API 570 P IPING I NSPECTOR
P REPARATORY C OURSE
COURSE NOTES
Conducted by
P. S. JOSHI. Asian Business Consultants. Pune
Pune..
1
API 570 P IPING I NSPECTOR
P REPARATORY C OURSE
TABLE OF CONTENTS
CHAPTER
DESCRIPTION
1.
Overwiew of API 570
2.
Overview of RP- API 574
3.
Overwiew of ASME B 31.3
4.
Overview of ASME B 16.5
5.
Overview of ASME Section IX
6.
Overview of ASME Section V
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CHAPTER-1
570 PIPING INSPECTION CODE
1.
1.1
1.1.1
INTRODUCTION TO API-570
SCOPE
Coverage :
API 570 covers inspection, repair, alteration, and rerating procedures for metallic
piping systems that have been in service.
Repair ; The work necessary to restore a piping system to a condition suitable
for safe operation at the design condition.
Alterations : A physical change in any component that has design implications
affecting the pressure containing capability or flexibility of a piping system
beyond the scope of its design.
Rerating : A change in either or both the design temperature or the maximum
allowable working pressure of a piping system. A rerating may consist of an
increase, a decrease, or a combination of both. Rerating below original design
conditions is a means to provide increased corrosion allowance.
1.1.2
LIMITATIONS :
API 570 shall not be used as a substitute for the original construction
requirements governing a piping system before it is placed in service.
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1.2
SPECIFIC APPLICATIONS
1.2.1
Included Fluid Services :
API 570 applies to piping systems for process fluids, hydrocarbons, and
similar flammable or toxic fluid services, such as the following.
a.
Raw, intermediate, and finished petroleum products.
b.
Raw intermediate, and finished chemical products.
c.
Catalyst lines.
d.
Hydrogen, natural gas, fuel gas, and flare systems.
e.
Sour water and hazardous waste streams above threshold limits, as
defined by jurisdictional regulations.
f.
Hazardous
chemicals
above
threshold
limits,
as
defined
by
jurisdictional regulations.
1.2.2 Excluded and Optional Piping Systems :
The fluid services and classes of piping systems listed below are excluded from the
specific requirements of API 570 but may be included at the owner’s or user’s
(owner/user’s) option.
a.
Fluid services that are excluded or optional include the following.
1.
Hazardous fluid services below threshold limits, as defined by
jurisdictional regulations.
2.
Water (including fire protection systems) , steam, steam-condensate,
boiler feed water, and Category D fluid services, as defined in ASME B
31.3
4
b.
Classes of piping systems that are excluded or optional are as follows :
1.
Piping systems on movable structures covered by jurisdictional
regulations, including piping systems on trucks, ships, barges, and
other mobile equipment.
2.
Piping systems that are an integral part or component or rotating or
reciprocating mechanical devices, such as pumps, compressors,
turbines, generators, engines, and hydraulic or pneumatic cylinders
where the primary design considerations and/or stresses are derived
from the functional requirements of the device.
3.
Internal piping or tubing of fired heaters and boilers, including tubes,
tube headers, return bends, external crossovers, and manifolds.
4.
Pressure vessels, heaters, furnaces, heat exchangers, and other fluid
handling or processing equipment, including internal piping and
connections for external piping.
5.
Plumbing, sanitary sewers, process waste sewers, and storm sewers.
6.
Piping or tubing with an outside diameter not exceeding that of NPS ½.
7.
Nonmetallic piping and polymeric or glass-lined piping.
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2.
2.1
DEFINITIONS
APPLICATION CODE :
The code, code section, or other recognized and generally accepted engineering
standard or practice to which the piping system was built or which is deemed by
the owner or user or the piping engineer to be most appropriate for the situation,
including but not limited to the latest edition of ASME B 31.3
2.2
AUTHORIZED INSPECTION AGENCY :
Defined as any of the following. :
a.
The inspection organization of the jurisdiction in which the piping system is
used.
b.
The inspection organization of an insurance company that is licensed or
registered to write insurance for piping systems.
c.
An owner or user of piping systems who maintains an inspection
organization for activities relating only to his equipment and not for piping
systems intended for sale or resale.
d.
An independent inspection organization employed by or under contract to
the owner or user of piping systems that are used only by the owner or
user and not for sale or resale.
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e.
An independent inspection organization licensed or recognized by the
jurisdiction in which the piping system is used and employed by or under
contract to the owner or user.
2.3
AUTHORIZED PIPING INSPECTOR :
An employee of an authorized inspection agency who is qualified and certified to
perform the functions specified in API 570. A nondestructive (NDE) examiner is
not required to be an authorized piping inspector. Whenever the term inspector
is used in API 570, it refers to an authorized piping inspector.
2.4
AUXILLARY PIPING :
Instrument and machinery piping, typically small-bore secondary process piping
that can be isolated from primary piping systems. Examples include flush lines,
seal oil lines, analyzer lines, balance lines, buffer gas lines, drains and vents.
2.5
CUI :
Corrosion under insulation, including stress corrosion cracking under insulation.
2.6
DEADLEGS :
Components of a piping system that normally have no significant flow. Examples
include the following
:
blanked branches, lines with normally closed block
valves, lines with one end blanked, pressurized dummy support legs, stagnant
control valve bypass piping, spare pump piping, level bridles, relief valve inlet
and outlet header piping, pump trim bypass lines, high point vents, sample
points, drains, bleeders, and instrument connections.
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2.7
DEFECT :
An imperfection of a type or magnitude exceeding the acceptable criteria.
2.8
EXAMINER :
A person who assists the inspector by performing specific nondestructive
examination (NDE) on piping system components but does not evaluate the
results of those examinations in accordance with API 570, unless specifically
trained and authorized to do so by the owner or user. The examiner need not be
qualified in accordance with API 570.
2.9
HOLD POINT :
A point in the repair or alteration process beyond which work may not proceed
until the required inspection has been performed and documented.
2.10 IMPERFECTIONS :
Flaws or other discontinuities noted during inspection that may be subject to
acceptance criteria during an engineering and inspection analysis.
2.11 INDICATION :
A response or evidence resulting from the application of a nondestructive
evaluation technique.
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2.12 INJECTION POINT :
Locations where relatively small quantities of materials are injected into process
streams to control chemistry or other process variables. Injection points do not
include locations where two process streams join.
2.13 IN-SERVICE :
Refers to piping systems that have been placed in operation, as opposed to new
construction prior to being placed in service.
2.14 INSPECTOR :
An authorized piping inspector.
2.15 LEVEL BRIDLE :
A level gauge glass piping assembly attached to a vessel.
2.16
MAXIMUM ALLOWABLE WORKING PRESSURE (MAWP)
The maximum internal pressure permitted in the piping system for continued
operation at the most severe condition of coincident internal or external pressure
and temperature (maximum and minimum) expected during service. It is the
same as the design pressure, as defined in ASME B 31.3 and other code
sections, and is subject to the same rules relating to allowances for variations of
pressure or temperature or both.
9
2.17 ON-STREAM :
Piping containing any amount of process fluid.
2.18 PIPING CIRCUIT :
A section of piping that has all points exposed to an environment of similar
corrosivity and that is of similar design conditions and construction material.
2.19 PRIMARY PROCESS PIPING :
Process piping in normal, active service that cannot be valved off or, if it were
valved off, would significantly affect unit operability.
Primary process piping
normally includes all process piping greater than NPS 2.
2.20
REPAIR ORGANIZATION :
Any of the following :
a.
An owner or user of piping systems who repairs or alters his or her own
equipment in accordance with API 570.
b.
A contractor whose qualifications are acceptable to the owner or user of
piping systems and who makes repairs or alterations in accordance with
API 570.
c.
One who is authorized by, acceptable to, or otherwise not prohibited by
the jurisdiction and who makes repairs in accordance with API 570.
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2.21 SECONDARY PROCESS PIPING :
Small-bore (less than or equal to NPS 2) process piping downstream of normally
closed block valves.
2.22 SMALL-BORE PIPING (SBP) :
Piping that is less than or equal to NPS 2.
2.23 SOIL-TO AIR (S/A) INTERFACE :
An area in which external corrosion may occur on partially buried pipe. The zone
of the corrosion will vary depending on factors such as moisture, oxygen content
of the soil, and operating temperature. The zone generally is considered to be
from 12 inches (305 mm) below to 6 inches (150 mm) above the soil surface.
Pipe running parallel with the soil surface that contacts the soil is included.
2.24 SPOOL :
A section of piping encompassed by fianges or other connecting fittings such as
unions.
2.25 TEMPER EMBRITTLEMENT :
A loss of ductility and notch toughness in susceptible low-alloy steels, such as 1
¼ Cr and 2 ¼ Cr, due to prolonged exposure to high-temperature service [700 o
F-1070oF (370oC-575oC) ]
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2.26 TEMPORARY REPAIRS :
Repairs made to piping systems in order to restore sufficient integrity to continue
safe operation until permanent repairs can be scheduled and accomplished
within a time period acceptable to the inspector or piping engineer.
2.27 TEST POINT :
An area defined by a circle having a diameter not greater than 2 inches (50 mm)
for a line diameter not exceeding 10 inches (250 mm) or not greater than 3
inches (75 mm) for larger lines. Thickness readings may be averaged within this
area. A test point shall be within a thickness measurement location.
2.28 THICKNESS MEASUREMENT LOCATIONS (TMLs) :
Designated areas on piping systems where periodic inspections and thickness
measurement’s are conducted.
2.29 WFMT :
Wet fluorescent magnetic -particle testing.
3.
OWNER/ INSPECTION ORGANISATION
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3.1
API AUTHORIZED PIPING INSPECTOR QUALIFICATION AND
CERTIFICATION :
Authorized piping inspectors shall have education and experience in accordance
with Appendix A of this inspection code. Authorized piping inspectors shall be
certified by the American Petroleum Institute in accordance with the provisions of
Appendix A. Whenever the term inspector is used in this document, it refers to
an authorized piping inspector.
3.2
RESPONSIBILITIES :
3.2.1 An owner/user organization is responsible for developing, documenting,
implementing, executing, and assessing piping inspection systems and
inspection procedures that will meet the requirements of this inspection code.
These systems and procedures will be contained in a quality assurance
inspection manual or written procedures and shall include :
a.
Organization and reporting structure for inspection personnel.
b.
Documenting
and
maintaining
inspection
and
quality
assurance
procedures.
c.
Documenting and reporting inspection and test results.
d.
Corrective action for inspection and test results.
e.
Internal auditing for compliance with the quality assurance inspection
manual.
f.
Review and approval of drawings, design calculations, and specifications
for repairs, alterations, and re-ratings.
g.
Ensuring that all jurisdictional requirements for piping inspection, repairs,
alterations, and re-rating are continuously met.
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h.
Reporting to the authorized piping inspector any process changes that
could affect piping integrity.
i.
Training requirements for inspection personnel regarding inspection tools,
techniques, and technical knowledge base.
j.
Controls necessary so that only qualified welders and procedures are
used for all repairs and alterations.
k.
Controls necessary so that only qualified nondestructive examination
(NDE) personnel and procedures are utilized.
l.
Controls necessary so that only materials conforming to the applicable
section of the ASME Code are utilized for repairs and alterations.
m.
Controls necessary so that all inspection measurement and test
equipment are properly maintained and calibrated.
n.
Controls necessary so that the work of contract inspection or repair
organizations meet the same inspection requirements as the owner/user
organization.
o.
Internal auditing requirements for the quality control system for pressurerelieving devoices.
3.2.2 PIPING ENGINEER :
The piping engineer is responsible to the owner/user for activities involving
design, engineering review, analysis, or evaluation of piping systems covered by
API 570.
3.2.3 REPAIR ORGANIZATION :
The repair organization shall be responsible to the owner/user and shall provide
the materials, equipment, quality control, and workmanship necessary to
maintain and repair the piping systems in accordance with the requirements of
API 570.
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3.2.4 AUTHORIZED PIPING INSPECTOR :
When inspections, repairs, or alterations are being conducted on piping systems,
an API authorized piping inspector shall be responsible to the owner/user for
determining that the requirements of API 570 on inspection, examination, and
testing are met, and shall be directly involved in the inspection activities. The
API authorized piping inspector may be assisted in performing visual inspections
by other properly trained and qualified individuals, who may or may not be
certified piping inspectors. Personnel performing nondestructive examinations
shall meet the qualifications identified in 3.12, but need not be API authorized
piping inspectors.
However, all examination results must be evaluated and
accepted by the API- authorized piping inspector.
3.2.5 OTHER PERSONNEL :
Operating, maintenance, or other personnel who have special knowledge or
expertise related to particular piping systems shall be responsible for promptly
making the inspector or piping engineer aware of any unusual conditions that
may develop and for providing other assistance, where appropriate.
INSPECTION AND TESTING
1.
RISK BASED INSPECTION (RBI)
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RBI is identifying and evaluating potential degradation consequence of which
may be a risk of creation of unsafe conditions (for plant, process, people ) and /
or likely failure of component.
RBI involves following essential elements :
2.
•
Expected type of degradation i.e. type of degradation process as well as
environmental factors may cause.
•
Likely areas affected i.e. identifying the most prone areas and possible
locations to look for the type of degradation.
•
Measurement of degradation i.e. quantifying the amount of degradation.
•
Assessment and evaluation i.e. analysis of degradation and likely
consequences.
•
Above all effectiveness of inspection practices, tools techniques employed
have a great bearing of success of RBI program.
PREPARATION :
Prior to actual inspection proper preparation and safety precautions are essential
particularly if components are to be inspected internally. This essentially involves
-
3.
•
Isolating and segregating the piping system, installing blanks (blids) etc.
•
Removal of harmful liquids, gases, vapors, flushing out and purging to bring
down residual content to safe levels.
•
Obtain suitable permissions to work i.e. cold work permit (CWP), Hotwork
Permits (HWP) etc.
•
Protective equipment, clothing, masking as required.
•
Safety equipments shall be subjectto operating facilities safety requirements.
(e. g. electrical requirements, flame arrester etc.)
INSPECTION FOR SPECIFIC TYPES OF CORROSION AND
CRACKING :
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Each owner/ user should provide specific attention to the need for
inspection of piping system that are susceptible to the following specific
types & areas of deterioration :
3.1
a.
Injection points.
b.
Deadlegs.
c.
Corrosion under insulation ( CUI ).
d.
Soil-to-air (S/A ) interfaces.
e.
Services specific & localized corrosion.
f.
Erosion &c orrosion/erosion.
g.
Environmental cracking.
h.
Corrosion beneath linings & deposits.
i.
Fatigue cracking .
j.
Creep cracking.
k.
Brittle fracture.
l.
Freeze damage.
.
Injection Points : Injection points are sometimes subject to accelerated or
localized corrosion.
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 (300) or three pipe diameters upstream of the injection point, whichever is
greater. The recommended downstream limit of the injection point circuit is the
seconed change in flow direction past the injection point, or 25 feet (7.6 m)
beyond the first change in flow direction, whichever is less. In some cases, it may
17
be more appropriate to extend this circuit to the next piece of pressure
equipment.
Guide Lines For Selecting TMLS :
a.
Establish TMLs on appropriate fittings within the injection point
circuit.
b.
Establish TMLs on the pipe wall at the location of expected pipe
wall impingement of injected fiuid.
c.
TMLs at intermediate locations along the longer straight piping
within the injection point circuit may be required.
d.
Establish TMLs at both the upstream & downstream limit of the injection
point circuit.
The preferred methods of inspecting injection points are radiography and/or
ultrasonics, as appropriate, to establish the minimum thickness at each TML.
For some applications, it is beneficial to remove piping spools to facilitate a visual
inspection of the inside surface. However, thickness measurements will still be
required to determine the remaining thickness.
During periodic scheduled inspections, more extensive inspection should be
applied to an area beginning 12 inches (300 mm) upstream of the injection
nozzle and continuing for at least ten pipe diameters downstream of the injection
point. Additionally, measure and record the thickness at all TMLs within the
injection point circuit.
3.2
Deadlegs : The corrosion rate in deadlegs can vary significantly from the
adjacent active piping. The inspector should monitor wall thickness on selected
deadlegs, including both the stagnant end and at the connection to an active line.
In hot piping systems, the high-point area may corrode due to convective
18
currents set up in the deadlegs. Consideration should be given to removing
deadlegs that serve no further process purpose.
3.3.
Corrosion Under Insulation : External inspection of insulated piping systems
should include a review of the integrity of the insulation system for conditions that
cold lead to corrosion under insulation (CUI) and for signs of ongoing CUI.
Sources of moisture may include rain, water leaks, condensation and deluge
systems. The most common forms of CUI are localized corrosion of carbon steel
and chloride stress corrosion cracking of austenitic stainless steels.
Below are the guidelines for indentifying potential CUI areas for inspection. The
extent of a CUI inspection program may vary depending on the local climate –
warmer marine locations may require a very active program; whereas cooler,
drier, mid-continent locations may not need as extensive a program.
3.4
Insulated Piping Systems Susceptible to CUI : Certain areas and types of
piping systems are potentially more susceptible to CUI, including the following :
a.
Areas exposed to mist overspray from cooling water towers.
b.
Areas exposed to steam vents.
c.
Areas exposed to deluge systems
d.
Areas subject to process spills, ingress of moisture , or acid vapors.
e.
Carbon steel piping systems, including those insulated for personnel
protection, operation between 250 F- 2500 F (-40C-1200 C). CUI is
particularly aggressive where operating temperatures cause frequent or
continuous condensation and re-evaporation of atmospheric moisture.
f.
Carbon steel piping systems that normally operate in-service above 250 0
F (1200C) but are in intermittent service.
g.
Deadlegs and attachments that protrude from insulated piping and operate
at a different temperature than the operating temperature of the active
line.
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h.
Austenitic stainless steel piping systems operating 150 0F- 4000 F (650C2040C). (These systems are susceptible to chloride cracking. )
i.
Vibrating piping systems that have a tendency to inflict damage to
insulation jacketing providing a path for water ingress.
j.
Steam traced piping systems that may experience tracing leaks, especially
at tubing fitting beneath the insulation.
k.
3.5
Piping systems with deteriorated coatings and/or wrappings.
Common Locations on Piping Systems Susceptible to CUI : The areas of
piping systems listed above may have specific locations within them that are
more susceptible to CUI, including the following :
a.
All penetrations or breaches in the insulation jacketing systems, such as :
1.
Deadlegs (vents, drains, and other similar items)
2.
Pipe hangers and other supports.
3.
Valves and fittings (irregular insulation surfaces)
4.
Bolted-on pipe shoes.
5.
Steam tracer tubing penetrations.
b.
Termination of insulation at flangers and other piping components.
c.
Damaged or missing insulation jacketing
d.
Insulation jacketing seams located on the top of horizontal piping or
imporperty lapped or sealed insulation jacketing.
e.
Termination of insulation in a vertical pipe.
f.
Caulking that has hardened, has separated, or is missing.
g.
Bulges or staining of the insulation or jacketing system or missing bands
(Bulges may indicate corrosion product buildup).
20
h.
Low points in piping systems that have a known breach in the insulation
system, including low points in long unsupported piping runs.
i.
Carbon or low-alloy steel flanges, bolting, and other components under
insulation in high-alloy piping systems.
3.6
Soil-to-Air Interface : Soil-to-air (S/A) interfaces for buried piping without
adequate cathodic protection shall be included in scheduled external piping
inspections.)
Thickness measurements and excavation may be required to assess whether the
corrosion is localized to the S/A interface or extends to the buried system.
Thickness readings at S/A interfaces may expose the metal and accelerate
corrosion if coatings and wrappings are not properly restored.
If the buried piping is uncoated at grade, consideration should be given to
excavating 6 inches to 12 inches (150 mm to 300 mm) deep to assess the
potential for hidden damage.
3.7
Service Specific & Localized Corrosion : An effective inspection program
includes the following three elements, which help identify the potential for service
specific & localized corrosion & select appropriate TMLs :
a.
An inspector with knowledge of the service & where corrosion is
likely to occur.
b.
Extensive use of nondestructive examination (NDE).
c.
Communication from operating personnel when process upsets occur that
may affect corrosion rates.
•
Dew
point corrosion in condensing streams.
21
•
Mixed grades of carbon steel piping in hot corrosive oil service (450 deg F
[230 deg]C) or higher temperature & sulfur content in the oil greater than 0.5
percent by weight.
•
Non silicon kiled steel pipe, such as A-53 & API 5L, may corrode at higher
rates than does silicon killed steel pipe, such as A-106 especially in high –
temperature sulfidic environments.
3.7
Erosion & corrosion/ erosion :
Erosion can be defined as the removal of
surface material by the action of numerous individual impacts of solid or liquid
particles. It can be characterized by grooves, rounded holes, waves, & vallys in a
directional pattern. Erosion usually occurs in areas of turbulent flow, such as at
change of direction in a piping system or downstream of control valves where
vaporization may take place.
3.8
Erosion damage is usually increased in streams with large quantities of solid or
liquid particles flowing at high velocities. A combination of corrosion & erosion
( corrosion/erosion )results in significantly greater metal loss than can be
expected from corrosion occurs at high velocity & high turbulence areas.
Examples of places to inspect include the following :
a.
Downstream of control valves, especially when flashing is
occurring.
22
b.
Downstream of orifices.
c.
Downstream of pump discharges.
d.
At any point of flow direction change, such as the inside & outside radii of
elbows.
3.9
Environmental Cracking : Piping system construction materials are normally
selected to resist the various forms of stress corrosion cracking (SCC). However,
some piping system may be susceptible to environmental cracking due to upset
process conditions, CUI unanticipated condensation, or exposure to wet
hydrogen sulfide or carbonates.
Examples of environmental cracking include :
a.
Chloride SCC of austenitic stainless steels due to moisture &
chlorides under insulation, under deposits , under gaskets, or in crevices.
b.
Caustic SCC ( sometimes known as caustic embrittlement ).
c.
Scc in environments where wet hydrogen sulfide exists, such as systems
containing sour water.
d.
Hydrogen blistering & hydrogen induced cracking ( HIC ) damage .
4. CORROSION BENEATH LININGS AND DEPOSITS :
4.1 General:
If external or internal coatings, refractory linings, and corrosion-resistant linings
are in good condition and there is no reason to suspect a deteriorated condition
23
behind them, it is usually not necessary to remove them for inspection of the
piping system.
The linings should be inspected for separation, breaks, holes, and blisters. If any
of these conditions are noted, it may be necessary to remove portions of the
internal lining to investigate the effectiveness of the lining and the condition of the
metal piping beneath the lining.
Corrosion beneath refractory linings can result in separation and bulging of the
refractory. If bulging or separation of the refractory lining is detected, portions of
the refractory may be removed to permit inspection of the piping beneath the
refractory.
4.2. FATIGUE CRACKING :
Fatigue cracking of piping systems may result from excessive cyclic stresses that
are often well below the static yield strength of the material. The onset of lowcycle fatigue cracking is often directly related to the number of heat-up and cooldown cycles experienced. Excessive piping system vibration (such as machine
or flow-induced vibrations) also can cause high-cycle fatigue damage.
Fatigue cracking can typically be first detected at points of high-stress
intensification such as branch connections.
Locations where metals having
different coefficients of thermal expansion are joined by welding may be
susceptible to thermal fatigue.
Preferred NDE methods of detecting fatigue
cracking include liquid-penetrant testing (PT) or magnetic-particle testing (MT).
Acoustic emission also may be used to detect the presence of cracks that are
activated by test pressures of stresses generated during the test.
It is important that the owner/user and the inspector understand that fatigue
cracking is likely to cause piping failure before it is detected with any NDE
methods. Of the total number of fatigue cycles required to produce a failure, the
24
vast majority are required to initiate a crack and relatively fewer cycles are
required to propagate the crack to failure.
Therefore, proper design and
installation in order to prevent the initiation of fatigue cracking are important.
4.2.12 CREEP CRACKING :
Creep is dependent on time, temperature, and stress. Cracking is accelerated by
creep and fatigue interaction when operating conditions in the creep range are
cycle.
If excessive temperatures are encountered, mechanical property and
microstructural changes in metals also may take place.
NDE methods of detecting creep cracking include liquid-penetrant testing,
magnetic-particle testing, ultrasonic testing, radiographic testing, and in-situ
metallography.
Acoustic emission testing also may be used to detect the
presence of cracks that are activated by test pressures or stresses generated
during the test.
4.2.13 BRITTLE FRACTURE :
Carbon low-alloy, and other ferritic steels may be susceptible to brittle failure at
or below ambient temperatures. Brittle fracture usually is not a concern with
relatively thinwall piping.
Most brittle fractures have occurred on the first
application of a particular stress level (that is, the first hydrotest or overload)
unless critical defects are introduced during service. The potential for a brittle
failure shall be considered when rehydrotesting.
4.2.14 FREEZE DAMAGE :
At subfreezing temperatures, water and aqueous solutions in piping systems may
freeze and cause failure because of the expansion of these materials.
After
25
unexpectedly severe freezing weather, it is important to check for freeze damage
to exposed piping components before the system thaws. If rupture has occurred,
leakage may be temporarily prevented by the frozen fluid. Low points, riplegs,
and deadlegs of piping systems containing water should be carefully examined for
damage.
4.3
TYPES OF INSPECTION AND SURVEILLANCE :
Different types of inspection and surveillance are appropriate depending on the
circumstances and the piping system . These include the following :
a.
Internal visual inspection.
b.
Thickness measurement inspection.
c.
External visual inspection.
d.
Vibrating piping inspection
e.
Supplemental inspection.
4.3.1 INTERNAL VISUAL INSPECTION :
Internal visual inspections are not normally performed on piping. When possible
and practical, internal visual inspections may be scheduled for systems such as
large-diameter transfer lines, ducts, or other large-diameter piping systems.
Such inspections are similar in nature to pressure vessel inspections and should
be conducted with methods and procedures similar to those outlined in API 510.
4.3.2 THICKNESS MEASUREMENT INSPECTION :
A thickness measurement inspection is performed to determine the internal
condition and remaining thickness of the piping components.
Thickness
measurements may be obtained when the piping system is in or out of operation
and shall be performed by the inspector or examiner.
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4.3.3 EXTERNAL VISUAL INSPECTION :
In addition to these scheduled external inspections that are documented in
inspection records, it is beneficial for personnel who frequent the area to report
deterioration or changes to the inspector.
4.3.4 SUPPLEMENTAL INSPECTION :
Other inspections may be scheduled as appropriate or necessary. Examples of
such inspections include periodic use of radiography and/or thermography to
check for fouling or internal plugging, thermography to check for hot spots in
refractory lined systems, or inspection for environmental cracking.
Acoustic
emission, acoustic leak detection, and thermography can be used or remote leak
detection and surveillance.
Ultrasonics and/or radiography can be used for
detecting localized corrosion.
4.4
THICKNESS MEASUREMENT LOCATIONS :
4.4.1 GENERAL :
Thickness measurement locations (TML’s) are specific areas along the piping
circuit where inspections are to be made.
The nature of the TML varies
according to its location in the piping system.
The selection of TML’s shall
consider the potential for localized corrosion and service-specific corrosion as
described in 5.3
4.4.2 TML MONITORING :
Each piping system shall be monitored by taking thickness measurements at
TML’s. Piping circuits with high potential consequences if failure should occur
27
and those subject to higher corrosion rates or localized corrosion will normally
have more TMLs and be monitored more frequently.
The minimum thickness at each TML can be located by ultrasonic scanning or
radiography. Electromagnetic techniques also can be used to identify thin areas
that may then be measured by ultrasonics or radiography. When accomplished
with ultrasonics, scanning consists of taking several thickness measurement at
the TML searching for localized thinning. The thinnest reading or an average of
several measurement readings taken within the area of a test point shall be
recorded and used to calculate corrosion rates, remaining life, and the next
inspection date.
Where appropriate, thickness measurements should include measurements at
each of the four quadrants on pipe and fittings, with special attention to the inside
and outside radius of elbows and tees where corrosion/erosion could increase
corrosion rates. As a minimum, the thinnest reading and its location shall be
recorded.
TML’s should be established for areas with continuing CUI, corrosion at S/A
interfaces, or other locations of potential localized corrosion as well as for
general uniform corrosion.
TMLs should be marked on inspection drawings and on the piping system to
allow repetitive measurements at the same TMLs.
This recording procedure
provides data for more accurate corrosion rate determination.
4.4.3 TML SELECTION :
In selecting or adjusting the number and locations of TMLs the inspector should
take unto account the patterns of corrosion that would be expected and have
been experienced in the process unit.
28
More TMLs should be selected for piping systems with any of the following
characteristics :
a.
Higher potential for creating a safety or environmental emergency in the
event of a leak.
b.
Higher expected or experienced corrosion rates.
c.
Higher potential for localized corrosion.
d.
More complexity in terms of fittings, branches, deadlegs injection points,
and other similar items.
e.
Higher potential for CUI
Fewer TMLs can be selected for piping systems with any of the following three
characteristics :
a.
Low potential for creating a safety or environmental emergency in the
event of a leak.
b.
Relatively non-corosive piping systems.
c.
Long, straight-run piping systems.
TMLs can be eliminated for piping systems with either of the following two
characteristics :
a.
Extremely low potential for creating a safety or environmental emergency
in the event of a leak.
b.
Non-corrosive systems, as demonstrated by history or similar service, and
systems not subject to changes that could cause corrosion.
4.5
THICKNESS MEASUREMENT METHODS :
29
Ultrasonic thickness measuring instruments usually are the most accurate mean
for obtaining thickness measurements on installed pipe larger than NPS 1.
Radiographic profile techniques are preferred for pipe diameters of NPS 1 and
smaller. Radiographic profile techniques may be used for locating areas to be
measured, particularly in insulted systems or where non-uniform or localized
corrosion is suspected.
Where practical , ultrasonics can then be used to obtain the actual thickness of
the areas to be recorded. Following ultrasonic readings at TMLs, proper repair of
insulation and insulation weather coating is recommended to reduce the potential
for CUI.
Radiographic profile techniques, which do not require removing insulation, may
be considered as an alternative.
When ultrasonic measurements are taken above 150 oF (65oC), instruments,
couplants, and procedures should be used that will result in accurate
measurements at the higher temperatures.
Measurements should be adjusted by the appropriate temperature correction
factor.
a.
Improper instrument calibration.
b.
External coatings or scale.
c.
Excessive surface roughness.
d.
Excessive “rocking” of the probe (on the curved surface)
e.
Subsurface material flaws, such as laminations.
f.
Temperature effects [at temperatures above 150 oF (65oC)]
g.
Small flaw detector screens.
30
h.
Thickness of less than 1/8 inch (3.2 mm) for typical digital thickness
gauges.
In addition, it must be kept in mind that the pattern of corrosion can be nonuniform.
For corrosion rate determinations to be valid, it is important that measurements
on the thinnest point be repeated as closely as possible to the same location.
Alternatively, the minimum reading or an average of several readings at a test
point may be considered.
When piping systems are out of service, thickness measurements may be taken
through openings using calipers. Calipers are useful in determining approximate
thicknesses of castings, forgings, and valve bodies, as well as pit depth
approximations from CUI on pipe.
Pit depth measuring devices also may be used to determine the depth of
localized metal loss.
4.6
PRESSURE TESTING OF PIPING SYSTEMS :
Pressure tests are not normally conducted as part of a routine inspection.
Exceptions to this include requirements of local jurisdictions, after welded
alterations or when specified by the inspector or piping engineer. When they are
conducted , pressure tests shall be performed in accordance with the
requirements of ASME B 31.3
If a pressure test is to be maintained for a period of time and the test fluid in the
system is subject to thermal expansion, precautions shall be taken to avoid
excessive pressure.
31
When a pressure test is required, it shall be conducted after any heat treatment.
A pneumatic pressure test may be used when it is impracticable to hydrostatically
test due to temperature, structural, or process limitations. However, the potential
risks to personnel and property of pneumatic testing shall be considered when
carrying out such a test. As a minimum, the inspection precautions contained in
ASME B 31.3 shall be applied in any pneumatic testing.
During a pressure test, where the test pressure will exceed the set pressure of
the safety valve on a piping system, the safety relief valve or valves should be
removed or blanked for the duration of the test. As an alternative, each valve
disk must be held down by a suitably designed test clamp.
The application of an additional load to the valve spring by turning the adjusting
screw is not recommended.
Other appurtenances that are incapable of
withstanding the test pressure, such as gage glasses, pressure gages,
expansion joints, and rupture disks, should be removed or blanked.
Lines
containing expansion joints that cannot be removed or isolated may be tested at
a reduced pressure in accordance with the principles of ASME B 31.3. If block
valves are used to isolate a piping system for a pressure test, caution should be
used to not exceed the permissible seat pressure as described in ASME B 16.34
or applicable valve manufacturer data.
Upon completion of the pressure test, pressure relief devices of the proper
settings and other appurtenances removed or made inoperable during the
pressure test shall be reinstalled or reactivated.
4.7
MATERIAL VERIFICATIONS AND TRACEABILTY :
During repairs or alterations of low- to high alloy piping systems, the inspector
shall verify the installation of the correct new materials. At the discretion of the
32
owner/user or the inspector, this verification can be either by 100 percent
checking or testing in certain critical situations or by sampling a percentage of the
materials.
Testing can be accomplished by the inspector or the examiner with the use of
suitable portable methods, such as chemical spot testing, optical spectrographic
analyzers, or X-ray fluorescent analyzers. Checking can involve verifying test
reports on materials, markings on piping components and bolting, and key
dimensions.
If a piping system component should fail because an incorrect material was
inadvertently substituted for the proper piping material, the inspector shall
consider the need for further verification of existing piping materials.
The extent of further verification will depend upon circumstances such as the
consequences of failure and the likelihood of further material errors.
4.8
INSPECTION OF VALVES :
Normally, thickness measurements are not routinely taken on valves in piping
circuits. The body of a valve is normally thicker than other piping components for
design reasons. However, when valves are dismantlted for servicing and repair,
the shop should be attentive to any unusual corrosion patterns or thinning and,
when noted, report that information to the inspector.
If gate valves are known to be or are suspected of being exposed to
corrosion/erosion, thickness readings should be taken between the seats, since
this is an area of high turbulence and high stress.
Control valves or other throttling valves, particularly in high pressure drop-andslurry services, can be susceptible to localized corrosion/erosion of the body
33
downstream of the orifice. If such metal loss is suspected, the valve should be
removed from the line for internal inspection. The inside of the downstream
mating flange and piping also should be inspected for local metal loss.
Critical check valves should be visually and internally inspected to ensure that they
will stop flow reversals.
An example of a critical check valve may be the check valve located on the outlet of
a multistage, high head hydro-processing charge pump. Failure of such a check
valve to operate correctly could result in over pressuring the piping during a flow
reversal. The normal visual inspection method should include :
a.
Checking to insure that the flapper is free to move, as required, without
excessive looseness from wear.
b.
The flapper stop should not have excessive wear. This will minimize the
likelihood that the flapper will move past the top dead central position and
remain in an open position when the check valve is mounted in a vertical
position.
c.
The flapper nut should be secured to the flapper bolt to avoid backing off in
service.
Leak checks of critical check valves are normally not required.
4.9
INSPECTION OF WELDS IN- SERVICE :
Inspection for piping weld quality is normally accomplished as a part of the
requirements for new construction, repairs, or alterations. However, welds are
often inspected for corrosion as part of a radiographic profile inspection or as part
of internal inspection.
When preferential weld corrosion is noted, additional
welds in the same circuit or system should be examined for corrosion.
34
If the noted imperfections are a result of original weld fabrication, inspection
and/or engineering analysis is required to assess the impact of the weld quality
on piping integrity. This analysis may be one or more of the following
a.
Inspector judgment.
b.
Certified welding inspector judgment.
c.
Piping engineer judgment.
d.
Engineering fitness-for-service analysis.
Issues to consider when assessing the quality of existing welds include the
following
a.
Original fabrication inspection acceptance criteria.
b.
Extent, magnitude, and orientation of imperfections.
c.
Length of time in-service.
d.
Operating versus design conditions.
e.
Presence of secondary piping stresses (residual and thermal)
f.
Potential for fatigue loads (mechanical and thermal).
g.
Primary or secondary piping system.
h.
Potential for impact or transient loads.
i.
Potential for environmental cracking.
j.
Weld hardness.
In many cases for in-service welds, it is not appropriate to use the random or
spot radiography acceptance criteria for weld quality in ASME B 31.3 These
35
acceptance criteria are intended to apply to new construction on a sampling of
welds, not just the welds examined, in order to assess the probable quality of all
welds (or welders) in the system.
Some welds may exist that will not meet these criteria but will still perform
satisfactorily in service.
4.10
INSPECTION OF FLANGED JOINTS :
The markings on a representative sample of newly installed fasteners and
gaskets should be examined to determine whether they meet the material
specification. The markings are identified in the applicable ASME and ASTM
standards. Questionable fasteners should be verified or renewed.
Fasteners should extend completely through their nuts. Any fastener failing to do
so is considered acceptably engaged if the lack of complete engagement is not
more than one thread.
Flanged and valve bonnet joints should be examined for evidence of leakage,
such as stains, deposits, or drips.
Process leaks onto flange and bonnet
fasteners may result in corrosion or environmental cracking.
This examination should include those flanges enclosed with flange or splashand-spray guards.
36
5.
5.1
FREQUENCY AND EXTENT OF INSPECTION
GENERAL :
The frequency and extent of inspection piping circuits depend on the forms of
degradation that can affect the piping and consequence of a piping failure.
Inspection strategy based on likelihood and consequence of failure, is referred to
as risk-based inspection. Piping classification scheme in Section given below is
based on the consequence of a failure. The classification is used to establish
frequency and extent of inspection.
The owner/user may devise a more
extensive classification scheme that more accurately assesses consequence for
certain piping circuits.
The consequence assessment would consider the
potential for explosion, fire, toxicity, environmental impact and other potential
effects associated with a failure.
After an effective assessment is conducted, the results can be used to establish
a piping circuit inspection strategy and more specifically better define the
following :
a.
The most appropriate inspection methods, scope, tools and techniques to
be utilized based on the expected forms of degradation;
b.
The appropriate inspection frequency;
c.
The need for pressure testing after damage has been incurred or after
repairs or modifications have been completed; and
d.
The prevention and mitigation steps to reduce the likelihood and
consequence of a piping failure.
37
5.2
PIPING SERVICE CLASSES :
All process piping systems shall be categorized into different classes. Such a
classification system allows extra inspection efforts to be focused on piping
systems that may have the highest potential consequences if failure or loss of
containment should occur. In general, the higher classified systems require more
extensive inspection at shorter intervals in order to affirm their integrity for
continued safe operation. Classifications should be based on potential safety
and environmental effects should a leak occur.
5.2.1 CLASS 1 :
Services with the heist potential of resulting in an immediate emergency if a leak
were to occur are in Class 1.
environmental in nature.
Such an emergency may be safety or
Examples of Class1 piping include, but are not
necessarily limited to, those containing the following :
a.
Flammable services that may auto-refrigerate and lead to brittle fracture.
b.
Pressurized services that may rapidly vaporize during release, creating
vapors that may collect and form an explosive mixture, such as C2, C3
and C4 streams.
c.
Hydrogen sulfide (greater than 3 percent weight ) in a gaseous stream.
d.
Anhydrous hydrogen chloride.
e.
Hydrofluoric acid.
f.
Piping over or adjacent to water and piping over public through ways.
5.2.2 CLASS 2 :
38
Services not included in other classes are in Class 2. This classification includes
the majority of unit process piping and selected off-site piping . Typical examples
of these services include those containing the following :
a. On-site hydrocarbons that will slowly vaporize during release.
b. Hydrogen, fuel gas and natural gas
c. On-site strong acids and caustics.
5.2.3 CLASS 3 :
Services that are flammable but do not significantly vaporize when they leak and
are not located in high activity areas are in Class 3 .
Services that dare
potentially harmful to human tissue but are located in remote areas may be
included din this class. Examples of Class 3 service are as follows :
5.3
a.
On site hydrocarbons that will not significantly vaporize during release.
b.
Distillate and product lines to and from storage and loading.
c.
Off-site acids and caustics.
INSPECTION INTERVALS :
The interval between piping inspections shall be established and maintained
using the following criteria :
a.
Corrosion rate and remaining life calculations.
b.
Piping service classification.
39
c.
Applicable jurisdictional requirements
d.
Judgment of the inspector, the piping engineer, the piping engineer
supervisor, or a corrosion specialist, based don operating conditions,
previous inspection history, current inspection results, and conditions that
may warrant supplemental inspections covered in 5.4.5 of code.
Thickness measurements should be scheduled based on the calculation of not
more than half the remaining life determined from corrosion rates indicated or at
the maximum intervals suggested in Table 6-1, whichever is shorter. Shorter
intervals may be appropriate under certain circumstances. Prior to using Table
6-1, corrosion rates should be calculated in accordance with 7.13 of code.
The inspection interval must be reviewed and adjusted as necessary after each
inspection or significant change in operating conditions.
General corrosion,
localized corrosion, pitting, environmental cracking, and other forms of
deterioration must be considered when establishing the various inspection
intervals.
5.4
EXTENT OF VISUAL EXTERNAL AND CUI INSPECTIONS :
External visual inspections, including inspections for corrosion under insulation
(CUI), should be conducted at maximum intervals listed in Table 6-1 to evaluate
items such as those in Appendix D. The external visual inspection on bare piping
is to assess the condition of paint and coating systems, to check for external
corrosion, and to check for other forms of deterioration. This external visual
inspection for potential CUI is also to assess insulation condition and shall be
conducted on all piping systems susceptible to CUI listed in 5.3.3.1 of code
40
Following the external visual inspection of susceptible systems, additional
examination is required for the inspection of CUI. The extent and type of the
additional CUI inspection are listed in Table 6-2 . Damaged insulation at higher
elevations may result in CUI in lower areas remote from the damage. NDE
inspection for CUI should also be conducted as listed in Table 6-2 at suspect
locations of 5.3.3.1 (excluding c ) meeting the temperature criteria for 5.3.3.1
(e,f,h).
Radiographic examination or insulation removal and visual inspection is normally
required for this inspection at damaged or suspect locations.
Other NDE
assessment methods may be used where applicable. If the inspection of the
damaged or suspect areas has located significant CUI, additional area should be
inspected and, where warranted, up to 100 percent of the circuit should be
inspected.
The extent of the CUI program described in Table 6-2 should be considered as
target levels for piping systems and locations with no CUI inspection experience.
It is recognized that several factors may affect the likelihood of CUI to include :
a.
Local climatic conditions
b.
Insulation design.
c.
Coating quality.
d.
Service conditions.
Facilities with CUI inspection experience may increase or reduce the CUI
inspection targets of Table 6-2. An exact accounting of the CUI inspection target
is not required. The owner/user may confirm inspection targets with operational
history or other documentation.
Piping systems that are known to have a remaining life of over 10 years or that
are adequately protected against external corrosion need not be included for the
NDE inspection recommended in Table 6-2.
However, the condition of the
41
insulating system or the outer jacketing, such as a cold-box shell, should be
observed periodically by operating or other personnel. If deterioration is noted, it
should be reported to the inspector.
The following are examples of these
systems :
a.
Piping systems insulated effectively to preclude the entrance of moisture.
b.
Jacketed cryogenic piping systems
c.
Piping systems installed in a cold box in which the atmosphere is purged
with an inert gas.
d.
Piping systems in which the temperature being maintained is sufficiently
low or sufficiently high to preclude the presence of water.
5.5
EXTENT OF THICKNESS MEASUREMENT INSPECTION :
To satisfy inspection interval requirements, each thickness measurement
inspection should obtain thickness readings on a representative sampling of
TMLs on each circuit . This representative sampling should include data for all
the various types of components and orientations (horizontal and vertical) found
in each circuit. This sampling also must include TMLs with the earliest renewal
date as of the previous inspection. The more TMLs measured for each circuit,
the more accurately the next inspection date will be projected.
Therefore,
scheduled inspection of circuits should obtain as many measurements as
necessary.
The extent of inspection for injection points is covered in 5.3.1 of code.
5.6
EXTENT OF SMALL-BORE, AUXILIARY PIPING, AND
CONNECTIONS INSPECTIONS :
THREADED -
5.6.1 SMALL BORE PIPING INSPECTION :
42
Small bore piping (SBP) that is primary process piping should be
inspected in accordance with all the requirements of this document.
SBP that is secondary process piping has different minimum requirements
depending upon service classification. Class1 secondary SBP shall be
inspected to the same requirements as primary process piping. Inspection
of Class2 and Class 3 secondary SBP is optional. SBP deadlegs (such
das level bridles) in Class 2 and Class 3 systems should be inspected
where corrosion has been experienced or is anticipated.
5.6.2 AUXILIARY PIPING DDDDINSPECTION :
Inspection of secondary, auxiliary SBP associated with instruments and
machinery is optional. Criteria to consider in determining whether auxiliary
SBP will need some form of inspection include the following :
a.
Classification.
b.
Potential for environmental or fatigue cracking.
c.
Potential for corrosion based on experience with adjacent primary
system.
d.
Potential for CUI.
5.6.3 THREADED-CONNECTIIONS INSPECTION :
Inspection of threaded connections will be according to the requirements
listed above for small-bore and auxiliary piping. When selecting TMLs on
threaded connection, include only those that can be radio-graphed during
scheduled inspection.
Threaded connections associated with machinery and subject to fatigue
damage should be periodically assessed and considered for possible
renewal with a thicker wall or upgrading to welded components.
The
43
schedule for such renewal will depend on several issues, including the
following :
a.
Classification piping
b.
Magnitude and frequency of vibration.
c.
Amount of unsupported weight.
d.
Current piping wall thickness.
e.
Whether or not the system can be maintained on stream.
f.
Corrosion rate.
g.
Intermittent service.
TABLE 6-1----RECOMMENDED MAXIMUM INSPECTION INTERVALS
Types of Circuit
Class 1
Class 2
Class 3
Injection points
Soil-to-air interfaces
Note :
Thickness
Measurements
5 years
10 years
10 years
3 years
Visual External
----
By Class
5 years
5 years
10 years
By Class
Thickness measurements apply to systems for which TMLs have been
established in accordance with 5.5
44
TABLE D6-2 --- RECOMMENDED EXTENT OF CUI INSPECTION
FOLLOWING VISUAL INSPECTION
Approximate Amount of Followup
Examination with NDE or Insulation
Removal at Areas with
Damaged Insulation
Pipe Class
1
75%
2
50%
3
25%
Approximate Amount of CUI
Inspection by NDE at Suspect
Areas ( 5.3.3.2 ) on Piping Systems
within Susceptible Temperature
Ranges ( 5.3.3.2 e.f.h )
50%
33%
10%
45
6. INSPECTION DATA EVALUATION
6.1
CORROSION RATE DETERMINATION :
6.1.1 REMAINING LIFE CALCULATIONS :
The dreaming life of the piping system shall be calculated from the following
formula :
t
Remaining life (years) =
actual – t minimum
-----------------------------
Corrosion rate
[inches (mm) per year]
where :
t
actual
=
the actual minimum thickness, in inches (mm),determined at the
time of inspection as specified 5.6
t
minimum = the minimum required thickness, in inches (mm) for the limiting
section or zone.
The long term (L.T.) corrosion rate of piping circuits shall be calculated from the
following formula :
Corrosion rate (L.T.) =
t
initial - t last
--------------------------------time (years) between last
and initial inspections
46
The short term (S.T.) corrosion rate of piping circuits shall be calculated from the
following formula :
Corrosion rate (S.T.) =
t
previous – t last
--------------------------time (years) between last
and previous inspections
Long term and short term corrosion rates should be compared to see which
results in the shortest remaining life.
6.1.2 EXISTING PIPING SYSTEMS :
Corrosion rates shall be calculated on either a short term or a long term basis.
For the short term calculation, readings from the two most recent inspections
shall be used. For the long term calculation, wall thicknesses from the most
recent and initial (or nominal) inspections shall be used. In most cases, the
higher of these two rates should be used to estimate remaining life and so set the
next inspection interval.
If calculations indicate that an inaccurate rate of corrosion has been assumed,
the rate to be used for the next period shall be adjusted to agree with the actual
rate found.
6.2
MAXIMUM
ALLOWABLE
DETERMINATION :
DWORKING
PRESSURE
The maximum allowable working pressure (MAWP) for the continued use of
piping systems shall be established using the applicable code. Computations
may be made for known materials if all the following essential details are known
to comply with the principles of the applicable code :
a.
Upper and/or lower temperature limits for specific materials.
47
b.
Quality of materials and workmanship.
c.
Inspection requirements.
d.
Reinforcement of openings.
e.
Any cyclical service requirements.
For unknown materials, computations may be made assuming the lowest grade
material and joint efficiency in the applicable code.
When the MAWP is
recalculated, the wall thickness used in these computations shall be the actual
thickness as determined by inspection (see definition) minus twice the estimated
corrosion loss before the date of the next inspection. Allowance shall be made
for the other loadings in accordance with the applicable code. The applicable
code allowances for pressure and temperature variations from MAWP are
permitted provided all of the associated code criteria are satisfied.
6.3
MINIMUM REQUIRED THICKNESS DETERMINATION :
The minimum required pipe wall thickness, or retirement thickness, shall be
based on pressure, mechanical, and structural considerations using the
appropriate design formulas and code allowable stress. Consideration of both
general and localized corrosion shall be included.
For services with high
potential consequences if failure were to occur, the piping engineer should
consider
increasing the required minimum thickness above the calculated
minimum thickness to provide for unanticipated or unknown loadings,
undiscovered metal loss, or resistance to normal abuse.
6.4
REPORTING AND RECORDS FOR PIPING SYSTEM INSPECTION
Any significant increase in corrosion rates shall be reported to the owner/user for
appropriate action.
48
The owner/user shall maintain appropriate permanent and progressive records of
each piping system covered by API 570. These records shall contain pertinent
data such as piping system service; classification; identification numbers;
inspection intervals; and documents necessary to record the name of the
individual performing the testing, the date, the types of testing, the results of
thickness measurements and other tests, inspections, repairs (temporary and
permanent), alterations, or rerating. Design information and piping drawings may
be included. Information on maintenance activities and events affecting piping
system integrity also should be included.
The date and results of required
external inspections shall be recorded. (see API RP 574 for guidance on piping
inspection records).
The use of a computer based system for storing, calculating, and analyzing data
should be considered in view of the volume of data that will be generated as part
of a piping test-point program. Computer programs are particularly useful for the
following :
a.
Storing the actual thickness reading.
b.
Calculating short and long term corrosion rates, retirement dates, MAWP,
and reinspection intervals on a test point by test point basis.
c.
Highlighting areas of high corrosion rates, circuits over-due for inspection,
close to retirement thickness, and other information.
49
7.
7.1
REPAIRS, ALTERATIONS, RERATING
REPAIRS AND ALTERATIONS :
The principles of ASME B31.3 or the code to which the piping system was built
shall be followed.
7.1.1 AUTHORIZATION :
All repair and alteration work must be done by a repair organization as defined in
Section 3 and must be authorized by the inspector prior to its commencement.
Authorization for alteration work to a piping system may not be given without
prior consultation with, and approval by, the piping engineer. The inspector will
designate any inspection hold points required during the repair or alteration
sequence.
The inspector may give prior general authorization for limited or
routine repairs and procedures, provided the inspector is satisfied with the
competency of the repair organization.
7.1.2 APPROVAL :
All proposed methods of design, execution, materials, welding procedures,
examination, and testing must be approved by the inspector or by the piping
engineer, as appropriate. Owner/user approval of on stream welding is required.
Welding repairs of cracks that occurred in service should not be attempted
without prior consultation with the piping engineer in order to identify and correct
the cause of the cracking. Examples are cracks suspected of being caused by
vibration, thermal cycling, thermal expansion problems, and environmental
cracking.
50
The inspector shall approve all repair and alteration work at designated hold
points and after the repairs and alterations have been satisfactorily completed in
accordance with the requirements of API 570
7.1.3 WELDING REPAIRS (DDINCLUDING ON0STREAM) :
7.1.3.1
TEMPORARY REPAIRS :
For temporary repairs, including on steam,
a full encirclement
welded split sleeve or box type enclosure designed by the piping
engineer may be applied over the damaged or corroded area.
Longitudinal cracks shall not be repaired in this manner unless the
piping engineer has determined that cracks would not be expected
to propagate from under the sleeve. In some cases, the piping
engineer will need to consult with a fracture analyst.
If the repair area is localized (for example, pitting or pinholes) and
the specified minimum yield strength (SMYS) of the pipe is not
more than 40,000 psig (275,800 kPa), a temporary repair may be
made by fillet welding a properly designed split coupling or plate
patch over the pitted area (See 7.2.3 for design considerations and
Appendix C for an example )
The material for the repair shall
match the base metal unless approved by the piping engineer.
For minor leaks, properly designed enclosures may be welded over
the leak while the piping system is in service, provided the
inspector is satisfied that adequate thickness remains in the vicinity
of the weld and the piping component can withstand welding
without the likelihood of further material damage, such as form
caustic service.
51
Temporary repairs should be removed and replaced with a suitable
permanent repair at the next available maintenance opportunity.
Temporary repairs may remain in place for a longer period of time
only if approved and documented by the piping engineer.
7.1.3.2
PERMANENT REPAIRS :
Repairs to defects found in piping components may be made by
preparing a welding groove that completely removes the defect and
then filling the groove with weld metal deposited din accordance
with 7.2
Corroded areas may be restored with weld metal deposited din
accordance with 7.2 Surface irregularities and contamination shall
be removed before welding. Appropriate NDE methods shall be
applied after completion of the weld.
If it is feasible to take the piping system out of service, the defective
area may be removed by cutting out a cylindrical section and
replacing it with a piping component that meets the applicable
code.
Insert patches (flush patches) may be used to repair damaged or
corroded areas if the following requirements are met :
a.
Full penetration groove welds are provided.
b.
For Class 1 and Class 2 piping systems, the welds shall be
100 percent radio-graphed or ultrasonically tested using
NDE procedures that are approved by the inspector.
c.
Patches may be any shape but shall have rounded corners
(1 inch (25mm) minimum radius)
52
7.1.4 NON-WELDING REPAIRS (ON STREAM) :
Temporary repairs of locally thinned sections or circumferential linear defects
may be made on stream by installing a properly designed and fabricated bolted
leak clamp. The design shall include control of axial thrust loads if the piping
component being clamped is (or may become) insufficient to control pressure
thrust. The effect of clamping (crushing) forces on the component also shall be
considered.
During turnarounds or other appropriate opportunities, temporary leak sealing
and leak dissipating devices, including valves, shall be removed and appropriate
actions taken to t\restore the original integrity of the piping system. The inspector
and/or dipping engineer shall be involved in determining repair methods and
procedures.
Procedures that include leak sealing fluids (pumping) for process piping should
be reviewed for acceptance by the inspector or piping engineer. The review
should take into consideration the compatibility of the sealant with the leaking
material; the pumping pressure on the clamp (especially when re[pumping); the
risk of sealant affecting downstream flow meters, relief valves, or machinery, the
risk of subsequent leakage at bolt threads causing corrosion or stress corrosion
cracking of bolts; and the number of times the seal area is re-pumped.
7.2
WELDING AND HOT TAPPING :
All repair and alteration welding shall be done in accordance with the principles
of ASME B 31.3 or the code to which the piping system was built.
Any welding conducted on piping components in operation must be done in
accordance with API Publ 2201. The inspector shall use as a minimum the ‘
53
Suggested Hot Tap Checklist” contained in API Publication 2201 for hot tapping
performed on piping components.
7.2.1 PROCEDURES, QUALIFICATIONS, AND RECORDS :
The repair organization shall use welders and welding procedures qualified in
accordance with ASME B31.3 or the code to which the piping was built.
The repair organization shall maintain records of welding procedures and welder
performance qualifications. These records shall be available to the inspector
prior to the start of welding.
7.2.2 PERHEATING AND POSTWELD HEAT TREATMENT :
7.2.2.1
PREHEATING :
Preheat temperature used in masking welding repairs shall be in
accordance with the applicable code and qualified welding
procedure. Exceptions for temporary repairs must be approved by
the piping engineer.
Preheating to not less that 300 oF (150oC) may be considered as an
alternative to postweld heat treatment (PWHT) for alterations or
repairs of piping systems initially postweld heat heated as a code
requirement (see note). This applies to piping constructed of the P1 steels listed in ASME B31.3. P-3 steels , with the exception of
Mn-Mo steels, also may receive the 300oF(150oC) minimum preheat
alternative when the piping system operating temperature is high
enough to provide reasonable toughness and when there is no
identifiable hazard associated with pressure testing , shutdown, and
startup.
The inspector should determine that the m9inimum
preheat temperature is measured and maintained. After welding,
54
the joint should immediately be covered with insulation to slow the
cooling rate.
NOTE :
Preheating may not be considered as an alternative to environmental
cracking prevention.
Piping systems constructed of other steel initially requiring PWHT normally
are postweld heat treated if alterations or repairs involving pressure
retaining welding are performed.
The use of the preheat alternative
requires consultation with the piping engineer who should consider the
potential for environmental cracking and whether the welding procedure
will provide adequate toughness.
Examples of situations where this
alternative could be considered include seal welds, weld metal buildup of
thin area, and welding support clips.
7.2.2.2
POSTWELD HEAT TREATMENT :
PWHT of piping system repairs or alterations should be made using
the applicable requirements of ASME B31.3 or the code to which
the piping was built.
See 7.2.2.1 for an alternative preheat
procedure for some PWHT requirements. Exceptions for temporary
repair must be approved by the piping engineer.
Local PWHT may be substituted for 360- degree banding on local
repairs on all materials, provided the following precautions and
requirements are applied.
a.
The application is reviewed, and a procedure is developed
by the piping engineer.
b.
In evaluating the suitability of a procedure, consideration
shall be given to applicable factors, such as base metal
thickness, thermal gradients, material properties, changes
55
resulting from PWHT, the need for full penetration welds,
and surface and volumetric examinations after PWHT.
Additionally, the overall and local strains and distortions
resulting from the heating of a local restrained area of the
piping wall shall be considered in developing and evaluating
PWHT procedures.
c.
A preheat of 300oF (150oC), or higher as specified by
specific welding procedures, is maintained while welding.
d.
The required PWHT temperature shall be maintained for a
distance of not less than two times the base metal thickness
measured form the weld. The PWHT temperature shall be
monitored by a suitable number of thermocouples (a
minimum of two) based on the size and shape of the area
being heat treated.
e.
Controlled heat also shall be applied to any branch
connection or other attachment within the PWHT area.
f.
The PWHT is performed for code compliance and not for
environmental cracking resistance.
7.2.3 DESIGN :
Butt joints shall be full penetration groove welds.
Piping components shall be replaced when repair is likely to be inadequate. New
connections and replacement s shall be designed and fabricated according to
the principles of the applicable code. The design of temporary enclosures and
repairs shall be approved by the piping engineer.
56
New connections may be installed on piping systems provided the design,
location, and method of attachment conform to the principles of the applicable
code.
Fillet-welded patches require special design considerations, especially relating to
weld-joint efficiency and crevice corrosion.
Fillet-welded patches shall be
designed by the piping engineer. A patch may be applied to the external surfaces
of piping, provided it is in accordance with 7.1.3 and meets either of the following
requirements. :
a.
The proposed patch provides design strength equivalent to a reinforced
opening designed according to the applicable code.
b.
The proposed patch is designed to absorb the membrane strain of the part
in a manner that is in accordance with the principles of the applicable
code, if the following criteria are met :
1. The allowable membrane stress is not exceeded in the piping part
or the patch.
2. The strain in the patch does not result in fillet weld stresses exceeding
allowable stresses for such welds.
3. An overlay patch shall have rounded corners (se Appendix C)
7.2.4 MATERIALS :
The materials used in making repairs or alterations shall be of known weldable
quality, shall conform to the applicable code, and shall be compatible with the
original materials. For material verification requirements see 4.8
7.2.5 NON-DESTRUCTIVE EXAMINATION :
57
Acceptance of a welded repair or alteration shall include NDE in accordance with
the applicable code and the owner/user’s specification, unless otherwise
specified in API 570
7.2.6 PRESSURE TESTING :
After welding is completed, pressure test in accordance with 4.7 shall be
performed if practical and deemed necessary by the inspector. Pressure tests
are normally required after alterations and major repairs. When a pressure test
is not necessary or practical, NDE shall be utilized in lieu of a pressure test.
Substituting special procedures for a pressure test after an alteration or repair
may b e done only after consultation with the inspector and the piping engineer.
When it is not practical to perform a pressure test of a final closure weld that joins
a new or replacement section of piping to an existing system, all of the following
requirements shall be satisfied :
a. The new or replacement piping is pressure tested.
b. The closure weld is a full penetration butt-weld between a weld neck flange
and standard piping component or straight sections of pipe of equal
diameter and thickness, axially aligned ( not miter cut ), and of equivalent
materials. Acceptable alternatives are
1.
slip-on flanges for design cases upto Class 150 and 500 oF,
(260oC) and
2.
socket welded flanges or socket welded unions for sizes NPS 2 or
less and design cases upto Class 150 and 500 oF (260oC).
A
spacer designed for socket welding or some other means shall be
used to establish a minimum 1/16 inch (1.6 mm ) gap. Socket
58
welds shall be per ASME B31.3 and shall be a minimum of two
passes.
c. Any final closure butt-weld shall be of 100 percent radiographic quality;
OR angle beam ultrasonics flaw detection may be used, provided the
appropriate acceptance criteria have been established.
d. MT or PT shall be performed on the root pass and the completed weld for
butt-welds and on the completed weld for fillet welds.
7.3
RERATING
Rerating
piping systems by changing the temperature rating or the MAWP may
be done only after all of the following requirements have been met :
a. Calculations are performed by the piping engineer or the inspector.
b. All ratings shall be established in accordance with the requirements of the
code to which the piping system was built or by computation using the
appropriate methods in the latest edition of the applicable code.
c. Current inspection records verify that the piping system is satisfactory for the
proposed service conditions and that the appropriate corrosion allowance
is provided.
d.
Rerated piping systems shall be leak tested in accordance with the code
to which the piping system was built or the latest edition of the applicable
code for the new service conditions, unless documented records indicate
a previous leak test was performed at greater than or equal to the test
pressure for the new condition. An increase in the rating temperature that
does not affect allowable tenside stress does not require a leak test.
59
e. The piping system is checked to affirm that the required pressure relieving
devices are present, are set at the appropriate pressure, and have the
appropriate capacity at set pressure.
f.
The piping system rerating is acceptable to the inspector or piping
engineer.
g.
All piping components in the system (such as valves, flanges, bolts,
gaskets, packing, and expansion joints) are adequate for the new
combination of pressure and temperature.
h.
Piping flexibility is adequate for design temperature changes.
i.
Appropriate engineering records are updated.
j.
A decrease in minimum operating temperature is justified by impact test
results, if required by the applicable code.
60
8.
INSPECTION OF BURIED PIPING
Inspection of buried process piping is different from other process piping inspection
because significant external deterioration can be caused by corrosive soil conditions.
Since the inspection is hindered by the inaccessibility of the affected areas of the piping,
the inspection of buried piping is treated in a separate section of API 570.
8.1
TYPES AND METHODS OF INSPECTION
8.1.1 Above Grade Visual Surveillance :
Indications of leaks in buried piping may include a change in the surface contour
of the ground, discoloration of the soil, softening of paving asphalt, pool
formation, bubbling water puddles, or noticeable odor. Surveying the route of
buried piping is one method of identifying problem areas.
8.1.2 Close Interval Potential Survey :
The close interval potential survey performed at ground level over the buried pipe
can be used to locate active corrosion points on the pipe’s surface.
Corrosion cells can form on both bare and coated pipe where the bare steel
contacts the soil. Since the potential at the area of corrosion will be measurably
different from an adjacent area on the pipe, the location of the corrosion activity
can be determined by this survey technique.
8.1.3 Pipe Coating Holiday Survey :
The pipe coating holiday survey can be used to locate coating defects on buried
coated pipes, and it can be used on newly constructed pipe systems to ensure
that the coating is intact and holiday free.
More often it is used to evaluate
61
coating serviceability for buried piping that has been in service for an extended
period of time.
8.1.4 Soil Resistivity :
Corrosion of bare or poorly coated piping is often caused by a mixture of different
soils in contact with the pipe surface. The corrosiveness of the soils can be
determined by a measurement of the soil resistivity. Lower levels of resistivity
are relatively more corrosive than higher levels, especially in areas where the
pipe is exposed to significant changers in soil resistivity.
8.1.5 Cathodic Protection Monitoring :
Cathodically8 protected buried piping should be monitored regularly to assure
adequate levels of protection. Monitoring should include periodic measurement
and analysis of pipe to soil potentials by personnel trained and experienced in
cathodic protection system operation.
More frequent monitoring of critical
cathodic protection components, such as impressed current rectifiers, is required
to ensure reliable system operation.
8.1.6 Inspection Methods :
Several inspection methods are available.
Some methods can indicate the
external or wall condition of the piping, whereas other methods indicate only the
internal condition. Examples are as follows :
a.
Intelligent pigging. This method involves the movement of a
device (pig) through the piping either while it is in service or after it has
been removed from service.
Several types of devices are available
employing different methods of inspection.
62
b.
Video cameras. Television cameras are available that cana be
inserted into the piping. These cameras may provide visual inspection
information on the internal condition of the line.
c.
Excavation.
In many cases, the only available inspection
method that can be performed is unearthing the piping in order to visually
inspect the external condition of the piping and to evaluate its thickness
and internal condition.
8.2
FREQUENCY AND EXTENT OF INSPECTION :
8.2.1 Above-Grade Visual Surveillance :
The owner/ user should, at approximately 6 month intervals survey the surface
conditions on and adjacent to each pipeline path.
8.2.2 Pipe to Soil Potential Survey :
A close interval potential survey on a cathodically protected line may be used to
verify that the buried piping has a protective potential throughout its length. For
poorly coated pipes where cathodic protection potentials are inconsistent, the
survey may be conducted at 5 year intervals for veritication of continuous
corrosion control.
For piping with no cathodic protection or in areas where leaks have occurred due
to external corrosion, a pipe to soil potential survey may be conducted along the
pipe route. The pipe should be excavated at sites where active corrosion cells
have been located to determine the extent of corrosion damage.
63
8.2.3 Pipe Coating Holiday Survey :
The frequency of pipe coating holiday surveys is usually based on indications
that other forms of corrosion control are ineffective. For example, on a coated
pipe where there is gradual loss of cathodic protection potentials or an external
corrosion leak occurs at a coating defect, a pipe coating holiday survey may be
used to evaluate the coating.
8.2.4 Soil Corrosivity :
For piping buried in lengths greater than 100 feet ( 30 m ) and not cathodically
protected, evaluations of soil corrosivity should be performed at 5 year intervals.
Soil resistivity measurements may be used for relative classification of the soil
corrosivity.
8.2.5 Cathodic Protection :
If the piping is cathodically protected, the system should be monitored at intervals
in accordance with Section 10 of NACE RP0169 or Section 11 of API RP 651.
8.2.6 External and Internal Inspection Intervals :
If internal corrosion of buried piping is expected as a result of inspection on the
above grade portion of the line, inspection intervals and methods for the buried
portion should be adjusted accordingly. The inspector should be aware of and
consider the possibility of accelerated internal corrosion in deadlegs.
The external condition of buried piping that is not cathodically protected should
be determined by either pigging, which can measure wall thickness or by
excavating according to the frequency given in Table 9-1. Significant external
corrosion detected by pigging or by other means may require excavation and
evaluation even if the piping is cathodically protected.
64
Piping inspected periodically by excavation shall be inspected in lengths of 6 feet
–8 feet ( 2.0 m-2.5 m ) at one or more locations judged to be most suspectible to
corrosion. Excavated piping should be inspected full circumference for the type
and extent of corrosion ( pitting or general ) and the condition of the coating.
If inspection reveals damaged coating or corroded piping, additional piping shall
be excavated until the extent of the condition is identified. If the average wall
thickness is at or below retirement thickness, it shall be repaired or replaced.
If the piping is contained inside a casing pipe, the conditional of the casing
should be inspected to determine if water and/ or soil has entered the casing.
The inspector should verify the following :
a. both ends of the casing extend beyond the ground line;
b. the ends of the casing are sealed if the casing is not self-draining; and
c.
the pressure carrying pipe is properly coated and wrapped.
8.2.7 Leak Testing Intervals :
An alternative or supplement to inspection is leak testing with liquid at a pressure
atleast 10 percent greater than maximum operating pressure at intervals one-half
the length of those shown in Table 9-1 for piping not cathodically protected and
at the same intervals as shown in Table 9-1 for cathodically protected piping.
The leak test should be maintained for a period of 8 hours.
Four hours after the initial pressurization of the piping system, the pressure
should be noted and, if necessary, the line repressurized to original test pressure
and isolated from the pressure source.
65
If, during the remainder of the test period, the pressure decreases more than 5
percent, the piping should be visually inspected externally and/ or inspected
internally to find the leak and assess the extent of corrosion.
Sonic
measurements may be helpful in locating leaks during leak testing.
Buried piping also may be surveyed for integrity by using temperature-corrected
volumetric or pressure test methods.
Table 9-1
Frequency of Inspection for Buried Piping
Without Effective Cathodic Protection
Soil Resistivity( ohm-cm )
< 2,000
2,000 to 10,000
> 10,000
Inspection Interval ( years )
5
10
15
Other alternative leak test methods involve acoustic emission examination and
the addition of a tracer fluid to the pressurized line ( such as helium or sulfur
hexafloride ). If the tracer is added to the service fluid, the owner/ user shall
confirm suitability for process and product.
8.3
REPAIRS TO BURIED PIPING SYSTEMS :
66
8.3.1 Repairs to Coatings :
Any coating removed for inspection shall be renewed and inspected
appropriately.
For coating repairs, the inspector should be assured that the coating meets the
following criteria :
a.
It has sufficient adhesion to the pipe to prevent under film migration of
moisture.
b.
It is sufficiently ductile to resist cracking.
c.
It is free of voids and gaps in the coating ( holidays ).
d.
It has sufficient strength to resist damage due to handling and soil
stress.
e.
It can support any supplemental cathodic protection.
In addition, coating repairs may be tested using a high voltage holiday detector.
The detector voltage shall be adjusted to the appropriate value for the coating
material and thickness. Any holidays fould shall be repaired and retested.
8.3.2 Clamp Repairs :
If piping leaks are clamped and reburied, the location of the clamp shall be
logged in the inspection record and may be surface marked.
Both the marker and the record shall note the date of installation and the
location of the clamp. All clamps shall be considered temporary. The piping
should be permanently repaired at the first opportunity.
67
8.3.3
Welded Repairs :
Welded repairs shall be made in accordance in 8.2 of Code.
8.3.4 Records :
Record systems for buried piping should be maintained in accordance with 7.6 of
Code. In addition, a record of the location and date of installation of temporary
clamps shall be maintained.
******
68
RECOMMENDED PRACTICE API- 574
1 REASONS FOR INSPECTION
A.
GENERAL
1.
The primary purpose of inspection is to identify active deterioration
mechanisms and to specify repair, replacement, or future inspections for
affected piping.
2.
By developing a database of inspection history, the user may predict
and recommend future repairs and replacements.
3.
The user can act to prevent or retard further deterioration and, most
importantly, prevent loss of containment.
4.
This should result in increased operating safety, reduced maintenance
cost, and more reliable and efficient operations.
5.
API 570, Piping Inspection Code provides the basic requirements for
such an inspection program. This recommended practice supplements
API 570 by providing piping inspectors with information that can improve
skill and increase basic knowledge and practices.
B.
SAFETY
1.
A leak or failure in a piping system may be only a minor inconvenience, or
it may become a potential source of fire or explosion, depending on the
temperature, pressure, contents, and location of the piping.
69
2.
Adequate inspection is a prerequisite for maintaining the lines containing
flammable fluids and toxic chemicals in a safe operable condition.
3.
Several
safety regulations mandate piping, that carries hazardous
chemicals be inspected according to accepted codes and standards,
which includes API 570.
C.
RELIABILITY AND EFFICIENT OPERATION
1.
Thorough inspection and analysis and the use of historical records of
piping systems are essential to the attainment of acceptable reliability,
efficient operation, and optimum on stream service.
2.
Piping replacement schedules can be developed to coincide with planned
maintenance turnaround schedules through methodical forecasting of
piping service life.
D.
REGULATORY REQUIREMENTS
1.
Regulatory requirements usually cover only those conditions that affect
safety and environmental concerns.
2.
Inspection groups in the Petrochemical industry familiar with the industry’s
problems inspect for other conditions that adversely affect plant operation.
3.
Each plant should be familiar with the local requirements for process
piping inspection.
70
2 CORROSION MONITORING OFPROCESS PIPING
1.
The single most frequent reason for replacing piping is
thinning due to
corrosion.
2.
The key to the effective monitoring of piping corrosion is identifying and
establishing thickness monitoring locations (TMLs) .
3.
TMLs are designated areas in the piping system where thickness
measurements are periodically taken. By taking repeated measurements and
recording at the same points over extended periods, corrosion rates can more
accurately be calculated.
Some of the factors to consider when establishing the corrosion monitoring plan
for process piping are :
a.
Classifying the piping in accordance with API 570.
b.
Categorising the piping into circuits of similar corrosion behavior.
c.
Identifying susceptible locations where accelerated corrosion is expected.
d.
Accessibility of the TMLs for monitoring.
PIPING CIRCUITS:
1.
A piping circuit is a section of piping of which all points are exposed to an
environment of similar corrosivity and which is of similar design conditions and
construction material.
71
2.
By identifying like environments as circuits, the spread of calculated corrosion
rates of the TMLs in each circuit is reduced.
3.
Corrosion rates are normally increased at areas of increased velocity and/ or
turbulence. Elbows, reducers, tees, control valves, and orifices are examples of
piping components where accelerated corrosion may occur because of increased
velocity and / or turbulence.
4.
Such components are normally areas to locate additional TMLs in a piping circuit.
5.
Areas of no flow, such as deadlegs ( Section 6.3.2 ) may cause accelerated
corrosion and may need additional TMLs.
INJECTION POINTS:
1.
Injection points are some times subject to accelerate or localized corrosion.
2.
Injection points may be treated as separate inspection circuits and need to be
inspected thoroughly on a regular schedule.
*********
FREQUENCY AND TIME OF INSPECTION
72
GENERAL:
The frequency of piping inspections should be determined by the following conditions :
a.
The consequence of a failure ( piping classification ),
b.
The degree of risk ( likelihood and consequence of a
failure )
c.
The amount of corrosion allowance remaining
d.
The historical data available
e.
Regulatory requirements.
API 570 requires classifying piping systems according to the consequences of failure.
The frequency and thoroughness of piping inspections will range from often and
extensive in low piping classes where deterioration is extreme, to seldom and cursory in
high piping classes in non-corrosive services.
INSPECTION WHILE EQUIPMENT IS OPERATING
An effective, program of piping inspection will include obtaining as many of the required
wall thickness measurements as possible while a plant is on stream. Both ambient and
high temperature ultrasonic thickness measurements may be taken. On most piping,
wall thickness radiographs can be taken independently through undisturbed insulation.
Radiographs can also be used to identify corroded areas.
On stream inspection can reduce downtime by the following means :
73
•
Extending process runs by assuring piping conditions are suitable for continued
operation.
•
Permitting fabrication of replacement piping before a shutdown.
•
Eliminating unnecessary work and reducing shutdown personnel requirements;
for example, personnel who are otherwise used to remove insulation and break
flanges for inspection during the turnaround can be made available for other
work.
•
Aiding maintenance planning to reduce surges in work-load, thus, stabilizing
personnel requirements.
INSPECTION WHILE EQUIPMENT IS SHUT DOWN
Inspections that cannot be made while the equipment is operating must be made when
the system is shut down. In addition, when piping is opened for any reason, it should be
inspected internally as far as accessibility permits.
Adequate follow up inspections
should be conducted to determine the causes of defects, such as leaks, misalignment,
vibration, and swaying that were detected while the unit was operating.
*****
SAFETY PRACTICES IN INSPECTION
( API 574 – CHAPTER 8 )
74
A )
SAFETY PRECAUTIONS ( 8.1 )
Procedures for segregation of piping, installation of blinds etc. shall be integral
part of safety practices of the plant. In general piping to be opened shall be :
-
Isolated from all sources of harmful liquids and gases, vapours.
-
Purging to remove all oil and toxic gases
-
Precautions should be taken before hammer testing which may cause
cracks, failures, or allow contents to be released.
B )
PREPARATORY WORK ( 8.2 )
All possible preparatory work should be done before scheduled start of
inspection which include :
-
Scaffolds erection
-
Excavation of buried piping at inspection points
-
Check availability and working condition of inspection tools required
-
Availability and condition of equipments and clothing for personnel
safety
-
Necessary warning signs
-
Barricades
INSPECTION PROCEDURES
( API-574 – CHAPTER 10 )
75
A )
INSPECTION DURING OPERATION :
a.
Leakage spots ( corrosion product build up at pipe support and clamps
contact area )
b.
Signs of misalignment, vibrations
c.
Supports and vibrations
d
External condition of piping insulation
a )
Leakage spots: :
Leaks in utility piping may not be hazardous.
Leaks in hot toxic, volatile gases may be dangerous. leak drippings may corrode
piping below. attention shall be given to flange joints, packing glands,
expansion joints, valve bonnets etc.
Leaks may be stopped or reduced
by
tightening flanges, packing glands. Isolate the piping and attend to it if situation
warrants.
b )
Misalignment
-
Pipes dislodged from supports,
-
Shifting of base plate, breaking of foundation
-
Pipe supports forced out of plumb
-
Expansion joints excessively damaged
-
Equipment walls at terminal points showing
-
Excessive repair of bearings of rotating machinery to which piping is
deformation
connected.
c )
Supports & Vibrations
76
-
Physical damage, distortion , movement of supports,
failure or loosening of
foundation bolts
-
Restricted operations of pipe rollers, slide plates
-
Broken pipe anchors
-
Damage to small branch line due to thermal movement of larger lines ( X-Y-Z
directions )
-
If excessive vibrations are observed in a piping welds shall be inspected for
cracks, especially at points of restraints, anchors
-
Additional supports may be considered for poorly supported lines
-
Seek advice of Consultant / Piping Engineer to eliminate / dampen the
vibrations
d )
External Corrosion
-
Due to defects in Coating, painting or damaged insulation
-
Survey for CUI shall be done in operation to the extent possible
-
Lines that sweat, liquid spills, condensate (relief valves down stream ) may
cause external corrosion
-
Hot spots due to damage of internal refractory lining.
-
Night glow or balding of pipes may be seen
-
To arrest balding external cooling by water, air, may be used till system is
removed for maintenance
INSPECTION DURING SHUT DOWN
77
1. Visual inspection after pipe is opened at various flanged joints and valves.
( Flash light and extension lights and mirrors magnifying glasses may be used )
may reveal following :
a )
Excessive corrosion / Erosion, fouling
b )
Cracks ( welds are most prone areas ) investigate cracks further by blast
cleaning and wet fluorescent MPI, LPI and UT
c )
Gasket faces of flanges shall be checked for scratches, cuts, pitting etc
( Ref. ASME B 16.5 Para 6.0 )
d )
Valves, bodies to be checked for thickness, flanged ends for defects ©
above and other parts ( seat stem spring for damage and breakage, check
studs and nuts for deformation, shaving of threads etc.
e )
Check threaded joints for loose threads, corrosing, cross threading,
ensure new Teflon tapes are used while putting back in place
f )
Areas seen as hot spots externally shall be inspected for damage
internally and repaired
g )
Damage to internal painting, coating, cladding shall be surveyed and
repaired
PRESSURE TESTS
1 )
Piping systems subject to pr. Test include :
a.
Underground lines and other inaccessible piping
b.
Water and other non-hazardous utility lines
78
c.
Long oil-transfer lines in arcas where a leak or spill would not be
hazardous to personnel or harmful to the environment.
2 )
3 )
d.
Complicated manifold systems.
e.
Small piping and tubing systems.
f.
All systems after a chemical cleaning operation.
API 570 sec. 3.7 gives guidelines for preparing piping for pressure Testing.
During liquid pressure Test, all air must be expelled, or else failure could be
more violent than liquid-full system.
4 )
Avoid over pressure
– yield limit may exceed. Use calibrated pressure Gauges (gauge range 1 ½ to 4
times test pressure). However, 2 to 3 times Pt is preferred.
5 )
6 )
Fluids used a.
water – (preferred )
b.
Liquid products normally carried if not toxic or inflammable
c.
Steam
d.
Air, Nitrogen, Helium
Water as test medium may not be suitable for
a.
Acid lines
b.
Vacuum lines ( vertical lines )
c.
Corrosion of Austentic Steels ( SCC )
d.
May freeze in cold weather
79
7 )
Steam may be used particularly if it is used for heating or purging. However,
-
difficulty in draining condensate from all areas and
-
Compressibility (unsafe )
-
Inaccessibility and burn to personnel on leakage could put severe
restrictions. All precautions of pneumatic testing stated in ASME B 31.3
must be observed for steam testing as well.
Pneumatic tests:
•
Pneumatic tests with soap solutions are permissible. However, best gaseous
mediums would be inert gases like nitrogen Helium etc.
•
Helium is ideal as it can detect minutest cracks which otherwise would be missed
in water, air, steam or Nitrogen testing.
•
Helium leakage in ppm levels can be detected by Helium sniffers.
Hence they are used when service conditions are particularly critical.
HAMMER TESTING
•
Hammer testing is old method to detect unexpected thin sections.
•
Cast Irons and Caustic lines inside coated lines should not be hammered
•
Requires personal expertise
•
Hammer test shall be followed up by other methods like UT at suspected areas.
*******
80
NSPECTION OF UNDERGROUND PIPING
1
In addition to product corrosion the Underground Piping is exposed to soil
corrosion. Following methods are adopted in inspection of Underground Piping :
2.
A survey above ground of the piping route could show discoloration of soil,
pool formation, noticeable odor etc. for which corrosion and leak may be
probable cause.
All Pipes are inspected at and just below the point where they enter earth,
concrete, asphalt etc. since these areas are more prone to corrosion.
3.
Close internal potential survey – This technique measures the potential of the
pipe to the soil directly over pipe at fixed intervals ( 5 ft, 10 ft. etc. )
Pipe contact can be made at an above ground attachment. Sudden change of
P/S potential is location for further scrutiny ( by excavation, if required ).
4.
Holiday pipe coating survey is employed to ensure that coating is intact and
holiday free.This technique is used for predicting corrosion activity in specific
area and coating replacement decisions.
5.
Soil resistivity testing : This technique is used for relative classification of the
soil resistivity.Lower levels of resistivity are more corrosive than higher levels.
81
6.
Cathodic Protection Monitoring : This shall be carried out regularly to assure
adequate levels of protection.
Periodic monitoring includes checking condition of sacrifical anodes or rectifier
currents in impressed current system.
7.
Intelligent Pigging : This method involves movement of device (pig) through
piping. However, this technique requires line to be free from restrictions (i.e. full
bore valves, absence of reduces) and five diameter bankds.
Very effective
technique in long distance piping. However, blant piping has limited use.
8.
Video Cameras
:
These provide direct visual information on internal
condition of pipe.
9.
Excavation : Sometimes the only available method is unearthing of piping for
visual inspection of external condition of piping and evaluate its thickness.
10.
Leak testing
:
VIG lines that can not be visually inspected should be
periodically.
a.
Pressure decay method : Pressurise the line, block it, remove
source of pressure, monitoring over a period of time will provide indicating
of pressure tightness. Performance can be confirmed by leak simulation.
82
b.
Volume in/ volume out method uses volumetric measuring meter at
each end of the line. Performance can be determined by leak simulation.
c.
Single point volumetric method is similar to pressure decay method
except that a graduated cylinder is employed to check level reduction by
leakage.
d.
Maker chemical (tracer) may be added to line to detect leak and
soil gas samples near line are tested for presence of maker chemicals.
e.
Accoustic emission technology detects and locates leaks by sound
created by leak and detected by senser.
********
83
RETIREMENT THICKNESS FOR PIPES
( API 574 Par. 11.1 )
1 )
Thickness formulas from ASME B31.3 shall be used.
t = tm + A
Where tm =
tm =
PD
---------------- + A
2SE +2PY
PD
-------2SE
or,
… ( Barlow formula)
( for t > D/6 or P/SE > 0.385, special considerations
required )
In practice t is generally higher due to rounding up of pipe
schedule to higher number.
2 )
For low pressure and temperatures, above thicknesses could be so small for
sufficient structural strength for span and other UDL ( insulation, snow etc. )
3 )
Absolute minimum thickness (
t a ) shall be determined based on internal
pressure, sag, buckling etc.
Pipe should not be permitted to deteriorate below this thickness ( t a ), which is
called
“Retirement Thickness” i.e. Pipe shall be retired ( replaced ) at this
thickness.
4 )
Above calculations shall be performed by or under direction of Piping Engineer.
84
RETIREMENT THICKNESSFOR VALVES & FLANGED FITTINGS:
( API 574 – Para 11.2 )
1.Stress pattern for valves and flanges in quite complex due to simultaneous effects of :
2.
-
Internal pressure
-
Bolts load forces and movements
-
Stress concentration due to shape
ASME B 16.34 determines that min. Valve wall thickness (t v) shall be
tv =
1.5 x t …..
for Valve classes 150 – 2500
tv =
1.35 x t …
for Valve class 4500
Where, t = Thickness of Cylinder with S = 7000 psi and Pressure same as that
from P – T ratings
Actual thickness ( ta ) given in B 16.34 = tv + 0.1 In.(fixed)
Valve thickness per API 600 have additional corrosion and erosion requirement
over ( ta ) from B 16.34
3.
Where corrosion / erosion is anticipated thickness measurements shall be
made to determine metal loss.
4.
Formula for calculating retirement thickness of pipe can be used for Valves
and flanged fittings using factor 1.5 and 5 Valves from ASME B 31.3.
Calculations described above not required for welded fittings. Pipe thickness can be
adopted for welded fittings using appropriate corrections for shape, if necessary.
85
INSPECTION RECORDS
( API 570 – Chapter 12 )
1.
-
Inspection records provide :
A comprehensive picture of general condition ( i.e. health ) of piping
system
-
Decide on additional / supplementary inspections
-
Evaluation of remaining useful life
-
Deciding on probable retirement and replacement programmes and take
advance action for the same.
The data should be arranged on suitable forms so that successive inspection
records furnished a chronological picture.
2.
Sketches : Original isometric sketches may be used or new sketches made
to show TMLs and other relevant information.
3.
Thickness Data
:
Record of thickness data obtained from periodic or
scheduled inspections shall be shown on sketches and tabulated and attached
sketches ) Fig. 34 sample form
4.
Review of Records : Records of previous inspection shall be reviewed soon
after current data is available from field and follow-up action sheets shall be
prepared showing :
-
Approaching retirement thickness
-
Need of further investigation based on past and present data ( i.e.
excessive corrosion rates on both occasions )
86
-
In other cases specific features to be monitored during on-stream or next
shut down inspection.
-
A list for predictable repairs and alterations shall be made so that
maintenance dept. can obtain materials, keep components ready, if
nessary, fabricate well ahead of next shut down. This list will also help to
plan manpower for next shut down.
*********
87
PLANT PIPING CODE - ASME B 31.3
PIPING FUNDAMENTALS
1.
General :
Prior to study of Plant piping code, a quick review of piping fundamentals is
essential for prper understanding of the code.
A pipe or a tube is hollow, longitudinal product. `A tube’ is a general term used
for hollow product having circular, elliptical or square cross-section or for that
matter cross-section of any closed perimeter.
A pipe is tubular product of circular cross-section that has specific sizes and
thicknesses governed by particular dimensional standard.
2.
Classification :
Pipe can be classified based on methods of manufacture or based on their
applications.
3.
Methods of manufacture :
Seamless pipes are manufactured by drawing or extrusion process. ERW pipes
( Electric resistance welded pipes ) are formed from a strip which is longitudinally
welded along its length. Welding may be by Electric resistance, high frequency,
or induction welding, ERW pipes can also be drawn for obtaining required
dimensions and tolerances.
88
Pipes in small quantities are manufactured by EFW ( Electric fusion welding )
process where in instead of electric resistance welding, the longitudinal seam is
welded by manual or automatic electric arc process.
There are spiral seam welded pipes, which are large dia pipes 500 NB and
above, and pipes are made by welding a spiral seam produced by forming
continuous steel skelp into circular shape.
Centrifugally cast pipes are made by spraying molten metal along a rotating die
where the pipes are cast in shape due to centrifugal action.
Classification based on end use :
Pipes a re classified as :
-
Pressure pipes or Process pipes
-
Line pipes
-
Structural pipes
1.
Pressure pipes are those which are subjected to fluid pressure and or
temperatures. Fluid pressure in generally internal pressure due to fluid
being conveyed or may be external pressure ( e.g. jacked piping ) and are
mainly used as plant piping.
2.
Line Pipes are mainly used for long distance conveying of the fluids and
are subjected to fluid pressures. These are generally not subjected to
high temperatures.
3.
Structural pipes are not used for conveying fluids and therefore not
subjected to fluid pressures or temperatures. They are used as structural
components ( e.g. handrails, columns, sleeves etc. ) and are subjected to
static loads only.
89
Pipes Dimensional Standards :
4.
Diameters : Pipes are designated by Nominal size, Starting form 1/8” Nominal
size, and increasing in steps.
1.
Pipe sizes increases in steps of 1/8” fir 1/8” to ½” : 1/8”, ¼”, 3/8”, ½”
Nominal size.
2.
Sizes in steps of ¼” : ½”, ¾”, 1”, 1 ¼”, 1 ½”
3.
In steps of ½” upto 4” : 1 ½”, 2”, 2 ½”, 3”, 3 ½”, 4”
4.
In steps of 1” upto 6” : 4”. 5”, 6”
5.
In steps of 2” upto 36” : 6”, 8”, 10” ……. Etc.
For the Nominal size upto including 12”, there is one unique O.D. ( different from
nominal size ) and I.D. would vary depending on schedule number. For Nominal
sizes 14” and above, O.D. is same as Nominal size.
5.
Schedule No. :
Pipes are designated by schedule number or weight designation like Std. (S),
Extra Strong (XS) and Double Extra Strong (XXS)
Pipe schedule number S is defined as :
Sch. NO. S = 1000 P/S
Where P = Internal Pressure (psi)
S = Allowable tensile strength of material used.
90
Common pipe schedules are Sch 40, Sch 80, Sch 120, Sch 160, for larger pipe
sizes intermediate schedule numbers ( Sch20, Sch 30 etc. ) are also employed
( Ref. Pipe Dimension Chart )
For Carbon steel, Pipe wall thickness tolerance is + 12 ½% i.e. Pipe wall
thickness can vary 12 ½% from thickness obtained from dimension chart.
For stainless steels schedule numbers are designated by suffix S i.e. 10S, 40S,
80S e tc.
Length :
Pipes are manufactured in `random length’ which is + 20’ –0” and in
double random length + 40’ –0”.
6.
Fittings
Pipe fittings are the components which tie together pipe lines, valves, and other
parts of a piping system. They are used in “making up” a pipe line. Fittings may
come in screwed, welded, soldered, or flanged varieties and are used to change
the size of the line or its direction and to join together the various parts that make
up a piping system.
The majority of pipe fittings are specified by the nominal pipe size, type, material
and the name of the fitting.
Besides the end connections mentions above
(screwed, welded, soldered, flanged) it is also possible to order bell and spigot
fittings, which are usually cast iron and used for low pressure service.
In general, a fitting is any component in piping system that changes its direction,
alters its function, or simply makes end connections. A fitting is joined to the
system by bolting, welding or screwing, depending on many variables in the
system.
91
6.1
Butt-Welded Fittings
Welded fittings are used primarily in systems meant to be permanent.
They have the same wall thickness as the mating pipe. Among the many
advantages of butt welded systems are the following :
1.
They have a smooth inner surface and offer gradual direction
change with minimum turbulence.
2.
They require much less space for constructing and hanging the
pipe system.
3.
They form leak-proof constructions.
4.
They are almost maintenance free.
5.
They have a higher temperature and pressure limit.
6.
They form a self-contained system.
7.
They are easy to insulate
8.
They offer a uniform wall thickness through-out the system.
One of the major disadvantages of butt-welded systems is that are not
easy to dismantle. Therefore, it is often advisable to provide the system
with enough flanged joints so that it can be broken down at intervals.
( One of the main uses of the butt-welded system, is for steam lines, which
are usually in high-temperature/ high-pressure service ).
6.2
Socket Welded Fittings
Socket welded fittings have certain advantages over butt-welded fittings.
They are easier to use on small-size pipelines and the ends of the pipes
need not be beveled since the pipe end slips into the socket of the joint.
With socket-welded fittings there is no danger of the weld protruding into
the pipeline and restricting flow or creating turbulence.
Thus, the
advantages of the socket-welded system are :
92
1.
The pipe does not need to be beveled.
2.
No
tack welding is necessary for alignment since joint and the
pipe are self -aligning.
3.
Weld a material can not extend into the pipeline.
4.
It can be used in place of threaded fittings, therefore, reducing the
likelihood of leaks, which usually accompany the use of threaded
fittings.
5.
It is less expensive and easier to construct than other welded
systems.
One of the major disadvantages of this type of fitting is the possibility of a
mismatch inside the fitting where improperly aligned or mated parts may
create a recess where corrosion could start.
Socket-welded fittings have the same inside diameter as standard
(Schedule 40), extra strong (Schedule 80), and double extra strong
(Schedule 160) pipe, depending on the weight of the fitting and mating
pipe. Socket-welded fittings rare covered in ASA B16.11. They are drilled
to match the internal diameter of schedule 40 or schedule 80 pipe.
6.3
Flanged Fittings
Flanged connections are found on piping systems throughout the
petrochemical and power generation fields on pipelines that are a
minimum of 2 in.(5.08 cm ) in diameter. The majority of flanged fittings are
made of cast steel or cast iron.
Flanged steel fittings are used in place of cast iron where the system is
subjected to shock or high-temperature/ high-pressure situations where
the danger of fire is prevalent, because cast iron has a tendency to c rack
or rupture under certain stresses. A flange may be cast or forged onto the
ends of the fitting or valve and bolted to a connecting flange which is
93
screwed or welded onto the pipeline, thereby providing a tight joint. An
assortment of facings, ring joint grooves, and connections are available in
flange variations.
One advantage of flanged systems is that they are easily dismantled and
assembled. One of the disadvantages is that they are considerably than
an equally rated butt-welded system, because of the large amount of
metal that go into making up joints and flanges. Moreover, flanged fittings
occupy far more space than the butt-welded or screwed equivalents.
Because of this higher weight load, a flanged system becomes far more
expensive to support or hang from the existing structure.
*****
94
STUDY OF ASME B 31.1 CODE REQUIREMENTS
1.1
GENERAL :
The Code sets forth engineering requirements deemed necessary for safe design
and construction of pressure piping.
Unless agreement is specifically made between contracting parties to use
another issue, or the regulatory body having jurisdiction imposes the use of
another issue, the latest Edition and Addenda issued at least 6 months prior to
the original contract date for the first phase of activity covering a piping
installation shall be the governing document for all design, materials, fabrication
erection, examination, and testing for the piping until the completion of the work
and initial operation.
1.2
SCOPE :
Rules for the Process Piping Code Section B31.3 1 have been developed
considering
piping
typically
found
in
petroleum
refineries;
chemical,
pharmaceutical, textile, paper, semiconductor, and cryogenic plants; and related
processing plants and terminals within the property limits.
This Code prescribes requirements for materials and components, design,
fabrication, assembly, erection, examination, inspection, and testing of piping.
1.3
DEFINITIONS :
1.3.1 Chemical plant : an industrial plant for the manufacture or processing of
chemicals, or of raw materials or intermediates for such chemicals. A
chemical plant may include supporting and service facilities, such as
storage, utility, and waste treatment units.
95
1.3.2 Fluid service : a general term concerning the application of a piping
system, considering the combination of fluid properties, operating
conditions, and other factors which establish the basis for design of the
piping system. See Appendix M.
a.
Category D Fluid Service
:
a fluid service in which all the
following apply :
1.
the fluid handled is nonflammable, nontoxic, and not
damaging to human tissues as defined in para 300.2 ;
2.
the design gage pressure does not exceed 1035 kPA (150
psi) ; and
3.
the design temperature is from –29 o C (-20o F) through 186o
C (366o F)
b.
Category M Fluid Service : a fluid service in which the potential
for personnel exposure is judged to be significant and in which a
single exposure to a very small quantity of a toxic fluid, caused by
leakage, can produce serious irreversible harm to persons on
breathing or bodily contact, even when prompt restorative
measures are taken.
c.
High Pressure Fluid Service : a fluid service for which the owner
specifies the use of Chapter IX for piping design and construction;
see also para. K300
d.
Normal Fluid Service : a fluid service pertaining to most piping
covered by this Code, i.e. not subject to the rules for Category D,
Category M, or High Pressure Fluid Service.
96
1.3.3 Petroleum refinery – an industrial plant for processing or handling of
petroleum and products derived directly from petroleum. Such a plant
may be an individual gasoline recovery plant, a treating plant, a gas
processing plant (including liquefaction), or an integrated refinery having
various process units and attendant facilities.
1.3.4 Piping components – mechanical elements suitable for joining or
assembly into pressure-tight fluid-containing piping systems. Components
include pipe, fittings, flanges, gaskets, bolting, valves, and devices such
as expansion joints, flexible joints, pressure hoses, traps, strainers, in-line
portions of instruments, and separators.
********
97
DESIGN OF PIPES FOR SERVICE CONDITIONS
1.1
DESIGN CONDITIONS :
This paragraph defines the temperatures, pressures, and forces applicable to the
design of piping, and states the considerations that shall be given to various
effects and their consequent loadings.
1.1.1 Design Pressure :
The design pressure of each component in a piping system shall be not
less than the pressure at the most severe condition of coincident internal
or external pressure and temperature (minimum or maximum) expected
during service.
1.1.2 Design Temperature :
The design temperature of each component in a piping system is the
temperature at which, under the coincident pressure, the greatest
thickness or highest component rating is required.
1.1.3 Design Minimum Temperature :
The design minimum temperature is the lowest component temperature
expected in service.
1.1.4 Bases for Design Stresses :
The bases for establishing design stress values (allowable stress values)
for metallic materials in this Code are as follows.
98
Basic allowable stress values at temperature for materials not exceed the
lowest of the following :
1.
the lower of one-third of SMTS and one-third of tensile strength at
temperature;
2.
the lower of two-third of SMYS and two – thirds of yield strength at
temperature;
2.2
WELD JOINT QUALITY FACTOR, EJ :
Basic Quality Factors. The weld joint quality factors E j tabulated in Table A-1B
are basic factors for straight or spiral longitudinal welded joints for pressurecontaining components as shown in Table 302.3.4
Increased Quality Factors.
Table 302.3.4 also indicates higher joint quality
factors which may be substituted for those in Table A-1B for certain kinds of
welds if additional examination is performed beyond that required by the product
specification.
2.3
PRESSURE DESIGN OF COMPONENTS :
2.3.1 Straight Pipe :
The required thickness of straight sections of pipe shall be determined in
accordance with following equation.
tm = t + c
The minimum thickness T for the pipe selected considering manufacturer’s
minus tolerance, shall be not less than tm.
99
The following nomenclature is used in the equations for pressure design of
straight pipe.
tm
=
minimum required thickness, including mechanical,
corrosion, and erosion allowances.
t
=
pressure design thickness.
c
=
the sum of the mechanical allowances (thread or groove
depth) plus corrosion and erosion allowances.
T
=
pipe wall thickness (measured or minimum per purchase
specification
d
=
inside diameter of pipe.
P
=
internal design gage pressure.
D
=
outside diameter of pipe as listed in tables of standards or
specification or as measured.
E
=
quality factor from Table A-1A or A-1B
S
=
stress value of materials.
Y
=
coefficient from Table 304.1.1, valid for t < D/6 and for
materials shown. The value of Y may be interpolated for
intermediate temperatures.
For t > D/6,
Y
=
d + 2c
-----------D + d+2c
Straight Pipe Under Internal Pressure :
For t < D/6, the internal pressure design thickness for straight pipe shall
be not less than that calculated in accordance with Eq. (3a) :
t
=
PD
--------------2(SE + PY)
100
Following Equation may be used instead of above equation
t
=
PD
------2SE
For t > D/6 or for P/SE > 0.385, calculation of pressure design thickness
for straight pipe requires special consideration of factors such as theory of
failure, effects of fatigue, and thermal stress.
2.3.2 Blanks :
The minimum required thickness of a permanent blank (representative
configurations shown in Fig. 304.5.3) shall be calculated in accordance
with Eq. (15)
tm
=
dg
√
3P
--------- + c
16SE
wheredg
=
inside diameter of gasket for raised or flat face flanges, or
the gasket pitch diameter for ring joint and fully retained
gasketed flanges.
E
=
same as defined earlier.
P
=
design gage pressure
S
=
same as defined earlier
c
=
sum of allowances defined earlier.
****
101
2.
MATERIALS
Generic Description:
Classification of materials by generic description involves the grouping of materials into
broad categories according to certain attributes such as general composition,
mechanical properties, product form, or end use.
There are no precise rules governing which attributes to apply in defining material
groups, and the level of detail afforded the classification system depends largely on the
level of detail needed to communicate specific ideas. Consequently, materials may be
generically grouped according to very broad characteristics, for example metal or
nonmetal, ferrous or nonferrous, or cast or wrought. Alternatively, materials may be
placed in more narrowly defined generic groups such as mild steel, 3XX series stainless
steel, or NiCrMo alloy.
With piping materials, generic grouping based on alloy content is most popular. These
groups usually reflect the primary alloy content, and may include varying levels of
complexity depending upon the extent to which one needs to communicate specific
material needs. Table-5.1 gives an indication of the progression from simple generic
descriptors, to complex generic descriptors, which may involve some elements of a
standardized classification system (e.g., 300 series austenitic stainless steel).
Table 5.1 Levels of Generic Classification of Materials
Simple
Intermediate
Complex
Carbon Steel
Low Carbon Steel
Fully Killed, Low Carbon Steel
Low Alloy Steel
Cr-Mo Steel
2 ¼ Cr-1Mo Steel
Stainless Steel
Austenitic Stainless Steel
Nickel Alloy
High Nickel Alloy
300 Series Austenitic Stainless
Steel
NiCrMo Alloy
102
Generic material descriptions are frequently used during the early stages of a project,
including project definition, conceptual design, front end design, preliminary design,
process design, and/or budget estimation. For materials selection purposes during
these stages, the user must be aware of Code requirements, but is not looking for a
precise solution for each piping system.
Rather, the user should be looking at more global issues including resistance of generic
material groups to various forms of corrosion, material cost and availability for various
product forms, delivery times, need for qualification testing, and existence of suitable
forming and joining technology.
Trade Names and Proprietary Designations
Trade names are used by manufacturers to uniquely identify their materials and
products. Sample trade names include Inconel 625, Incoloy 825, Hastelloy C-275,
Carpenter 20Cb-3, Allegheny- Ludlum Al-6 XN, Mather & Platt Xeron 100, Lincoln
Fleetweld 5P+, and VDM 1925hMo.
Although there are definite commercial reasons for the existence of trade names (e.g.,
typically to induce purchasers to specify and buy only the product of a particular
manufacturer), many manufacturers and trade associations publish trade name
equivalency charts. Consequently, there is usually no need to restrict material
selections through use of a single trade name. However, two exceptions do exist where
it may be necessary to specify materials by trade name. The exceptions are:
a. Materials of very recent development, still be protected by patent right, and
b. Sophisticated materials required for very severe service situations, where all
potential manufacturers may not be equally capable of making the same quality of
product. (For certain high alloy materials, minor chemistry or processing
modifications can dramatically affect alloy performance.)
Common ASTM Carbon Steel Piping Materials:
For everyday work, most piping systems are constructed from carbon steel. Material
designations are seemingly inconsistent and random and, for the most part, knowledge
of specifications and grades can only be gained with experience.
Nevertheless, for practical guidance, specification and grade designations can be
grouped according to product form and notch toughness properties, as in Table 5.10.
Table 5.10 Common ASTM Carbon Steel Piping Material Specifications & Grades
103
Product Forms
See Note(s)
ASTM Materials
without Impact Tests
A 53 Gr. B
A 106 Gr.B
ASTM Materials
with Impact Tests
A 333 Gr. 1
A 333 Gr. 6
A 105
A 350 Gr. LF2
Wrought Fittings
A 234 Gr. WPB
A 420 Gr. WPL6
Castings
A 216 Gr. WCB
A 216 Gr. WCC
A 352 Gr. LCB
A 352 Gr. LCC
A 193 Gr. B7
A 320 Gr. L7
A 193 Gr. B7M
A 320 Gr. L7M
A 194 Gr. 2H
A 194 Gr. 2HM
A 194 Gr. 7
A 194 Gr. 7M
Pipe
2
Flanges & Forged
Fittings
3
Bolts, Studs, and
Cap Screws
Nuts
4,5
4,5
Notes to Table 5.10
1.
2.
3.
4.
5.
Column headings refer to impact testing requirements of the material
manufacturing specifications.
For ASTM A 53, the type of pipe should also be specified, where S =
Seamless, E = Electric Resistance Welded, and F = Furnace Butt Welded.
Note: Type S is normally used for pressure piping, Type E is sometimes
used, but Type F is rarely used.
Forged fittings include weldolets, threadolets, and sockolets (WOT, TOL,
SOL).
B7M, 2HM, L7M, AND 7M refers to grades with strength and hardness
control, typically for resistance to sulfide stress cracking in sour (H 2S)
environments. See also NACE MRO175.
Quenched and tempered low alloy bolting has excellent notch toughness at
lower temperatures. B31.3 permits use of low alloy steel bolting to lower
temperatures than would be expected for corresponding carbon steel piping
components. See the “Min. Temp”. Column of B31.3 Table A-2 for lower limit
of temperature.
104
Material Requirements of B31.3:
Materials considerations are specifically covered in B31.3 Chapter III, but there are also
material references in many other chapters. The Code categorises various fluids as
below , the material selection many times is governed by nature of fluid.
Table 5.11 Fluid Service Categories
Normal Fluid Service
Category D Service
Category M Service
Pertains to most piping covered by the Code and
includes piping not classified within the other fluid
services listed below [¶300.2].
Service in which the fluid is nonflammable,
nontoxic, and not damaging to human tissue; the
design pressure does not exceed 150 psig (1030
kPag); and the design temperature is from -20ºF
(-29ºC) TO 366ºF (186ºC)[¶300.2].
Service in which a single exposure to a very small
quantity of toxic fluid can produce serious
irreversible harm on breathing or body contact,
even when prompt restorative measures are
taken [¶300.2].
Service which applies when designated by the
owner, typically for pressures in excess of that
allowed by ASME B16.5 Class 2500 rating, for the
specified design temperature and material group
[¶k300(a)].
High Pressure (K) Service
. Notes to Table 5.11
a. For exact descriptions and classification of fluid service, refer to B31.3.
b. Severe cyclic conditions are defined by B31.3 as “conditions which are
vibrating, cyclic or fatigue in nature, with S E exceeding 0.8 SA and with the
equivalent number of cycles exceeding 7000; or other conditions which the
designer determines will produce an equivalent effect [¶300.2].” Even though it
may appear that severe cyclic conditions satisfy the B31.3 definition for a “fluid
service”, they have not been included as a separate fluid service in the above
table because, when severe cyclic conditions exist, they are typically a subset
of one of the other four listed fluid services.
Materials and Specifications [¶323.1]
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B31.3 classifies materials as listed, unlisted, unknown, or reclaimed, and places
conditions on the used of such materials. Table 5.12 summarizes the characteristics of
each material classification.
In most cases, Code users deal with listed materials. These may be considered as
materials, which are “prequalified” for Code use based on inherent properties [¶323]
and listed in B31.3 Tables A-1 and A-2. For pressure design purposes, the Code
provides stress values for the listed materials as a function of temperature (since
mechanical behavior is temperature dependent). However, the suitability of a particular
material for a particular fluid service is beyond the scope of the Code [¶300(c)(6)]. A
materials specialist should be consulted to ensure correct materials selection for a fluid
service.
Temperature Limitations [¶323.2]
B31.3 recognizes that material properties and behavior in service are temperature
dependent. A significant portion of b31.3 Chapter III deals with temperature limitations
for materials, in particular lower temperature limits where impact testing may apply. The
Code also imposes cautionary and restrictive temperature limits in Tables A-1 and A-2,
and requires designers to verify that materials are suitable for service throughout the
operating temperature range [¶323.2].
Table 5.12 Material Classifications [ ¶323.1]
Listed Materials
[¶323.1.1] Those materials or components which conform
to a specification listed in B31.3 Appendix A, Appendix B,
or Appendix K, or to a standard listed in B31.3 Table
326.1, A326.1 or K326.1. for pressure design, listed
materials and allowable stress values are provided for
listed materials, these are most convenient to use.
Unlisted Materials
[¶323.1.2] Those materials which conform to a published
specification
covering
chemistry,
physical,
and
mechanical properties, method and process of
manufacture, heat treatment, and quality control, and
which otherwise meet the requirement of the Code.
Unknown Materials
Reclaimed Materials
[¶323.1.3] Those materials of unknown specifications, not
to be used for pressure containing piping components.
[¶323.1.4] Used materials, which have been salvaged
and properly identified, as conforming to a listed or
published specification.
Upper Temperature Limits [¶323.2.1]
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Upper temperature limits for listed limited materials are the maximum temperatures for
which a stress value or rating is shown directly in or referenced by the Code. The Code
may also provide notes to the stress value tables, precautionary information in Appendix
F, and /or restrictions within the text of Code. For example, from Table A-1, the upper
temperature limit for ASTM A 106 Grade B pipe is 1100ºF even though there are two
notes pertaining to use of the material above 800ºF and 900ºF, respectively. ¶F323.4(a)
(2) and ¶F323.4(a)(4) also discuss these notes.
Of course, the Code does permit use of listed materials at temperatures above the
maximum indicated by the stress value or rating, provided there is no prohibition in the
Code [¶323.2.2(a)] and provided the designer verifies the serviceability of the material
[¶323.2.1(b)]. Verification would typically involve material specialists with an engineering
background and a “sound scientific program carried out in accordance with recognized
technology” [¶323.2.4].
Lower Temperature Limits and Impact Testing [¶323.2.2]
Lower temperature limits for materials are established as a means of controlling risk of
brittle fracture. Terms frequently used in lower temperature limit discussions include
notch sensitivity, impact testing, Charpy testing, and notch brittleness.
For must Code users, the basic question to be answered is: “Do I need to use impact
tested materials”, answering the question can be complex and convoluted; however, the
basic steps to determining the answer are listed below and are discussed in detail in the
following paragraphs.
a. select the design minimum temperature for the piping. This may involve process
engineering and or heat transfer specialists, and consideration of ambient
temperature effects.
b.
obtain the minimum permissible temperature for the proposed piping materials
according to B31.3 rules.
c. Follow the instructions of B31.3 to determine whether impact tests are required
(e.g., Table 323.2.2).
d. If impact tests are required, consult the additional requirements of B31.3 regarding
impact test methods and acceptance criteria.
Common Code Paragraphs Relating to Notch Toughness and Low Temperature
Requirements
For the convenience of users of the guide, several clauses and tables applicable to
B31.3 impact testing requirement are listed in Table 5.15 below. Users are cautioned
that this guide is not a substitute for the ASME B31.3 Code, which should be consulted
for all requirements affecting pressure piping design and construction.
Table 5.15 B31.3 Clauses and Tables Applicable to Impact Testing
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Clause or
Table
301.3.1
Description
301.5.1
Dynamic Effects – Impact
301.9
Reduced Ductility Effects
302.2.4(h)
Allowances for Pressure and Temperature Variations (below the
minimum temperature shown in Appendix A)
309.2.2
Carbon Steel Bolting (note that B7M, L7M, B7, L7, 2HM, 7M,
2H, and 7 are low alloy steels, not carbon steels)
321.1.4(c )
Materials (of unknown specification used for piping supports)
323.2
Temperature Limitations
323.2.2
Lower Temperature Limits, Listed Materials
323.2.3
Temperature Limits, Unlisted Materials
323.3
Impact Testing Methods and Acceptance Criteria
323.4.2(a)
Ductile Iron
323.4.2(b)
Other Cast Irons
Table 323.3.1
Impact Testing Requirements for Metals
Table 323.2.2
Requirements for Low Temperature Toughness Tests for Metals
Table 323.3.5
Minimum Required Charpy V-Notch Impact Values
Table A-1
Basic Allowable Stresses in Tension for Metals (see Min. Temp.
column and Note 6 at the beginning of the table)
Table A-2
Design Stress Values for Bolting Materials (see Min. Temp.
column and Note 6 at the beginning of the table)
Design Minimum Temperature
Materials Selection
When selecting materials for plant piping systems, legal, code, commercial, and
technical considerations must be addressed.
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Legal Considerations
Legal considerations include understanding and appreciation of:
a. legislation applicable to the jurisdiction having authority over the design, construction
and operation of the piping system; and
b. contracts which exist between various parties.
For example, many states, provinces, and countries have legislated the use of B31.3
rules for construction of piping systems, so the Code essentially become a legal
document. Local jurisdictions may also operate under government acts and regulations,
which impose additional requirements that, may be:
a. technical (e.g., prohibitions concerning certain materials or design practices), or
b. organizational (e.g., registration of designs, registration of welding procedures,
registration and accreditation of quality control systems)
For many projects, contract documents, including specifications prepared by the owner
or owner’s engineer, impose restrictions on:
a. Materials (e.g., quality level, notch toughness properties, service environment,
product form), and
b. Fabrication/construction methods (e.g., bending, forming, welding, heat treating,
hydrotest water quality, cleaning chemicals)
B31.3 Code Considerations
As indicated earlier in this chapter, the B31.3 Code is concerned with pressure integrity
(safety). This is manifest, for example, through provision of allowable design stresses as
a function of temperature, rules for notch toughness evaluation and brittle fracture
avoidance, restrictions for various fluid service categories, requirements for weld
procedure qualifications, restrictions on forming and bending practices, examination
requirements, and numerous prohibitions, limitations, conditions, and precautionary
measures scattered throughout the Code.
Although Code issues must be considered in the material selection process, the Code
does not instruct the user on how to select specific materials. ¶300( c)(6) states:
“Compatibility of materials with the service and hazards from instability of contained
fluids are not within the scope of this Code. See Para. F323”. The first sentence of
¶F323(a) states: “Selection of materials to resist deterioration in service is not within the
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scope of this Code”. Clearly, the technical issues related to materials selection must be
considered by personnel with specific training in this area.
Commercial Considerations
Materials decisions invariably have an impact on project cost and schedule. Can the
material be purchased in the requirement form? What will be the initial cost? When will
the material be available? What is the life cycle cost relative to other material options?
Who can fabricate the material into a piping system? When can it be delivered and at
what cost? What are the anticipated maintenance costs with the selected material?
These questions can be difficult to answer, but every materials decision has a
commercial impact, which must be considered. The level of detail given to study of the
commercial impact is widely variable depending on project scope, technical complexity,
and management.
Technical Considerations
Technical considerations begin with an understanding of process and containment
requirements including pressure, temperature, fluid velocity, and fluid characteristics, as
well as risk and consequences of failure. Material properties are then evaluated in light
of this understanding, and generally include consideration of chemical, mechanical, and
physical properties, as well as corrosion resistance, weldability, and formability.
Fundamentally, final materials selection involves the proper matching of material
properties with process design conditions, mechanical design conditions, fabrication
and construction conditions, and operating conditions.
Table 5.16 provides and overview of some material selection issues relative to other
project variables.
Project Variable
Materials Selection Issues
Process Design
•
Conditions and Corrosion •
General weight loss corrosion
Localized corrosion (pitting, crevice, fretting)
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Resistance
Mechanical Design
Conditions and
Mechanical Properties
•
•
•
•
•
Fabrication and
Construction Conditions
•
•
•
•
•
Operating Conditions
•
•
•
Stress corrosion cracking (a.k.a environmental
cracking)
Strength (i.e., required thickness)
Ductility and resistance to brittle fracture
Hardness (requirements usually linked to process
design via stress corrosion cracking issues
Low temperature notch toughness (in addition to
ambient temperature effects, can also be linked to
process design such as significant JouleThompson effects on blowdown of high pressure
gases, or handling of cryogenic fluids)
High temperature strength and creep resistance
Vibration and fatigue resistance
shop or field work, including availability of
equipment and skilled personnel
forming and bending needs
joining needs (welding, threading, brazing, and
soldering)
ease of maintenance and repair, including
availability of equipment and skilled personnel
(e.g., manned or unmanned plant)
product delivery requirements, planned on –
stream efficiency, and proposed plant or unit
turnaround schedule
adequacy of project safeguards – e.g., prevention
of leakage between streams (one or two check
valves), adequacy of pressure and temperature
controls
From Table 5.16, one might correctly assume that selection of materials is an
evolutionary process, especially for technically complex projects. Generally the
materials selection process involves a series of steps, separated in time, with each step
narrowing down possibilities until the best option is determined. As project details
unfold, this narrowing of options is typically manifested by a change in the way materials
are identified, going from very generic descriptions (e.g., stainless steel) to
specifications, type, and grade (e.g., ASTM A 312 TP304L).
The level of detail applied during materials selection depends heavily on factors such as
the scope, size and complexity of the project, the stage of the project, the corporate
style of the participants, and the availability of materials specialists. Although the steps
sometimes overlap, careful analysis of several projects would show at least three
distinct phases of materials selection with the following characteristics:
a. Conceptual design - overview of process technology
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b. Process design – details of process technology
c. Mechanical design – primary scope of B31.3
Conceptual Design – overview of Process Technology
Development of a materials selection and corrosion control philosophy for a project
normally begins with evaluation and understanding of the process technology. Although
this step in the materials selection process is not always evident or obvious, and may
even be omitted when the process is well understood, it is a logical starting point for a
grass roots project.
As an example, in the very early stages of project development, where “ballpark”
economics are being thrashed out, the main interest of management is “big picture”
material costs. That dreaded classic question generally reaches the materials specialist.
How much stainless steel do we have to buy?. Of course, at the conceptual stage
process details can be sketchy at best, so there is much crystal ball gazing at this point.
Nevertheless, best efforts are made to provide a very generic overview of material
options, knowing that management doesn’t generally understand that there are at least
fifty different kinds of stainless steel, each with its own unique price and delivery terms,
and hundreds of material options that go by much stranger sounding names than
“stainless steel”.
The job of the materials specialist, who may also be called the corrosion specialist, is to
examine the proposed process for any major issues, which could jeopardize the project
in financial and/or schedule terms. This is normally done in consultation with process
professionals who have defined the process in terms of block flow diagrams, process
stream compositions, and chemical reactions that may occur. A few typical questions to
be answered during conceptual design are listed below.
a.
b.
c.
d.
Are carbon steels adequate?
Can coatings or chemicals be used economically to control corrosion?
If high alloy materials are required, how much will they cost?
How well is the interaction between the process environment and the material
understood?
e. Is there a requirement for materials testing prior to selection?
f. Could required materials testing jeopardize the project in financial or schedule
terms?
As an example, consider conceptual design for a plant for handling high velocity wet
natural gas at 1000psi, with 25% CO 2 and H2S AT 200ºF. Bare carbon steel would not
be a likely candidate material due to excessive weight loss corrosion. Inhibitors could be
considered, but adequate corrosion control may not be possible. The process is a bit
hot for conventional organic coatings or plastic liners. Both CO 2 and H2S could permeate
the coating and cause coating failure if the system were subject to rapid pressure
changes. Intermediate alloys containing chromium could work with adequate control
welding and heat treatment. High alloy steels (stainless steels) could also work, but
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there is a large increment in cost and there may be potential for chlorides and resultant
chloride stress corrosion cracking (CISCC).
Process Design
If development economics favor further work, the next phase of material selection is
generally made coincident with or slightly lagging behind process design. Process
information is examined in detail and materials are selected based on compatibility with
process stream characteristics and other external variables if they are known. Decisions
often require consultation with process engineers for clear understanding of process
conditions, including steady and non-steady state conditions such as start-up, upset,
planned shutdown, and unplanned shutdown.
As an example of the material selection process for a given stream, one might
designate piping materials such as carbon steel (CS) with a suitable corrosion were
important. However, if it is also known that the pipe might be exposed to low ambient
temperatures where impact properties were required, one might upgrade the material
selection to CSIT (carbon steel, impact tested) . For another stream, which could be
considered very corrosive, one might specify 3XXL stainless steel, where “L” grade is
imposed to resist HAZ sensitization during welding, and the possibility of intergranular
corrosion is service. If that same stream contained an aqueous chloride phase at 80ºC,
3XX would be susceptible to CISCC. In that case, one might specify a duplex stainless
steel or superduplex stainless steel, depending upon chloride level, oxygen content and
temperature.
While there is no single method for making and documenting materials selection
decisions, the normal output at this stage of a project is a Corrosion and Materials
Report. The word corrosion is generally included in the title of the report, since many of
the material selection decisions reflect a response to corrosion predictions. The report
typically contains the basis for decision making, as well as narratives describing issues,
concerns, and limitations governing final materials selection for a given portion of the
process.
Material selection diagrams (MSD’s) and/or material selection tables are generally
included with the Corrosion and Materials Report. MSD’s are typically modified process
flow diagrams (PFD’s) showing generic material choices and corrosion allowances for
each corrosion circuit. Corrosion circuits are elements of the process with similar
corrosion characteristics, and are frequently equivalent to process streams defined on
the PFD, or to subsets of process streams. Presentation of materials selection data in
diagram is generally the most useful format for communication with other design
professionals, who will use the information during completion of subsequent work. Such
presentation also assists in maintaining materials engineering input on the project. A
simplified example of a MSD for an amine sweetening unit is shown in Figure 5.1
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During the mechanical design stage, the process characteristics shown by process
simulations and PFD’s and the material requirements shown by the Corrosion and
Materials Report and MSD’s, are carefully examined. Then a piping class, which
summarizes detailed mechanical and material requirements, is generally assigned
to each line in the piping system. Note that the use of piping classes is not a B31.3
requirement; it is a typical approach to mechanical design within the pressure
piping industry.
An example of a simple piping class is shown in Figure 5.2. It is a table of information
for a given pressure rating and service characteristic, which describes acceptable piping
component types and dimensions, as well as material specifications, types, classes,
and/or grades. Piping components include pipe, forgings, fittings, valves, bolting,
gaskets, and other piping specials. Usually the piping class contains information about
corrosion allowance, postweld heat treatment, and nondestructive examination. Within a
corporation, piping classes often exist from previous projects, or are supplied by the firm
contracted to complete the engineering. When they do not exist, they are usually
developed on the basis of process, material, and mechanical requirements.
The piping class designator is typically an alphanumeric descriptor such s D2 or AA2U,
which is shown on the piping drawings (collectively, a group of drawings including P &
ID’s, MFD’s, piping plans and sections, and isometrics), usually as part of the line
number. a typical line number would be 6 in HC-34212-D2, where 6 in. is the nominal
pipe size, HC is the commodity descriptor (e.g., hydrocarbon), 34212 is the line serial
number, and D2 is the piping class. Specification breaks, which may be for material or
pressure reasons, are also applied to piping drawings.
Depending on project scope and technical complexity, the mechanical design stage
may also include preparation of detailed material specifications (stand alone or
supplementary) to address issued such as material chemistry, processing requirements,
product form (cast, forged, welded), fracture toughness, weldabilty, heat treatment,
nondestructive examination, and various forms of corrosion resistance.
********
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3. FABRICATION, ASSEMBLY, AND ERECTION
Introduction:
Chapter V of the B31.3 Code is devoted to the fabrication, assembly, and erection of
piping systems. These terms are defined by ¶300.2 as follows.
a.
Fabrication is the preparation of piping for assembly, including cutting, threading,
grooving, forming, bending, and joining of components into subassemblies.
Fabrication may be performed in the shop or in the field.
b.
Assembly is the joining together of two or more piping components by bolting,
welding, bonding, screwing, brazing, soldering, cementing, or use of packing
devices as specified by the engineering design.
c.
Erection is the complete installation of a piping system in the locations and on the
supports designated by the engineering design, including any field assembly,
fabrication, examination, inspection, and testing of the system as required by the
code.
Fabrication, assembly, and erection require the use of many special processes
including:
a. Forming and bending by cold and hot methods;
b. Joining by welding, brazing, soldering, or mechanical methods including threading,
flanging, specialty high pressure connections, and mechanical interference fits
(MIF); and
c. Heat treatment by local methods, or by permanent or temporary furnaces.
B31.3 assumes some understanding of the special processes used during fabrication,
assembly, and erection of piping systems. However, as with materials of construction,
the level of understanding is widely varied and often restricted to a few processes in the
user’s repertoire of experience.
Consequently, the objective of this chapter is to explore the basic technology behind
some of the special processes in relation to requirements of the Code.
115
Bending and Forming [¶332]
General
Bending and forming processes are sophisticated technical operations. An evaluation of
the effects of bending and forming on material properties is integral to the use of such
products in piping systems. In this light, the following Code statements should be
considered as more than simple motherhood:
a. ¶332.1 states: “pipe may be bent and components may be formed by any hot or cold
method which is suitable for the material, the fluid service, and the severity of the
bending or forming process.”
b. ¶332.3 states: “the temperature range for forming shall be consistent with material,
intended service, and specified heat treatment”.
These Code clauses are intended to trigger the engineering input necessary to verify
that final material properties will be satisfactory for the intended service. And, even
though the Code does impose requirement for design (e.g., ¶304.2) and fluid service
(e.g.,¶306.2), engineering input is still needed. The Code does not and can not provide
rules to address the specific requirements of every situation.
As part of an engineering evaluation, below are some useful starting questions
regarding the effects of bending and forming on material properties for a specific
service.
a. What effect will the bending or forming temperature and deformation parameters
(e.g., cold, warm, or hot bending, strain rate and total strain) have on strength,
ductility, hardness and notch toughness of the resulting bend?
b. What effect will the resulting microstructure have on general corrosion, localized
corrosion (galvanic, pitting, and/or crevice corrosion), stress corrosion cracking, or
long-term mechanical properties?
c. What are the risks relative to formation of hard spots, undesirable precipitation
effects, fatigue resistance, and creep resistance?
Hopefully the above questions would be answered with the help of metallurgical and/or
corrosion specialists, in combination with suitable testing when appropriate.
Bending
The need for changes to the direction of flow in piping systems has traditionally been
accommodated through the use of manufactured fittings such as elbows and tees.
However, changes to direction of flow may also be made through the use of pipe bends.
In fact, with modern equipment, substantial economic benefits can be derived from the
116
use of bends, by virtue of reduced fitting, welding, and nondestructive examination
(NDE) costs.
Before examining bends in detail, a few comments regarding bend types may be useful
to readers with no bending experience. In the bending and piping industries, bend types
are often described by a multitude of terms. Although a formal classification system
does not exist, bends are usually referred to in terms of:
a. Method of manufacture, including cold bends, hot bends, furnace bends, induction
bends, arm bends, ram bends, three point bends, miter bends, segmented bends,
corrugated bends, and creased bends;
b. Location of manufacture, that is, field bends or factory bends;
c. Shape or appearance, such as L-bends, S-bends, wrinkle bends, miter bends,
segmented bends, corrugated bends, and creased bends; and
d. Function or end-use, such as sag bends, overbends, side bends, and combination
bends.
Note that several of the terms described in (c) and (d) above are rooted in cross-country
pipeline construction, where bends are normally used to accommodate changes of
elevation associated with the terrain or to provide for expansion and contraction of the
pipeline with changes of temperature. For plant piping systems, it is most common to
use bending terms reflective of the method of manufacture, which may include
combinations of terms (e.g., three point cold bend, hot furnace bend, hot induction
bend).
Regardless of bend type, all bends have certain features and dimensional
characteristics which must be carefully specified during piping design and controlled
during bend procurement and manufacture (see Figure 6.1).
.
B31.3 addresses limitations on outer fiber elongation (strain) in clauses dealing with
post bend heat treatment [¶332.4]. In addition to B31.3 requirements, be cautions
about outer fiber strain restrictions imposed by other standards, which may be
applicable to the piping system (e.g., NACE MRO176).
Although not specified in B31.3, when longitudinally welded pipe is used for bending,
the longitudinal weld should be placed as near as practical to the neutral axis of the
bend.
Heat Treatments Required After Bending or Forming
Through heat treatment rules B31.3 does address some of the adverse effects of
bending and forming operations on material properties. The rules are based on type of
bending operation (hot or cold), type of material, and outer fiber strain.
Regardless of material thickness, heat treatment is required according to conditions
prescribed by ¶331:
117
a. After hot bending and forming operations carried out on P nos.3, 4, 5, 6, and 10A
materials;
b. After cold bending and forming.
1. of P-No. 1 to P-No.6 materials where the outer fiber elongation in the direction of
severest forming (usually extrudes) exceeds 50% of specified minimum
elongation stated for the specification grade, and thickness of the starting pipe
material;
2. of any material requiring impact testing, if the maximum calculated fiber strain
after bending or forming exceeds 5%; and
3. when specified by the engineering design.
With regard to (a) above, the materials listed are capable of transformation hardening
when cooled from hot bending and forming temperatures, so heat treatment is aimed at
restoring mechanical properties to a level reasonably consistent with the starting
materials. With regard to (b) above, work hardening effects imparted by cold bending
and forming reduce the ductility and notch toughness (impact strength) of materials. As
well, cold bending and forming operations generate residual stresses in the finished
parts. Heat treatment is therefore applied as a tool to reduce the negative
consequences of these effects (e.g., brittle fracture).
Welding
Most people associated with the pressure piping industry will, at some point, come in
contact with welding. This could mean:
a. Writing a welding procedure,
b. Qualify a welding procedure or welding personnel,
c. Reviewing a welding procedure for acceptance of rejection in a specific application,
or
d. Doing the welding, which will likely involve trying to interpret someone else’s welding
procedure.
To laymen, welding is a magic act. With the common arc welding processes, the arc
ignites with a flash of bright light, the magician (welder) moves the bright light along the
interface between the metals and “presto”, a weld is created. Of course, well-informed
piping professionals know that welding is a lot more than smoke and mirrors. It is a very
complex interdisciplinary science involving aspects of mechanical, civil, electrical, and
metallurgical engineering. Thorough technical understanding of welding operations
requires specific training, which is only available at select engineering, technical, and
trade schools.
B31.3 provides welding guidance in the areas of:
a. responsibility [¶328.1],
b. qualifications[¶328.2], and
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c. technical and workmanship criteria [¶328.3 through ¶328.6].
these are discussed in detail in the following sections.
Welding Responsibility [¶328.1]
B31.3 is very clear regarding responsibility for welding. ¶328.1 states: “each employer is
responsible for the welding done by the personnel of his organization and; except as
provided in paragraphs. 328.2.2 and 328.2.3, shall conduct the tests required to qualify
welding procedures, and to qualify and as necessary requalify welders and welding
operators”. This philosophy is consistent with other sections of the ASME code and with
similar codes, standards, and specifications around the world.
The two exceptions in ¶328.1, regarding the need for employers to conduct welding
qualification tests, are:
a. Procedure Qualifications By others [¶328.2.2], and
b. Performance Qualification By Others [¶328.2.3]
Although these exemptions exist, the employer is not exempt from responsibility for
welds prepared according to procedures or personnel qualified by others. Close
examination of the conditions attached to these exemptions will enhance understanding
as to why the employer is responsible for all welding.
Regarding exemption of an employer from weld procedure qualifications through use of
welding procedures qualified by others, interpretation of B31.3 restrictions shows that
the exemption is limited to low risk situations. For the exemption to apply, the Code has
the following requirements:
a. The inspector must be satisfied [¶328.2.2(a)]:
1.
2.
With the capability of the organization providing the procedure [¶328.2.2(a)(1)];
and
That the employer intending to use the procedure has not made any changes
to it.
b. Base metals are restricted to P-No. 1, P-No. 3, P-No. 4 Gr. 1 (13%Cr max.), or PNo. 8 [¶328.2.2(b)].
c. Impact tests are not required [¶328.2.2(b)].
d. Base metals to be joined are of same P-No., except P-No. 1, P-No. 3, and P-No. 4
Gr. 1 may be welded to each other as permitted by ASME Section [X[¶328.2.2( c)].
e. Base metal thickness does not exceed ¾ in. (19 mm) [¶328.2.2( d)].
f. PWHT is not required [¶328.2.2( d)]
g. Design pressure does not exceed ASME/ANSI B16.5 Class 300 at design
temperature [¶328.2.2( e)].
h. Design temperature is in the range -20ºF through 750ºF (-29ºC through 399ºC),
inclusive [¶328.2.2( e)]
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i. Welding processes are restricted to SMAW or GTAW or combination thereof
[¶328.2.2( f)].
j. Welding electrodes are restricted to those listed in ¶328.2.2( g).
k. Employer accepts responsibility for both the WPS and PQR by a signature
[¶328.2.2( h)].
l. Employer has at least one welder/welding operator who, while in his employ, has
passed a performance qualification test using the procedure and the P-No. of
material specified in the WPS. Qualification must have been with a bend test per
ASME Section IX Para QW-302. Qualification by radiography alone is not
acceptable [¶328.2.2(i)].
Always consult the latest revision of the Code for any changes to the exemption
restrictions, which may occur from time to time.
Regarding exemption of an employer from performance qualification testing, a
performance qualification made another employer may be accepted, subject to the
following restrictions [¶328.2.3]:
a. The inspector must specifically approve the exemption.
b. The qualification is limited to piping using the same or equivalent procedure with
essential variables within the limits of ASME Section IX.
c. The employer must obtain a copy of the performance qualification test record from
the previous employer, which contains information prescribed by ¶328.2.3. This
requirement seriously restricts the portability of welding qualifications. For example,
why would an employer release such records to a competitor, unless the competitor
is part of the same corporate group?
The restriction has been overcome in some North American locations through
qualification tests administered by the jurisdiction having authority over the work (e.g.,
state or province). In other locations, especially developing countries where massive
projects are undertaken, the portability restriction has been overcome by general
acceptance of qualification cards issued by some large local industrial organization.
Typically, the qualifying organization issues each welder a laminated ID card containing
the welder’s photograph and other qualification information.
Of course, welder performance qualification cards are valuable. Laminated
photographic ID is essential and must be carefully controlled. For example, without
laminated photographic ID it would be quite possible to have one qualified welder
showing up at different test centers, passing qualification tests for all of his friends.
Alternatively, it would be possible for unqualified welders to be substituted on the work
by forgery of qualification cards without photographic ID.
Welding Qualification [¶328.2]
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Although the qualification exemptions discussed above may be used, normally the
employer is required to conduct welding qualifications. B31.3 controls the details of
welding qualifications by referencing:
a. ASME Section IX[¶328.2.1(a)],
b. Supplementary technical requirements [¶328.2.1(b) through 328.2.1( f)], and
c. Requirements for qualification records [¶328.2.4].
By external reference to ASME Section IX, the B31.3 Code takes advantage of a
general working document governing welding qualifications for the entire ASME Code.
Topics in the following paragraphs, which address welding variables listed in ASME
Section IX, are indicated by the “QW” prefix to clause numbers.
Joints [¶QW-402]
The terminology used to describe weld joints can be confusing, with meaning often
dependent on the industry sector where work is carried out, as well as on applicable
codes and standards. Experience and intuition often form the basis for understanding
various terms. For example, the term “butt weld” is commonly used in pressure piping
applications to describe a butt joint with a groove weld, which is typically a full
penetration groove weld.
To properly communicate welding requirements it is important to make some basic
distinction relative to:
a. joint types,
b. weld types, and
c. joint geometry and end preparation.
Following from these basics, several supplementary details should also be considered,
including:
a.
b.
c.
d.
e.
degree of joint penetration full or partial,
weld profile – convex or concave,
alignment and fit-up details,
backing type, if used, including weld metal and backwelded joints, and
access for welding (i.e., single welded joints, double welded joints)
Joint Types
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There are five basic types of joints, as described in Table 6-1. Note that the joint is the
interface between the members. This distinction is important, since it governs
interpretation of weld symbols and thickness of the joint (e.g., for preheat purposes).
Table 6.1 Five Basic Joint Types
Butt Joint
A joint between two members aligned
approximately in the same plane.
A joint between two members approximately at
right angles (90º) to each other
A joint between two members approximately at
right angles (90º) to each other, in the form of a T.
A joint between two overlapping members.
A joint between the edges of two or more parallel
or nearly parallel members.
Corner Joint
Tee joint
Lap joint
Edge joint
Types of Welds
There are three basic types of welds, as listed in Table 6.2
Table 6.2 Basic Weld Types
Groove Weld
A weld made in the groove between two members to be joined.
Fillet Weld
A weld of approximately triangular cross section, joining two
surfaces approximately at right angles to each other.
Plug or Slot
Weld
A weld made through a circular or elongated hole in one member
of a lap or T joint, joining that member to the surface of the other
member exposed through the hole.
End Preparation And Joint Geometry
End preparation [¶328.4.2] refers to the shape and dimensions of the base metal when
viewed as a cross section at the welding end, prior to fit-up and welding. Joint geometry
refers to the shape and dimensions of a joint when viewed in cross section after fit-up
and prior to welding.
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For pressure piping, joint geometry refers mainly to the type of groove to be used, of
which there are many. B31.3 provides some guidance concerning end preparations and
resultant joint geometry [¶328.4.2(a)(2) and Fig. 328.4.2].
For manually welded piping butt joints, the single-vee groove is most common. For thick
joints, however, compound vee grooves may be used to reduce welding costs,
distortion, and residual stress.
In other situations, decision regarding joint geometry involve consideration of several
issues, including Code requirements, selected welding process, size and type of filler
metal, welding position, access to the root of the joint, availability of suitable tools for
joint preparation, and economy.
Joint Penetration
Joint penetration refers to the minimum depth that a groove weld extends from its
face into the joint, exclusive of reinforcement (i.e., weld metal in excess of the quantity
required to fill the joint). With pressure piping, it is normal to aim for full (complete)
penetration welds where the weld metal completely fills the groove and is fused to the
base metal throughout the total thickness. Limits on incomplete penetration are listed in
B31.3 and discussed later in this book.
In some cases, the engineering design may require partial penetration joints. The extent
of penetration may be described in terms of the effective throat, although specification
of the maximum amount of incomplete penetration is more useful when nondestructive
examination methods are applied to verify joint quality.
As an example of a situation where partial penetration joints would be used, consider a
butt-welded cement mortar lined piping system. With this type of construction, a thin
gasket of suitable diameter (e.g., compressed asbestos or equivalent) is spot glued to
the cement surface of one member of a joint. The other member is then fit up tight
against the gasket and the joint is clamped. The root bead is then deposited, taking care
not to penetrate completely through the root face of the carrier pipe. If they are
penetrates the root face of the carrier pipe, the gasket may burn and loose its ability to
provide a seal, or concentrated heat from the arc may cause the cement to crack and
fall away from the pipe wall.
Backing
While one normally thinks of 200 and 300 series stainless steels in the classification of
austenitic materials, the group also includes may nonferrous alloys.
Imposes two special requirements for nonferrous and nonmetallic backing rings,
specifically:
1. that the designer approve their use, and
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2. that the welding procedure using them be qualified as required by ¶328.2.1(e).
in addition to the above Code restrictions on backing rings, designers normally prohibit
their use for:
a. corrosive services where the space between the ring and the pipe might be a
location for crevice or pitting attack.
b. Cyclic or vibrating services where notches associated with rings become sites for
development of fatigue cracks, and
c. Cryogenic or low temperature services where notches become sites for initiation of
brittle fracture.
Consumable Inserts [¶328.2.1(e), ¶328.3.3]
¶328.3.3] indicates that consumable inserts may be used provided:
a. they are of the same nominal composition as the filler metal,
b. they will not cause detrimental alloying of the weld metal, and
c. their suitability is demonstrated by weld procedure qualification [¶328.2.1(e)].
In general, the B31.3 position on consumable inserts is consistent with that of ASME
Section IX, which treats consumable inserts as a nonessential variable for the common
arc welding processes, which would use inserts (e.g., GTAW).
However, under strict interpretation, the ASME position on nonessential variables
means that a WPS could be amended without requalification, whether the insert were
added or deleted. Under B31.3 rules, addition or deleted. Under B31.3 rules, addition or
deletion of an insert would not be permitted without a supporting PQR (i.e.,
requalification)
Pre-heating :
B31.3 defines preheating as the application of heat to the base metal immediately
before or during a forming, welding, or cutting process [¶300.2]. This definition has a
slightly broader scope than the definition provided in ASME Section IX ¶QW – 492.
B31.3 also states that preheat is used, along with heat treatment to minimize the
detrimental effects of high temperature and severe thermal gradients inherent in welding
[¶330.1]. Although not specifically mentioned in B31.3, these detrimental effects can
include:
a. cold (hydrogen ) cracking,
b. hard, brittle heat affected zones,
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c. distortion, and/or
d. high residual stress.
Preheat can also be used to assist in the fusion (melting) of metals with high
conductivity such as copper and copper alloys, and thick sections of aluminum and
aluminum alloys. Preheat is sometimes used to assist in the alignment of parts, but
such practice is usually discouraged due to lack of control over the alignment activity
and the potential introduction of abnormally high stresses.
ASME Section IX defines preheat temperature as the minimum temperature in the weld
joint preparation immediately prior to welding; or in the case of multiple pass welds, the
minimum temperature in the section of the previously deposited weld metal,
immediately prior to welding [¶QW – 492].
Note that the ASME definition of preheat temperature as applied to multipass welds is
also known as minimum interpass temperature in other codes, standards, and
specifications. In this book, the term minimum interpass will be used when referring to
the minimum temperature of the deposited weld metal before starting the next pass of a
multipass weld since, from a technical perspective, it is not always necessary that the
temperature between passes meet or exceed the minimum preheat temperature at the
start of the first pass.
ASME Section IX defines interpass temperature as the highest temperature in the weld
joint immediately prior to welding, or in the case of multipass welds, the highest
temperature in the section of the previously deposited weld metal, immediately before
the next pass is deposited [¶QW – 492]. Again, strictly speaking, the interpass
temperature as defined by ASME is the maximum interpass temperature. In practice, it
is measured near the start of the next pass.
Most requirements for preheat and minimum interpass temperature control are aimed at
prevention of cold cracking in transformation hardenable materials such as carbon
steels, low alloy steels, intermediate alloy steels, and martensitic stainless steels. For
cold cracks to form, the four conditions listed in the left column of Table 6-7 must be
satisfied simultaneously.
The magnitude of any one of the four conditions cannot be defined with accuracy and
depends largely on the other three conditions. The beneficial effect of preheat on each
of these conditions is shown in the right column of Table 6.7.
Table 6.7 Influence of Preheat and Minimum Interpass Temperature on Conditions
Required for Cold Cracking
Conditions Necessary for Cold Benefits of Preheat and Minimum
Cracking
Interpass Temperature Control
Presence of hydrogen in sufficient Diffuses hydrogen away from the joint,
125
quantity.
Sufficient tensile stress, which may be
applied, residual, or a combination of
both.
A susceptible microstructure, which is
normally interpreted to mean a hard
microstructure, hence the frequent use
of hardness tests to assess the risk of
cold cracking.
A temperature threshold below some
critical
level
(e.g.,300ºF),
which
depends somewhat on alloy content
and metal structure.
reducing the risk of cracking.
Alters stress distribution during welding
and offers a small reduction of residual
stress upon completion of welding.
Reduces
probability
of
forming
susceptible microstructure by slowing
the cooling rate.
Keeps the weldment above threshold
temperature for cracking until the weld
is completed.
Another term used by ASME Section IX is preheat maintenance. Although not
specifically defined by the code, examination of ¶QW – 406.2 shows that the term
applies to the maintenance or reduction of preheat upon completion of welding, prior to
any required postweld heat treatment. The primary reason for preheats maintenance
after completion of welding is to continue diffusion of hydrogen from the weldment. It
may also be used for reduction of thermal gradients and resulting residual stresses or
distortions, and/or for isothermal transformation. When preheat maintenance is
specified for a welding procedure, it should include both temperature and time. Simply
indicating “yes” on the weld procedure specification is meaningless.
For most Code users, the following questions regarding preheat and interpass control
must be answered:
a. What preheat and minimum interpass temperatures should be used for the
application?
b. How should the heat be applied?
c. How, where, and when should the temperature be measured?
Detailed technical answers to the above questions can be very complex. Since most
piping applications involve some legal requirement (contractual and/or jurisdictional),
the obvious starting point for answers is to examine the minimum requirements of B31.3
and ASME Section IX.
Preheating for all types of piping welds is covered in B31.3 under ¶330. The second
sentence of ¶330.1 states: “ The necessity for preheating and the temperature to be
used shall be specified in the engineering design and demonstrated by procedure
qualification”. If such requirements are not included in the engineering design, then the
minimum Code requirements are generally assumed.
In addition to information contained in B31.3 Table 330.1.1, there are numerous other
methods of evaluating or verifying requirements for preheat and interpass temperature
control. Some techniques, with associated comments, are described below:
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a. Nomographs are a favorite tool of technical specialists for estimating preheat
requirements. One common method used for carbon and carbon-manganese steels
was published by the British Welding Institute in a book entitled Welding Steels
without Hydrogen Cracking by F.R. Coe. The technique has a sound scientific basis
in that it accounts for base metal thickness, arc energy input, carbon equivalent, and
hydrogen potential of the welding process. The publication also describes
techniques for dealing with alloy steels.
b. For the less technically inclined, the use of “look-up” tables is very common. These
may be in very simple or very complex form. For ASME code users, the appendix of
a book entitled Weldability of Steels by R.D. Stout and W.D.Doty can be a very
useful source of preheat information. This appendix is based on WRC Bulletin 191
first published in January 1974 and republished in March 1978. Although the
information may appear to be a bit dated (depending upon the current state of your
career), it nevertheless addresses the complex issues of base metal thickness,
carbon content and general chemistry (e, g., hardness and hardenability), and
hydrogen potential.
c. Other sections of the ASME code are often consulted for preheat information
including ASME Section VIII, Division 1, Appendix R; ASME Section VIII, Division 2,
Appendix D; and ASME Section I, A – 100.
d. Several types of preheat calculators have been developed over the years. One
common calculator is available from the Lincoln Electric Company. It incorporates
the influence of hydrogen, carbon equivalent and thickness on preheat selection.
e. Complex preheat calculation techniques have been published, which relate cooling
rates calculated by various formulae (e.g., solutions to Rosethal’s equations for heat
flow from a moving heat source) to time-temperature transformation (TTT or
equivalent) diagrams. However, these techniques find little application within the
pressure piping industry, due to the complexity of calculations, the need to select
values for “constants” which are not constant over the temperature ranges involved
in welding, and the lack of complete time-temperature transformation data for the
materials involved. Of course, as computers continue to change our world, one may
find increasing application of these more fundamental methods.
B31.3 does not restrict the methods of preheat, but some owner specifications do.
Some methods of preheating include:
a. Oxyfuel gas fired torch (propane, butane, and sometimes acetylene),
b. Electric resistance elements,
c. Induction coils, and
127
d. Exothermic kits.
From a practical welding perspective, the method of heating is not generally an issue as
long as the correct preheat temperature is achieved, with the heat uniformly applied
throughout the full thickness and circumference of the joint. In some cases, the use of
oxyacetylene torches is prohibited by owner specifications due to the intensity of the
heat source and the risk of local damage to the base metal or weld metal if the heat is
concentrated at one location.
B31.3 requires that the preheat temperature be checked to ensure that the temperature
specified by the WPS is obtained prior to and during welding [¶330.1.3(a)]. However,
B31.3 does not prescribe:
a. The exact methods by which temperature must be measured,
b. The location of temperature measurements, or
c. The timing of temperature measurements.
temperature measurements:
a. Temperature indicating crayons, thermocouple pyrometers, or other suitable means
shall be used to measure temperature, [¶330.1.3(a)]
b. Thermocouples may be attached by capacitor discharge welding without the need
for welding procedure and performance qualifications, subject to visual examination
of the area after thermocouple removal, [¶330.1.3(b)] and
c. The preheat zone shall extend at least 1 inch beyond each edge of the weld. ( Note
that many owner specifications require at least 2 inches and some as much as 6
inches) [¶330.1.4].
Although the Code definitions of preheat and interpass temperature refer to the
deposited weld metal, temperature measurement directly on hot weld metal can result in
contamination and is generally discouraged. Common industry practice is to measure
preheat and interpass temperature in a manner which insures that the correct preheat
has been reached from the edge of the welding groove to the outer limits of the
specified preheat zone width.
Preheat temperature, by definition, is measured immediately before the start of welding;
however, interpass temperature measurement can be the subject of some debate.
When interpass temperature control is required by a WPS, the interpass temperature
128
is normally measured immediately before the start of the next pass, at the location
where the next pass will be started.
Purists may argue that by only measuring the temperature at the starting point of the
next pass, it is possible for the next pass to be placed over weld metal thatis not exactly
within the interpass range. It’s true, of course, but practically speaking, interpass
temperature measurement for process piping is hardly an exacting science.
Gas for Shielding, Backing, and Purging [¶QW – 408]
Protection of hot and molten metal from the atmosphere is a necessary part of most
welding operations. Protection may be accomplished using:
a. externally supplied shielding, backing, and purging gases, and/or
b. fluxes which decompose to give a slag covering and/or a gaseous shield.
Externally supplied protective gases prevent atmospheric contamination of the hot
molten metal by displacing air from the weld area. In general, protective gases may be:
a. Inert gases like helium or argon, which do not react with the hot metal,
b. Reactive gases such as carbon dioxide, nitrogen, or hydrogen, which do react in a
limited way with the hot metal and may be oxidizing or reducing depending upon the
specific gas/metal interaction, or
c. Mixture of inert and/or reactive gases (e.g., 75Ar/25CO 2 ).
For many welding applications, shielding gases are actually mixturers of gases, with the
composition of the mixture optimized to provide the best combination of shielding
characteristics and process operating characteristics. Selection of a gas depends on
several somewhat interrelated factors including:
a. cost and availability at required purity levels,
b. Ease of handling, stability, and physiological effects,
c. Metallurgical characteristics including solubility in metals being welded, reactions
with metals being welded and resultant degree of protection afforded to hot metal,
effects on wetting behavior, effects on penetration as it affects type and thickness of
metals to be welded, and effects on end properties of the weld deposit, and
d. Welding process characteristics including welding position, ease of arc ignition as
influenced by ionization potential of the gas, arc stability, and penetration as affected
by thermal conductivity of the gas.
129
Solubility is a particularly important issue in gas selection, since dissolved gas in the
molten metal can lead to porosity on freezing. Insert gases such as helium and argon
have very limited solubility in most metals and are therefore used extensively for gas
shielded arc welding processes.
Although carbon dioxide is virtually insoluble in most metals, it is reactive and will cause
some surface oxidation and some loss of oxidizable elements. Nevertheless, carbon
dioxide is used extensively for GMAW and FCAW of carbon and low alloy steels.
In some cases, limited amounts of certain gases are included in the shielding gas
mixture to accomplish objectives other than shielding. Three examples are listed below:
a.
Nitrogen has been added to stainless steel shielding gases as an alloy addition,
which imparts improved corrosion resistance and strength, and as a technique of
controlling phase balance in duplex stainless steel weld metal.
b.
Oxygen may be added to argon in amounts typically from 1 to 5%, to improve
wetting of stainless steel deposits, to improve bead shape, and to reduce
undercutting.
c.
Hydrogen has been added to shielding gases to increase penetration
characteristics, through increased arc voltage and consequent increased heat input.
As a word of caution, minor additions of reactive gases should not be attempted without
thorough understanding of the consequences, and procedure qualification to evaluate
the effect of such additions.
Cleaning [¶328.4.1]
[¶328.4.1] does provide some motherhood statements about cleaning, but a welding
procedure should be specified about cleaning methods, solutions, abrasives, and tools.
This is particularly true for nonferrous metals and stainless steels, since inappropriate
cleaning methods can lead to cracking (prior to or in service) and/or loss of corrosion
resistance.
¶328.5.1(d) prohibits peening on the root pass and final pass of a weld. Peening work
hardens the metal, reduces ductility, and therefore increases the risk of cracking during
or after welding. Peening between passes can be permitted because heat of
subsequent weld passes heat treats (softens) the peened weld metal of previous
passes. Note that chipping necessary for slag removal is not considered to be peening.
¶328.5.1(e) is intended to prohibit welding under adverse weather conditions. Moisture
can cause porosity and hydrogen cold cracks. Excessive wind blows shielding away
causing porosity and brittle welds, for both gas shielded and coated electrodes. Another
130
practical issue with excessive wind under dry or arid conditions is the swirling of dirt,
within the welder’s helmet, making it difficult to see the weld pool. If you cann’t see what
you’re doing, you can’t weld.
¶328.5.1(f) provides some general advice on preserving the seat tightness of weld end
valves. The valve manufacturer should always be consulted concerning welding
conditions appropriate to maintaining seat tightness and responsibility for dismantling,
reassembly, and testing when necessary.
Some issues to consider include characteristics of sealing materials and risk of heat
damage (e.g., plastic or metal-to-metal seat elements), use of extended bodies for soft
seated valves, or use of a water quench to cool have materials which do not
transformation harden(e.g., austenitic stainless steels).
¶328.5.3 indicates that seal welds must be done by a qualified welder. While this
requirement may seem obvious, significant commercial gains can be made through the
use of unqualified welders. The need for seal welds to cover all threads is imposed to
avoid notch effects, which could cause brittle fracture or fatigue cracks. For the record,
a seal weld is not a back weld.
Mechanical Testing
Mechanical testing requirements for welding procedures are found in ASME Section IX.
However, if the base metal will not withstand the 180 degree guided bend test required
by ASME Section IX, B31.3 permits qualification if the weld bend specimen will undergo
the same degree of bending as the base metal (within 5 degree) [¶328.2.1(b)].
As well, when impact testing is required by the Code or engineering design, B31.3
indicates that those requirements shall also be met in qualifying weld procedures
[¶328.2.1(d)].
Heat Treatment [¶331]
Heat treatment is used to minimize certain detrimental effects associated with welding,
bending and forming processes [¶331].
Depending on the nature of each process, attendant high temperatures, severe thermal
gradients, and/or severe metal forming operations (cold work) can result in dramatic
loss of toughness, reduction of ductility, increased hardness, and/or high residual
stresses. In turn, these can lead to premature, unexpected, and potentially catastrophic
failures caused by brittle fracture, fatigue cracking, stress corrosion cracking, and/or
hydrogen embrittlement.
131
B31.3 provides basic heat treatment practices suitable for most welding, bending, and
forming operations, but warns that they are not necessarily appropriate for all service
conditions [¶331].
Common examples where compliance with minimum B31.3 heat treatment
requirements could be considered inappropriate include process streams containing
caustics, amines used for gas sweetening operations, and hydrogen sulfide. In the case
of process streams containing hydrogen sulfide, it is known that the minimum
temperature allowed by Table 331.1.1 may not cause sufficient softening for resistance
to sulfide stress cracking in severe sour environments.
This accounts for the careful wording in clause 5.3.1.3 of NACE Standard MRO175-95,
which states: “Low-alloy steel and martensitic stainless steel weldments shall be stress
relieved at a minimum temperature of 620ºC (1150ºF) to produce a maximum hardness
of 22 HRC maximum.” Typically, temperatures required to satisfy the 22 HRC maximum
criterion for low alloy steels are well above 620ºC (1150ºF). given the toxic nature of
sour environments, before construction one should confirm that proposed heat
treatment cycles are capable of satisfying maximum hardness restrictions.
Confirmation would typically involve cross-sectional hardness surveys of the welding
procedure qualification test coupons.
Forms of Heat Treatment
There are many forms of heat treatment, each intended to accomplish a certain task.
Frequently, more that one task is accomplished by a particular thermal cycle. Heat
treatments listed in B31.3 table 331.1.1 are best described as stress relieving heat
treatments, since the primary purpose of the treatment is the reduction of residual
stresses due to welding, forming, or bending operations.
Such treatment may also result in improved ductility, lower hardness (note that B31.3
does impose some hardness restrictions), better toughness, and reduced distortion
during subsequent machining operations.
B31.3 also allows the use of annealing, normalizing and tempering, in lieu of a required
heat treatment after welding, bending, or forming, provided that the mechanical
properties of any affected weld and base metal meet specification requirements after
such treatment and that the substitution is approved by the designer [¶331.2.1].
Stress relief of carbon and low alloy steel is carried out at a temperature slightly below
the lower critical temperature (A 1 ) of the steel, hence there is some use of the term
subcritical stress relief (i.e., there is no phase transformation at subcritical
temperatures).
For high alloy materials, such as austenitic stainless steels, considerably higher
temperatures are required for effective stress relief due to the inherent hot strength of
these materials. Although B31.3 does not mandate application of heat treatment to
132
austenitic stainless steels, when applied (e.g., for service reasons), it is usually carried
out at a temperature of approximately 1650ºF.
Annealing is a common term in the heat-treating business, but there are many types of
anneal. A full anneal is performed at high temperature (e.g., about 50 to 100ºF above
the upper critical temperature for carbon steels), followed by slow cooling, generally in a
furnace. It provides maximum softening, resulting in lowest hardness and strength.
A stress relief anneal is performed on carbon and alloy steels at a temperatures slightly
below the lower critical temperature, and many also be known as a subcritical stress
relief or subcritical anneal.
Both the stress relief anneal and full anneal are applied as softening treatments, but
other effects may result from the thermal cycles including changes to mechanical
properties, physical properties, and microstructure.
Although “full anneal” is generally implied when the word “anneal” is used without any
qualifier, if a “full anneal” is required, fewer surprises will occur if the term “full anneal” is
used.
Sometimes the term solution anneal is used to describe what might properly be called a
solution heat treatment. In this case, an alloy is heated to a temperature high enough to
dissolve one or more constituents into solid solutions, and then cooled rapidly enough to
hold the constituents in solid solution.
Solution heat treatments are generally applied to highly alloy steels and other high alloy
materials for the purpose of dissolving one or more constituents, which may affect the
properties of the material. For example, many of the austenitic stainless steel pipes
purchased according to ASTM A 312 are supplied in the solution treated condition.
Normalizing of carbon and low alloy steels is carried out by heating to a temperature
range similar to that used for a full anneal, but the parts are allowed to cool in still air.
This can save time and money compared to annealing, if the soft structure of the full
anneal is not required. Normalizing is also effective in refining the grain size and
homogenizing the structure, resulting in better toughness, more uniform mechanical
properties, and better ductility.
Tempering is a heat treatment, which may be applied to transformation hardenable
steels after a normalizing operation and is generally applied after a quenching
operation. Tempering is carried out below the lower critical temperature. It is used to
reduce hardness and improve toughness and ductility at the expense of reduced
strength.
Heat Treatment Requirements
133
¶331.1.1 imposes the following heat treatment requirements:
a.
Heat treatment shall be in accordance with the material groupings and thickness
ranges in Table 331.1.1 except as provided in ¶331.2.1 and ¶331.2.2.
b.
Heat treatment to be used after production welding shall be specified in the WPS
and shall be used in qualifying the welding procedure.
c.
The engineering design shall specify the examination and/or other production
quality controls (not less than the requirements of B31.3) to ensure that the final
welds are of adequate quality.
d.
Heat treatment for bending and forming shall be in accordance with ¶332.4.
Governing Thickness for Heat Treatment of Weld [¶331.1.3]
B31.3 contains a detailed treatment of metal thickness rules governing the need for heat
treatment, as well as exceptions to the rules [¶331.1.3]. Table 6.8 below may be used to
assist with interpretation of B31.3 requirements.
Table 6.8 Governing Thickness and Exemptions for Postweld Heat Treatment
(PWHT) of Welds
Weld Type
PWHT
Governing
Thickness
And
Exceptions
Butt Welds and welds not covered PWHT required when the thickness of the
elsewhere in this table
thicker component measured at the joint
exceeds the limits provided in Table
331.1.1. No exceptions.
Branch Connection Welds for set-on PWHT required when the thickness
or set-in designs, with or without through the weld in any plane is greater
reinforcement, as per Fig. 328.5.4 D
than twice the minimum material
thickness requiring heat treatment as
specified
in
Table
331.1.1.
No
exceptions. See B31.3 for assistance
134
Fillet Welds for slip-on, socket, and
seal welded connections NPS 2 and
smaller; and for external nonpressue
parts such as lugs and pipe supports
in all pipe sizes
with weld thickness calculations
PWHT required when the thickness
through the weld in any plane is more
than twice the minimum material
thickness requiring heat treatment as
specified in Table 331.1.1. There are
three exceptions to this rule:
1. Heat treatment is not required for PNo. 1 materials with weld throats 7 5/8
in. (716 mm), regardless of base
metal thickness.
2. Heat treatment is not required for PNo. 3,4,5 or 10A materials with weld
throats 7 ½ in. (713 mm), regardless
of base metal thickness, provided that
preheat applied during welding was
not less than the recommended
preheat (see Table 330.1.1 and the
WPS), and that base metal SMTS is
less than 71 ksi (490 Mpa).
3. Heat treatment is not required for
ferritic materials when welds are
made with filler metal which does not
air harden. (see Note 1.)
(1) Note that this can be a dangerous exception for some services and should be
used with caution. Just because the filler metals do not harden, doesn’t mean the
heat-affected zones of the base metals have not hardened. Furthermore, just
because the deposited filler metal may be in a soft and ductile condition, doesn’t
mean the base metal heat affected zones are in the same condition.
Equipment and Methods of Heat Treatment
B31.3 does not impose limitations on heating equipment and methods. It only indicates
that the heating method must provide the required metal temperature, metal
temperature uniformity, and temperature control, and then lists methods which may be
used for heating including furnace, local flame heating, electric resistance, electric
induction, and exothermic chemical reaction [ ¶331.1.4].
Heating methods used for heat treatment may be classified in terms of the facility used
for heat-treating and the energy source. Facilities can be discussed in terms of local
heat treatment and furnace heat treatment.
a. Local heat treatment involves the heating of a small band of metal. Normally the
band being heat-treated is stationary, but in some manufacturing operations, the
band moves. Examples of moving bands include in-line-tempering operations used
135
during manufacture of quenched and tempered pipe and local heating operations
used in the manufacture of induction bends.
b. Furnace heat treatment generally involves placing the item to be heat treated inside
a permanent furnace operated by a fabrication shop or commercial heat treater.
However, it is possible to construct temporary heat treatment facilities (e.g., at the
job site), which may range from simple ad hoc insulated box constructions to
complex portable furnaces.
There are several energy sources used in heat-treating. Current commercial sources of
heat energy and characteristics are discussed below:
a. Electric resistance heat is produced when an electric current is passed through
wires made from a material with high electrical resistivity. The electric current
increase atomic movement in the wire, and this energy is then released in the form
of heat. There is a wide selection of heating elements available in the marketplace,
with various sizes and shapes to fit practically any geometry. Heaters are flexible
and durable and are commonly used for local heat treatment of welds during field
construction. Although resistance elements may burn out or short circuit against the
pipe, there are several advantages supporting use of electric resistance heat,
especially for local heat treatment of welds.
a. Heat can be continuously and evenly applied.
b. Temperature can be adjusted accurately and quickly.
c. Welders can work in relative comfort. For preheating applications, they do not
have to stop intermittently to raise preheat temperature.
d. Heat input can be adjusted fairly easily for example, to control the amount of
heat applied to different pipe quadrants or sections of dissimilar thickness such
as weld-in valves.
b. Heat can be produced by chemical reaction using exothermic kits. The chemical
composition of constituents in modern exothermic heat kits is proprietary, however.
When materials in the kit are reacted, heat is released. Heating cycles are
controlled in terms of the size, shape, and heating value of the exothermic charge;
the size, shape, and mass of the component to be heat treated; and the local
environmental conditions. Although exothermic kits offer the advantages of
portability, low capital equipment cost, and simple operator training, they have two
major limitations:
1.
2.
Once the kit has been ignited, it is difficult to perform any further adjustments.
It is usually difficult or impossible to satisfy Code and owner requirements on
heating rate, holding time, and cooling rate.
For these reasons, use of exothermic kits is restricted by many owner specifications,
except perhaps for infrequent use at remote locations such as drilling sites. Successful
application of exothermic kits requires careful planning and contingency measures.
136
c.
Radiant heaters use infrared radiation generated by a gas flame or quartz lamp to
develop heat. Infrared radiation is a form of electromagnetic radiation, which
behaves similarly to light. The intensity of the radiation falls off in proportion to the
square of the distance between the heat emitter and the part heated. Radiation
reaching the part is either absorbed, causing the temperature of the part to
increase, or reflected (wasted). Consequently, surface condition of the metal will
affect the efficiency of the process, as will the relative positions of the heater and
the part, since the heater must “see” the part for effective heating.
d. Induction coils create heat with the passage of alternating current (ac). The
alternating magnetic field associated with the alternating electrical field penetrates
the metal to be heated, changes strength and direction in phase with the external
alternating electric current, and produces eddy currents in the part to be heattreated. The rise and collapse of magnetic fields and their associated eddy currents
stimulate atomic movement resulting in the release of heat within the part.
Temperature Measurement
B31.3 does not impose restrictions on the devices used for temperature verification
[¶331.1.6]. Although devices such as temperature indicating crayons, thermometers,
and optical pyrometers may be used, thermocouple pyrometers are generally used to
measure and record the temperature of the surfaces being heat-treated. For proper
temperature measurement, the hot end of the thermocouple junction must be in direct
contact with the surface of the pipe or kept at the same temperature as the pipe by
being inserted into a terminal joined to the pipe.
B31.3 does not impose any restrictions on the thermocouple attachment methods. To
this end, one may observe on various job sites, attachment of thermocouples using
steel bands, wire, ad hoc clamping devices, or weld metal. The suitability of any of
these thermocouple attachment methods should be addresses by specifications
developed during the engineering design or by QA/QC personnel monitoring the work.
For example, steel bands or wires can become loose at the heat treatment temperature
so that the thermocouple is no longer in contact with the surface, leading to false
temperature readings. Ad hoc clamping devices can work loose, and the attachment
method of such devices can cause local damage to the pieces being heat-treated. Use
of weld metal to fix the thermocouple to the pipe surface changes the composition of the
junction, resulting in measurement error. Experience with attachment of thermocouples
by capacitor discharge welding indicates that the process works well. B31.3 has specific
statements permitting the attachment of thermocouples to pipe using capacitor
discharge welding without the need for weld procedure and performance qualifications
[¶331.1.6, ¶330.1.3(b)]
B31.3 does not address the number of thermocouples required or the placement of
thermocouples. Although these issues should be dealt with in construction
specifications, perhaps discussion of a few sources of measurement error would be
useful in making such determinations.
137
a. Heat rises. With local heat treatment, the temperature measured on the top of a pipe
will normally be higher than the temperature measured on the bottom of the pipe.
Typically, as diameter increases, steps are necessary to allow introduction of more
heat at the bottom and sides of the pipe than at the top of the pipe. The need for
additional temperature measurement points and heating controls does have
commercial implications.
b. The pipe will be hottest adjacent to the source of the heat. During local heat
treatment, the pipe is normally heated from the outside, so the inside surface will be
a bit cooler than the outside surface, depending upon the thickness of the pipe and
the extent to which insulation is used and drafts prevented. For example, if the bore
of the pipe is not plugged with insulation and the wind is whistling through it, a
substantial difference between the inside and outside surface temperatures might be
expected. Since heat treatments are often conducted for service reasons, and the
service is usually on the inside of the pipe, specific attention is required to ensure
that the inside surface is adequately heated (and that the outside surface is not
excessively heated).
c. The surface temperature of a resistance coil or other radiant heat source is
considerably above that of the pipe being heated. If the hot junction of the
thermocouple is not insulated form the heat source, the temperature reading will be
higher than the actual temperature at the pipe surface.
d. Thermocouple wires should run along the pipe surface under the insulation for
several inches before coming outside the insulation on the pipe surface. If the wires
are brought straight out of the insulation from the point of contact with the pipe, heat
may be conducted away from the hot junction leading to a temperature reading
lower than the pipe surface.
e. Measurement errors may be introduced if extension wires are not of the same
composition as the thermocouple wires, all the way from the hot junction to the cold
junction. Don’t accidentally reverse the wires at a connection point.
f. Ensure that instrumentation is properly calibrated. Battery operated circuits should
be calibrated at regular intervals and the output of regulated power supplies should
be checked occasionally for accuracy.
g. Damaged or contaminated thermocouples and extensions can lead to measurement
error and should be checked regularly for physical damage (severe bends, kinks,
partially broken wires, weld spatter or slag trapped between the wires).
Heating and Cooling Rates [¶331.1.4]
B31.3 does not impose restrictions on heating and cooling rates [¶331.1.4]. ASME
Section VIII, Division 1, UCS-56 requirements are frequently applied, but there are
causes where insulation and coils are ripped off immediately after the soak period. In
the stress relieving business, time is money, especially if the heat treater is working by
the weld or lump sum. So, if heating and cooling rates need to be controlled, it should
be stated in specifications or other contract documents.
Hardness Tests[¶331.1.4]
B31.3 makes the following statements regarding hardness testing.
138
Hardness tests of production welds and of hot bent and hot-formed piping are intended
to verify satisfactory heat treatment. Hardness limits apply to the weld and to the heat
affected zone (HAZ) tested as close as practicable to the edge of the weld.
a. Where a hardness limit is specified in Table 331.1.1, at least 10% of welds, hot
bends, and hot formed components in each furnace heat treated batch and 100% of
those locally heat treated shall be tested.
b. When dissimilar metals are joined by welding, the hardness limits specified for the
base and welding materials in Table 331.1.1 shall be met for each material.
The Code does not discuss many of the technical details necessary to give an accurate
and representative appraisal of production weld hardness. Consequently, owner
specifications are recommended for guidance on applying this simple but often misused
and abused test method. Owner specifications should consider the size of hardness
indentations relative to the size of weld zones to be measured, surface preparation of
the weld, methods for locating the zones of interest, and training requirements for
hardness testing personnel.
********
139
ASME B 16.5
PIPE FLANGES AND FLANGED FITTINGS
1.
SCOPE :
General :
This Standard covers
a.
Pressure temperature ratings, materials, dimensions, tolerances,
marking, testing.
b.
for pipe flanges and flanged fittings in sizes NPS ½ through NPS 24
and in rating Classes 150, 300, 400, 600, 900, 1500 and 2500,
c.
Flanges and flanged fittings may be cast, forged, or ( for blind flanges
and certain reducing flanges only ) plate materials,
d.
Requirements and recommendations regarding bolting and gaskets
are also included.
Codes and Regulations :
A flange or flanged fitting used under the jurisdiction of other codes is subject to
any limitation of that code or regulation.
This includes any maximum
temperature limitation, or rule governing the use of a material at low temperature,
or provisions for operation at a pressure exceeding the pressure temperature
ratings in this Standard.
140
2.
PRESSURE-TEMPERATURE RATINGS
Rating Basis
Ratings are maximum allowable working gage pressures at the temperatures
shown in Tables for the applicable material and rating.
For intermediate
temperatures, linear interpolation is permitted.
Rating Temperature
The temperature shown for a corresponding pressure rating is the temperature of
the pressure containing shell of the flange or flanged fitting. In general, this
temperature is the same as that of the contained fluid subject to the requirements
of the applicable code or regulation. For any temperature below –20 oF, the rating
shall be no greater than the rating shown for –20 oF.
Temperature Considerations
Flange Attachment
Socket welding and threaded flanges are not recommended for service above
500oF or below –50oF if severe thermal gradients or thermal cycling are involved.
High Temperature Service
At temperatures in the creep range, gradual relaxation of flanges, bolts, and
gaskets may progressively reduce bolt loads. It may be necessary to arrange for
periodic tightening of bolts to prevent leakage.
Joints subject to substantial
thermal gradients may require the same attention.
141
When used above 400oF, Class 150 flanged joints may develop leakage unless
care is taken to avoid imposing severe external loads and/or severe thermal
gradients. For other classes, similar consideration should be above 750 oF.
Low Temperature Service
Some of the material listed in the rating tables undergo sufficient decrease in
toughness at low temperatures that they cannot safely sustain shock loadings,
sudden changes of stress or temperature, or high stress concentrations.
System Hydrostatic Test
Flanged joints and flanged fittings may be subjected to system hydrostatic tests
at a pressure not to exceed 1.5 times the 100 oF rating rounded off to the next
higher 25 psi.
3.
SIZE
The size of a flange or flanged fitting covered by this Standard is its nominal pipe
size, NPS. Use of “nominal” indicates that the stated size or dimension is only
for designation, not measurement. The actual dimension may or may not be the
nominal size.
4.
MARKING
Name
The manufacturer’s name or trademark shall be applied.
142
Material
a.
Cast flanges and flanged fittings shall be marked with ASTM specification,
grade identification symbol, and the melt number or melt identification.
b.
Plate flanges, forged flanges, and flanges fittings shall be marked with
ASTM specification number and grade identification symbol.
c.
A manufacturer may supplement these mandatory material indications
with his trade designation for the material grade, but confusion of symbols
shall be avoided.
Rating Class
The marking shall be the applicable pressure rating class : 150, 300, 400, 600,
900, 1500 or 2500.
Designation
The designation B16 shall be applied preferably located adjacent to the class
designation, to indicate conformance to this Standard.
Size
The nominal pipe size shall be given.
5.
MATERIALS
General
Flanges and flanged fittings covered by this Standard shall be castings, forgings
and (for blind flanges only) plate.
143
Toughness
Some of the materials listed in Table 1A undergo a decrease in toughness when
used at low temperatures, to the extent that Codes referencing this Standard
may require impact tests for application even at temperatures higher than +20 oF.
It is the responsibility of the user to assure that such testing is performed.
Gaskets
The user is responsible for selection of gasket materials which will withstand the
expected bolt loading without injurious crushing, and which are suitable for the
service conditions.
6.
DIMENSIONS
Wall thickness
For inspection purposes the minimum wall thickness t m of flanged fittings at the
time of manufacture shall be as shown in Tables 10, 13, 16, 19, 22, 25 and 28,
except as provided in para 6.1.1. See Annex D for the basis used to establish
values of tm.
Additional metal thickness needed to withstand assembly stresses, shapes other
than circular, and stress concentrations must be determined by the manufacturer,
since these factors vary widely.
In particular, 45 deg. Laterals, true Y’s and
crosses may require additional reinforcement to compensate for inherent
weaknesses in these shapes.
Local areas having less than minimum wall thickness will be acceptable provided
that :
144
a.
the area of subminimum thickness can be enclosed by a circle whose
diameter is no greater than 0.35 √dtm where d is the inside diameter as
defined above and tm is the minimum wall thickness as shown in the
tables listed in para 6.1; and
b.
measured thickness is not less than 0.75 tm; and
c.
enclosure circles are separated from each other by an edge-to-edge
distance of more than 1.75
____
√ dtm.
Facings
Table 4 gives dimensions for facings other than ring joint.
Table 5 gives
dimensions for ring joint facings. Figure 7 shows application of facings. Classes
150 and 300 fittings and companion flanges are regularly furnished with a 0.06
in. raised face which is included in the minimum flange thickness C. Classes
400, 600, 900, 1500 and 2500 fittings and companion flanges are regularly
furnished with 0.25 in. raised face which is additional to the minimum flange
thickness C. Any other facing than the above, when required for any class, shall
be furnished as follows.
No metal shall be cut from the minimum flange thickness specified herein.
In the case of the 0.25 in. raised face, tongue or male face (other than 0.06 in.
raised face for Classes 150 and 300), the minimum flange thickness C shall be
first provided and then the raised face, tongue or male face shall be added
thereto.
With ring joint, groove, or female face, the minimum flange thickness shall be first
provided and then sufficient metal added thereto so that the bottom of the ring
joint groove, or the contact face of the groove or female face is in the same place
as the flange edge of a full thickness flange.
Flange Facing Finish
145
The finish of contact faces of pipe flanges and connecting end flanges of fittings
shall be judged by visual comparison with Ra standards ( see ASME B46.1 ) and
not by instruments having stylus tracers and electronic amplification.
The
finishes required are given below.
Flange facings
Either a serrated concentric or serrated spiral finish having a resultant surface
finish from 125 uin. To 250 uin. Average roughness shall be furnished. The
cutting tool employed should have an approximate 0.06 in. or larger radius, and
there should be from 45 grooves/in. through 55 grooves/in.
Flange Facing Finish Imperfections
Imperfections in the flange facing finish shall not exceed the dimensions shown
in Table 3. Adjacent imperfections shall be separated by a distance of at least
four times the maximum radial projection. A radial projection shall be measured
by the difference between an outer radius and an inner radius encompassing the
imperfection where the radii are struck from the centerline of the bore.
Imperfections less than half the depth of the serrations shall not be considered
cause for rejection. Protrusions above the serrations are not permitted.
Spot Facing
All cast and forged flanges and flanged fittings shall have bearing surfaces for
bolting which shall be parallel to the flange face from within 1 deg. Any back
facing or spot facing required to accomplish parallelism shall not reduce the
flange thickness C below the dimensions given in Tables 9, 10, 12, 13, 15, 16,
18, 19, 21, 22, 24, 25, 27, and 28. Any spot facing or back facing shall be in
accordance with MSS SP-9.
146
7.
TEST
Flanged Fitting Training
Each flanged fitting shall be given a hydrostatic shell test as specified below :
Flange Testing
Flanges are not required to be hydrostatically tested.
Hydrostatic Shell Test
The hydrostatic shell test for flanged fittings shall be no less than 1.5 times the
100oF rating rounded off to the next higher 25 psi increment.
The test duration shall be minimum of one min for fittings NPS 2 and smaller, 2
min for fitting NPS 2 ½ -NPS 8, and 3 min for fittings NPS 10 and larger.
No visible leakage is permitted through the pressure boundary wall.
LIMITING DIMENSIONS OF GASKETS
GASKET DIMENSIONS
The actual dimensions of a gasket must be established by the user. Reference to a
dimensional standard for gaskets, such as ASME B16.21, is recommended.
147
Limiting gasket dimensions are given in Tables E1, E2, and E3. These dimensions
represent approximately the maximum combinations of widths and diameters of the
different types of gaskets covered which meet rating requirements.
Gaskets are divided into three groups based on their gasket loading factors as shown in
the ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, Pressure Vessels.
Gasket contact widths for the three groups are as follows :
Group No. I
Slip-on flange raised face width
Group No. II
Large tongue width
Group No. III
Small tongue width minus 0.03 in., but not less than 0.18 in.
Gaskets of Group No. Ia have inside diameters equal to the outside diameter of the
corresponding pipe, which follows the principle established in ASME B16.21. In order to
avoid pocketing of fluid handled, Group No. I gaskets may be extended to the inside
diameter of valves, pipe, or the bore of integral, welding neck, or socket weld type
flanges. Group No. Ia gaskets have outside contact diameters equal to the outside
diameter of the raised face.
Gaskets of Groups Nos. IIa and IIIa also have inside diameters equal to the outside
diameter of the corresponding pipe. It may be desirable under some conditions to make
the inside diameter of these gaskets equal to the inside diameter of valves, pipe, or the
bore of integral, welding neck, or socket weld type flanges, and this is permissible
provided the gasket contact width does not exceed than shown. This provision affects
gasket shown in Figs. E4, E5, E8 and E9 and requires a reduction in gasket outside
diameters as well as inside diameters.
Additional provisions for varying gasket widths in contact with raised face are covered in
para E3(b). Group Nos. IIb and IIIb have outside contact diameters equal to the outside
diameter of the raised face.
148
The outside diameter of gaskets or centering rings extending beyond the raised face is
equal to the bolt circle minus one bolt diameter. This type gasket is designed to be
aligned by the flange bolts.
Group Nos. IIa and IIIa gaskets are designed for those users who prefer that narrow
gaskets be located close to the bore, thereby keeping the pressure area to a minimum
and giving maximum flexibility to the flanged joint. See para E3(f). Group Nos. IIb and
IIIb gaskets are to be located at the outside of the raised face for ease in aligning the
gaskets without a centering ring.
TOLERANCES
Gasket contact widths for Group Nos. II and III shall not exceed specified contact width
by more than 10%.
STUDY OF ASME SECTION IX
(WELDING QUALIFICATIONS)
Chap. 1
Introduction to welding qualifications
Chap. 2
Establishing WPS
149
Chap. 3
PQRs and WPQs and Acceptance Standards
Chap. 4
A Note on Consumables
Chap. 5
Guidelines for review of WPS, PQR
Chap 6
Road map for review of WPS/PQR
1. INTRODUCTION TO WELDING QUALIFICATIONS.
“A welding procedure is the detailed methods and practices involved in the production of
a weld ment”.
The written welding procedure, required by codes, comprises
the step-by-step
directions for making a specific weld and proof that the weld is acceptable.
Codes also require proof that welders and welding operators have the necessary skill
and ability to follow the welding procedure successfully. This requires that welders and
welding operators make specific welds, which are then tested to prove that the welder
can produce the weld quality required.
150
Section IX of the ASME Boiler and Pressure Vessel Code covers welding and brazing
qualifications. It is entitled ”Qualification Standard for Welding and Brazing Procedures,
Welders, Brazers, and Welding and Brazing Operators”.
This code makes the following statement concerning responsibility : “Each manufacturer
or contractor is responsible for the welding done by his organization and shall conduct
the tests required to qualify the welding procedures he uses and the performance
qualifications. These records shall be certified by the manufacturer or contractor and
shall be accessible to the authorized inspector.”
The ASME code calls the welding procedure a Welding Procedure Specification (WPS).
This document provides in detail the required conditions for specific applications to
assure repeatability by properly trained.
Welders and welding operators. A WPS is a written welding procedure prepared to
provide direction for making production welds to code requirements.
The ASME
provides a sample form, which may be used or modified provided that it covers all
information.
The WPS provides directions to the welder or welding operator to assure compliance
with the code requirements.
The complete WPS describes all of the essential,
nonessential, and supplementary essential (when required) variables for each welding
process.
The WPS should reference the supporting procedure qualification record
(PQR). A PQR is a record of the welding data used to weld the test coupons. It shows
all conditions that were used when welding the rest coupons and the actual results of
the tested specimens.
The completed PQR should record all essential and
supplementary essential (when required) variables for each welding process used to
weld the test coupon. Nonessential or other variables used during the welding of test
coupons need not be recorded.
The PQR should be certified accurate by the manufacturer or contractor.
This
certification is the manufacturer’s or contractor’s verification that the information is a true
151
record the variables that were used during the welding of the .... coupon and that the
test results are in compliance
..... Section IX of the code.
The manufacturer or
contractor cannot subcontract this certification function.
There are three types of variables for welding procedure specifications WPS. “Essential
variables” are those in which change is considered to affect mechanical properties of
the weld joint or weldment. “Supplementary essential variables” are required for metals
for which notch toughness tests are required. “Nonessential variables” are those in
which a change may be made in the WPS without re-qualifications.
The variables for each welding process is listed in detail in Section IX. For this reason it
is necessary to refer to the code when writing, testing, or certifying the welding
procedures.
Welding Procedure Specification :
To help explain the welding procedure specification (WPS) an example is shown. In
this example, the ABC Pressure Vessel Company is using the gas metal arc welding
process, semi automatically applied for welding P-1 grade steel pipe in the horizontal
fixed and vertical positions. Each entry will be explained briefly.
Joints :
The joint design is a single ‘V ‘ groove with a 60 to 70 0 included angle.
It is
recommended that a sketch be drawn on the form in the area under details. If more
space is needed, use a third sheet. The welding parameters are placed in the table
provided. Backing is not used, and backing materials need not be described. However,
if backing is used, it must be described.
Base Metals :
152
To reduce the number of WPS required, P numbers are assigned to base metals
depending on characteristics such as composition, weldability, and mechanical
properties. Groups within P number are assigned for ferrous metals for the purpose of
procedure qualifications where notch toughness requirements are specified. The same
P numbers group the different base metals having comparable characteristics.
The P numbers and groupings of most of the different steels are given in the Section
IX. Base metal classifications and groupings in AWS B2.1 are slightly different. If a P
number is not available for the material involved, its ASTM specification number may be
used. If an ASTM specification number is not available, the chemical analysis and
mechanical properties can be used. Under base metals the thickness range must be
shown, and if it is in pipe, the pipe diameter range must be shown.
Filler Metals :
Electrodes and welding rods are grouped according to their usability characteristics,
which determines the ability of the welders to make satisfactory welds with a given filler
metal. This grouping is made to reduce the number of WPSs needed. The groups are
given F numbers, which relate to the composition and usability. This is filled in on the
form. This block also requires ASME specification number and the AWS classification
number of the filler metal used.
The ASME specification numbers are the same as the AWS specification number with
the addition of the letters SF. These data are given in ASME Section IX and in the AWS
B2.1 document. The AWS classification number for the filler metal specification is also
given on the label on the filler metal box. The A number is the classification of weld
metal analysis. For example, A-1 has a mild steel weld metal deposit.
This
classification system is given in both specifications.
The size of the filler metal, which is its diameter, must be shown as well as deposited
weld metal thickness range for groove or filler welds. In the case of submerged arc, the
153
consumable insert analysis should be shown. Other information relating to filler metals
not mentioned above should be given, when available.
Position :
The welding position of the groove or fillet weld must be described according to AWS
terminology. If vertical welding is involved, it should be mentioned whether progression
is upward (uphill) or downward (downhill).
Preheat :
A minimum temperature shall be given as well as the maximum interpass temperature.
Preheat maintenance temperature should be given. Where applicable, special heating
should be recorded.
Postweld Heat Treatment :
If a postweld
heat treatment is used, it must be described.
This includes the
temperature range and the time at temperature. If there is not postweld heat treatment,
write in “none”.
Gas :
This shielding gas should be identified, and if it is a mixture, should be described. The
shielding gas flow rate should be recorded. If backing gas or trailing shield gas is used,
the gas composition should be given and flow rate recorded.
Electrical Characteristics :
The welding current should be shown as alternating (ac) or direct current (dc). If direct
current is used, the polarity of the electrode should be reported. The amperes and
154
voltage range should be recorded for each electrode size, position, and thickness. This
is also presented in a tubular form
In the case of gas tungsten arc welding the tungsten electrode size and type should be
described. For gas metal arc welding the mode of metal transfer must be described.
The electrode wire feed speed range should be recorded.
In the case of gas tungsten arc welding the tungsten electrode size and type should be
described. For gas metal arc welding the mode of metal transfer must be described.
The electrode wire feed speed range should be recorded.
Technique :
Under technique, describe the weld as made with stringer or weave beads. Oscillation
should be used to make weave beads. This should also show in the sketch. Often,
both techniques are used in the same weld. For the gas-shielded process the nozzle
inside diameter should be recorded.
The method of cleaning before welding and
between passes must be recorded.
If back gouging is employed, it should be
described. The contact tip-to-work distance should be described as a minimum-tomaximum dimension.
It should be stated whether multiple or single-pass technique is used.
It is also
necessary to indicate whether a single electrode or multiple electrodes are used. It is
also necessary to indicate whether a single electrode or multiple electrodes are used.
The travel speed range should be described. Peening, if used, must be described, and
any other pertinent information concerned with making the weld should be mentioned.
For example, pulsing, if employed, would need to be described.
Procedure Qualification :
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Record to support the welding procedure specification (WPS), it is necessary to test
and certify the weld results. This is done by making the welds described in the WPS,
machining them, and testing the specimen in accordance with the code. This is done by
the procedure qualification record (PQR) defined as a document providing the actual
welding variables used to produce an acceptable test weld, and the results of tests
conducted on the weld for the purpose of qualifying a welding procedure specification
(WPS). It must reference a specific WPS.
An example of a procedure qualification record is shown in Figures , which are similar
to ASME QW-483. This sample PQR is a record of actual conditions used to weld the
coupons made in accordance with WPS.
Many of the data required by the PQR are the same as the information on the
referenced WPS. In fact, the data on the front sheets are almost identical. The back
(sheet 2 of 2) of the PQR is straight forward and is a record of the mechanical test, the
tensile test, the guided bend test, the toughness test when required, and the filler weld
test when used.
A toughness test, either impact or drop weight, is not required by Section IX of the
code. These tests may be required by other sections of the code and must be made
according to other provisions of the code or an ASTM specification.
The example
shows typical data that would be entered.
If the test data meet the requirements of the code, the form is then signed by the
manufacturer’s representative, certifying that the statements in the record are correct
and that the test welds were prepared, welded, and tested in accordance with
requirements of Section IX of the ASME code. The test record of the PQR qualifies the
WPS and fulfills the requirements for the code. All changes to a PQR require
recertification by the manufacturer or contractor.
It is necessary to have specific WPSs and PQRs to cover all the weld processes,
combination of welding processes, different P groupings of base materials and so on, to
156
comply with the variables involved. Every process and base metal used in production
of the product must be covered by a WPS, which must be qualified by a PQR.
Record of Welder Qualification Tests :
With the WPS and PQR documents in order, it is then necessary to test the welders and
welding operators for the work to be done. Each welder and welding operator involved
in manufacturing or installing the products covered by the ASME Boiler and Pressure
Vessel Code must be qualified.
The welder who prepares the procedure qualification record (PQR) specimens that pass
code requirements is personally qualified within his or her performance qualification
variables. All other welders and welding operators are qualified by specific welding
tests, which are designed to determine the ability of the welder or welding operator to
make welds required by the WPS that will cover work. An example of the “Record of
Welder or Welding Operator Qualification Tests” is shown by Figure 21-7, which is
similar to ASME QW-484.
The record of welder or welding operator performance qualification tests should include
the essential variables, the type of test and test results, and the ranges qualified, for
each welder and welding operator. Each welder and welding operator should be
assigned an identifying number, letter, or symbol. It is used to identify the work of that
person. The tests assigned are in accordance with the code and the mechanical tests
should meet the requirements applicable by the code. Radiographic examination may
be substituted for mechanical tests accept for GMAW using short-circuiting metal
transfer. The radiographic technique and acceptance criteria should be in accordance
with the code. In general, welders who meet the code requirements for groove welds
are also qualified for filler welds, but not vice versa. A welder qualified to weld in
accordance with one qualified WPS is also qualified to weld in accordance with other
qualified WPSs using the same welding process, within the limits of the essential
variables according to the code..
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If a welder has not welded for a period of three months or more, his or her qualifications
shall be expired. If there is reason to question the welder’s ability to make welds that
meet the specifications, his or her qualification shall be considered expired. There are
various other conditions relative to welder qualifications listed in the code. The code
must be consulted for this information.
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2. ESTABLISHING WPS
ASME Section IX relates to qualification of welders, welding operators, brazers and
brazing operators and the procedures that they employ in welding and brazing.
It is divided into parts, part QW gives requirements for welding and part QB contains
requirements for brazing. For the purpose of this course we shall deal only with part
QW.
WPS & PQR
The purpose of welding procedure specification (WPS) and procedure qualification
records (PQR) is to determine that the weldment proposed for construction is capable of
providing the required properties for its intended application.
WPS is intended to provide direction for the welder and lists the variables, both
essential and non essential and the acceptable ranges of these variables when using
the WPS.
It is presumed that welder or welding operator performing the welding procedure
qualification test is skilled workman so that welding procedure qualification test
establishes the properties of weldment and not the skill of the welder.
The purpose of performance qualification is to determine if the welder is able to deposit
sound metal or the welding operator is able to operate welding equipment properly.
Part QW is divided into 4 articles.
Article I
-
Welding general requirements
Article II
-
Welding procedure qualifications
159
Article III
-
Welding performance qualifications
Article IV
-
Welding data
Before we proceed let us first understand various test position in groove welds in plates,
groove welds in pipes and fillet weld in plates etc. (Ref. Figure 461.3, 4 & 5)
In general,
1G or 1F is called flat positions
2G or 2F is called horizontal and circumferential
3G or 3F is called vertical position &
4G or 4F is called overhead position
Position 5G is only in welds in pipes. It is a position when pipe axis is held horizontal
and circumferential seam is welded without rotating. In a way it is combination of 1G,
3G & 4G.
Position 6G is also for the pipes when pipe axis is at 45 deg. to horizontal plate and
circumferential seam is welded without rotating the pipe. It is combination of all
positions.
(Refer Fig. 461.1) is the diagram defining the position for groove welds depending on
the inclination of the axis of the weld and the angle of rotation of the face of the weld.
There is similar (Refer fig. 461.2) giving position for fillet welds.
(Refer fig. 451.1) gives the thickness limits and the type and number of the test
specimen required for procedure qualification of groove and (Refer fig. 463.1) a,b,c,d,e,f
shows the method of the taking the test specimen.
In case of weld between dissimilar materials where it is difficult to carry out bending so
that weld is at the center of convex position, transverse bends are replaced by
longitudinal bends and the fig. look like (Refer fig. 463.1 c)
(Refer fig. 451.3 & 451.4) Give the test required to fillet test and (fig462.4) a,d ( it is
similar except that instead of bend there is macro examination of 2 sections of ¼
section.)
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(Refer fig. 452.1) gives performance qualification limits and type and number of the test
specimen required table (fig) gives the diameter limits. It is worth noting that one, two or
more welders can be qualified on just one test coupon. Each may be using even
different processes.
(Refer fig. 462.4 B & C) gives the requirements for performance qualification of fillet
welds.
(Refer fig. 461.9) gives performance qualification position and diameter limits.
Welding Variables :
Article (IV) gives data about various types of welding variables. It also gives tables for
various welding processes showing essential variables, supplementary essential
variables and non essential variables for procedures qualification; and essential
variables for performance qualification.
Essential variables for procedure are those welding variables whose change will affect
the mechanical properties (other than notch-toughness) of the weldment (ex. Change in
P-number, filler metal, electrode type, preheat post heat etc.)
Supplementary essential variables for procedure are those welding variables for
procedure are those welding variables whose change will after the notch toughness
properties of weldment (ex. Uphill or down hill vertical welding, heat input, preheat or
PWHT)
Non essential variables for performance are those welding variables which will not
affect the mechanical properties of weldment (ex. Joint design, method of back gauging
or cleaning etc.)
Essential variables for performance are those welding variables which will affect the
ability of welder to deposit sound weld (e.g. position, deletion of backing F-number etc.
161
Change in process is essential variable for procedure as well as performance.
Before we proceed let us first understand the term P-number A-number and F-number.
All those materials are divided into various P-numbers depending on their nominal
composition and further divided into groups depending on their nominal composition
and further divided into groups depending on the type of refinement / min. specified
UTS etc. QW-422 gives the full details.
Plain carbon steels, C-Si, Cr-Mn & C-Mn-Si are grouped as P-1 materials and austenitic
stainless steel as P-8 material. Ferrous welding consumable are classified under
various A-numbers based on their weld metal chemical composition (table 442) and all
welding electrodes and welding rods are grouped in different F-number depending on
their AWS classification which is based on type of flux and chemical composition (table
432)
Now let us have look on some essential variables tables.
QW 253 WPS- SMAW
QW 353 WPQ- SMAW
The following tables are to be referred frequently for working with ASME Section IX and
hence one has to understand them (how to) in right context.
Refer ASME Section IX.
1.
Refer Fig. QW 461.3
-
Groove Welds in Test Position
2.
Refer Fig. QW 461.4
-
Fillet welds in Plates Test Positions.
3.
Refer Fig. QW 461.5
-
Fillet Welds in Pipe Test Positions
4.
Refer fig. QW 462.2
-
Method of Taking out the Test Specimen
5.
(a, b, c, d & e)
6.
Refer fig. QW 463.1
(Performance Qualification
-
Method of Taking out the Test Specimen
162
(a, b, c, d,e & f)
7.
Refer Table QW 451
Qualification)
-
Procedure Qualification Thickness Limits and
Test Specimens.
8.
Refer Table QW 452
-
Performance Qualification and Test
Specimens.
9.
Refer Table QW 461.9
-
Performance Qualification Position and
diameter limits.
10.
Refer Table QW 461.1
-
Test Jig dimensions
Acceptance Criteria Procedure Qualification
1.
QW 153 Tension Test
2.
QW 163 Bend Test
3.
QW 183 Micro Examination Procedure Specimens
4.
QW 184 Micro Examination Performance Specimens
5.
QW 191 Radiographic Examination
3. ACCEPTANCE STANDARDS.
Welding Procedure Qualification :
The purpose of procedure qualification testing is to demonstrate that the materials
and methods prescribed in a
joint
mechanical properties
procedure specification
that
meet the
will in fact produce weld
application
and
specification
requirements.
There are four steps in the qualification of welding procedure :
#
Preparation and welding of suitable samples
#
Testing of representative specimens
#
Evaluation of overall preparation, welding, testing and end results.
#
Approval (if the result are favorable)
163
Preparation of Procedure Qualification Sample joints
Test assemblies usually have a representative joint in the middle. The size, type,
and thickness are related to the type and thickness of material to be welded in
production and the number, type, and size o specimens to be removed for testing.
The materials used as well as the welding details are governed by the particular
welding procedure specifications that are to be qualified.
Evaluation of Test Results :
The test results for a procedure qualification sample weld, with the records of joint
preparation, welding and testing, should now be made available for review. These
results will be analyzed by the responsible parties to determine whether the test details
and results meet the requirements of the applicable specifications.
Approval Of Qualification Tests and Procedure Specifications :
As a rule, the inspection agency or customer must approve the procedure qualification
tests, the test results, and
the procedure specifications before any production
welding is done.
Qualification is accomplished when the required tests have been completed and
approval has been obtained. However, authentic documentary evidence must be
available to show that the joints were indeed satisfactory. As an inspector, you should
witness the welding and testing of all specimens, if possible, because you will gain
factual knowledge of procedure details that
will
be helpful in later inspections of
production welds.
At
any time, an ASME Authorized Inspector can call
for re-qualification of a
procedure if he is not satisfied with the data presented.
Code Qualification Requirements :
AWS Structural Welding Code, in paragraph 5.5 sets forth the requirements for
qualifying those welding procedures which do not meet
the prequalified status of
164
paragraph 5.1 of that code, or which must be qualified for other reasons, such as
contract requirements. The type and number of specimens that must be tested to
qualify a welding procedure are given in paragraph 5.10. The test results required are
given in paragraph 5.12.
ASME Boiler and Pressure Vessel Code :
The
ASME Boiler and Pressure Vessel Code is authoritative
about welding
procedures. Section IX is the basic document. It is titled Welding and Brazing
Qualifications. All sections of the ASME Code require welding procedures to be
qualified
"in accordance
with
Section
IX"
in
addition
to
supplemental
requirements of each specific section.
ASME Section III on Nuclear Components for Power
Plants, paragraph NB-
2539.2, states. "The welding procedure ... shall be qualified in accordance with NB4000 and Section IX of this Code". Paragraph NC-2539.2 refers to NC-4000 and
Section IX. Similarly, NG-2539.2 refers to NG-4000 and IX.
ASME Section VIII, Division I, on Pressure Vessels, paragraph UW 28,
qualification of welding
procedures
requires the
in accordance with Section IX. Paragraph UB
28 requires brazing procedures to be similarly qualified.
Other procedures in ASME Section III, such as NB-4361 on Specially Designed
Seals, are no exception. "Each Manufacturer or Installer shall prepare a procedure
specification. The procedure shall be qualified as a new procedure and shall be
completely re-qualified when any of the essential variables listed below are changed."
Paragraph
NB-4381.2
on
the
requirements
for
hard surfacing
states.
"The
procedure shall be qualified as a new procedure and shall be completely re-qualified
when any of the changes listed in NB-4382 are made."
The ASME Code is well summarized in a series of identical paragraphs NB-4321,
NC-4321 and so forth-entitled "Procedure Specifications and Qualifications."
165
Each manufacturer and/or Installer is responsible for the welding done
by his
organization and shall establish the procedure and conduct the tests required by this
Article and by Section IX of this Code.
Changes in a Qualified Procedure :
If a fabricator who has qualified a welding procedure desires at some later date to
make a change in that procedure, it may be necessary to conduct additional qualifying
tests. Re-qualification is necessary when any one of the essential variables listed in
the governing standard or code is changed.
For example, one such variable is the heat treatment that follows welding. Heat
treatment has a profound effect on most welds. Its omission (when called for) or its
addition to a welding procedure when not called for would be a change in an important
essential variable, requiring requalification of the procedure.
Note :
The most important factors are usually classed as essential variables; if changed,
re-qualification is necessary. Much the same situation exists in connection with
welder and welding operator qualifications. The variables that are most frequently
considered essential and generally require re-qualification are shown in the following
pages. Remember, reference should always be made to the governing code or
specification
to
determine whether the magnitude of a given change requires re-
qualification.
*********
166
4. WELDING CONSUMABLES
A Brief Introduction :
ASME Section II Part `C' covers classification and properties of consumables for
welding and brazing comprising of Welding Rods, Electrodes and Filler metals. These
consumables are grouped into a number of sub-sections, in other words, Specifications,
referred to as SFA Number.
Each SFA No. covers consumables of overall similar characteristics, grouped together
for compatibility with same group of parent metals. For example, electrodes for carbon
steel are grouped in SFA 5.1
Periodical Assessment, Approvals & Certification :
Each SFA specification stipulates requirements for chemical composition limits,
manufacturing methods, required tests & test methods, acceptance criteria,
classification, marking, packaging, intended use of the consumables, and rules for
periodical assessment, approvals and certification
Some Common Specifications
Some of the commonly used SFA Nos. are listed below ; the list is not exhaustive. For a
complete list refer to Section II-C.
SFA 5.1 Covered carbon steel arc welding electrodes
SFA 5.4 Covered corrosion resisting chromium and chromium-nickel electrodes
SFA 5.5 Low Alloy steel covered arc welding electrodes
SFA 5.9 Corrosion resisting chromium and chromium nickel steel bare filler wire
SFA 5.17 Carbon steel electrodes and fluxes for submerged arc welding ( SAW )
167
SFA 5.18 Carbon steel filler metals for gas shielded arc welding (GTAW / GMAW )
SFA 5.20 Carbon steel electrodes for flux-cored arc welding ( FCAW )
SFA 5.23 Low Alloy steel electrodes & fluxes for SAW
SFA 5.28 Low alloy steel filler metals for gas shielded arc welding (GTAW / GMAW )
SFA 5.29 Low Alloy steel electrodes for Flux-cored arc welding ( FCAW )
AWS Classification of Consumables :
American Welding Society has evolved a system of identifying classes of consumables
in an alfa-numeric code, which is commonly referred to as AWS class. An explanation
of what this classification signifies is given below for typical four common examples:
1. Classification of covered Electrodes for SMAW
(Shielded Metal Arc - also known as Manual Metal Arc):
AWS - E - XX - YY - G
e.g. AWS E-7018
or, AWS E 8018 B2
E …..Coated electrode
XX….. Minimum tensile strength in ksi
YY……Coating Type & chemistry
G…… Alloy addition, if any
2. Classification of GTAW / GMAW / PAW Bare Wire Rod
AWS - ER - XX -S - YY
e.g. AWS ER-70-S-G2
ER….. Bare Rod / electrode
XX….. Minimum tensile strength in ksi
S…….Solid
YY……Specific chemical composition
168
3. Classification of SAW Wire and Flux for Carbon Steel
AWS - F - XXX - E - YYY
F.............Flux
1st X......Tensile strength in 10,000 psig
2nd X.......Condition of Heattreatment ..
A....as welded
P.... Post heat
3rd X........Impact strength
E..............Electrode wire
YYY..........Classification of
carbon steel wire, e.g. EL8, EM12K, or EH14.
4. Classification of SAW Wire & Flux for Alloy Steel
AWS - F - XXX - E C- YYY N- ZM
F.............Flux
1st X......Tensile strength in 10,000 psig
2nd X.......Condition of Heattreatment ..
A....as welded
P.... Post heat
3rd X........Impact strength
E..............Electrode wire
C..............Composite electrode
YYY..........Classification of alloy steel wire
N..............For special purpose
ZM............Chemical composition of weld metal
Classification of Parent Materials and Welding
Consumables as per ASME Code Section IX
In developing ASME Section IX, each welding process that was included in the Section,
was reviewed with regard to those parameters, called VARIABLES, which have
significant effect upon welding operations and fabricator's ability to qualify Welding
Procedures and Welders' performance. Variables are categorized as Essential, Non169
essential and Supplementary (for assurance of notch toughness) variables in the case
of low temperature operation.
Essential Variables are given in comprehensive details in the chapter called "Welding
Data". Change in an Essential Variable of an established Welding Procedure requires
re-qualification of a Procedure with a new set of Essential Variables. Broadly speaking,
and for ease of remembering, following main Essential Variables should be considered
in proposing any Welding Procedure Specification :
i. Welding Process, e.g. SMAW, GTAW, SAW etc.
ii. Parent Material , material specifications categorized into P Nos.
iii. Material Thickness
iv. Welding Consumable, categorized into F No. & A No.
v. Maintenance of Preheat, Interpass & Post heat
vi. Post Weld Heat Treatment and finally, the supplementary essential requirement of,
vii. Impact Testing to assure notch toughness properties. Assignment of P Numbers
To rationally reduce the number of Welding Procedure required to be qualified, base
materials have assigned P Numbers, essentially based on comparable material
characteristics, such as chemical composition, mechanical properties and weldability.
(Refer QW-442)
Assignment of F Numbers : Electrodes and welding rods have been grouped into F
Numbers ( Refer QW-432), essentially on the basis of their usability characteristics,
which fundamentally determine the ability of the Welders to make satisfactory welds,
with a given filler metal. This grouping also reduces the number of welding procedures
and performances which required to be qualified, where it can be logically done.
Assignment of A Numbers :Weld Metal compositions have been classified and grouped
into A Numbers, essentially on the basis of their weldability characteristics, as reflected
by the nominal chemical composition obtained from their actual weld metal analyses.
Cautionary Note
170
These assignments do not imply that base materials and filler materials be
indiscriminately substituted for a base metal or a filler metal which was used in the
qualification test, without consideration of compatibility , from the standpoint of
metallurgical properties, postweld heat treatment, design, mechanical properties and
service requirements.
*********
6.
GUIDELINES FOR REVIEW OF WPS/PQR .
An inspector has to review the WPS, PQR and WPQ documents to ensure that they
meet the ASME sect IX requirements. A checklist shall be used to verify that the WPS is
properly completed and is addressing all the requirements of ASME Sect IX and
construction code. It is also necessary to verify that PQR has been completed to meet
all the ASME sect IX requirements (including test results as per acceptance criteria)
The important part here is also to verify that values of essential variables
recorded on the PQR properly support the specified range of WPS
171
Checklist for Review of WPS (SMAW Process)
Refer QW 250 for variables.
(Supplementary variables not needed)
1)
See identification block showing WPS no.___________, Rev__________ and
PQR no.___________. Also at the end the reviewer shall give his comments.
There is signature of the viewer at the end.
2)
QW 402 gives joint details. QW 403 is indicating Base metals for example if a
PQR is having base metal thk. 25.4mm the WPS supported by it can be from
4.8mm to 5.8mm. So if these variables are written in QW 403.8 properly in WPS
and PQR column then the column at qualification shall indicate OK which
confirms that the variable is within the requirements and addressed properly.
3)
QW 404 is for filler metals
4)
QW 405 is for positions.
5)
QW 406 is for preheat.
6)
QW 407 is for PWST
7)
QW 409 is for electrical characteristics.
8)
QW 410 is for technique.
9)
Additionally QW 401 says “A change in process is an essential variable.” This
has to be verified here and documented.
10)
QW 202.2, 3,4 are mentioned for reminder to the verifier.
11)
This is reminder for QW 200.4 combination of processes.
12)
This is reminder for reviewer for bend and tension test as per QW 451.1
13)
This is reminder for QW 404.5. The basis for assigning A numbers.
14)
This is reminder for QW 170- Notch toughness – if required by construction code.
15)
This is to remind if there are any contracts /company/other
16)
requirements to be addressed (QW201)
172
173