Tank Inspection with magnetic flux leakage Ppt.pptx

Guidelines and Methods for
Inspection of Atmospheric and
Low-pressure Storage Tanks
08-March-2023
Sriram Avinash
For the benefit of business and people

1 Scope
2
2&3 References& Definitions
4 Types of Storage Tanks
5 Reasons for Inspection &
Causes of Deterioration.
6 Inspection Frequency &
Scheduling.
7 Methods of Inspection
8 Tank Assessment
9 Tank Repair &
Alterations
10 Records
11 Appendix A
SUMMARY

Scope
4
Title of the presentation - DD/MM/YY
1
This document provides useful information and
recommended practices for the maintenance and
inspection of atmospheric and low-pressure
storage tanks.
While some of these guidelines may apply to
other types of tanks, these practices are intended
primarily for existing tanks that were
constructed to API Spec 12A or API Spec 12C,
and API Std 620 or API Std 650.

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2.References:
API, ASME, ASNT, ASTM, OSHA
3.Definitions:
1.alteration: Any work on a tank involving cutting, burning,
welding, or heating operations that changes the physical
dimensions and/or configuration of a tank.
Examples of alterations include:
a. The addition of a man way or nozzle exceeding 12
in. NPS (nominal pipe size).
b. An increase or decrease in tank shell height.

2.applicable standard: The original standard of construction,
such as API standards unless the original standard of
construction has been superseded or withdrawn from
publication; in this event, applicable standard means the current
edition of the appropriate standard.
3. atmospheric pressure: When referring to (vertical) tanks,
the term “atmospheric pressure” usually means tanks designed to
API Std 650. API Std 650 & 653 provides for rules to design
tanks for “internal pressure” up to 21/2 lbf/in.2.
7

3.4 authorized inspection agency: It can be one of the following:
a. The inspection organization of an insurance company which
is licensed or registered to and does write aboveground
storage tank insurance
b. An owner or operator of one or more aboveground
storage tank (s) who maintains an inspection organization for
activities relating only to his equipment and not for above
ground storage tanks intended for sale or resale.
c. An independent organization or individual under contract to
and under the direction of an owner or operator and
recognized or otherwise not prohibited by the jurisdiction in
which the aboveground storage tank is operated. The owner
or operator’s inspection program shall provide the controls
necessary for use by authorized inspectors contracted to
inspect aboveground storage tanks.
8

5.authorized inspector: An employee of an authorized
inspection agency that is certified as an aboveground
storage tank inspector per API Std 653, Appendix D.
6.bottom-side: The exterior surface of the tank bottom, usually
used when describing corrosion. Other terms with the same
meaning are “under-side” or “soil-side.”
7.change-in-service: A change from previous operating
conditions involving different properties of the stored product
such as specific gravity or corrosivity and/or different service
conditions of temperature and/or pressure.
9

3.8 examiner: A person who assists the API authorized tank
inspector by performing specific non-destructive examination (NDE)
on the tank but does not evaluate the results of those examinations
in accordance with API Std 653 or this recommended practice,
unless specifically trained and authorized to do so by the owner or
user. The examiner does not need to be certified in accordance with
API Std 653 nor needs to be an employee of the owner or user, but
shall be trained and competent in the applicable procedures in
which the examiner is involved. In some cases, the examiner may
be required to hold other certifications as necessary to satisfy
owner or user requirements. Examples of other certification that
may be required are American Society for Non-Destructive Testing
SNT-TC- 1A or CP189, or American Welding Society Welding
Inspector Certification. The examiner’s employer shall maintain
certification records of the examiners employed, including dates
and results of personnel qualifications and shall make them
available to the API Authorized Inspector.
10

9. inspector: An Authorized Inspector and an employee
of an Authorized Inspection Agency who is qualified and
certified to perform tank inspections under this standard.
10.MFL (magnetic flux leakage): An electromagnetic scanning
technology for tank bottoms. Also known as MFE (magnetic flux
exclusion).
11.product-side: The interior surface of a tank bottom, usually
used when describing corrosion. Other terms with the same
meaning are “top-side” or “product-side.”
12.owner/operator: The legal entity having control of and/or
responsibility for the operation and maintenance of an existing
storage tank.
11

13. reconstruction: The work necessary to re-assemble a tank that
has been dismantled and relocated to a new site.
14. reconstruction organization: The organization having assigned
responsibility by the owner/operator to design and/or reconstruct
a tank.
15. repair: Any work necessary to maintain or restore a tank to a
condition suitable for safe operation. Typical examples of
repairs includes:
a. Removal and replacement of material (such as roof, shell,
or bottom material, including weld metal) to maintain tank
integrity.
b. Re-levelling and/or jacking of a tank shell, bottom, or roof.
c. Addition of reinforcing plates to existing shell penetrations.
d. Repair of flaws, such as tears or gouges, by grinding and/or
gouging followed by welding.
12

16. shell capacity: The capacity that the tank can hold based
on the design liquid level (see API Std 650).
17. soil-side: See definition for bottom-side.
18.storage tank engineer: One or more persons or
organizations acceptable to the owner or user who are
knowledgeable and experienced in the engineering disciplines
associated with evaluating mechanical and material
characteristics affecting the integrity and reliability of tank
components and systems. The tank engineering, by consulting
with appropriate specialists, should be regarded as a
composite of all entities necessary to properly address
technical requirements and engineering evaluations.
13

19.tank specialist: Someone experienced in the design and
construction of tanks per API Std 620 and/or API Std 650, and
the inspection and repair of tanks per API Std 653.
20. top-side: See definition for product-side.
14

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4.1 GENERAL
Important factors such as the volatility of the stored fluid and the
desired storage pressure result in tanks being built of various
types, sizes, and materials of construction. In this document, only
atmospheric and low pressure storage tanks are considered.
Guidelines for inspection of tanks operating at pressures greater
than
15 lbf/in.2 (103 kPa) gauge are covered in API RP 572.
Types of Storage Tanks
GENERAL

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1. Storage Tanks with Linings and/or Cathodic
Protection
Tank Bottom Lining (API RP 652)
Cathodic protection (API RP
651)
2. Storage Tanks with
Leak Detection
Systems
Design Guidelines for leak
detection (API Std 650,Appendix
I)
GENERAL Types of Storage Tanks

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18
4.1.3 Storage Tanks with Auxiliary Equipment
Most storage tanks are provided with some of the following auxiliary
equipment such as liquid-level gauges, high-and low-level alarms
and other overfill protection systems, pressure- relieving devices,
vacuum venting devices, emergency vents, roof drain systems,
flame arrestors, fire protection systems and mixing devices.
Stairways, ladders, platforms, handrails, piping connections and
valves, manholes, electric grounding connections (as required) and
cathodic protection systems are considered examples of storage
tank auxiliary equipment.
GENERAL Types of Storage Tanks

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2. ATMOSPHERIC STORAGE TANKS
1.Construction Materials and Design Standards
Atmospheric storage tanks are designed to operate with their gas
and vapor spaces at internal pressures approximating atmospheric
pressure.
Such tanks are usually constructed of carbon steel, alloy steel,
aluminium or other metals, depending on service. Additionally, some
tanks are constructed of non-metallic materials such as reinforced
concrete, reinforced thermosetting plastics, and wood. Some
wooden
tanks constructed to API Spec 12E are still in service.
ATMOSPHERIC
STORAGE TANKS

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4.2.2 Use of Atmospheric Storage Tanks
AST in the petroleum industry are normally used for fluids having a
true vapor pressure that is less than atmospheric pressure. Vapor
pressure is the pressure on the surface of a confined liquid caused
by the vapors of that liquid. Vapor pressure varies with temperature
and increases as the temperature rises.
Crude oil, heavy oils, gas oils, furnace oils, naphtha, gasoline, and
non-volatile chemicals are usually stored in atmospheric storage
tanks. Many of these tanks are protected by pressure -vacuum
vents that maintain the pressure difference between the tank vapor
space and the outside atmosphere to just a few ounces per square
inch.
ATMOSPHERIC
STORAGE TANKS

4
4.2.3 Types of Atmospheric Storage Tank Roofs
The most common type of
atmospheric storage tank
is the fixed cone roof tank,
These roofs are normally supported
by internal structural but can be fully
self- supporting in smaller diameters
(typically, 60 ft [3 m] diameter or less).
up to 300 ft (91.5 m) in diameter
& 64 ft (19.5 m) in height (larger
diameter tanks have been built,
mostly outside the U.S.)
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ATMOSPHERIC
STORAGE TANKS

4
The umbrella roof has radially-arched
segmental plates with integral
framing support members (usually
without internal support columns).
In the steel dome roof tank, the roof
plates are usually formed with curved
segments joined to be self-supporting.
22
ATMOSPHERIC
STORAGE TANKS

4
The floating-roof tank is designed to
minimize filling and breathing losses
by eliminating or minimizing the vapor
space above the stored liquid. The
shell and bottom of this type of tank
are similar to those of the fixed roof
tanks, but in this case, the roof is
designed to float on the surface of the
stored liquid. Older styles of floating
roofs include single steel deck details
without annular pontoons. Such
roofs have no reserve buoyancy and
are susceptible to sinking in service.
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ATMOSPHERIC
STORAGE TANKS

4
Annular-pontoon and double-deck Some floating-roof tanks have
fixed aluminium geodesic dome roofs installed on top of the tank shell
to reduce product vapor loss or to eliminate the need to drain rainwater
from the roof. These are considered internal floating roofs is a tank with
a fixed steel cone roof over a floating roof.
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ATMOSPHERIC
STORAGE TANKS

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ATMOSPHERIC
STORAGE TANKS

4
Floating-roof sealing systems are used
to seal the space between the tank
wall and the floating roof, typically with
a mechanical seal. This type of seal
consists of a shoe which is a plate that
is pressed against the tank wall by
springs (or by counter-weights in older
designs) or other tensioning system,
with a flexible vapor membrane
attached between the shoe and the
floating roof outer rim.
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ATMOSPHERIC
STORAGE TANKS

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4.3 LOW PRESSURE STORAGE TANKS
3.3.1 Description and Design of Low-pressure Storage
Tanks
Low-pressure storage tanks are those designed to operate with
pressures in their gas or vapor spaces exceeding the 2.5 lbf/in.2 (18
kPa) gauge permissible in API Std 650, but not exceeding the 15
lbf/in.2 (103 kPa) gauge maximum limitation of API Std 620. These
tanks are generally constructed of steel or alloy steel and are usually
welded, although riveted tanks in low-pressure service are still
found. Rules for the design and construction of large, welded, low-
pressure storage tanks are included in API Std 620.
LOW PRESSURE
STORAGE TANKS

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4.3.2 Use of Low Pressure Storage Tanks
Low-pressure storage tanks are used for the storage of the more
volatile fluids having a true vapor pressure exceeding the pressure
limits of API Std 650, but not more than 15 lbf/in.2 (103 kPa) gauge.
Light crude oil, some gasoline blending stock, light naphtha, pentane,
some volatile chemicals, liquid oxygen and liquid nitrogen are
examples of liquids that may be stored in low-pressure storage
tanks.
LOW PRESSURE
STORAGE TANKS

4
4.3.3 Types of Low Pressure Storage Tank Roofs
Tanks that have cylindrical shells and
cone or dome roofs are typically used
for pressures less than about 5 lbf/in.2
(34.5 kPa) gauge. Tank bottoms may
be flat or have a shape similar to the
roof. Hold-down anchorage of the
shell is generally required.
Vapor Dome Roof
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LOW PRESSURE
STORAGE TANKS

4
For pressures above about 5
lbf/in.2 Gauge (34.5 kPa),
hemispheroid, spheroid, and noded
spheroid tank types are commonly
used. Tanks for this application are
now typically constructed as
spheres. Such tanks are designed
to withstand the vapor pressure
that may be developed within a
tank having no devices or
means to change or relieve the
internal volume.
Plain Hemispheroids
30
LOW PRESSURE
STORAGE TANKS

4
Hemispheroid
31
Plain Spheroid
LOW PRESSURE
STORAGE TANKS

32
Reasons for
Inspection and
Causes of
Deterioration
5

5
33
5.1 REASONS FOR INSPECTION
a. Reduce the potential for failure and the release of stored products.
b. Maintain safe operating conditions.
c. Make repairs or determine when repair or replacement of a tank
may be necessary.
d. Determine whether any deterioration has occurred, and if so,
prevent or retard further deterioration.
e. Keep ground water, nearby waterways, and the air free of
hydrocarbon and chemical pollution.
f. Regulatory compliance.
g. Risk management through data gathering and prioritization
of maintenance and capital expenditures.
Reasons for Inspection & Causes of Deterioration
REASONS FOR
INSPECTION

5
34
5.2 DETERIORATION OF TANKS
External Corrosion
Foundation material used for forming
a pad under the bottom may
contain materials that can promote
corrosion.
Poor drainage may allow water to
remain in contact with the tank
bottom.
Accumulation of the fluid under the tank can cause external corrosion
of the tank bottom.
An improperly sealed ring wall, as shown in Figure, may allow
moisture to accumulate between the tank and the support, thereby
accelerating corrosion.
DETERIORATIO
N OF TANKS

5
Foundation Seal
35
DETERIORATIO
N OF TANKS

5
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External Corrosion
The lower tank shell can become severely corroded externally at, or
just above, or below, the grade line, where soil movement has raised
the grade level to cover the lower portion of the shell.
External corrosion also occurs when external insulation absorbs
ground or surface water by wicking action, or when damaged or
improperly sealed openings around nozzles and attachments allow
water behind the insulation.
A sulfurous, acidic or marine atmosphere can damage
protective coatings and increase the rate of corrosion.
DETERIORATIO
N OF TANKS

5
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External Corrosion
The type of tank and the construction details used can affect the
location and extent of external corrosion. Inspections should look
for areas where tank construction details cause water or sediment
to accumulate.
Riveted tanks offer many niches where concentration cell corrosion
can occur. Leaks at seams of riveted tanks may cause failure of
external coatings, allowing external corrosion to develop.
DETERIORATIO
N OF TANKS

5
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Internal Corrosion/Deterioration
Riveted tanks offer many niches where concentration cell corrosion
can occur. Leaks at seams of riveted tanks may cause failure of
external coatings, allowing external corrosion to develop.
Internal corrosion in the vapor space above the liquid of these tanks
can be caused by hydrogen sulfide vapor, water vapor, oxygen, or any
combination of these.
DETERIORATIO
N OF TANKS

5
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Internal Corrosion/Deterioration
In the areas in contact with the stored liquid, corrosion is commonly
caused by acid salts, hydrogen sulfide or other sulfur compounds, or
contaminated water that settles out and mixes with solids on the
bottom of the tank. This layer is typically referred to as bottom
sediment and water (BS&W).
Stress corrosion cracking can be concern where the product is known
to be reactive with welds and heat-affected zones. Areas of high stress
concentration, such as at weld seams and around nozzle necks, are
more susceptible to accelerated corrosion due to the effects of product
contact.
Hydrogen blistering, hydrogen grooving, caustic stress
corrosion cracking, electrolytic corrosion and acid erosion. (API
571)
DETERIORATIO
N OF TANKS

5
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5.3 DETERIORATION OF OTHER THAN FLAT BOTTOM
AND NON-STEEL TANKS
Concrete tanks can be attacked by the tank contents, can crack
because of settlement or temperature changes, or can spall because
of atmospheric conditions, resulting in exposure of the steel
reinforcing bars to further atmospheric corrosion.
External stress corrosion cracking of stainless steel tanks may be a
concern if chlorides that may be present in insulation get wet or
enter the insulation.
Aluminium can be affected by impurities such as acids or
mercury compounds in process streams or wastewater.
DETERIORATIO
N OF TANKS

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5.4 LEAKS, CRACKS, AND MECHANICAL
DETERIORATION
Leaks can occur at improperly welded or riveted joints, at pipe thread
or gasket connections or cover plates, or at crack-like flaws
(including arc strikes on plates) in welds or in plate material. Three-
plate in lap- welded tank bottoms are particularly prone to defects
that can lead to leaks.
Crack-like flaws can result from a number of causes, including
deficiencies in design, fabrication, and maintenance. The most likely
points for crack-like flaws to occur are at the bottom-to-shell details,
around nozzle connections, at manholes, around rivet holes or around
rivet heads, at welded brackets or supports, and at welded seams.
The lower-shell-to-sketch-plate or shell-to-bottom weld is especially
critical because in relatively large or relatively hot tanks, there is a
higher likelihood this detail can develop a crack-like flaw due to high
stresses.
DETERIORATIO
N OF TANKS

5
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5.5 DETERIORATION AND FAILURE OF
AUXILIARY EQUIPMENT
Examination of tank venting devices should be included in periodic
inspection to ensure that proper operation and protection are
maintained. See API RP 576 for information regarding inspection
of pressure-relieving devices.
DETERIORATIO
N OF TANKS

5
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5.6 SIMILAR SERVICE METHODOLOGY FOR
ESTABLISHING TANK CORROSION RATES
Similar service uses experience from tanks in similar locations
and services to establish corrosion rates.
The similar service should be examined independently for both the
product-side and the soil-side corrosion since the mechanisms
and corrosion rates are entirely independent of one another.
DETERIORATIO
N OF TANKS

Inspection Frequency
and Scheduling
44
6

6 Inspection Frequency and Scheduling
1. FREQUENCY OF INSPECTION (API 653)
2. CONDITION-BASED INSPECTION SCHEDULING
CONDITION-BASED
INSPECTION SCHEDULING
45

6
46
In most cases, the new thickness includes some excess
thickness. This excess thickness may be the result of any one or
all of the following factors:
a. Additional thickness added to the required thickness as
a corrosion allowance.
b. Additional thickness resulting from using the closest, but
larger, nominal plate thickness, rather than the exact value
calculated.
c. Additional thickness from deliberately setting the
minimum acceptable thickness of plates for construction
purposes.
d. Additional thickness on the upper portions of shell
courses not
required for product loading at that level.
e. Additional thickness, available due to a change in tank
Inspection Frequency and Scheduling
CONDITION-BASED

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For structural members and parts, such as roof supports and
platforms, normal accepted industry practice for structural
design (such as methods provided in the Steel Construction
Manual issued by the American Institute of Steel Construction)
can be used to calculate the allowable loads of members in the
new condition.
For external piping, nozzles, and valves, the methods
provided in API 570 and ASME standards can be used to
determine minimum acceptable thickness.
CONDITION-BASED

API-653 provides an extensive list of factors to be considered in determining
appropriate inspection intervals for in- service tanks.
Inspections from Outside the Tank:
• According to the standard, all tanks must receive an external inspection by
an authorized inspector at least once every 5 years, or more frequently
depending on the rate of tank shell corrosion.
48

Internal Inspections:
• API-653 generally requires that all newly installed tanks receive an internal
inspection within 10 years of their entry into service.
• However, the maximum initial internal inspection interval may extend up to
25 years based on the completion of a risk-based inspection (RBI)
assessment and the types of leak prevention, detection or containment
safeguards that have been installed.
• Subsequent internal inspections are based on the rate of corrosion, with
the duration extending from 20 to 30 years, depending on the method
used to assess the rate of corrosion.
• Corrosion rate may be estimated from tanks in similar service.
• If corrosion rate is not known or and similar service assessment data is not
available, the actual “t” shall be determined, interval shall not exceed
10year of operation.
49

1. The interval between inspections is most influence by service
history, unless special reason indicate early inspection (6.2.2).
2. In the case of insulated tanks remove the insulation to the
extent necessary to determine condition of roof & shell
(6.3.2.2).
3. Tank grounding system components, shunts, cable
connections etc. shall be visually checked (6.3.2.3).
50

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6.4 FITNESS-FOR-SERVICE EVALUATION
Aboveground storage tanks can be evaluated to determine fitness for
continued service. API RP 579 provides fitness-for-service (FFS)
evaluation criteria for tanks based on what is known or can be
determined about the tank from various inspections. Different levels of
assessment are provided, depending on the information available for
evaluation and resources (experience and money) available. FFS
deals primarily with the evaluation of defects and flaws such as
corrosion, pitting, crack-like flaws, laminations, and distortions that
can affect remaining service life. Specific criteria for evaluating
defects or flaws are provided for in API RP 579.
FITNESS-FOR-SERVICE
EVALUATION

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1. PREPARATION FOR INSPECTIONS
Before entering or re-entering any tank, appropriate safety
precautions are necessary. These precautions are discussed in detail
in API Std 2015 and API RP 2016. Generally, such precautions
include, but are not limited to, the following:
a. Removal of hazardous gases.
b. Removal of gas-generating, pyrophoric, or toxic residues.
c. Isolation from any source of toxic or gas-generating fluids by
the use of blinds or by disconnection/isolation.
d. Assurance of an atmosphere that contains sufficient oxygen.
Where applicable, OSHA rules for safe entry into confined spaces
should be followed (Title 29, Code of Federal Regulations, Part
1910.146).
e. Potential for collapse of either fixed or floating roofs.
Methods of Inspection
PREPARATION FOR
INSPECTIONS

2. EXTERNAL INSPECTION OF AN IN-SERVICE TANK
1. Ladder and Stairway Inspection
Should be examined carefully for corroded or broken parts. Its condition
of may be checked by visual inspection and by sounding.
2. Platform and Walkway Inspection
Can be inspected in the same manner as ladders and stairways. The
thickness of walking surfaces used by personnel can be checked at
the edges with calipers and in other areas by tapping with a hammer.
Low spots where water can collect should be checked carefully
because corrosion may be rapid in such areas. Drain holes can be
drilled in the area to prevent future accumulation of water.
54
EXTERNAL INSPECTION
OF AN IN-SERVICE TANK

7
7.2.3 Foundation Inspection
The foundations of tanks may be made of sand or other fill pads;
crushed stone pads or stone-filled grade bands; steel and concrete
piers, ring walls, or natural earth pads. Pads should be visually checked
for erosion and for uneven settlement.
The opening or joint
between a tank bottom and
the concrete pad or base
ring should be sealed to
prevent water from flowing
under the tank bottom.
55
EXTERNAL INSPECTION

7.2.4 Anchor Bolt Inspection
The condition of anchor bolts can
usually be determined by visual
inspection.
Visual inspection can be aided by
removal of the nuts, one by one, or
supplemented by ultrasonic thickness
examination. Anchor bolts nuts should
be checked for a snug fit to the anchor
bolt chair top plate (i.e., there should
be no distance between the location of
the nut on the bolt and the anchor
chair top plate.)
56
EXTERNAL INSPECTION

7.2.5 Grounding Connection Inspection
The grounding connections should be visually checked for intact
connection and for corrosion at the point where they enter the earth
or attach to a grounding rod and at the tank ground clip.
If any doubt exists about the condition of the grounding connection, its
resistance can be checked. The total resistance from tank to earth
should not exceed approximately 25 ohms.
57
EXTERNAL INSPECTION

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58
7.2.6 Protective Coating Inspection
Rust spots, blisters, peeling, cracking and coating due to lack of
adequate bond, are all types of common paint failure. Rust spots and
blisters are easily found by visual inspection. Coating bond failure is not
easily seen unless a blister has formed or has broken. Care should be
taken not to significantly damage protective coatings during inspection.
Paint blisters occur most often on the roof and on the side of the tank
receiving the most sunlight. Coating bond failure commonly occurs
below seam leaks.
Other points at which the paint may fail are in crevices or depressions
and at tank seams that are welded, riveted, or bolted. The paint on
the tank roof is especially susceptible to accelerated failure. The
paint on floating roofs should be inspected carefully, especially in
areas where there is standing water or product.
EXTERNAL INSPECTION

7
59
7.2.7 Insulation Inspection
Visual examination is normally performed. Detailed inspection should
be conducted around nozzles, around the saddles of horizontal
tanks, and at caulked joints.
Areas of insulation may need to be removed prior to such inspection
especially on the shaded side of the tank, on roofs, below
protrusions, and at areas of obvious water Intrusion.
Insulation support clips, angles, bands, and wires should be spot-
checked for tightness and signs of corrosion and breakage. If
access is available internally, many of these areas can be checked
by UT from the inside.
Corrosion under insulation (CUI) is most aggressive in
temperature ranges between 120°F (49°C) and 200°F (93°C).
EXTERNAL INSPECTION

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60
7.2.8 Tank Shell Inspection
If any foreign material or soil has collected around the bottom of the
shell or if the tank has settled below grade, a close inspection
should be made at and below the grade line.
Tanks with products at elevated temperatures in cold climates may
have water present near the shell and under the bottom because of
ice or snow build up around the tank.
Corrosion products or rust scale can be removed by picking, scraping,
wire brushing, or blasting (with sand, grit or water under high
pressure) so that the depth and extent of the corrosion may be
evaluated. The potential hazards of using such methods should be
evaluated beforehand. For example, hammer testing or removal of
heavy scale should not be done with the tank under pressure or
otherwise in service.
EXTERNAL INSPECTION

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61
7.2.8.1 Thickness Measurements (API 653)
Sun, shade, prevailing winds, and marine environments may affect
the rate of external corrosion significantly. These factors need to be
considered when determining the number and location of thickness
measurements to be taken.
In obtaining shell thickness, special attention should be given to the
upper 24 in. (61 cm) of uncoated shells of floating-roof tanks. These
portions of the shell plates can corrode at a higher rate than the
lower shell plates because of constant exposure to the atmosphere
on both sides.
EXTERNAL INSPECTION

7
62
7.2.8.2 Stiffeners and Wind Girders
Can be inspected visually and by hammer testing. Thickness
measurements should be made at points where corrosion is evident.
Any pockets or crevices between the rings or girders and the shell
should receive close attention. If the stiffening members are welded to
the shell, the welds should be visually checked for cracks. The areas
can be checked by the magnetic particle or liquid penetrant
examination method. If the magnetic particle method is used for
detecting cracks while the tank is in service, current flow (prod
techniques) should not be used because of the danger of sparks. For
this type of test, a permanent magnet or electromagnet (magnetic
flow) technique should be used.
EXTERNAL INSPECTION

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63
7.2.8.3 Caustic Cracking
If caustic or amine is stored in a tank, the tank should be checked for
evidence of damage from caustic stress corrosion cracking,
sometimes referred to as caustic embrittlement. The most probable
place for this to occur is around connections for internal heating units
or coils. This type of deterioration is manifested by cracks that start on
the inside of the tank and progress through to the outside. If this
condition exists, the caustic material seeping through the cracks will
deposit readily visible salts (usually white). Thorough cleaning and
checking with indicating solutions is necessary before welded repairs
are conducted on steel that has been affected by caustic stress
corrosion cracking. Cracking may occur during welding repairs in
such areas.
EXTERNAL INSPECTION

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64
7.2.8.4 Hydrogen Blisters (API 571)
They are found most easily by visual examination and by touch.
Visual examination should be aided by use of hand-held lighting of
sufficient candlepower (at least 100 lumens) under low ambient
lighting conditions, holding the flashlight against the shell so the
light beam shines parallel to the shell surface. Many small blisters
can be found by running fingers over the metal surface.
EXTERNAL INSPECTION

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7.2.8.5 Leaks, Crack-like Flaws, and Distortion
Leaks are often marked by a discoloration or the absence of paint in
the area below the leaks. The nature of any leaks found should be
carefully determined. If there are any indications that a leak is
believed to be due to a crack, the tank should be removed from
service as soon as possible, and a complete inspection should be
made to determine the repairs required.
Crack-like flaws can be found at the connection of nozzles to the
tank, in welded seams, and in the metal ligament between rivets or
bolts, between a rivet or bolt and the edge of the plate, at the
connection of brackets or other attachments to the tank, and at the
connection of the shell to the bottom of a welded tank.
EXTERNAL INSPECTION

7
66
Deformation can be caused by settlement of the tank, wind,
earthquake, internal pressure in the tank due to defective vents
or relief valves, an operating or induced vacuum in the tank,
severe corrosion of the shell, movement of connected piping,
improper welding repair methods, and other mechanical
damage.
Settlement or frost heave of the soil beneath a tank bottom can
cause
deformation of the shell at the bottom edge.
When a welded tank has significant deformations, weld seams may
be highly stressed and can crack. The joints most susceptible to
cracking are those at connections, at the bottom to shell joint, at
floating-roof deck lap seams, the shell-to-roof joint, and at vertical
shell seams.
EXTERNAL INSPECTION

7
67
7.2.8.6 Rivet Inspection
If the tank is of riveted or bolted construction, a number of
randomly
selected rivets or bolts should be checked for tightness.
EXTERNAL INSPECTION

7
68
7.2.9 Tank Roof Inspection
The roof or top head of a tank can be inspected for significant thinning
by ultrasonic thickness examination or even by MFL scanning (if the
roof condition is thought sound enough to withstand the weight of the
equipment). Hammer testing may dislodge scale from the internal
plate surfaces into stored product and is not a recommended method
of establishing roof plate integrity for personnel loading. Suitable fall
protection should be used when working on roofs. In general, the
inspector should always walk on weld seams if they are present,
because of the extra thickness available to support body weight.
EXTERNAL INSPECTION

7
69
Excessive gaps between the shell and the seal (s) of a floating roof
can indicate improper seal installation, altered seal condition due to
tank operations or long-term wear and tear or a malfunctioning seal
(s) due to external influences (earthquake, high winds, snow and ice).
Visual inspection may be adequate to determine seal condition, and
corrections may be possible while the tank is in service. If permanent
repairs cannot be made, the defective areas and any temporary
repairs should be noted in the records so that permanent repairs can
be made when the tank is removed from service. Seal damage can
occur if the maximum operating level is exceeded when portions of
the seal are pushed up above the top angle or plate edge.
EXTERNAL INSPECTION

7
70
Drainage systems on floating roofs should be inspected frequently
for leakage or blockage. If the drains are blocked, an accumulation
of liquid can cause floating roofs to sink or to be severely damaged.
Proper operation of check valves in drainage sumps should be
verified on a regular schedule, especially for those in fouling or
corrosive service.
Platforms and guardrails on a roof should be checked carefully in the
same manner as described earlier for stairways and ladders.
EXTERNAL INSPECTION

7
71
7.2.10 Auxiliary Equipment Inspection
Tank pipe connections and bolting at each first outside flanged joint
should be inspected for external corrosion. Visual inspection
combined with scraping and picking can reveal the extent of this
condition.
The soil around the pipe should be dug away for 6 in. - 12 in. (150 mm
- 300 mm) to allow for inspection.
Flame arrestors should be opened at appropriate intervals, and
the screens or grids should be visually inspected for cleanliness
and corrosion. Bees and mud daubers occasionally plug
arrestors.
Other auxiliary equipment should be inspected to ensure that it is
in an
operable and safe condition.
EXTERNAL INSPECTION

EXTERNAL INSPECTION OF
72
OUT-OFSERVICE TANKS
3. EXTERNAL INSPECTION OF OUT-OFSERVICE TANKS
1. External Tank Bottom Inspection
Tank bottoms that rest on pads or on soil can be reliably inspected for
soil-side corrosion using inspection technology developments such as
magnetic flux leakage (MFL) bottom scanners or robotic inspection
equipment. With these developments, tunnelling under or completely
lifting a tank just for soil-side bottom inspection should normally be
avoided. It should be remembered that inspection of a tank by lifting may
necessitate a hydrostatic test that would be unnecessary with other
methods. As it is difficult to refill a tunnel properly, tunnelling should be
applied only to locations near the edge of the tank. Clean sand or
washed gravel are the best types of fill material.

7
73
OUT-OFSERVICE TANKS
2. External Pipe Connection Inspection
same as when the tank is in service (see 7.2.5).
3. External Tank Roof Inspection
All roof plates should be checked for thickness, regardless of the external
appearance. The inside surface of the roof plates may be susceptible to
rapid corrosion because of the presence of corrosive vapors, water
vapor, and oxygen. The interiors of the pontoons or double decks on
floating roofs should be inspected visually. Metal thickness
measurements should also be taken. A bright, portable light (of at least
100 lumens) will be needed for this work.
Coupons approximately 12 in. X12 in. (300 mm X 300 mm) in size can
also be removed from the roof to check for under-side corrosion and
rafter condition. All coupons should be round or have rounded corners;
no square-cornered coupons should be cut.

7
74
OUT-OFSERVICE TANKS
7.3.3 External Tank Roof Inspection
All seals should be inspected visually for corroded or broken parts and
for worn or deteriorated vapor barriers. Any exposed mechanical parts-
such as springs, hanger systems and other tensioning devices, and
Shoes-are susceptible to mechanical damage, wear, and atmospheric or
vapor space corrosion.
Most floating-roof tanks are equipped with guides or stabilizers to
prevent rotation. These guides are subject to corrosion, wear, and
distortion and should be inspected visually. If the guides are distorted or
the roof is no longer in alignment with these guides, the roof may have
rotated excessively. The shell should then be inspected for deformations
or other defects as previously outlined in this section.

7
75
OUT-OFSERVICE TANKS
7.3.4 Valve Inspection
All valves on the tank should be inspected when the tank is out of
service. If leakage or significant deterioration is noted, consideration
should be given to valve replacement while the tank is out of service.
Valves can be refurbished if there is sufficient time during the out-of-
service period but this option could affect the return to service
schedule for the tank. Water draw-off valves should be inspected to
determine their condition.
Bonnet and flange bolts should be examined to ensure that they
have not significantly corroded and that they are tight and have
proper engagement length.

7.4 INTERNAL INSPECTION
7.4.1 Precautions
The tank must be emptied of liquid, freed of gases, and washed or
cleaned out as appropriate for the intended inspection. Appropriate
certification of the tank for personnel entry and inspection work should be
part of the permit process. Many tanks that are cleaned after removal
from service are not completely gas-free or product free unless particular
attention is paid to areas where hydrocarbon build-up can be overlooked
otherwise. Such areas include fixed roof support columns, floating-roof
legs, and guide poles all fabricated from pipe or other closed sections
without drainage holes and bearing pads or striker pads on the bottom
that may have leak paths (exhibited by product weeping). Diffusers and
other internal piping extensions inside the tank open to the product can
retain product in the piping inverts and should also be completely drained
and cleaned, and made otherwise safe prior to inspection work.
76
INTERNAL INSPECTION

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77
7.4.2 Preliminary Visual Inspection
Visual inspection is important for safety reasons since the condition
of the roof or top head and any internal supports should be
established first. The vapor space, the liquid-level line, and the
bottom are areas where corrosion will most likely be found. If large
areas are severely corroded, it may be best to have them water or
abrasive-blasted.
From a personnel safety or equipment operability standpoint, it
may be necessary to remove light coatings of oil or surface rust.
Inspectors should also be alert to accumulation of dry pyrophoric
(self-igniting when exposed to ambient conditions) material that may
ignite during inspection. These accumulations may occur on the
tank bottom, in the seal rim space areas, or on the top of rafters.
Such accumulations that cannot be cleaned out prior to inspection
should be kept moist to reduce the potential for ignition.
INTERNAL INSPECTION

7
78
7.4.3 Types and Location of Corrosion
The vapor space above the stored liquid can be an area of
significant corrosion. This is caused by the presence of corrosive
vapors, such as hydrogen sulfide, mixed with moisture and air.
The vapor-liquid interface is another region that may be subject to
accelerated corrosion, especially when fluids heavier than water
are stored.
When the stored fluid contains acid salts or compounds, they may
settle to the bottom of the tank; and if water is present, a weak
(corrosive) acid will form. Pitting-type corrosion can occur in the top
of tanks directly under holes or openings where water can enter.
The weld heat affected zone (HAZ) has been found to corrode at
an accelerated rate in relation to the surrounding shell plate
material.
INTERNAL INSPECTION

7
79
7.4.3 Types and Location of Corrosion
Among other types of deterioration that can occur on the shells
of storage tanks are hydrogen blistering, caustic stress
corrosion cracking, galvanic corrosion between dissimilar metals
in close proximity, and mechanical cracking.
These types of deterioration occur less frequently on the roofs and
bottoms of tanks. Carbon steel that contains slag inclusions and
laminations is more susceptible to hydrogen blistering. Caustic
stress corrosion cracking may occur in tanks storing caustic
products. Hot, strong caustic can also cause accelerated general
corrosion.
Areas of residual stresses from welding or areas highly stressed from
product loading are most susceptible to caustic corrosion. Such
corrosion thrives when the temperature rises above 150ºF (65ºC)
and is most likely to occur around heating coil connections at the
tank wall or at piping supports on the bottom.
INTERNAL INSPECTION

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80
7.4.4 Tank Bottoms
Good lighting is essential for a quality visual inspection. A
minimum 100-watt halogen light is usually adequate, but more
light is better. Magnetic flux leakage (MFL) inspection devices can
be used to rapidly scan for metal loss in the tank bottom plates.
Statistical methods are also available for assessing the probable
minimum remaining metal thickness of the tank bottom, and the
methods are based on a sampling of thickness scanning data. The
number of measurements taken for a statistical sampling will
depend on the size of the tank and the degree of soil-side corrosion
found.
Typically, 0.2% - 10% of the bottom should be scanned randomly.
The collection of thickness data is required to assess the
remaining bottom thickness. In addition, the outer circumference
next to the shell should be included in the statistical sampling.
INTERNAL INSPECTION

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81
7.4.4 Tank Bottoms
Seams of riveted tanks can be checked by running a thin-
bladed scraper or knife along the riveted seam.
Representative sections or coupons (minimum size 12 in. [300
mm] each way) may be taken to confirm the results of magnetic
flux leakage or ultrasonic examinations. The increasing accuracy
of magnetic flux leakage, ultrasonic scanning, and other
automated methods makes coupon removal less useful, especially
considering the time and expense associated with replacing the
coupons.
Coupons may be advisable in assessing the root cause of soil-
side corrosion.
If settlement is detected (internally or externally), the magnitude
of the settlement should be measured. (API Std 653, Appendix B,
provides guidelines for evaluation of tank bottom settlement.)
INTERNAL INSPECTION

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82
7.4.4 Tank Shell
The area of highest stress in flat bottom tanks is commonly at the
shell-to-bottom joint detail and this area can be susceptible to
corrosion. Close visual inspection for this area should be done
for evidence of corrosion or other defects. It should be noted that
a riveted shell to bottom joint using a structural angle detail is
considered a mechanical joint, not a welded joint, and may not
be suitable for certain types of examination.
INTERNAL INSPECTION

7
83
7.4.6 Testing for Leaks
The hydrostatic test will be the best method for detecting shell leaks.
If a hydrostatic test is not to be made, a penetrating oil (such as
diesel or automobile spring oil) can be sprayed or brushed on one
side of the shell plate in suspect areas and the other side can then
be observed for leakage. The liquid penetrant method used for
finding cracks can also be used in much the same manner, with the
penetrant applied to one side of the plate and the developer applied
to the other side. For either method, approximately 24 hours may be
required for leaks to become evident. Tank bottom leak detection
methods are described in Section 8.
INTERNAL INSPECTION

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84
7.4.7 Linings
Special inspection methods may be needed when the inside
surfaces of a tank are lined with a corrosion resistant material such
as steel or alloy steel cladding, rubber or other synthetic fabric,
organic or inorganic coatings, glass, or concrete (see API RP 652).
To avoid mechanical damage to the linings, considerable care should
be taken when working inside tanks lined with rubber, synthetics,
glass, or organic or inorganic coatings. Glass-lined tanks are
especially susceptible to severe damage that cannot be easily
repaired.
Concrete linings are difficult to inspect adequately, primarily because
the surface is porous. Concrete-lined steel bottoms are impractical
to inspect unless the concrete is removed.
INTERNAL INSPECTION

7
85
8. Roof and Structural Members
If corrosion is noted on the roof and upper shell, then structural
members may also be thinning, possibly at as much as twice the
rate of the thinning of the roof or shell, since both sides of the
structural members are exposed to the corrosive vapors. ( API Std
653, Appendix C).
9. Internal Equipment
Pipe coils, coil supports, swing lines, nozzles, and mixing
devices should be visually inspected.
INTERNAL INSPECTION

7.5 TESTING OF TANKS
When storage tanks are built, they are tested in accordance with the
standard to which they were constructed. The same methods can be
used to inspect for leaks and to check the integrity of the tank after repair
work. When major repairs or alterations have been completed, such as
the installation of anew tank bottom or the replacement of large sections
of shell plate, the test requirements are specified in API Std 653,
Section12.
Consideration should also be given to the notch toughness of the shell
material at the air and water temperatures existing at the time of the
test. A discussion of notch toughness and brittle fracture can be found
in API RP 571 and in API Std 653, Section 5.
86
TESTING OF TANKS

5. TESTING OF TANKS
If water is not available and if the roof of the tank is reasonably air tight
or can be made so, a carefully controlled air test using air pressure not
exceeding 2 in. (0.50 kPa) of water pressure may be applied. This type of
test is of very little use as a strength test and is used only in inspection
for leaks.
6. INSPECTION CHECKLISTS
API Std 653, Appendix C provides sample checklists of items
for consideration when conducting external and internal
inspections.
87
TESTING OF TANKS

Purpose of assessment:
1. To ensure suitability for continued /change of service.
2. To make decisions - repairs, alterations, dismantling, relocation
or reconstruction.
Factors to be considered in the assessment:
a) Internal corrosion (product/water at the bottom)
b) External corrosion.
c) Stress levels and allowable stress levels;
d) Properties of products: specific gravity, temperature, and
corrosivity;
e) MDMT.
TANK ASSESSMENT OVERVIEW
TANK ASSESSMENT
8
89

f) Roof - live load, wind, and seismic load.
g) Foundation, soil, and settlement.
h) Chemical/mechanical properties of tank material.
i) Distortions of the existing tank;
j) Operating conditions-rate/frequency of filling /
emptying.
Tank Roof Evaluation
Repair is required when
1. Roof is corroded to an average thickness < 0.09” in any
100 Sq Inch area.
2. There is a through hole in the plates.
TANK ASSESSMENT
TANK ASSESSMENT
8
90

FIXED ROOFS
1. Roof support members (rafters, girders, columns, and
bases) shall be inspected for soundness.
2. Distorted (such as out-of-plumb columns), corroded, and
damaged members shall be evaluated/repaired/ replaced if
necessary.
3. Particular attention-of severe internal corrosion of pipe
columns.
4. Frangible roof: evaluation of roof to shell joint for
compliance.
ROOF ASSESSMENT
TANK ASSESSMENT
8
91

FLOATING ROOFS
1. Cracks/punctures/holes in roof plates and pontoons
shall be repaired/affected areas replaced.
2. Pitted areas shall be evaluated & the affected areas shall
be repaired or replaced.
3. Roof support systems, perimeter seal systems,
appurtenances such as a rolling ladder, anti-rotation
devices, water drain systems, and venting systems shall
be evaluated for needed repairs or replacements.
ROOF ASSESSMENT
TANK ASSESSMENT
8
92

TANK SHELL EVALUATION
Flaws, deterioration, or other conditions (e.g. change
of service, re-location, corrosion, the original CA) that might
adversely affect the performance or structural integrity of the
shell must be evaluated and a determination made regarding
suitability for intended service.
Isolated minor pitting - normally not a concern..
API 653 -provides methods to evaluate general corrosion and
pitting.
(For other deteriorations- API 579/API 580)
SHELL EVALUATION
TANK ASSESSMENT
8
93

What is pitting?
Pitting is defined as localized regions of metal loss that can be
characterized by a pit diameter on the order of the plate thickness
or less, and a pit depth that is less than the plate thickness.
(Source API 579 Clause 6.1)
----------------------------------------------------------------------
What is general corrosion?
May be uniform corrosion.(uniform metal loss)
What is Localized corrosion or local metal loss
(Local Thin Area-LTA)?
Local metal loss on the surface of the component; the length of a
region of metal loss is the same order of magnitude as the width.
(Source API 579 clause 5.2)
SHELL EVALUATION
TANK ASSESSMENT
8
94

EVALUATION OF GENERAL CORROSION IN SHELL PLATES.
Actual Thickness Determination:
1. For each corroded area, determine the minimum thickness
(t₂ ) excluding widely scattered pits in the corroded area.
2. Calculate the critical length (L) ( L ≤ 40”)
3. L = 3.7 x √ D t₂
4. D = diameter of the tank (in feet)
5. t₂ = least thickness, in inches.
6. Measure thickness along the vertical planes
(minimum five equally spaced readings per plane)
SHELL EVALUATION
TANK ASSESSMENT
8
95

7. Determine ‘average value’ of the readings in each
plane.
8. The least of averages = t₁ (inches)
The criteria for continued operation:
t₁ ≥ tmin + CA required until the next inspection.
t₂ ≥ 60 % of tmin + CA required until the next
inspection.
SHELL EVALUATION
TANK ASSESSMENT
8
96

EVALUATION OF WIDELY SCATTERED PITS
Widely scattered pits may be
ignored when:
a) The remaining thickness under the pit shall
be ≥ one-half the minimum acceptable tank
shell thickness
b) The sum of their dimensions along any vertical
line is ≤ 2” in an 8” length.
SHELL EVALUATION
TANK ASSESSMENT
8
97

SHELL EVALUATION
TANK ASSESSMENT
8
98

The minimum shell thickness is calculated as below.
(method applicable to dia. ≤ 200’ only).
-----------------------------------------------------------------------
a) minimum thickness of an entire shell course:
tmin = [2.6 (H-1)DG] / SE
--------------------------------------------------------------------------
b) minimum thickness at a locally thinned area
or any other location of interest.
tmin = [2.6 HDG] / SE
--------------------------------------------------------------------------
tmin = minimum acceptable thickness, in inches
for each course.(not < 0.1” for any course)
D = nominal dia. of tank, in feet.
G = highest specific gravity of the contents;
SHELL EVALUATION
TANK ASSESSMENT
8
99

H = height from the bottom of the shell course under
consideration to the maximum liquid level when
evaluating an entire shell course, in feet.
or
height from the bottom of the length L (see 4.3.2.1)
from the lowest point of the bottom of L of the
locally thinned area to the maximum liquid level, in
feet.
or
height from the lowest point within any location of
interest to the maximum liquid level, in feet (ft);
SHELL EVALUATION
TANK ASSESSMENT
8
100

S = maximum allowable stress in psi.(Listed in Table 4.1 )
NOTE : for reconstructed tanks, S value is from the
current applicable standard;
E = the original joint efficiency for the tank.
(Table 4.2 if original E is unknown)
E = 1.0 when evaluating the retirement thickness in a
corroded plate, away from welds or joints
by at least the greater of 1 in. or twice the plate
thickness.
SHELL EVALUATION
TANK ASSESSMENT
8
101

If the tank will be hydrostatically tested, the hydrostatic
test height, Ht, shall be limited by one of the following
methods.
The tank shall not be filled above the level determined by the
lesser value of Ht
determined below.
a) After determining the controlling thickness
of an entire shell course, Ht calculated as follows:
SHELL EVALUATION
TANK ASSESSMENT
8
102

b) After determining the controlling thickness by 4.3.2.1
for a locally thinned area, or at any other location of interest
within a shell course, Ht is calculated as follows:
SHELL EVALUATION
TANK ASSESSMENT
8
103

Ht = the height from the bottom of the shell course
under consideration to the hydrostatic test height
when evaluating an entire shell course in feet;
or
the height from the bottom of the length, L, for the
most severely thinned area in each shell course to
the hydrostatic test height in feet;
or
is the height from the lowest point within any other
location of interest to the hydrostatic test height in
feet;
St = max. allowable hydrostatic test stress in psi
(Table 4.1)
SHELL EVALUATION
TANK ASSESSMENT
8
104

NOTE : For reconstructed tanks, St value is from
current applicable standard.
Alternatively, the minimum shell thickness of tanks
dia. ≤ 200 ft may be calculated using variable
design point method.
SHELL EVALUATION
TANK ASSESSMENT
8
105

SHELL EVALUATION
TANK ASSESSMENT
8
106

DISTORTIONS
Shell distortions:
1. Out-of-roundness,
2. Buckled areas,
3. Flat spots, (measured in vertical plane)
Causes of shell distortions:
1. Foundation settlement,
2. Over or under pressuring,
3. High wind,
4. Poor shell fabrication, or repair techniques, etc.
Shell distortions shall be evaluated on an individual
basis.
SHELL EVALUATION
TANK ASSESSMENT
8
107

FLAWS
Flaws:
1. Cracks or laminations -thorough examination and evaluation
to determine nature and extent and need for repair.
2. If repair needed-develop/implement repair procedure.
3. Scars (arc strikes, gouges, or tears from temporary attachment
welds)- evaluation case-by-case basis.
4. Cracks in the shell-to-bottom weld shall be removed.
SHELL EVALUATION
TANK ASSESSMENT
8
108

Wind Girders and Shell Stiffeners
Degradation by corrosion renders these elements
inadequate for the design conditions.
Shell Welds
Deteriorated welds due to corrosion or pitting must be
evaluated and appropriate repair procedures established
or the tank rerated as necessary.
ASSESSMENT
TANK ASSESSMENT
8
109

SHELL PENETRATIONS
The condition and details of existing shell penetrations (nozzles,
man-ways, cleanout openings, etc.) shall be reviewed when
assessing the integrity of an existing tank shell.
Existing shell welds that are not modified or affected by
repairs and are closer than required by API 650 (7th
or later
edition) are acceptable when no defects noted by MPI.
Nozzle wall thickness shall be evaluated for pressure and
all other loads.
SHELL EVALUATION
TANK ASSESSMENT
8
110

TANK BOTTOM EVALUATION
General
Tank bottom is assessed
1. To prevent leakage causing environmental damage.
2. Each aspect of corrosion phenomena, and other
potential leak or failure mechanism must be
examined.
3. Excessive foundation settlements affect the integrity
of shells and bottoms.
4. Monitoring the settlement is a recognized
practice to assess the integrity.
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
111

CAUSES OF BOTTOM FAILURE:
a) Product side/soil side corrosion (thinning, pitting.)
b) Corrosion of weld joints (weld/HAZ)
c) Weld joint cracking.
d) Stresses on the bottom plates due to
Roof support loads and shell settlement;
e) Inadequate drainage under the tank bottom;
f) The lack of an annular plate ring when required;
g) Uneven settlement (high localized stresses in
The bottom plates)
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
112

h) Roof support columns or other supports welded to the
tank bottom where adequate allowance for movement was not
made;
i) Rock or gravel foundation pads with inadequately filled-
in surface voids;
j) Non-homogeneous fill under the bottom
(a lump of clay in a sand foundation);
k) Inadequately supported sumps.
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
113

Tank Bottom Release Prevention Systems (RPSs)
Purpose: to maintain tank integrity/protect
the environment.
These include:
1. Internal inspection of tank bottom;
2. Leak detection systems and leak testing of the tank;
3. Cathodic protection
4. Lining interior
5. Providing a release prevention barrier (RPB) or
6. Combination of these measures, depending on the
operating environment and service of the tank.
Internal Inspection
To assess the bottom integrity and identify
conditions that may lead to future loss of integrity.
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
114

Leak Detection Systems and Leak Testing
Purpose:
to identify, quantify, and/or locate a tank bottom
failure not detectable visually.
Release Prevention Barriers (RPBs)
Includes - steel bottoms, synthetic materials,
clay liners, concrete pads, etc placed under a tank,
Functions of RPB:
1) prevents the escape of released material,
2) contains or channels the released material
for leak detection.
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
115

BOTTOM PLATE THICKNESS MEASUREMENTS
Magnetic flux leakage (MFL) and UTG - commonly used.
UTG is to confirm and quantify MFL data.
The quality of the data depends on
1. personnel,
2. equipment
3. procedures.
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
116

METHOD TO CALCULATE THE MINIMUM ACCEPTABLE
THICKNESS OF THE BOTTOM/PORTIONS
MRT = min. remaining thickness at the end
of interval Or .
MRT = (Minimum of RTbc or RTip) – Or (StPr + Upr)
Or = in-service interval of operation
(years to next internal inspection)
RTbc = min. remaining thickness from ‘bottom side
corrosion’ after repairs;
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
117

RTip = min.remaining thickness from ‘internal corrosion’
after repairs;
StPr = max. rate of corrosion not repaired on the top side.
StPr = 0 for coated areas of the bottom.
UPr = max. rate of corrosion on the bottom side.
UPr = 0 for areas that have effective CP.
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
118

UNLESS A STRESS ANALYSIS IS PERFORMED,
the minimum bottom plate thickness in the
critical zone shall be
the smaller of
1. Half the original bottom thickness (excluding CA)
2. 50 % of tmin of the lower shell course,
(but not < 0.1”)
Isolated pitting will not affect the strength appreciably.
The thickness at the toe of the outside bottom-to-shell weld
shall be ≥ 0.1”
The projection of the bottom beyond the outside
toe of the shell-to-bottom weld shell shall be ≥ 3/8”.
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
119

BOTTOM ASSESSMENT
TANK ASSESSMENT
8
120

MINIMUM THICKNESS FOR ANNULAR PLATE RING
The annular ring is required to increase strength The
min.thickness of annular ring is usually > 0.1”. Unless a
stress analysis is performed, the annular plate thickness
shall be in accordance with 4.4.6.2 or 4.4.6.3, as
applicable.
Case 1: Specific gravity < 1 (refer to clause 4.4.6.2)
Case 2: Specific gravity ≥ 1 (refer to clause 4.4.6.3)
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
121

Case 1:
4.4.6.2 - product specific gravity < 1.0,
- annular plate is required for other than
seismic loading.
- the thickness of the annular plates shall
be not be < than the thicknesses given in
Table 4.5, plus CA.
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
122

THICKNESS EXCLUDING CORROSION ALLOWANCE
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
123

Case 2:
4.4.6.3 - specific gravity ≥ 1.0.
- annular plate is required for other than
seismic loading
- the thickness of the annular plates shall be in
accordance with API 650, Table 5-1, plus CA.
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
124

API 650 TABLE 5-1 a
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
125

API 650 TABLE 5-1 b
BOTTOM ASSESSMENT
TANK ASSESSMENT
8
126

TANK FOUNDATION EVALUATION
Principal causes of foundation deterioration
1.Settlement
2.Erosion,
3.Cracking, and
4.Deterioration of concrete initiated
by:
calcining,
attack by underground water,
attack by frost, and
attack by alkalies and acids.
FOUNDATION ASSESSMENT
TANK ASSESSMENT
8
127

MECHANISMS OF CONCRETE DETERIORATION
a) Calcining (loss of water of hydration)
-exposure to sufficiently high temperature
for a period of time.
-during intermediate cooling, the concrete absorbs
moisture, swells, loses its strength, and cracks.
b) Deterioration of concrete exposed to underground water
can be caused by
Chemical attack,
Cyclic changes in temperature, and
Freezing moisture;
TANK ASSESSMENT
8
128

c) Expansion of freezing moisture in porous concrete
or concrete with minor settlement causes cracks.
Temperature cracks:
can result in spalling and/or the development
of serious structural cracks;
d) sulfate-type alkalies, and to a lesser extent, chlorides,
can act corrosively to destroy the bond of the concrete;
TANK ASSESSMENT
8
129

e) temperature cracks (hairline cracks of uniform width) do not
seriously affect the strength of the concrete foundation
structure;
however, these cracks can be potential access points for
moisture or water seepage that could eventually result in
corrosion of the reinforcing steel.
TANK ASSESSMENT
8
130

Failure of a tank due to brittle fracture occurs, either
1. During first hydrostatic test or on the first filling
in cold weather,
2. After a change to lower temperature service,
or after a repair/ alteration.
So once a tank has demonstrated the ability to withstand the
combined effects of maximum
liquid level (highest stresses) and lowest operating temperature
without failing, the risk of failure due to brittle fracture with
continued service is minimal.
BRITTLE FRACTURE ASSESSMENT
TANK ASSESSMENT
8
131

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.
For unheated tanks, the shell metal temperature shall be the
design metal temperature.
TANK ASSESSMENT
8
132

TANK ASSESSMENT
8
133

Tank Repairs &
Alterations
13
4
9
134

All repairs must be authorized by AI or storage tank
engineer prior to commencement by a repair organization.
Authorization for alterations may not be given without
prior consultation with, and approval by the engineer
The AI
- shall designate hold points.
- shall specify minimum documentation on
completion.
- may give prior general authorization for
limited or routine repairs not requiring
hydrostatic test or an engineering
evaluation.
TANK REPAIR & ALTERATION
9 Repairs & Alteration
135

All proposed design, work execution, materials,
welding procedures, examination, and testing
methods must be approved by the AI or by an
engineer.
The AI or an engineer shall approve all specified
repair and alteration work at the designated hold
points and after repairs and alterations have been
completed in accordance with the requirements of
this standard.
136

REMOVAL AND REPLACEMENT OF SHELL PLATE MATERIAL
The min. thick of the replacement shell plate shall be calculated
in accordance with the as-built standard.
The thickness of the replacement shell plate shall not be less
than the greatest nominal thickness of any plate in the same
course adjoining the replacement plate except where the
adjoining plate is a thickened insert plate.
The minimum size of a replacement shell plate-
- greater of 12” or 12 x thickness of the
replacement plate. (rounded corners of Radius)
a. 6” for t ≤ 0.5”
b. greater of 6”or 6t for t > 0.5”
137

Prior to welding the new vertical joints, the existing
horizontal welds shall be cut for a minimum
distance
of 12 in. beyond the new vertical joints.
The vertical joints shall be welded prior to welding
the horizontal joints.
Weld the shell-to-bottom weld last.
The areas to be welded shall be ultrasonically
inspected for defects and remaining thickness.
138

Lapped patch repair plates may be used
1. for the closure of holes caused by the removal of
existing shell openings or the removal of severely
corroded or eroded areas.
2. to reinforce areas of severely deteriorated shell
plates that are not able to resist the service loads.
3. for shell plates that are below the retirement
thickness.
4. to repair small shell leaks, or minimize the
potential from leaks from severely isolated or
widely scattered pitting.
139

The repair plate thickness selection shall be
based on a design that conforms to the as-built
standard and API 653, using a joint efficiency not
exceeding 0.70.
The minimum repair plate dimension shall be 4” with a
minimum overlap of 1” and a maximum overlap of 8
times the shell thickness (8t).
The repair plate thickness shall not exceed the nominal
thickness of the shell plate adjacent to the repair.
140

 The repair plate thickness shall be based
on a design that conforms to the as-built
standard and API 653, using a joint efficiency not
> 0.35.
 The repair plate thickness shall not exceed
the shell plate thickness at the perimeter of the
repair plate by more than one-third, but no
more than 1/8 in.
 The repair plate thickness not to exceed
½”.
141

• The remaining strength of the deteriorated
areas under the repair plate shall not be
considered in the calculation of service or
hydro-test loads.
• Lapped patch repair plates may be used to repair
small shell leaks, or minimize the potential from
leaks from severely isolated or widely scattered
pitting if the following requirements are
satisfied.
142

REPAIR OF DEFECTIVE WELDS
• Cracks, lack of fusion, and rejectable slag and porosity
needing repair shall be removed completely by gouging
and/or grinding and the resulting cavity properly prepared
for welding.
• Generally, it is not necessary to remove existing weld
reinforcement in excess of that allowed by API 650 when
discovered on an existing tank with a satisfactory service
history.
• Existing weld undercut deemed unacceptable shall be
repaired by additional weld metal, or grinding, as
appropriate.
143

Welded joints that have experienced loss of metal due to
corrosion may be repaired by welding.
Arc strikes discovered in or adjacent to welded joints
shall be repaired by grinding and/or welding. Arc strikes
repaired by welding shall be ground flush with the plate.
144

REPAIR OF SHELL PENETRATIONS
• Repairs to existing shell penetrations shall be
in compliance with API 650.
• Reinforcing plates may be added to existing
unreinforced nozzles when deemed appropriate The
reinforcing plate shall meet all dimensional and weld
spacing requirements of API 650.
• As an alternative, the reinforcing plates may be
added to the inside of the tank provided that
sufficient nozzle projection exists.
145

146

147

ADDITION OR REPLACEMENT OF SHELL PENETRATIONS
New shell penetrations (addition or replacement) shall be in
accordance with material, design, and stress relief
requirements of API 650.
The required reinforcement area shall be calculated as per API
650, except the variable S shall be the allowable design
stress from Table 5-2 of API 650 for the existing shell
plate.
Use 20,000 psi, for unknown materials.
A joint efficiency of 1.0 may be used (see 9.8.5).
The variable H shall be the height from the
centerline of the penetration to the maximum
liquid level, in ft.
Repairs & Alteration
148

The following erection requirements shall be met:
a) if an integral reinforcement design is used, the insert plate at
its periphery shall have a 1:4 reduction taper to match the
shell plate thickness when the insert plate exceeds the shell
plate thickness by more than 1/8 in.
b) spacing of welds - in accordance with Figure 9.1
c) the new insert plate shall be joined to existing shell plate with
full penetration and full fusion butt welds.
Examinations shall be per Section 12. (and
penetrations located on a shell joint shall
receive additional radiography.
(RT for a length = 3 x diameter of the opening,
(API 650,Section 5.7.3.)
149

Penetrations larger than 2 NPS shall be installed with the use of an
insert plate if the shell plate thickness is greater than 1/2 in.
and the shell plate material does not meet the current
design metal temperature criteria.
In addition, the following requirement shall be met:
a) the minimum diameter of the insert plate shall be at least
twice the diameter of the penetration or the diameter plus 12
in., whichever is greater;
b) when reinforcing plates are used, the minimum diameter of the
insert plate shall equal the diameter of the reinforcing plate
plus 12 in.
150

ALTERATION OF EXISTING SHELL PENETRATIONS
Alteration shall comply with API 650.
Installation of a new tank bottom above the existing bottom,
may require alteration of
existing penetrations in the bottom course.
The existing reinforcing plate may be trimmed to increase
the spacing between the welds provided that the
altered detail complies with the requirements of API
650.
151

The existing re-pad may be removed and a new one
added.(re-pad is not permitted on existing stress relieved
assemblies.)
When not known that the assembly was stressed
relieved, then the alteration shall meet the requirements
of API 650,(Section 5.7.4.-thermal relief)
When the upper half of the existing re-pad meets
all requirements of API 650, it can be left in place with
approval of the purchaser.
Only the lower half of the existing re-pad need be
removed and replaced with the new one.
152

The new re-pad is provided with a new telltale hole if needed.
The shell plate thickness under the telltale hole shall be checked
after drilling and the thickness shall not be less than 1/2 tmin plus
any required CA.
The welds to be replaced around the perimeter of the reinforcing
plate and between the reinforcing plate and neck of the penetration
shall be completely removed by gouging and grinding.
The new reinforcing plate shall be in accordance with Figure 9.3. If
required to maintain weld spacing, a tombstone shaped reinforcing
plate may be used (see Figure 9.4).
153

154

155
155

The existing penetration may be moved by cutting
the section of the shell containing the fitting and
reinforcing plate, and raising the entire assembly
to the correct elevation (see Figure 9.5).
Repairs & Alteration
156

157

REPAIR OF TANK BOTTOMS
Welded-on patch plates permitted within
certain limitations. (Fig 9.9 - acceptable details)
a) The min. dimension of the plate that overlaps
a bottom seam or existing patch is 12 in.
May be of any shape with rounded corners
(minimum radius of 2 inch)
b) A smaller welded-on patch diameter ≥ 6 inch is permitted
1. if it does not overlap a bottom seam;
2. it is not placed fully or partially over an
existing patch; and
3. it extends beyond the corroded bottom area,
if any, by at least 2 in.
158

159

REPAIRS WITHIN THE CRITICAL ZONE
a) Max. plate thickness is ¼” and must meet toughness requirements
of API 650.
b) When a welded-on patch plate is within 6 in. of the shell, the
welded-on patch plate shall be tombstone shaped.
c) Welds- min two-pass and examination of each pass –visual and PT
or MT.
d) Installation of a welded-on patch plate by butt-welding to an
adjacent existing patch is not permitted.
e) Patch plates over existing patches are not allowed in
the critical zone.
160

Patch plates -NOT permitted in the critical zone when the
operating temperature exceeds 200 °F for CS
or 100 °F for SS.
If more extensive repairs are required within the critical
zone the bottom plate welded to the shell
shall be replaced.
The shell-to-bottom weld shall be removed and replaced
for a minimum distance of 12 in. on each side
of the new bottom plate.
161

Welded-on patch plates not meeting the requirements are
permitted if the repair method has been reviewed and
approved by an engineer.
The review shall consider brittle fracture, stress due to
settlement, stress due to shell bottom discontinuity,
metal temperature, fracture mechanics, and the extent
and quality of NDE.
Unacceptable indications such as cracks, gouges, tears, and
corroded areas in bottom plates, located outside the
critical zone, may be repaired by deposition of weld
metal.
162

The repair of corroded plates in the critical zone is limited to pit
welding or overlay welding under the following
conditions.
a) The sum of the pit dimensions along an arc
parallel to the shell-to-bottom joint does not
exceed 2 in. in an 8-in. length.
b) There must be sufficient thickness (at least 0.1”)
for completion of a sound weld and to avoid burn
through.
A lesser thickness is permitted only if
reviewed and approved by an engineer .
c) All weld repairs shall be ground flush and
be examined.(root/final pass by PT or MT.
Additionally annular butt final pass by UT.)
163

REPLACEMENT OF TANK BOTTOM PLATES
Suitable noncorrosive material cushion such
as sand, gravel, or concrete shall be used
between the old bottom and the new
bottom.
The shell shall be slotted with a uniform cut
made parallel to the tank bottom. The new
bottom plate shall extend outside the shell as
required by API 650.
All rules for weld spacing shall be followed.
164

Existing shell penetrations shall be raised or their re-pads
modified if the elevation of the new bottom results
in inadequate nozzle reinforcement/ weld space
requirements ( as given in API 650.)
For floating roof tanks, the support legs can either remain the
same or be shortened.
New bearing plates for roof support legs and for fixed roof
support columns shall be installed. For internal floating roofs with
aluminum supports, new austenitic stainless steel or acceptable
non-metallic (e.g. Teflon® 6) spacers shall be added to isolate
supports from the carbon steel bottom.
165

When removing an existing tank bottom, the tank shell shall be
separated from tank bottom either by:
a) cutting the shell parallel to the tank bottom a
minimum of 1/2 in. above the bottom-to-shell weld
(cut line B-B as shown in Figure 10.1), or
b) removing the entire shell-to-bottom attachment
weld, including any penetration and HAZ by arc
gouging and/or grinding etc.
All arc-gouged areas of the tank shell-to-bottom weld
shall be magnetic particle examined, and defective
areas repaired and re-examined.
166

For tanks with shell plate of unknown toughness , new weld joints
in the bottom or annular ring shall be spaced at least
the greater of 3 in. or 5t from existing vertical weld
joints in the bottom shell course, where t is the
thickness of the bottom shell course, in inches.
Replacement of portions of an existing tank bottom (entire
rectangular plates or large segments of plates) not
within the critical zone are permitted under the same
rules per API 650.
167

For tank materials having 50,000 psi yield strength or less,
existing shell penetrations need not be raised if the
following conditions are met.
a) For reinforced penetrations, including low-types, a
minimum of 4” shall be maintained between the shell-to
bottom weld toe and the nearest penetration attachment
weld toe (reinforcing plate periphery weld, or nozzle neck
weld to low type reinforcing plate and shell welds).
b) For self-reinforced penetrations, the greater of 3” or 21/2t
shall be maintained between the shell-to-bottom weld toe
and the nearest penetration attachment weld toe.
168

c) The shell-to-bottom weld is to be welded with low hydrogen
electrodes and with welding procedures limiting distortion
and residual stress.
d) The toes of the welds shall be blend-ground to minimize stress
concentrations as follows.
i) For circular reinforcing plates, blend-grind the periphery
attachment weld from the “four o'clock” position to the
“eight o'clock” position.
Blend-grind the inside and outside of the shell-to-bottom
weld a minimum of one penetration diameter length on
either side of the penetration centerline.
169

ii) For diamond-shaped reinforcing plates, blend-grind the
lower horizontal length of the diamond shaped attachment
weld.
iii) For low-type penetrations, blend-grind the nozzle
attachment weld (shell and reinforcing plate) from the
“four o'clock” position to the “eight o'clock” position.
170

e) The blend-ground lengths of welds listed above
shall be magnetic particle examined before and
after hydrostatic test.
Additional Welded-on Plates
If other welded-on plates such as wear, isolation, striker, and
bearing plates, are to be added to tank bottoms, they shall be
installed in accordance with 9.10.1, and examined in accordance
with 12.1.7.
For these additional welded-on plates, if the lap weld
spacing requirements not met, magnetic
particle (MT) or Liquid Penetrant (PT) examination is
required for the exposed welds or portions of welds failing to
meet minimum spacing criteria.
171

Repair of Fixed Roofs
Roof repairs shall meet the requirements of API 650
External Floating Roofs
Repair method shall restore the roof to a condition enabling it to
perform as required.
Internal Floating Roofs
Repairs as per original construction drawings.
If the drawings are not available, the roof to be repaired to App
H of 650.
172

Primary Seals
Rim-mounted primary shoe seals and toroidal seal systems
can be removed, repaired, or replaced.
To minimize evaporation losses and reduce potential hazard
to the workers, no more than one-fourth of the roof seal
system should be removed an in-service tank at one time.
Installation of Primary and Secondary Seals.
If the roof rim thickness is less than 0.1” thick, it shall be
replaced. The new roof rim shall be 3/16-in. thickness,
minimum.
173

HOT TAPS (RADIAL HOT TAPS)
NOT permitted on shell requiring thermal
stress relief.
For tank shell plates of recognized toughness, the
connection size and shell thickness limitations are shown in
Table 9.1.
For shell plates of unknown toughness, the
following limitations apply.
1) Nozzle dia ≤ NPS 4
2) The shell plate temperature shall be at or above
the minimum shell design metal temperature for
the entire hot tapping operation.
174

3) All nozzles shall be reinforced (per API 650)
minimum thick of re-pad = shell thickness.
minimum dia of re-pad = dia of cutout + 2”
4) The maximum height of tank liquid above the hot tap location
during the hot tapping operation shall be such that the
hydrostatic tank shell stress is less than 7,000 lbf/in.2 at the
elevation of the hot tap.
5) The minimum height of tank liquid above the hot
tap location shall be at least 3 ft during the hot tapping
operation.
175

6. Hot taps
a) not permitted on roof or in gas/vapor space.
b) not to be installed on laminated/severely pitted
shell plate.
c) not permitted on tanks where the heat
of welding may cause environmental cracking .
(Eg: caustic cracking or SCC.)
176

177

10
179
Records & Reports
1. GENERAL
Good records form the basis of an effective inspection program and
allow for properly scheduled inspections. Accurate and
complete records help predict when repairs and replacements
may be needed, reducing the potential for safety and
environmental hazards.
2. RECORDS AND REPORTS API Std 653
A complete record file should consist of at least three
types of records:
a) design and construction records,
b) repair/alteration records, and
c) inspection records.
RECORDS

10
180
Form & Organization
3. FORM AND ORGANIZATION
The report should clearly breakdown the following categories
of recommendations:
a.Those areas that require immediate repair or change that are
mandatory in order to maintain the continued safety, health and
environmental concerns of the facility and that should not be
delayed.
b.Those areas that should be repaired to extend the tank life
that may fail before the next internal inspection.
c.Those areas that can be deferred until the next internal
inspection without jeopardizing health, environment or
safety and that the owner/operator wants to defer.
d.Those items that are strictly non-threatening areas of concern
such as cosmetic issues, settlement that is within the API Std
653 tolerances.
All recommendations should be backed up with supporting
calculations, photos and the rationale for such recommendations.
RECORDS

9
182
Ultrasonic Thickness
(UT) Measurement
A.1 Ultrasonic Thickness (UT) Measurement
Dual-element transducers can have the ability to measure thin
sections from 0.050 in.-1.000 in. (1.3 mm Ð 25 mm).
Holes in the material or sections of less than 0.050 in. (1.27 mm)
measured with too low a frequency will provide either no reading
or a false reading.
Epoxy coatings have a velocity approximately half that of the steel,
so that the ultrasonic tool will read the epoxy coating thickness
as twice its
actual thickness (0.015 in. [15 mils] epoxy would read as 0.030 in. [30
mils]). Selection of a single-crystal transducer operating in the so-
called echo-to-echo mode can prevent this coating thickness error.
However, the single-crystal transducer has poor resolution for
small diameter deep pits.
APPENDIX A

9
183
Integrity of Repairs
2. Ultrasonic Corrosion Testing
(ASME) recommends 10% minimum overlap for readings based
on the transducer diameter. Large diameter transducers will not
find small diameter deep corrosion pits.
3. Ultrasonic Shear Wave Testing
Shear wave inspection can be used to assist in the discrimination
between laminations and inclusions in material. Automated
shear wave is especially effective for this purpose. The most
general application of shear wave transducers is to detect
defects in butt- welded joints, usually in lieu of radiography.
APPENDIX A

9
184
Integrity of Repairs
4. Magnetic Flux Leakage Bottom Inspection
The user should make sure that the scanner is calibrated properly
and has a validation and/or calibration test plate. A primary
advantage of these tools is the ability to detect product-side
pitting, soil-side corrosion, and holes in the tank bottom in an
efficient and economical manner. All of the systems require some
additional inspection to quantify detected flaws.
5. Robotic Inspection
These robotic crawler devices are designed for total immersion in
liquids and have been successful in providing ultrasonic thickness
information on tank bottoms in clear finished product storage such
as gasoline, naphtha and some crude oil. This equipment needs
to be used under carefully controlled circumstances and within
API safety guidelines for work on tanks in service.
APPENDIX A

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