9. For a liquid thermal expansion relief device which protects only a blocked-in portion of a piping system, the set pressure shall not exceed the lesser of the system test pressure or _________% of design pressure.

a. 105
b. 110
c. 115
d. 120

10. An ASTM A53 Grade B pipe with a maximum wall thickness of 0.75” is being considered for use in a cold service. What minimum temperature can it be used and not have an impact test?

a. +20°F
b. +15°F
c. +10°F
d. 0°F

11. Each set of impact test specimens shall consist of __________ specimen bars.

a. 2
b. 3
c. 4
d. 5

12. A carbon steel ASTM A 53 Grade B material is being impact tested. What is the minimum energy requirement for this material (average for 3 specimens-fully deoxidized steel)?

a. 7 ft-lbs
b. 10 ft-lbs
c. 13 ft-lbs
d. 15 ft-lbs

13. A thicker wall pipe is joined to a thinner wall pipe. The thicker pipe is taper bored to facilitate the fit up. What is the maximum slope of the taper bore?

a. 15 degrees
b. 20 degrees
c. 25 degrees
d. 30 degrees

14. A NPS 2 schedule 80 (0.218” wall) is welded into a NPS 6 Schedule 40 (0.0.280” wall) header. What size cover fillet weld (tc) is required around the fully penetrated groove weld of the branch into the header? (Express answer to nearest hundredth)

a. 0.15”
b. 0.20
c. 0.22”
d. 0.25”

15. An NPS 8 schedule A NPS 8 Schedule 40 (0.322” wall), ASTM A 106 Grade B, is to be welded. The weather is clear. The sun is shining. The temperature is 30°F. What preheat temperature, if any, is required.

a. None
b. 25°F
c. 50°F
d. 175°F

16. The zone for preheat shall extend:

a. At least ½” beyond each edge of the weld
b. At least 1” beyond each edge of the weld
c. Over only the weld itself
d. At a minimum 2” each side of the weld

17. An ASME A 106 Grade B, NPS 8, Schedule 40 (0.322” wall) pipe is to be welded to an ASME A335 Grade P9, NPS 8, Schedule 40 (0.322” wall) pipe. What preheat temperature is required?

a. 50°F
b. 175°F
c. 300°F
d. 350°F

18. When components of a piping system are joined by welding, the thickness to be used in applying the heat treatment provisions of ASME B 31.3, Table 331.1.1 shall be:

a. That of the thinner component measured at the joint, except for certain exclusions.
b. That of the thicker component measured at the joint, except for certain exclusions.
c. That of the average thickness of the two components, except for certain exclusions.
d. That of the thinner component measured in the thinner pipe except exclusions.

19. An NPS 4 Schedule 40 (0.237” wall) branch connection is welded into a NPS 6 Schedule 40 (0.0.280” wall) header. A ¼” reinforcing pad is used around the branch connection. The branch connection is inserted into the header. The material of the branch and the header is ASTM A 106 Grade B. What thickness would be used to determine whether heat treatment of this connection is required? (Express answer to nearest hundredth.)

a. 0.80”
b. 0.77”
c. 0.70”
d. 0.60”

20. An ASME A335 Grade P9, NPS 8, Schedule 40(0.322” wall) pipe is to be welded to an ASME A335 Grade P9, NPS 8, Schedule 40 (0.322” wall) pipe. What Brinnell Hardness is required after post weld heat treatment?

a. 200
b. 225
c. 241
d. 250

21. Where a hardness limit is specified in Table 331.1.1, at least _______% of welds, hot bends, and hot formed components in each furnace heat treated batch and 100% of those locally heat treated shall be tested.

a. 5
b. 10
c. 15
d. 20

22. An ASME A335 Grade P11, NPS 8, Schedule 120 (0.718” wall) pipe is to be welded to an ASME A 335 Grade P9, NPS 8, Schedule 80 (0.500” wall ) pipe. What Brinnell Hardness number is required after post weld heat treatment?

a. The Grade P11 material is the controls; thus, the Bhn number must be ≤ 225.
b. The average of both material must give a Bhn number of ≤ 233.
c. The grade P9 material only requires checking; its Bhn number must be ≤ 241.
d. The grade P11 material must be ≤225 and the Grade p9 material must be ≤ 241.

23. Flattening of a bend, the difference between maximum and minimum diameters at any cross section, shall not exceed_________ % on nominal outside diameter for internal pressure.

a. 5
b. 8
c. 10
d. 12

24. Flattening of a bend, the difference between maximum and minimum diameters at any cross section, shall not exceed_________ % on nominal outside diameter for internal pressure.

a. 2
b. 3
c. 5
d. 8

25. While assembling a piping system it is required to pull two pieces into alignment. This distorts one of the pieces (puts a bend into one of the pipe sections. The assembly is in a strain that the inspector feels is detrimental to the equipment. What action should the inspector take?

a. Since any distortion that introduces a strain is prohibited, the detail(s) should be removed and the problem corrected.
b. Since the pipe details fit up and there appears to be no problem, the system my be tested and if no leaks the Inspector can accept it.
c. As long as the system will fit together and the flanges and other connections will make connection, the Inspector may accept it.
d. If the system will not make connection the Inspector should require the problem to be corrected; however, if it connects without leaks, the Inspector may accept it.

26. Before bolting up flanged joints, the Inspector should check alignment to the design plane. It should be within ______in / ft or ______% measured across any diameter.

a. 1/16, 0.5%
b. 1/8, 0.05%
c. 1/32, 0.05%
d. 1/64, 0.5%

27. Before bolting up flanged joints, the Inspector should check alignment of the flange bolt holes. They shall be aligned within ______ inch maximum offset.

a. 1/32
b. 1/16
c. 1/8
d. 9/64

28. An Inspector, checking bolts on flanges, finds 3 bolts in a NPS 6, 300# class flange that will not meet ASME B31.3 bolt length specification.What did he find?

a. The bolt only extended from the nut by ¼”
b. The lack of engagement was 2 threads.
c. The lack of engagement was 1 thread
d. The bolt only extended from the nut by 3/8”

29. You find a flanged joint with two fibre gaskets used to make up the joint. What is the correct course of action for an Inspector?

a. Remove the gaskets and replace them with two spiral wound grafoil filled gaskets
b. The joint is acceptable as is because the gaskets are fibre.
c. Two gaskets are unacceptable; have the joint repaired to take only one gasket
d. Remove the gaskets and replace them with two wrapper with grafoil tape

30. An Inspector finds incomplete penetration in a radiograph of a girth weld of normal fluid service piping. What can he accept or can he accept any incomplete penetration?

a. If the incomplete penetration is 1/16” or less (or ≤ 0.2T w) deep, he may accept.
b. If the incomplete penetration is 1/32” or less (and ≤ 0.2T w) deep, he may accept
c. He may not accept the incomplete penetration
d. If the incomplete penetration is 1/32” or less (or ≤ Tw) deep, he may accept

31. When spot or random examination reveals a defect, what should the Inspector do?

a. Take one additional sample of the same kind used for the first examination. If it is acceptable, repair or replace the original defect and accept the job.
b. Take two additional samples of the same kind used for the first examination. If they are acceptable, repair or replace the original defect and accept the job.
c. Take two additional samples using a different inspection technique. If this is acceptable, repair or replace the original defect and accept the job.
d. Take 4 additional samples of the same kind used for the first examination. If they are acceptable, repair or replace the original defect and accept the job.

32. Prior to a hydrostatic test, a piping system may be subject to a preliminary test using air at no more than ______ psi gage to locate major leaks.

a. 45
b. 35
c. 25
d. 15

33. What is the minimum time that a leak test must be maintained (all joints and connections shall be examined for leaks)?

a. 60 minutes
b. 45 minutes
c. 30 minutes
d. 10 minutes

34. A NPS 10 ASTM A335 Grade P9 pipe was installed. It had to be changed by adding an NPS 6 ASTM A335 Grade P9 branch connection. The weld(s) were post weld heattreated. When should this section of piping be leak tested or should it be leak tested?

a. before and after the heat treatment
b. before the heat treatment
c. after the heat treatment
d. no test is required

35. If a non-toxic flammable liquid is used as a leak-testing medium, it must have:

a. At least a flash point of 1200F
b. A boiling point of 1500F
c. A vapour point of 1000F
d. A staybolt viscosity of 120 at 1220F

36. Where the design temperature of the system is the same as the hydrostatic test temperature, the hydrostatic test pressure shall be not less than:

a. That calculated according to B31.3
b. 1.1 times the design pressure
c. 1.25 times the operating pressure
d. 1.5 times the design pressure

37. Calculate the hydrostatic leak test at 700F. required for a piping system with NPS 6 ASTM A 106 Grade B pipe that operates at a maximum of 6000F and 400 psi. Round to the nearest psi.

a. 500 psi
b. 600 psi
c. 694 psi
d. 440 psi

38. Where the test pressure of piping exceeds the a vessels test pressure, and it is not considered practicable to isolate the piping from a vessel, the piping and the vessel may be tested together at the vessel test pressure, provided the owner approves and the vessel test pressure is not less than _______% of the piping test pressure calculated by ASME B31.3, paragraph 345.4.2 (b).

a. 67
b. 77
c. 85
d. 110

39. If a pneumatic leak test is used, the test pressure shall be __________% of design pressure.

a. 50
b. 150
c. 125
d. 110

40. If it becomes necessary to use a “Sensitive Leak Test” method, the test pressure shall be at least the lesser of _______psi or ________% of the design pressure.

a. 10,33
b. 15,25
c. 17,23
d. 20,20

41. Unless otherwise specified by the engineering design, the following records shall be retained for at least _____ years after the record is generated for the project: examination procedures, and examination personnel qualifications.

a. 10
b. 8
c. 5
d. 2

42. What is the longitudinal weld joint factor, Ej, for API 5L ERW (Electric Resistance Welded) pipe?

a. 1.00
b. 0.95
c. 0.85
d. 0.60

43. What is the casting quality factor, Ec, of a A216 carbon steel casting that is not upgraded per B31.3 paragraph 302.3.3 © and Table 302.3.3 ©?

a. 0.85
b. 0.80
c. 0.75
d. 0.60

44. A carbon steel pipe has ≤ 0.3% carbon in it. What is its Modulus of Elasticity at 4000F?

a. 30,000,000 psi
b. 31,900,000 psi
c. 29,000,000 psi
d. 27,700,000 psi

45. Double welded slip-on flanges should be _______ between the welds for fluid services that require leak testing of the inner fillet weld, or when fluid handled can diffuse into the enclosed space, resulting in possible failure.

a. sanded
b. machined
c. scored
d. vented

46. If a relief valve has a stop valve at the inlet or outlet. Is it permissible to close either or both these valves while the equipment the relief valve is protecting is in service.

a. It is not permissible to block off a relief valve while the equipment it is protecting is in operations.
b. It is permissible if an authorized person is present and this person can relieve the pressure by another means.
c. It is permissible to block off a relief valve while the equipment it is protecting is in a reduced operating mode, i.e. the operating pressure and/or temperature is reduced.
d. It is permissible to block off a relief valve only when the equipment it is protecting is not in operations.

47. Why would you not use cast iron material in the majority of cases in oil refinery or chemical plant applications?

a. The possibility of embrittlement when handling strong caustic solutions.
b. Its lack of ductility and its sensitivity to thermal and mechanical shock restricts its use.
c. The possibility of stress corrosion cracking when exposed to acids or wet H2S.
d. The possibility of stress corrosion cracking if exposed to chlorides in H2O>50 ppm.

48. If you expose copper and copper alloys to ammonia, what would this possibly cause?

a. embrittlement
b. stress corrosion cracking
c. hydrogen attack
d. sulphidation

49. You have a fluid that does not operate at high pressure. The fluid is not toxic. The fluid is not flammable. Exposure to the fluid will not cause damage to human tissue. The design gage pressure is 120 psi and the operating temperature is 1000F. The owner requires metal piping to be used and he does not designate the category. No cyclic problems will occur. What category fluid service would you design?

a. Normal fluid service
b. Category D fluid service
c. Category M fluid service
d. High pressure fluid service

50. In elevated temperature service any condition of pressure and temperature under which the design conditions are not exceeded is known as the:

a. Operating conditions
b. Design condition
c. Extent of the excursions
d. Service life

51. In elevated temperature service a condition under which pressure or temperature or both, exceed the design conditions is known as:

a. A design condition
b. An operating condition
c. An excursion
d. A duration

52. In elevated temperature service a condition under which pressure or temperature or both, exceed the design conditions is known as:

a. Estimated life
b. Service life
c. Equivalent life
d. Excursion life

53. The Inspector finds that ERW (electric resistance weld) pipe is used in a piping system. What longitudinal joint factor (Ej) would be used to calculate the required thickness for pressure?

a. 0.85
b. 0.60
c. 0.80
d. 0.90

54. The joint factor cannot be increased by additional examination on which of the following longitudinal pipe joint:

a. Electric fusion weld, single butt weld, straight or spiral, without filler metal
b. Electric fusion weld, double butt weld, straight or spiral
c. Electric fusing weld, single butt weld, straight or spiral with filler metal
d. Electric resistance weld, straight or spiral

55. A NPS 10 pipe made from ASTM A106 Grade B carbon steel is to be checked for minimum thickness ™. The pipe operated at 900°F. The existing thickness is 0.29”. Determine the coefficient Y.

a. 0.4
b. 0.5
c. 0.6
d. 0.7

56. A NPS 10 pipe made from ASTM A53 Grade B carbon steel is to be checked for thickness (t). The pipe operates at 975°F. The existing thickness is .29”. Determine the coefficient Y.

a. 0.4
b. 0.5
c. 0.6
d. 0.7

57. “S” is defined as the stress value for material from Table A-1 of ASME B31.3. Pick the value of “S” when the material is ASTM A335 Grade P9 and the temperature is 950°F.

a. 11400 psi
b. 10600 psi
c. 7400 psi
d. 20000 psi

58. An NPS 12 seamless pipe made from ASTM A53 Grade B material operates at 600 psi and 600°F. Calculate the pressure design thickness for these conditions.

a. 0.218”
b. 0.442”
c. 0.205”
d. 0.191”

59. An NPS 12 (12.75” o.d.) seamless pipe made from ASTM A-53 Grade B material operates at 600 psi and 600°F. The conditions require that a corrosion allowance of 0.125” be maintained. Calculate the minimum required thickness for these conditions.

a. 0.218”
b. 0.346”
c. 0.330”
d. 0.436”

60. An NPS 4 (4.5” o.d.) seamless pipe made from ASTM A-106 Grade A material operates at 300 psi and 400°F. The pipe must cross a small ditch and it must be capable of supporting itself without any visible sag. A piping Engineer states that the pipe must be at least 0.25” thick just to support itself and the liquid product. He also states that a 0.10” corrosion allowance must be included. Calculate the thickness required for the pipe.

a. 0.292”
b. 0.392”
c. 0.350”
d. 0.142”

61. A blank is required between two NPS 8,150 pound class flanges. The maximum pressure in the system is 285 psi at 100°F. A corrosion allowance of 0.10” is required. The inside diameter of the gasket surface is 8.25”. The blank is ASTM A-285 Grade C material. Calculate the thickness required for the blank.

a. 0.545”
b. 0.584”
c. 0.530”
d. 0.552”

62. Which of the below may only be used for category D fluid service?

a. ASTM A-333 Grade 6
b. API 5L Grade X46
c. ASTM A-106 Grade B
d. ASTM A-53 Grade F

63. What is the minimum thickness of a blank that is made from A516-60 material (seamless) and is 17.375” I.D.? The pressure is 630 psi at 600°F. Corrosive product will be on both sides of the blank, and the specified corrosion allowance is 1/8”.

a. 1.5”
b. 1.627”
c. 1.752”
d. 2.067”

64. Per B31.3, a piping designer must have _______ years of experience if she has a bachelor’s degree in engineering?

a. 5
b. 10
c. 15
d. Not specified

65. Using the given formula, calculate the design pressure of a 0.397” replacement pipe (measured thickness) with the following information:
i. Material: A672 B70 Class 13
ii. Pressure and temperature: 753 psi @ 300°F
iii. Diameter: NPS 16
iv. Corrosion allowance: 1/16”
P = ( )D 2SE t − c

a. 1000 psi
b. 949 psi
c. 942 psi
d. 800 psi

66. What is the design pressure allowed on a replacement A-135-A ERW pipe that is NPS 6 (6.625”), and is installed in a system operating at 7000F? The pipe is Sch.80, and the engineering specifications require a 1/16” erosion allowance to be maintained. P = ( )D2SE t − c

a. 1596 psi
b. 1167 psi
c. 1367 psi
d. 1800 psi

67. What schedule of seamless pipe will be required if a seamless replacement piece is ordered for a piping circuit with the following conditions:

i. Material : A-106 Grade B
ii. Pressure and temperature: 770 psi @ 800°F
iii. Diameter: NPS 18
iv. Corrosion allowance: 1/8”

a. Sch. 40
b. Sch. 60
c. Sch. 80
d. Sch. 140

68. An A 381 Y 35 pipe is 1.0” thick and is installed in a system operating at 150 psi. A replacement pipe will be ordered, and will be the same material (not normalized or quenched/tempered). If the design minimum temperature is 400°F and the nominal pressure stress is 10,000 psi, what temperature can this material be operated at without impact testing?

a. +80F
b. -80F
c. 680F
d. 200F