API 579 Fitness for Service Assessment Services

API 579 Fitness for Service Assessment (FFS) is one of the fastest ways to turn inspection findings into a clear decision—can the equipment remain in service, does it need rerating, or should it be repaired now or at the next turnaround.

If you have an active inspection finding and want a quick, structured screen, use the interactive FFS screening workflows on this page to see whether an API 579 Fitness for Service Assessment (FFS) may be needed for your equipment.

These workflows cover common damage mechanisms addressed in API 579, including general metal loss, local metal loss, pitting, crack-like flaws, hydrogen damage, distortions and misalignment, dents and gouges, creep, fire damage, laminations, and fatigue.( Please scroll down the page to find the FFS screening workflow tool. )

At Inspection 4 Industry LLC (I4I), we perform Fitness-For-Service evaluations in accordance with API 579-1 / ASME FFS-1 and issue a complete engineering report that you can use for integrity decisions, operations planning, and management review.

API 579 Fitness for Service Assessment (FFS) Deliverables

Every API 579 Fitness for Service Assessment (FFS) we deliver is a decision-ready package—not a generic memo and not a coaching exercise. You provide the inspection/NDE results and operating basis, and Inspection 4 Industry LLC performs the applicable API 579 Part(s) and Level(s) and issues the report with results.

Your final report package typically includes:

  • The applicable API 579 Part(s) and the assessment Level used (Level 1 / Level 2 / Level 3)
  • Clear conclusion: Fit for service / Not fit for service at the evaluated operating conditions
  • Rerated limits when required (for example, reduced allowable pressure and/or temperature limitation)
  • Practical integrity actions: repair now, repair at next turnaround, or monitor and run with defined scope
  • A monitoring/inspection basis aligned to the controlling damage mechanism
  • Traceable inputs, assumptions, calculations, and an organized report structure suitable for internal review

Part 3 — Brittle Fracture Assessment

Brittle fracture is not a corrosion-rate question; it’s a fracture-risk question driven by metal temperature, material behavior, stress, and flaws. Inspection 4 Industry LLC performs Part 3 brittle fracture assessments as part of an API 579 fitness for service assessment when low temperature events, start-ups, shutdowns, or unexpected cooling create concern about safe operation.

For example, during a winter start-up a light ends receiver or a cold-side exchanger channel experiences a metal temperature excursion below what the unit expected. The site wants a restart decision that can stand up to scrutiny. We execute the Part 3 evaluation route using the available design basis, operating envelope, and relevant inspection findings, then issue a report stating whether the component is acceptable at the evaluated conditions or whether restrictions or rerating actions are required.

API 579 Part 3 — Brittle Fracture Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Is brittle fracture a potential integrity concern for this equipment based on metal temperature exposure and operating conditions?
For example; a light ends receiver or cold-side exchanger channel sees a winter metal temperature excursion below the site’s expected operating envelope during start-up.
2) Do you need to establish or confirm a pressure–temperature operating basis (pressure–temperature envelope) for continued operation?
For example; an overhead receiver has a known low-temperature risk and the unit needs a documented pressure–temperature envelope before continuing winter operation.
3) Are you changing operating conditions or rerating in a way that requires reconfirming pressure–temperature limits?
For example; after a process change, a receiver or drum will see a lower metal temperature or a higher operating pressure at low temperature, requiring updated pressure–temperature limits.
4) Is your decision basis tied to Part 3 temperature criteria such as Critical Exposure Temperature (CET) and/or Minimum Allowable Temperature (MAT)?
For example; the site needs to confirm whether the vessel is acceptable at a specific low metal temperature during start-up, using CET and MAT as the decision basis.
5) Do you have the required Part 3 basis inputs available (e.g., Year of Fabrication, Nominal Wall Thickness, PWHT at initial construction, PWHT after repairs) to support establishing CET/MAT and the pressure–temperature basis?
For example; a 1970s-era drum has incomplete records, and you must confirm nominal thickness and PWHT history before establishing CET/MAT.
6) Are original hydrotest records part of the brittle fracture basis (Original Hydrotest Pressure and Temperature During Original Hydrotest and metal temperature during hydrotest where applicable)?
For example; the vessel’s restart decision relies on confirming original hydrotest pressure and hydrotest temperature used to support the operating envelope at low metal temperature.
7A) Is Charpy Impact Data available for this equipment/material?
For example; material test reports include Charpy impact results for the shell plate, or weld procedure qualification records include impact testing relevant to the component.
7B) If Charpy Impact Data is NOT available, does your Part 3 basis need to address the absence of Charpy Impact Data for the brittle fracture decision?
For example; the vessel is older and has no available Charpy records, so the brittle fracture decision must proceed using the Part 3 route that addresses missing impact data.
8) Is your current concern primarily a crack-like flaw acceptability case (flaw-focused) rather than a temperature-based brittle fracture screening decision?
For example; PAUT identifies a planar indication at a nozzle-to-shell weld and the primary question is crack-like flaw acceptability rather than a temperature screening decision.
9) Is the pressure boundary material outside the intended Part 3 brittle fracture screening applicability for this pathway?
For example; you are screening a carbon steel drum based on the assumed plate material and PWHT history, but inspection records show the pressure boundary is a different material grade or construction condition than assumed (such as a clad/overlayed section or a material that does not match the screening route inputs), so the selected Part 3 screening pathway may not apply.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 4 — General Metal Loss Assessment

General metal loss is refinery reality: broad wall thinning from long-term corrosion or erosion. Inspection 4 Industry LLC performs Part 4 assessments as part of an API 579 fitness for service assessment when thinning is general in nature and the question is whether remaining thickness supports continued operation at current conditions, or whether rerating is required.

Think of a vacuum column bottom section with widespread thinning across a large shell area after years of high-severity service. Management wants a decision: keep running to turnaround, rerate, or repair now. We apply Part 4 using your thickness data (grids or scans) and operating basis and issue a report that clearly states acceptability and, when required, defines rerated operating limits to safely reach the next planned outage.

API 579 Part 4 — General Metal Loss Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Has inspection identified metal loss that is characterized as general metal loss (i.e., not a single Local Thin Area (LTA) controlling the decision)?
For example; a vacuum column bottom shell course shows broad thinning over a 12 ft wide band, with most readings between 0.62 and 0.70 in, rather than one isolated low spot controlling.
2) Is the measured thickness everywhere greater than or equal to the required minimum thickness (tmin) when corrosion/erosion allowance and design basis are considered?
For example; your calculated tmin is 0.50 in (including corrosion allowance), but the thinnest measured point is 0.47 in, so at least one location is below tmin.
3) Do you have sufficient thickness readings to establish minimum measured thickness (tmm) and average measured thickness (tam) for the affected region?
For example; you have a 10×10 UT grid (100 readings) over the thinned band, allowing tmm = 0.47 in and tam = 0.61 in to be defined from the dataset.
4) Is there significant variation in thickness such that thickness profiles (grid data) are required rather than only point thickness readings?
For example; spot UT shows values ranging from 0.72 in down to 0.44 in across the same shell course, so a scan/C-scan or UT grid is needed to characterize the thinning pattern.
5) Is the component not in cyclic service (or does it satisfy the cyclic service screening procedure referenced to Part 14 for applicability of the Part 4 Level 1/Level 2 procedures)?
For example; a stabilizer reflux drum runs steady with infrequent pressure/temperature cycling, rather than daily start-stop operation or frequent pressure swings that could drive cyclic service concerns.
6) Does the metal loss region have smooth contours without notches (negligible local stress concentrations) for applicability of Level 1/Level 2 procedures?
For example; the thinned area transitions gradually over several inches (0.68 → 0.62 → 0.58 in) rather than a sharp groove or undercut-like notch that creates a local stress raiser.
7) Is the component within the Part 4 applicability limitations for component type and loads (including internal pressure and, where applicable, external pressure and supplemental loads for the selected assessment level)?
For example; a straight shell section under internal pressure is being evaluated, and supplemental loads are limited to typical sustained weight and nozzle loads rather than complex external loads controlling the case.
8) Is the component not operating in the creep range (per the limitation referenced to Table 4.1)?
For example; the thinning is on a crude unit overhead receiver operating around 120°F to 180°F, not on high-temperature equipment like fired heater outlet piping where creep may control.
9) Is the intent to determine acceptability using tmm and tam versus tmin, and if needed determine rerating such as MAWPr and coincident temperature?
For example; the thinned shell has tmm = 0.47 in and tam = 0.61 in versus tmin = 0.50 in, and the site needs to know whether MAWP must be reduced from 250 psig to a rerated value to operate safely until the next turnaround.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 5 — Local Metal Loss Assessment

Local metal loss is where average thickness can look acceptable but a localized region controls integrity. Inspection 4 Industry LLC performs Part 5 assessments as part of an API 579 fitness for service assessment using detailed thickness profiles when local thin areas or groove-like features govern the decision.

A refinery example is localized under-deposit corrosion in a crude overhead circuit creating a concentrated low-thickness region near a nozzle or discontinuity. The key decision is whether it is acceptable to continue until the next shutdown and what limits apply. We characterize the local region correctly, execute the Part 5 checks, and deliver a report stating fit or not fit, any rerated limits, and whether repair should be immediate or can be planned for the turnaround with monitoring.

API 579 Part 5 — Local Metal Loss Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Has inspection identified metal loss that is characterized as local metal loss (Local Thin Area (LTA)) rather than general metal loss?
For example; a crude overhead circuit nozzle area shows a 6 in × 8 in low-thickness patch with one minimum reading at 0.23 in, while surrounding shell is 0.45–0.55 in.
2) Are the measured thicknesses in the LTA adequate to satisfy the future corrosion/erosion allowance and the required minimum thickness (tmin)?
For example; tmin is 0.28 in (including corrosion allowance), but the LTA includes readings down to 0.23 in, so the LTA is not everywhere ≥ tmin.
3) Do you have sufficient LTA thickness data to define the LTA (including dimensions and thickness information) for the selected assessment level (including thickness profiles where required)?
For example; you have a UT grid over the LTA (e.g., 1 in spacing) or a thickness scan/C-scan that defines the LTA footprint and the thickness profile, not just one or two point readings.
4) Is the LTA being evaluated under Level 1 applicability (Type A component, internal pressure only, and the LTA can be characterized by a single thickness with one or two surface area dimensions)?
For example; an LTA on a straight shell course under internal pressure is defined as 8 in long × 6 in wide with a representative thickness (e.g., 0.23 in) for Level 1 screening.
5) Have the distances from the LTA to the nearest weld joint and to the nearest major structural discontinuity been determined (as applicable to the assessment procedure)?
For example; the LTA edge is 1.5 in from a longitudinal seam weld and 4 in from a nozzle weld, so weld proximity must be accounted for in how the LTA is evaluated.
6) Has the LTA and surrounding region been examined as required (including examination of the flaw surface and weld seams around the affected area using applicable methods such as UT/MT/PT, as appropriate to the case)?
For example; the site performs UT scanning to define thickness, and MT or PT at nearby welds/attachments to confirm there are no crack-like indications around the thinned region.
7) If the component is susceptible to brittle fracture (per Part 3 basis), have the required examination considerations around the LTA and weld seams been addressed?
For example; the LTA is on a drum that can see low metal temperature during winter start-ups, so weld seams around the LTA are examined and brittle fracture considerations are addressed before a run/repair decision.
8) Is the intent to determine acceptability using Remaining Strength Factor (RSF) for the LTA and compare to allowable RSF, and if needed determine reduced MAWP (rMAWP / MAWPr) for continued operation?
For example; the LTA has tmm = 0.23 in and the evaluation calculates RSF = 0.93, and the site needs to confirm acceptability or establish a reduced MAWP from 300 psig to a rerated value to run until the next turnaround.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 6 — Pitting Corrosion Assessment

Pitting is not “just thinning.” A small number of deep pits can control integrity even when average thickness looks fine. Inspection 4 Industry LLC performs Part 6 pitting corrosion assessments as part of an API 579 fitness for service assessment for localized and widespread pitting, including cases where pitting activity must be considered relative to a future inspection date.

A very common oil & gas case is a cooling-water exchanger channel head or water box with scattered but deep pits. The plant needs more than “watch it.” We evaluate pitting severity using the Part 6 methodology and issue a report that answers two operational questions: is it acceptable now, and will it remain acceptable until the planned next inspection—along with a monitoring interval recommendation that matches the risk.

API 579 Part 6 — Pitting Corrosion Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Has inspection identified pitting corrosion on the pressure boundary?
For example; a cooling-water exchanger channel head shows scattered pits with measured pit depths from 0.03 in to 0.12 in across the wetted surface.
2) Are all pit depths within the specified corrosion/erosion allowance AND is adequate thickness available for the future corrosion allowance?
For example; corrosion allowance is 0.06 in, but the deepest pit is 0.10 in, and the remaining thickness at the pit is below what’s needed to cover future corrosion allowance to the next inspection date.
3) For a Level 1 Assessment basis, is the pitting corrosion arrested?
For example; two consecutive inspections 3 years apart show the same maximum pit depth (e.g., 0.08 in both times) with no increase in pit density in the same mapped locations.
4) Does the case meet Level 1 applicability (Type A component, one-sided widespread pitting corrosion, designed to a recognized code or standard, and internal pressure is the only load considered)?
For example; widespread one-sided pitting is on the internal surface of a separator shell course under internal pressure, with no external pressure case and no unusual supplemental loads controlling.
5) Do you have Level 1 pitting data (measure of surface damage/pitted area AND maximum pit depth, supported by photograph with reference scale and/or rubbing)?
For example; inspection provides a photo with a ruler showing a pitted patch about 4 in × 6 in and documents maximum pit depth as 0.11 in, supported by a rubbing or marked reference area.
6) Is the pitting categorized beyond Level 1 widespread pitting (localized pitting, pitting within a Local Thin Area (LTA), or an LTA located within a region of widespread pitting)?
For example; most of the surface has light pitting, but one localized region near a nozzle has clustered deep pits forming an LTA footprint (e.g., a 3 in × 3 in area with multiple pits over 0.12 in deep).
7) For a Level 2 Assessment basis, do you have pit-couple data (pit diameter and pit depth for each pit, and distance between pit centers; include pit-couple orientation where applicable)?
For example; two adjacent pits are documented as Pit A: 0.35 in diameter × 0.10 in deep, Pit B: 0.30 in diameter × 0.09 in deep, with center-to-center spacing of 0.60 in along the longitudinal direction.
8) Is the pitting corrosion located on both surfaces of the component?
For example; UT mapping confirms pitting on the internal surface from process fluid and additional pitting on the external surface under insulation, meaning both-sided pitting is present.
9) Is the intent to determine acceptability using Remaining Strength Factor (RSF) and, if needed, determine reduced MAWP (rMAWP / MAWPr) for continued operation?
For example; the assessment calculates RSF = 0.90 based on the pitting data, and the site needs to confirm acceptability or rerate MAWP from 200 psig to a reduced MAWPr to operate safely.
10) Are you assessing pitting corrosion at a specific future inspection date using current pitting data and an estimated pitting progression rate (pit depths/diameters/spacing/density)?
For example; today’s maximum pit depth is 0.10 in, and the site assumes a pitting progression of 0.01 in/year to predict whether the deepest pit could reach 0.13 in by a 3-year inspection interval.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 7 — Hydrogen Blistering, HIC, and SOHIC Assessment

Hydrogen damage can drive overly conservative decisions if it is not treated correctly. Inspection 4 Industry LLC performs Part 7 assessments for hydrogen blistering, HIC, and SOHIC as part of an API 579 fitness for service assessment, including cases near welds and discontinuities, and we apply the proper assessment route when the evaluation must link to other Parts.

In refinery service, a realistic scenario is a sour water stripper drum or a hydrotreater-related circuit where UT scanning identifies HIC-type indications near a weld and blister-like features in a localized region. Operations wants to know if the equipment can safely run to the next turnaround and what monitoring is necessary. We perform the Part 7 assessment pathway and deliver a report that states acceptability, any required rerating or repair actions, and a monitoring plan aligned to the hydrogen damage mechanism.

API 579 Part 7 — Hydrogen Blistering / HIC / SOHIC Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Has inspection identified hydrogen blistering, HIC, and/or SOHIC in the pressure boundary?
For example; UT scanning on a sour water stripper drum reports blister-like indications in a 10 in × 12 in region, and additional HIC-type planar indications are noted in the shell plate.
2) Is the indication limited in a way that can be dispositioned without an API 579 Part 7 assessment (i.e., it does not affect structural integrity for continued operation at current conditions)?
For example; one small isolated blister is confirmed by examination to be shallow and away from welds/nozzles, with no growth compared to the prior inspection and no associated crack-like indications.
3) Has the damage been characterized by applicable inspection/examination methods sufficient to define its type and extent (blistering, HIC, SOHIC) for assessment?
For example; inspection provides mapped locations and sizes, UT data that distinguishes blistering from planar HIC-type indications, and documentation of affected plates/courses for the assessment.
4) Is the location of the damage defined relative to weld joints and other structural discontinuities (e.g., in base metal, in/near weld areas, or adjacent to attachments/nozzles)?
For example; the mapped HIC indications are 1 in to 3 in from a longitudinal seam weld, and blistering is clustered near a nozzle reinforcement area—so weld/discontinuity proximity is clearly defined.
5) Do you need a documented acceptability decision for continued operation at current operating conditions (or to establish operating limits) with this damage present?
For example; the unit wants to run to the next turnaround in 24 months, but the damage report includes multiple HIC indications near welds—so a documented decision is required for continued service.
6) Is there a crack-like flaw associated with this damage (or an indication that must be treated as crack-like for acceptability)?
For example; a planar indication near a weld is reported with crack-like characteristics (defined length and orientation) and must be evaluated as a crack-like flaw rather than as blistering-only behavior.
7) Is the controlling concern a separate damage mechanism that requires evaluation under another Part (e.g., general metal loss, local metal loss, pitting, or distortion) rather than hydrogen blistering/HIC/SOHIC as the controlling condition?
For example; the same drum also has a localized thin area with tmm = 0.28 in versus tmin = 0.32 in, so local metal loss may control the immediate operating decision even with hydrogen damage present.
8) Do you have the minimum information required to complete a Part 7 assessment (equipment identification, dimensions/thickness, operating conditions, and inspection results defining the damage type, size, and location)?
For example; you can provide vessel tag, diameter/course thickness (e.g., 72 in OD, 0.75 in nominal), current operating pressure/temperature, and the inspection mapping showing each HIC/SOHIC/blister feature location and size.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 8 — Weld Misalignment and Shell Distortions Assessment

Settlement, out-of-roundness, bulges, peaking, and misalignment can become integrity issues even when thickness is fine. Inspection 4 Industry LLC performs Part 8 assessments as part of an API  579 fitness for service assessment when geometry itself is the concern and must be evaluated for acceptability in pressurized service.

A familiar refinery case is a tall fractionation column that develops measurable ovality due to foundation movement, or a localized bulge after an internal event. You provide dimensional survey data or targeted measurements. We apply Part 8 and issue a report stating whether the distortion is acceptable at current operating conditions, whether rerating is required, and whether correction or reinforcement should be executed immediately or can be planned for the next outage.

API 579 Part 8 — Weld Misalignment and Shell Distortions Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Has inspection identified weld misalignment and/or shell distortions (e.g., peaking, out-of-roundness, bulging, or local distortion) that may affect structural integrity?
For example; a tall fractionation column shows measurable ovality after foundation movement, or a shell course near a circumferential weld shows peaking with a visible “flat spot” across the weld line.
2) Can the condition be dispositioned without an API 579 Part 8 assessment (i.e., it does not affect acceptability for continued operation at current conditions)?
For example; a small local dent on a non-pressure boundary attachment is cosmetic only, but a measured shell distortion near a weld is not cosmetic and cannot be dispositioned without evaluation.
3) Have the distortion/misalignment measurements required for the selected Part 8 procedure been collected (geometry, magnitude, and location of the distortion/misalignment)?
For example; a dimensional survey reports out-of-roundness where the maximum measured diameter is 144.8 in and the minimum is 141.2 in at the same elevation, and peaking at a weld is measured as 0.75 in over a 24 in gauge length.
4) Is the location of the distortion/misalignment defined relative to weld joints, discontinuities, and the component region where acceptability is being evaluated?
For example; the bulge is centered 6 in above a circumferential seam weld and 18 in from a nozzle reinforcement pad, so the assessment location is tied to welds and discontinuities.
5) Do you need a documented acceptability decision for continued operation at current operating conditions (or to establish operating limits) with this distortion/misalignment present?
For example; the column operates at 150 psig and 450°F and the site needs to know whether the measured ovality/bulge is acceptable to run until the next turnaround or whether operating limits must be imposed.
6) Is the controlling concern primarily metal loss (general or local), where the distortion is secondary to thickness acceptability?
For example; the same shell course has tmm = 0.38 in versus tmin = 0.44 in, so thickness controls the decision and the distortion becomes secondary.
7) Is there a crack-like flaw associated with the distorted/misaligned region (or an indication that must be treated as crack-like for acceptability)?
For example; MT at the peaked circumferential weld reports a linear indication 1.25 in long at the weld toe, meaning crack-like flaw evaluation may be required.
8) Is the component operating in the creep range such that a creep evaluation may be required instead of (or in addition to) Part 8?
For example; distortion is on a hot header operating around 900°F for years, so creep range operation may require Part 10 remaining-life evaluation in addition to the Part 8 distortion checks.
9) Do you have the minimum information required to complete a Part 8 assessment (equipment identification, geometry/dimensions, operating conditions, and inspection measurements defining the distortion/misalignment type, magnitude, and location)?
For example; you can provide vessel tag, diameter and course thickness (e.g., 144 in OD, 0.75 in nominal), operating pressure/temperature, and a dimensional survey showing peaking, bulge height, or ovality measurements at the affected weld elevation.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 9 — Crack‑Like Flaw Assessment

Cracks require a different approach than metal loss. Inspection 4 Industry LLC performs Part 9 crack-like flaw assessments as part of an API 579 fitness for service assessment when NDE identifies planar indications, crack-like features, or flaw shapes that must be treated as crack-like to determine safe operation.

A typical refinery case is a crack-like indication found by PAUT or TOFD at a nozzle-to-shell weld on an FCC main fractionator, or at a weld in an amine circuit with high stress concentration and cyclic operation. The unit needs a decision: can it run to the next planned shutdown with monitoring, or is immediate repair mandatory? We execute the Part 9 assessment at the applicable level and deliver a report that states fit or not fit, any operating limitations, and the recommended integrity action and timing.

API 579 Part 9 — Crack-Like Flaws Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Has inspection identified a crack-like flaw (planar flaw predominantly characterized by length and depth, with a sharp root radius), such as a planar crack, lack of fusion/lack of penetration in a weld, or a sharp groove-like localized corrosion feature?
For example; PAUT on a nozzle-to-shell weld of an FCC main fractionator reports a planar indication 2.0 in long with an estimated depth of 0.18 in in a 0.75 in wall.
2) Is the indication a volumetric flaw that should be treated as crack-like for assessment (e.g., aligned porosity/inclusions, deep undercut, root undercut, overlap) because micro-cracks may exist and NDE may not be sensitive enough to confirm micro-cracking?
For example; UT shows a line of aligned inclusions in a weld root over 1.5 in length, and because micro-cracking cannot be ruled out by the available NDE, the indication is conservatively treated as crack-like.
3) Is the component operating in the creep range?
For example; a hot header or fired heater outlet component with a crack-like indication operates around 900°F for long periods, which indicates creep-range operation and drives a different evaluation need.
4) Are dynamic loading effects significant (e.g., earthquake, impact, water hammer, etc.) for the crack-like flaw location?
For example; a piping circuit with a known water hammer history has a crack-like indication near a support or restraint where transient loads could be significant compared to normal operating loads.
5) Is the crack-like flaw subject to loading conditions and/or an environment that may result in crack growth in service?
For example; an amine circuit weld with a crack-like indication is exposed to an environment and cyclic operating swings that could support crack growth between inspections.
6) Do you have the original equipment design data needed for the assessment (design basis consistent with the Part 2 original design criteria requirement)?
For example; the assessment needs design pressure/temperature and governing dimensions (e.g., 250 psig at 650°F, 96 in ID, 0.75 in nominal thickness) consistent with the original design basis.
7) Do you have maintenance and operating history information needed to define the assessment case (service history relevant to the flaw and any known changes in operating conditions)?
For example; the unit can provide that the weld was repaired 8 years ago, the circuit experienced frequent start-stop operation in the last 2 years, and operating pressure/temperature changed after a revamp.
8) Are the loads and stresses available or can they be determined at the crack location for the applicable operating condition(s)?
For example; the site can provide pressure and supplemental loads, and the assessment will determine stresses at the flaw location (e.g., membrane + bending at the nozzle-to-shell weld) for the operating case.
9) Are the required material properties available for the Part 9 assessment (as applicable to the selected level and acceptance method)?
For example; material documentation confirms the pressure boundary grade and key properties required by the selected assessment method, and PWHT status is known for the affected weld.
10) Has the flaw been characterized to define the governing flaw (including length and depth, flaw type: surface-breaking/embedded/through-wall, orientation, and whether there are multiple or branched cracks requiring identification of a predominant crack)?
For example; TOFD reports two indications, but the governing flaw is identified as a surface-breaking flaw 2.0 in long by 0.18 in deep, oriented parallel to the weld, with the second smaller indication non-governing.
11) Is the case intended for a Level 1 or Level 2 assessment (FAD-based), rather than a Level 3 assessment with a crack explicitly incorporated into a numerical model?
For example; you want an FAD-based evaluation using the characterized flaw size and calculated stresses, rather than building a detailed numerical model with the crack explicitly included.
12) If you are pursuing Level 1: does the component and flaw geometry satisfy the Level 1 limiting conditions (component type limitations, wall thickness limit, maximum permitted crack length, permitted flaw type/orientation, and minimum distance from major structural discontinuities as specified by the Level 1 procedure)?
For example; the flaw is located 8 in away from a major structural discontinuity, the wall thickness is within the Level 1 procedure limit, and the crack length/depth are within the maximum permitted for the selected component geometry.
13) Is the intent to determine acceptability using the Failure Assessment Diagram (FAD) method for the current flaw size and operating conditions (stress levels), and document whether the assessment point is on/inside the FAD (acceptable) or outside the FAD (unacceptable)?
For example; the assessment plots the assessment point for the 2.0 in × 0.18 in flaw under the operating stress case and documents whether it falls inside the FAD acceptance boundary.
14) Is your objective to evaluate the likelihood of brittle fracture by postulating a standard reference flaw and solving for Minimum Allowable Temperature (MAT) consistent with the Part 3 definition?
For example; the unit needs a low-temperature operating decision and wants the MAT corresponding to a standard reference flaw at the evaluated stress condition to define a pressure–temperature basis.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 10 — Creep Assessment for High‑Temperature Service

Creep is time-dependent damage and becomes a remaining-life management issue in high-temperature service. Inspection 4 Industry LLC performs Part 10 evaluations as part of an API 579 fitness for service assessment when components operate in the creep range and remaining life must be evaluated for continued safe operation.

A classic refinery scenario is fired heater outlet piping or hot headers with long-term exposure at elevated temperature, sometimes combined with operational cycling. The business decision is whether the circuit can safely meet the next run length and what inspection interval is necessary. We perform the Part 10 remaining-life evaluation and deliver a report that provides a practical integrity plan: continue with defined monitoring, rerate to extend life, or schedule repair or replacement at a defined outage to prevent a run-ending failure.

API 579 Part 10 — Creep Damage Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Is creep damage a potential concern for this equipment based on operating temperature and time at temperature (i.e., long-term elevated temperature exposure)?
For example; fired heater outlet piping or hot headers operate around 850°F to 950°F for years, and the circuit has accumulated 120,000+ hours at elevated temperature.
2) Have inspections identified indications consistent with creep damage (for example, creep cracking, creep cavitation, bulging, distortion, or wall thinning in a high-temperature region)?
For example; during inspection, a hot header shows localized bulging of 0.6 in over a 24 in length, and replication/UT reports creep cavitation near a girth weld HAZ.
3) Is the operating history available to define the assessment case (time at operating temperature, temperature history, and relevant process/operating conditions)?
For example; the unit can provide historian trends showing typical outlet temperature of 910°F with excursions to 940°F, plus total run hours since last replacement (e.g., 38,000 hours since 2019).
4) Is the equipment design and fabrication information available needed for the creep assessment (component identification, dimensions, thickness, material specifications, and weld information where applicable)?
For example; you can provide piping size and schedule (e.g., 12 in NPS, 1.00 in nominal), material specification, weld details, and component geometry where the creep concern exists.
5) Has the damage been characterized sufficiently for assessment (location, extent, and type of creep damage, including whether crack-like indications are present)?
For example; inspection identifies the affected weld number, axial location (e.g., 3 ft downstream of the heater outlet), bulge footprint (e.g., 10 in long), and whether any crack-like indications are detected by MT/PT/UT.
6) Is there a crack-like flaw that controls acceptability and requires a crack-like flaw assessment method in addition to creep considerations?
For example; a linear surface indication 1.0 in long is found at the bulged region near a weld, so crack-like flaw acceptability may control in addition to the creep evaluation basis.
7) Is the controlling condition primarily a different damage mechanism (general metal loss, local metal loss, pitting, or distortion) rather than creep damage as the controlling assessment basis?
For example; the same hot line has an LTA from corrosion with tmm = 0.58 in versus tmin = 0.70 in, so metal loss may control the immediate decision while creep remains a secondary concern.
8) Do you need a documented acceptability decision for continued operation at current operating conditions, including remaining life assessment and/or rerating based on creep damage?
For example; management needs a run-length decision—can the circuit safely operate for the next 18 months at current temperature, or is rerating/repair required based on remaining life.
9) Are you assessing creep damage at a defined future date (next inspection/turnaround) using available damage data and an estimated progression rate or remaining life calculation basis?
For example; the site plans a turnaround in 2 years and wants the assessment to determine whether remaining life is at least 24 months at current conditions, using current damage findings and the temperature-time history.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 11 — Fire Damage Assessment

ire exposure creates urgent restart decisions. Inspection 4 Industry LLC performs Part 11 fire damage evaluations as part of an API 579 fitness for service assessment for equipment exposed to fire or overheating from a process upset, including evaluation of distortion, potential property degradation, and the resulting integrity decision.

Imagine a pump seal fire or localized hydrocarbon pool fire that exposes nearby piping and a small vessel such as an overhead accumulator or separator. The site needs a defendable answer before restart. You provide the event description, exposure area information, and inspection results (dimensional checks, NDE findings, hardness/metallurgical checks if performed). We execute the Part 11 evaluation route and issue a report stating whether the equipment can return to service as-is, whether rerating is required, or whether repair or replacement is mandatory before restart.

API 579 Part 11 — Fire Damage Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Has the equipment experienced a fire exposure event that could have affected the pressure boundary?
For example; a pump seal fire or localized hydrocarbon pool fire exposes nearby piping and a small vessel (such as an overhead accumulator or separator) for approximately 10–20 minutes before extinguishment.
2) Do you need a documented evaluation to determine whether the equipment is acceptable for continued operation following the fire exposure?
For example; the unit is ready for restart, but the equipment was in the exposure zone and management needs a documented basis that can support a restart decision and management review.
3) Is the fire exposure information available to define the assessment case (location/extent of exposure on the equipment and the exposure duration where known)?
For example; the site can provide a written event description showing which side of the vessel was exposed, the approximate flame footprint (e.g., lower 6 ft of shell and two nozzles), and the best estimate of exposure duration (e.g., 15 minutes).
4) Have post-fire inspections been performed to identify and document fire-related damage mechanisms (e.g., distortion, blistering, cracking, localized metal loss, or other pressure boundary damage) for the affected area?
For example; post-event inspection includes dimensional checks for bulging/out-of-roundness, UT thickness checks in the exposed region, and NDE at nearby welds/nozzles to confirm whether crack-like indications are present.
5) Are the required geometry/thickness measurements and material information available for the damaged region to support the fire damage assessment?
For example; you can provide nominal thickness (e.g., 0.625 in), post-fire minimum measured thickness (e.g., 0.58 in), vessel diameter, and known material/PWHT status for the exposed shell course and welds.
6) After the post-fire inspection, is the controlling condition identified as a different damage mechanism requiring evaluation under another Part (e.g., general metal loss, local metal loss, pitting, crack-like flaw, weld distortion/misalignment, hydrogen damage, or creep)?
For example; after the fire event, inspection finds a crack-like indication at a nozzle weld toe or measurable shell distortion, so the controlling condition becomes crack-like flaw or distortion rather than “fire exposure” alone.
7) Is the intent to establish fitness-for-service for continued operation at current operating conditions, and if needed establish operating limits and required repairs/mitigation actions following the fire exposure?
For example; the site needs a clear outcome: return to service as-is, return to service with rerated limits, or repair/replacement required before restart—based on the post-fire condition of the pressure boundary.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 12 — Dents, Gouges, and Dent‑Gouge Combination Assessment

Mechanical damage happens during maintenance, lifting, transport, or unexpected impacts. Inspection 4 Industry LLC performs Part 12 assessments for dents, gouges, and combined dent-gouge conditions as part of an API 579 fitness for service assessment to determine whether the damaged area is acceptable for continued pressure service and whether fatigue concerns require more detailed evaluation.

An oil & gas example is a gas plant separator or produced-water vessel dented during maintenance with visible surface damage at the dented region. The operator wants a clear decision: keep running until shutdown, repair now, or monitor. We characterize the damage geometry based on your measurement data, apply the Part 12 assessment approach, and issue a report that states acceptability, any operating limitations, and repair timing recommendations aligned to the result.

API 579 Part 12 — Dents and Gouges Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Has inspection identified a dent and/or gouge in the pressure boundary that may affect integrity?
For example; a gas plant separator is bumped during maintenance and inspection finds a visible dent on the shell plus a shallow gouge at the center of the dented area.
2) Can the dent/gouge be dispositioned without an API 579 Part 12 assessment (i.e., it does not affect acceptability for continued operation at current conditions)?
For example; a very shallow surface mark with no measurable dent depth and no material removal might be dispositioned, but a measurable dent with a gouge on the pressure boundary typically cannot be closed without evaluation.
3) Have the dent/gouge measurements required for the selected Part 12 procedure been collected (location, dimensions, and depth as applicable)?
For example; the dent is measured as 1.25 in maximum depth over a 14 in length, located 30 in below a circumferential weld and 18 in from a nozzle centerline, with the gouge length and width recorded.
4) Is the remaining thickness in the damaged area defined (including local thinning associated with the gouge, if present)?
For example; nominal thickness is 0.500 in, but UT at the gouge shows a minimum remaining thickness of 0.410 in at the deepest point.
5) Has the dent/gouge region been examined as required to determine whether crack-like indications are present?
For example; MT or PT is performed over the gouge and at the dent “knees” to confirm no linear crack-like indications exist before dispositioning continued operation.
6) Is a crack-like flaw present that controls acceptability and requires evaluation under the crack-like flaw assessment procedures?
For example; MT detects a linear indication 0.75 in long at the gouge root, so crack-like flaw evaluation controls acceptability rather than dent/gouge screening alone.
7) Is the controlling concern primarily metal loss (general or local) rather than dent/gouge effects as the controlling condition?
For example; UT mapping shows a local thin area with tmm = 0.34 in versus tmin = 0.40 in in the same region, so metal loss controls the operating decision more than dent shape.
8) Do you need a documented acceptability decision for continued operation at current operating conditions (and if needed establish operating limits or required repair/mitigation actions) for the dent/gouge condition?
For example; the operator needs a clear decision—run to next shutdown, repair now, or impose operating limits—based on dent depth/shape, remaining thickness at the gouge, and examination results.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 13 — Laminations Assessment

Laminations can appear during UT mapping even when equipment has run for years. Inspection 4 Industry LLC performs Part 13 lamination evaluations as part of an API 579 fitness for service assessment and applies the Part’s routing logic when laminations behave like other damage types.

A refinery scenario is UT scanning on a vessel shell course—such as a desalter vessel or a drum in corrosive service—where laminations are reported near a seam and close to weld areas. The concern is whether they threaten integrity near discontinuities or could interact under service loads. We perform the Part 13 evaluation and deliver a report stating acceptability, monitoring requirements, and whether repair or replacement planning is required.

API 579 Part 13 — Laminations Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Has inspection identified lamination(s) in the pressure boundary material?
For example; UT mapping on a vessel shell course identifies a lamination indication that is planar and parallel to the plate surface, reported during a scan near a longitudinal seam area.
2) Can the lamination(s) be dispositioned without an API 579 Part 13 assessment (i.e., it does not affect acceptability for continued operation at current conditions)?
For example; a small lamination is detected well away from welds, nozzles, or attachments, and does not intersect a high-stress region—versus a lamination near a seam weld where acceptability cannot be assumed.
3) Has the lamination been characterized to define its location, length/width (plan dimensions), and through-thickness position relative to the surface(s)?
For example; UT reports the lamination footprint as 4.0 in × 2.5 in, located at Elev. 18'-6", and the through-thickness position is mid-wall (e.g., centered ~0.30 in from the OD surface in a 0.75 in plate).
4) Is the lamination located in a region where stress levels and loading conditions for the evaluation can be determined for the applicable operating condition(s)?
For example; the lamination is on the shell course of a drum operating at 150 psig and 350°F, and the assessment can determine stress levels in that shell region under the operating condition.
5) Has the lamination region been examined as required to determine whether it must be treated as a crack-like flaw for acceptability?
For example; follow-up examination checks whether the lamination breaks to the surface, intersects a weld, or behaves like a planar flaw that requires crack-like flaw treatment for acceptability.
6) Is a crack-like flaw present or required to be evaluated using crack-like flaw procedures (rather than lamination-only evaluation as the controlling basis)?
For example; UT indicates the lamination connects to a surface-breaking planar indication near a weld toe, so crack-like flaw evaluation controls rather than lamination-only screening.
7) Do you need a documented acceptability decision for continued operation at current operating conditions (and if needed establish operating limits or required repair/mitigation actions) for the lamination condition?
For example; laminations are reported near a seam and close to weld areas on a desalter vessel shell course, and the site needs a documented decision whether it can run to the next turnaround without repair.
8) Do you have the minimum information required to complete a Part 13 assessment (equipment identification, dimensions/thickness, operating conditions, and inspection results defining the lamination size, location, and through-thickness position)?
For example; you can provide vessel tag, diameter and nominal thickness (e.g., 96 in ID, 0.75 in nominal), operating pressure/temperature, and UT mapping that documents lamination footprint and through-thickness position relative to OD/ID.
Answer all questions, then click “Check if FFS is needed”.

API 579 Part 14 — Fatigue Damage and Ratcheting Assessment

Fatigue and ratcheting are driven by cycles: start-ups, shutdowns, pressure/temperature swings, and repeated transients. Inspection 4 Industry LLC performs Part 14 evaluations as part of an API 579 fitness for service assessment when cyclic operation is significant, when ratcheting is suspected, or when cracking indicates fatigue-driven mechanisms may control remaining life.

A refinery example is a compressor discharge circuit or an overhead system that sees frequent start-stop operation and thermal swings, where cracking appears near weld toes, attachments, or discontinuities. The site wants to know whether the component can safely continue under the current operating pattern, whether cycle limits or operational changes are needed, or whether repair must be completed now. We build the loading and cycle history from available plant data, execute the Part 14 evaluation route, and deliver a report that converts operational cycling into a clear integrity decision.

API 579 Part 14 — Fatigue Screening (Workflow)

Instruction: Answer all questions, then click “Check if FFS is needed”.

1) Is fatigue damage a potential concern based on cyclic loading (pressure, temperature, or other repeated operating cycles) for this equipment/component?
For example; a compressor discharge circuit or overhead system sees frequent start-ups/shutdowns and pressure/temperature swings, such as 2–4 start-stop cycles per week plus repeated operational transients.
2) Has inspection identified cracking or crack-like indications where fatigue is a credible damage mechanism?
For example; MT/PT finds toe cracking at an attachment weld or a small crack-like indication at a nozzle reinforcement area where repeated thermal swings occur during cycling operation.
3) Do you need to determine whether the component is in cyclic service using the Part 14 cyclic service screening procedure for applicability of other Parts (e.g., Part 4/Part 5)?
For example; general metal loss or local metal loss is present, but the site must confirm whether the operation qualifies as cyclic service before using Level 1/Level 2 procedures in the metal loss Parts.
4) Is operating history available to define the cyclic loading basis (number of cycles and the nature/magnitude of the cyclic loads for the evaluation period)?
For example; the unit can provide cycle history from operations/historian: 600 pressure cycles over 12 months and repeated temperature swings (e.g., 250°F to 450°F) during start-ups and shutdowns.
5) Can the stress/strain range at the location of interest be determined for the cyclic loading condition(s) (including pressure and other applicable loads for the evaluation)?
For example; pressure ranges are known (e.g., 50 psig to 220 psig) and the assessment can determine the corresponding stress range at a nozzle-to-shell weld or attachment detail for the evaluated cycle.
6) Is there an existing crack-like flaw that must be evaluated using crack-like flaw assessment procedures (and fatigue used for crack growth/remaining life as applicable)?
For example; PAUT/TOFD confirms a planar crack-like flaw with known length and depth, so crack-like flaw acceptability is evaluated and fatigue is used to address crack growth and remaining life as applicable.
7) Do you need a documented acceptability decision for continued operation under cyclic loading, including remaining life determination and/or inspection interval basis?
For example; the site needs a decision whether the component can continue under the current operating pattern, whether cycle limits or operational changes are required, and what inspection interval supports continued safe operation.
8) Are you assessing fatigue at a defined future date using current condition information and the cyclic loading basis (cycle counts and stress range) to determine remaining life or required actions?
For example; the unit plans the next turnaround in 18 months and needs the fatigue evaluation to confirm the component can reach that date under projected cycles, or to define actions if it cannot.
Answer all questions, then click “Check if FFS is needed”.

When More Than One Part Applies

Real equipment rarely has only one damage mechanism. A crude unit overhead receiver may show general thinning, localized thinning, and pitting. A sour circuit may combine hydrogen damage with crack-like indications. After a fire evaluation under Part 11, the controlling condition may still be metal loss, cracking, distortion, or creep. Inspection 4 Industry LLC integrates all applicable Parts into one coherent API 579 fitness for service assessment and delivers one clear report conclusion that identifies the controlling risk and the controlling operating limit.

Start Your Assessment

If you have an inspection finding and need a defensible decision, send the available inspection and operating basis and request an API 579 Fitness for Service Assessment (FFS) from Inspection 4 Industry LLC. We will perform the applicable Part(s) and deliver the complete Fitness‑For‑Service report package with results, limits (if any), and clear integrity actions for continued safe operation.

 

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