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API 570 (2018) Terms/Definitions
Terms in this set (162)
Piping system, circuit or contiguous sections thereof meeting all of the following: has been decommissioned with no intention for future use; has been completely de-inventoried/purged of hydrocarbon/chemicals; and is physically disconnected (e.g. air-gapped) from all energy sources and/or other piping/equipment.
3.1.2 Alloy Material
Any metallic material (including welding filler materials) that contains alloying elements, such as chromium, nickel, or molybdenum, which are intentionally added to enhance mechanical or physical properties and/or corrosion resistance. Alloys may be ferrous or non-ferrous based. NOTE: Carbon steels are not considered alloys, for purposes of this Code.
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 original design. The following are not considered alterations: comparable or duplicate replacements and replacements in kind.
3.1.4 Applicable 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/user or the piping engineer to be most appropriate for the situation, including but not limited to the latest edition of ASME B31.3.
Approval/agreement to perform a specific activity (e.g. piping repair) prior to the activity being performed.
3.1.6 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/user of piping systems that are used only by the owner/user and not for sale or resale;
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/user.
3.1.7 Authorized Piping Inspector
An employee of an owner/user organization or authorized inspection agency (3.1.6) who is qualified and certified by examination under the provisions of Section 4 and Annex A and is able to perform the functions specified in API 570 where contracted or directed to do so. An 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.
3.1.8 Auxiliary Piping
Instrument and machinery piping, typically small-bore secondary process piping that can be isolated from primary piping systems but is normally not isolated. Examples include flush lines, seal oil lines, analyzer lines, balance lines, buffer gas lines, drains, and vents.
3.1.9 Condition Monitoring Locations CMLs
Designated areas on piping systems where periodic examinations are conducted in order to assess the condition of the piping. CMLs may contain one or more examination points and utilize multiple inspection techniques that are based on the predicted damage mechanism(s). CMLs can be a single small area on a piping system e.g. a 2 in. diameter spot or plane through a section of a pipe where examination points exist in all four quadrants of the plane. NOTE: CMLs now include, but are not limited to what were previously called TMLs.
3.1.10 Construction Code
The code or standard to which the piping system was originally built (e.g. ASME B31.3).
3.1.11 Contact Point
The locations at which a pipe or component rests on or against a support or other object which may increase its susceptibility to external corrosion, fretting, wear or deformation especially as a result of moisture and/or solids collecting at the interface of the pipe and supporting member.
3.1.12 Corrosion Allowance
Material thickness in excess of the minimum required thickness to allow for metal loss (e.g. corrosion or erosion) during the service life of the piping component. NOTE: Corrosion allowance is not used in design strength calculations.
3.1.13 Corrosion Barrier
The corrosion allowance in FRP equipment typically composed of an inner surface and an interior layer which is specified as necessary to provide the best overall resistance to chemical attack.
3.1.14 Corrosion Rate
The rate of metal loss (e.g. reduction in thickness due to erosion, erosion/corrosion or the chemical reaction(s) with the environment, etc.) from internal and/or external damage mechanisms.
3.1.15 Corrosion Specialist
A person acceptable to the owner/user who is knowledgeable and experienced in the specific process chemistries, degradation mechanisms, materials selection, corrosion mitigation methods, corrosion monitoring techniques, and their impact on piping systems.
3.1.16 Corrosion Under Insulation (CUI)
External corrosion of carbon steel and low alloy steel piping resulting from water trapped under insulation. External chloride stress corrosion cracking (ECSCC) of austenitic and duplex stainless steel under insulation is also classified as CUI damage.
3.1.17 Critical Check Valves
Check valves in piping systems that have been identified as vital to process safety (see 5.13). Critical check valves are those that need to operate reliably in order to avoid the potential for hazardous events or substantial consequences should reverse flow occur.
3.1.18 Cyclic Service
Refers to service conditions that may result in cyclic loading and produce fatigue damage or failure (e.g. cyclic loading from pressure, thermal, and/or mechanical loads). Other cyclic loads associated with vibration may arise from such sources as impact, turbulent flow vortices, resonance in compressors, and wind, or any combination thereof. Also see API/ASME 579-1/ASME FFS-1, Definition of Cyclic Service, in Section I.13 and screening methods in Annex B1.5, as well as the definition of "severe cyclic conditions" in ASME B31.3 Section 300.2, Definitions.
3.1.19 Damage Mechanism
Any type of deterioration encountered in the refining and chemical process industry that can result in metal loss/flaws/defects that can affect the integrity of piping systems (e.g. corrosion; cracking; erosion; dents; and other mechanical, physical, or chemical impacts). See API 571 for a comprehensive list and description of damage mechanisms that may affect process piping systems in the refining, petrochemical and chemical process industries.
3.1.20 Damage Rate
The rate of deterioration other than corrosion, i.e. rate of cracking, rate of HTHA, creep rate, etc.
Components of a piping system that normally have little or no significant flow. Some examples include blanked (blinded) 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, pressure relieving device inlet and outlet header piping, pump trim bypass lines, high-point vents, sample points, drains, bleeders, and instrument connections. Deadlegs also include piping that is no longer in use but still connected to the process.
An imperfection of a type or magnitude exceeding the acceptance criteria.
An approved and documented postponement of an inspection, test, or examination. See 7.13.
3.1.24 Design Pressure (of a piping component)
The pressure at the most severe condition of coincident internal or external pressure and temperature (minimum or maximum) expected during service. It is the same as the design pressure defined in ASME B31.3 and other code sections and is subject to the same rules relating to allowances for variations of pressure or temperature or both.
3.1.24 Design Temperature (of a piping system component)
The temperature at which, under the coincident pressure, the greatest thickness or highest component rating is required. It is the same as the design temperature defined in ASME B31.3 and other code sections and is subject to the same rules relating to allowances for variations of pressure or temperature or both. NOTE: Different components in the same piping system or circuit can have different design temperatures. In establishing this temperature, consideration should be given to process fluid temperatures, ambient temperatures, heating/cooling media temperatures, and insulation.
3.1.25 Due Date
The date established by the owner-user and in accordance with this code, whereby an inspection, test, examination, or inspection recommendation falls due or is to be completed. The date may be established by rule-based inspection methodologies (e.g. fixed intervals, retirement half-life interval, retirement date), risk-based methodologies (e.g. RBI target date), fitness-for-service analysis results, owner-user inspection agency practices/procedures/guidelines, or any combination thereof.
3.1.26 Examination Point
Recording point measurement point test point. A specific location on a piping system to obtain a repeatable thickness measurement for the purpose of establishing an accurate corrosion rate. CMLs may contain multiple examination points. NOTE: Test point is a term no longer in use as "test" in this Code refers to mechanical or physical tests (e.g. tensile tests or pressure tests).
The act of performing any type of NDE for the purpose of data collection and/or quality control functions performed by examiners. NOTE: Examinations would be typically those actions conducted by NDE personnel, welding or coating inspectors, but may also be conducted by authorized piping inspectors.
A person who assists the inspector by performing specific NDE on piping system components and evaluates to the applicable acceptance criteria (where qualified to do so), but does not evaluate the results of those examinations in accordance with API 570 requirements, unless specifically trained and authorized to do so by the owner/user.
3.1.29 External Inspection
A visual inspection performed from the outside of a piping system to locate external issues that could impact the piping systems' ability to maintain pressure integrity (see 5.5.4). External inspections are also intended to find conditions that compromise the integrity of the coating and insulation covering, the supporting structures and attachments (e.g. stanchions, pipe supports, shoes, hangers, instrument, and small branch connections).
3.1.30 Fitness-For-Service Evaluation
An engineering methodology whereby flaws and other deterioration/damage contained within piping systems are assessed in order to determine the structural integrity of the piping for continued service (see API 579 1/ASME FFS-1).
Piping component usually associated with a branch connection, a change in direction or change in piping diameter. Flanges are not considered fittings.
3.1.32 Flammable Materials
As used in this Code, includes all fluids which will support combustion. Refer to NFPA 704 for guidance on classifying fluids in 6.3.4. NOTE: Some regulatory documents include separate definitions of flammables and combustibles based on their flash point. In this document flammable is used to describe both and the flash point, boiling point, auto ignition temperature or other properties are used in addition to better describe the hazard.
3.1.33 Flash Point
The lowest temperature at which a flammable product emits enough vapor to form an ignitable mixture in air, (e.g. gasoline's flash point is about -45 °F, diesel's flash point varies from about 125 °F to 200 °F.) NOTE: An ignition source is required to cause ignition above the flash point, but below the auto-ignition temperature.
An imperfection in a piping system usually detected by NDE which may or may not be a defect depending upon the applied acceptance criteria.
3.1.35 General Corrosion
Corrosion that is distributed more or less uniformly over the surface of the piping, as opposed to being localized in nature.
3.1.36 Hold Point
A point in the repair or alteration process beyond which work may not proceed until the required inspection/examination has been performed and verified.
Flaws or other discontinuities noted during inspection that may be subject to acceptance criteria during an engineering and inspection analysis.
A response or evidence resulting from the application of a nondestructive evaluation technique.
3.1.39 Industry-Qualified UT Angle Beam Examiner
A person who possesses an ultrasonic angle beam qualification from API (e.g. API QUTE/QUSE Detection and Sizing Tests) or an equivalent qualification approved by the owner/user. NOTE: Rules for equivalency are defined on the API ICP website.
3.1.40 Injection Point
Injection points are locations where water, steam, chemicals or process additives are introduced into a process stream at relatively low flow/volume rates as compared to the flow/volume rate of the parent stream. NOTE: Corrosion inhibitors, neutralizers, process anti-foulants, de-salter demulsifiers, oxygen scavengers, caustic, and water washes are most often recognized as requiring special attention in designing the point of injection. Process additives, chemicals and water are injected into process streams in order to achieve specific process objectives. Injection points do not include locations where two process streams join (see 3.1.60, mixing points). EXAMPLE: Chlorinating agents in reformers, water injection in overhead systems, polysulfide injection in catalytic cracking wet gas, antifoam injections, inhibitors, and neutralizers.
3.1.41 In Service
Designates a piping system that has been placed in operation as opposed to new construction prior to being placed in service or retired. A piping system not currently in operation due to a process outage is still considered to be in service. The operational stage of a piping system lifecycle that commences upon initial commissioning and ends when the piping system is finally retired from service or abandoned in place. NOTE 1: Does not include piping systems that are still under construction or in transport to the site prior to being placed in service or piping systems that have been retired. NOTE 2: Piping systems that are not currently in operation due to a temporary outage of the process, turnaround, or other maintenance activity are still considered to be "in service." Installed spare piping is also considered in service; whereas spare piping that is not installed is not considered in service.
3.1.42 In-Service Inspection
All inspection activities associated with piping after it has been initially placed in service but before it has been retired.
The external, internal, or on-stream evaluation (or any combination of the three) of piping condition conducted by the authorized inspector or his/her designee. NOTE: NDE may be conducted by examiners at the discretion of the responsible authorized piping inspector and become part of the inspection process, but the responsible authorized piping inspector shall review and approve the results.
3.1.44 Inspection Code
Shortened title for this Code (API 570).
3.1.45 Inspection Plan
A documented set of actions and strategies detailing the scope, extent, methods and timing of specific inspection activities in order to determine the condition of a piping system/circuit based on defined/expected damage. (see 5.1).
An authorized piping inspector per this inspection Code.
3.1.47 Integrity Operating Window (IOW)
Established limits for process variables (parameters) that can affect the integrity of the equipment if the process operation deviates from the established limits for a predetermined amount of time. See 18.104.22.168
3.1.48 Intermittent Service
The condition of a piping system whereby it is not in continuous operating service, i.e. it operates at regular or irregular intervals rather than continuously. NOTE: Occasional turnarounds or other infrequent maintenance outages in an otherwise continuous process service does not constitute intermittent service.
3.1.49 Internal Inspection
An inspection performed on the inside surface of a piping system using visual and/or NDE methods (e.g. boroscope). NDE on the outside of the pipe to determine remaining thickness does not constitute an internal inspection.
A legally constituted governmental administration that may adopt rules relating to process piping systems.
3.1.51 Level Bridle
The piping assembly associated with a level gauge attached to a vessel.
A nonmetallic or metallic material, installed on the interior of pipe, whose properties are better suited to resist damage from the process than the substrate material.
3.1.53 Localized Corrosion
Deterioration restricted to isolated regions on a piping system, i.e. corrosion that is confined to a limited area of the metal surface (e.g. non-uniform corrosion).
A safety procedure used to ensure that piping is properly isolated and cannot be energized or put back in service prior to the completion of inspection, maintenance, or servicing work.
3.1.55 Major Repairs
Welding repairs that involve removal and replacement of large sections of piping systems.
3.1.56 Management Of Change MOC
A documented management system for review and approval of changes (both physical and process) to piping systems prior to implementation of the change. The MOC process includes involvement of inspection personnel that may need to alter inspection plans as a result of the change.
3.1.57 Material Verification Program
A documented quality assurance procedure used to assess metallic alloy materials (including weldments and attachments where specified) to verify conformance with the selected or specified alloy material designated by the owner/user. NOTE: This program may include a description of methods for alloy material testing, physical component marking, and program recordkeeping (see API 578).
3.1.58 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 (minimum or maximum) expected during service. It is the same as the design pressure, as defined in ASME B31.3 and other code sections, and is subject to the same rules relating to allowances for variations of pressure or temperature or both. If the piping system is being rerated, the new MAWP shall be the rerated MAWP.
3.1.59 Minimum Alert Thickness (Flag Thickness)
A thickness greater than the minimum required thickness that provides for early warning from which the future service life of the piping is managed through further inspection and remaining life assessment.
3.1.60 Minimum Design Metal Temperature/Minimum Allowable Temperature MDMT/MAT
The lowest permissible metal temperature for a given material at a specified thickness based on its resistance to brittle fracture. In the case of MAT, it may be a single temperature, or an envelope of allowable operating temperatures as a function of pressure. It is generally the minimum temperature at which a significant load can be applied to a piping system as defined in the applicable construction code. It might be also obtained through a Fitness-For-Service evaluation.
3.1.61 Minimum Required Thickness Tmin
The thickness without corrosion allowance for each component of a piping system based on the appropriate design code calculations and code allowable stress that consider pressure, mechanical and structural loadings. NOTE: Alternately, minimum required thicknesses can be reassessed using Fitness-For-Service analysis in accordance with API 579-1/ASME FFS-1.
3.1.62 Mixing Point
Mixing points are locations in a process piping system where two or more streams meet. The difference in streams may be composition, temperature or any other parameter that may cause deterioration and may require additional design considerations, operating limits, inspection and/or process monitoring.
An item that is not in accordance with specified codes, standards or other requirements. NOTE: A non-conformance does not necessarily mean that the item is defective or that the item is not suitable for continued service.
3.1.64 Nonpressure Boundary
Components and attachments of, or the portion of piping that does not contain the process pressure. EXAMPLE: Clips, shoes, repads, supports, wear plates, nonstiffening insulation support rings, etc.
3.1.65 Off-Site Piping
Piping systems not included within the plot boundary limits of a process unit, such as, a hydrocracker, an ethylene cracker or a crude unit. EXAMPLE: Tank farm piping and inter-connecting pipe rack piping outside the limits of the process unit.
3.1.66 On-Site Piping
Piping systems included within the plot limits of process units, such as, a hydrocracker, an ethylene cracker, or a crude unit.
3.1.67 On-Stream Piping
Piping systems that have not been isolated and decontaminated, i.e. still connected to in-service process equipment NOTE: Piping systems that are on-stream can be full of product during normal processing or empty or may still have residual process fluids in them and not be currently part of the process system (e.g. temporarily valved-out of service).
3.1.68 On-Stream Inspection
An inspection performed from the outside of piping systems while they are on-stream using NDE procedures to establish the suitability of the pressure boundary for continued operation (see 5.5.2).
3.1.69 Overdue Inspection
Inspections for in-service piping that remain in operation and have not been performed by the due date documented in the inspection plan, and have not been deferred by a documented deferral process. See 7.13.
3.1.70 Overwater Piping
Piping located where leakage would result in discharge into streams, rivers, bays, etc., resulting in a potential environmental incident.
The organization that execises control over the operation, engineering, inspection, repair, alteration, pressure testing, and rating of the piping systems.
3.1.72 Owner/User Inspector
An authorized inspector employed by an owner/user who has qualified by examination under the provisions of Section 4 and Annex A.
A pressure-tight cylinder used to convey, distribute, mix, separate, discharge, meter, control or snub fluid flows, or to transmit a fluid pressure and that is ordinarily designated "pipe" in applicable material specifications. NOTE: Materials designated as "tube" or "tubing" in the specifications are treated as pipe in this Code when intended for pressure service external to fired heaters. Piping internal to fired heaters should be in compliance with API 530.
3.1.74 Piperack Piping
Process piping that is supported by consecutive stanchions or sleepers (including straddle racks and extensions).
3.1.75 Piping Circuit
A subsection of piping systems that includes piping and components that are exposed to a process environment of similar corrosivity and expected damage mechanisms and is of similar design conditions and construction material where by the expected type and rate of damage can reasonably be expected to be the same. NOTE 1: Complex process units or piping systems are divided into piping circuits to manage the necessary inspections, data analysis, and record keeping. NOTE 2: When establishing the boundary of a particular piping circuit, it may be sized to provide a practical package for record keeping and performing field inspection.
3.1.76 Piping Engineer
One or more persons or organizations acceptable to the owner/user who are knowledgeable and experienced in the engineering disciplines associated with evaluating mechanical and material characteristics affecting the integrity and reliability of piping components and systems. The piping engineer, by consulting with appropriate specialists, should be regarded as a composite of all entities necessary to properly address piping design requirements.
3.1.77 Pipe Spool
A section of piping with a flange or other connecting fitting, such as a union, on both ends which allows the removal of the section from the system.
3.1.78 Piping System
An assembly of interconnected pipe that typically are subject to the same (or nearly the same) process fluid composition and/or design conditions. NOTE: Piping systems also include pipe-supporting elements (e.g. springs, hangers, guides, etc.) but do not include support structures, such as structural frames, vertical and horizontal beams and foundations.
Localized corrosion of a metal surface in a small area and takes the form of cavities called pits. Pitting can be highly localized (including a single pit) or wide spread on a metal surface.
3.1.80 Positive Material Identification PMI
Any physical evaluation or test of a material to confirm that the material, which has been or will be placed into service, is consistent with the selected or specified alloy material designated by the owner/user. NOTE: These evaluations or tests can provide qualitative or quantitative information that is sufficient to verify the nominal alloy composition (see API 578).
3.1.81 Postweld Heat Treatment PWHT
A work process which consists of heating an entire weldment or section of fabricated piping to an elevated temperature after completion of welding in order to relieve the detrimental effects of welding heat, such as reducing residual stresses, reducing hardness, and/or slightly modifying properties (See ASME B31.3, paragraph 331).
3.1.82 Pressure Boundary
The portion of the piping that contains the pressure retaining piping elements joined or assembled into pressure tight fluid-containing piping systems. Pressure boundary components include pipe, tubing, fittings, flanges, gaskets, bolting, valves, and other devices such as expansion joints and flexible joints. NOTE: Also see non-pressure boundary definition.
3.1.83 Pressure Design Thickness
Minimum allowed pipe wall thickness needed to hold the design pressure at the design temperature. NOTE 1: Pressure design thickness is determined using the rating code formula, including needed reinforcement thickness. NOTE 2: Pressure design thickness does not include thickness for structural loads, corrosion allowance, or mill tolerances and therefore should not be used as the sole determinant of structural integrity for typical process piping (e.g. 7.3).
3.1.84 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 typically does not include small bore or auxiliary process piping (see also secondary process piping).
A document that specifies or describes how an activity is to be performed on a piping system, often a step-by-step description (e.g. temporary repair procedure, external inspection procedure, hot tap procedure, NDE procedure, etc). NOTE: A procedure may include methods to be employed, equipment or materials to be used, qualifications of personnel involved, and sequence of work.
3.1.86 Process Piping
Hydrocarbon or chemical piping located at, or associated with a refinery or manufacturing facility. Process piping includes piperack, tank farm, and process unit piping, but excludes utility piping (e.g. steam, water, air, nitrogen, etc).
3.1.87 Quality Assurance
All planned, systematic, and preventative actions required to determine if materials, equipment, or services will meet specified requirements so that the piping will perform satisfactorily in-service. Quality assurance plans will specify the necessary quality control activities and examinations. NOTE: The contents of a quality assurance inspection management system for piping systems are outlined in 4.3.1.
3.1.88 Quality Control
Those physical activities that are conducted to check conformance with specifications in accordance with the quality assurance plan (e.g. NDE techniques, hold point inspections, material verifications, checking certification documents, etc.).
Activity that discards an existing component, fitting, or portion of a piping circuit and replaces it with new or existing spare materials of the same or better qualities as the original piping components.
The work necessary to restore a piping system to a condition suitable for safe operation at the design conditions. NOTE: If any of the restorative changes result in a change of design temperature or pressure, the requirements for re rating also shall be satisfied. Any welding, cutting, or grinding operation on a pressure-containing piping component not specifically considered an alteration is considered a repair. Repairs can be temporary or permanent (see Section 8).
3.1.91 Repair Organization
Any of the following:
a) an owner/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/user of piping systems and who makes repairs or alterations in accordance with API 570,
c) an organization that is authorized by, acceptable to, or otherwise not prohibited by the jurisdiction and who makes repairs in accordance with API 570.
The work process of making calculations to establish pressures and temperatures appropriate for a piping system, including design pressure/temperature, MAWP, structural minimums, required thicknesses, etc.
A change in the design temperature, design pressure or the maximum allowable working pressure of a piping system (sometimes called rating). NOTE: A rerating may consist of an increase, a decrease, or a combination of both. Derating below original design conditions is a means to provide increased corrosion allowance.
3.1.94 Retired From Service
Piping systems that are no longer going to be used for any process service.
3.1.95 Risk-Based Inspection RBI
A risk assessment and risk management process that is focused on inspection planning for piping systems for loss of containment in processing facilities, which considers both the probability of failure and consequence of failure due to materials of construction deterioration. See 5.2.
The movement of a device (visual, ultrasonic, etc.) over a wide area as opposed to a spot reading and used to find flaws/defects (e.g. the thinnest thickness measurement at a CML or cracking in a weldment). See guidance contained in API 574.
3.1.97 Secondary Process Piping
Process piping located downstream of a block valve that can be valved-off without significantly affecting the process unit operability is commonly referred to as secondary process piping. Often, secondary process piping is small-bore piping (SBP).
3.1.98 Small-Bore Piping SBP
Pipe or pipe components that are less than or equal to NPS 2.
3.1.99 Soil-to-Air Interface SAI
An area in which external corrosion may occur or be accelerated on partially buried pipe or buried pipe near where it egresses from the soil. NOTE: 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 at least 12 in. (305 mm) below to 6 in. (150 mm) above the soil surface. Pipe running parallel with the soil surface that contacts the soil is included.
3.1.100 Structural Minimum Thickness
Minimum required thickness without corrosion allowance, based on the mechanical loads other than pressure that result in longitudinal stress. See 7.6. NOTE: The thickness is either determined from a standard chart or engineering calculations. It does not include thickness for corrosion allowance or mill tolerances.
3.1.101 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 and/or piping engineer NOTE: Injection fittings on valves to seal fugitive (LDAR) emissions from valve stem seal are not considered to be "temporary repairs" as described in 22.214.171.124 and 8.1.5 in this Code.
Procedures used to determine pressure tightness, material hardness, strength, and notch toughness. Example: Pressure testing, whether performed hydrostatically, pneumatically, or a combination of hydrostatic / pneumatic or mechanical testing. NOTE: Testing does not refer to NDE using techniques such as PT, MT, etc.
3.1.103 Tank Farm Piping
Process piping inside tank farm dikes or directly associated with a tank farm.
3.1.104 Utility Piping
Non-process piping associated with a process unit (e.g. steam, air, water, nitrogen, etc.)
American Petroleum Institute
American Society of Mechanical Engineers
American Society for Nondestructive Testing
Automated Ultrasonic Examination
Boiler and Pressure Vessel Code (of ASME)
Computerized Monitoring Button
Condition Monitoring Location
Corrosion Under Insulation, including Stress Corrosion Cracking Under Insulation
Electromagnetic Acoustic Transducer
External Chloride Stress Corrosion Cracking
Eddy Current Technique
Fiberglass Reinforced Plastic
Guided Wave Examination
Hydrogen Induced Cracking
Integrity Operating Window
Inspection Isometric Drawing
Leak Detection And Repair (of fugitive emissions)
Minimum Allowable Temperature
Maximum Allowable Working Pressure
Minimum Design Metal Temperature
Manufacturer's Data Reports
Magnetic Flux Leakage
Management Of Change
Material Test Report (Mill Test Report)
NACE International, the Corrosion Society, previously National Association of Corrosion Engineers
Nominal Pipe Size (followed, when appropriate, by the specific size designation number without an inch symbol)
Occupational Safety and Health Administration
Phased Array Ultrasonic Technique
Post Construction Committee (of ASME)
Pulsed Eddy Current
Positive Material Identification
Procedure Qualification Record
Pressure Relieving Device
Profile Radiographic Examination
Post-Welding Heat Treatment
Radio Frequency Identification Devices
Radiographic Examination (Method) or Radiography
Reinforced Thermoset Plastic
Soil Air Interface
Stress Corrosion Cracking
Standards Development Organization (e.g. API, ASME, NACE)
Specified Minimum Yield Strength
Thickness Monitoring Location
Welding Procedure Specification
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