API 510- Chapter 4

API 510 Chapter 4 Frequency and Data Evaluation (Sections 6 and 7)

4.1 Introduction

Sections 6 and 7 of API 510 cover the subjects of inspection interval frequency (section 6) and inspection data evaluation (section 7). The contents of these sections are closely linked with, not only each other but also the previous section 5 covering inspection practices. Note the following points about these sections:

They contain the main core material of API 510, particularly from the viewpoint of exam question content.

All three of the sections have been added to, rearranged and changed in emphasis with each new edition of the code. They therefore have the characteristics of something that has grown organically rather than been designed recently from scratch. There is a focus and a logical order, of sorts, but this is surrounded by a mass of additional information contained in rather dense paragraphs of text.

The title data evaluation predominates in section 7. Don’t be misled by this – vessel inspection doesn’t generally result in large data sets that need sorting and analysing – just think of it as describing what you do with inspection findings. Figure 4.4, later, shows the situation.

API 510 section 6 is a section of principle; it contains some of the major technical points of API 510 that appear in both open-book (calculation) and closed-book parts of the API 510 examination. These carefully presented eggs, golden or otherwise, contain much of the API view of the world on how and when vessels should be inspected. Section 6 is shorter than it was in previous editions, owing to the relocation of 33 information about corrosion rates and pressure testing to other sections. The essential content can be distilled down to a handful of fairly straightforward background principles. Here they are:

Principle: Although section 6 provides guidelines; the API certified vessel inspector retains a large amount of discretion as to what types of inspection are actually done on pressure vessels.

Principle: The general philosophy of section 6 is that the following inspection periods are used as a ‘default level’ for vessels, unless there is good reason to do otherwise:

  • External visual inspection: 5 years
  • Internal inspection or ‘thorough’ on-stream inspection: 10 years or half the remaining corrosion life (with a few exceptions)

Paradoxically, a lot of section 6 is then devoted to providing credible reasons for doing otherwise. The result is that section 6 is, in reality, promoting a risk-based inspection (RBI) approach to vessel inspection, but with a few ‘boundaries’ that should not be exceeded. If you read the section with this in mind, it will seem less muddled to you.

4.2 The contents of section 6

Figure 4.1 shows the contents list of section 6. It starts off with general information on the principles of inspecting vessels before use and after service changes and then moves on to the opportunities offered by RBI. It continually refers to the possibility of replacing internal inspections of vessels with on-stream inspections. Section 6.5 contains most of the key information.

Section 6.6, PRVs, contains information of a very general nature only and there is little in it that does not appear in the main PRV code (API 576). We will look at this later.

Figure 4.1 What’s in API 510 section 6?
Figure 4.1 What’s in API 510 section 6?

Section 6.2: inspection during installation and service changes Section 6.2 is a recent addition to the content of API 510. It makes the commonsense point that a pre-use inspection is required in order to collect base-line information that will be useful in future inspections. Look at 6.2.1.2 though, which makes clear that this does not have to include an internal vessel inspection; it is more about verifying what are essentially design and construction requirements. These are:

  • Nameplate information
  • Correct installation
  • PRV settings

(See 6.2.1.1 list items (a) to (c).)

Section 6.3: RBI This section contains little more than general RBI knowledge but opens the door to the key principle that the results of RBI evaluations can be used to override various API 510 requirements. Note the following two important points:

The results of an RBI study can be used to change both the 5-year external and 10-year internal/on-stream ‘default’ inspection periods specified by sections 6.4 and 6.5 respectively.

If you do the above and exceed the 10-year internal/onstream inspection limit (stated in section 6.5), the RBI assessment must be revalidated at 10-year intervals (at least).

Figure 4.2 shows the basic principles of RBI. Don’t get too excited about RBI in the context of API 510 – it has its own code (API RP 580), which is the subject of a separate ICP supplementary exam.

Section 6.4: external inspection Prior to considering RBI, section 6.4 introduces the default level of 5 calendar years for external visual examination of pressure vessels. Note how it is expressed… unless justified by an RBI assessment, for above ground vessels, an external inspection should be carried out at intervals not exceeding the lesser of 5 years or the required internal/on-stream inspection interval. This mouthful relates to calendar years, and so applies whether the vessel is in continuous service or not (see section 6.4.2).

Figure 4.2 The basic idea of RBI
Figure 4.2 The basic idea of RBI

Section 6.5: internal and on-stream inspection (see Fig. 4.3)

Remember the principle in force here; internal inspections may be replaced by on-stream inspections. Section 6.5 contains the necessary qualifications to allow you to do this. First, however, it provides the ‘baseline’ requirement for periodicity as follows.

The inspection interval should be not be more than:

  • 10 years or
  • Half the estimated remaining life
Figure 4.3 Internal/on-stream inspection periods
Figure 4.3 Internal/on-stream inspection periods

If the calculated remaining life is less than 4 years, the inspection interval may be 100 % of the remaining safe operating life, up to a maximum of 2 years. Let’s call this the low-life cap, and not spend too much time trying to understand it.

For vessels not in continuous service that are blanked and purged so that no corrosion takes place, the inspection interval can be taken as a 10-year service life, but you have to be sure that the vessel is:

  • Isolated from the process fluid and
  • Not exposed to some other corrosive internal environment

Vessels that are not in continuous service and are not blanked and purged should be treated as normal continuous service vessels as above. Watch out for this as an exam question.

Although API 510 makes it quite clear that internal inspection is the preferred method of examination (particularly if there is localized corrosion or other types of damage) it then provides a healthy list of eight get-outs whereby it can be replaced with an on-stream inspection. See Fig. 4.3.

Section 6.6: pressure-relieving devices (PRVs)

Note the key content of section 6.6 covering the requirements of a PRV repair organization. They have to: .

  • Be experienced in valve maintenance
  • Have a QC system and training programme that is fully documented
  • Use qualified personnel
  • Follow the requirements of API 576 when doing inspection and testing of PRVs

These points are commonsense. Most of the technical detail about PRVs comes later in API 576.

PRV inspection periods

Note the requirement for PRV inspection periods in section 6.6.2.2 of your code. The general ‘default periods’ are:

5 years or 10 years (depending on whether the process conditions are corrosive), and remember that these can (and should) be changed to fit in with the results of previous inspections and the dreaded RBI studies.

Now try these familiarization questions.

4.3 API 510 section 6 familiarization questions

1.

Q1. API 510 section 6.2.1.1: inspection during installation
Which of these would not normally be included in a pre-use (installation) external inspection of a pressure vessel?

 
 
 
 

2.

Q2. API 510 section 6.2.1.2: inspection during installation
An inspector discovered that a newly installed vessel has a missing manufacturer’s data report should:

 
 
 
 

3.

Q3. API 510 section 6.3: risk-based inspection
An RBI assessment may be used to establish inspection intervals for:

 
 
 
 

4.

Q4. API 510 section 6.4.1: external inspection period
How often should a vessel external inspection be performed on an above-ground vessel?

 
 
 
 

5.

Q5. API 510 section 6.5.1.1: internal inspection interval
What is the interval between internal inspections for a vessel with a projected remaining life of 30 years that is in continuous use?

 
 
 
 

6.

Q6. API 510 section 6.5.1.1/6.5.1.2: internal inspection interval
A vessel has a projected remaining life of 15 years under its current regime of being in use 50 % of the time. The remainder of the time it is isolated from the process fluid and damage mechanisms by being filled with nitrogen. What is the internal inspection interval?

 
 
 
 

7.

Q7. API 510 section 6.6: PRVs Pressure-relieving devices should be inspected, tested, and maintained in accordance with:

 
 
 
 

8.

Q8. API 510 section 6.6.2.2: PRV inspection intervals
The maximum test/inspection interval for PRVs in a ‘typical process service’ is:

 
 
 
 

4.4 Section 7: inspection data evaluation, analysis and recording

Whereas section 6 covers matters of principle, section 7 of API 510 is a cocktail of practical approximation and reasoned assumptions. It brings together most of the key concepts surrounding corrosion rate, remaining life, evaluation methods and fitness-for-purpose of corroded areas. It has been rearranged from previous editions of API 510, in which the above concepts were spread over several different sections, but the technical song remains much the same.

Note the breakdown of section 7 (you might find Fig 4.4 useful in visualizing what is in there).

Inspection data, evaluation, analysis and recording

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

Think of sections 7.1 to 7.3 as fitting together into a set, suitable for dealing with uniform corrosion, with sections 7.4 and 7.5 acting as a general list of requirements to be used when assessing localized corrosion or defects in more detail.

Section 7.1: corrosion rate determination API codes place stratospheric importance on the effects of wall thinning of pipes/vessels and the calculation of the maximum allowable working pressure (i.e. design pressure) that this horribly corroded item will stand. To this end, they use a mixed set of abbreviations and symbols to represent the various material thicknesses at a condition monitoring location (CML). These look much more confusing than they actually are. Note the following definitions in API 510 section 7.1.1.1: .

tinitial is the thickness measured at the first inspection (not necessarily when it was new) or the start of a new corrosion rate environment; . tactual is used to denote the actual thickness measured at the most recent inspection;

Figure 4.4a API 510 section 7: data evaluation; what’s this all about?
Figure 4.4a API 510 section 7: data evaluation; what’s this all about?

 

Figure 4.4b API 510 section 7.3.3: the half-life/double corrosion rate principle
Figure 4.4b API 510 section 7.3.3: the half-life/double corrosion rate principle

tprevious is the thickness measured at an inspection previous to another specified inspection; . trequired is a calculated value, rather than a measured one. It is the minimum (safe) required thickness in order to retain safely the pressure and (more importantly) meet the requirements of the design code (e.g. ASME VIII). This calculated required thickness excludes any specified corrosion allowance (it will be added on afterwards).

There is substantially less to these definitions than meets the eye. Just read them slowly and they will make sense. API 510 likes to differentiate between the long-term (LT) corrosion rate and the short-term (ST) corrosion rate. Again, this is nothing to get excited about. Figure 4.5 shows the idea in a simpler form.

A commonsense principle of API codes is that the most pessimistic corrosion rate (from those that are considered relevant) is used. It then falls to the API-certified pressure vessel inspector in conjunction with a corrosion specialist to decide which ones are relevant (that is what it says in section 7.1.1.1). For example, if there have been recent changes in

Figure 4.5 Corrosion rate definitions
Figure 4.5 Corrosion rate definitions

process conditions, then the current short-term rate will be more relevant than the long-term rate experienced under the old process conditions.

Section 7.1.2: newly installed vessels: corrosion rate determination

For new(ish) vessels, it is obviously difficult to establish a valid corrosion rate. Section 7.1.2 gives four possible ways to ‘estimate’ it (see Fig. 4.6):

  • Calculate it from data supplied about vessels in the same or similar service.
  • Estimate it from the owner/user’s experience.
  • Estimate it from published data (e.g. NACE corrosion handbook).
  • Measure it by taking on-stream thickness measurements after a minimum 1000 hours of operation (and keep it under review through time).

This section has little validity on its own; its main purpose is to support the subsequent section 7.3, where the objective is to go on to calculate MAWP in a corroded vessel or calculate a vessel’s remaining lifetime and inspection period for a given MAWP.

Section 7.3: MAWP (maximum allowable working pressure) determination

We saw in Chapter 3 of this book how US pressure equipment codes mainly refer to MAWP (maximum allowable working pressure) as the maximum pressure that a component is designed for. European codes are more likely to call it design pressure.

Remember the two key things about MAWP:

It is the maximum gauge pressure permitted at the top of a vessel as it is installed (for a designated temperature). This means that at the bottom of a vessel the pressure will be slightly higher owing to the self-weight of the fluid (hydrostatic head). . MAWP is based on calculations using the minimum

ESTIMATE THE CORROSION RATE FROM

Figure 4.6 Corrosion rates for newly installed vessels
Figure 4.6 Corrosion rates for newly installed vessels

thickness, excluding the amount of the actual thickness designated as the corrosion allowance.

A significant amount of the exam content (closed-book and open-book questions) involves either the calculation of MAWP for vessels with a given amount of corrosion or the calculation of the minimum allowable corroded thickness for a given MAWP. Figure 4.7 shows the principle

Finally, note the statement in section 7.3.1 about code editions. The idea is that MAWP calculations can be based on either the latest edition of the ASME code or the edition to which the vessel was built. This may be to fit in with the way that the system of compliance with the ASME code works in the USA, with a legal requirement for code compliance in most states.

Section 7.4: fitness-for-service analysis of corroded regions This section is one of the core parts of API 510. Its content always appears in the examinations, in one form or another. Simplistically, it works on the view that corrosion may be either:

Figure 4.7 The principles of MAWP
Figure 4.7 The principles of MAWP
  • uniform, so it may be difficult to see visually, or
  • localized, i.e. some areas of material may be thinner than they appear, and it may be difficult to get true readings owing to surface roughness.

The following methods can be used to obtain the minimum thickness:

  • UT: A-scan, B-scan and C-scan methods
  • Profile RT
  • Depth gauges

Section 7.4.2: evaluation of locally thinned areas

When considering the analysis of locally thinned areas, the concept of average remaining thickness is used. It is this average thickness that will be used to determine the corrosion rate, and subsequently the estimated life and frequency of inspection for the vessel. There are a couple of simple rules to follow.

Areas with no nozzles For areas of significant corrosion, the remaining material thickness is calculated from equally spaced thickness measurements averaged over a length not greater than:

  • For vessels up to 60-inch ID (inside diameter): half the vessel diameter or 20 in, whichever is less.
  • For vessels greater than 60-inch ID: one third the vessel diameter or 40in, whichever is less.

Figure 4.8 shows the situation. Note the direction along which thickness readings are taken. If, as for most vessels, circumferential (hoop) stresses are the governing factor, then thickness readings will be averaged along the longitudinal direction (look at the statements in section 7.4.2.3).

Areas with nozzles If the averaged area contains an opening (i.e. a nozzle) the situation is slightly different. The requirement is that the averaging area should not extend inside the limit of

Figure 4.8 API 510 section 7.4.2.1: corrosion averaging
Figure 4.8 API 510 section 7.4.2.1: corrosion averaging

reinforcement defined in ASME VIII UG-35. We will look at this later when we consider ASME VIII.

Section 7.4.3: evaluation of pitting API codes have well-defined ideas about the effect of pitting on vessel integrity. The clarity of the code sections covering this has varied in past code editions but the general principle is clear. Widely scattered pits are not a threat to integrity and may be ignored provided the following criteria are true:

The remaining thickness left below any pit is more than half the trequired thickness.

AND, IF IT PASSES THAT 

The total area of the pits that are deep enough to eat into trequired do not exceed 7 in2 in any circle that is 8 in in diameter.

AND, IF IT PASSES THAT… .

The sum of the dimensions of the pits that eat into trequired along any straight line within an 8-in circle do not exceed 2 in.

You have to be careful of the API code definitions here as it uses the term ‘corrosion allowance’ to describe the amount of spare material left over and above trequired. Don’t confuse this with the nominal corrosion allowance added to calculated thicknesses in ASME VIII. This is a totally separate idea. The thrust of the idea is that it is thinning below the trequired thickness that threatens integrity. Figure 4.9 shows the principle.

This is not the only way that pitting/defects can be assessed. API also allows you to use the enthusiasm-sapping 1000+ pages of API 579. Note the specific comment in API 510 (section 7.4.4.1) that recommends API 579 for assessing ground areas where defects have been removed. Note also that the method of analysis given in ASME VIII division 2 appendix 4 may be used (see section 7.4.4.2). This is a complex method involving the determination of design stresses and should be carried out by an experienced pressure vessel engineer. The detail of this is outside the scope of the API 510 examination.

Corroded vessel heads API 510 section 7.4.6 deals with the way to treat corrosion in vessel heads. It presents a couple of approximations to simplify the process, depending on the shape of the head. Figure 4.10 shows the situation.

Figure 4.9a Pitting interpretation (continues on next page)
Figure 4.9a Pitting interpretation (continues on next page)

Section 7.5: use of API 579 fitness-for-service evaluations The main purpose of this section is to cross-reference the use of API 579. This is the API code covering fitness-for-service (or fitness-for-purpose). API 579 is a large document (1000+ pages) divided into many sections. It is used when vessels are in a damaged condition and have to be assessed to see if they are suitable for future use.

Figure 4.9b Pitting interpretation (continued)
Figure 4.9b Pitting interpretation (continued)

You need to know of its existence (and what the sections cover) but the API 579 code itself is not in the API 510 examination syllabus. The main sections are (see Fig. 4.11):

  • 7.5.3 Brittle fracture .
  • 7.5.4 General metal loss .
  • 7.5.5 Local metal loss .
  • 7.5.6 Pitting corrosion
  • 7.5.7 Blisters and laminations .
  • 7.5.8 Weld misalignment and shell distortions .
  • 7.5. Crack-like flaws .
  • 7.5.11 Fire damage

There are three different levels of assessment for each of the sections in API 579, which become more complex as the level increases. The API inspection engineer may attempt level 1 but it is recommended that levels 2 and 3 would normally be carried out by experienced ‘design’ engineers. Other methods of defect assessment may be carried out, such as fracture mechanics evaluation of cracks, provided that you use an

Figure 4.10 Dealing with corroded vessel heads
Figure 4.10 Dealing with corroded vessel heads

 

Figure 4.11 Some sections of API 579
Figure 4.11 Some sections of API 579

established method and actually believe that these highly academic techniques have some relevance to the real world.

Section 7.7: evaluation of existing equipment with minimal documentation This is a relatively new and expanding part of API 510. The objective is to give guidelines on what to do when dealing with vessels that have no nameplate details or construction date. Read through section 7.7 and note the main requirements as follows:

You need to do retrospective design calculations to the appropriate edition of the ASME VIII code. Remember that major changes were made in 1999.

Unidentified materials can be retrospectively qualified using UG-10(c) of ASME VIII or, as a default, use the material properties for the material SA-283 Grade C.

If the RT grade (which defines the extent of radiography used during manufacture) is not known, use a joint efficiency of E = 0.7 for required thickness calculations.

After doing all this, it is the responsibility of the inspector to attach a new nameplate showing MAWP, maximum and minimum temperature (MDMT, minimum design metal temperature) and the date. Now try these familiarization questions.

4.5 API 510 section 7 familiarization questions

1.

Q1. API 510 section 7.1.1.1: corrosion rates
Short-term corrosion rates are typically determined by:

 
 
 
 

2.

Q2. API 510 section 7.1.2: corrosion rate for vessels/changes in service
A vessel has just changed service and no published or ‘similar service’ data are available to predict the probable corrosion rate under the new service regime. What should the inspector do?

 
 
 
 

3.

Q3. API 510 section 7.4.2: evaluation of locally thinned areas
For vessels with an inside diameter of less than or equal to 60 inches, corroded wall thickness is averaged over a length not exceeding the lesser of:

 
 
 
 

4.

Q4. API 510 section 7.4.2: evaluation of locally thinned areas
A vessel has an inside diameter of 90 inches. What is the maximum allowed averaging length for calculating corroded wall thickness?

 
 
 
 

5.

Q5. API 510 section 7.4.2.3: evaluation of locally thinned areas
For an internally pressurized cylindrical vessel shell with no significant induced bending stresses (e.g. wind loads) corrosion is usually averaged along which plane?

 
 
 
 

6.

Q6. API 510 section 7.4.4.2: advanced thinning analysis
As a general rule, the design stress used for an ASME VIII division 2 appendix 4 assessment (when used as an alternative to API 510) is:

 
 
 
 

7.

Q7. API 510 section 7.4.6: assessing corrosion in vessel heads
The effect of corrosion near the center of vessel heads is calculated under API 510 using:

 
 
 
 

8.

Q8. API 510 section 7.4.6.2: corroded areas in vessel heads
For torispherical heads, the central portion can be assumed to be a hemisphere of radius equal to:

 
 
 
 

9.

Q9. API 510 section 7.4.6.3: corroded areas in vessel heads
For ellipsoidal heads, the central portion can be assumed to be a hemisphere of radius equal to:

 
 
 
 

10.

Q10. API 510 section 7.7: evaluation of vessels with minimal documents
For a pre-1999 pressure vessel that has drawings but no nameplate information the inspector and engineer should:

 
 
 
 

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