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API 653 Exam Chapter 16 – The NDE Requirements of ASME V
16.1 Introduction
This chapter is to familiarize you with the specific NDE requirements contained in ASME V. API 650 references ASME V as the supporting code but only articles 1, 2, 6, 7 and 23 are required for use in the API 653 examination.
These articles of ASME V provide the main detail of the NDE techniques that are referred to in many of the API codes. Note that it is only the body of the articles that are included in the API examinations; the additional (mandatory and non-mandatory) appendices that some of the articles have are not examinable. We will now look at each of the articles 1, 2, 6, 7 and 23 in turn.
16.2 ASME V article 1: general requirements
Article 1 does little more than set the general scene for the other articles that follow. It covers the general requirement for documentation procedures, equipment calibration and records, etc., but does not go into technique-specific detail. Note how the subsections are annotated with T-numbers (as opposed to I-numbers used for the appendices).
Manufacturer versus repairer One thing that you may find confusing in these articles is the continued reference to The Manufacturer. Remember that ASME V is really a code intended for new manufacture. We are using it in its API 653 context, i.e. when it is used to cover repairs. In this context, you can think of The Manufacturer as The Repairer.
Table A-110:imperfections and types of NDE method This table lists imperfections in materials, components and welds and the suggested NDE methods capable of detecting them. Note how it uses the terminology imperfection some of the other codes would refer to these as discontinuities or indications (yes, it is confusing). Note that table A-110 is divided into three types of imperfection:
Service-induced imperfections
Welding imperfections
Product form
We are mostly concerned with the service-induced imperfections and welding imperfections because our NDE techniques are to be used with API 653, which deals with in-service inspections and welding repairs.
The NDE methods in table A-110 are divided into those that are capable of finding imperfections that are:
Open to the surface only
Open to the surface or slightly subsurface
Located anywhere through the thickness examined
Note how article 1 provides very basic background information only. The main requirements appear in the other articles, so API examination questions on the actual content of article 1 are generally fairly rare. If they do appear they will probably be closed book, with a very general theme.
16.3 ASME V article 2: radiographic examination
ASME V article 2 covers some of the specifics of radiographic testing techniques. Note that it does not cover anything to do with the extent of RT on storage tanks, i.e. how many radiographs to take or where to do them (we have seen previously that these are covered in API 650 and 653).
Most of article 2 is actually taken up by details of image quality indicators (IQIs) or penetrameters, and parameters such as radiographic density, geometric unsharpness and similar detailed matters. While this is all fairly specialized, it is fair to say that the subject matter lends itself more to open book exam questions rather than closed-book ‘memory’ types of questions.
T-210: scope This explains that article 2 is used in conjunction with the general requirements of article 1 for the examination of materials including castings and welds.
Note that there are seven mandatory appendices detailing the requirements for other product-specific, technique specific and application-specific procedures. Apart from appendix V, which is a glossary of terms, do not spend time studying these appendices. Just look at the titles and be aware they exist. The same applies to the three non mandatory appendices.
T-224: radiograph identification Radiographs have to contain unique traceable permanent identification, along with the identity of the manufacturer and date of radiograph. The information need not be an image that actually appears on the radiograph itself (i.e. it could be from an indelible marker pen) but usually is.
T-276: IQI (image quality indicator) selection
T-276.1: material IQIs have to be selected from either the same alloy material group or an alloy material group or grade with less radiation absorption than the material being radiographed. Remember that the IQI gives an indication of how ‘sensitive’ a radiograph is.
The idea is that the smallest wire visible will equate to the smallest imperfection size that will be visible on the radiograph.
T-276.2: size of IQI to be used (see Fig. 16.1)
Table T-276 specifies IQI selection for various material thickness ranges. It gives the designated hole size (for hole type IQIs) and the essential wire (for wire type IQIs) when the IQI is placed on either the source side or film side of the weld. Note that the situation differs slightly depending on whether the weld has reinforcement (i.e. a weld cap) or not.
Figure 16.1 IQI selection
T-277: use of IQIs to monitor radiographic examination
T-277.1: placement of IQIs For the best results, IQIs are placed on the source side (i.e. nearest the radiographic source) of the part being examined. If inaccessibility prevents hand-placing the IQI on the source side, it can be placed on the film side in contact with the part being examined. If this is done, a lead letter ‘F’ must be placed adjacent to or on the IQI to show it is on the film side. This will show up on the film.
IQI location for welds. Hole type IQIs can be placed adjacent to or on the weld. Wire IQIs are placed on the weld so that the length of the wires is perpendicular to the length of the weld. The identification number(s) and, when used, the lead letter ‘F’ must not be in the area of interest, except where the geometric configuration of the component makes it impractical.
T-277.2: number of IQIs to be used At least one IQI image must appear on each radiograph (except in some special cases). If the radiographic density requirements are met by using more than one IQI, one must be placed in the lightest area and the other in the darkest area of interest. The idea of this is that the intervening areas are then considered as having acceptable density (a sort of interpolation).
T-280: evaluation of radiographs (Fig. 16.2)
This section gives some quite detailed ‘quality’ requirements designed to make sure that the radiographs are readable and interpreted correctly.
T-282: radiographic density These are specific requirements that are based on very well established requirements used throughout the NDE industry.
It gives numerical values of density (a specific measured parameter) that have to be met for a film to be considered acceptable.
Figure 16.2 Evaluation of radiographs
T-282.1: density limitations
This specifies acceptable density limits as follows:
Single film with X-ray source: density = 1.8 to 4.0
Single film with gamma-ray source: density = 2.0 to 4.0
Multiple films: density = 0.3 to 4.0
A tolerance of 0.05 in density is allowed for variations between densitometer readings.
T-283: IQI sensitivity
T-283.1: required sensitivity In order for a radiograph to be deemed ‘sensitive enough’ to show the defects of a required size, the following things must be visible when viewing the film:
For a hole type IQI: the designated hole IQI image and the 2T hole .
For a wire type IQI: the designated wire .
IQI identifying numbers and letters
Figure 16.3 Backscatter gives an unclear image
T-284: excessive backscatter Backscatter is a term given to the effect of scattering of the X or gamma rays, leading to an unclear image.
If a light image of the lead symbol ‘B’ appears on a darker background on the radiograph, protection from backscatter is insufficient and the radiograph is unacceptable. A dark image of ‘B’ on a lighter background is acceptable (Fig. 16.3).
T-285: geometric unsharpness limitations Geometric unsharpness is a numerical value related to the ‘fuzziness’ of a radiographic image, i.e. an indistinct ‘penumbra’ area around the outside of the image. It is represented by a parameter Ug (unsharpness due to geometry) calculated from the specimen-to-film distance, focal spot size, etc.
Article 2 section T-285 specifies that geometric unsharpness (Ug) of a radiograph shall not exceed the following:
Material Ug thickness, in (mm) Maximum, in (mm) Under 2 (50.8) 0.020 (0.51) 2 through 3 (50.8–76.2) 0.030 (0.76) Over 3 through 4 (76.2–101.6) 0.040 (1.02) Greater than 4 (101.6) 0.070 (1.78)
In all cases, material thickness is defined as the thickness on which the IQI is chosen.
16.4 ASME V article 6: penetrant testing (PT)
T-620: general This article of ASME V explains the principle of penetrant testing (PT). We have already covered much of this in API 577, but ASME V article 6 adds some more formal detail.
T-642: surface preparation before doing PT Surfaces can be in the as-welded, as-rolled, as-cast or asforged condition and may be prepared by grinding, machining or other methods as necessary to prevent surface irregularities masking indications. The area of interest, and adjacent surfaces within 1 inch (25 mm), need to be prepared and degreased so that indications open to the surface are not obscured.
T-651: the PT techniques themselves Article 6 recognizes three penetrant processes:
Water washable
Post-emulsifying (not water based but will wash off with water)
Solvent removable
The three processes are used in combination with the two penetrant types (visible or fluorescent), resulting in a total of six liquid penetrant techniques.
T-652: PT techniques for standard temperatures
For a standard PT technique, the temperature of the penetrant and the surface of the part to be processed must be between 50 ℉ (10 ℃) and 125 ℉ (52 ℃) throughout the examination period. Local heating or cooling is permitted to maintain this temperature range.
T-670: the PT examination technique (see Fig. 16.4)
Figure 16.4 PT examination technique
T-671: penetrant application
Penetrant may be applied by any suitable means, such as dipping, brushing or spraying. If the penetrant is applied by spraying using compressed-air type apparatus, filters have to be placed on the upstream side near the air inlet to stop contamination of the penetrant by oil, water, dirt or sediment that may have collected in the lines.
T-672: penetration time
Penetration time is critical. The minimum penetration time must be as required in table T-672 or as qualified by demonstration for specific applications.
Note: While it is always a good idea to follow the manufacturers’ instructions regarding use and dwell times for their penetrant materials, table T-672 lays down minimum dwell times for the penetrant and developer. These are the minimum values that would form the basis of any exam questions based on ASME V.
T-676: interpretation of PT results
T-676.1: final interpretation Final interpretation of the PT results has to be made within 10 to 60 minutes after the developer has dried. If bleed-out does not alter the examination results, longer periods are permitted. If the surface to be examined is too large to complete the examination within the prescribed or established time, the examination should be performed in increments.
This is simply saying: inspect within 10–60 minutes. A longer time can be used if you expect very fine imperfections. Very large surfaces can be split into sections.
T-676.2: characterizing indication(s) Deciding (called characterizing in ASME-speak) the types of discontinuities can be difficult if the penetrant diffuses excessively into the developer. If this condition occurs, close observation of the formation of indications during application of the developer may assist in characterizing and determining the extent of the indications; i.e. the shape of deep indications can be masked by heavy leaching out of the penetrant, so it is advisable to start the examination of the part as soon as the developer is applied.
T-676.4: fluorescent penetrants
With fluorescent penetrants, the process is essentially the same as for colour contrast, but the examination is performed using an ultraviolet light, sometimes called black light. This is performed as follows:
(a) It is performed in a darkened area.
(b) The examiner must be in the darkened area for at least 5 minutes prior to performing the examination to enable his or her eyes to adapt to dark viewing. He or she must not wear photosensitive glasses or lenses.
(c) Warm up the black light for a minimum of 5 min prior to use and measure the intensity of the ultraviolet light emitted. Check that the filters and reflectors are clean and undamaged.
(d) Measure the black light intensity with a black lightmeter. A minimum of 1000 μW/cm2 on the surface of the part being examined is required. The black light intensity must be re-verified at least once every 8 hours, whenever the workstation is changed or whenever the bulb is changed.
T-680: evaluation of PT indications
Indications are evaluated using the relevant code acceptance criteria (e.g. API 650 for tanks). Remember that ASME V does not give acceptance criteria. Be aware that false indications may be caused by localized surface irregularities. Broad areas of fluorescence or pigmentation can mask defects and must be cleaned and re-examined.
16.6 ASME V article 7: magnetic testing (MT)
Similar to the previous article 6 covering penetrant testing, this article 7 of ASME V explains the technical principle of magnetic testing (MT). As with PT, we have already covered much of this in API 577, but article 7 adds more formal detail. Remember again that it is not component specific; it deals with the MT techniques themselves, not the extent of MT you have to do on a storage tank.
T-720: general MT methods are used to detect cracks and other discontinuities on or near the surfaces of ferromagnetic materials. It involves magnetizing an area to be examined, then applying ferromagnetic particles to the surface, where they form patterns where the cracks and other discontinuities cause distortions in the normal magnetic field.
Maximum sensitivity is achieved when linear discontinuities are orientated perpendicular to the lines of magnetic flux. For optimum effectiveness in detecting all types of discontinuities, each area should therefore be examined at least twice, with the lines of flux during one examination approximately perpendicular to the lines of flux during the other; i.e. you need two field directions to do the test properly.
T-750: the MT techniques (see Fig. 16.5) One or more of the following five magnetization techniques can be used:
(a) Prod technique
(b) Longitudinal magnetization technique
(c) Circular magnetization technique
(d) Yoke technique
(e) Multidirectional magnetization technique
Figure 16.5 MT examination technique
The API examination will be based on the prod or yoke techniques (i.e. (a) or (d) above), so these are the only ones we will consider. The others can be ignored for exam purposes. T-752: the MT prod technique T-752.1: the magnetizing procedure Magnetization is accomplished by pressing portable prod type electrical contacts against the surface in the area to be examined. To avoid arcing, a remote control switch, which may be built into the prod handles, must be provided to allow the current to be turned on after the prods have been properly positioned. T-752.3: prod spacing Prod spacing must not exceed 8 in (203 mm). Shorter spacing may be used to accommodate the geometric limitations of the area being examined or to increase the sensitivity, but prod spacings of less than 3 in (76 mm) are usually not practical due to ‘banding’ of the magnetic particles around the prods. The prod tips must be kept clean and dressed (to give good contact).
T-755: the MT yoke technique
This method must only be used (either with AC or DC electromagnetic yokes or permanent magnet yokes) to detect discontinuities that are surface breaking on the component.
T-764.1: magnetic field strength When doing an MT test, the applied magnetic field must have sufficient strength to produce satisfactory indications, but it must not be so strong that it causes the masking of relevant indications by non-relevant accumulations of magnetic particles. Factors that influence the required field strength include:
Size, shape and material permeability of the part
The magnetization technique
Coatings
The method of particle application
The type and location of discontinuities to be detected
Magnetic field strength can be verified by using one or more of the following three methods:
Method 1: T-764.1.1: pie-shaped magnetic particle field indicator
Method 2: T-764.1.2: artificial flaw shims
Method 3: T-764.1.3 hall effect tangential-field probe
T-773: methods of MT examination (dry and wet) Remember the different types of MT technique. The ferromagnetic particles used as an examination medium can be either wet or dry, and may be either fluorescent or colour contrast:
For dry particles the magnetizing current remains on while the examination medium is being applied and excess of the examination medium is removed. Remove the excess particles with a light air stream from a bulb, syringe or air hose (see T-776).
For wet particles the magnetizing current will be turned on after applying the particles. Wet particles from aerosol spray cans may be applied before and/or after magnetization. Wet particles can be applied during magnetization as long as they are not applied with sufficient velocity to dislodge accumulated particles.
T-780: evaluation of defects found during MT As with the other NDE techniques described in ASME V, defects and indications are evaluated using the relevant code acceptance criteria (e.g. API 650). Be aware that false indications may be caused by localized surface irregularities. Broad areas of particle accumulation can mask relevant indications and must be cleaned and re-examined.
16.7 ASME V article 23: ultrasonic thickness checking In the ASME V code, this goes by the grand title of Standard Practice for Measuring Thickness by Manual Ultrasonic Pulse-Echo Contact Method: section SE-797.2. This makes it sound much more complicated than it actually is. Strangely, it contains some quite detailed technical requirements comprising approximately seven pages of text and diagrams at a level that would be appropriate to a UT qualification exam. The underlying principles, however, remain fairly straightforward. We will look at these as broadly as we can, with the objective of picking out the major points that may appear as closed-book questions in the API examinations.
The scope of article 23, section SE-797
This technique is for measuring the thickness of any material in which ultrasonic waves will propagate at a constant velocity and from which back reflections can be obtained and resolved. It utilizes the contact pulse echo method at a material temperature not to exceed 200 8F (93 8C). Measurements are made from one side of the object, without requiring access to the rear surface.
The idea is that you measure the velocity of sound in thematerial and the time taken for the ultrasonic pulse to reach the back wall and return (see Fig. 16.6). Halving the result gives the thickness of the material.
Figure 16.6 UT thickness checking
Summary of practice
Material thickness (T), when measured by the pulse-echo ultrasonic method, is a product of the velocity of sound in the material and one half the transit time (round trip) through the material. The simple formula is:
T = Vt/2
where
T =thickness
V =velocity
t=transit time
Thickness-checking equipment
Thickness-measurement instruments are divided into three groups:
Flaw detectors with CRT readouts. These display time/ amplitude information in an A-scan presentation (we saw this method in a previous module). Thickness is measured by reading the distance between the zero-corrected initial pulse and first-returned echo (back reflection), or between multiple back reflection echoes, on a calibrated base-line of a CRT. The base-line of the CRT should be adjusted to read the desired thickness increments. Flaw detectors with CRT and direct thickness readout. These are a combination pulse ultrasound flaw detection instrument with a CRT and additional circuitry that provides digital thickness information. The material thickness can be electronically measured and presented on a digital readout. The CRT provides a check on the validity of the electronic measurement by revealing measurement variables, such as internal discontinuities, or echo-strength variations, which might result in inaccurate readings.
Direct thickness readout meters. Thickness readout instruments are modified versions of the pulse-echo instrument. The elapsed time between the initial pulse and the first echo or between multiple echoes is converted into a meter or digital readout. The instruments are designed for measurement and direct numerical readout of specific ranges of thickness and materials.
Standardization blocks Article 23 goes into great detail about different types of ‘search units’. Much of this is too complicated to warrant too much attention. Note the following important points. Section 7.2.2.1: calibration (or standardization) blocks Two ‘calibration’ blocks should be used: one approximately the maximum thickness that the thickness meter will be measuring and the other the minimum thickness.
Thicknesses of materials at high temperatures up to about 540 ℃ (1000 ℉) can be measured with specially designed instruments with high-temperature compensation. A rule of thumb is as follows:
A thickness meter reads 1 % too high for every 55 ℃ (100 ℉) above the temperature at which it was calibrated. This correction is an average one for many types of steel. Other corrections would have to be determined empirically for other materials.
An example. If a thickness meter was calibrated on a piece of similar material at 20 ℃ (68 ℉), and if the reading was obtained with a surface temperature of 460 ℃ (860 ℉), the apparent reading should be reduced by 8 %.
Now try these familiarization questions on ASME V articles 1, 2 and 6.
16.5 ASME V articles 1, 2 and 6: familiarization questions
Now try these familiarization questions covering ASME V articles 7 and 23 (article 9 questions are too easy).
16.8 ASME V articles 7 and 23: familiarization questions
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API 653 Exam Chapter 15 – Cathodic Protection: API RP 651
This chapter is about learning to become familiar with the layout and contents of API RP 651: Cathodic Protection of Above-ground Storage Tanks. This is the main source of information on cathodic protection of tank bottoms included in the API 653 BOK.
15.1 Cathodic protection – what’s it all about?
Cathodic protection (CP) is about protecting the soil side of a tank bottom from corrosion. Although modern tanks tend to be constructed on concrete bases, many older ones were laid directly on soil or rubble bases, so the underside of their floors are in permanent contact with the soil. Depending on its make-up, conductivity and suchlike, corrosion currents pass between the soil and the floor, a galvanic cell is set up and the floor corrodes away. This type of corrosion can be quite aggressive and widespread, and of course is hidden away under the floor where it cannot be seen. The first clue of its existence is generally a leakage of the tank contents into the surrounding soil, causing all manner of problems.
API 653 is well aware of the need to minimize underfloor corrosion. The latest edition places limits on the timing of the first internal inspection of a new tank (see API 653 section 6.4.2.1) and allows a longer maximum interval if CP is fitted, particularly in conjunction with an internal lining protecting the product side as well. The inference is that a CP system can therefore reduce the probability of failure (POF) when carrying out an RBI assessment of a tank. Similarly, API 653 refers to CP as an example of a release prevention system (RPS) – a generic term used for any measure used to preserve tank integrity, particularly of the floor (see API 653 clause 4.4.3).
API 575, being an older publication, sticks to a few well established references to CP. It is raised as an issue to 269 consider if you are trying to decide the bottom corrosion rate by ‘similar service’ extrapolation rather than by actual measurement. Whether or not CP is installed will obviously have a large effect on whether similar service assumptions are valid or just a fanciful way of justifying fewer inspections.
Apart from that, there is a mention of tunnelling under the bottom to assess soil-side corrosion (yes, its allowed, see API 575 (section 7.3.1)), a reminder to include CP when replacing tank bottoms, and that is about all. From this you can see that almost all of the relevant information on CP is delegated over to API 651.
API 651 is a well-established but short document (now on its 3rd edition: 2007). As a short code, it supplies supplementary technical information suitable mainly for open-book examination questions. Similar to the other short document in the BOK (API 652: Lining of Tank Bottoms) it is more of 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 points about API 651:
Scope. It has a narrow scope (evidenced by its title), which is specifically about the cathodic protection (CP) of above ground tanks. In addition, the technical information that it provides is at a ‘general knowledge’ level. There is little that is new or innovative about this subject.
Exam BOK. Not all sections of the code are actually included in the API 653 BOK. The sections that are covered are those that describe the more general aspects of CP. They are:
Sections 1 to 6
Section 8
Section 11
Those sections that describe the technical detail of CP systems (API 651 sections 7, 9 and 10) are specifically excluded from the BOK, so you can cross them out in your code.
Definitions. It contains a good few specific terminology and definitions (most of which are defined in the ‘definitions’ section 3). There is nothing particularly difficult about the terms used, once you have read through them. Most are general engineering knowledge or commonsense.
Related codes. Similar to most of the other codes in the API 653 exam BOK, section 2 of API 651 refers to a lot of related codes that are not actually in the BOK. The main ones are a long list of specific API RP documents covering various detailed aspects of cathodic protection (RP 1632, RP-01-69, RP-01-77 and others). Once again, do not worry about these referenced documents; you need to know that they exist but will not need them for the API 653 examination.
Damage mechanisms. API 651 is based on the avoidance of galvanic corrosion mechanisms, so can therefore expect some crossover with the content of API 571: Damage Mechanisms. There are a few minor differences in terminology, but no direct contradictions as such. In fact, API 571 contains much more technical detail about galvanic corrosion than API 651, which is more focused on its avoidance, rather than describing the mechanisms in great technical detail.
On a general note, API 651 consists mainly of text and technical descriptions, accompanied by explanatory photographs of a general nature. It contains no calculations relevant to exam questions. In recent API 653 exams, many of the questions about API 651 have been found in the closed-book part of the exam, so you do need to develop a working familiarity with the technical content of API 651 in order to prepare for these questions. We will look at some of the more important areas as we work through this chapter.
15.2 The content of API 651
15.2.1 API 651 sections 1 and 2: Scope and References
These sections contain 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 specifications, and the list of ones covering the more specialized aspects of cathodic protection (which are not in the 653 BOK).
15.2.2 API 651 section 3: Definitions
This is a long section, compared to the length of API 651 itself. It also contains more important definitions than are often found in this area of API codes, so you need to give this section a bit of attention. Note the following definitions as potential exam questions:
Coke breeze, backfill, liner and membrane
Tank pad and tank cushion
Groundbed and shallow-anode groundbed
Structure-to-structure and structure-to-electrolyte voltage
Note this important one:
The difference between an anode and a cathode (and which one corrodes)
Figure 15.1 summarizes some of the terminology used in API 651.
15.2.3 API 651 section 4: Corrosion of Above-ground Steel Storage Tanks
This section covers how and why storage tanks corrode. The galvanic corrosion mechanism (API 651 section 4.1.1) Although the text does not mention it specifically, just about all corrosion in the world involves galvanic corrosion cells of one type or another. This section breaks the description of the cell into four parts (a, b, c, d). Note the following points, where they appear in the text:
Figure 15.1 Tank cathodic protection: API 653 terminology
It is the anode that corrodes, as the base metal goes into solution.
The cathode protects the anode (you can think of it like that), and no corrosion takes place at the cathode.
The objective of CP is therefore to make the tank cathodic, so it will not corrode. It does, of course, have to be cathodic to something, so a sacrificial anode is used for this.
Note the point in 4.1.1d, which infers the fact that tank bottoms may actually suffer galvanic corrosion cells on both their external surface and internal surfaces.
API 651 sections 4.1.2–4.1.5
These sections contain quite a few little hidden points that you can expect to appear as exam questions. Note the following:
Pitting corrosion has a smaller number of (larger) corrosion cells than general corrosion. Definitions of pitting appear regularly as exam questions. Someone, somewhere, obviously thinks that knowing this makes you a good tank inspector.
Minute differences in alloying elements, contaminants and
Figure 15.2 Oxygen concentration cells
variations in the electrolyte (the soil) can result in uneven potentials, so starting off a corrosion cell. In practice, this means that these cells can start almost anywhere, and you have no way of predicting where that might be.
Areas of low oxygen concentrations become anodic (the part that corrodes).
Note the content of API 651 Fig. 2 (there is potential for exam questions in there) . . . you can see the idea in Fig. 15.2 here.
Corrosion mechanisms (API 651 section 4.2)
The important fact in section 4.2.1 is the part that stray currents (particularly DC ones) play in contributing to galvanic corrosion of storage tanks. Note where they come from; earthed (API call it grounded) DC power systems are often unrelated to the storage tank under consideration.
Section 4.2.2 contains the key technical definitions of galvanic corrosion. It is well worth learning the various technical points in this section; it contains at least four points that can form closed-book exam questions. Find these points by looking for the answers in your code (all in API 651 section 4.2.2) to these four questions:
1 Which way does current flow in a corrosion cell?
2 If a stainless steel tank is connected to a plain carbon steel tank, which one becomes the anode and corrodes?
3 In the above example, where in the tank will the worst corrosion actually occur, and why?
4 By inference, what two things most commonly govern the corrosion rate above?
Internal corrosion (API 651 section 4.3)
Note the content of this section about the possibility of corrosion occurring inside a tank bottom, not just on the outside (underneath). The list of six factors that influence the severity of corrosion are worth noting. The last one (temperature) was only added in the latest edition of API 651; it was not there before. Note also the cross-reference to API 652, which also mentions corrosion mechanisms (as does API 571).
15.3 Determination of the need for cathodic protection (API 651 section 5)
The first key points in this section occur in 5.1.3. This introduces the fact that pure hydrocarbons are not particularly corrosive and it is the presence of contaminants (water, etc.) that is the trigger for the corrosion of internal tank surfaces. For external corrosion, note the statement in 5.1.4 confirming that the tank bottom plays the role of the cathode and in order to install cathodic protection of the tank bottom it needs to be possible to pass a current between the tank bottom and a sacrificial anode situated in the ground external to the tank.
15.3.1 Tank pad and soil conditions (API 651 section 5.3)
This section contains some important points that come up regularly as examination questions. Here are the main ones:
The cushion material (note the terminology) under the tank can have an important effect on how well a CP system works.
Fine-grained cushion material is best as large-grained particles can result in differential aeration, encouraging pitting of the tank bottom.
High soil resistivity (resistance) is best (see API 651 Table 1) as it minimizes corrosion activity. Expect exam questions to ask you about the numbers in this table.
The need to check the resistance of surrounding soil, to see if there is any chance of contamination of a good, high resistance foundation layer.
15.3.2 Different types of tank cushion (foundation)
API 651 sections 5.3.2 to 5.3.7 introduce six different types of tank cushion as follows:
Sand pad
Continuous concrete pad
Crushed limestone or clamshell pad
Oiled-sand pad
Continuous asphalt pad
Native soil pad
Of these, almost all modern tanks (excluding perhaps some constructed in remote desert areas) are made using continuous concrete slab cushions. Section 5.3.3 discusses the use of a stable, properly prepared subsoil, free-draining concrete pad design and the fact that CP systems may not be sufficient to control corrosion, if these are not properly complied with. Figure 15.3 should help you understand these better.
The alternative (non-concrete) types of tank base are best considered in terms of their disadvantages. Salient points are:
For soil bases, pH must be checked to see if it is corrosive.
Clean-sand bases do not eliminate the need for CP.
Oiled sand may actually reduce the effectiveness of CP due to the higher resistance of the oiled sand (even though the oil may reduce corrosion in other ways).
Figure 15.3 Types of tank pad
15.3.3 Release prevention barriers (RPBs): API 651 section 5.4.3
Secondary containment is a way of controlling the accidental escape of the stored product, thereby reducing the chance of contamination due to leaks and spills. The three main methods in use are a liquid-tight tank dyke (or bund), a double bottom tank design and an impervious (thick plastic sheet) membrane underneath the tank foundation. The main content of API 651 section 5.4.3 is to emphasize that these RPBs can prevent the use of effective CP and, in some cases, produce conditions that actually accelerate the corrosion of the tank bottom.
15.3.4 Methods of CP for corrosion control (API 651 section 6)
This is straightforward enough. There are only two methods:
Section 6.2.1 explains the use of zinc or magnesium cast or ribbon anodes, buried underneath and/or around the tank and the resulting limitations (low anti-corrosion potential, restricted to low resistance soils, more useful for small tanks, etc.)
The more useful impressed current CP system is explained in section 6.3. API 651 Fig. 6 shows how it works. Note how the current direction travels from the buried anode to the tank (cathode and negative). Note also how these CP systems work off direct current (DC), usually provided by a rectifier powered by an alternating current (AC) source. This is good source material for exam questions. Note the materials identified in section 6.3.5 that the CP anodes are frequently made from – another good closed-book examination question.
Remember that you do not need API 651 section 7: Design of CP Systems as it is not in the exam BOK.
15.4 Criteria for cathodic protection (API 651 section 8)
This is a short section. It is included (perhaps) in the syllabus because it contains some quantitative (number) values that can be used as exam questions. For adequate protection, a tank must be 850 mV cathodic (negative) with the CP applied. This is with respect to a reference electrode contacting the electrolyte (soil) around the tank. It is important to read section 8.3: Measurement Techniques. It is a bit complicated but do not worry too much about the detail. The main points are:
The important measurement is the tank-to-soil protection potential.
The protection potential is measured with the CP current applied.
Correction is needed for IR (voltage) drops in the soil.
Notice what reference electrodes can be made of (API 651 Table 3).
Remember to cross out section 9 of API 651: Impressed Current Systems and section 10: Interference Currents. They are not in the API 653 exam BOK.
15.5 Operation and maintenance of CP systems (API 651 section 11)
This section is largely commonsense; however, it contains important exam question information. The best way to retain this information is to read through the section and find the answers yourself to the following questions:
1 Should a tank be full or empty when doing a bottom-toelectrode potential check . . . and why?
2 What is breakout piping (check back in section 3: Definitions)? What safety precautions should you specifically take before separating joints if a CP system has been in use?
3 How often are periodic CP surveys recommended to ensure the system is still working correctly?
4 How often should the impressed current sources be checked?
5 What does API 651 section 11.4.7 recommend for the retention times for CP records?
Now try these self-test questions covering the content of API 651.
15.6 API 651: cathodic protection: practice questions
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API 653 Exam Chapter 14 – Welding Qualifications and ASME IX
14.1 Module introduction
The purpose of this chapter is to familiarize you with the principles and requirements of welding qualification documentation. These are the Weld Procedure Specification (WPS), Procedure Qualification Record (PQR) and Welder Performance Qualification (WPQ). The secondary purpose is to define the essential, non-essential and supplementary essential variables used in qualifying WPSs. ASME section IX is a part of the ASME Boiler Pressure Vessel code that contains the rules for qualifying welding procedures and welders. It is also used to qualify welders and procedures for welding to ASME VIII.
14.1.1 Weld procedure documentation: which code to follow?
API 650 and 653 require that repair organizations must use welders and welding procedures qualified to ASME IX and maintain records of the welding procedures and welder performance qualifications. ASME IX article II states that each Manufacturer and Contractor shall prepare written Welding Procedure Specifications (WPSs) and a Procedure Qualification Record (PQR), as defined in section QW-200.2.
14.2 Formulating the qualification requirements
The actions to be taken by the manufacturer to qualify a WPS and welder are done in the following order (see Fig. 14.1):
Figure 14.1 Formulating the qualification requirements
Step 1: qualify the WPS .
A preliminary WPS (this is an unsigned and unauthorized document) is prepared specifying ranges of essential variables, supplementary variables (if required) and non-essential variables required for the welding process to be used.
The required numbers of test coupons are welded and the ranges of essential variables used recorded on the PQR.
Any required non-destructive testing and/or mechanical testing is carried out and the results recorded in the PQR.
If all the above are satisfactory then the WPS is qualified using the documented information on the PQR as proof that the WPS works.
The WPS (see Fig. 14.2) is signed and authorized by the manufacturer for use in production.
Step 2: qualify the welder. The next step is to qualify the welder by having him weld a test coupon to a qualified WPS. The essential variables used, tests and results are noted and the ranges qualified on a Welder Performance Qualification (WPQ) (see Fig. 14.3).
Note that ASME IX does not require the use of preheat or PWHT (post weld heat treatment) on the welder test coupon. This is because it is the skill of the welder and his ability to follow a procedure that is being tested. The pre and PWHT are not required because the mechanical properties of the joint have already been determined during qualification of the WPS.
We will now look at the ASME IX code rules covering WPSs and PQRs. The code section splits the variables into three groups:
Essential variables
Non-essential variables
Supplementary variables
These are listed on the WPS for each welding process. ASME IX section QW-250 lists the variables that must be specified on the WPS and PQR for each process. Note how this is a very long section of the code, consisting mainly of tables covering the different welding processes. There are subtle differences between the approaches to each process, but the guiding principles as to what is an essential, non-essential and supplementary variable are much the same.
14.2.2 ASME IX welding documentation formats
The main welding documents specified in ASME IX have examples in non-mandatory appendix B section QW-482. Strangely, these are not included in the API 653 exam code document package but fortunately two of them, the WPS and PQR, are repeated in API 577 (have a look at them in API 577 appendix C). Remember that the actual format of the procedure sheets is not mandatory, as long as the necessary information is included.
The other two that are in ASME IX non-mandatory appendix B (the WPQ and Standard Weld Procedure Specification (SWPS)) are not given in API 577 and are therefore a bit peripheral to the API 653 exam syllabus.
14.3 Welding documentation reviews: the exam questions
The main thrust of the API 653 ASME IX questions is based on the requirement to review a WPS and its qualifying PQR, so these are the documents that you must become familiar with. The review will be subject to the following limitations (to make it simpler for you):
The WPS and its supporting PQR will contain only one welding process.
The welding process will be SMAW or SAW and will have only one filler metal.
The base material P group number will be limited to P1 only
Base materials are assigned P-numbers in ASME IX to reduce the amount of procedure qualifications required. The P-number is based on material characteristics like weldability and mechanical properties. S-numbers are the same idea as P-numbers but deal with piping materials from ASME B31.3.
14.3.1 WPS/PQR review questions in the exam
The API 653 certification exam requires candidates to review a WPS and its supporting PQR. The format of these will be based on the sample documents contained in annex B of ASME IX. Remember that this annex B is not contained in your code document package; instead, you have to look at the formats in API 577 appendix B, where they are shown (they are exactly the same).
The WPS/PQR documents are designed to cover the parameters/variables requirements of the SMAW, GTAW, GMAW and SAW welding processes. The open-book questions on these documents in the API exam, however, only contain one of those welding processes. This means that there will be areas on the WPS and PQR documents that will be left unaddressed, depending on what process is used. For example, if GTAW welding is not specified then the details of tungsten electrode size and type will not be required on the WPS/PQR.
In the exam questions, you will need to understand the variables to enable you to determine if they have been correctly addressed in the WPS and PQR for any given process.
Figure 14.4 The ASME IX numbering system
14.3.2 Code cross-references
One area of ASME IX that some people find confusing is the numbering and cross-referencing of paragraphs that takes place throughout the code. Figure 14.4 explains how the ASME IX numbering system works.
14.4 ASME IX article I
Article I contains less technical ‘meat’ than some of the following articles (particularly articles II and IV). It is more a collection of general statements than a schedule of firm technical requirements. What it does do, however, is crossreference a lot of other clauses (particularly in article IV), which is where the more detailed technical requirements are contained.
From the API exam viewpoint, most of the questions that can be asked about article I are:
More suitable to closed-book questions than open-book ones .
Fairly general and ‘commonsense’ in nature
Don’t ignore the content of article I. Read the following summaries through carefully but treat article I more as a lead-in to the other articles, rather than an end in itself.
Section QW-100.1
This section tells you five things, all of which you have met before. There should be nothing new to you here. They are:
A Weld Procedure Specification (WPS) has to be qualified (by a PQR) by the manufacturer or contractor to determine that a weldment meets its required mechanical properties.
The WPS specifies the conditions under which welding is performed and these are called welding ‘variables’.
The WPS must address the essential and non-essential variables for each welding process used in production.
The WPS must address the supplementary essential variables if notch toughness testing is required by other code sections.
A Procedure Qualification Record (PQR) will document the welding history of the WPS test coupon and record the results of any testing required.
Section QW-100.2
A welder qualification (i.e. the WPQ) is to determine a welder’s ability to deposit sound weld metal or a welding operator’s mechanical ability to operate machine welding equipment.
14.5 Section QW-140 types and purposes of tests and examinations
Section QW-141: mechanical tests Mechanical tests used in procedure or performance qualification are as follows:
QW-141.1: tension tests (see Fig. 14.5). Tension tests are used to determine the strength of groove weld joints.
QW-141.2: guided-bend tests (see Fig. 14.6). Guided-bend tests are used to determine the degree of soundness and ductility of groove-weld joints.
QW-141.3: fillet-weld tests. Fillet weld tests are used to determine the size, contour and degree of soundness of fillet welds.
QW-141.4: notch-toughness tests. Tests are used to determine the notch toughness of the weldment.
Figure 14.5 Tension testsFigure 14.6 Guided bend tests
14.6 ASME IX article II
Article II contains hard information about the content of the WPS and PQRs and how they fit together. In common with article I, it cross-references other clauses (particularly in article IV). From the API examination viewpoint there is much more information in here that can form the basis of open-book questions, i.e. about the reviewing of WPS and PQR. ASME IX article II is therefore at the core of the API examination requirements.
Section QW-200: general This gives lists of (fairly straightforward) requirements for the WPS and PQR:
QW-200.1 covers the WPS. It makes fairly general ‘principle’ points that you need to understand (but not remember word-for-word).
QW-200.2 covers the PQR again. It makes fairly general ‘principle’ points that you need to understand (but not remember word-for-word).
QW-200.3: P-numbers. P-numbers are assigned to base metals to reduce the number of welding procedure qualifications required. For steel and steel alloys, group numbers are assigned additionally to P-numbers for the purpose of procedure qualification where notch-toughness requirements are specified.
14.8 ASME IX article III
Remember that WPQs are specific to the welder. While the content of this article is in the API 653 syllabus it is fair to say that it commands less importance than articles II (WPSs and PQRs and their relevant QW-482 and QW-483 format forms) and article IV (welding data).
Section QW-300.1 This article lists the welding processes separately, with the essential variables that apply to welder and welding operator performance qualifications. The welder qualification is limited by the essential variables listed in QW-350, and defined in article IV Welding data, for each welding process. A welder or welding operator may be qualified by radiography of a test coupon or his initial production welding, or by bend tests taken from a test coupon.
Look at these tables below and mark them with post-it notes:
Table QW-353 gives SMAW essential variables for welder qualification.
Table QW-354 gives SAW essential variables for welder qualification.
Table QW-355 gives GMAW essential variables for welder qualification.
Table QW-356 gives GTAW essential variables for welder qualification.
Section QW-351: variables for welders (general) A welder needs to be requalified whenever a change is made in one or more of the essential variables listed for each welding process. The limits of deposited weld metal thickness for which a welder will be qualified are dependent upon the thickness of the weld deposited with each welding process, exclusive of any weld reinforcement.
In production welds, welders may not deposit a thickness greater than that for which they are qualified.
14.9 ASME IX article IV
Article IV contains core data about the welding variables themselves. Whereas article II summarizes which variables are essential/non-essential/supplementary for the main welding processes, the content of article IV explains what the variables actually are. Note how variables are subdivided into procedure and performance aspects.
Section QW-401: general Each welding variable described in this article is applicable as an essential, supplemental essential or non-essential variable for procedure qualification when referenced in QW-250 for each specific welding process. Note that a change from one welding process to another welding process is an essential variable and requires requalification.
Section QW-401.1: essential variable (procedure) This is defined as a change in a welding condition that will affect the mechanical properties (other than notch toughness) of the weldment (for example, change in P-number, welding process, filler metal, electrode, preheat or post-weld heat treatment, etc.).
Section QW-401.2: essential variable (performance) A change in a welding condition that will affect the ability of a welder to deposit sound weld metal (such as a change in welding process, electrode F-number, deletion of backing, technique, etc.).
Section QW-401.3: supplemental essential variable (procedure) A change in a welding condition that will affect the notchtoughness properties of a weldment (e.g. change in welding process, uphill or downhill vertical welding, heat input, preheat or PWHT, etc.).
Section QW-401.4: non-essential variable (procedure) A change in a welding condition that will not affect the mechanical properties of a weldment (such as joint design, method of back-gouging or cleaning, etc.).
Section QW-401.5 The welding data include the welding variables grouped as follows:
QW-402 joints
QW-403 base metals
QW-404 filler metal
QW-405 position
QW-406 preheat
QW-407 post-weld heat treatment
QW-408 gas
QW-409 electrical characteristics
QW-410 technique
Section QW-420.1: P-numbers P-numbers are groupings of base materials of similar properties and usability. This grouping of materials allows a reduction in the number of PQRs required. Ferrous P-number metals are assigned a group number if notch toughness is a consideration.
Section QW-420.2: S-numbers (non-mandatory) S-numbers are similar to P-numbers but are used on materials not included within ASME BPV code material specifications (section II). There is no mandatory requirement that S-numbers have to be used, but they often are. Note these two key points:
For WPS a P-number qualifies the same S-number but not vice versa.
For WPQ a P-number qualifies the same S-number and vice versa.
Section QW-430: F-numbers The F-number grouping of electrodes and welding rods is based essentially on their usability characteristics. This grouping is made to reduce the number of welding procedure and performance qualifications, where this can logically be done.
Section QW-432.1 Steel and steel alloys utilize F-1 to F-6 and are the most commonly used ones. Section QW-492: definitions QW-492 contains a list of definitions of the common terms relating to welding and brazing that are used in ASME IX. Try these ASME IX articles III and IV familiarization
14.11 The ASME IX review methodology
One of the major parts of all the API in-service inspection examinations is the topic of weld procedure documentation review. In addition to various ‘closed-book’ questions about welding processes and techniques, the exams always include a group of ‘open-book’ questions centred around the activity of checking a Weld Procedure Specification (WPS) and Procedure Qualification Record (PQR).
Note the two governing principles of API examination questions on this subject:
The PQR and WPS used in exam examples will only contain one welding process and filler material.
You need only consider essential and non-essential variables (you can ignore supplementary variables).
The basic review methodology is divided into five steps (see Fig. 14.7). Note the following points to remember as you go through the checklist steps of Fig. 14.7:
The welding process is an essential variable and for the API 653 exam will be limited to SMAW or SAW only.
Non-essential variables do not have to be recorded in the PQR (but may be at the manufacturer’s discretion) and must be addressed in the WPS.
Information on the PQR will be actual values used whereas the WPS may contain a range (e.g. the base metal actual thickness shown in a PQR may be 1/2 in, while the base metal thickness range in the WPS may be 3/16 in–1 in).
The process variables listed in tables QW-252 to QW-265
STEP 1: variables table
Find the relevant ‘brief of variables’ table in article II of ASME IX for the specified welding process (for example QW-253 for SMAW). This table shows the relevant essential and non-essential variables for the welding process.
STEP 2: PQR check
Check that the ‘editorial’ information at the beginning and at the end of the PQR form is filled in. • Check that all the relevant essential variables are addressed on the PQR and highlight any that are not.
STEP 3: WPS check
Check that the editorial information at the beginning of the WPS form is filled in and agrees with the information on the PQR.
Check that all the relevant essential variables are addressed on the WPS and highlight any that are not.
Check that all the relevant non-essential variables are addressed on the WPS and highlight any that are not.
STEP 4: range of qualification
Check that the range of qualification for each essential variable addressed in the PQR is correct and has been correctly stated on the WPS.
STEP 5: number of tensile and bend tests
Check that the correct type and number of tensile and bend tests have been carried out and recorded on the PQR.
Check that the tensile/bend test results are correct.
Figure 14.7 The ASME IX WPS/PQR review methodology
are referred to as the ‘brief of variables’ and must not be used on their own. You must refer to the full variable requirements referenced in ASME IX article IV otherwise you will soon find yourself in trouble.
The base material will be P1 only for the API 653 exam (base materials are assigned P-numbers in ASME IX to reduce the amount of procedure qualifications required).
14.12 ASME IX WPS/PQR review: worked example
The following WPS/PQR is for an SMAW process and contains typical information that would be included in an exam question. Work through the example and then try the questions at the end to see if you have understood the method.
Figures 14.8 and 14.9 show the WPS and PQR for an SMAW process. Typical questions are given, followed by their answer and explanation.
Figure 14.8a SMAW worked example (WPS)Figure 14.8b SMAW worked example (WPS)Figure 14.9a SMAW worked example (PQR)Figure 14.9b SMAW worked example (PQR)
Now try these familiarization questions, using ASME IX articles I and II to find the answers.
14.7 ASME IX articles I and II familiarization questions
Try these ASME IX articles III and IV familiarization Quick Guide to API 653 254 questions. You will need to refer to your code to find the answers.
14.10 ASME IX articles III and IV familiarization questions
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API 653 Exam Chapter 13 Introduction to Welding/API RP 577
13.1 Module introduction
The purpose of this chapter is to ensure you can recognize the main welding processes that may be specified by the welding documentation requirements of ASME IX. The API exam will include questions in which you have to assess a Weld Procedure Specification (WPS) and its corresponding Procedure Qualification Record (PQR). As the codes used for API certification are all American you need to get into the habit of using American terminology for the welding processes and the process parameters.
This module will also introduce you to the API RP 577 Welding Inspection and Metallurgy in your code document package. This document has only recently been added to the API examination syllabus. As a Recommended Practice (RP) document, it contains technical descriptions and instruction, rather than truly prescriptive requirements.
13.2 Welding processes
There are four main welding processes that you have to learn about:
Shielded metal arc welding (SMAW)
Gas tungsten arc welding (GTAW)
Gas metal arc welding (GMAW)
Submerged arc welding (SAW)
The process(es) that will form the basis of the WPS and PQR questions in the API exam will almost certainly be chosen from these.
The sample WPS and PQR forms given in the non mandatory appendix B of ASME IX (the form layout is not strictly within the API 653 examination syllabus, but we will discuss it later) only contain the information for qualifying these processes.
13.2.1 Shielded metal arc welding (SMAW)
This is the most commonly used technique. There is a wide choice of electrodes, metal and fluxes, allowing application to different welding conditions. The gas shield is evolved from the flux, preventing oxidation of the molten metal pool (Fig. 13.1). An electric arc is then struck between a coated electrode and the workpiece. SMAW is a manual process as the electrode voltage and travel speed are controlled by the welder. It has a constant current characteristic
Figure 13.1 The shielded metal arc welding (SMAW) process
13.2.2 Metal inert gas (GMAW)
In this process, electrode metal is fused directly into the molten pool. The electrode is therefore consumed, being fed from a motorized reel down the centre of the welding torch (Fig. 13.2). GMAW is known as a semi-automatic process as the welding electrode voltage is controlled by the machine.
Tungsten inert gas (GTAW)
This uses a similar inert gas shield to GMAW but the tungsten electrode is not consumed. Filler metal is provided from a separate rod fed automatically into the molten pool (Fig. 13.3). GTAW is another manual process as the welding electrode voltage and travel speed are controlled by the welder.
Submerged arc welding (SAW)
In SAW, instead of using shielding gas, the arc and weld zone are completely submerged under a blanket of granulated flux (Fig. 13.4). A continuous wire electrode is fed into the weld. This is a common process for welding structural carbon or carbon–manganese steelwork. It is usually automatic with
Figure 13.2 The gas metal arc welding (GMAW) processFigure 13.3 The gas tungsten arc welding (GTAW) process
the welding head being mounted on a traversing machine. Long continuous welds are possible with this technique.
Flux-cored arc welding (FCAW)
FCAW is similar to the GMAW process, but uses a continuous hollow electrode filled with flux, which produces the shielding gas (Fig. 13.5). The advantage of the technique is that it can be used for outdoor welding, as the gas shield is less susceptible to draughts.
13.3 Welding consumables
An important area of the main welding processes is that of weld consumables. We can break these down into the following three main areas:
Filler (wires, rods, flux-coated electrodes)
Flux (granular fluxes)
Gas (shielding, trailing or backing)
There are always questions in the API examination about weld consumables.
Figures 13.6 to 13.11 show basic information about the main welding processes and their consumables.
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API 653 Exam Chapter 12 – Tank Linings: API RP 652
12.1 Introduction
This chapter is about learning to become familiar with the layout and contents of API RP 652: Lining of Above-ground Storage Tanks. Similar to API RP 651, API 652 is a wellestablished document (recently issued in its 3rd edition: 2005). As a short code, it supplies supplementary technical information suitable mainly for open-book examination questions. Similar to the other short code in the syllabus, it is more a technical guide document than a true code, but it performs a function in supporting the content of API 653. It contains useful technical information on the lining of tank bottoms to minimize the effects of corrosion. API 652 is one of those API documents that, in each revision, seems to grow in technical detail, rather than keeping the scope constant and just making a few paragraph amendments, as many codes do.
Note the following five points about API 652:
Point 1.Tank bottoms can be lined on the inside or outside (i.e. the bottom surface). This is mentioned in a couple of places in the document but perhaps not made particularly clear.
Point 2. API 652 covers linings that are either applied to new tanks or retrofitted to old ones, normally to try to stop future corrosion where significant corrosion has already been found. It introduces both thin- and thick-film linings, but does not go into a lot of technical detail about the chemical and mechanical properties of the linings themselves. This is because lining materials are incredibly varied (there are hundreds of different proprietary ones, each specified by its own manufacturer’s data sheet) so it would be next to impossible to produce any meaningful generic information that would apply to all of them.
Point 3. Although very relevant to the API 653 body of knowledge, API 652 contains little information on inspection itself. It concentrates more on describing the need for tank bottom linings, their properties and how they can fail. Within this scope, however, lies a lot of technical information points suitable for use as closed-book exam questions.
Point 4. In the few areas that API 652 does contain information related to the inspection of linings (and, more importantly, the preparation of the surface before lining), it cross-references various related US codes. The main ones are from:
SSPC (The Steel Structures Painting Council)
NACE (The National Association of Corrosion Engineers)
While most oil/gas/petrochemical inspectors have heard of NACE codes, the SSPC ones are less familiar outside the US. These SSPC codes deal with metal surface cleaning, shot blast and surface finish grades. Most European countries use the Swedish standard SIS 055966 instead (the source of the SA shot blast surface finish grades).
Point 5. Like API 651, API 652 discusses corrosion mechanisms, specifically of the tank floors, so you can expect some crossover with the coverage of API 571 damage mechanisms. Note, however, that the corrosion discussed in API 652 is mainly related to the internal surfaces of the tank bottom, rather than the external galvanic corrosion described in more detail in API 571.
Finally, API 651 is mainly text and technical descriptions, accompanied by a few tables of a fairly general nature. It contains no calculations relevant to exam questions but does contain a few quantitative facts and figures that are worth remembering. API examinations have an annoying habit of using questions that test candidates’ short-term memory of facts and figures that appear in the codes. Watch out for these as you read through this code.
12.2 Linings and their problems, problems, problems
Inspectors soon become familiar with the application and inspection of linings and the problems that they bring. If you have never inspected linings, or been involved with them at all, you can give yourself a head start by reading the following commentary.
12.2.1 What are they?
The linings we are talking about here are mainly of the epoxy or rubber-based types, not loose steel linings, welded ‘buttered’ linings or anything like that. They are used on new tanks to try and stop corrosion, and on old tanks that are badly corroded, either because they were not lined in the first place or because the original lining has fallen off.
12.2.2 So what’s the problem?
The problem is that linings love to fall off. Overall, perhaps almost 50 % of new linings fall off and do not reach their design life, and that includes those that were reasonably well applied and inspected. If you consider those that were not well chosen, applied, inspected or whatever, then most of them fall off. All of each lining does not fall off of course, only bits of it annoyingly small bits clinging to (or supposed to be clinging to) rough welds, bits of spatter, sharp corners, etc. This leaves small unprotected areas of parent material.
Small unprotected areas are good news for the corrosion, which sees each one as an opportunity to produce a pinhole, the rate of corrosion being greatly accelerated by the small area. At the same time, it nibbles away at the not-very-well bonded lining on either side of the pinhole and starts to peel this back; the corrosion creeps underneath and the hole gets bigger. The incredibly unsurprising end result is that the parent metal corrodes through and everyone gets together in a big meeting to discuss why the lining failed. Works every time.
All is not finished yet we can reline it (they say).
Yes, you can reline tank or vessel surfaces successfully, either by piecemeal repairs or complete relining. You can also line vessels that were not lined originally and have already suffered, corrosion. The problem is that more than 50% of the linings (relinings that is) fail due to either poor preparation or for a new reason. Here it is:
To retrospectively line a corroded item, you have to get the surface totally clean of soluble salts and similar contaminants. It is no good just shotblasting the surface; it has to be chemically clean as well. This is always difficult, as, by definition, any surface that is corroded has probably been exposed to salts in some form.
12.2.3 The conclusion
The conclusion is simply that getting linings to perform well on tank or vessel surfaces is difficult. Although the linings themselves, like paints, are the results of a lot of expensive development and testing, and are generally of high quality, the practice of their pre-preparation and application is not always of such a high standard. The result is that many fail well before their design life and some components require continual relining throughout their life to keep corrosion to a manageable level.
12.3 So where does API 652 fit in?
If you were to put together a document to try to address the problems described above you would have to:
List the problems that cause linings to fail.
Decide ways to minimize them, particularly relating to pre-cleaning and application.
Specify some basic guidance on lining choice and types.
Ensure QA procedures and record systems were put in place to check the job was done properly.
Recommend regular inspections.
Eventually, after consulting various people and bodies (and listening to shiny presentations from lining technical sales teams), you would end up with something that looks surprisingly like API 652.
12.3.1 The contents of API 652
Figure 12.1 shows the contents list of API 652. It is a short document of 15–16 pages providing a fairly generic introduction to the subject of tank linings. It contains mainly text and tables with a few figures. There are no calculations. The chapter headings are in a logical order, starting with explaining why bottom linings are required and then progressing through lining selection, surface preparation, application, inspection and repair.
Figure 12.1 The contents of API 652
12.3.2 API 652 section 3: definitions
There are a few definitions here that are specific to US and API codes in particular. Watch out for them in exam questions:
An anchor pattern (API 652 definition 3.4) is the strange name given to a surface profile (or roughness) before the lining is applied. It is achieved by shotblasting and looks absolutely nothing like an anchor.
A thick-film lining (definition 3.33) is one with a dry film thickness (dft) of 20 mils (0.020 in) or 0.51 mm or greater. These are frequently epoxy-based, have multiple coats or are reinforced with glass-fibre-reinforced polymer (GRP) fibres.
A thin-film lining (definition 3.33) is one with a dft of less than 0.020 in (0.51 mm).
A lot of chemical-based names appear in the definition list: adduct, amine, bisphenol-A-polyester, copolymer, iso phthalic polyester, polyamide, phenolic and a few others. Do not worry too much about these – their definitions say what they are, and they generally only appear in open book questions (and then not very often).
12.3.3 API 652 section 4: corrosion mechanism
For historical reasons, API 652 contains descriptions of a few of the corrosion mechanisms that can give rise to the need for a bottom lining in the first place. These supplement the more detailed descriptions provided in the main damage mechanism code API 571. There is nothing that contradicts API 571, just one or two additional points that are expressed in a slightly different way.
It lists:
Chemical corrosion
Concentration cell (crevice) corrosion under deposits or mill scale
Galvanic cell corrosion
Sulphate-reducing bacteria (SRB) corrosion
Erosion/corrosion
Fretting (rubbing) corrosion
Of these, SRB corrosion contains the most detail (API 652 (4.5)). It is caused by bacteria colonies depositing on the steel, resulting in concentration cell pitting or chemical attack caused by the reduction of sulphate to sulphide. This is a common mechanism found on petroleum tank bottoms and the lower shell area.
12.3.4 API 652 (section 6): tank bottom lining selection
This is a long section for API 652, containing a lot of generic information about the suitability, advantages and disadvantages of the three main types of lining: thin-film, thick-film unreinforced and thick-film reinforced. There is information contained in here suitable for both open- and closed-book exam questions. Figure 12.2 shows a summary of some of the more useful points, expressed in the form of a table. Remember that all this is mainly with reference to linings applied to the inside (product-side) of the tank bottom. Shells can be lined also, but API 652 is predominately about bottom linings, as its title suggests.
Remember that API 652 only provides generic information. There are several hundred proprietary coating system products available. These differ a lot in chemical content, longevity and price. Manufacturer’s datasheets for these products are freely available and contain excellent technical detail.
12.3.5 Preparation and application
Surface preparation by blasting is a critical part of the lining application procedure. Figure 12.3 shows the details. The required level is SSPC SP-5 ‘white metal’ finish, with the lower ‘near-white metal’ level SSPC SP-10 being acceptable in some situations. Equally as important is cleaning to remove surface containments, typically chemicals, common on items that have been in use in a contaminated environment. This is done using a combination of chemical cleaning,
Figure 12.2 Tank bottom lining selectionFigure 12.3 Surface preparation
steam cleaning and rinsing with demineralized water. Note the following important points:
Blasting should not be performed if the temperature of the steel surface is less than 37 ℉ (3 ℃) above dewpoint or if the relative humidity is greater than 80 %.
The profile ‘anchor’ pattern required is typically 0.0015– 0.04 in (38–102 μm) and should be sharp and angular.
Following on from surface preparation, API 652 (8.2–8.5) gives guidelines for the lining application process. These are useful practical points as linings are prone to peeling off in early service if they are not applied properly. Note the following, which are valid points for either open- or closed book exam questions:
Excess lining thickness, as well as insufficient thickness, can cause failure of linings (8.5).
Curing times and temperatures must be in compliance with the lining manufacturer’s datasheets (8.5).
Wet film thickness (wft) can be checked during application to standard ASTM D4414.
After drying, dry film thickness (dft) can be checked to standard SSPC PA2.
12.3.6 Testing of existing linings (API 652 section 10)
All newly applied and existing linings require visual examination to check for pinholes and areas of obvious low or excessive coverage. The most common procedure is the spark (‘holiday’) test. Figure 12.4 shows the details. A high voltage is applied between the parent metal under the lining and a wire brush or sponge passed over the top surface of the dry lining. Any pinhole or discontinuity in the lining (known mysteriously as a ‘holiday’) causes current to flow, resulting in a visible blue spark and audible alarm.
Figure 12.4 Holiday (spark) testing of linings
Thin-film lining tests normally use a low voltage (67.5 V) supply and a wet sponge detection technique. Thick-film reinforced linings can use as high as 20 kV. The lining manufacturer’s datasheet will specify the correct voltage to be used. Insufficient voltage will not detect fine pinholes, whereas excessive voltage may actually break down weak areas of lining, causing additional discontinuities that were not there before.
Controversially, API 652 (10.5e) says that holiday testing is typically not recommended for linings that have been in previous service ‘since the pressure of moisture in the film can cause damage when exposed to the voltage’. Some lining manufacturers believe their lining specification have superseded this problem – but they do not write the API exam questions.
12.4 European surface preparation standards
In Europe, most industries use grades of metal shotblasting preparation based on the Swedish standard SIS 055900. This specifies the ‘SA’ shot blast grades, of which the most commonly used are:
Grade SA-3. A pure ‘white’ finish (a near-perfect blasted finish with no tarnish or staining).
Grade SA-2 1/2 . An ‘almost perfect’ blasted finish, but one that allows a minor tarnish or stained appearance. This grade SA-2 1/2 is the most common grade specified for preparation for painting and linings. It is much easier and cheaper to achieve than grade SA-3, which would be uneconomic for most utility steelwork, tanks and vessels.
Grade SA-2. A ‘thorough blast finish’ that still has significant surface staining and contamination. This is considered a slightly substandard surface finish that is not suitable as a base for paints or linings. .
Grade SA-1. A ‘light blast cleaning’ that still has significant surface staining and contamination. This is considered a poor quality surface finish that is not suitable as a base for paints or linings.
API codes do not use these grades. Instead, they use those grades specified by the US Society for Protective Coatings (formerly the Steel Structures Painting Council), known generically as the SSPC grades. These work to the same principles but instead of an SA grade, they are given as an SP grade. The conversions are broadly as follows:
SA grade (used in SSPC SP grade (used by API Europe) codes and in the USA)
SA-3 White metal finish SP-5 SA-2 1/2 SP-10 SA-2 SA-1 No equivalent Power tool cleaning to bare metal SP-11 No equivalent Water-jetted finish before relining SP-12 No equivalent Solvent-cleaned finish SP-1 Section 7 of API 652 specifies the surface grades required for preparation prior to lining. Note how they compare to the grades, and their European comparisons shown above. These comparisons are shown for understanding only; API exams will only mention the SSPC SP grades, not the European SA grades.
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API 653 Exam Chapter 11- Hydrostatic Testing and Brittle Fracture
API inspection codes in general have a strange love–hate relationship with hydrotesting. Storage tanks are no exception – on one hand API 653 explains how and when it should be done, but this is followed up by a long list of valid scenarios for exemption. Unlike pressure equipment items, the underlying message is that (excluding new or fully reconstructed tanks) a hydrotest on a storage tank is something that you choose to do, rather then being forced to do so by API 653.
11.1 What is the subject about?
Code coverage and API exam questions are in surprising agreement on their coverage of hydrotesting. They are concerned with:
WHY you would want to do a hydrotest.
WHEN it is necessary (and when you do not need to bother).
HOW the test is done, once you have decided to do it.
Hydrotesting fits well into the API exam question mix because of the way that coverage is spread around several of the codes in the API 653 body of knowledge (BOK). It is covered in API 653 (12.3), API 650 (7.3.6) and also has links to the brittle fracture section of API 571. The following list of hydrotest-related subjects can be shoe-horned into exam question format:
Allowable stress (S) levels. A tank scheduled for hydrotest must have a higher allowable S value than one which is not, to accommodate the increase in hoop stress caused by the water compared to its normal oil product (see Fig. 6.5 of this book).
Responsibilities, i.e. who decides if a hydrotest is required in various repair/alteration scenarios. .
Exemptions, and when they are allowed. This fits together with the question of responsibilities and who decides what.
There are enough basic principles, specific code clauses and data tables here to feed both open- and closed-book-style exam questions. That is why they regularly appear.
11.2 Why? The objectives of a hydrotest
Neither API 653 nor API 650 go into much detail but, simplistically, a hydrotest is:
A code test for leaks and .
A strength test (of sorts) plus .
A chance for brittle fracture and excessive foundation settlement to happen, if they are going to.
It can never be a full test of fitness for service, because in reality there are lots of defects and problems that a hydrotest will not discover. Water is not good at finding its way through very fine cracks, for example, and welds in some locations can contain huge internal defects without the remotest chance that they will result in structural collapse of the tank during a static-head-only hydrotest. This is well understood, which is why API 653 section 12 lists hydrotest as only one type of NDE, among all the other (ASME V) techniques used.
Perhaps the most agreed objective of hydrotesting a tank is to check for excessive foundation settlement on tanks laid directly on a soil, sand or rubble base, i.e. without a full concrete base, or at least a concrete ringwall installed under the shell.
11.3 When is a hydrotest required?
This is straightforward.
A hydrotest is only mandatory for:
A newbuild tank: API 650 (7.3.6)
A reconstructed tank: API 653 (12.3.1)
A hydrotest is required for a tank that has undergone major repairs or major alterations (API 653 definition 3.18) but it can be exempted if:
Firstly it has been agreed by a tank design engineer and the owner/user (12.3.2.2a and b). and then, either
It passes an FFP (fitness-for-purpose) assessment. or
It meets a quite long list (nearly two pages of API 653 (12.3.2.3) to (12.3.2.6)) of criteria relating to material, type, thickness, stress and weld location.
For non-major repairs or alterations, a hydrotest is not required. It actually says this in API 653 (12.3.3.1).
Excluding new-build and reconstructed tanks then, where a hydrotest is mandatory, the answer to whether a hydrotest is required after a repair or alteration simply hinges on whether the repair or alteration is major or not, according to API 653 definition 3.18. If it is major then it requires a test unless it can qualify for any of the exemption routes above.
11.3.1 Why would you want to find an excuse not to hydrotest?
Because it requires a large amount of treated water, which then has to be legally disposed of, meeting environmental standards, etc. It takes a lot of time, is expensive and the tank may have to be cleaned and dried out afterwards. Coupled with this it is only a partial test of fitness for service of a tank and other NDE techniques are better at finding fine defects. Hydrostatic Testing and Brittle Fracture 199 This goes a long way to explain why API 653 allows exemption in many cases.
11.4 Avoiding brittle fracture API 653 does not set out to be a textbook on brittle fracture – it does not even warrant a separate mention in the definitions section 3. That is fine, because the mechanisms of brittle fracture are more than adequately explained in API 571 along with its appearance, prevention and mitigation options. What API 653 (section 5) does do is set out a well-rehearsed methodology of preventing the specific occurrence of brittle fracture on storage tanks. In many cases this is set against a scenario of the tank or its operating condition having changed in some way with the potential of increasing the risk of brittle fracture, causing wholesale fracture of the shell, with the release of all the contents.
11.4.1 What causes increased risk of brittle fracture?
Four things:
Brittle material. Many cheaply produced materials lack toughness (tough is the opposite of brittle). This is actually the result of low ductility (because ductility and toughness are not precisely the same thing).
Thickness. The thicker a material section is, the more brittle (less tough) it is. Strange but true. Lots of textbooks will explain this to you if you need to know why.
Temperature. Simple steels get more brittle as they get colder. Effects vary with the specific material but 7–10 8C is used as a rough benchmark for a temperature below which brittle fracture (rather than ductile failure) may become a risk.
Stress. All failures need to be caused by stress of some sort. Brittle fracture is more likely at higher stresses. Simplistically, dynamic impact-induced stresses are the worst although more statically induced membrane stresses can also cause it, particularly during fast product filling or unexpected wind or seismic loadings.
Figure 11.1 The reasons for brittle fracture
These four factors can act singly or in combination (see Fig. 11.1) so measures need to be in place to restrict them all, to keep the chance of brittle fracture low.
11.4.2 When does API 653 section 5 worry about brittle fracture?
API 653’s views owe more to accumulated experience and intuition than advanced metallurgical theory – proven or otherwise. Clause 5.2.2 sets out four scenarios where it may happen and then the rest of section 5 goes on to describe a methodology to assess which you have. It is best to accept API’s view of this, whether you think it is oversimplified or not, because it forms the basis of their exam questions. API 653 (5.2.2) says that you should be worried about the risk of brittle fracture if a tank is being:
Hydrotested for the first time.
Filled for the first time in cold weather.
Changed to a service (product, site environment or both) where it will see a lower temperature than previously.
Repaired, altered, or reconstructed.
Conversely, if a tank is not in one of these four scenarios it is reasonable to expect that the risk of brittle fracture is minimal.
11.4.3 If there is a risk, what do you do?
Easy, do a hydrotest. If the tank passes without fracture, then its ‘brittle fracture integrity’ is proven and the problem has effectively gone away, even if the remainder of the scenario conditions are still there. Now you can see the main purpose of API 653 section 5 – to provide a methodology to decide whether or not you need to do an ‘enforced’ hydrotest, to prove a tank’s resistance to brittle fracture.
11.5 Is a hydrotest needed? API 653 flowchart (Fig. 5-1)
In common with many other API documents, API 653 expresses decision-making activities in the form a flowchart (see API 653 Fig. 5-1). You either like flowcharts or you do not. This one is very easy – it just looks complicated on first viewing – see Fig. 11.2 here which is a simplified version. The full API 653 Fig. 5-1 version has 11 steps, each of which is actually explained in the text of section 5.3.
Starting on the left of the flowchart, the objective is to spend as little time on the flowchart as possible by taking the first possible exemption from doing a hydrotest that you can.
Figure 11.2 The ‘hydrotest exemption’ flowchart
Failure is indicated by being unable to escape from the flowchart before arriving in disgrace at the right-hand end, where the only real practical option is to do the hydrotest, to prove that brittle fracture will not occur. The exemptions available in the flowchart are all based on API code experience – and support the idea that there is no advantage to be gained from doing a hydrotest if you really do not need to.
If you prefer things to be presented another way, then the list below shows all the exemptions. So there is no need to do a hydrotest if you can meet any one (not all) of the following criteria:
The tank was built to API 650 7th edition or later, so the material will be sufficiently tough (non-brittle). or .
It has already been hydrotested, and did not fail then. or .
The shell plate is 1/2 inch thick or less. or
It will not see temperatures lower than 60 ℉. or
It will not see hoop stresses greater than 7000 psi. or
The material is shown as exempt (by API 653 Fig. 5-2 if the grade is unknown or API 650 Fig. 4-1 if the grade is known). If you look at this figure in API 650 (see chapter 7) you will see how some grades of steel can keep their tough (non-brittle) characteristics down to beyond -30 ℉, but you need to be able to confirm that the material grade is the correct one. or
Figure 11.3 Tank hydrotesting
The tank has already been proven safe, when full at the lowest one day mean average temperature (LODMAT) for the geographical area where it is located (see API 650 Fig. 4-2).
If a tank cannot meet any one of the above criteria, you need to do a hydrotest. Figure 11.3 shows some important technical and procedural points.
11.5.1 Exam questions?
Yes. The API 653 exam regularly contain questions on both the generic API 571 aspects of brittle fracture and the tank specific aspects from API 653 and 650 explained above. Expect both open- and closed-book variants. The split may appear a bit random, but the questions themselves are normally fairly straightforward.
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Strangely at odds with the sensible idea that a storage tank can be heavily repaired throughout its life lies the subject of tank reconstruction. This is the wholesale dismantling of a tank into a large number of transportable pieces and then reassembling them somewhere else, on a completely different site. Opinions differ on whether this is all worth the bother. It is a labour intensive exercise and many countries with high labour rates would not find it economic – it would be cheaper to build a new one.
Technical practicality plays a part in the decision – it can be physically awkward getting the disassembled parts to fit, particularly for larger tanks. The state of corrosion can also cause problems – additional corrosion is often discovered during disassembly, requiring repairs before reassembly of the parts. Old, large tanks are the biggest risk.
Notwithstanding the practical and cost uncertainties, tank reconstruction is clearly a viable option in those countries that do it, so it is a long-standing part of API 653, with specific technical principles. It is also a valid topic for API 653 exam questions.
10.1 Code requirements for tank reconstruction
Unlike repairs, tank reconstruction is considered a ‘build as new’ activity. In most cases this turns into a ‘build better than new’ activity as one of the fundamental requirements is that reconstruction activities must be done to the ‘current applicable standard’, i.e. the code edition relevant to when it is reconstructed, not the old one to which it was originally built. This applies only to all new material, components, welding and NDE used during the reconstruction. Existing materials, components and welds that are not reworked can remain as they are, to the as-built standard. Figure 10.1 summarizes the situation.
Figure 10.1 Reconstructed tanks: which code?
The main code requirements for reconstruction are found in three places:
Section 8 of API 653 covers design consideration for reconstruction tanks. This is a one-page section setting out the relevant code-compliance requirements as described above.
API 653 section 10: Dismantling and Reconstruction is a longer section covering the procedures of dismantling the tank and putting it back together again. The dismantling bits (10.3) are unique to API 653 because they are not covered in the construction code. The reconstruction requirements (10.4) are practical additions to the construction code (API 650) – mainly about welding acceptance criteria and broad dimensional tolerances for the rebuilt tank.
API 650, the construction code itself, contains the most detailed information. This drives the technical detail of the reconstruction, reinforcing the principle that reconstruction is a new-build activity rather than a repair or alteration one. There are other non-API construction codes, which is why API 653 is careful to refer to the construction codes in generic terms rather than exclusively to API 650. Such niceties do not extend to the API exam – construction code questions will all be about API 650.
10.2 Reconstruction responsibilities
API 653 does not make such a well-defined split between the meaning of the words approval and authorization, as do API 510 or API 570 relating to pressure vessels and pipework. The inherent meanings of the words (as decided by API), however, are the same, as follows:
Approval means approval of a design procedure method or way of doing something, independent of whether the activity has started or not. It can also apply to accepting some work or activity that has finished (i.e. agreeing it has been done properly).
Authorization means authorizing an activity to start.
You can see these words in action in API 653 (10.1.4), although they are not defined for you. One long-standing controversial area of API ICP exams is the large number of questions about personnel responsibilities and their relevance to inspection practice outside the USA. Like them or not, Fig. 10.2 shows what they are for tank reconstruction. Note
Figure 10.2 Reconstruction responsibilities
how the API inspector alone can approve not only hold points and the extent of the completed tank document package but also authorize reconstruction work to start and approve its completion. The tank engineer therefore has no mandatory role in reconstruction. That is all there is about reconstruction responsibilities in API 653.
10.3 API 653 section 10: structure
Section 10 is split logically into dismantling (10.3) and reconstruction (10.4) activities. These subsections provide parallel coverage for the main components of the tank: bottom, shell and roof. The main issue of both dismantling and reconstruction is the objective of avoiding cracking in the reconstructed tank welds. The first part of achieving this is to ensure that parts of old existing welds are not left in place to interfere with new reconstruction welds causing local carbide concentrations and the risk of cracking. Much of section 10.3 is centred around this objective. Note particularly how:
Bottom plates must be cut a minimum of 2 in away from existing bottom seam welds (10.3.2.1) and 1/2 in away from the shell-to-bottom fillet weld (API 653 Fig. 10-1).
If the entire tank bottom is to be reused it must be cut a minimum of 12 in from the shell-to-floor junction, leaving the shell with the remaining part of the bottom still intact (API 653 10.3.2.2b and Fig. 10-1).
Shell plates must be cut a minimum of 6 in away from existing shell seam welds (10.3.3.1c) and 1 2 in up from the shell-to-bottom fillet weld (Fig. 10-1 again).
Roof plates must be cut a minimum of 2 in away from existing roof seam welds.
Figure 10.3 summarizes the content of API 653 Fig. 10-1 and some of its referenced sections. This is a common source of open-book exam questions. It is difficult to write an awkward question on this – so they are normally straightforward, just requiring you to read various minimum dimensions from the code Fig. 10-1. Easy.
10.4 Reconstruction (10.4 and 10.5)
This is simply a case of welding the cut parts back together again in a way that avoids brittle fracture, cracks or other integrity-threatening defects (10.4). In addition the completed tank has to meet a set of dimensional tolerances (10.5) on inclination (plumbness), roundness, peaking and banding in order that it does not suffer from excessive ‘out of design’ stresses in use.
Given that tank reconstruction is essentially a new construction activity, these sections of API 653 section 10 are based on the straight requirements of API 650, with a few
Figure 10.3 Tank dismantling options: API 653 (10.3)
additional practical aspects thrown in for good measure. Salient points are:
Weld spacings have to be maintained with a minimum 5t stagger on shell plate vertical joints (10.4.2.1).
Preheat of weld joints is necessary in cold climates. The preheat temperature depends on thickness (10.4.2.3):
Below 0 ºF, no welding is allowed.
0 ºF to 32 ºF on thickness > 1 in, preheat to 140 ºF.
Thickness > 1 1/2 in, preheat to 200 ºF (10.4.4.3).
Weld maximum undercut (as per API 650) and reinforce
Figure 10.4 Some important reconstruction requirements
ment limits (API 653 Table 10-1) apply. This is to avoid stress concentrations and crack initiation points.
Figure 10.4 above summarizes some of these important points. Note how they are mainly about the shell plates.
10.4.1 Use of low hydrogen welding rods
Most API codes are in agreement that whenever welding is carried out under any type of non-optimum conditions (e.g. on site), it is best to use low hydrogen welding rods. This minimizes the risk of cracking, caused by hydrogen molecules expanding in small discontinuities (such as grain boundaries) and progressively weakening the structure. Couple this with heating and cooling and you get cracks. Both API 571 and 577 (both in the API 653 body of knowledge) address hydrogen cracking and its prevention, so the subject almost always appears as (several) exam questions in one form or another.
Figure 10.5 shows the major issues relating to avoiding hydrogen cracking. Note how these are taken not only from API 653 section 10: Reconstruction but also from section 11: Welding.
Figure 10.5 The importance of low hydrogen welding rods
10.4.2 Reconstructed tank dimensional tolerances in API 653 (10.5)
In engineering terms, atmospheric storage tanks are large, rather floppy structures that do not take well to dimensional inaccuracies. The activity of reconstructing accurately an old tank after dismantling it can be difficult – it may be a slightly different size due to cutting, rejection of old weld seams, etc., and the old plates are frequently distorted, damaged during transport, or weakened by corrosion. The main problems usually occur with the shell. Excessive shell distortion has two effects:
Sticking roofs. Shells usually distort more near the top of the tank. This causes floating roofs to either stick or leak past the seals, letting vapour out and rain in.
Excessive stress. Tank shells are designed to the simple hoop membrane stress equation, which works on the assumption that the shell is round and of uniform (plane) section over its height, within certain tolerances. Any distortion that takes a shell outside this idealized shape causes stress to rise, indeterminately. This gives an increased risk of failure at almost any area of stress concentration, such as weld undercut or excessive weld cap convexity. API 650 (10.5) sets dimensional tolerances to try and avoid these problems.
10.4.3 Foundation tolerances
Uneven foundations will cause distortion in an otherwise accurate shell. Tolerances are specified by API 653 (9.10.5.6), depending on whether the foundations include a concrete ringwall (an annular concrete foundation ring on which the shell sits).
10.4.4 Shell tolerances
There are four of these: plumbness, roundness, peaking and banding. All can cause problems if excessive, and things get worse if they act together.
Plumbness (10.5.2) is simply inclination or out-of-verticality. The limit is 1 in 100 to a maximum of 5 inches (see 10.5.2.1). . Out-of-roundness (10.5.3) is the measured deviation of the shell shape from a true circle. Simplistically it is the difference between the minimum and maximum measured diameter. It causes bending stresses, which are not allowed for a simple hoop (membrane) stress design theory. As out-of-roundness (OOR) generally gets worse higher up the tank, it is measured in two places: 1 foot above the bottom as a reference and then higher up as required.
Peaking. This is distortion along the longitudinal (vertical) weld in the shell. It is mainly initiated by material rolling and/or welding stresses during new construction. Occasionally it can get worse in service.
Banding. Banding is similar to peaking but involves distortion around the circumferential (horizontal) shell welds rather than the vertical ones. It is less common and almost always the result of construction (or repair/ alteration/reconstruction) inaccuracies.
Figure 10.6 shows the tolerances allowed for these features in reconstructed tanks. Being large-dimension related, they require specialized equipment to measure accurately. The usual method is via laser measuring equipment, although API 653 refers to the older, but still effective, method of using plumblines and long ‘sweepboards’ made out of light wooden planks or aluminium strips.
The dimensional tolerances above are checked before the hydrostatic test on a reconstructed tank (10.5.1.2). Remember that tank reconstruction is the only situation after new construction where a hydrostatic test is truly mandatory to comply with API 653 – look back to API 653 section 12 and you can see it specified in 12.3.1a. Settlement measurements are also taken as per API 653 section 12.5 if there is any doubt about the strength or rigidity of the tank foundations.
Figure 10.6 Tolerances for reconstructed tanks
10.4.5 Tank reconstruction: API 653 versus API 650
Fundamentally, tank reconstruction is considered a new build activity. Remember that all new welding activity is treated as exactly that, as if it were being done on a completely new tank – with the requirement to follow the construction code API 650. In its role as an in-service code, however, API 653 is allowed several overrides to cater for site practicalities, while still providing a tank of sufficient structural integrity.
10.4.6 Reconstruction and other related codes
For the purposes of the API 653 examination (and practically as well), other codes also play their part in reconstruction activities. NDE is covered by ASME V and welding qualifications by ASME IX. Exam questions are rarely detailed enough to examine these links in any great depth – they are more likely to be either an API 653-specific question about reconstruction design or procedures, or very generic questions (unrelated to specific new-build/repair/alteration/ reconstruction activities) picked verbatim out of the wording of ASME V or IX, not both.
Now try these practice questions.
10.5 API 653 section 10: dismantling and reconstruction: practice questions
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API 653 Exam Chapter 9 – Tank Repairs and Alterations
Overall, a lot of the storage tanks in the world are in a bit of a mess. Here are the reasons why:
Poor maintenance. Tanks are easily forgotten when allocating maintenance budgets to higher priority parts of a plant. They are often seen as being less processcritical. Access is also difficult – external inspection/ maintenance requires scaffolding or mobile cranes.
Long lifetimes. It is not unusual for tanks to be 50 or more years old.
Multiproduct use. Changing process conditions leads to unpredictable (frequently unknown) corrosion rates.
Construction standards. Although tank construction codes (particularly recent ones) are technically consistent in themselves, tanks are hardly high technology items. Most are made from corrosion-prone low carbon steel. They are simple utilitarian fabrications, rather than cutting-edge engineering structures, which is reflected in their low price.
Environmental conditions. A lot of tanks are situated in dirty or marine environments. Once the external painting starts to break down, corrosion occurs quickly. It is worse if the external surfaces are lagged.
The result of all this is that most storage tanks end up needing a lot of repairs during their lifetime. These can range from small patches or replacement plate inserts through to replacing complete tank bottoms, shell courses (or ‘strakes’) or roofs. Some of these do little for the cosmetic appearance of the tank, but are perfectly technically viable – and cheaper than buying a new tank.
9.1 Repairs or alterations?
API in-service inspection codes are well known for their differentiation between repairs and alterations. They contain the definitive opinion that repairs and alteration are fundamentally different things. The rationale behind this is:
Alterations involve some kind of ‘new’ design aspect (for the tank in question) that needs to be considered. Repairs do not.
Because of the ‘new design’ aspect of alterations, technical details need to be approved and the work authorized to proceed by someone with the necessary knowledge. API certified inspectors are not always expected to have this knowledge. Some higher technical authority (a qualified ‘engineer’) has to have the final word.
Fortunately API 653 is more logical than some other codes as to the difference between repair and alterations. This is then qualified by dividing each into ‘major’ or ‘non-major’ categories, i.e. major repairs and major alterations. Note that the code does not actually classify the opposite of major repair or alteration as minor or ordinary. It just infers that they are ‘not major’. Wonderful.
Here are the key points:
A repair (non-major) is an activity used to fix some corrosion or similar problem to return a tank to a safe operating condition. Nothing is added and there is no significant design implication (API 653 definition 3.2.4).
A major repair is a repair (as above), but of a type specifically stated in API 653 definition 3.18, i.e.: .
Removing and then replacing a shell plate of longest dimension more than 12 in situated below liquid level.
Removing and then replacing annular ring material with the longest dimension more than 12 in.
Removing and then replacing more than 12 in of a vertical shell plate weld or annular plate ring radial weld located anywhere in the tank.
Removing and replacing a significant amount (>50% of weld) of the shell-to-bottom/ring weld.
Jacking up the tank shell to renew the complete tank bottom.
An alteration (non-major) is some change or addition that changes the tank’s physical dimension or configuration (definition 3.1).
A major alteration is an alteration (as above) that specifically involves:
Installing a new shell penetration >NPS 12 below the design liquid level (NPS is nominal pipe size).
Installing a new bottom penetration within 12 in of the shell.
Figure 9.1 shows the situation in pictorial form. Once you have accepted the principle of this repair versus alteration differentiation then the major versus non-major split fits in fairly naturally with the integrity implications of the activity. Repairs or alterations designed as major have a higher risk of leak or failure consequences if not done correctly. Figure 9.2 shows the responsibilities for approvals and the hydrotest requirements.
9.2 Hydrotest requirements
API 653’s view is that ‘non-major’ repairs or alterations are not important enough to warrant a mandatory hydrotest. Owners/users can of course perform one if they wish but it is not a code requirement. For major repairs or alteration then a hydrotest is required by section 12.3.1b of API 653. Even this, however, can be overridden by either:
An FFS assessment (API 653 section 12.3.2.7) – the exact type of which remains undefined.
Complying with the relevant exemption clauses chosen from API 653 sections 12.3.2.3 to 12.3.2.7. This is a rather long list but, in summary, simply says that the major repairs/alteration meet the requirements of:
Figure 9.1 Major repairs (MR) and major alterations (MA): API 653
Putting aside the minutiae of code clauses for the moment, you can see that API 653 does not actually impose a mandatory hydrotest for any repairs or alterations at all. It is
Figure 9.2 Approval and hydrotest requirements
mandatory for dismantled and reconstructed tanks (see API 653 section 12.3.1a) because this is similar to new construction activity. It therefore has to comply with the construction code API 650 as if it were a new tank, required to prove its integrity before use.
9.3 Repair and alterations – practical requirements
Section 9: Tank Repair and Alterations is one of the longest sections of API 653. From an API exam perspective also, the subject is important; repair and alteration-related topics can form up to 30–35% of the total haul of exam questions. Most of these have a practical engineering aspect to them involving design, welding, testing or responsibilities rather than any deeply theoretical considerations.
Figure 9.3 shows the breakdown of the section. Note how it divides logically into activities involving shell plates,
Figure 9.3 Tank repairs: the breakdown of API 653 section 9
penetrations (i.e. nozzles), bottoms and roofs. Detailed technical requirements cover all these areas – related to either repairs or alterations, as applicable. Throughout the sections, some common principles apply:
Minimum and maximum repair sizes and thickness
Allowable repair location
Weld locations, types and sizes
Methods of avoiding local hardness, leading to cracking and brittle fracture
We will look at these in turn, concentrating on those areas that feature heavily in the API exam questions.
9.3.1 Are these repairs temporary or permanent?
They are all permanent. Unlike pressure vessels, where some types of repairs have to be considered as temporary, storage tanks can be permanently repaired using fillet-welded ‘lap’ patches. They may not look particularly attractive, but they provide perfectly adequate strength and integrity against leaks. Non-welded repairs such as epoxy filler, wraps, clamps, etc., do not feature significantly in API 653 – there are a few references in API 575 but little technical detail. Welded repairs are clearly preferred, where possible.
9.3.2 The basics of code compliance
Fundamentally, tank repairs and alterations have to comply with the tank construction code API 650. Practically, however, API 650 does not cover most repair configurations, so API 653 section 9 takes over with the required technical detail. The principles are similar, although API 653 allows extra leeway in some areas, to allow for the realities of site fabrication work.
9.4 Repair of shell plates
Repair of shell plates comprises two types:
Replacement plates, where plates are cut out, normally because of corrosion, and a new replacement ‘insert’ plate is butt-welded in its place. These are covered in API 653 section 9.2.
Lap-welded patch plate (API 653 section 9.3). Here, a plate is fillet (lap)-welded over the top of a corroded (not cracked) area to restore the thickness and strength of the tank shell.
Both of these types are considered permanent repairs and the code clauses specify limitations on plate size and shape, allowable weld locations and design features related to them.
Engineering details of replacement shell plates are shown in API 653 Fig. 9-1. The main details of this are reproduced in Fig. 9.4 here – note the additional annotations taken from the subsections of API 653 (9.2).
API 653 section 9.3 covers similar restrictions for lap welded patch plates. There is no code figure for this – all the requirements are listed in the multiple subsections of 9.3. Figure 9.5 below summarizes the main requirements – note the limits on minimum and maximum overlap and the similar size restrictions to those for butt-welded replacement (insert) patches. Lamination checks of the parent plate before welding are important – UT checks for parent plate laminations are therefore required by API 653 (9.3.1a).
Figure 9.4 Replacement shell plates: API 653 section 9.2 and Fig. 9-1Figure 9.5 Shell lap patches: API 653 section 9.3
9.4.1 Repairing shell plate defects (9.6)
It is much easier to repair defective welds on shell plates in situ than to replace them or apply a lap-welded patch plate. As long as the minimum required plate thickness is maintained, corroded areas can be blended by grinding or blended and weld-repaired as need be. The requirements are fairly commonsense:
Cracks, lack of fusion and slag must be ground out completely before rewelding.
Excessive undercut in excess of API 650 limits needs to be removed by blending and rewelding if required (for plate ≤13 mm it is maximum 0.4 mm on vertical welds and 0.8 mm on horizontal welds).
Weld arc strikes must be removed as they cause stress concentrations.
9.5 Shell penetrations
There are three main things you can do with tank shell penetrations (nozzles or access manholes) .
Repair them (9.7)
Replace or add new penetrations (9.8)
Alter existing penetrations (9.9)
9.5.1 Repair of penetrations (9.7)
This is generally about adding of reinforcing (compensation) plates to existing nozzles. The reasons for needing to do this would be:
An increase in tank maximum fill height or product specific gravity, meaning that existing nozzles near the bottom of the shell require additional compensation.
The shell around existing nozzles is corroded (on either the inside or outside of the tank), so shell strength in that region needs to be restored.
Figure 9.6 shows the main technical requirements of adding these reinforcing plates to existing nozzles. Note the ‘tombstone’ plate fitted when the nozzle or manway is near the bottom of the tank (which they usually are). As you can see from the figure, the main issue is the minimum fillet weld (leg) size between the bottom of the tombstone plate and the bottom annular ring. Note how the nozzle-to-reinforcing plate weld is the same for the tombstone plate as for a reinforcing plate that does not extend all the way to the floor. The plate-to-floor weld is smaller.
Watch out for open-book exam questions about this section of the code – particularly about the optional horizontally split reinforcing plate and the positioning of the vent/tell-tale holes.
Figure 9.6 Adding reinforcement to existing nozzles
9.5.2 Alteration of existing shell penetrations (9.9)
This is about the effects of installing an additional tank bottom on top of an existing corroded one. The additional bottom is normally added either directly on or an inch or two above the existing one, with a layer of cushioning material such as sand or crushed stone in between the two. This causes the new bottom-to-shell weld to be raised up nearer the lowest shell nozzles reinforcing plate, frequently reducing the weld spacing to below the minimum distance required. Section 9.9 gives three solutions to this:
Figure 9.7 Altering existing penetrations
Trim the bottom of the existing nozzle reinforcing plate, as long as there is still adequate reinforcement available (as per the API 650 calculation, section 9.9.2.1).
Remove the existing reinforcing plate and replace with a new one (9.9.2.2). Sometimes it is possible to just replace the bottom half, leaving the top half in place.
Move the offending nozzle and its reinforcing plate upwards, increasing the spacing to the shell-to-bottom weld.
Figure 9.7 summarizes these three methods. As most of the technical detail is about weld spacing and sizes, these are normally only suitable for open-book exam questions. It is difficult to construct sensible closed-book exam questions from this topic.
9.6 Adding an additional bottom through an existing tombstone plate (9.9.4)
API 653 (9.9.4) is, arguably, a special case, where an additional bottom is added through an existing tombstone reinforcing plate. This is a rather complex new code section –a bit too involved for more than the occasional open-book exam question. The basic idea (see Fig. 9-6 of API 653) is that the lower edge of the tombstone plate is cut and bevelled to allow it to be welded into the new fillet weld added between the existing shell plate and the new bottom. This is then ‘backed up’ with an additional fillet weld on that.
9.7 Repair of tank bottoms
Tank bottoms can corrode from either the product side or soil side, so bottom repairs are a common occurrence, particularly on old, multiproduct tanks without cathodic protection. Similar to shells, bottoms can be permanently repaired using individual fillet-welded lap patch plates. Alternatively, if corrosion is very widespread, a complete new bottom can be fitted, usually directly on top of the existing one, unless there is some pressing reason for removing it.
9.7.1 Patch plate bottom repairs
API 653 Fig. 9-9 contains all the necessary information about what you can and can not do when doing bottom patch plate repairs. Figure 9.8 below shows some of the major points. Note how:
Minimum patch plate dimension is either 6 in or 12 in, depending on whether it overlaps an existing seam (9.10.1.1b).
Patch plates may be almost any shape or maximum size.
Minimum spacing distances have to be met to avoid HAZ interaction causing local hardening and cracking problems.
Special restrictions apply in the critical zone (the annular area extending 3 in in from the shell)
9.7.2 Repairs in the critical zone
The critical zone (API 653 definition 3.10) is the annular area of the tank bottom extending 3 in in from the shell. For tanks fitted with an annular ring, the critical zone is part of the
Figure 9.8 Patch plate bottom repairs
annular ring, but generally not all of it. The reason for separately identifying the critical zone is that it sees high bending stresses if foundation washout or distortion causes edge settlement. This bending would have a tendency to tear apart the shell-to-bottom fillet welds, as they have little strength. Stresses increase with small radial lengths and large vertical deflections, so repair restrictions are put in place to limit this.
Figure 9.9 shows typical restrictions on patch repairs.
Figure 9.9 Patch plate repairs in the critical zone
9.7.3 Repairing pitting in the critical zone (9.10.1.6)
Pitting can be repaired by overlay welding as long as the parent material underneath is not less than 0.1 in thick. The usual 2 in in 8 in cumulative maximum applies (the definition of isolated pitting), but in this case the plane in which this is calculated is on an arc parallel to the shell. This is the plane on which shear stress acts on the bottom plate if there is any foundation washout around the tank or circumference.
9.7.4 Replacement of tank bottom (9.10.2)
Full bottom replacement is a major exercise, used when the tank bottom is so severely corroded that wholesale replacement is the most practical option. This section really refers to replacing all the bottom plates, but while leaving the annular ring (with its critical zone) in place. Figure 9.10 shows the idea.
Note how Fig. 9.10 shows the definition of this activity as a repair, not a major repair or an alteration. In a fit of logic, API 653 definition 3.18(f) says:
Replacement of a tank bottom is not classed as ‘replacement
Figure 9.10 Replacing the tank bottom
of a tank bottom’ if the annular ring remains unaffected. You may need to read that again.
This means that it is classed as a straightforward repair without the requirement for a post-repair hydrotest.
Replacement of the tank bottom is predominately an exercise in complying with the construction code API 650. There is also a list of API 653 requirements (in 9.6.2) that override this, as they specifically refer to repairs. They are:
Sand/gravel cushion material is required between the existing and new floors (9.10.2.1.1). .
Penetrations may need to be raised to maintain minimum spacings above the bottom-to-shell weld (9.10.2.1.4 and 9.10.2.4).
For convenience, the activity of ‘replacing a tank bottom’ is normally done while leaving the existing bottom in place. API 653 sections 9.10.2.1.1 to 9.10.2.1.5 specifically cover this scenario, as the most popular option.
9.8 Repair of tank roofs
The repair of tank roofs is a fairly straightforward exercise, as long as you comply with the construction code requirements of API 650. API 653 does not have many preferences or overrides. This is probably more to do with the fact that tank roofs are little more than a simple plate structure under little stress, than any great technical philosophy. Looking at API 650 section 5.10: Roofs and appendix F you can see that they contain three types of information:
Calculation equations (which are not in the API 653 BOK).
Cross-references to other sections of API 650 (which are also not included in the BOK).
Limiting physical dimensions (minimum thickness, etc.) of roof plates and supporting components.
This self-limits the topics that appear as API 653 exam questions. A few questions appear about minimum thickness of roof plates or the roof-to-shell junctions, but they rarely extend further than that. You can expect these to be open book questions – easily picked out from section 10 of API 650. You can see some examples at the end of this chapter and Fig. 9.11 shows some corresponding points.
Figure 9.11 Repairs to roofs: API 653 (9.11–9.13) and API 650 (5.10)
9.9 Hot tapping: API 653 (9.14)
Hot tapping’ is the term given to cutting a new nozzle penetration into a tank when it still contains the product at its storage temperature (it does not need to be ‘hot’). This is a much quicker and less troublesome method than emptying and cleaning the tank in order to add the new penetration. It is a common procedure, normally performed without any mishaps, and also in pipelines and vessels, as well as storage tanks.
This API 653 section is a common source of exam questions. The hot tapping activity has specific requirements in nozzle reinforcement, weld size and testing in order to ensure that the design is strong enough and is completed without leaks or weld cracking. Note some key points about hot tapping a storage tank shell:
Hot tapping is always an alteration rather than a repair, as it changes the physical configuration of the tanks (API 653 definition 3.1).
If the new penetration is larger than NPS 12 then it becomes a major alteration, as hot taps are always installed below the liquid level (definition 3.18c).
Materials and stresses must be chosen to avoid brittle fracture.
The main issue during the installation is to avoid weld cracking, leading to leaks or fracture. This requires limitations to be placed on weld electrode type, weld spacings and weld joint type and size.
Figure 9.12 below shows how the hot tapping procedure is done. Note the steps of the operation:
1 The new flanged nozzle is welded to the tank shell, followed by the reinforcing (compensation) pad. 2 A valve is bolted to the flange and the tapping machine mounted on the other side of the flange (so the machine is isolated from the tank by the valve). The tapping machine
Figure 9.12 The hot tapping procedure: API 653 (9.14)
is fitted with glands, completely sealing the cutter and its driveshaft inside the fluid boundaries.
3 The valve is opened and the cutting head traverses through the valve, cutting the opening in the tank. A pilot drill and ‘catch wire’ arrangement holds on to the cut coupon, preventing it falling into the tank.
4 When the cut is complete the cutting head is retracted back through the valve, which is then closed, isolating the liquid so the cutting machine can be removed.
9.9.1 API RP 2201
API Recommended Practice RP 2201: Procedures for Welding or Hot Tapping on Equipment in Service is a detailed document covering the subject of hot tapping. It is very comprehensive, but the good news is that its content is not in the API 653 exam body of knowledge, so you do not need to study it. Knowledge of its existence, however, is an exam topic, as it is mentioned in the reference section of several of the API 653 subject codes.
9.9.2 API 653 (9.14) hot tapping requirements
This code section provides a good example of what API codes do best. Instead of bothering with too much technical detail of procedure, it just gets straight to those points that will have an influence on the integrity of the hot tapping penetration. This section 9.14 is valid examination question material. Most are open-book topics, but there are also several points of technical principle that make valid closed book questions
Figure 9.13 summarizes some key points. A lot of it centres around the requirement that hot-tapped nozzles require a reinforcement plate, which must be made from sufficiently tough material and then meet well-defined sizing and weld requirements. Penetration position is defined by the fact that it must be a minimum 3 feet below the liquid level (9.14.1.2) but not see sufficient static head pressure to cause a hoop stress of more than 7000 psi (9.14.1.1(4)).
Note how Fig. 9.13 summarizes key points of API 653 Fig. 9-10. This is a good concise figure summarizing a lot of technical detail, and a well-established source of API 653 examination questions.
9.10 Tank repair and alteration – other requirements
Remember that API 653 section 9 does not cover all the requirements of tank repair and alteration. Repair and alteration are fundamentally API 650 construction code
Figure 9.13 Hot tapping detail (see API 653 Fig. 9-10)
activities with the requirements of API 653 added to them, to cover the practical aspects of site work. This should become clearer when we look at the subject of tank reconstruction in Chapter 10. This is almost a purely API 650-based activity, treating the reconstruction as the same as building a new tank from scratch.
For the procedural aspects of welding and NDE of tank repair and alteration, ASME V, IX and API 577 provide more detail than API 653 itself. These therefore provide the source of exam questions of a more generic nature, e.g. related to other types of repair/alteration as well as hot tapping. We will cover them in separate chapters of this book. Exam questions tend to be fairly polarized, however, concentrating on one or the other, because that is how the questions are compiled.
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