This document discusses storage tanks and piping facilities and inspection frequencies at a refinery. It notes that there are 120 total storage tanks, including 13 LPG spheres or mounded bullets. It describes the different types of atmospheric storage tank roofs and lists codes and standards for tank inspection and repair. The document outlines the importance of regular tank inspections to prevent leaks and catastrophic failures. It provides details on inspection techniques, frequencies, and protocols. Record keeping and various tests run during and after maintenance and inspection are also summarized.

1. Storage tank/Piping
Facilities and Inspection Frequencies
Sanal S
Dy. Manager (Insp.)

2. Schematics of Inventory in Refinery
•Total Storage Tanks
: 120
•LPG sphere/Mounded Bullets
: 13

3. Types of
Atmospheric Storage Tank Roofs

4.  Floating roof tanks
• Storing volatile products like Crude, HSD, SK, MS,
Naphtha
• Minimize evaporation and hence improved safety
 Fixed roof tanks
• Storing heavy products like FO, LSHS, VGO, Bitumen
 Floating cum fixed roof tanks
• Storing volatile products with stringent quality
• ATF, JP5
Types of
Atmospheric Storage Tank

5. Common Nomenclature of a Tank
 Fixed Roof

6. Common Nomenclature of a Tank
 External Floating Roof

7. Common Nomenclature of a Tank
 Internal Floating Roof

8.  Prevent leaks into groundwater
 Establish a baseline of tank condition and corrosion rates
 Identify problems to perform repairs before you have a
significant leak or release -Maintain your capital asset
 Minimize chance of catastrophic tank failure
Why Inspect Your Tanks?

9. In Addition:
 OISD 129
 Refinery Operating System (ROS-67)
 ATR
Codes & Standards
 API 650 : Welded Steel Tank for oil storage
This Standard establishes minimum requirements for material, design, fabrication, erection,
and testing for vertical, cylindrical, aboveground, closed- and open-top, welded carbon or
stainless steel storage tanks in various sizes and capacities.
 API 653 : Tank Inspection, Repair, Alteration and Reconstruction
This standard covers Above ground steel storage tanks built to API Standard 650 and its
predecessor API 12C. It provides minimum requirements for maintaining the integrity of such
tanks after they have been placed in-service and addresses inspection, repair, alteration,
relocation, and reconstruction.
 API 651 : Cathodic Protection of Above Ground Storage Tank (AST)
 API 652 : Lining of Above Ground Storage Tank (AST)
 API 575 :Inspection of Atmospheric and Low-Pressure Storage Tanks
This standard provides useful information and recommended practices for the maintenance
and inspections for AST.
 API 571 : Damage Mechanisms Affecting Fixed Equipment in the Refining Industry

10. Safe Work Practices
 Preparing for Internal Inspections:
The standard mandates that all inspection work be
conducted in a manner that assures the safety and health of
inspection personnel and prevents workplace property
damage.
Section 1.4 of API-653 requires the development of safety
procedures


11. Leg Setting
• Floating roofs are provided with pipe
support legs. These support legs
support the roof when the roof is not
in floating condition
• During normal operation the pipe
support legs are kept in low leg
position
• When the roof is landed for repair or
cleaning, the support pipes are kept
in high leg position to provide more
head room for persons working
inside the tank .

12. Tank Inspection

13. Inspection Frequency (6.2)
API-653 provides an extensive list of factors to be considered in determining
appropriate inspection intervals for in- service tanks.
Inspections from Outside the Tank:
• According to the standard, all tanks must receive an external inspection by an
authorized inspector at least once every 5 years, or more frequently
depending on the rate of tank shell corrosion.

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

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

16. Tank M&I
• Empty tank
• Isolate
• Clean and degas
• Inspection blast of floor coating
• API 653 inspection
• Issue preliminary inspection report and develop list of
maintenance/repair items
• Perform tank maintenance and repair work

17. •Tank strapping i.e. calibration
•Final blast
•Tank coating
•Final inspection
•Return tank to service
•Exterior painting or concrete/asphalt work (optional)
•Final construction documentation
Tank M&I

18. Proper Inspection Protocol
 Visual inspection of welds, plates, and appurtenances
 UT (Ultra-sonic Thickness) testing of shell courses, floor, and
roof
 Vacuum testing of all floor weld seams –unless epoxy coated
 Identify bottom side corrosion on floors
 Settlement Survey

19. Tank Inspection Technique
 Magnetic Flux Exclusion (MFE)
 Ultrasonic Testing (UT)
 Vacuum Box Testing
 Dye Penetrant Testing
 Bottom Settlement Survey

20. Nondestructive Examinations (NDEs)
Personnel performing NDEs 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.

21. Tank Internal Corrosion
Tank Bottom*:
For tanks with potential sour water present, check closely for
accelerated corrosive attack. This is usually found at lowest
point & at water collecting pit. Also apply for lower 4”-7” of
internal shell.
Not internal but related, corrosion often occur to the under
side of tank bottom. For assessing the soil side , sample plates
shell be cut, app. Size of 400mm x 400mm (OISD-129)
*Based on experience & personal observations only
Tank Diameter Minimum no. of coupons to be cut
Asphalt bed /old bottom plate Soil
≤ 30.48m 4 10
≤45.8 m 6 12
≥ 45.8 m 8 16

22. Internal Corrosion
Bottom measurement methods ( 4.4.4):
1. Spot UT measurement
2. Visual, internal survey with hammer test
3. MFLT (Magnetic Flux Leakage)
4. Section removal (i.e. coupons)

23. Large MFE/UT Floor Scanner
Scans within 2” of Lap Weld Seams

24. Marking Corrosion Indications
Circles – Topside Corrosion
Square – Bottom side Corrosion

25. Tank Evaluation(4.5)
 Cause of foundation deterioration:
1. Settlement
2. Erosion
3. cracking of concrete ( Calcining, under ground water etc)
calcining (loss of water of hydration) can occur when
concrete has been exposed to sufficiently high temperature
for a period of time. During intermediate cooling periods,
the concrete can absorb moisture, swell, lose its strength,
and crack;
Foundation

26. Tank Shell - Ultrasonic Testing
•On the first shell course an avg. of a minimum of 4 readings shall be taken on each plate
diagonally to arrive at the remaining thickness
•On the second course, thickness measurement shall be carried out at two elevations to cover
all plates
•For the balance shell courses, thickness measurement shall be taken at three elevations
covering bottom, middle and top of the shell

27. Tank Shell
 For tanks in lighter
products service
such as Motor
Spirit & Naphtha,
pitting is generally
observed in the
middle courses of
the shell due to
frequent wetting
and drying of the
shell plates at this
elevation. In such
cases, thickness
survey should be
more extensive on
middle shell
courses

28. Tank Evaluation
 Shell:
1. Extreme upper, non wetted shell area often experience
accelerated corrosion. This is very real possibility in sour crude
or FO storage tanks due to high sulfur content.
2. Flaws, deterioration greater than corrosion allowance must be
evaluated for continued use suitability (4.3.1.1).

29.  Tank Roof/ Support Structural:
1. Roof plates corroded to an average “t” of less than 0.09”(in any
100 inch2). Repair or replaced (4.2.1.2).
2. Should corrosion is found in the upper shell course, the potential
for a like loss should be suspected on the internal roof plates,
rafter/structural members & roof support columns.
3. The supporting members shall be rejected when the overall loss in
thickness of material exceeds 25 % of initial thickness (OISD-129).
Tank Evaluation

30. Compression Plate Secondary Seal
with Wiper Tip on EFR Tank
The space between outer roof periphery and shell- seal by flexible device
providing a reasonable close fit to shell surface (C3.13)

31. Roof Drain
• Emergency roof drain sump shall be filled with clean water before boxing up of
the tank.

32. Roof Drain Hose Inspection
• All swivel joints shall be thickness surveyed and serviced during every outage and
individually hydro tested.
• Roof drain shall be hydro tested at a pressure of 3.5 Kg/cm2. The drain lines including
joints shall be tested for tightness by pressure testing with water at 3.5 Kg/cm2 (ROS 67).

33. Other Tank Appurtenances
• Spiral stairway
• Ladders
• Level gauges
• Pressure vacuum vents : Frequency and procedure outlined in OISD-STD-132
(Inspection of Pressure Relieving Devices).
• Shell and roof man ways
• Drain sumps
• Roof and Structural Members- All structures may be hammer tested.
• Wind Girders etc

34. Other Considerations
• Roof nozzles - shall be thickness gauged
• Roof leg support - shall be removed for inspection and thickness of
sleeves/legs shall be measured. 10% legs shall be removed for inspection.
• Pontoons - Minimum 25% to be thickness gauged.
• Insulation - The insulation from tank bottom shell course approx. 200 mm
shall be kept bare.
• Heating Coil - Heating coil including the supports shall be hammer tested,
particularly at the underside of coil and bends. Ultrasonic thickness
measurement shall be taken. The slope of the heating coils shall be checked
for proper draining of condensate. Sample pipe piece can be cut & removed
for sectioning and assessment of internal corrosion.
• All valves, other mountings and fittings - shall be checked for leakage and
proper functioning. All valves including breather valves shall be serviced
and reset at the required pressure and vacuum settings.
- Reference : OISD-129

35. Certification
Welding procedures and welder certificates shall be
prepared according to ASME Sec.9.
Magnetic and Liquid penetrant testing shall be applied
according to ASME Sec 5. and evaluated according to ASME
Sec.8.

36. Inspection of Storage Tanks During Fabrication
 Inspection of storage tanks during fabrication shall be carried out as per the
requirements of the applicable codes, specifications, drawings etc (OISD-
129)
1. Study of all the technical specifications.
2. Checking the foundation pad and slope.
3. Qualification of welding procedure and welding operator.
4. Checking of underside painting of the bottom plate prior to its laying.
5. Checking of slope of the bottom plate.
6. Checking of each batch of electrodes as per specifications and assurance of
its use as per recommended method by the manufacturer and codes.
7. Checking of proper welding sequence.
8. Evaluating radiography of butt-welded annular (radial) joints and vacuum
box test of the portion of weld on the bottom plate on which shell is to be
erected.

37. 9. Checking of fit-ups and noting of curvature and plumb readings before
and after welding of the shell courses.
10. Evaluating radiography of butt-welded joints as per the applicable
code.
11. A thorough visual check and oil penetrate test of the inside shell to
bottom weld seam before welding from outside.
12. Checking of nozzles/ man ways/ sumps for orientation, fit-ups and
welding.
13. Checking of set up of curb angle, roof trusses and roof plates prior to
welding.
14. Checking of set ups and reinforcement arrangement of wind girders
etc.
15. Checking of PWHT of clean out doors, shell and shell nozzles, where
applicable. After PWHT & before hydro testing, all such weld joints
shall be inspected visually and tested using MT or PT.
16. Checking of Nozzle pad for pneumatic test.
17. Checking of external & internal surfaces .
Inspection of Storage Tanks During Fabrication

38. Vacuum Box Testing of Floor Plate Weld
Seam
 Welds of bottom shall be checked with vacuum box with air pressure between 20kPa and 70 kPa.
Vacuum testing is performed using a testing box approximately 150 mm (6 in.) wide by 750 mm (30 in.) longwith a clear window in
the top, which provides proper visibility to view the area under examination.

39. Dye Penetrant Testing of Shell nozzle
Completed weld attaching nozzle to weld or pad to shell and nozzle neck
shall be to examined by a Magnetic Particle Testing or Dye Penetration Test .
Consideration should be given for extra NDE on hot taps (12.1.2.3)

40. Pressure Testing Pontoons
Following Repairs

41. Hydrostatic Testing (12.3)
A full hydrostatic test , held for 24 hrs. is required on (12.3.1):
• A reconstructed tank
• Any tank that has major repair or alternation (operation that require cutting,
addition, removal and /or replacement of annular plate ring, shell to bottom weld or a
sizable shell segment) 12.3.1.2.
General:
Aim of hydro test is checking welds against leaking as well settlement
control.
Roof plates shall be tested by vacuum box or bubble test. If bubble test is
used, before draining water after hydro test volume above water level shall
pressurized with air not exceeding weight of roof plates.

42. Other Tests
 Cone penetration test shall be carried out at sample plate cut
locations by executing department
 Heating Coils shall be hydraulically tested at 1.5 times operating
pressure and checked for any leaks.
 Oil penetrate test of pontoon rims to bottom deck plate joint.
 Pontoon air test/water test
 Fire Fighting System : Frequency and procedure for checking
shall be as per OISD-STD-142 (Inspection of Fire Fighting
Equipment)

43. Reporting &
Record Keeping

44. Inspection check list
Inspection Checklist:
Annex C of API-653 contains two comprehensive sample
checklists covering the internal and external inspection of
tanks:
 In-service tanks
 Out-of-service tanks
The checklists can aid the tank owner/operator in developing a
tank inspection assessment schedule, and can facilitate the
recording of findings from the inspection.

45. Links
• Annexure 2 ATR recommendations related to
tanks.docx
• Annexure 3 External Inspection Checklist.doc
• Annexure 4 Internal Inspection Checklist.doc
• Annexure 1 Failure Modes in tanks, its effects
and consequences.docx
• ATR 403 - Tnk Repr.docx

46. Offsite Piping Classification
• MS /Naphtha lines
• LPG/LNG lines
• Hydrogen lines
• Fuel gas lines
• Flare lines
• Offsite piping
• Tank farm piping
• Pipelines under Culvert

47. Inspection of Piping
There are three types of inspection of piping:
• Inspection during site fabrication/ erection
• Inspection during precommisioning
• Inspection Post commissioning
TYPES OF INSPECTIONS
a) External On Stream Inspection: Visual and instrument-aided (ultrasonic,
radiographic, thermo graphic
b) Comprehensive Inspection: External on-stream + pipeline specific inspection (based on
damage mechanism, on-stream availability etc)

48. In Addition:
 OISD 130
 Refinery Operating System (ROS-44 (Inspection and testing of pipelines and ,
ROS-60 Guide lines for prevention of external of pipelines )
Codes & Standards
API 570 : Piping Inspection Code In-service Inspection, Rating, Repair, and Alteration of Piping
Systems
This standard covers inspection, rating, repair, and alteration procedures for metallic and
fiberglass reinforced plastic (FRP) piping systems and their associated pressure relieving
devices that have been placed in-service.
 ASME B31.3 : Process Piping
This Code prescribes requirements for materials and components, design, fabrication,
assembly, erection, examination, inspection, and testing of piping
 API 571 : Damage Mechanisms Affecting Fixed Equipment in the Refining Industry
 API 577: Welding inspection and metallurgy
 PIPING MATERIAL SPECIFICATION CEMP -I , CEMP -II , SPF

49. Types of pipes
• Electric Resistance Welded Pipes
• Electric Fusion Welded Pipes
• Double Submerged Arc Welding Pipes
• Spiral Welded Pipes
• Seamless Pipes

50. Frequency of inspection
• The frequency and extent of inspection of piping system shall depend upon the form of
degradation that can affect the piping performance and consequence of piping failures
• The piping system shall be categorized into 3 classes based on the severity of
consequences of failure.
• CLASS I
• CLASS II
• CLASS III

52. In case, high corrosion rates are observed and half the remaining life is less than the
above mentioned scheduled intervals, then the comprehensive inspection interval
shall be suitably reduced to ensure that maximum inspection interval shall not be
more than half the remaining life.
Example: 1. Total thickness allowance available is 3 mm.
2. Corrosion rate is 0.2 mm per year
3. Remaining life = 3/0.2= 15 years
4. Half remaining life = 7.5 years
5. Hence comprehensive inspection interval shall not exceed 7.5 years

53. EXTERNAL ON-STREAM INSPECTION:
Visual Inspection:
Leaks (pipe connections, the packing glands of valves and expansion joints )
Alignment (Pipe dislodged from its support) ,
Supports (Movement or deterioration of concrete footings ),
Vibration ( check the weld joint for cracks) ,
External Corrosion ( ROS-60) ,
Bulging, Bowing and Sagging, Mechanical Damage from External Forces, Paint and Protective
Coating, Cracks, Insulation, Concrete Lining

54. EXTERNAL ON-STREAM INSPECTION:
Ultrasonic Thickness Survey:
Aboveground pipelines:
• One reading shall be at the centre of the bend and two readings on the same line on
either side of this reading.
• Minimum one ultrasonic scan each on the straight pipes on upstream and
downstream of the bend adjacent to welds of the bend to pipe
• One ultrasonic scan on the entire circumference (four readings) upstream and
downstream of the weld joint for process pipelines
• Minimum one ultrasonic scan (four readings) each on reducer/ expander and just
downstream on the pipe

55. EXTERNAL ON-STREAM INSPECTION:
• One ultrasonic scan on the pipe downstream of valves orifices, etc
• One ultrasonic scan minimum on horizontal pipe for every three meters length at
lower elevations where possibilities of collection and stagnation of carryover water, or
acid condensation or SO2 flow exist
• Branch connection, dead ends, etc, shall be checked by ultrasonic thickness survey
for corrosion and erosion
• Necessary work permit shall be taken as per OISD-STD-105 while carrying out
thickness survey
• The details of thickness survey shall be maintained on an isometric sketch.

56. EXTERNAL ON-STREAM INSPECTION:
Long range ultrasonic guided wave technology should be deployed to assess metal
loss in inaccessible location not covered under conventional ultra sonic thickness
measurement.
Radiographic Inspection: Critical spots, which cannot be inspected by ultrasonic
instruments accurately, shall be radiographed during operation to determine wall
thickness as well as internal conditions like fouling, scaling, etc.

57. Comprehensive Inspection
• Comprehensive inspection of pipelines shall include external inspections as covered
in external on-stream inspection and
• Inspection for Corrosion, Erosion and Fouling
• Inspection for Cracks
• Inspection of Gasket Faces of Flanges
• Inspection of Hot Spots
• Hammer Testing
• Pressure Testing

58. Pressure testing
Pressure testing of existing pipelines shall be carried out in the following conditions;
• After any major alteration / re-rating / replacement
• Inaccessible piping and complicated manifold
• System after chemical cleaning
• When the piping is out of service for more than six months
• Austenitic stainless steel piping shall be hydro-tested using water with chloride
content less than 50 PPM
• Stress due to testing shall not exceed 90% of the yield stress of the material of
construction of the piping.

59. Pressure testing
.
All newly installed piping shall be pressure tested prior to commissioning.
Hammer testing of piping undergoing a pressure test shall not be carried out.
Hammer testing of valves, pipes and fittings of cast iron construction, chrome-steel,
austenitic SS lines and stress relieved lines shall not be carried out
Pressure test shall not be carried out at metal temperatures near the ductile-to-brittle tem
Hydrostatic test pressure = 1.5 times design pressure * temperature correction (B 31.3)

60. Pneumatic test:
Pneumatic testing shall be considered only in the following cases:
Piping system which cannot safely be filled with liquid due to their design or supports
Piping system where traces of testing medium (liquid) is not permitted in the process
( example flare lines)
• Individual Components 1.1 x Design Pressure of component
• Systems 1.1 x Design Pressure of the weakest component in the system

61. INSPECTION OF HIGH TEMPERATURE PIPING :
• Thermographic survey of internally lined hot piping helps in locating the hot spots.
• Insulation shall be removed at specified locations including all bends and ultrasonic thickness
shall be carried out and the corrosion rate established.
• Spring hangers and spring supports of high temperature piping shall also be checked during
shutdown.
INSPECTION OF UNDERGROUND PIPING :
For Inspection of underground piping, special care is required to be given due to significant
external deterioration caused by corrosive soil condition
• These pipelines shall be inspected once in five years by using the suitable Coating Surveys such
as Pearson Survey, Current Attenuation Technique (CAT), Direct Voltage Gradient Survey
(DCVG) etc.
• All these lines shall be visually inspected at random once in ten years by digging at a few
locations. After excavation, the coating and wrapping shall be examined both visually and by
holiday detector. Pipelines crossing the roads and dykes shall also be inspected once in ten years
by digging and exposing the line completely.
.

62. INSPECTIONS IN SPECIFIC AREAS FOR CORROSION AND
CRACKING
Injection Points:
Injection points are sometimes subject to accelerated or localized corrosion from
normal or abnormal operating conditions
When designating an injection point circuit for the purposes of inspection, the
recommended upstream limit of the injection point circuit is a minimum of 12 inches
(300mm) or three pipe diameters upstream of the injection point, whichever is
greater. The recommended downstream limit of the injection point circuit is the
second change in flow direction past the injection point, or 25 feet (7.6 m) beyond the
first change in flow direction, whichever is less
Deadlegs:
The corrosion rate in dead legs can vary significantly from adjacent active piping. The
wall thickness should be monitored on selected dead legs, including both the
stagnant end and at the connection to an active line.

63. Corrosion under insulation (CUI)
The most common forms of CUI are localized corrosion of carbon steel and chloride
stress corrosion cracking of austenitic stainless steels. ( Temp -4 degree up to 120
degree)
Soil to Air Interface
Soil-to-air interfaces for buried piping without adequate cathodic protection shall be
included in scheduled external piping inspections
If the buried piping is uncoated at grade, consideration should be given to excavating
6 inches to 12 inches (150mm to 300mm) deep to assess the potential for hidden
damage
Small Bore Piping
Piping less than or equal to NPS 2” is considered as small bore piping. The vents,
drains in the main piping system, auxiliary instruments and machinery connections
and threaded connections and dead legs fall in the category of SBP

64. REPAIRS AND ALTERATIONS
• The thickness reduction, damages etc. shall be ascertained to determine adequacy
for continued service in line with the design standards. In case pipeline sections fail to
qualify the minimum requirements, affected sections of the pipeline shall be replaced
or repaired in line with the design code.
• Painting, insulation, wrapping and coating shall be done as per the design code
• All repair and alteration work shall be authorized and approved

65. Likely area of metal deterioration
External
• Above piping ground is subject to atmospheric corrosion
• Pipelines touching the ground are subject to corrosion due to dampness of the soil
• Crevice corrosion may take place at the pipe supports or sleepers where pipes are resting on
them.
• Deterioration takes place at the pipe support locations where relative movement between pipe and
pipe supports takes place.
• Buried pipelines are subject to soil corrosion
• Impingement attack may take place on pipelines in the vicinity of leaky pipes and steam traps.
• Insulated lines where weather shielding is damaged are subject to external corrosion
• Externally concrete-lined pipelines are subject to localised corrosion due to cracks in the concrete.
• Piping entering into or emerging from the underground may experience severe corrosion due to
coating damage
• Piping corrodes at locations of water accumulation and acid vapour condensation such as in the
vicinity of fire hydrants sulphur recovery plants, cooling towers, jetty, etc

66. Likely area of metal deterioration
• Internal
Usually a greater loss of metal wastage is observed near a restriction in the line or a
change in line direction because of the effects of turbulence or velocity. Therefore, it
is required to inspect pipe bends, elbows, and tees and also at restrictions such as
orifice flanges and throttling valves, and areas just down stream of the restriction.

67. Repairs by Welding:
Temporary repairs:
• Temporary repairs, including on stream or off stream, a full encircle split sleeve or
box type enclosure designed to take care of internal pressure can be considered over
damaged or corroded area. Area with longitudinal cracks shall not be repaired by
encircle sleeve.
• If repair area is small and localized, temporary repair may be carried out using
properly designed split coupling or fillet plate patch. The material of repair will match
with base metal.
• Areas with minor leaks shall be attended by welding of properly designed enclosures
• Temporary repairs shall be removed and replaced with permanent repairs at the next
available maintenance opportunity. Temporary repairs may remain in place for a
longer period of time only if approved and documented

68. Permanent repairs:
• All repairs and alteration welding shall be done in accordance to the code to which
the piping system has been built ( ASME B31.3)
• Corroded areas may be restored with weld deposits. However, Surface irregularities
and contaminations shall be removed before welding.
• Insert plates may be used to repair the damaged or corroded areas provided
following are met
(i) Full penetration groove welds
(ii) 100% radiography of joints for hydrocarbon/ critical service

69. • During out of service repair, the defective area shall be removed by cutting the
cylindrical sections and replacing it with piping component which meet the code
requirement.
• Wherever excessive corrosion/ erosion is observed at support locations,
consideration may be given to attaching a pipe pad at support locations for enhancing
life of pipeline
Non Welding Repairs:
• Clamping: Bolted clamps: The effect of clamping (crushing) forces on the component
shall be considered.
• Composite Sleeves: Composite sleeves shall not be used to repair leaks, metal loss
with a depth greater than 80% of the nominal wall thickness, cracks, or
circumferentially oriented defects.

70. INSPECTION DURING REPAIRS/REPLACEMENTS:
• The metallurgy and dimensions of the new pipe shall match with those of the existing
pipe.
• b) Repairs shall be carried out by a qualified welder using approved welding
procedures.
• c) For longitudinally welded pipes, the weld seam shall be kept staggered and the
longitudinal seam shall be kept in the upper quadrants.
• d) Piping systems repair work shall comply with applicable statutory requirements.
• e) Repaired welds shall be subject to same pre and post-weld heat treatments as
required in the case of new pipes

71. DOCUMENTATION:
Identification of particular piping systems in terms of location, class, total length,
material specification, general process flow and service condition and location of
corrosion probes, if any.
Location of thickness measurement points, replacement carried out, corrosion rate,
etc
All testing and inspection records shall be maintained
On the basis of records of previous and present inspection, a work schedule shall be
prepared for future on stream as well as comprehensive inspections

72. Links
• 001 fitup record format rev 4.doc
• 045 REQUEST FOR WELDER
QUALIFICATION TEST.doc
• 047 Format for Deviation.doc

73. Thank you