Corrosion Mapping with Multiple NDT Methods [2026]

Why single-point UT readings fall short for corrosion assessment, and how combining eddy current, PAUT, and automated UT builds maps for life assessment.

Atlantis NDT · March 2026 · NDT Methods

Multi-Method Corrosion Assessment: Complete Technical Guide & Implementation

Multi-Method Corrosion Assessment is a fundamental nondestructive examination technique used across industries for defect detection, material characterization, and asset integrity assessment. This comprehensive guide covers the physics principles, equipment requirements, procedures, advantages/limitations, industry applications, relevant standards, and practical FAQs.

Technique Overview: Physics and Principles

What is Corrosion Mapping and Multiple NDE Methods?

Corrosion is the most common degradation mechanism in industrial equipment. Ultrasonic thickness measurement provides point measurements; eddy current, phased array, and automated UT enable area mapping; visual inspection documents overall pattern. Combining methods creates comprehensive corrosion maps supporting remaining life assessment and maintenance planning.

How It Works: Physical Principles

The technique is based on fundamental physics principles that have been refined over decades of industrial application. Understanding these principles is essential for proper equipment selection, procedure development, and results interpretation.

Key Physics Concepts:

Wave Propagation: Electromagnetic or mechanical waves interact with material structure, boundaries, and discontinuities
Attenuation and Reflection: Signal strength changes as waves travel through material and encounter interfaces
Frequency Dependencies: Higher frequencies provide better spatial resolution but shorter penetration depth; lower frequencies provide greater penetration with reduced resolution
Material Properties: Conductivity, permeability, acoustic impedance, and density affect signal interaction and interpretation
Signal-to-Noise Ratio: Distinguishing true defect indications from background noise is critical for reliable defect detection
Sensitivity and Specificity: Balancing detection of all relevant defects while minimizing false positives and false negatives

Equipment Required: Components

Core Equipment Package

A complete inspection system includes multiple components, each serving specific functions:

Primary Instrument/Pulser-Receiver:

Function: Generates excitation signals and processes received/reflected signals
Options: Portable field units, benchtop laboratory systems, automated scanning systems
Key Features: Adjustable frequency, gain, pulse width, filtering, data storage, reporting capabilities

Probes/Transducers/Sensors:

Function: Generate signals and receive reflected energy; frequency and design vary by application
Typical Requirements: 3-5 different probes needed for comprehensive capability across frequency range and applications
Factors: Element size, frequency, beam geometry, couplant compatibility, durability

Couplant and Application Materials:

Function: Provides acoustic/electromagnetic pathway between equipment and component surface
Types: Water-based gels, oils, adhesive pastes, water-soluble compounds
Selection: Must be compatible with material, surface condition, temperature, and equipment

Reference Standards and Calibration Blocks:

Function: Verify equipment sensitivity and establish baseline for defect detection
Critical: Must be traceable to standards and document calibration history
Maintenance: Regular verification (typically annually) and re-certification as needed

Associated Hardware and Software:

Cables and Connectors: replaced as needed; damaged cables are a common source of signal noise
Data Acquisition System: Integrated in modern instruments; enables digital storage and automated reporting
Analysis/Reporting Software: trending, defect sizing, statistical analysis and report generation
Calibration Services: periodic instrument calibration, typically annual, with traceable certificates

Typical Equipment Configurations

Basic Entry-Level Setup: one portable unit, 2-3 probes, reference blocks, couplant

Professional Inspection Setup: portable unit, 5+ probes for multiple frequencies/applications, multiple reference standards, advanced software

Automated/Production Setup: multi-channel systems, automated scanning fixtures, integrated data management

Step-by-Step Inspection Procedure

Pre-Inspection Planning

1. Understand the Inspection Objective: What are you trying to detect? (cracks, corrosion, wall loss, delaminations, other degradation). Defect characteristics (size, orientation, location) drive method selection and equipment configuration.

2. Review Component Specifications: Material type, thickness, geometry, surface finish, operating history, previous inspection results. Review relevant codes/standards (ASME, API, ASTM, ISO) for acceptance criteria and procedural requirements.

3. Develop Written Procedure: Standard operating procedure (SOP) documenting equipment setup, frequency selection, scanning pattern, acceptance criteria, reporting format. Procedure should be approved by Level III inspector or authority having jurisdiction.

4. Calibrate Equipment: Verify instrument sensitivity against reference standards. Document all calibration data. Equipment must be in calibration throughout inspection period.

Surface Preparation

5. Clean Component Surface: Remove paint, corrosion, dirt, and other debris that would interfere with signal transmission. Method depends on material sensitivity (abrasive blasting for thick components, gentle methods for coatings being preserved).

6. Document Surface Condition: Photograph areas of concern. Surface roughness, temperature, and condition affect signal quality—document baseline for future comparisons.

7. Apply Couplant: Apply appropriate coupling medium between probe and component surface. Ensure full contact and eliminate air gaps that would block signal transmission.

Data Acquisition

8. Perform Scan: Systematically scan component following documented pattern (linear, grid, circumferential for cylindrical components). Maintain consistent probe contact and coupling.

9. Record Baseline Measurements: Establish baseline measurements in non-defect areas for comparison. Baseline establishes signal characteristics for this specific component.

10. Document Anomalies: Mark and measure any indications that differ from baseline. Use consistent measurement methodology. Document location, size, character of indication.

Data Analysis and Interpretation

11. Compare to Standards: Evaluate recorded indications against acceptance criteria specified in applicable standard or company procedure. Determine if indication is acceptable, requires further evaluation, or is rejectable.

12. Size Defects: If applicable, quantify defect dimensions using sizing algorithms appropriate to indication type. Different defect types (cracks, inclusions, porosity) require different sizing approaches.

13. Trend Historical Data: Compare current results to previous inspections. Identify accelerating degradation, new defects, or stable conditions. Trending supports maintenance decisions and remaining life assessment.

Reporting

14. Document Findings: Create inspection report documenting equipment used, procedure followed, findings, measurements, and disposition (acceptable/unacceptable/conditional). Include photographs and data files as supporting documentation.

15. Establish Follow-up Actions: For unacceptable conditions, recommend repair/replacement. For acceptable conditions, schedule next inspection interval. For conditional acceptances, specify monitoring frequency and criteria for equipment removal from service.

Advantages and Limitations

Key Advantages

Non-invasive: Detects internal defects without requiring component dismantling or sample removal
Real-time Results: Immediate indication of defects; no waiting for laboratory analysis
Quantitative Data: Provides measurements (depths, sizes, extent) supporting engineering decisions
Repeatability: Same procedure applied to same location produces consistent results for trending
Cost-Effective: Compared to destructive testing or equipment replacement, inspection is economical risk mitigation
Versatility: Applicable across multiple industries and component types
Portability: Field equipment enables on-site inspection without removing equipment

Key Limitations

Surface Access Required: Component surface must be accessible; internal components in closed systems may be inaccessible
Surface Condition Dependency: Rough, painted, or corroded surfaces reduce signal quality; extensive surface preparation required
Material Constraints: Certain material types (very coarse grain, extreme thickness, high attenuation) limit effectiveness
Operator Skill Required: Results depend heavily on inspector experience, training, and interpretation skill
Equipment Complexity: Modern systems offer many options; proper selection requires technical knowledge
Reference Standards Needed: Proper calibration requires access to appropriate reference standards and regular verification
Defect Character Interpretation: Difficulty distinguishing between different defect types (cracks vs. inclusions) in some applications
False Positives/Negatives: Misinterpretation of noise signals as defects or missing actual defects due to signal masking

Applications by Industry

Oil & Gas Refining and Petrochemical

Wall thickness monitoring of pipes, vessels, and exchangers; weld examination in fabrication and in-service; early detection of corrosion patterns and erosion. Predictive maintenance based on corrosion mapping and remaining life assessment.

Power Generation

Boiler tube inspection, turbine blade examination, steam line integrity assessment. High-temperature and pressure equipment with stringent safety requirements. Creep damage assessment in ferritic steels.

Aerospace and Aviation

Structural component inspection, fastener examination, composite material assessment. Extremely tight defect size limits and high sensitivity requirements. Automated scanning systems common for high-volume production.

Automotive and Manufacturing

Weld quality assurance in production; bearing and component inspection; material verification. High-speed automated systems integrated into production lines for statistical quality control.

Infrastructure and Transportation

Bridge and structural steel inspection, railroad track assessment, pipeline integrity verification. Long-term trending of deterioration supports maintenance planning and safety decisions.

Standards and Codes

The following standards and codes address this inspection technique:

ASME Standards: Section V (Article 4 and Article 5 for ultrasonic examination, Article 8 for eddy current, Article 23 for the referenced thickness-measurement standard), Section VIII (pressure vessel requirements), B31.3 (piping)
API Standards: 510/570/653 (in-service inspection codes), RP 574 and RP 575 (inspection practices), RP 571 (damage mechanisms)
ASTM Standards: E797 (ultrasonic thickness measurement by the manual pulse-echo contact method) and the method-specific ASTM practices for the techniques used
ISO Standards: ISO 16809 (ultrasonic thickness measurement) and the method-specific ISO standards for the techniques used
AWS Standards: D1.1 (weld inspection and acceptance)
Industry-Specific Codes: NACE, DNVGL, Lloyd's, ABS, and other classification society requirements

Professionals performing this inspection must be familiar with applicable standards for their industry, equipment type, and geographic location.

Frequently Asked Questions (FAQs)

Q1: What training and certification do I need to perform Corrosion Mapping and Multiple NDE Methods inspections?

Personnel requirements depend on the method, level, sector, certification scheme and employer authorisation. Confirm the training, experience, assessment and any technique-specific requirements for the assignment.

Q2: How often should equipment be calibrated?

A: Minimum annually per most standards. Critical equipment: before/after major inspections or if showing questionable results. Third-party calibration recommended for audit defensibility. Documentation of all calibration activities essential.

Q3: Can I use this technique on all material types?

A: No. Material properties (grain size, composition, magnetic permeability, electrical conductivity) significantly affect technique effectiveness. Review material specifications and prior experience before committing to this method for new applications. Trial inspections may be needed to verify applicability.

Q4: What size defect can this technique reliably detect?

A: It depends on material, thickness, surface condition, equipment, technique, operator skill and the type of corrosion. There is no single figure: detection and sizing capability is established for a specific procedure, through demonstration on representative reference standards or a probability of detection (POD) study. Ask for the demonstrated capability of the procedure being used.

Q5: How do I ensure results are reproducible and defensible for regulatory audit?

A: Written procedure approved by Level III or authority having jurisdiction; documented operator certifications; equipment calibration certificates; baseline measurements and reference standards; digital data files with timestamps; photographs and location documentation; report signed by qualified personnel. Comprehensive records demonstrate due diligence.

Q6: What's the difference between this technique and similar methods?

A: Each technique has distinct physics principles, capabilities, and limitations. The NDT method selector tool helps compare techniques. Consult NDT consulting services for complex applications requiring method comparison.

Q7: How much does an inspection cost and what factors affect pricing?

A: Cost depends on component size/complexity, accessibility, surface preparation effort, depth of analysis, and inspector labor rate. Equipment cost: portable systems are a serious capital purchase and automated systems considerably more, which is why most owners buy the service rather than the instrument. Providers price advanced-method work at a premium over conventional UT.

Q8: How do I get started with implementing this technique if my facility currently doesn't use it?

A: Step 1: Take formal training courses for your team. Step 2: Invest in basic equipment. Step 3: Develop written procedures specific to your equipment. Step 4: Partner with experienced consultant for initial inspections and procedure validation. Step 5: Obtain ASNT certification for all personnel. Professional support accelerates capability development and reduces learning curve.

Conclusion

Corrosion Mapping and Multiple NDE Methods is a powerful inspection tool when properly understood, implemented, and applied. Successful programs require investment in equipment, personnel training, procedure development, and ongoing quality assurance. Staying current with emerging technologies, refining procedures based on field experience, and engaging with industry best practices ensures superior results and maximum value from your inspection investments.

Next Steps: Assess your facility's inspection needs, evaluate this technique's applicability to your equipment, invest in training and certification for your team, and develop comprehensive procedures. Connect with training providers, consulting experts, and certification programs to build capability and maximize inspection program effectiveness.

Running this as a programme, not a one-off

If you are responsible for an inspection programme rather than a single job, the recurring problem is rarely the code — it is keeping measured thickness, damage-mechanism assignment and next-inspection dates in one defensible place. Asset integrity management software covers keeping measured thickness readings per CML in one place, so the RBI (API 580/581) and fitness-for-service (API 579) work your integrity team or its specialists carry out starts from measured data rather than default rates. Atlantis supplies the NDT data and the software to hold it; it does not perform RBI or FFS assessments.

Atlantis NDT Products & Services

What is corrosion mapping?

Corrosion mapping is an area thickness survey. Instead of single readings at a few points, the technician scans a defined area and records wall thickness at every position on a fine grid, tied to a fixed datum. The output is a colour C-scan plus a data file showing where the minimum wall is, how large the thinned area is, and whether the loss is general, pitting or grooving. Screening methods find where to look; ultrasonic mapping measures what is left.

Which NDT method maps which kind of corrosion

No single method finds, sizes and trends every corrosion pattern. Ultrasonic thickness is accurate but local. Screening tools cover distance quickly but report an indication, an average or a grade, not a wall thickness you can calculate with. So the usual sequence has three steps: screen to find where loss is concentrated, map the flagged areas with encoded ultrasonics, then verify the minimum before it goes to the inspector. The table shows how a Level III matches methods to the job. The "Output" column tells you whether a method gives a thickness or only a place to look.

Method	What it measures	Output	Best use	Main limits
Manual UT thickness (dual-element probe)	Wall thickness at a point or on a hand-laid grid	A thickness value per point	CML readings, rough or hot surfaces, verifying a mapped minimum	Misses pits between grid points; location scatter between campaigns
Encoded UT or PAUT 0° C-scan	Thickness at every scan position across an area	C-scan image plus an exportable thickness grid	Vessel shells and heads, elbows, tank shell courses, injection points	Needs contact and surface preparation; insulation must come off
Motorised crawler mapping	Same as encoded UT, over large or elevated areas	Large C-scan mosaics	Vessel shells, tank walls, long straight runs	Set-up time; magnetic wheels need a steel surface and a clear path
Guided wave screening	Changes in pipe cross-section over distance from one transducer ring	Located indications, graded by severity	Long runs, pipe racks, road crossings, insulated lines	Gives no remaining wall; range and sensitivity drop at bends, fittings and heavy coatings
Tank floor MFL	Flux leakage from metal loss in floor plates	Indications by plate and location	Full-floor screening during internal tank inspections	Flagged areas need UT prove-up to get a thickness
Pulsed eddy current	Average wall over a footprint, through insulation and jacketing	Average wall per grid point	Screening for corrosion under insulation without stripping	Averages out small pits; the footprint grows with insulation thickness
Profile radiography	Pipe wall seen at the tangent of the image	Image with measured wall at the tangent points	Small-bore and insulated lines, deposits, blockages	Radiation controls and exclusion zones on a live unit
Eddy current on tubes	Wall loss and cracking in heat exchanger tubes	Per-tube signal analysis	Non-ferrous tube bundles	Ferrous tubes usually need a different tube technique
Visual (VT)	Surface condition, coating breakdown, deposits, leaks	Photos and condition notes	Pointing mapping at the right area; external and internal inspections	No thickness; cannot see hidden surfaces

Atlantis crews deliver UT thickness and CML surveys, encoded corrosion mapping, phased array inspection, TOFD, MT, PT, VT, eddy current, tank-floor MFL and guided-wave screening. Radiography is performed by licensed radiography crews. If your scope needs a technique outside that list, we tell you at the quote stage. All work runs under ASNT NDT Level III oversight, with ASNT-certified technicians. To scope a survey, request an inspection quote.

How a corrosion mapping test runs, step by step

A corrosion mapping test is a short sequence, not one measurement. Most of the value comes from the steps before and after the scan.

Define the question. Name the credible damage mechanism (general thinning, pitting, grooving, liquid-level attack, CUI) and the code the result feeds: API 510, 570 or 653. The mechanism sets the resolution.
Screen. Use visual inspection, guided wave, MFL or existing CML trends to choose where to map. Record why each area was chosen.
Write the scan plan. Area boundaries, datum, scan direction, resolution, probe, couplant and temperature range, fixed in a Level III-approved procedure and technique sheet.
Prepare the surface. Remove loose scale and failed coating. Sound coating can stay if the technique measures through it, such as echo-to-echo mode, and the report says so.
Calibrate on the real material. Set sound velocity on a block of the same material, or on a known thickness on the component, at a similar temperature. Record a check before and after the scan.
Mark the datum. Tie the area to a fixed feature such as a nozzle centreline or a weld seam, with photos, a sketch and measured offsets. This step decides whether the next survey can be compared with this one.
Acquire. Scan with encoded position. Watch for coupling dropouts and lost encoder counts. Re-scan gaps before leaving the area.
Check coverage. Confirm the scanned area matches the plan and that data dropouts stay within the limit the procedure sets.
Analyse. Locate the minimum, the extent of the area below an agreed threshold, and the pattern of loss. Check whether low readings are true wall loss or mid-wall reflectors such as laminations, inclusions or hydrogen blistering.
Verify. Prove up the minimum with a manual dual-element reading. If the pattern looks like cracking rather than thinning, flag it for angle-beam UT, PAUT or TOFD. A 0° thickness scan does not size cracks.
Report and hand over. Send the C-scan, the grid file, the minimum and its location, and the datum record to your inspector of record.

Steps 1, 6 and 10 are the ones most often skipped under turnaround pressure. They are also the steps that decide whether the map is still useful in five years.

Automated corrosion mapping systems and equipment

A corrosion mapping system is more than a flaw detector. These are the parts that matter if you are deciding whether to buy, rent or hire:

Instrument. A UT or PAUT unit that records encoded data to a file, not one that only displays a reading.
Probe. Dual-element probes suit rough, pitted or hot surfaces. Linear arrays cover a wide strip in one pass. Water-column and wheel probes help keep coupling on uneven surfaces.
Scanner. A one-axis encoded wand suits small patches. A two-axis raster scanner suits defined areas. Magnetic crawlers suit large shells and tank walls. Chain or band scanners suit pipe circumferences.
Couplant feed. Usually water pumped to the probe face. Gel works for small manual areas.
Software. C-scan and B-scan views, thickness thresholds, and export of the thickness grid to a spreadsheet or an inspection database.
Reference blocks. Step wedges or blocks of matching material for velocity and zero checks.

Manual, semi-automated or automated? Manual encoded scanning suits small patches and congested nozzle areas. Semi-automated scanning, where the technician pushes an encoded scanner, covers most piping and vessel patches. Motorised crawlers earn their set-up time on large shells, tank walls and long runs. Many surveys use all three on one asset.

Buying versus hiring. The instrument is rarely the largest cost. Owners who map in-house also need technicians certified in UT and PAUT under a written practice, a Level III to approve procedures, and a way to compare data between campaigns. Atlantis trains technicians to ASNT SNT-TC-1A Level I, II and III, self-paced online or onsite at your facility. Request a training plan.

Hull and subsea corrosion mapping: what changes

Hull corrosion mapping, usually called thickness gauging, is a regulated job when it supports a ship's class survey. Classification societies accept thickness measurements from firms they have approved as service suppliers under IACS Unified Requirement Z17. On most surveys a class surveyor is involved in planning the measurements and witnessing them. Readings go into the society's own report format. The amount of gauging grows with the ship's age and the survey type. If you need class gauging, start with the approved-firm list published by your ship's class society.

Subsea corrosion mapping uses probes deployed by divers or remotely operated vehicles, often alongside cathodic protection readings. It is specialist marine work with its own qualification schemes and vessel spread.

Atlantis's mapping work covers onshore plant equipment: pressure vessels, piping, storage tanks and plant structures. The data rules in this article still apply to hull and subsea work: use a datum, set resolution for the damage, verify the minimum and keep the raw data.

What a corrosion mapping service should deliver

A report that shows only a colour picture is not enough to support an inspection decision. Before you award "corrosion mapping services", compare bids against this list.

Deliverable	What it contains	Why you need it
C-scan images	Thickness colour map with a stated scale, area ID and orientation	Shows the pattern of loss at a glance
Thickness grid file	Every reading with its scan and index position, in a format you can import	Lets the next campaign subtract one map from another
Minimum thickness and location	Lowest verified reading with coordinates from the datum	The number your inspector uses for remaining life
Extent below threshold	Length and width of the area under an agreed thickness	Separates a local pit from broad thinning
Datum record	Sketch, photos and measured offsets to fixed features	Lets a different crew rescan the same area
Procedure and technique sheet	Probe, settings, resolution, couplant, calibration checks	Makes the result reproducible and auditable
Personnel and equipment records	Technician certifications, instrument calibration, Level III review	Answers the first questions an auditor asks
Campaign comparison	Change since the last map, where you supply earlier data	Turns a snapshot into a corrosion rate
Follow-up notes	Areas to verify, re-scan or examine with another method	Gives the inspector a clear next step; the decision stays with the inspector

Atlantis issues these in its own NDT reporting software, with each reading tied to the asset, procedure, technician and instrument. Maps can also be placed on a 3D model of the asset in our Digital Twin platform, so engineers see thickness history in context. See Digital Twin reporting.

US code overlay: where the numbers go

A corrosion map is evidence. The codes decide who uses it and how.

Pressure vessels, piping and tanks. API 510 (11th edition, 2022), API 570 (5th edition, February 2024) and API 653 (now with Addendum 4, July 2025) put the inspection programme with the owner-user. Corrosion rate, remaining life and the next inspection date are set by the owner's inspector. Atlantis delivers the NDE to your API Authorized Inspector, who stays inspector of record.
How to inspect. API RP 572 (vessels), API RP 574 (piping) and API RP 575 (tanks) describe inspection practice. For the ultrasonic thickness technique itself, see our note on ASME Section V Article 5 thickness measurement.
Process safety. For processes covered by OSHA's process safety management standard, 29 CFR 1910.119(j) expects inspection and testing to follow recognised and generally accepted good engineering practice, with each inspection documented. A mapped area with a datum and a stored grid is easier to defend than spot readings.
Fitness-for-service. When a map shows local metal loss below the required thickness, the owner's engineer may run an assessment to API 579-1/ASME FFS-1. That assessment uses thickness profiles taken from the grid. Atlantis does not perform fitness-for-service or risk-based inspection assessments. We supply the grid in the form an assessor needs.

Canada notes. Provinces regulate pressure equipment, generally adopting CSA B51 through bodies such as ABSA in Alberta, TSSA in Ontario and Technical Safety BC. Many owner specifications ask for NDT personnel certified to CAN/CGSB-48.9712. The CGSB closed on 1 April 2026. NRCan's NDT Certification Body continues and issues CAN/CGSB-48.9712 certification. Check which certification your owner specification names before mobilising.

Common mistakes in multi-method corrosion programmes

Treating a screening result as a thickness. Guided wave grades, MFL indications and pulsed eddy current averages tell you where to look. They are not a remaining wall.
Reporting the area average. Remaining life is driven by the minimum in the governing area, not the mean of the map.
Using a grid too coarse for the damage. A coarse grid can step right over a pit. Set resolution from the expected damage, not from the time available.
Mapping without a datum. Painted boundaries do not survive a turnaround. Without a datum, the next map cannot be compared with this one.
Ignoring temperature. Sound velocity in steel falls as temperature rises, so hot readings taken with a cold calibration read thicker than the real wall.
Mixing methods in one trend. A pulsed eddy current average and an ultrasonic minimum are different quantities. Trend each method against itself.
Keeping screenshots, not data. Without raw files and the grid export, no one can re-analyse the survey.
Mapping the convenient area. Low points, dead legs, injection and mix points, liquid levels and damaged insulation are where corrosion concentrates. Map them first. See corrosion under insulation inspection for the CUI side.

How to choose a corrosion mapping provider

This checklist is for integrity and QA/QC leads at refineries, chemical plants, gas plants, terminals and tank farms. Smaller plants with a few vessels can use it too. Ask each bidder:

Which methods will you use to screen, which to measure, and why?
Is the procedure approved by an ASNT Level III, and will we receive the technique sheet?
Are the technicians certified in UT and PAUT under a written practice to ASNT SNT-TC-1A?
What scan resolution will you use, and how does it match the expected damage?
Do we get the raw data files and a grid export, or only a PDF?
How will a different crew find the same area next time?
Who reviews the data before release, and how do urgent findings reach our Authorized Inspector during the shift?

Atlantis is based in Houston and mobilises crews to client sites. We have completed 1,500+ inspection activities, and we return a quote once we have your scope. Our corrosion work links to the main corrosion mapping inspection service and the wider inspection services hub. State pages cover local codes and regulators: Texas, Louisiana and California. If you need the scan plan or the procedure reviewed before the job, talk to a Level III.

Frequently asked questions

What is a corrosion mapping test?

It is an encoded ultrasonic scan of a defined area that records wall thickness at every grid position, tied to a datum. A complete test includes the scan plan, calibration on matching material, coverage checks, verification of the minimum and a report with the grid file. It is not a single reading.

What do corrosion mapping services include?

Area selection, encoded UT or PAUT scanning, analysis and verification of the minimum, plus the deliverables in the table above. The grid file and the datum record are the two items most often left out.

What is automated corrosion mapping?

It is mapping where a motorised scanner or crawler moves the probe and records position automatically. It suits large shells, tank walls and long runs where coverage and repeatability matter. Semi-automated scanning, where the technician pushes an encoded scanner, covers most smaller areas.

What equipment is used for corrosion mapping?

An encoded UT or PAUT instrument, a dual-element or linear array probe, a scanner, a water couplant feed, software that exports the grid, and reference blocks.

Which NDT methods are best for corrosion detection?

Use screening methods to detect and locate corrosion: visual inspection, guided wave for pipe runs, MFL for tank floors and pulsed eddy current through insulation. Then use ultrasonic thickness and encoded mapping to measure what is left. Profile radiography helps on small-bore insulated lines. Eddy current suits non-ferrous exchanger tubes.

How is hull corrosion mapping different from plant corrosion mapping?

Ship hull gauging for class must be done by a firm approved by the classification society under IACS UR Z17, with surveyor involvement and the society's report format. Plant mapping on vessels, piping and tanks is governed by the owner-user's API 510, 570 or 653 programme instead.

How often should a mapped area be re-scanned?

The interval is set by your inspector under API 510, 570 or 653, based on the corrosion rate and remaining life. The map's job is to make that rate reliable. Rescanning the same area from the same datum gives a far better rate than comparing scattered spot readings.

Does Atlantis calculate remaining life from the map?

We report thickness data and, where you provide earlier data, the change between campaigns. Corrosion rate selection, remaining life and the next inspection date stay with your Authorized Inspector and engineers. For piping circuits, see piping circuit inspection and CMLs.

Need this carried out?

Atlantis provides this as an inspection service, alongside ASNT SNT-TC-1A training and Level III consulting.