API 570 chapter 6 Flashcards
Inspection due date may be determined through a risk assessment in accordance with API 580 and the due date may exceed ….
the typical half-life interval used in a more
conventional analysis.
When should Piping shall be inspected in accordance with code of construction requirements
at the time of installation
The minimum installation inspection should include the following items: (3)
a) verifying that piping is installed correctly, the correct metallurgy is installed, supports are adequate and secured, exterior attachments such as supports, shoes, hangers are secured, insulation is properly installed, flanged and other mechanical connections are properly assembled and the piping is clean and dry;
b) verifying the pressure-relieving devices satisfy design requirements (correct device and correct set pressure) and are properly installed.
c) Base-line thickness
what happens if the piping service changes?
establish new service conditions + PRD settings
What if the location of piping and service are changed
piping should be inspected before it is reused
An RBI assessment conducted in accordance with API 580 may be used to (2)
- determine the inspection intervals
2. next inspection due date and extent of inspection.
Class 1 piping thickness measurement/visual external time frame?
5 years / 5 years
Class 2 piping thickness measurement/visual external time frame?
10 years / 5 years
Class 3 piping thickness measurement/visual external time frame?
10 years / 10 years
Injection point piping thickness measurement/visual external time frame?
3 years / by class
Soil to Air piping thickness measurement/visual external time frame?
See API 574 for SAI / by class
Class 4 piping thickness measurement/visual external time frame?
Optional for both
Class 4 determination is determined by whom?
owner/user
interval for piping that is non - continuous?
based on the number of years of actual service instead of calendar years provided that they are
- isolated from process fluids
- not exposed to corrosive internal environments (purged)
what is class 1 piping?
services with the highest potential of resulting in an immediate emergency
Some class 1 piping type?
a) Flammable services that can auto-refrigerate and lead to brittle fracture.
b) Pressurized services that can rapidly vaporize during release, creating vapors that can collect and form an explosive mixture, such as C2, C3, and C4 streams. Fluids that can rapidly vaporize are those with
atmospheric boiling temperatures BELOW 50 °F (10 °C) or where the atmospheric boiling point is below the operating temperature (typically a concern with high-temperature services).
c) Hydrogen sulfide (greater than 3 % weight) in a gaseous stream.
d) Anhydrous hydrogen chloride.
e) Hydrofluoric acid in main and trace acid services per API RP 751.
f) Piping over or adjacent to water and piping over public throughways (refer to national or local regulations e.g.
Department of Transportation and Coast Guard for inspection of over water piping).
g) Flammable services operating above their auto-ignition temperature.
what is class 2 piping?
slowly vaporize during release such as those operating below the boiling point but above the flash point,
Some class 2 piping type? (3)
a) on-site hydrocarbons that will slowly vaporize during release such as those operating below the boiling point but above the flash point,
b) on-site hydrogen, fuel gas, and natural gas,
c) on-site strong acids and caustics
what is class 3 piping?
Services that are either flammable but do not significantly vaporize when they leak, i.e. below the flash point, or flammable but are located in remote areas and operate below the boiling point
Some class 4 piping type? (7)
a) steam and steam condensate;
b) air;
c) nitrogen;
d) water, including boiler feed water or stripped sour water;
e) lube oil, seal oil;
f) ASME B31.3, Category D services;
g) plumbing and sewers.
what is class 4 piping?
Services that are essentially nonflammable and nontoxic are in Class 4, as are most utility services.
Some class 3 piping type? (6)
a) on-site hydrocarbons that will not significantly vaporize during release such as those operating below the flash point;
b) off-site distillate and product lines to and from storage and loading;
c) tank farm piping;
d) off-site acids and caustics;
e) off-site hydrogen, fuel gas and natural gas; and
f) Other lower risk hydrocarbon piping that does not fall in Class 1, 2, or 4.
Piping that is in non-continuous service and not adequately protected from corrosive environments may experience….?
increased internal corrosion while idle.
External visual inspections, including inspections for CUI, should be conducted at intervals no greater than ………
those listed based on class 1/2/3/4
NDE inspection for CUI should suspect locations operating between ______and what type of material?
10 °F (–12 °C) and 350 °F (175 °C)
carbon steel and low alloy steel piping.
Actions/NDE performed for damage or suspect location for CUI ?
RT or insulation removal and visual inspection is normally required for this inspection
at damaged or suspect locations additional areas should be inspected and, where warranted, up to 100 % of the circuit should be inspected.
% Extent of CUI inspection for Class 1 at damaged / non damaged insulation?
75%/50%
Extent of CUI inspection for Class 2 at damaged / non damaged insulation?
50%/33%
Extent of CUI inspection for Class 3 at damaged / non damaged insulation?
25%/10%
Extent of CUI inspection for Class 4 at damaged / non damaged insulation?
optional
factors that affect CUI? (4)
a) local climatic conditions,
b) insulation design and maintenance,
c) coating quality,
d) service conditions
inspection targets (%) can increase/decrease based on….
experience
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 2
Types of Extent of Thickness Measurement Inspection / CML monitoring (2)
- Point to Point
2. Circuit Analysis Method
What is Point to Point ?
- corrosion rate, remaining life and re-inspection interval is determined for each individual CML
- Future inspections are managed based on the worst case 1/2 life established
Cons of Point to Point?
- lead to frequent inspections of the same piping system if not carefully managed
- cannot apply a statistical analysis since 1) a relationship of one CML to another has not been established, and 2) the individual CML rates may be generated over significantly different time periods, when operating conditions may have changed
Thickness measurements for general thinning sampling should include?
all the various types of components within the circuit.
If RBI is used to set the inspection interval or due date, CMLs …..
are NOT required for inspection
Where localized damage mechanisms are identified, sampling should include
location and orientation (top/bottom, inside/outside radius, etc.) where the damage is most likely to
occur.
The number and specific CMLs to be monitored at each inspection shall be determined by
- by the inspector in consultation with a piping engineer and/or
- corrosion specialist where non-uniform corrosion or other damage mechanisms are expected.
What is Circuit Analysis Method?
Needs to be circuitized into common corrosion mechanisms and expected rates, a statistical
analysis may be used to determine a representative circuit corrosion rate and inspection interval.
Circuit Analysis and Point to Point Method concerns
- Calculated corrosion rate used to predict the future remaining life was a product of the prior operating history, it is important to check for any acceleration of the corrosion rate over time and to be aware of planned operational changes.
- Developed considering the potential active damage mechanisms
- Representative CMLs should be primarily based on the locations where the damage mechanisms are
likely to be most active (include a sampling of all sizes, orientations, component types and design
features ) - For general corrosion, it may not be necessary to identify the specific orientation of the sample point.
Statistical tools may be used to determine or adjust the CML quantities when
prior data are available.
Inspection on small bore piping inspection practices shall include what type of damage mechanism?
shall take into consideration damage mechanisms in
API 571 other than just wall thinning (e.g. stress corrosion cracking, hydrogen induced cracking, embrittlement, etc).
Class 1 and 2 secondary SBP shall be inspected to
the same requirements as primary process
piping.
Class 3 and Class 4 secondary SBP
is optional at the owner-users discretion depending upon reliability and risk.
Insulated SBP should receive the same inspection practices for CUI as
as the primary piping or vessels
preferred inspection methods for insulated SBP (2)
Insulation stripping and radiography
Deadlegs concerns (4)
- accumulation of contaminated water,
- solid materials,
- different temperatures from the main line or the accumulation
- concentration of corrosive species
Deadlegs that are part of primary piping systems should be considered at greater risk because (2)
- inability to valve them off in the event of a leak
- higher potential consequence of a large
leak
Consideration should be given to removing potentially corrosive deadlegs that are
non-essential.
Who should be consulted for placement of CMLs on deadlegs because of their potential for localized corrosion, especially with regard to accelerated corrosion above and below liquid interfaces.
Corrosion specialists
What can be useful for locating liquid interfaces in deadlegs?
Infrared thermography
Inspections of horizontal deadlegs that may not be liquid full should have examination points in all ….
four quadrants of any CMLs.
Potentially corrosive deadlegs with CMLs should be tracked in separate…… and documented….
in a separate piping circuit from the mainline piping and documented in the inspection records and on inspection ISO’s.
Deadlegs may be combined into one circuit if their anticipated damage mechanisms and corrosion rates….
are similar.
Inspections NDE on deadlegs?
- Profile RT on Small Diameters, susceptible fouling deposits that can calls under deposit corrosion
- Scanning Ut or RT on larger Diameters
Other examination techniques for deadlegs include EMAT and PEC.
Deadlegs that may collect water and be susceptible to freezing from external ambient conditions should be (2)
adequately insulated and heat traced for such cases.
Inspection of auxiliary SBP associated with instruments and machinery is _______and the the need would be determined ______
optional / by risk assessment.
Criteria to consider in determining whether auxiliary SBP will need some form of inspection include the following: (5)
a) piping classification;
b) potential for environmental or fatigue cracking, particularly on non-braced SBP (e.g. reciprocating and centrifugal compressors, flow induced vibration);
c) potential for corrosion based on experience with adjacent primary systems;
d) potential for CUI;
e) potential for fatigue, erosion and/or corrosion on thermowells
PRD inspection interval for typical process services
5 years
PRD inspection interval for clean (non-fouling) and noncorrosive services
10 years
When should inspection and testing interval shall be reduced for PRD? (2)
- heavily fouled or stuck
2. when a PRD fails an as received pop test,
As a default criteria for a valve being stuck shut, use a max ____% of set pressure
150
the inspection interval for all pressure relieving
devices is determined by the
inspector, engineer, or other qualified individual per the owner/user’s quality assurance system
Inspection of threaded connections
should be according to the requirements listed above for small-bore and auxiliary piping.
When PRDs are removed for inspection and
testing, what else needs to be inspected?
inlet and outlet lines should be visually inspected for fouling and plugging.
When seal-welding threaded connections to reduce likelihood of threaded connection failure scenarios, pay close attention
to weld prep cleanliness to avoid welding defects and cover all threads completely.
SBP connections associated with rotating equipment, especially threaded connections are often subject to ____ and should be periodically assessed and considered for _______
fatigue damage / possible renewal with a thicker wall or
upgrading joint design.
where should cmls be on elbows?
inside and outside raidus
when hydrostatically tested and thermal expansion is possible…watch out for
excessive pressure
who is responsible for developing, implementing, executing and assessing inspection system and procedures?
owner users
who is responsible for assuring material meet the code/spec for pmi
inspector
who develops the inspection plan?
AI and/or Engineer
what materials are subject to temper embrittement?
low chroms (2 1/4 chrom)
Piping fabricated of or having components of austenitic stainless steel should be hydrotested with a solution made up
of potable water de-ionized/de-mineralized water or steam condensate
if piping is rerated to a lower design temp which of the following is required
impact testing if applicable by code
NDE for environmental cracking?
WFMT, PT,ET,UT
piping periodically inspected by excavation shall be inspected in lengths of
6-8feet
primary inspection used during original construction?
VI and pressure test
close-interval potential survery used for?
locating active corrosion cells on bare and coating piping
