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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.


By Carlos Molina

Following with the subjects that you should study for the exam, today we will have a short explanation of the reason behind some of weld spacings in tank elements. Boy, I have to tell you, thinking for this article was difficult, because it involves many figures and tables that are present in the API 650 and API 653 standards. And writing it was more difficult, because of the little time I have (As most of you in the Oil and Gas Field).

First let me ask you a question: In which plane are tank shell stresses higher, in a vertical or an horizontal plane?

[click to continue…]


By Carlos Molina

Today Apiexam is receiving  requests for a simulator of the API 653 exam. It was designed by me and built by Bareta. It features 48 API 653 questions in a multiple choice question format.

It runs on Windows Vista, 2008, 7, 8 and 2012. It should be preferablly used in operative systems of 64bits, although it can work in 32bits environments.

This software mimics the experience you will have in the real exam, which I think is the most important use of the software at this stage in your study: getting familiar with the computer based testing environment. The software will show you a simplified tutorial screen in the likes of the actual tutorial (the real one has several pages, while this has only one). You can mark the questions where you have any doubt for later review. if you notice you have problems with any specific question, go open your book and answer it, and put that question into your flashcard software.

It has only 50 questions in multiple choice format, because it is a beta version. It will have an upgrade the fastest possible to the most possible quantity of questions. Remember I have by now created 240 questions from the subjects in the BOK. 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 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. (I haven´t mastered in internet skills yet) But it will only be used once for the software.

These are 2 screen captures of the software.

API 653 exam simulator

API 653 exam simulator


API 653 exam simulator

API 653 exam simulator

In the actual exam, API is the sponsor, which has invested other enterprise with the task of administering the exam. This other enterprise will have then facilities and expert personnel to watch over the test. Be ready to be frisked, at least visually, as you are not permitted to ingress foods, pens or electronic equipment (only eyeglasses are allowed). The test lasts 4 hours, which is much more of the time you actually need if you study enough. They will let you go to the bathroom or let you go retrieve your cellphone, but they may be overseeing your call.

Lastly, I would like you to consider an option. I am for the first time using a mail list subscription form. If you would like to receive weekly updates of the articles I write here in APIEXAM, you can type your mail 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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Thanks and good study.


By Carlos Molina

Hi friends.

I keep studying about API 653. I have to be a re-certified API 653 Inspector before september 2015.  I obtained my certification back in september 2012, with only one year experience in tank repair and, as I did with my english language skills, most of it was self-taught (I took a course, though). Now I have to regain all the knowledge again, which is really easy if you know how to learn it.

I hope you are studying well for your own exam, taking advantage of what I or others offer, and if you are not, remember it is scheduled for March 15, 2015. So you better  wash out of the holidays inertia and start studying right now.

Today we are going to talk about hydrostatic testing in API 653, more specifically about hydrostatic height calculations. Some of the questions of the exam are from this subject.


Hydrostatic testing is (or a least should be) done in every new welded tank for oil storage and it is mandatory for any tank that has been under a major alteration, according to API 653.

And as we are students,  let´s remember the definition of hydrotest of API 653.

Definition of hydrotest per API 653



As it says, for new or repaired tanks, the purpose of hydrostatic testing is to demonstrate the tank´s fitness for service, and the better you test, the less risk you have once the tank is in operation.

If you are planning to take the exam, you should be familiar with all of the requirements of API 650 and 653 regarding hydrotesting. But right now we will concentrate in calculating hydrostatic test height.


For a tank that has been in operation, several things can happen that may highlight the need for an hydrostatic test

*If the tank is going to be used for a new, more sever service. That means, when the liquid that will be stored has a higher specific gravity than the current stored  product.

*When there have been repairs. Maybe your repairs are perfect, but some corrosion remains in other areas of the tank.

Determination of hydrostatic test height Ht, when you have calculated a controlling thickness for an entire shell course, can be achieved solving for the following equation, where Ht is the height from the bottom of the shell course under consideration to the hydrostatic test height

Hydrotest height over an entire shell course

Over entire shell course

Determination of hydrostatic test height Ht, when you have calculated controlling thickness for a locally thinned area (I haven´t treated the subject of controlling thicknesses here so far, my bad) can be achieved solving for the following equation, where Ht is the height from the bottom of the length, L, (see for the most severely thinned area in each shell course to the hydrostatic test height in feet

Hydrotest height over locally thinned area

Over locally thinned area

So, hydrostatic test height depends on 4 variables, which are.

St is the smaller value between fractions of yield strenght or tensile strenght, or the maximum allowable hydrostatic test stress.

Stress values for hydrostatic height calculus

Stress values for hydrostatic height calculus

E is the joint efficiency. Look how to find joint efficiency here

Tmin is the controlling thickness

D is the diameter of the tank.

Let´s see an example of height calculation. I am assuming you have some background on the formulas  of API 650 and API 653.


A tank will be subjected to hydrostatic testing after repairs. After some study, the inspector decides to run calculations for hydrostatic test height over the first shell course and over a locally thinned area close to a vertical seam, 36 inches high in the 4th shell course. Steel is A36 with Y = 36000psi and T=58000psi. Shell courses are 6ft high and the tank is 48ft diameter. First two courses were welded before 1980, and the other courses were added recently. The controlling thickness for the first shell course is 7mm and for the locally thinned area is 6,35mm. What should be the hydrostatic test height?


Well, for the equations, values are these

Case 1. Lower shell course

E=0,85. See Table 4-2

St = smaller of 0,88Y or 0,472Y, then St = 27376psi

D= 48

Tmin= 7mm = 0,275in

Hydrotest height for entire shell course

So, hydrostatic test height will be 15,93m.

Case 2. Locally thinned area in 4th course

=1. See Table 4-2.

St = smaller of 0,9Y or 0,519Y, then St = 30102psi

D= 48

Tmin = 6,35mm=0,25in

Hydrotest height for locally thinned area

Hydrostatic test height over the locally thinned area can be 16,7m. (A total height of 23,01m)

Then the tank has a maximum fill height  is 15,93m.


You have to be aware that variables in these and other equations of the standards can have different values depending on year of fabrication, purpose of calculation (design or hydrostatic loads), etc. In the exam, you have to be very careful to avoid mistakes, as they always trhow some confusing questions.

You can notice that the presence of different defects in tank shells implies than more than one value of Tmin or Ht should be calculated in a real tank inspection. This kind of dual example analysis is not common in other literature.

And that´s it for now.

As always, I am open to all kind of comments about the information in this site. And lastly, take a look at the following Ad.

ad for the simulator