TABLE OF CONTENTS
LIST OF SUBJECTS
THE PRACTICAL APPROACH TO REFINERY
STORAGE TANK INSPECTION
REFERENCE
API GUIDE FOR INSPECTION OF REFINERY EQUIPMENT
CHAPTERS II and XIII
CORROSION AND CORROSION CONTROL, 2nd Edition
By: HERBERT H. UHLIG
CORROSION ENGINEERING, 2nd Edition
By: FONTANA and GREEN
ASME SEC. V NON-DESTRUCTIVE EXAMINATION 2013 Ed.
NACE SURFACE PREPARATION HANDBOOK
API 650 Welded Tanks for Oil Storage,
12th Ed., ERRATA 2, Dec. 2014
API 653 Tank Inspection, Repair, Alteration, and Reconstruction,
5TH Ed. Nov. 2014
TABLE OF CONTENTS
INTRODUCTION
CODES and HISTORY
1.0 CHECKLIST INSPECTION
2.0 CHECKLIST FORM
3.0 THE INSPECTOR
4.0 INSPECTION REPORT AND RECORD
5.0 FREQUENCY OF INSPECTION
6.0 NON-DESTRUCTIVE EXAMINATION IN TANKAGE
6.1. LIQUID PENETRANT METHOD
6.2. MAGNETIC PARTICLE EXAMINATION
6.3. ULTRASONIC INSPECTION
6.4. INDUSTRIAL RADIOGRAPHY
6.5. MAGNETIC FLUX LEAKAGE TEST
6.6. Phased Array Ultrasonic Testing (PAUT) in Lieu of Radiography
7.0 OTHER METHODS OF TESTING
PNEUMATIC LEAK TEST
HYDROSTATIC TEST
8.0 LOCATING LEAKS ON TANK FLOOR
VACUUM TESTING
FLOODING METHOD: a. INTERNAL FLOODING
b. EXTERNAL FLOODING
9.0 PRACTICAL TEST FOR ATMOSPHERIC TANKS
10.0 DETERIORATION OF STEEL TANKS
11.0 APPROACH TO TANK INSPECTION
12.0 SAFETY IN TANK INSPECTION
13.0 PRACTICAL WAYS OF SUPRESSING CORROSION IN TANKAGE
14.0 Tank Farm Corrosion Control Using Cathodic Protection
APPENDIX I
SUGGESTED APPROACH TO REFINERY TANK
EXTERNAL INSPECTION
APPENDIX IIa OUTLINE OF THE COMMON FORMS OF CORROSION
AND MAJOR CORROSION PROMOTING SUBSTANCES
INSIDE REFINERY STORAGE TANKS
APPENDIX IIb SUGGESTED APPROACH TO REFINERY TANK
INTERNAL INSPECTION
APPENDIX III
SAMPLE REPORT A AND B
APPENDIX IV
RETIRING LIMITS OF PLATE THICKNESS
APPENDIX V
SUGGESTED APPROACH FOR FLOOR RENEWAL OF
SMALL CAPACITY TANKS (20, 000 – 30, 000 bbls.)
APPENDIX VI
MAINTENANCE PAINTING GUIDELINE
APPENDIX VII MISCELLANEOUS DATA AND TABLES
APPENDIX VIII NDE Requirements Summary API 653 Table F.1
APPENDIX IX
NDE Requirements Summary API 650 Annex T
Copyright 2000
All Rights Reserve
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INTRODUCTION
In service, steel tanks are bound to fail and the cause of failure is
principally blamed to corrosion. Although broken parts can be considered
another cause of failure. It is generally attributed to the weakening effects
of corrosion unless breaking its caused by any mechanical means or natural
disaster like earthquake.
Tanks built before 1945 may be of a riveted construction. Tank built up
to about 1965 BS 2654 have tank shells designed with a joint efficiency
factor of 0.85 and the weld would only have been inspected visually during
construction.
After 1965 it became normal practice to have shells designed with a
joint efficiency factor of 1.00 and with weld quality inspected by spot
radiography during construction.
Basically, the rate of corrosion in tankage is dependent on the type of
atmospheric condition to which the tank is exposed and the type of service
it is employed. It is therefore important that periodic inspection is carried
out so that remedial measures can be taken before serious deterioration of
the tank develops.
This booklet is divided into 13 equally important sections and the
presentations are made in such a manner that a practical approach to tank
inspection can be followed. Because it is considered difficult to work by
memory alone, the used of an inspection checklist is emphasized.
Considering that good inspection requires good Inspector, the criteria of the
qualifications and characteristics of the Inspector are given. Blaming
corrosion in most failures of the tank, the principal type of corrosion and the
major promoting substances in tankage are briefly viewed.
Because atmospheric vertical storage tanks are the most common
Petroleum refineries, discussions of methods in suppressing corrosion and
safety practices are primarily based on these tanks. Likewise, the
illustrations for non-destructive examinations and testing considered to be
practical are referred to the same type of tanks namely the Cone Roof and
the Annular Pontoon Floating Roof tanks. See figures 1 and 2 respectively.
CODES and HISTORY
Conventional atmospheric or low-pressure storage tanks are generally
built in accordance with the following codes
-
-
British Standard, BS 2654 (Manufacture of Vertical Welded NonRefrigerated Storage Tanks with Buut-Welded Shells for the
Petroleum Industry)
American Standard, API Std 650 (Welded Steel Tanks for Oil
Storage
German Code, DIN 4119-1 and -2 (Aboveground Cylindrical Flatbottomed Tank Installation of Metallic Material
French Construction code, CODRES (code Francias de
Construction des Reservoirs Cylindriques Verticaux en Acier
UCSIP et SNCT
2
3
4
5
1.0
CHECKLIST INSPECTION
2.0
In checklist inspection, visual inspection, which is the primary nondestructive examination, is first performed. The inspector walks around the
tank and notes down all his initial findings on the checklist. He is usually
equipped with the following inspection tools:
1.
2.
3.
4.
5.
6.
7.
8.
Checklist form, pencil and hardboard
Marker such as chalk or crayon
Inspection mirror and magnifying lens
Flashlight
Pit gauge, ruler or caliper
Pocket knife or scrapper, inspection digger
Ball peen hammer
Ultrasonic thickness measuring device
After completing the checklist, the inspector reviews the part that seems
to be in poor condition. In some cases, applicable non-destructive
examinations are conducted just to confirm this condition. Good judgment
is of utmost importance, otherwise unnecessary and costly repairs may
arise.
CHECKLIST FORM
Two forms are generally used: the external and internal checklists. The
simplest form being considered is the one where in the tank parts are listed
according to accessibility. Like the foundation it is listed no. 1 because this
is the most accessible part of the tank. The shell is always no. 2 because
bulges, buckles and paint failures are visible even at a distance. Moreso,
its inspection can be performed almost simultaneously with the foundation.
Next to the shell are the stairways and platforms. The no. 4 is the roof.
Manways, nozzles, valves can be listed last or under the headings of the
parts where they are attached.
The form should include the following tank data:
1.
2.
3.
4.
5.
6.
7.
Identification and the tank location
Service of the tank
Nominal and safe filling heights
Nominal and safe filling capacities
Tank inside diameter
Date tank last cleaned
For gasoline tanks, leaded must be indicated
See sample checklist forms or check API 653 Annex C
6
7
PONTOON FLOATING ROOF TANK
INTERNAL INSPECTION CHECKLIST
PONTOON FLOATING ROOF TANK
INTERNAL INSPECTION CHECKLIST
DATE ____________________
NO _________________________
TANK IDENTIFICATION _________ SERVICE _______ AREA ___________
NOM. CAPACITY _____________ SAFE FILLING CAPACITY _____________
INSIDE DIAMETER ______ HEIGHT ______ SAFE FILLING HEIGHT _______
DATE TANK LAST INSPECTED _______ DATE TANK LAST CLEANED______
INSPECTED BY ____________________ OTHERS: _____________________
DATE ____________________
NO _________________________
TANK IDENTIFICATION _________ SERVICE _______ AREA ___________
NOM. CAPACITY _____________ SAFE FILLING CAPACITY _____________
INSIDE DIAMETER ______ HEIGHT ______ SAFE FILLING HEIGHT _______
DATE TANK LAST INSPECTED _______ DATE TANK LAST CLEANED______
INSPECTED BY ____________________ OTHERS: _____________________
PARTS
CONDITION
REMARKS
1. Foundation
2. Shell
a. Paint
b. Thickness
c. Manway/Clean-out
Door & Others
3. Stairway/Platform &
Handrail
4. Roof
a. Paint
b. Pontoon
c. Manholes
d. Drains
e. Vents
f. Roof Leg Sleeve
g. Anti Rotation Sys.
h. Foam Dam
i. Others
5. Rolling Ladder & Track
6. Windgirder/Walkway &
Handrail
7. Nozzles/Valves
8. Level Gauge
9. Nameplate/Base
Miscellaneous
VP-Very Poor; P-Poor; F-Fair; G-Good; N-Not Accessible/Not Inspected
PARTS
CONDITION
REMARKS
1. Tank Floor
a. Welds
b. Plate Thickness
c. Annular Plate
d. Roof Leg Pads
2. Shell Internal wall
a. Seam Welds
b. Manway/Nozzles
Necks welds to Shell
3. Roof Deck Underside
a. Seal Pan
b. Center Roof Drain Pit
c. Roof Drain Sys. Hose
Or Pipe Swivel
d. Roof Leg
e. Monkey Ladder
4. Roof Seal
a. Mechanical Type
- Counter Weights
b. Rubber Seal Type
5. Water Draw-Off Sys.
a. Sump & Pipe
Miscellaneous
VP-Very Poor; P-Poor; F-Fair; G-Good; N-Not Accessible/Not Inspected
8
9
CONE ROOF TANK
EXTERNAL INSPECTION CHECKLIST FORM
CONE ROOF TANK
INTERNAL INSPECTION CHECKLIST FORM
DATE ____________________
FILE NO ________________
TANK NO_________ SERVICE _______ LOCATION ___________________
NOM. CAPACITY _____________ SAFE FILLING CAPACITY _____________
INSIDE DIAMETER ______ HEIGHT ______ SAFE FILLING HEIGHT _______
DATE TANK LAST INSPECTED _______ DATE TANK LAST CLEANED______
INSPECTED BY ____________________ OTHERS: _____________________
DATE ____________________
FILE NO ________________
TANK NO_________ SERVICE _______ LOCATION ___________________
NOM. CAPACITY _____________ SAFE FILLING CAPACITY _____________
INSIDE DIAMETER ______ HEIGHT ______ SAFE FILLING HEIGHT _______
DATE TANK LAST INSPECTED _______ DATE TANK LAST CLEANED______
INSPECTED BY ____________________ OTHERS: _____________________
PARTS
CONDITION
REMARKS
1. Foundation
2. Tank Shell
a. Identification
b. Painting
c. Seam Weld
d. Thickness
e. Manways
f. Clean-out door
g. Other Attachments
3. Stairway/Platform
a. Landing
b. Handrail
4. Roof Deck
a. Painting
b. Thickness
c. Manholes
d. Vents
e. Sampling Hatch
f. Handrail
g. Others
5. Windgirder
6. Level Gauge/Pipe
7. Nozzles/Valves
Miscellaneous
VP-Very Poor; P-Poor; F-Fair; G-Good; N-Not Accessible/Not Inspected
PARTS
CONDITION
REMARKS
1. Shell Internal Wall
a. Pitting Condition
b. Seam Weld
c. Others
2. Bottom Plate
a. Pitting Condition
b. Seam Weld
c. Thickness
d. Water Draw-off Sump
e. Water Draw-off Pipe
f. Others
3. Roof
a. Roof Underside
b. Roof Support
c. Others
4. Level Gauge Float
a. Cable Connection
b. Guide Wire
5. Foam Deflector
Miscellaneous
VP-Very Poor; P-Poor; F-Fair; G-Good; N-Not Accessible/Not Inspected
10
11
3.0
THE INSPECTOR
The Inspector should have an inquisitive mind and never satisfied with
superficial appearance that readily absorbs details. He should have a
passion for thoroughness. He must have practical knowledge of the effects
of time, wear and corrosion on tank parts. He should know all defects that
are found so that he can assist in prescribing the necessary repair
procedure.
The Inspector should have the basic knowledge of engineering and
must be familiar with the design specifications presented in the following
standards.
1. Atmospheric tank
----API Std. No. 650
2. C-15 psig tank
----API Std. No. 620
3. Full vacuum to
atmospheric
----ASME Code Sec. VIII
API Std. No. 620
4. Over 15 psig tank
----ASME Code Sec. VIII
API Std. 620 – for
max. compression
4.0
INSPECTION REPORT AND RECORD
It is not possible to evaluate tanks without records. Inspection reports
should be maintained and all information must be updated and kept in
permanent files for immediate and future references.
Reports should be concise and definite. If at all possible, highly
technical presentations should be avoided. It should be remembered that
simple yet descriptive terms makes reporting easy and effective. In case
there is a need to include layouts or drawings, the orientations should be
clear.
Inspection is considered complete when reports and the possible
recommendations are submitted. See sample report Appendix III.
These inspection reports and complete records along with inspector
recommendations and documentation of disposition shall be maintained by
the owner/operator for the life of the tank. Local jurisdictions may have
additional reporting and record keeping requirements for tank inspections.
4.1
Because tanks are built with parts for specific usage, the Inspector
should be aware of them. He must be well verse in all refinery and chemical
process industrial practices.
A good Inspector knows his limitation. Consultations with Technical
Experts and accepted standard practices are made when needed.
b. Inspection History
The inspection history includes all measurements taken, the
condition of all parts inspected, and a record of all examinations and
tests. A complete description of any unusual conditions with
recommendations for correction of details which caused the
conditions shall also be included. This file will also contain corrosion
rate and inspection interval calculations.
4.2
12
Records
a. Construction Records
Construction records may include nameplate information,
drawings, specifications, construction completion report, and any
results of material tests and analyses.
Reports
a. Report Contents
Reports shall include at a minimum the following information:
i.
date(s) of inspection;
ii.
type of inspection (external or internal);
iii.
scope of inspection, including any areas that were not
inspected, with reasons given (e.g. limited scope of
inspection, limited physical access;
iv.
description of the tank (number, size, capacity, year
constructed, materials of construction, service history, roof
and bottom design, etc.), if available;
13
v.
vi.
vii.
viii.
ix.
x.
xi.
xii.
list of components inspected and conditions found (a
general checklist such as found in Annex C may be used
to identify the scope of the inspection) and deficiencies
found;
inspection methods and tests used (visual, MFL, UT, etc.)
and results of each inspection method or test;
corrosion rates of the bottom and shell;
settlement survey measurements and analysis (if
performed);
recommendations per 6.9.3.1;
name, company, API 653 certification number and
signature of the authorized inspector responsible for the
inspection;
drawings, photographs, NDE reports and other pertinent
information shall be appended to the report.
c.
Nondestructive Examination (NDE)
Personnel performing NDE shall meet the qualifications
identified in 12.1.1.2, but need not be certified in accordance with
Annex D. The results of any NDE work, however, must be
considered in the evaluation of the tank by an authorized inspector.
b. Recommendations
Reports shall include recommendations for repairs and
monitoring necessary to restore the integrity of the tank per this
standard and/or maintain integrity until the next inspection, together
with reasons for the recommendations. The recommended
maximum inspection interval and basis for calculation that interval
shall also be stated. Additionally, reports may include other less
critical observations, suggestions and recommendations.
It is the responsibility of the owner/operator to review the
inspection findings and recommendations, establish a repair scope,
if needed, and determine the appropriate timing for repairs,
monitoring, and/or maintenance activities. Typical timing
considerations and examples of repairs are:
i.
ii.
iii.
iv.
v.
prior to returning the tank to service—repairs critical to the
integrity of the tank (e.g. bottom or shell repairs);
after the tank is returned to service—minor repairs and
maintenance activity (e.g. drainage improvement,
painting,
gauge repairs, grouting, etc.);
at the next scheduled internal inspection—predicted or
anticipated repairs and maintenance (e.g. coating
renewal, planned bottom repairs, etc.);
monitor condition for continued deterioration—(e.g. roof
and/or shell plate corrosion, settlement, etc.).
14
15
5.0
FREQUENCY OF INSPECTION
Because of the cost involved, it is unreasonable to take tanks out of
service just for inspection. Unless special reasons indicate that inspection
must be made, full inspection can be performed in conjunction with a
properly planned maintenance program or schedule.
With continuing in-service inspection records, full tank inspection and
maintenance program can be scheduled with a frequency proportional to
the rate of corrosion in the tank.
5.1
5.2
5.3
5.4
Routine In-service Inspections - The external condition of the
tank shall be monitored by close visual inspection from the
ground. The interval of such inspections shall not exceed one
month.
External Inspection - All tanks shall be given a visual external
inspection by an authorized inspector. Shall be conducted at
least every five years or RCA/4N years (where RCA is the
difference between the measured shell thickness and the
minimum required thickness in mils, and N is the shell corrosion
rate in mils per year) whichever is less.
Ultrasonic Thickness Inspection - External, ultrasonic
thickness measurements of the shell can be a means of
determining a rate of uniform general corrosion while the tank
is in service, and can provide an indication of the integrity of the
shell. Intervals not to exceed the following:
5.3.1 When the corrosion rate is not known, the maximum
interval shall be five years
5.3.2 When the corrosion rate is known, the maximum
interval shall be the smaller of RCA/2N years (where
RCA is the difference between the measured shell
thickness and the minimum required thickness in mils,
and N is the shell corrosion rate in mils per year) or 15
years.
Internal Inspection - The interval from initial service date until
the first internal inspection shall not exceed 10 years unless a
tank has one or more of the leak prevention, detection,
corrosion mitigation, or containment safeguards listed in API
653 Table 6.1. The initial internal inspection date shall be based
on incremental credits for the additional safeguards in API 653
Table 6.1 which are cumulative.
16
For example, the maximum interval for a ¼ in. bottom that has a release
prevention barrier and a fiberglass lining would be determined as follows:
10 years (initial) + 5 years (fiberglass lining) + 10 years (release
prevention barrier) = 25 years.
The initial inspection interval shall not exceed 20 years for tanks without
a Release Prevention Barrier, or 30 years for tanks with a Release
Prevention Barrier.
17
6.0
NON-DESTRUCTIVE EXAMINATION IN TANKAGE
The use of noninvasive techniques to determine the integrity of a
material, component or structure.
The standard non-destructive examinations in tankage are the
following:
1. Liquid Penetrant Method
2. Magnetic Particle Method
3. Ultrasonic Examination
4. Industrial Radiography
5. Magnetic Flux Leakage Test
The recommended practices laid out in ASNT, ASME, and API
standards are equal in the performance of these methods.
6.1
Liquid Penetrant Examination
Liquid penetrant method is an effective means of locating surface
discontinuities. The typical application of this method is in finding cracks
and pinholes or porosities on welds of manways and nozzles necks
attachments to the tank shell.
b. Penetrating Oil Testing:
In this method, penetrating oil is applied on the inspection side
of the surface and seepage is observed at its opposite side.
Usually, diesel or kerosene is used as penetrants.
Cracks that may possibly develop at the heat-affected zone of the
shell opening can also be detected with this method.
The method is applicable on the lapped joints of the roof deck
and bottoms of pontoons. When renewal of tank floors are being
made, the circumferential fillet welds at the juncture of the bottom
and shell plates are tested by this method as shown in fig.-3.
Basically, two modes of applications are employed under this
method. The first is the standard “Dye-Penetrant” and the other is the
conventional “Gas-Oil” test.
a. Dye-Penetrant test (PT):
As the term implies, it calls for the used of a dyed penetrating
liquid and a developer.
To a properly prepared surface for inspection, a dye penetrant
(red) is applied and allowed to penetrate sufficiently. Then all the
excess penetrant is cleaned with appropriate solvent. When using
solvents in aerosol cans, it is important not to spray directly on the
surface to be inspected. There is a risk of cleaning out the dye that
had possibly penetrated a discontinuity. Cleaning is best carried
out by wiping off the area with solvent soaked lint free rugs.
After the removal of the excess penetrant is completed, a white
developer is the n applied on the same area. The appearance of
deep colored dye locates the defect. For good developing,
developers in aerosol cans are used.
18
Gas-oil such as diesel or kerosene is applied on the inspection
area and allowed to penetrate for a certain time. Preferably,
penetration is allowed overnight. Evidence of wetting of the side
opposite the inspection side locates a leak.
19
6.2
Magnetic Particle Examination (MT)
Under this method, advantages offered by liquid penetrant are
achieved with greater sensitivity. Subsurface defects are also detected.
However, sensitivity decreases as the depth of the defects increases.
Common defects in tankage that are detected with this method are
cracks and laminations. However, to reveal these defects satisfactorily,
the surface to be inspected should be fully cleaned. Sometimes
abrasive blast cleaning is necessary. To reveal fine defects, the surface
should be smooth ground. Rough surface hampers the mobility of the
magnetic particle due to mechanical trapping that leads to false
indications.
6.4
Radiographic Examination (RE)
With permanent record, interior macroscopic flaws as cracks,
porosities, non-metallic inclusions are indicated.
In tankage, radiography is mainly applied whenever there are works
that involves the shell plate butt-welding joints. Installing new insert
type manways and nozzles also requires radiographic examination. The
adjoining butt joint of new annular ring section of the tank floor also
requires random radiographic examination.
6.3
Ultrasonic Examination (UE)
In tankage, ultrasonic inspection is mainly applied for wall thickness
measurements. Flaw detection is rarely performed. The API Std. No.
650 “Thickness by One-Foot Method” is considered to be practical.
Usually only the bottom shell course and spots accessible along the
stairway are surveyed for thickness. However, if the result showed
suspects of deteriorations, then scaffoldings or sky-climbers are
provided in order to conduct full thickness survey on the tank shell.
Ultrasonic meters operating under the basis of electronic transittime measurements are used. With this meter, using normal probes,
flaws chiefly of the laminar type that has substantial component parallel
to the inspection surfaces can be detected. The presences of such
flaws are indicated by a change or disappearance of the normal
thickness readings. Corroded or fitted backwall also gives the same
indications.
20
21
6.5
Magnetic Flux Leakage Test
MFL is the “Best” method to evaluate a tank bottom condition
quickly and cost effectively.
a. Magnetic Flux Leakage Test Principle
b. Magnetic Flux Leakage Test Limitations
i.
Tank Floor Cleanliness
ii.
Tank Surface Condition
iii.
Floor and coating thickness
iv.
Sensitivity
v.
Coverage - physical limit
Pipe
Floor corner
Around Patch
repair
Plate edge
Around Wear pads
MFL Untested Areas
The untested areas mentioned above are to be inspected by:
- Ultrasonic Testing - Each corner 140x140mm, near shell to
bottom weld.
- Ultrasonic Testing /HandScan - 10 mm on all four edges,
underneath pipes, around wear pads and existing patch repairs.
6.6
Phased Array Ultrasonic Testing (PAUT) in Lieu of
Radiography API 650 Annex U
This alternative is limited to joints where the thickness of the thinner
of the two members joined is greater than or equal to 10 mm (3/8 in.)
The UT shall be performed in accordance with a written procedure
which has been reviewed and approved by the Purchaser and conforms
to the requirements of Section V, Article 4
CODES:
a. ASTM E 2491-06 Standard Guide for setting up phased arrays
b. ASME B31.1 – Code Case 168
c. ASME B31.3 – Code Case 181 Use of Alternative UT Acceptance
Criteria
d. ASME B31.1 – Code Case 179 Use of UT in Lieu of RT (1.5 in or
less thk)
e. ASME Section III – Code Case N-659 Use of (UT) an alternative to
(RT) for nuclear power plant
components
and
transport
containers
f. ASME Section V – Code Case 2557 – Use of Manual PA S-scan
UT
g. ASME Sec. V Mandatory Appendixes
22
23
h. ASME Section I & VIII, Division 1 & 2 – Code Case 2235 Use of UT
in Lieu of RT
i. ASME Section XI – Code Case N-713 Examination Requirements
for Portions of Class 1 and 2 Systems and Components within
the Containment System Boundary
Main Features of PAUT:
a. Multiple elements are housed in one probe. Each element is
wired independently and can be pulsed separately.
b. Capable of generating range of angles (e.g. 35°-70°) resulting
in an increased probability of detection (POD) of weld
imperfection.
c. Specialized computer software is used for visualization and
interpretation of acquired inspection data.
7.0
OTHER METHODS OF TESTING IN TANKAGE
7.1
Pneumatic Leak Test
In tankage, the method is generally applied the tightness check of
the reinforcing pad at the shell attachment. The test is performed by
injecting air not to exceed 15-psig to the pad through its telltale hole.
Soapy solution is then applied on all seam welds at the reinforcing pad
and at the attachment welding to the shell. Indications of bubbles locate
the leak. See figure 4a for application.
The tightness of the pontoons of the floating roofs is also tested
with this method. However in this case, air not to exceed 9-inches water
pressure is injected instead. See figure 4b for application on pontoons.
7.2
Hydrostatic testing of shell
Generally, water-filling test is conducted in order to check the
integrity of the tank shell, Because of the scales that usually develops
at the shell; it is sometimes necessary to blast clean the scaled wall of
the tank. It should be considered that a small hole or crack can be easily
covered by thin scale and thus, leaks may not show during the test.
Cone roof tanks are water filled to a height 2-inches above the top
leg of the top angle. Floating roof tanks are filled up to the
recommended safe filling height. In some cases, when there is a need
to adjust the safe filling height of the tank because of thinning of the
shell, the recommendation laid-out in API Std. No. 650 is followed.
Buckling and bulging of the shell and leaks at the seam welds are
observed during the test. The telltale holes of the reinforcing pads of
the shell attachments are also observed for leakage. Leaks originating
on this part indicates the possibility of either defects on the attachment
welding to the shell or crack at the heat affected zone of the opening
The shell shall be tested by one of the following methods:
a. If water is available for testing the shell, the tank shall be filled
with water to the maximum design liquid level, H;
b. If sufficient water to fill the tank is not available, the tank may
be tested by painting all of the joints on the inside with a highly
penetrating oil, such as automobile spring oil, and carefully
examining the outside of the joints for leakage;
24
25
Minimum fill and discharge rate:
7.3
Tank external shell settlement evaluation (API 653 Annex B)
A settlement survey shall be conducted for all existing tanks that
undergo a hydrostatic test, except for tanks that have a documented
service history of acceptable settlement values, and no settlement is
anticipated to occur during the hydrotest.
Shell elevation measurements shall be made at equally-spaced
intervals around the tank circumference not exceeding 10 m (32 ft). The
minimum number of shell measurement points shall be eight.
Six sets of settlement readings are required for new tanks:
a. Before start of the hydrostatic test;
b. With tank filled to 1/4 test height (±600 mm [2 ft]);
c. With tank filled to 1/2 test height (±600 mm [2 ft]);
d. With tank filled to 3/4 test height (±600 mm [2 ft]);
e. At least 24 hours after the tank has been filled to the maximum
test height.
f. After tank has been emptied of test water.
Three sets of settlement readings are required for existing
tanks:
a. Before start of the hydrostatic test;
b. During filling;
c. At least 24 hours after the tank has been filled to the maximum
test height.
26
27
8.0
LOCATING LEAKS ON TANK FLOORS
Locating leaks on tank floors is usually done by visual inspection. But
because of the usual dirty condition of the floor; small holes or cracks are
often missed. To effect better visual inspection, dirty floors are cleaned by
means of abrasive blast cleaning method. Advantage of this method of
cleaning is that wet spots usually appear and this locates the leak. This is
attributed to the capillary flow of liquid from wet to dry surface. The
disadvantages of this method is that additional holes may be generated that
can add to the problem of locating leaks. This is particularly true whenever
the floor is exhibiting isolated thin spots.
Because of this, other methods had been developed in order to improve
locating leaks on the tank floors. The most common and perhaps the most
popular are the vacuum and flooding methods.
8.1
Vacuum Testing
Vacuum testing requires proper surface preparation. The need to
clean the surface to be inspected free from scales that are capable of
plugging small holes or cracks is of utmost importance. Otherwise,
Testing will not yield good results.
In the performance of the test, the surface is first coated with films
of soapy solution. The n the open side of the vacuum box is placed on
top of the test area. With the used of a vacuum pump or an air ejector,
partial vacuum of at least 12-psig is maintained inside the box. Leaks
can simply be located by the appearance of continuous bubbles at any
point on the test area. Observation is made at the top glass of the box.
The effectivity of this method is enough to locate even hairline
cracks. Care should be exercised that heavy soapy solution is not
applied. It usually gives false indication. The main disadvantage of this
method is its difficulty to apply on non-flat surfaces. Moreso, in large
tanks, it is considered to be time consuming and labor intensive.
8.2
Flooding Method
Basically, there are two ways of conducting flooding test in finding
leaks on tank floors. It can be Internal or External flooding.
a. Internal Flooding
Under this method, the tank floor is internally flooded with water to
a depth sufficient enough to cover the highest level of the floor. Leaks
are simply located by looking for bubbles on the water when air not to
exceed 6-inches water pressure is injected at the floor underside. Care
should be observed that water is pump first into the tank before injecting
air.
b. External Flooding
As the term implies, flooding with water done outside the tank by
constructing a temporary dike. The dike is constructed in such a way
that it can maintain a hydrostatic height of at least 12-inches water from
the highest level of the floor. Leaks are simply located by looking for
entry of water from the floor underside. See figure 6.
In addition to the construction of the dike, several couplings with
nipples of at least 12-inches long are welded on the floor. The number
of coupling depends upon the size of the tank. Large tanks would
require more couplings than small tanks. The purpose of the coupling
is to be able to see whether water had reached that portion of the floor.
Moreso, it allows water to flow faster since water flows only as fast as it
can displace air. After all the leaks are located and repaired, the nipples
are simply removed and the couplings are plugged.
Another way is coating with films of soapy solution instead of
pumping water. This time, air not exceed 3-inches water pressure is
injected at the underside. Indication of soap bubbles locates the leak.
28
29
In both ways, the preparation calls for the placing of sufficient
temporary seal around the tank outside periphery at the bottom. This is
to be able to build-up air pressure to the desired value. Two couplings
are installed at the floor as shown in figure 5, one is employed as the
inlet for the air and the other is for the installation of the U-tube type
pressure gauge. After the completion of the test, the couplings are
simply closed with bulb plugs.
The method being limited to low pressure, it may not be sufficient
to blow out scales on pits that may be among the cause of the leak. The
need of jarring the floor is sometimes needed in order to pop out scales
from the pits
Tanks that are used for storing asphalts, wax or other similar
materials are tested with this method but steam instead of air is injected.
In conditions where it is considered hazardous to inject air, higher cost
inert gases such as nitrogen or argon are used.
See also API 650 Annex I Undertank Leak Detection and Subgrade
Protection
30
31
9.0
PRACTICAL TESTING FOR ATMOSPHERIC TANKS
Because of the cost involved, testing methods for tankage should be
chosen according to their most practical way of application. Say for tanks
where floor renewal had been done, it would be unreasonable to conduct
water-filling test since the method is more of testing the shell rather than the
floor. The practical test that can be considered is either vacuum or flooding
for a leak free floor. The same thing goes for floating roofs, to check for
leakage, floating with water is unnecessary. Gas-oil or vacuum test are
reliable. Cone roofs can be visually inspected easily. Thus, methods other
than this are not required.
It should be considered that unnecessary testing adds up to the cost of
tank maintenance and should be avoided. See table 1 for some suggestions
for testing atmospheric tanks.
Table 1 – Suggested testing of Atmospheric Tanks
Tank Parts
Test Method
Shell
Water filling Test (1) (2)
Cone Roof
Visual Inspection
Roof
Floating Roof
Gas-oil or Vacuum Test
Pontoon
Pneumatic Leak Test
Old
Flooding Test (3)
Floor
New
Vacuum Test (4) (5)
Neck to Shell
Dye-Penetrant or
Manways
and
Welding
Magnetic Particle
Nozzles
Reinforcing Pad
Pneumatic Leak Test
Roof drain system (6)
Hydrostatic Test (7)
See Appendix VIII and IX
Notes:
1.
2.
3.
4.
5.
6.
7.
Major works that includes plate renewal or insert type window closure
would require radiographic examination as laid in API Std. No. 650
Minor welding repair may not require water-filling test. Dye-Penetrant or
vacuum testing can be satisfactory.
Not suggested for tanks that employs “Earth-Pad” type foundation.
Vacuum testing can be performed.
Test conducted on all seam welds.
The circumferential weld between the shell and the floor can be inspected
with “Gas-oil” method.
Applicable for pipe and swivel drain line only.
Pressurized the line 50 psig for at least 10 minutes. Check for evidence of
leak. Then reduced the pressure to 5 psig and check the swivel joints for
evidence of leaks (swivel joints are self locking that at high pressure
leakage may not be detected. However, if the seal are defective, leaks will
result at low pressure).
32
10.0
DETERIORATION OF STEEL TANKS
Basically, corrosion is the primary cause of steel tank deterioration. In
Petroleum Refineries, the forms of corrosion that are usually encountered
in tankage are weld decay, pitting and crevice, and vapor space corrosion.
Weld decay is an example of the effects of localized corrosion. The
occurrence of this corrosion is due to the possible existence of some
heterogeneities in the metal and this is well exhibited by the geometry of the
structure of the weld metal. Weld metal maybe anodic to the steel and in
the presence of an electrolyte, a corrosion cell is created thus causing this
form of corrosion. See figure 7 showing the mechanics of weld decay
corrosion.
Pitting and crevice are forms of highly localized corrosion.
They
deserve special mention because they are considered to be the most
harmful types of corrosion that could take place on metals. With only small
percent weight loss of the metal, they could result to costly tank failure.
Perforation that causes leakage usually resulted.
The initiation of the attack or crevice corrosion as the term denotes will
require crevice where small volume of solution can be deposited and remain
stagnant. Additionally, the attack may also be produced by surface deposits
that could create a stagnant condition thereunder, In tankage, this form of
attack commonly occurs at the external parts like skip-welded lapped joints,
nuts and bolts, rivet heads, and surfaces where there are deposits of sand,
dirt or even the corrosion product itself.
Compared to crevice, pitting is considered more vicious because it does
not require crevice to initiate. It is self-initiating. Pitting results when a small
anodic area develops on the metal surface because of certain irregularities
in the physical and chemical structure of the metal. Another possible cause
of pitting is the presence of mill scale. Mill scale easily break and flake under
small variation of temperature and in the presence of an electrolyte, an
electrical corrosion cell is created between the broken mill scale and the
metal. Since mill scale is cathodic to the metal, pitting will result on metal.
Pitting takes long periods to initiate but once started, it will penetrate the
metal at an ever-increasing rate. It also tends to undermine or undercut the
metal surface as they grow. Another effect of pitting is that it acts as stress
raiser that could result to fatigue cracking. See figures 8 a and b illustrating
pitting formation due to broken mill scale and cross sections of different
types of pitting respectively.
33
The third form of corrosion that can be encountered in tanks is the vapor
space corrosion. It basically occurs in Cone Roof type tanks because of the
presence of the vapor space above its working portion. Moisture and
oxygen are introduced into tanks in different ways. They can either be
drawn in the tank with the stock or by breathing during temperature
changes. However, much is drawn during the emptying operation of the
tank.
11.0
APPROACH TO TANK INSPECTION
To minimized cost, the length of time a tank will be placed\ out of service
should be to the minimum. It is therefore advisable that external inspection
is conducted while the tank is still in service. Internal inspection can then
be performed in conjunction to a schedule maintenance program.
11.1
The moisture that may condense above the working portion of the tank
will act as the electrolyte. Thereby establishing corrosion in the vapor
space. The extent of this corrosion will depend heavily on the activity of the
tank. The more the tank is active, the more severe the vapor space
corrosion will occur. Since in Refineries, the intermediate products tanks
are the most active, such corrosion is usually severe. Moreso, for tanks that
are used to carry high sulfur crudes, the vapor space corrosion occurs at an
accelerated rate. This is the number 1 reason why Floating Roof Tanks are
employed for this stock.
34
External Inspection
The primary concern of external inspection lies mainly in the paint
failures, broken parts and area where water can be collected and
trapped such as pockets, crevices, and other deposits like dirt. The
evaluation of these areas shall pertain to the possible effect of
atmospheric corrosion.
35
Atmospheric corrosion is principally galvanic. The base metal is the
anode and the oxide of the base metal as the cathode. In the presence
of the condensates o the moisture in the atmosphere, a corrosion cell is
established. The severity of atmospheric corrosion depends on the type
and amount of moisture present in the atmosphere. Condensate near
marine and industrial areas contains salt and other contaminants
thereby making it better electrolyte and more corrosive that
condensates in an inland or rural areas even under equal humidity and
temperature condition.
Since painting is the only practical means of protecting the tank from
atmospheric corrosion, faulty paintworks will result to its accelerated
deterioration. Another factor to which the Inspector should be on the
looked out is the presence of deposits that can initiate crevice corrosion
as mentioned in Sec. 10.0. See Appendix I for some suggestions to the
approach to tank external inspection.
11.2
Internal Inspection
The concern of the internal inspection is the evaluation of the extent
of the possible corrosion that could take placed inside the tank. As
compared to atmospheric corrosion that takes place on the external
parts of the tank, internal corrosion is usually more severe. Sometimes
it reached a degree that maintenance repair is no longer economical
and it is more preferable to erect new tank as replacement.
The corrosion promoting substances that are common in refinery
tanks are the following:
-
Hydrogen Sulfide
Moisture and Dissolved oxygen
Contaminated water
Hydrogen sulfide is not actually corrosive but whenever it is in
contact with water, an acid of sulfate evolves and is responsible to
corrosion. Moisture as itself does not really have a part in the corrosion
cell but it is bound to condense and it is the condensate that will act as
the electrolyte to establish corrosion. The presence of dissolved oxygen
will stimulate corrosion because of its depolarizing effect.
36
The detrimental effect of the first two groups of corrosion promoting
substances are commonly experienced in Cone Roof type tanks as
vapor space corrosion above the working portion of the tank.
Furthermore, the condensates of moisture and the depolarizing
dissolved oxygen plays an important role in the occurrence of pitting
corrosion at the mid-section of the working portion of the shell of this
tank. This is because the area undergoes more wetting and drying than
others. Such corrosion is usually encountered on tanks that are used
to carry light stocks such as kerosene, gasoline, and light charge.
Tanks that are used to carry heavy stocks like crude oil does not exhibit
this corrosion because more or less a permanent film is formed on the
shell and thus serve as protection.
Perhaps the most harmful corrosion promoting substances that are
encounter so in refinery tanks is the contaminated water. The role that
it plays is perhaps the most important part in a corrosion cell, which is
the electrolyte. Its presence will always result in the tank; the floor and
the lower portion of the shell course will usually exhibit weld decays and
pittings. In some cases, the extent of the corrosion that may take place
will reach a degree that floor renewal will be necessary.
Water is weak electrolyte but when contaminated it becomes a
strong electrolyte and corrosive. In tankage, it is principally introduced
during transportation of the stocks. Say from the Oil Well to the Super
Tankers and then to the storage tanks of the refineries. Normally, tanks
that are used to carry refinery products like gasoline, diesel, etc. are not
contaminated with water. However, when the stocks are transported
from one refinery to another, or the bulk plant, chances of introducing
water to the tank are high especially when ship tankers are employed
as transportation.
See Appendix II for some suggestion to the approach to tank
internal inspection.
37
12.0
SAFETY IN TANK INSPECTION
Because of the risk involved, Inspection should only be conducted by a
team of at least two Inspectors or an Inspector aided by an Assistant or
Trainee Inspector. No one Inspector should be allowed to work alone.
Before any inspection proceeds, valid work permits should be issued and
the area where the inspection us to be conducted should be clearly
identified.
12.1
Safety tips for tanks in-service inspection:
1. Inspection should only be carried out with tools or
equipments that will not generate or emit sparks.
2. Only inspection procedures that will not generate spark or
electricity should be conducted. However, if the need
arises, it should be confined to light structures. If magnetic
particle examination is needed, only magnets should be
used.
3. The Inspector should wear only work clothes that are made
of materials that will not generate static electricity.
4. If inspections are to be conducted at high places, proper
scaffoldings or skyclimbers should be provided. The
Inspector should be equipped with safety belts or lifelines.
5. Because of he risk involved, inspection should not be
conducted on the roof while the tank is still in service.
However, if the need arises, the following safety
precautions should be observed:
a. Floating Roof Tank:
-
-
Inspection should be carried-out only when the roof level is at
high position. The most ideal level for inspection is when the
tank is filled up to its maximum safe filling height. Inspection
while the roof is at the low position is possible if the space is
declared gas-free. At all times, an air mask and lifelines should
be used. Only one Inspector should go down the roof and the
assisting Inspector as the lookout atop the tank.
Added safety precaution is that the operation personnel are
properly notified in advance so that the operation of the tank is
programmed in such a way that all activities of the tank is
suspended at least until the duration of the inspection. On the
other hand, the Inspector should see to it that the inspection is
performed in the shortest time possible. This is practically
considered when inspecting tanks that are used to carry
intermediate products.
38
b. Cone Roof Tank:
- If plate thinning is suspected, wooden planks at least long
enough to span between two rafters or trusses should be
securely placed to serve as the Inspector’s access. One safety
practice is for the Inspector to walk over the roof along the
lapped welded joints. This is the area considered to be stronger
than others.
Lastly, irrespective whether it is Floating or Cone Roof type tanks,
only visual inspection should be carried out.
12.2
Safety requirements for inspecting tanks that are out of service
are not as rigid as for tanks that are still in service. However,
when it calls for tank entry, the following preparations should be
followed:
a. Preparation of tank:
- Remove all stocks possible through existing connections.
- Remove all sources of ignition from the area.
- Open all manways.
- Remove balance of stocks through manways, clean-out door and
or through the water draw-off nozzles.
- Blank off all lines connected to the tank.
- Install ventilating system. No entry shall be made unless the tank
is declared gas-free.
Preparation of the Inspector for tank entry:
-
Check for proper attire.
If needed, air mask must be used and check for fit and operation.
Check for sufficient air supply.
Check air line hose and safety line to keep free and untwisted.
Perhaps the most important consideration to be taken for every tank
entry understands the difference between “Gas Free” and “Lead Hazard
Free”.
Notwithstanding the importance of good judgment needed for every
inspection. Safety plays an important role on why only qualified
Inspectors are allowed to do inspection. An experienced Inspector can
be able to predict the type of possible corrosion that could exist
depending on the type of tank that is employed for certain services. Say
for Cone Roof tanks that are used for intermediate product or heavy
stock such as crude oil, the Inspector will readily be on guard when roof
inspection is needed. This is because that such tanks usually exhibits
intensive vapor space corrosion that could lead to the weakening of the
roof structure.
9
It should be remembered that each worker is responsible to his own
safety and that he can never do a good work without knowing how to do
it safely.
13.0
PRACTICAL WAYS OF
TANKAGE
SUPPRESSING
CORROSION IN
Basically, the only practical means of protecting the tank from
atmospheric corrosion is by application of protective coatings as mentioned
in Sec. 11. Coating systems are selected depending on the type of
atmospheric condition of the surroundings. For highly contaminated marine
or industrial atmospheres, high performance Epoxy system with Zinc-rich
primers are used. In mild atmospheric conditions, an Alkyd paint system
will perform satisfactorily.
The underside of the tank floor is usually considered buried. Thus, it
has been a common practice that high resistivity pads or cushions are
compacted under the floor. The most common material are bituminous
sand and concrete asphalt. In addition to these compactions, properly
monitored impressed current cathodic protection system may be provided.
However, in the case of concrete asphalt, this is not applicable because of
its very high resistivity unabling plates are laid between the pad and the tank
floor.
In large diameter tanks, monitoring the protection at the center of the
floor is only effective if reference electrode is installed at the center.
However, this may not be necessary in small diameter tanks because the
indication of protection of the floor near the shell can be more or less
considered an indication at the center.
Suppressing corrosion inside the tank does not really very from the
external parts. In cone Roof tanks, the underside of the roof and the nonworking portion of the shell can be protected by coating application as well.
In this case, it will definitely call for high performance Epoxy system.
Cement mortar is also satisfactory but because of its weight, it has its
restriction. The floor topside plus 1-meter of the shell is usually protected
by application of glass reinforced Epoxy (GRE) or Polyester (GRP).
Protecting intermediate product tanks that carries light stocks usually
requires gas blanketing. This will eliminate the drawing in of excessive
moistures.
40
41
14.0
TANK FARM CORROSION CONTROL USING CATHODIC
PROTECTION
When designing an internal cathodic protection system for such an
important facility as an oil storage tank farm, careful consideration should
be given to the size and nature of the problem. It is in many ways more
complex than a conventional aqueous storage tank system. When the
criteria for internal cathodic protection are examined, one begins to realize
the extent to which the engineer is involved in instrumenting a successful
cathodic protection system.
Under normal conditions, the major factors governing the design of
external cathodic protection are the total surface area of the structures to be
protected, the quality of the coating, soil resistivity and the required life of
the system. When protecting tank farm facilities however, additional thought
should be given to structures, which come under the influence of the
cathodic protection current. Because of the complexity of tank farm layouts,
it is wise to include all facilities under the same protection system.
For safety reasons, all oil storage tanks are lifted with a grounding
system. This usually takes the form of bare copper cable looped round the
tank and may have additional bare earthing mats or rods. The system may
also be interconnected throughout the tank farm, making isolation of tanks
or groups of tanks impossible. Fire hydrant systems are also a cause for
concern when planning a protection scheme. Although relatively easy to
isolate, when constructed of steel they also require protection. As the piping
layout will inevitably the throughout the whole of the tank farm, it is wise to
include it under the same system as the storage tanks. This will eliminate
the possibility of interaction, which may be a serious problem. Water wells
supplying storage tanks and hydrant systems can have their natural
potentials reversed by interaction from deep well ground beds if not
connected to the same source of protection.
CRITERIA FOR INTERNAL CATHODIC PROTECTION
Safety Aspects
Due to the potentially dangerous environment and the need to minimize
the risk of excessive current flows, sacrificial anodes are preferred to
impressed current systems. All anodes should be attached directly to the
structure, thus eliminating the possibility o “shorting”. The fact that the
electrolyte fluctuates in level and can fall to only a few inches in depth also
makes the use of sacrificial anodes more practical.
42
Surface Area to be protected
When calculating the surface area to be protected, consideration should
be given to the maximum basic sediments and water level in the tank
together with the surface area of any ancillary equipment, which may be
installed.
Type and Quality of Coating
Before an estimate of current requirement can be made, full facts
relating to the type and quality of coating must be obtained. This is crucial
as it may be years before the tank is opened for maintenance. Lack of
information about the coating may result in premature anode failure.
Electrolyte Composition
Detailed analysis of the electrolyte is recommended as this may contain
bacteria harmful to the type of coating in use, and ultimately affect current
requirements. Information relating to pH values and resistivities of media
will also be of assistance when choosing coating and anode materials.
Monitoring the system
It is not normal practice to have facilities installed to measure anode
current outputs. Practical and safety reasons dictate that anodes are
connected directly to the tank’s surface. However, it is important to measure
structure to electrolyte potentials. Tank design will normally determine the
location of electrodes should be placed at areas of high turbulence.
Selection of Protective Materials
Care needs to be taken when selecting the coating so as to guard
against the possibility of cathodic disbanding. The integrity of the coating
should be such that resistance to chemical attack by the known constituents
within the media is guaranteed.
History of Leak Rate and Anode Failure
Information relating to anode failure and leak rate must be studied to as
certain the possible need for different types of anodes, the quantity and their
positioning.
Tank Maintenance Timetable
Before completing the list of requirements for cathodic protection it is
necessary to consult the appropriate department to as certain the time span
between tanks being opened. This is required to ensure that anode life will
be maintained throughout the tanks’ service life.
Other Equipment to be protected
In addition to the protection of oil storage tanks there is usually the need
to protect other vessels such as firewater storage tanks and wash tanks etc.
Internal protection of fire hydrant standpipes is also a possibility.
43
Completion of Cathodic Protection System
On completion of the installation the tank is ready to become
operational. Due to the differing specific gravities, basic sediment and water
will separate out naturally from the oil to form the electrolyte, but this will
take place over a period of time. To avoid contamination of anodes and
reference electrodes it is wise to fill tanks with water to drain off level prior
to filling with crude. This will help in preventing the anodes and electrodes
from becoming contaminated. It will also serve as a means of testing
structure potentials, although these will change slightly once the natural
electrolyte is formed.
Monitoring the System
To establish protection levels it is necessary to install permanent test
facilities so that stable and accurate potentials may be recorded. The critical
factors involved are the locations of the half-cell and the connection to the
structure being monitored. Because tank farm locations are often subject
to made up ground and imported backfill during the construction stage, halfcell positioning can be critical when determining protection levels. Large
variations in potential readings have been recorded over a radius of three
feet and less. Depth of half-cell and soil contamination from oil etc., may
also affect readings. (Fig. 1).
Costs
Having collected all necessary information relating to the cathodic
protection system to be adopted, a cost appraisal should be made to justify
the expenditure.
Type of Cathodic Protection to be used
Due to such high soil resistivities and the size of most tank farm layouts,
the current requirements dictate that impressed cathodic protection be
used. Seasonal changes may also mean that current outputs have to be
adjusted.
CRITERIA FOR EXTERNAL CATHODIC PROTECTION
Safety Aspects
Safety aspects need to include the positioning of all negative cable
connections away from flanges and valves, etc. Resistor boxes must be
remote from all potentially hazardous environments.
Surface Area to be protected
When calculating the surface area to be protected, consideration should
be given to all ancillary equipment, such as valves, connecting pipework
and drain lines, etc.
Type and Quality of Coating
Information relating to all coated parts need to be taken into
consideration when calculating current requirements. In the case of old tank
farms it is very often the case that there is no reliable information available.
It is quite normal to find a mixture of bare and coated structures throughout
a tank farm.
History of Leak Rate and Anode Failure
Information relating to past leaks should be studied to help evaluate the
effectiveness of previous and existing ground beds. Potential values need
to be examined to help in the analysis when investigating records relating
to leaks.
Additional Current Requirement due to Ancillary Equipment
Consideration to all ancillary equipment related to the tank farm layout
must be taken into account. Items such as drain lines, flow lines, valves
and cable conduit are usually part of the same electrical circuit as the main
structures being protected.
Influence on Other Structures
It is most important that care be taken when introducing cathodic
protection that there is no interaction with other structures, which are not
under the same scheme. This is particularly so when using deep well
ground beds as they tend to have a greater throwing power (Fig. 2).
Ground Conditions
Ground conditions have to be investigated and soil resistivity data
obtained to provide as accurate a picture as possible regarding the overall
electrolyte media.
Other Equipment to be protected
Other equipment to be protected may include water storage tanks,
which can be protected by drawing current from other ground beds via a
variable resistor box (Fig. 3). It is possible to protect a group of tanks in this
way either internally or externally. By installing one or more anodes in or
around such tanks and then regulating the current flow until the desired
potential is achieved.
44
45
Costs
Unlike internal cathodic protection where some tanks and vessels have
a limited life span, external cathodic protection when applied to the above
structures is always justified.
Summary
While it is recognized that long standing accepted data for design is the
preferred option, due to the irregularities encountered in the application of
cathodic protection under discussion, a certain amount of arbitrary
measures and to some extent estimations have to be applied.
When calculating the current requirement, it is wise to assume that
surfaces are bare or poorly coated unless reliable information is to the
contrary.
To assist in the lowering of the groundbed to earth resistance (shallow
groundbeds) excellent results have been achieved by increasing the
groundbed size and by supplying a trickle feed of water from nearby hydrant
standpipes. Although this may lead to over design of groundbed life, it is
compensated for by the lower driving voltage required and the long-term
savings of groundbed replacement.
Results have shown that protection levels are best achieved by locating
groundbeds evenly throughout the area to be protected.
Transformer outputs were as follows:
T/R
V
A
1
28
90
2
60
65
3
40
140
4
17
18
5
30
80
6
20
40
7
12
48
A total of 481 amps was required to protect the 19 storage tanks.
Based on a surface area of 683.395 ft², actual current density =
0.7 mA/ft².
Example of Current Requirement
All field data and calculations below are based on actual information
gained from an operational tank farm.
Tank Farm A
19 tanks 214 ft dia. Surface area = 683, 395 ft²
Current requirements for bare steel in soil = 1-3mA/ft²
Current requirements for poorly coated steel in soil = 0.1 mA/ft²
Based on bare steel current = 683 A – 2.050 A.
Based on poorly coated steel current = 68 A.
To protect fully the above tank farm, seven impressed groundbeds were
installed, three deep well and four shallow.
46
47
APPENDIX I
SUGGESTED APPROACH TO REFINERY TANK
EXTERNAL INSPECTION
Any evidence of deterioration that is considered dangerous to the
operation of the tank must be considered enough reason to place the tank
out of service for immediate corrective measures.
1. Foundation:
- Evaluate evidence of foundation settlement. Excessive settlement
is considered dangerous to the operation of the tank.
a. Concrete ring wall:
- Evaluate extent of concrete cracking and spalling.
- Investigate the condition of any reinforcing steel bars. Diameter
measurements and hammer testing can reveal their condition.
- Surface concrete cracks can be repaired by dressing up the
cracked area with mortar plasters. But if defect is general and
considered to be serious, immediate repair must be considered.
b. Earth Pad:
- Evaluate extent of erosion (if any). Excessive erosion can cause
excessive foundation settlement.
2. Shell:
a. Investigate evidence of shell deformations such as bulging and
buckling. In Cone Roof tanks, such deformation usually indicates
faulty pressure-vacuum vents. This is considered dangerous to the
operation of the tank. In Floating Roof tanks, deformations such as
these are hardly experienced.
b. Investigate evidence of leakage. Spots where there is paint
discoloration or loss of paint films under a discolored spots indicate
leak. The nature of the leak should be fully evaluated whether from
stress cracking or corrosion. In Floating Roof tanks, it is possible
to repair the leak even the tank is still in service by lowering the roof
level to at least one-foot from the leak point. However, only cold
work must be performed. In Cone Roof tanks, repair is only
possible when the tank is out of service because of the inherent risk
involved.
c. Conduct ultrasonic thickness measurements on the shell wall.
Such inspection can give good indication of the condition of the
internal wall. However, if the internal wall can be inspected visually
like in Floating Roof tanks, ultrasonic thickness measurement may
not be required if there is no visible corrosion observed.
48
d. Evaluate the condition of the paint. An area that shows paint
failures such as flaking, peeling-off, blistering, rust creepage, etc.,
should be given proper attention. Whenever accessible, the metal
under this defects must be investigate the extent of corrosion that
may have taken placed.
After where there are deposits of sand, dirt and other foreign materials
should also be investigated whenever possible. Such deposit usually
creates a stagnant condition thereunder and thus, may initiate crevice
corrosion.
Isolated paint failure must be repaired by spot cleaning and spot
painting following a sound procedure for maintenance painting. If failure
were general, it would be wiser to submit the tank to a sound general
repainting procedure. Another acceptable method of determining the
remaining service life of the paint is by film thickness measurement. If the
remaining film thickness is considered insufficient to protect the tank,
repainting should be recommended.
3. Stairway/Platform/Walkway/Handrail:
On these areas, failure usually occurs on spots where crevices are
present. Crevice corrosion is always initiated on these spots. The
extent of this form of corrosion should be evaluated. Shaking the
handrails can give good indication of their condition.
The inspection should show that these parts would remain in good
condition at least until the next inspection. If this cannot be satisfied, an
earlier program for maintenance repair should be recommended.
4. Manway/Clean-out door/Nozzle:
Check for leakage on the manway and clean-out door cover. Leak
indicates loose bolts or defective gaskets. Sometimes, it is the result of
corroded flange mating surfaces between the cover and these
attachments.
Conduct ultrasonic thickness measurements on the necks of all
these shell attachments. Refer to Appendix for the retiring thickness.
Check the roof drain nozzle valve for any evidence of passing
product. If found positive, this indicates faulty roof drain connection and
the valve should be closed. Immediately, the check valve of the roof
center sump should be investigated for possible product overflow.
49
All the telltale holes of the reinforcing pads of these attachments
should be investigated for evidence of leakage. As the term denotes, it
will tell you a tale about a leak. Leaks on this hole indicate either a crack
at the heat-affected zones of the shell opening or weld defect of the
shell attachment.
5. Roof:
Because of the risk involved, inspecting the roof while the tank is
still in service is not advisable. However, when the need arises, safety
precautions laid-out on Sec. 12 of this booklet must be satisfied.
Evaluate the condition of the wheel; the pinion block of the
bearing must be fully lubricated. To check the bearing, it is
advisable to lift the wheel to a certain extent that it can be rolled
freely.
e. Roof leg pipe sleeve/sampling hatch/Auto bleeder:
Visual inspection can satisfactorily show their condition as per
paint failure, broken parts and corrosion.
a. Pressure-Vacuum Vents:
Check condition of the vent. If found in poor condition,
immediate repair should be recommended. It is dangerous to
operate the tank with faulty pressure-vacuum vent because it could
lead to the total failure of the tank. Records should be maintained
with respect to the testing and calibrations of this vent. The vent
must be set to open at 1.30 inch-water pressure and 0.06 inch-water
vacuums.
b. Roof deck and pontoon of Floating Roof tank:
Investigate the roof deck and pontoon bulkheads for flooding.
Unreasonable flooding is dangerous to the operation of the tank.
Small leak that appears like a weep can be located by looking for
signs of paint discoloration. Excessive leak that causes excessive
flooding should be corrected without delay.
Evaluate of the condition of the paint follows the outline given
on item 2d.
c. Roof center sump and check valve:
The center sump should be free from any foreign materials or
debris.
The check valve if found open should be evaluated with respect
to the cleanliness of the ball and the seat. If found closed, do not
attempt to disturbed because this is an indication of product
overflow due to the faulty roof drain connection inside the tank.
Disturbing the valve may not maintain its tightness because of the
possible presence of dirt.
d. Rolling ladder and track:
Check condition of all members in the manner the parts on item
3 is evaluated.
50
51
APPENDIX IIa
APPENDIX IIb
OULTINE OF THE COMMON FORMS OF CORROSION
AND MAJOR CORROSION PROMOTING SUBSTANCES
INSIDE THE REFINERY STORAGE TANKS
SUGGESTED APPROACH TO REFINERY TANK
INTERNAL INSPECTION
Basically, internal inspection calls for the evaluation of the degree of
corrosion that take place inside the tank. Referring to appendix IIa, the parts
that are commonly attacked by corrosion are the floor, roof and the shell.
The severity of corrosion is dependent on the type of the tank and the
service to which it is employed.
Since tank entry is required, it is of utmost importance that all the safety
requirements laid-out for the aspect must be fully satisfied. Refer to Sec.
12.0 for safety requirements for tank entry.
1. Floor:
As compared to the other parts of the tank, perhaps the floor is the
hardest hit with corrosion. This is because of the usual settlement of
contaminated water at the bottom. For mother tanks wherein heavy
deep sludge are formed at the bottom, corrosion of the floor is usually
less because more or less the sludge act as protection. But sometimes,
whenever small pocket of water is trapped underneath, it results to
highly localized corrosion that usually develops into a hole.
Because of the usual dirty condition of the floor, it is advisable to
make as standard practice the cleaning of the floor by means of
abrasive blasting. It is only under this condition that proper and effective
evaluation of the floor can be made.
a. Evaluate the degree of corrosion on the floor:
Referring to Sec. 10.0 and Appendix IIa, weld decay, pitting and
crevice are the common forms of corrosion that are encountered in
tankage. Thus as the primary step of evaluation, it is suggested
that the Inspector should first conduct an overall visual inspection.
If it is observed that severe general corrosion had taken-placed,
renewal of the floor should be recommended. If the condition shows
that renewal is not necessary, the following steps for evaluation are
suggested:
-
52
Investigate all seam welds. An area that exhibits weld decay should
be repaired by grinding the decayed area and weld build-up.
Conduct pitting survey. Perhaps this is the most difficult part of the
inspection. Although still not considered a conclusive evaluation
method, pitting depth measurement with the aide of a pit gauge can
be satisfactory.
53
Isolated pittings with depths exceeding 25% of the original
thickness should be repaired by weld filling.
Areas wherein
concentration of deep pitting is being exhibited, repair is made by
patching. If it is observed that unreasonable scattered shallow and
deep pittings are being exhibited, application of extra heavy thick
coating as corrosion protection should be considered as principal
remedial measure.
b. Conduct thickness survey:
This can be done with the of an ultrasonic thickness measuring
device as described in Sec. 6.0
Usually, two properly oriented straight-line patterns across one
another are satisfactory. If the thickness survey indicates suspect
of corroded underside, it is advisable to cut coupons in progressive
sizes (12” x 12” with increment o at least 2” at both sides) in order
to evaluate the degree of the underside corrosion and at the same
time verify the thickness of the plate. If severe underside corrosion
is evaluated, renewal of the floor must be recommended. Refer to
appendix IV for plate retiring thickness.
c.
Locating leaks:
If the tank has been found leaking during service, methods
described in Sec. 8.0 can be applied whichever is practical.
In most cases, because of abrasive blast cleaning leak are
simply located by looking for traces of wetting. Leaks can be
repaired either by weld filling or patch plates.
d. Look for spots exhibiting crevices:
All crevices should be seal welded because they initiate crevice
corrosion.
e.g. - floor reinforcing plate under roof legs and columns.
- strip plate underneath the level gauge float cable
connection on the tank floor.
e. Annular plates:
In large tanks, this is the principal supporting member at the
bottom region of the shell. It is important that the integrity of this
section is always maintained. Refer to Appendix IV for the retiring
thickness of the annular plate.
54
Evaluation of this section is similar to the floor plate. However,
repair procedure is somehow more stringent. If patch repair is to
be made, the patch plate should not be welded up to the shell. If
unreasonable amount of scattered deep and shallow pittings are
being exhibited, renewal of the plate should be considered.
2. Roof and Supports:
Inspection of the roof and its support is not difficult to undertake. Most
of the inspection performed is on the cone roof and practically very little
inspection is needed on the floating roofs.
a. Locating leaks:
Leaks are simply located by men of visual inspection even
without the use of mobile scaffolding. Hole can be easily seen by
looking for light passage through the roof plate.
In some cases wherein the roof tightness is required, vacuum
testing as mentioned in Sec. 8.0 is also applicable.
Repairs can be by soft patch or by welding patch plate.
Sometimes, soldering is satisfactory.
b. Evaluate the degree of vapor space corrosion:
Requiring mobile scaffolding, visual inspection is a satisfactory
method in the evaluation of the extent of vapor space corrosion that
may take place on the roof plate and support members (truss or
rafters). UT thickness survey is good for the roof plate while caliper
measurement o the dimension of the support member is considered
an effective yardstick in the determination of its serviceability.
The remaining dimension of the support member must be within
the limits of the section modulus given for the design load of the
roof. For asphalt tanks where accumulation of heavy asphalts at
the roof structure is possible, recommendation for the removal of
this accumulation must be made. It could cause additional load to
the roof and may result to overloading.
3. Shell:
The shell is the least attack by corrosion but when corroded,
sometimes it reached a degree that it would be better to erect new
tank as replacement.
55
Tanks that are most susceptible to corroded shell are the Cone
Roof types that are used to carry light intermediate products
because these are the tank that undergoes more filling and
emptying operations. Corrosion is always in the form of wide
shallow and deep elliptical pittings and generally concentrated at
the mid section of the working portion of the shell.
At the lower portion of the bottom shell course, narrow deep
pitting is usually exhibited because of the usual settlement of
corrosive water.
APPENDIX III
SAMPLE REPORT A
ANNULAR PONTOON FLOATING ROOF TANK
EXTERNAL INSPECTION CHECKLIST
Date 20-10-83
No. INP-143/83
Tank Identification T-1219
Service L-Crude Oil
Area TF-4
Nom. Capacity 359, 959 bbls.
Safe Filling Capacity 325, 712 bbls.
Inside Diameter 57 mtr.
Height 16.24 mtrs. Safe Filling Height 14.74 mtrs.
Date Tank Last Inspected 28-8-82
Date Tank Last Cleaned 15-10-73
Inspected by R. S. Ibe
Other Last internal inspection – 10/73
Parts
1. Foundation
2. Shell
a. Paint
b. Thickness
c. Manway/Clean-out
Door & Others
3. Stairway/Platform
& Handrail
4. Roof
a. Paint
b. Pontoon
c. Manholes
d. Drains
e. Vents
f. Roof leg sleeve
g. Anti Rotation Sys.
h. Foam Dam
i. Others
5. Rolling Ladder
& Track
6. Windgirder/Walkway
& Handrail
7. Nozzles/Valves
8. Level Gauge Pipe
9. Nameplate/Base
Miscellaneous
Condition
G
G
VP
G
G
VP
VP
VP
G
G
P
G
G
F
G
F
P
P
VP
G
F
G
Remarks
1. Only superficial cracks were found on the foundation.
2. The tank is exhibiting general paint failure.
3. The platform chequered plate, stairs and the
handrailings were found badly corroded and
considered unsafe
4. The roof center sump was full of dirt and
the drain check valve is in poor condition
5. The anti-rotation rafters are in poor condition.
6. The walkway is exhibiting scattered shallow and
deep pittings Handrails are badly corroded.
7. The railing ladder track chequered plate is
badly corroded
8. Galvanize coating of level gauge pipe has badly
weathered
Recommendations, Placing tank out-of-service
- Dress up the foundation plasters & check grounding
- Renew all parts found badly corroded.
- Weld build-up all deep pitting found on the
walkway plates
- Clean roof center sump, service center checkvalve, ladder wheel bearings, anti-rotation rafters,
all gate valves and among thermal relieve valves
- Submit the tank to general repainting in the earliest
time possible. The use of high performance
point system must be considered.
VP-Very Poor; P-Poor; F-Fair; G-Good; N-Not Accessible/Not Inspected
56
57
APPENDIX III
SAMPLE REPORT B
APPENDIX IV
RETIRING LIMITS OF PLATE THICKNESS
ANNULAR PONTOON FLOATING ROOF TANK
INTERNAL INSPECTION CHECKLIST
1. Tank Shell:
To maintain the safe operation of the tank, the shell plate thickness must
not be less than the minimum thickness laid-out in API Std. 650. The retiring
thickness is reached when the corrosion allowance is gone.
Date 06-02-84
No. INP-005/84
Tank Identification T-1219
Service L-Crude Oil
Area TF-4
Nom. Capacity 359, 959 bbls.
Safe Filling Capacity 325, 712 bbls.
Inside Diameter 57 mtrs.
Height 16.24 mtrs. Safe Filling Height 14.74 mtrs.
Date Tank Last Inspected 20-10-73
Date Tank Last Cleaned 15-10-73
Inspected by R. S. Ibe
Other Last internal inspection – 10/73
Considering one-foot strip from the bottom of the shell course.
Calculation of the shell thickness is as follows:
t = 66(H-1) x D x G + CA
Parts
1. Tank Floor
a. Welds
b. Plate Thickness
c. Annular Plate
d. Roof leg pads
2. Shell Internal Wall
a. Seam Welds
b. Manway/Nozzle
Necks welds to
Shell
3. Roof Deck underside
a. Seal Pan
b. Center Roof Drain Pit
c. Roof drain sys.
or Pipe swivel
d. Roof leg
e. Monkey ladder
4. Roof Seal
a. Mechanical type
- counter weights
5. Water draw-off sys
a. Sump & Pipe
Miscellaneous
Condition
P
P
G
F
G
G
G
G
G
G
F
G
G
G
G
G
G
P
Remarks
1. The floor and the annular plates are
exhibiting scattered shallow and deep
pitting about 50% of the pittings have
Vertical cross-sectional shape.
2. About 50% of the floor lapped weld exhibits
weld decay.
3. The roof leg pads were found skip-welded
only to the floor.
4. About 1-meter of the shell from the floor is
exhibiting scattered narrow-deep pitting.
5. Seal pan of roof emergency drain was found
with thick accumulation of scale
Recommendations:
- Grind and weld build-up weld decays.
- Seal weld all leg pads to the floor.
- Consider the application of glass reinforced
Epoxy (GRE) or polyster (GRP) lining on the
floor plus 1-meter of the shell.
- Clean seal pan
- Service roof drain swivel joints and
check valve.
Others:
All recommendations given in our internal
Inspection report (06-01-84) still stands.
VP-Very Poor; P-Poor; F-Fair; G-Good; N-Not Accessible/Not Inspected
S
where:
t = minimum thickness in millimeters
H = height of the tank in feet
D = tank diameter in feet
G = specific gravity of liquid to be stored
- use 1 if G is less than 1
- use the actual value if G is neared than 1
S = maximum allowable stress in psi
- for bottom course, both high and low strength steels:
the lesser value of:
2/3 of the yield strength or
3/8 of the tensile strength
- for all courses above the bottom course, for low
strength steels;
the lesser value of:
½ of the yield strength or
0.85 of the tensile strength
- for all courses above the bottom course, for high
strength steel;
the lesser value of:
2/3 of the yield strength or
2/5 of the tensile strength
CA = corrosion allowance taken to be 3 mm
(1.5 mm is satisfactory for atmospheric exposure
but additional 1.5 must be considered for the
internal corrosion)
58
59
2. Floor and Roof:
The minimum plate thickness for new plate should not be less than 6
mm for the floor and 5 mm for the roof including corrosion allowance. The
retiring thickness is ½ of the original thickness.
APPENDIX V
SUGGESTED APPROACH FOR FLOOR RENEWAL OF
SMALL CAPACITY TANKS (20, 000-30, 000 bbls.)
Annular plate thickness must not be less than 7 mm including corrosion
allowance. The retiring thickness is reached when the corrosion allowance
is gone.
1. Removal of old floor:
The complete floor shall be fire cut from the inside edge of the ring wall
or 100 mm from the internal wall of the shell s shown in figure A.
In order to have minimum distortion, the floor shall be gauge in 6-phases
(A to F) diametrically opposite as illustrated in the welding sequence figure
B.
After completing the gauging of phase A, wedge or conical pins shall be
used to lift the shell in order to provide sufficient clearance for taking out the
old plates as well as bringing in the new ones.
When the old plates are removed completely, compact bituminous sand
with a slope of at least 1/100 from the center to the outside edge of the ring
wall. At the center if there is a center column, a flat area slightly larger than
the base plate of the column shall be left to assure good stability from the
column. See figure C.
2. Installation of the new plates and welding sequence:
All plates designated “P” in figure B and the center (CP) plate shall be
installed first. The n all plates (PA) within phase A since it is the only phase
open. At this stage, welding of welds “W1”, “W2” and “W4” is possible (fig.
B). The shell shall be tack-welded (50-250 mm) to the new plate at this
phase.
Operate the same for phase B up to F in successive order with respect
to the welding sequence.
At the site, the sequence of some welds (W) may be modified for
convenience. However, it must not be included in the shrinkage (S) frame.
After all the plates are installed and tack-welded to the shell, the
roundness of the tank must be checked before weld “W3” proceeds. As
good practice, W3 must be carried out following the backstep method. Make
sure that the lapped joints at the edge of the floor is formed in such a manner
that it will provide a smooth contour to the shell as shown in detail Z on
figure B.
After all the welds are completed, if there is a center column, the
plumbness of the column must be check before welding its clip guides.
60
61
Testing:
APPENDIV VI
MAINTENANCE PAINTING GUIDELINE
Method laid out in Section 9 of this booklet is applicable:
Lapped joints – vacuum testing
Fillet “W3” welds – Gas-oil
Tank note that gas-oil must be done before the external “W3” proceeds.
1. Sound paint not intended to b removed must not be damaged during
the process of surface preparation.
2. Large areas intended for repainting and where abrasive blast
cleaning is not practical, hydroblasting to a pressure of at least
6,000 psi should be performed. The process is good enough to
remove not well-bounded paints, scums and other surface
contaminants.
This is followed by touch-up cleaning to ensure the further
removal of the contaminants that were not removed during
hydroblasting.
Areas where surface profile is to be maintained should be
abraded by means of mechanical abrader or other suitable means.
3. Hand tool or power tool cleaning are satisfactory methods of
surface preparation of small areas. However, in case of live pipings
or surfaces and areas considered hazardous, the use of power tool
is not allowed. Only sparkle brushes and scrappers are allowed.
4. Junctions between the spot cleaned areas and sound paints should
present a smooth feathered appearance. All spot cleaned areas
must be spot primed and must overlap the adjacent sound paint to
a slight extent for assurance of full coverage.
5. Before the work has progress too far, adhesion of newly applied
paint over any existing sound paint must be investigated. It is
advisable to explore beneath the surface of the new paint coveredover rust and loosening of film. If such conditions are discovered,
the surface must be cleaned and repainted.
6. The effect of newly applied paint over the old underlying film should
be noted. Any evidence of curling, lifting and excessive wrinkling
must be repaired. If defects are general rather than existing in few
isolated areas, the use of difference paint system must be taken
into consideration.
62
63
APPENDIX VII
MISCELLANEOUS DATA AND TABLES
1. Pascal’s Law:
At any point in a fluid at rest, the pressure is the same in all
direction.
2. Pressure:
The intensity of a pressure exerted at any point is the amount of
force per unit area.
calculated in the formula below:
PD
T = (12.7)
St
where:
t - minimum wall thickness in millimeter
P - allowable pressure in psi
D - inside diameter of the pipe in inches
St - tensile stress in psi
F
P =
6. Doubling the diameter of the pipe will increase its carrying capacity
four times.
A
where:
P - the unit pressure.
F - force exerted on a certain area and at all times
acting normal to the plane surface of that area.
A - the cross-section of the area subject to the force F.
7. Rule of thumb: If in a branch connection, twice the design pressure
exceeds the allowable pressure at the header, reinforcing is
required.
For full calculations, methods laid-out in ANSI B31.1 and B31.3
are generally followed.
3. Variation of pressure with respect to the depth of the fluid.
8. For relatively short headers where multiple branch connections are
intended, increasing the thickness of the header can be applied if
reinforcing is not possible.
P = wh
where:
P - the pressure due to the available head in psf.
w - density of the fluid in lb./cu.ft.
h - available head in feet.
To convert psf to psi, divide by 144. Thus, if w = 62.4
lb./cu.ft. (water):
p = 0.433h
9. To find the area of a circle, multiply the square of the diameter by
0.785, or multiply the square of the circumference by 0.0796.
10. To find the diameter of a circle equal in area to a given square,
multiply a side of the square by 1.128.
11. To find the side of a square equal in area to a given circle, multiply
the diameter of the circle by 0.886.
4. Relationship of height of a certain liquid to another liquid.
a. To convert the height of any liquid to height of water,
multiply the height of the liquid by its specific gravity.
b. To convert the height of water to height of liquid, divide the
height of water by the specific gravity of the liquid.
12. To find the surface area of a sphere, multiply the square of the
diameter by 3.14.
5. The retiring thickness of the pipe is considered reached when the
corrosion allowance is gone. As a good guideline, the remaining
thickness must not be lower than the thickness
14. °C = (F-32) : °F = (°C x 1.8) + 32
1.8
15. °C + 273 = °Kelvin : °F + 460 = °Rankine
64
13. To find the volume of a sphere, multiply the cube of the diameter by
0.524.
65
TANK DIAMETER, AREA, VOLUME
Tank
Diam. (m)
5
6
8
10
12
15
16
18
20
22
25
26
28
30
32
35
36
38
40
42
45
46
48
50
Shell Area
/meter ht. (m²)
15.70
18.84
25.12
31.40
37.68
47.10
50.24
56.52
62.80
69.08
78.50
81.64
87.92
94.20
100.48
109.90
113.04
119.32
125.60
131.88
141.30
144.44
150.72
157.00
Bottom Plate
Area (m²)
19.625
28.260
50.240
78.500
113.040
175.630
200.960
254.34
314.00
379.94
490.63
530.66
615.44
706.50
803.84
961.63
1017.36
1133.54
1256.00
1384.74
1589.63
1661.06
1808.64
1962.50
TANK VENT REQUIERMENTS
Volume (bbl)
Per meter ht.
123.44
177.75
316.01
493.77
711.02
1110.97
1264.04
1599.80
1975.06
2389.82
3086.06
3337.85
3871.12
4443.89
5056.15
6048.92
6399.19
7129.97
7900.24
8710.02
9998.74
10448.07
11376.35
12344.13
Over 50 meters, multiply bottom plate area by 6.29 to get bbl. Per meter ht.
of shell.
Tank Size
I.D. (meter)
Max. Pumping
Rate (bbl/hr)
Vent Req’d
No
Size
3–6
1, 000
1
4”
7–9
3, 000
1
6”
10 – 15
5, 000
1
8”
16 – 20
5, 000
1
10”
16 – 20
10, 000
1
12”
21 – 30
5, 000
1
10”
21 – 30
10, 000
1
12”
21 – 30
15, 000
2
10”
31 – 35
5, 000
1
12”
31 – 35
10, 000
2
10”
31 – 35
15, 000
2
10”
31 – 35
20, 000
2
12”
31 – 35
25, 000
2
12”
36 – 45
5, 000
2
10”
36 – 45
10, 000
2
12”
36 – 45
15, 000
2
12”
36 – 45
20, 000
3
12”
36 – 45
25, 000
3
12”
Over 45 Straight line extrapolation of API 2000
Vent Req’d
Heated Tanks
No
Size
1
12”
1
12”
1
24”
1
24”
1
24”
1
24”
1
36”
1
36”
1
36”
1
36”
1
36”
1
36”
1
36”
1
36”
1
36”
1
36”
1
36”
1
36”
The Pressure Vacuum vents shall be used when the ff. conditions apply:
- Flash point of the stock is less than 100 °F.
- Temperature of the stock is above or within 15 °F of its flash point
at the highest of plating temperature.
- The stocks are valuable and have low vapor pressure.
The Pressure-vacuum vent should be set to open at 1.30 inch water
pressure and 0.66 inch water vacuum. Flame arrestors are not required.
66
67
TABLE – VARYING SURFACE CONDITION
TABLE – WORK DONE WITH DIFFERENT NOZZLE SIZES
Surface Condition
Division 1 – New Construction
Class 1
Notes:
1. Removed of heavy mastic, grease and other materials difficult to
remove by sandblasting were not considered.
2. Figures were based on surfaces that are immediately accessible.
3. Brush off grace, light blast cleaning that will remove only loose mill
scale, rust and other foreign matter.
4. Commercial blast grace, thorough blast cleaning that will remove at
least two-thirds of all tightly adhering mill scale, rust and other
foreign matter.
5. Near-white metal grace, very thorough blast cleaning that will
remove at least 95% of the total tightly adhering mill scale, rust and
other foreign matter.
6. White metal grace, blast cleaning to pure metal. All tightly adhering
mill scale rust and other foreign matter are completely removed.
Description
: Steel with tight mill scale
Class 2
: Steel with loose mill scale and
Fine amorphous rust, no pits.
Class 3
: Practically no mill scale, over
rust, some pitting
Division 11 – Maintenance
Class 4
: Thin finish coat, some primer
showing, rust negligible
Class 5
: Thin finish coat, considerable
primer showing, 10% of
surface contains rust, loose
mill scale and loose coating
film.
Class 6
: Finished coat thoroughly
weathered and badly bustered
about 30% of surface contains
rust with pitting and hard scale
Class 7
: Badly pitted steel with rust
nodules.
Note:
1. Class 4 and 5 requires blasting cleaning.
2. Class 1, 2, and 3 requires blast cleaning to remove mill scales and
to provide the desired anchored pattern for better adhesion. The
importance of the removal of mill scale is that it is cathodic to steel
and being cathodic, establishes and electrical corrosion cell that will
result to subsequent ptiing. Moreso, it flakes in slight variation of
temperature thus causing premature failure to coating.
3. Class 6 and 7 requires blast cleaning because of being considered
as general deterioration.
SUGGESTED PRACTICE FOR BLAST CLEANING
1. Cleaning should proceed by sections, bays, or other identifiable
areas of work. Cleaning of each section must be entirely
completed, inspected and accepted before the application of
coating.
2. The substrate should be decrease, all rough edges and protrusions
should be removed and ground to smooth contours before blasting
proceeds.
3. No blast cleaning should be done on surfaces that are moist or will
become moist before the application of coating. It should only
precede when surface temperature is over the dew point or when
the relative humidity is below 80%.
4. No blast-cleaned surface should be allowed to remain uncoated
overnight unless special precautions are taken. Under favorable
condition, only a maximum of 4 hours is allowed for blast-cleaned
surface to remain without coating.
5. To eliminate traces of blast product on the surface, cleaning are
satisfactorily carried out with the use of clean brushes made of hair
bristles, blowing with dry air and vacuum cleaners. Wiping with cloth
or rug should be avoided. They usually introduce lints that are
detrimental to coating adhesion.
68
69
6. To minimize the nuisance of the dusty blast products and to make
blasting faster, the nozzle should be at least aimed 2 to 3 feet from
the surface to be cleaned and at an angle. Ideally, blasting at 45°
angle is most satisfactory.
70
APPENDIX VIII
NDE Requirements Summary API 653 Table F.1
71
Acceptance Standards:
Air Test: None
Pen Oil: None
MTPT: ASME Section VIII, Appendix 8 (paragraphs 8-3,
8-4, 8-5)
RE: ASME Section VIII (paragraph UW-51(b))
Tracer Gas: None
UE: API Std. 650, Section 8.3.2.5
VB: None
VE: API Std 650, Section 8.5.1
Examiner Qualifications:
Air Test: None
Pen Oil: None
MTPT: API Std 650, Section 8.2.3
RE: ASNT SNT-TC-1A Level II or III. Level I personnel
may be used under the supervision of Level II or Level III
personnel with a written procedure in accordance with
ASME Section V, Article 2.
Tracer Gas: None
UE: ASNT SNT-TC-1A Level II or III. Level I personnel
may be used under the supervision of Level II or Level III
personnel with a written procedure in accordance with
ASME Section V, Article 2.
VB: API Std 650, Section 8.6.4
VE: API Std 650, Section 8.5.1
Procedure Requirements:
Air Test: API Std 650, Section 7.3.5
Pen Oil: None
MTPT: ASME Section V
RE: ASME Section V, Article 2
Tracer Gas: API Std 650, Standard 8.1.11.c
UE: ASME Section V
VB: API 650, Section 8.6
VE: None
72
73
APPENDIX IX
NDE Requirements Summary API 650 Annex T
74
75
Acceptance Standards:
MT
: ASME Section VIII, Appendix 6 (Paragraphs 6-3, 6-4, 6-5)
PT
: ASME Section VIII, Appendix 8, (Paragraphs 8-3, 8-4, 8-5)
RT
: ASME Section VIII, Paragraph UW-51(b)
Tracer Gas
: API Std 650, Section 8.6.11.b
UT
: For welds examined by UT in lieu of RT, acceptance standards are in
Annex U.6.6. For UT when RT is used for the requirements of 7.3.2.1,
the acceptance standard is as agreed upon by the Manufacturer and
Purchaser.
VB
: API Std 650, Section 8.6.9
VE
: API Std 650, Section 8.5.2
Examiner Qualifications:
MT
: API Std 650, Section 8.2.3
PT
: API Std 650, Section 8.4.3
RT
: ASNT SNT-TC-1A Level II or III. Level-I personnel may be used under
the supervision of a Level II or Level III with a written procedure in
accordance with ASME Section V, Article 2.
Tracer Gas
: None
UT
: For welds examined by UT in lieu of RT, the inspector must be ASNTTC-1A or CP-189 Level II or Level III per API Std 650 Annex U.4.1. For
UT when RT is used for the requirements of 7.3.2.1, the required
qualifications are ASNT-TC-1A Level II or Level III. A Level I may be
used with restrictions, see API Std 650, Section 8.3.2.
VE
: API Std 650, Section 8.5.1
VB
: API Std 650, Section 8.6.4
Definitions:
MT
Pen Oil
PT
RT
VB
VE
= Magnetic Particle Examination
= Penetrating Oil Test
= Liquid Penetrant Examination
= Radiographic Testing
= Vacuum-Box Testing
= Visual Examination
76
Procedure Requirements:
MT
: ASME Section V, Article 7
PT
: ASME Section V, Article 6
RT
: A procedure is not required. However, the examination method must
comply with ASME Section V, Article 2. Acceptance standards shall be in
accordance with ASME Section VIII, Paragraph UW-51(b).
UT
: For shell welds examined by UT in lieu of RT, ASME, Section V, Article
4 and API Std 650 Annex U.3.5. For welds when RT is used for the
requirements of 7.3.2.1, ASME Section V.
VB
: API Std 650, Sections 8.6.2, 8.6.5, 8.6.6, 8.6.7, and 8.6.8
VE
: None
Tracer Gas
: API Std 650, Section 8.6.11.a
77