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By Carlos F Molina


What we are going to do is to dissect the diagram in FIG. 4.1 of API653 until we truly understand it. and there will be no way we fail any of the questions related to this in the exam. First of all we are going to see the following diagram.


Look at the vertical sections drawn in the picture (Remember that hoop stresses (stresses that are tangential to the shell of the tank) are higher in vertical planes than in horizontal planes).

Corrosion can affect tank shells in many ways, as the standard says. In time, uncontrolled corrosion can weaken or destroy the tank´s shell, resulting in holes or possible structural failure, and release of stored products into the environment. But the most common seen form of damage is a “generally uniform loss of metal over a large area or in localized areas”. In an scheduled external inspection scenary, where you have to evaluate a tank shell, you will have to follow the procedure of of API 653 and figure 4.1.

THE PROCEDURE For determining the controlling thicknesses in each shell course when there are corroded areas of considerable size, measured thicknesses shall be averaged in accordance with the following procedure.

1. Calculate the minimum thickness t2 in the corroded area

2. Calculate the critical lenght L in which thicknesses “average out”, with one of the following formulas


3. Locate L, in several vertical planes that you think are more affected by corrosion, and measure at least 5 points to get t avg in each one of those vertical planes. One of those planes will have the lowest average thickness, that you should compare to tmin acording to the formulas in


Esentially, this procedure limits the size of the zone you are evaluating so it is not too big. This way the “averaging out” is a more realistic way of evaluating metal loss than the arithmetical average.

It is like they say in my homeland about the problem with statistics: “If I eat 2 chickens and you don´t eat any, then we both ate 1 chicken each”. Given that metal loss profiles can have very differente thicknesses, there is a need for a method to average the corrosion. That is what the standard is trying to avoid: a situation where the shell evaluation is too simplisitic. What I try to say is that smaller the thickness in any point, the smaller the zone were thicknesses average out, with 40inches limit as a maximum. After you have calculated the critical lenght, then you will have to take five measures in it and alculate the arithmetical media and compare it to the minimum allowable.


Usually, 4, 6 or 8 measurements of shell thickness are taken in several vertical lines comprising 360° in each course of the tank shell to fullfill the UT requirements of external inspection, although this has to be an agreement with the owner/operator. When using a tank crawler, usually you measure every foot on eight lines in the eight wind directions in the tank shell. This can be modified depending on the configuratio of the tank.

Remember that this procedure for shell evaluation is for localizaed corroded areas. For a complete shell plate, you will have to take UT measurements in the best agreement with the owner.


CUI was detected after the insulation of a tank was removed for inspection. It generated a corroded area away from vertical welds, in the bottom of the third course of the tank, which is in operation. The inspector took 5 UT measures along 3 vertical planes each, in the positions where he thought there was more corrosion, following the instructions in API 653, The authorized inspector shall visually or otherwise decide which vertical plane(s) in the area is likely to be the most affected by corrosion. His findings are illustrated in Fig 1. The product stored is crude oil with a specific gravity of 0.978. Corrosion rate is 0,5mm/year. Having in mind the average corrosion measured, is the tank safe to operate until next inspection due in 5 years? D= 15,24m. The third course is originally 12mm thick A36M steel. Maximum liquid level is 11,88m and courses are 8ft wide.


Figure 1. UT Measurements of a localized thinned area showing planes 1, 2 and 3



1) Find the controlling thickness


2) Calculate the critical lenght


3) Calculate Tavg along several vertical planes, with at least 5 thickness measures in each plane, and compare against T min




The lowest average thickness is 7,94mm, in plane #2. Then we calculate Tmin in USC



As API 653 says, the criteria for continued operation is as follows:

i) the value t1 shall be greater than or equal to Tmin (see 4.3.3 or 4.3.4), subject to verification of all other loadings listed in; t1 is Tavg


The tank is safe to operate.

ii) the value t2 shall be greater than or equal to 60 % of Tmin; and


The tank is safe to operate.

iii) any corrosion allowance required for service until the time of the next inspection shall be added to Tmin and 60 % of Tmin


The tank is safe to operate until next inspection


The tank is safe to operate until next inspection

This analisis shall be made for as many thinned areas there are in the tank shell. If the corroded area still is larger than 40 inches. If the corroded region is larger than L in the vertical direction, the region must be divided into multiple sections such that no individual section is larger than L. Each section must then be evaluated separately.

See you next week with more articles on tank inspection based in API 653.

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Vacuum testing in tanks

By Carlos Molina.

I am writing this post because of this video that a good friend  sent to me about vacuum box testing, that I want to show you. Besides, I will give you instructions for the construction of your own flat vacuum box, but first a little background.


My first contact with aboveground storage tanks was in 2011. I had been working before as a penetrant testing inspector for a large pipe project in Rubiales (my record was 64 penetrant tests in one day), and a friend of mine named Oscar, which you are going to see in the video, called me with an offer to work in tank repair.  Of course I accepted, switched cities and later became API 653 certified.

One of the earliest tasks I had was to have some welded-on bottom patch plates vacuum tested. But i didn´t know how to do it and the company had no vacuum box. We only had the vacuum pump.  The bottom of the first tank in maintenance was finished and ready to be blasted for paint. But there was no vacuum box the day scheduled for blasting. Luckily I met someone that had one and I took some pictures of it, then made my own for more or less $35 dollars using plexyglass, “sieve rubber”, a discarded foam retired from the peripheral seal of an IFR of another tank the company repaired earlier, wood glue and a tap. It worked fine the first time and was the best vacuum box I´ve ever had. I didn´t need anyone´s help to use it because the foam was so soft. It was so quick. I fell in love with it.


My first self-made vacuum box

That first contact made quite an impression in me, much more later when I found out how much they charge for a vacuum box.


Vacuum boxes are widely used troughout the industry for leak testing. They can be used in tank bottoms, tank roofs, containment liners, pressure vessels like heat exchangers and condensor, and pipes for the detection of leaks, in parts during fabrication or for completed parts. The primary objective of vacuum box testing is, of course, detect any leaks in the surface or joint being examined.

According ASME BPVC V article 10, “the objective of the vacuum box technique of bubble leak testing is to locate leaks in a pressure boundary that cannot be directly pressurized”. That is exactly what happens with tanks, that because of its large volume cannot be overpressurized to test weld seams, so a vacuum box has to make the job. If we apply this logic, then vacuum boxes are more likely to be used in low pressure, large equipment than in high pressure, small equipment. However, it cannot replace hydrostatic testing, because of the higher head pressure you can achieve with water.

In the following video, that was sent to me by my good friend Oscar Andrade, you can see the basics of vacuum box testing in tank bottoms.


Vacuum Box testing can be used on the following instances of construction a welded storage tank.

In the first pass of the internal shell-to-bottom weld if approved instead of MT, PT, or Pen. Oil.
In the bottom welds. 7.3.4a
In the welds of roofs designed to be gas-tight if not air tested.
In all seams of internal floating roofs exposed to liquid or vapors if not tested by penetrating oil. H.6.2
In seams of flexible membrane liners for leak protection. I.6.2
In welded shell joints above the hydrostatic test water level unless tested with penetrating oil.
In the shell-to-bottom weld joints.


The following diagrams will help you make your own flat vacuum box. I hope the diagrams are completely explanatory.


You will need rounded corners plexyglass, a rubber called “sieve rubber”, foamy rubber, a 1/4″ NPT tap, and a knife. I used wood glue to make the parts together, but there are better options.


With this instructions you can make a flat vacuum box for $35 dollars. Make sure to use a foamy rubber at least 1 inch thick and don´t let the connections pass trough under the plexyglass level. Otherwise when the vacuum is made, the soap film solution will enter your vacuum hose. You can use any soap for the test solution.


Off course, I don´t take responsibility for the wrong use of this vacuum box. I am only giving away what has worked to me in the past. Vacuum box testing can be dangerous and should be conducted by qualified personnel.

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By Carlos Molina

Last time we saw the basics of shell calculations for reconstructed tanks. Today we will make some practice exercises on determining thicknesses for reconstructed tanks

The book of knowledge says this about reconstructed tanks:

The inspector should be able to determine the minimum thickness of the shell of a reconstructed tank. The inspector should be able to:

c) Calculate “td”, design shell thickness (API-650,, for tanks of 200 foot diameter and smaller)

d) Calculate “tt”, hydrostatic test shell thickness (API-650,


We have seen an advance to this issue in the article we had on calculating joint efficiencies, but we will have a further look to the formulas that appear there.

Formulas for the calculation of Minimum Thickness for Reconstructed Tank Shells

The minimum thickness of the shell of a reconstructed tank, is given by the following formulas found in

In International System (SI) units



In United States Customary System (USC) units



Td is the shell design thickness (mm and inches)

Tt is the hydrostatic test shell thickness (mm and inches)

D is the nominal tank diameter (m and ft)

H is the design liquid level (m and ft)

= is the height from the bottom of the course under consideration to the top of the shell including the top
angle, if any; to the bottom of any overflow that limits the tank filling height; or to any other level specified by
the Purchaser, restricted by an internal floating roof, or controlled to allow for seismic wave action.

G is the design specific gravity of the liquid to be stored, as specified by the Purchaser

CA is the corrosion allowance (mm and inches)

Sd is the allowable stress for the design condition (Mpa and psi)

St is the allowable stress for the hydrostatic test condition (Mpa and psi)


Let´s consider the following example

Example 1. A tank is completely de-seamed and the reconstructed using A283 Gr C steel plates for the shell. Product stored is Texas Crude Oil at 60°F (G= 0,918), CA is 1/8″, and the diameter of the tank is 28,6m. Design liquid level is 9,5m. Plates to be used are 6ft high. Which are the minimum thicknesses for the first shell course for the design and the hydrostatic test condition?




D = 28,6m

H = 9,5m

G = 0,918

CA = 0,125″

Sd = 137Mpa

St = 154Mpa

E = 1 beacuse the tank is completely de-seamed

Using the formula to calculate the minimum thickness for the design condition, we have:


And for the hydrostatic test condition:

Example 2. A tank built in 1970 is dismantled and later reconstructed using A283 Gr C steel plates for the shell. Product stored is vehicle gasoline at 60°F (G = 0,739), CA is 3mm, and the diameter of the tank is 15,6m. Design liquid level is 12,5m. Plates to be used are 6ft high. Which are the minimum thicknesses for each shell course for the design and the hydrostatic test condition if the tank wasn´t completely de-seamed?




D = 15,6m

H = 12,5m

G = 0,739

CA = 0

Sd = 137Mpa

St = 154Mpa

E = 0,85 according to Table 4.2 of API 653, given that the tank wasn´t completely de-seamed. This is a hint at the fact that this formulas hide the E variable, because it is 1 for de-seamed tanks as by default in new tanks.

Using the formula to calculate the minimum thickness for the design condition, we have:


And for the hydrostatic test condition:



You can see the E variable in the lower portion of the equation.

Example 3. A tank of unknown material was completely de-seamed and reconstructed with the following measures: D = 58m, H = 27ft. Product is water and corrosion allowance is 0,1″. Samples of the tank shell material are taken and yield stenght is found to be 32000psi, while tensile strenght is found to be 56000psi. Which is the minimum thickness for design and hydrostatic conditions? Use USC unit of systems.



D = 58m = 190ft

H = 27ft

G = 1

E = 1

CA = 0,1″

For the calculation of Sd, have in mind what API 653 8.4.2 says

For material not listed in Table 5-2, an allowable stress value of the lesser of 2/3 yield strength or 2/5 tensile strength shall be used.


Sd is the lesser of 2/3*32000 = 21333psi or 2/5*56000 = 22400psi

For tanks of unknown material, have in mind what API 653 8.4.3 says regarding St

For material not listed in Table 5-2, an allowable stress value of the lesser of 3/4 yield strength or 3/7 tensile strength shall be used.


St is the lesser of 3/4*32000 = 24000psi or 3/7*56000 = 24000psi

With these data, we can solve for the design condition:


And for the hydrostatic test condition:


Most API 653 exams contain questions that require you to pick out S values from one of Table 4.1 of API 653 of table 5.2 od API 650. Make sure to use  table 5.2 of API 650 for new and reconstructed tanks.

That´s all and I hope you liked it.

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By Carlos Molina.

Today we will have a glimpse on reconstructed tanks, as needed to pass the api653 exam. This is the first post of a 2 article series.

First of all, let´s see the definition of a reconstructed tank according to API 653


Any work necessary to reassemble a tank that has been dismantled and relocated to a new site. In short, a reconstructed tank is a tank that has been dismantled and its pieces used together to make a new tank. But this should be made carefully.


I have a confession to make: I have never seen one reconstructed tank in my professional exercise. Maybe one of my readers will give us more tips about it. At this stage, I seriously doubt that I would ever know one reconstructed tank, given that the subject of brittle fracture has prevented a lot of owners from using old tanks for new ones.

But the subject of reconstructed tanks should be important to all of us inspectors, and I know about one case in which use of a reconstructed tank went really wrong. Please look the following excerpt about the Ashland Oil Spill:

On January 2, 1988, a four-million gallon tank was used for the first time after being dismantled (from an Ohio location) and rebuilt in Pennsylvania. It was this tank, holding approximately 3.5 million gallons of diesel oil, that failed and collapsed, dumping nearly 1 million gallons of the oil into a storm sewer that leading to the Monongahela River.  At 4:58pm, a worker checked the tank levels and verified the tank was almost full. At 5:02, when the worker was walking away from the tank, he heard a loud boom and turned to find the roof of the tank collapsed. Ashland Co. later took full responsibility for the incident, accepting that they did violate industry standards when reconstructing the tank

(According to this revision of wikipedia)


Showing the magnitude of the Consequences of catastrophic failures in tanks .


The failure in this case was initiated in an welded TEE area as a result of carburization as a consequence of cutting or welding operations to the plates. One million people were affected. The fuel contaminated river ecosystems, killing thousands of animals, such as waterfowl and fish. Ashland paid U$8M to the people directly affected by the  spill. And although only a U$2.25 million were fined to the company (U$5M in 2015) , the cleanup effort really took  U$23million in 2015 dollars. (The amount of fines was lower then. Compare to the U$43billion fined to BP for the Deepwater Horizon oil spill)

Here we again see the devastating effects of brittle fracture, this time in a reconstructed tank. In fact, the Ashland Spill Oil is credited as the triggering event for the creation of the API 653 and other integrity standards. With that in mind, now let´s go on to what you should study for yout API 653 exam.


The book of knowledge says this about reconstructed tanks:

The inspector should be able to determine the minimum thickness of the shell of a reconstructed tank. The inspector should be able to:

a) Determine “Sd”, allowable stress for design condition (API-650, table 5-2, API-653, 8.4.2)
b) Determine “St”, allowable stress for hydrostatic test condition (API-650, Table 5-2, API-653, 8.4.3)
c) Calculate “td”, design shell thickness (API-650,, for tanks of 200 foot diameter and smaller)

d) Calculate “tt”, hydrostatic test shell thickness (API-650,


The following are the numerals dealing with allowable stresses is reconstructed tanks

8.4.2 The maximum design liquid level for product shall be determined by calculating the maximum design liquid level for each shell course based on the specific gravity of the product, the actual thickness measured for each shell course, the allowable stress for the material in each course, and the design method to be used. The allowable stress for the material shall be determined using API 650, Table 5-2. For material not listed in Table 5-2, an allowable stress value of the lesser of 2/3 yield strength or 2/5 tensile strength shall be used.

8.4.3 The maximum liquid level for hydrostatic test shall be determined by using the actual thickness measured for each shell course, the allowable stress for the material in each course, and the design method to be used. The allowable stress for the material shall be determined using API 650, Table 5-2. For material not listed in Table 5-2, an allowable stress value of the lesser of 3/4 yield strength or 3/7 tensile strength shall be used.

Knowing this 2 numerals, let´s go on to the determination of allowable stresses.


First we will see how to determine allowable stresses for reconstructed tanks. If you were going to study by yourself, it will be easy to get confused and use for reconstructed tanks the table 4.1 of API 653 in search of allowable stresses, but that is a mistake. You should use table 5-2 of API 650 instead


The following are 2 questions of the kind that would appear in the open book section of the exam.


QUESTION: For plates of A283 Gr C steel used in a reconstructed tank, determine Sd (allowable stress for design condition).

ANSWER: You simply go to Table 5.2B of API 650 and read from the sixth column that Sd is 20,000psi.

QUESTION: For plates of A516 Gr 60 steel used in a reconstructed tank, determine St (allowable stress for hydrostatic test condition)

ANSWER: Reading the seventh column, we get a value for St of 24,000psi.

And now let´s take a look at some examples of questions that can be made in the exam.


QUESTION: For a material not listed in Table 5.2, having Y = 36,000psi and T = 62,000psi, which is the allowable stress for the design condition?

ANSWER: The lesser of 2/3*36,000 = 24,000psi  or 2/5*62,000 = 24,800psi, then choose 24,000psi

QUESTION: For a material not listed in Table 5.2, having Y = 30,000psi and T = 55,000psi, which is the allowable stress for the hydrostatic condition?

ANSWER: The lesser of 3/4*30,000 = 22,500psi  or 3/7*55,000 = 23,570psi, then choose 22,500psi


Calculation of minimum thicknesses for design and hydrostatic conditions in reconstructed tanks follow the same rules for new tanks. Let´s see a summary.

  • Joint efficiency E is 1, as in new tanks. That´s why the E variable won´t show up in the formulas. Hey, note that this is for tanks that have been completely cutted apart.
  • Values for Sd and St are the same as in new tanks. This has to do with the fact that a new and a reconstructed tank haven´t  been subjected to an hydrostatic and hasn´t proved itself against operational conditions. Values of Sd and St for new and reconstructed are LOWER than for existing tanks, for the same reason.
  • Compare API 653 8.4.2 to API 650 and API 653 8.4.3 to API 650 The values of the fractions for Sd an St are the same.
  • The values of Sd and St for a reconstructed tank are the same for all shell courses, as opposed to API 653, in which this values vary according to shell height for existing tanks. (See table 4.1 of API 653)

The formulas for thickness calculation for reconstructed tanks are found in 5.6.3 of API 650. That will be the subject of my next post.


The formulas and tables to use in reconstructed tanks are found in API 650, as they are treated as new tanks.

Thanks a lot for your attention, and see you next time


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By Carlos Molina

Hi. This is a short post, written to teach you how to calculate the number of points for settlement measurement around a tank. If you want to become a certified API 653 inspector, this is what the body of knowledge for the 2015 API 653 certification exam asks from you

The inspector should be able to calculate the number of survey points for determining tank settlement.

At least one question on this matter will show up in the exam. And it is such an easy thing….


In a tank, the number of settlement points around the periphery for external settlement  measurement is given by the following formula

Number of settlement points


N is the minimum required number of settlement measurement points.

D is the tank diameter, in feet (ft).

And the following rules should apply:

1) The maximum spacing between settlement measurement points shall be 32 ft.

2) No less than eight measurement points

Before any hidrostatic test, elevation measurements should be taken inside the tank, as stated in of API 650

Internal bottom elevation measurements shall be made before and after hydrostatic testing. Measurements shall be made at maximum intervals of 3 m (10 ft) measured on diametrical lines across the tank. The diametrical lines shall be spaced at equal angles, with a maximum separation measured at the tank circumference of 10 m (32 ft). A minimum of four diametrical lines shall be used.

There is not much to say about this issue, apart that just having a look at Figure 1 for easiness.

Settlement measurement points

FIGURE 1. Measurements of Bottom Settlement (internal and external)



Settlement measurement stations are to be used during hydrostatic test and operation of the tank; settlement measurements should be taken at a planned frequency, based on an assessment of soil settlement predictions (See Annex B of API 653)

Of utmost importance is the maximum allowable differential settlement between 2 consecutive stations that may have several consequences: (a) Out-ofplane displacements are induced in the shell in the form of buckling under a displacement-controlled mechanism; (b) High stresses develop at the base of the shell and in the region of the settlement; and (c) High stresses develop in the tank bottom.

Further explanation of tank settlement is found in Annex B, Api 653. The purpose of this article is make you aware that you will be asked about this subject in your exam.

Thanks for reading

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By Carlos Molina

In terms of risk, catastrophic storage tank failure stands as one of the most costly events that can ever happen. It happens with no warning. It can have huge consequences of everything related to your plant: living beings, property, compliance, stakeholders, processes and finances. It is not something you would want for your facility.

Catastrophic tank failure is usually a consequence of brittle fracture, which is not always understood and is understimated when making tank repairs and inspections. Given that in some locations aboveground tanks have been in service for more than a few decades, and that is not uncommon to build a tank from parts used in other tanks, catastrophic tank failure is a real concern.


*References for Tables and figures taken from API 650, twelfth edition, 2013

Whenever there is doubt about the capabilities of some steel to withstand all the loads, maybe because is old, or the tank is of unknown steel, or if it is going to operate at low temperatures, impact tests are recommended, and sometimes mandatory according to the standards, to rule out the possibility of brittle fracture.

When deciding upon the use of an existing tank, the first thing you will take into account will be the exemption curve given in Figure 5.2 of API 653. Existing tanks fabricated from steels of unknown material specifications, thicker than 1/2 in. and operating at a shell metal temperature below 60 °F, can be used if the tank meets the requirements of Figure 5.2. The original nominal thickness for thickest tank shell plate shall be used for the assessment.

Figure 5.2 “Exemption Curve for Tanks Constructed from Carbon Steel of Unknown Material Specification”

exemption curve api-653


When a tank is being reconstructed, each individual plate for which adequate identification does not exist shall be subjected to chemical analysis and mechanical tests as required in ASTM A6 and ASTM A370 including Charpy V-notch. Impact values shall satisfy the requirements of API 650


Impact testing is required if you are going to apply preheating as an alternative to PWHT, as found in 11.3.1.


If you are repairing a tank, and you are short of water for hydrostatic test, make sure to include impact testing in your PQR´s before comencement of work, to make it easier to avoid hydrotest. of API 653 says “welds to existing metal, develop welding procedure qualifications based on existing material chemistry, including strength requirements. Welding procedures shall be qualified with existing or similar materials, and shall include impact testing. Impact testing requirements shall follow appropriate portions of API 650, Section 9.2.2 and shall be specified in the repair procedure.”

Of course, there are many other requirements to hydrotest exemption, which are described in detail in 12.3.2 of API 653


Brittle fracture concerns are more critical when dealing with the following parts of a tank :shell plates, shell reinforcing plates, shell insert plates, bottom plates welded to the shell, plates used for manhole and nozzle necks, plate-ring shell-nozzle flanges, blind flanges, and manhole cover plates. Bottoms are usually thinner and don´t get as much affected by brittle fracture as the mentioned parts.

If you know the material specification, experience has shown that some materials don´t need impact testing. How to know if you need impact test for a new material? When you jave your new plates in location, use figure 4.1a or 4.1b of API 650* .  Plates less than or equal to 40 mm (1.5 in.) thick may be used at or above the design metal temperatures indicated in Figure 4.1a and Figure 4.1b without being impact tested.

Figure 4.1a. Minimum Permissible Design Metal Temperature for Materials Used in Tank Shells without Impact Testing (SI). (Use this figure for known material specification)

figure 4-1a original

For example, let´s consider an ASTM A36 As Rolled, Semi-Killed plate for a shell 12,5mm thick with a design metal temperaure of 10°C. Will it be safe for use?


API 650 manages three types of steel: Killed, As-rolled and Normalized

KILLED: Killed steel is steel that has been completely deoxidized by the addition of an agent before casting, so that there is practically no evolution of gas during solidification. They are characterized by a high degree of chemical homogeneity and freedom from gas porosity. The steel is said to be “killed” because it will quietly solidify in the mould, with no gas bubbling out. It is marked with a “K” for identification purposes

AS ROLLED: In the event that customers heat-treat their own plates, the product is referred to in as-rolled condition. After being rolled, the plate is cooled in static air. The term as-rolled condition stems from the fact that the product is not heat-treated

NORMALIZED: In this condition, carbon steel is heated to approximately 55 °C above Ac3 or Acm for 1 hour; this ensures the steel completely transforms to austenite. The steel is then air-cooled, which is a cooling rate of approximately 38 °C (100 °F) per minute. This results in a fine pearlitic structure, and a more-uniform structure.

In our example, the plate is As-rolled, semikilled material, which makes it a group I, according to Table 4.4a or 4.4b of API 650.

Excerpt of table 4.4a. Material groups (SI)

Table 4.4a Material Groups

Design Metal Temperature is defined as “the lowest temperature considered in the design, which, unless experience or special local conditions justify another assumption, shall be assumed to be 8 °C (15 °F) above the lowest one-day mean ambient temperature of the locality where the tank is to be installed”. The values for mean temperatures in any location in the United States can be found in Figure 4.2—Isothermal Lines of Lowest One-Day Mean Temperatures, not seenin this article. Maximim design temperature is 93°C for tanks designed to API 650.

Our design metal temperature is 10°C and our shell thickness is 12,5mm for a group I material. This combination of materials, design, and construction features, makes our steel safe for use (See figure 1)

Figure 1.

impact testing no need


For a new tank, if required by the Purchaser or if the material falls in an area other than “safe for use”, a set of Charpy V-notch impact specimens shall be taken from plates after heat treatment (if the plates have been heat treated), and the specimens shall fulfill the stated energy requirements. Three specimens are needed, and the average value of the three tests should be compared against the minimum requirements of Table 4.5a—Minimum Impact Test Requirements for Plates.

For a new tank, the impact test requirements and the definition of “controlling thickness” for pipings and forgings used as shell nozzles and manholes is found in numeral 4.5 of API 650.


When a new tank is constructed and impact tests are required by 4.2.9, 4.2.10, or 4.5.4, impact test should follow the guidelines found in numeral 9.2 of API 650, that is not treated further in this article.


For people studying for the  API 653 exam, have in mind what the Body Of Knowledge says.

The inspector should understand the importance of tank materials having adequate toughness. The inspector should be able to determine:

a) Tank design metal temperature (API-650, & Figure 4-2)*
b) Material Group Number for a plate (API-650, Tables 4-3a and 4-3b)*
c) If impact testing is required (API-650, Figure 4-1)
d) If impact test values are acceptable (API-650, Table 4-4)*

*References for Tables and Figures taken from API 650, twelfth edition, 2013

As you can see, impact testing it is not a very difficult subject to understand. The standards are very clear regarding old and new tanks. Notice that the BOK works exclusively with API 650 and not with API 653.


As some of you know, I have been working on a simulation of the real exam. Next week, we will deliver a new version of the simulator, fixing some of the answers and allowing the user to retry the failed questions. Don´t forget to look after this software.

If you want to receive more articles like this, please take some seconds from your time and give us your email. Although sometimes is difficult, I try to publish every week.

Thanks for reading.

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By Carlos Molina

Tank settlement is one of the topics of the Body Of Knowledge for the API 653 exam. It is a very important subject for us tank inspectors, althought is also one of the most vague topics for a new inspector. In fact, the word “settlement” is mentioned more than 250 times in the API 653 standard. As an inspector, you should be able to determine the type  and extent of tank settlement, and decide if it can affect tank integrity. In the api 653 exam, maybe 2 questions will show up about this subject. And as complex as it may look in the api 653 standard, the limitations imposed by the BOK make it a really easy topic.


In new tanks, the API 650 standard doesn´t necessarily asks for a settlement measurement to be done during hydrostatic tests. If there is no settlement expected (for example,  a tank over a giant rock), it might not need settlement measurements, but that´s a decision that is entirely up to the owner.  In normal conditions, there will always be settlement. Anyway, you should design and construct foundations to limit any settlement at all, as impossible it is to eliminate it.

For the sake of information, you should know how setttlement measurements are made. During hydrostatic testing for new and old tanks, at least 6 sets of measurements shall be made.

1. When the tank is empty before hydrostatic testing

2. When the tank is 1/4 full

3. When the tank is 1/2 full

4. When the tank is 3/4 full

4. 24 hours after it is filled

4. With the tank empty again.

Shell elevation measurements shall be made at equally-spaced intervals around the tank circumference not exceeding 10 m (32 ft)


During operations, shell settlement measurements should be taken at a planned frequency, based on an assessment of soil settlement predictions. Bottom settlement monitoring is to be made during internal inspections, respecting the intervals given for inspections in API 653 4.4.6. Identify and evaluate any tank bottom settlement is one of the 3 key objectves of internal inspections, because it plays such an important role on many tank failures and floating-roof problems.

Settlement can be caused by the following:

  1. Lack of support under the base circumference affecting the cylindrical shell and the tank bottom. Parts or the concrete ring may be lost.
  2. Non homogeneous geometry or compressibility of the soil deposit (voids or crevices below the bottom plate)
  3. Non uniform distribution of the load applied to the foundation. Differential pressure during emptying and filling cycles
  4. Uniform stress acting over a limited area of the soil stratum
  5. Wrongly constructed foundations (deficient reinforcement of the concrete, bad quality cement, etc)
  6. Liquefaction phenomenon around the foundation generated by earthquakes. Consider the following excerpt:

The Niigata earthquake was also the first seismic disaster in Japan where the liquefaction of the ground attracted notice. Among the disaster incidents caused by the earthquake, five crude oil storage tanks in a refinery caught fire and continued burning for two weeks, spreading into the surrounding area and burning down a total of 286 adjacent houses. One of them was a 30,000kL floating roof type tank, 51,500mm in diameter, and 14,555mm in height, which was fully stocked with oil. The cause of the fire was ignition by sparks generated by the collision of the floating roof with the side wall, which in turn was caused by the movement of the crude oil by the sloshing phenomenon. Source.


Various forms of settlements could take place in tanks. The BOK considers 3 types of settlement and their evaluation.

1. Edge settlement

Edge settlement occurs when the tank shell settles sharply around the periphery, resulting in deformation of the bottom plate near the shell-to-bottom corner junction,  or the depth of the depressed area of the bottom plate. You can see a diagram for edge settlement below.


Edge settlement affects bottom parallel and perpendicular welds in different manners. It affects weld seams that are “parallel” to the shell in a more critical manner that the ones that run “perpendicular”.

How to evaluate edge settlement?

STEP 1. Annex B of API 653 separates Edge Settlement evaluations in two separate scenarios:

1. If edge settlement is in an area with a welded seam than runs parallel +-20°  to the shell, B turns into Bew

2. If edge settlement is in an area with a welded seam than runs perpendicular +-20°  to the shell, B turns into Be


STEP 2. With the value of R, B and the tank diameter, you can check the maximum allowable vertical settlement in figures B-11 of API 653 for Bew or B-12 for Be. A sample of that diagram you can see next.


See API 653 B-11 and B-12 for the whole details.

Welds in tanks with settlement greater than or equal 75 % of Bew or Be, and larger than 2 in., are to be inspected with magnetic particle of liquid penetrant method. Additionally, weld seams should be inspected vissually and if they show strains bigger than 2%, they should be repaired.  Any plate exceeding acceptable plastic strains (typically 2 % to 3 %) should be replaced.

2. Bottom settlement near the tank shell

This kind of settlement can be present in the bottom or in the annular ring zone, if there is one. It occurs when the bottom deforms showing a depression or a convexity in relation with a flat plane bottom. That deformation is caused by stresses in the bottom plate that have to be evaluated.


How to evaluate bulges in tank bottoms?

STEP 1. As per API 653 B3.3, measure the bulge or depression in its entire lenght. The half of that measure is radius R of the bulge.

STEP 2. The maximum dimension for bulges or depressions is given by the following equation:



B is the maximum height of bulge or depth of local depression, in inches;

R is the radius of an inscribed circle in the bulged area or local depression, in feet.

3. Localized bottom settlement remote from the tank shell.

Localized bottom settlement remote from tank shell are depressions (or bulges) that occur in a random manner, remote from the shell. The same equation (B3.3) used for bottom settlement near the tank shell can be used for the evaluation of this kind of settlement, granted the bottom has single-pass welded joints.


  1. Leave plenty of free space under any nozzle, to prevent any contact with the floor if there is settlement.
  2. Settlement occurs to every tank, and it can be different in practice from the measured settlement during and after hydrostatic testing.
  3. If there is uniform settled expected (If foundations werent well built), you can use flexible joints or maritime hoses that can absorb those misalignments.
  4. Edge settlement often can be predicted in advance, with sufficient accuracy from soil tests. Anyway, piping (especially buried piping) should be designed with adequate consideration to prevent problems caused by such settlement


See that it is pretty easy? I think this is a good explanation of what you will have to learn in order to answer correctly questions regarding tank settlement in the API 653 examination. If you liked this article that will help you in your inspections, then subscribe to my mail list, and you will receive a weekly article about equipment integrity and how to pass your exams.

Cheers and good luck


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By Carlos Molina

Hi friends. Today´s article is really short, but is to let you know of the new version of the API 653 exam Simulator. This 2.0 Version has 100 questions total, an improvement of 52 from the previous version. The new simulator has some bug fixes from the former one, given that it did convert percentages to decimal points, an issue we discovered late.


This version still has to improve, and I promise that I will make my best to update it within a week to the subscribers of my blog. I have to improve the result screen and allow the user to go back to solve the test. Remember that I have a dayjob and little time, jeje.

What is the objective of this simulator? To get you accustomed to the test environment, mimicking the conditions of the actual exam. As far as I know, this simulator is one of its kind.

I took special consideration to the fact that some 70% of questions in the actual exam are from the API 653 standard, so the most of the questions in this simulator were taken from API 653. By the other side, there are new questions that aren´t in my questions series.

To receive your copy, write your mail to me and I well send it to you in the span of 1-2 business days. If you write your mail address in the form below, you will not receive any more mails regarding any other subject. I won´t collect any personal data.

Be aware that this form will work like a subscribing list, so you will have to confirm by entering to your mail account and answering an automatically generated mail.

If you would like to receive weekly updates of the articles I write here in APIEXAM, you can type your mail address next.  I promise to never sell or giveaway your email address to anyone – and you are allowed to unsubscribe at anytime

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There are 5 days lacking to begin with the testing window for the API 653 exam. Study until the last minute. When you sit in front of that computer, you will be given 13 minutes, some paper and some pencils before your exam to take a “learn how to use a computer” tutorial (The same is summarized in the simulator). Obviously, you know how to do this already, so take this time to do a “braindump” and write anything you’d like as fast as you can that you think will help you during the test. I want you to pass in the first try.


Thanks and good study.


By Carlos Molina

According to API 653 3.14, Hot tapping identifies a procedure for installing a nozzle in the shell of a tank that is in service. This means that a tank can continue to be in operation whilst maintenance or modifications are being done to it. This is in complete compliance with the API 653 standard, but following some rules. First of all, for all of you students, let´s review what the BOK of the API 653 March 15 exam has to say.

a) The Inspector should be familiar with the Hot Tapping requirements. (API-653, Paragraph 9.14)
b) The inspector should be able to calculate the minimum spacing between an existing nozzle and a new hot tap nozzle. (API-653 Paragraph 9.14.3)

Hot tapping is more common in pipelines, althought the principles are the same that for tanks. In a normal pipe hot tapping operation, you wish 2 or 3 things.

1. You want flow in the pipe so you can cool the welded zone, given that the liquid works as a heat sink.
2. You want no gases or vapors in the pipe
3. You want to weld nozzles and reinforcements to the pipe without penetrating too much in the base metal, because of pressure.

With tanks it is the same, with the diferrence that flow conditions in tanks are close to stagnant.


The following diagram summarizes the requirements for hot tapping found in API 653 9.14


Requirements for hot-taps in tanks

1. Hot taps are not permitted on shell material requiring thermal stress relief
2. Welding shall be done with low hydrogen electrodes.
3. Hot taps are not permitted on the roof of a tank or within the gas/vapor space of the tank.
4. Hot taps shall not be installed on laminated or severely pitted shell plate. As an inspector, you have to make sure that thickness measures are taken in the proposed area for a hot tap.
5. Hot taps are not permitted on tanks where the heat of welding may cause environmental cracking (such as
caustic cracking or stress corrosion cracking).
6. Minimum spacing in any direction (toe-to-toe of welds) between the hot tap and adjacent nozzles shall be equivalent to the square root of RT where R is the tank shell radius, in inches, and T is the shell plate thickness, in inches.
7. Minimum distance between the toe of the hot tap weld and a vertical seam should be 12in
According to API RP 2201 (Remember this number very well as could be a question of the exam), the hazards for a hot tapping operation in tanks are the following:

a. Tank venting, with vapors reaching the exterior area where welding is taking place.
b. Product within the tank rising and overflowing.
c. Inadvertently allowing the liquid level within the tank to fall below the point of welding, exposing the vapor space within the tank to an ignition source.

Welding on the exterior of tanks in service shall not be conducted unless controls are established and in place to prevent flammable vapors from reaching the area of welding. Work must be stopped immediately should flammable vapors be detected in the welding area.

When hot tapping or welding on a rank in service maintain liquid in the tank at a level at least 3 feet (1 meter) above the area where the work is being performed. No attempt should be made to hot tap or weld above this liquid level in atmospheric pressure petroleum storage tanks because of the potential danger of an explosive atmosphere inside the tank vapor space. Measurements of the tank level should be made by a hand tape gauge to verify the accuracy of automatic or remote reading gauges.


Welding should never be allowed on the decks of floating roof tanks, as they are subject to flammability hazards in several locations:
a. Inside the pontoons.
b. Between the deck and liquid surface near the tank roof gauge float compartment
c. Near the roof seal vent.
d. Near the floating roof lift leg vent.
e. Between the primary and secondary seal.
f. Near the roof drain.

Thanks for reading this article and consider the following warning



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By Carlos Molina

Hi friends. I am longing to make it in the integrity field. I mean, I want to make it in the tanks, in the pipes and in the pressure vessels and static equipment.

Tank level seen with Infrared camera

Yo can see tank levels at once with infrared cameras

Here is a gift for you

Today I am writing you about the API 580 certification, the same I talked about in this article

On february 2, I received this mail from the guys of prometric that contained a pdf file. I opened up the PDF file and read that I  achieved a passing grade and i am now certified to conduct rbi inspections. I dont have the experience yet though. Here is a screenshot of the document.


But as for the exam, I actually just studied some 3 days total. I really didn’t have much time in the previous months to study, and just one month before the exam, the API 580 course I was due was cancelled. I thought I had no chance. In the last week, I read the RP on the bus while in my conmute, I read the RP while I was having my lunch, and I reviewed some questions and answers I had in an spaced repetition software (in a very disorderly way).
I almost flunked. I got 50 questions right, just to a little over the 71% needed. What helped me was that I can understand english well and generally have been good in multiple choice exams troughout my life.

During the exam, all you had to do is make sure that you get the 49 questions you need in order to pass. Be sure of 49, and you can do anything to the others, from guessing to discarding to whatever. And if you passed, congratulations on this significant professional acomplishment.

And continuing with my goal to completely prepare you for these exams, here are more questions for the API 653 Certification examination.


I am bringing you today 25 questions about Microbiologically induced corrosion (MIC). You can download them Here. Microbial corrosion, also called bacterial corrosion, bio-corrosion, microbiologically influenced corrosion, or microbially induced corrosion (MIC), is corrosion caused or promoted by microorganisms, usually chemoautotrophs. It can apply to both metals and non-metallic materials (Wikipedia)

For the exam, I can´t tell you how many questions about this subject will show up. Maybe none. Anyway, I prepared these questions with the intention to make you really knowledgeable to the subject.

More pages on the API 653 questions series

1. Beginning the path: API 653 Questions

2. General and definitions. #2 in the API 653 questions series.

3. In the core of API 653. Path # 3.

4. Damage mechanisms for API 653 inspection. Path #4

5. Corrosion Under Insulation 

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Thanks and good study.