Pipeline operators face ongoing threats from corrosion and other anomalies in buried pipelines. To manage integrity, two primary assessment methods are employed: Inline Inspection (ILI) and External Corrosion Direct Assessment (ECDA). Both are formally recognized by regulators (e.g., PHMSA 49 CFR Parts 192/195, CSA Z662, NACE SP0502) as valid integrity assessment techniques.
ILI tools (sometimes called “smart pigs”) physically traverse a live pipeline to collect data on wall condition.
ECDA is a structured, four-phase process that uses above-ground surveys and targeted digs to assess external corrosion. Each method has advantages, limitations, and suited use-cases. The sections below compare ILI and ECDA in terms of typical applications, cost, reliability, and regulatory requirements, with a summary table and guidance for choosing the appropriate method.
Inline Inspection (ILI)
Overview: ILI refers to running instrumented “smart PIGs” through the pipeline during service. These devices house nondestructive testing sensors (e.g., Magnetic Flux Leakage (MFL), Ultrasonic Testing (UT) and geometric “gauge” tools) that measure wall thickness, detect metal loss, cracks, dents, and other anomalies.
A smart pig is launched and retrieved via special fittings (launchers/receivers) and uses the pipeline’s product flow for propulsion, so inspections can often be done without a full shutdown.
Capabilities: Modern ILI tools provide comprehensive, high- resolution data on pipeline integrity. For example, MFL pig detects corrosion pits and quantify metal loss, while UT pig precisely measures remaining wall thickness and even image cracks. A well-executed ILI run anomalies maps by location and size along the entire inspected length.
This data allows operators to prioritize repairs or replacements before failures occur. As one integrity review notes, “periodic [ILI] assessments… help mitigate risks by enabling detection and control” of corrosion and defects. In practice, ILI is the most direct means to assess both external and internal corrosion (if a liquid is present) and is typically required on high-pressure transmission pipelines where feasible.
Advantages: Key advantages of ILI include non-intrusive operation (no prolonged shutdown), extremely detailed inspection data, and automated mapping of defects. Inline tools provide quantitative wall-thickness and anomaly sizing, supporting preventive maintenance. By catching defects early, ILI can reduce unplanned outages and environmental incidents. Many operators find ILI “cost-effective” in the long run because it limits emergency repairs.
Limitations: ILI requires a piggable pipeline. This means the line must be of sufficient diameter (typically ≥4 inches), have internal geometry compatible with pigs (no complex constrictions or unmapped elbows), and allow pig launching/ receiving. Non-metallic pipe segments, severely corroded casings, or unbarred tees/valves can block pigs.
Preparing a pipeline for ILI also adds cost: it often requires cleaning (“dirt pigs”) and line passages, plus dedicated personnel. As one industry study notes, “the cost of inline inspection can be high;” expenses include pig runs, extra personnel, production downtime, and the inspection tool itself.
These costs mean ILI is usually done on major transmission lines at multi-year intervals which may not fulfill corporate or jurisdictional minimum inspection requirements.
Reliability: When conducted properly, ILI is highly reliable for detecting and quantifying pipeline defects. Inline tools must be qualified (e.g., per API 1163) and their performance validated, but they are generally the best way to find small corrosion pits and cracks over long distances.
The downside is that if a pig does not transit or if the tool is unsuitable for a given pipeline, the inspection may be incomplete. Also, ILI typically cannot inspect extremely small diameter lines or pipe legs, and by definition it only assesses areas the pig can reach.
External Corrosion Direct Assessment (ECDA)
Overview: ECDA is a four-phase structured process focused on external corrosion threats. It is outlined in NACE SP0502/NACE SP0504 (now under AMPP) and recognized by regulators. In brief, ECDA involves:
Pre-Assessment (data gathering and region identification)
- Pre-Assessment (data gathering and region identification)
- Indirect Inspection (above-ground surveys such as close-interval potential surveys, DCVG/ACVG, and soil testing)
- Direct Examination (targeted excavations of the pipe at locations indicated by indirect tools)
- Post-assessment (analysis and reporting).
The goal is to “assess and reduce the impact of external corrosion on pipeline integrity.” By locating existing corrosion activity and enabling repairs, ECDA helps prevent defects from growing unchecked. It is typically repeated cyclically (e.g., every 5–7 years) as part of the integrity management plan.
Capabilities: ECDA uses indirect techniques to find potential corrosion. For example, Close Interval Surveys (CIS) measure cathodic protection (CP) effectiveness, DCVG/ACVG detect coating “holidays” and anomalies, and soil resistivity/pH tests gauge corrosivity.
These data are analyzed to flag pipeline regions of concern. In the direct examination phase, the operator then excavates at high-risk spots, inspects the coating, measures corrosion damage and remaining thickness, and evaluates CP performance.
The combination of survey data and confirmatory digs enables operators to identify actual corrosion defects and “fix them” while addressing root causes. Afterward, a post-assessment report documents findings and sets re-assessment intervals.
Advantages: ECDA can be done without taking the pipeline out of service. (According to Matcor, “Unlike inline inspection, ECDA does not require shutting down the pipeline, making it a more efficient and less costly option.”) It is often the only practical choice for pipelines that cannot be pigged – e.g., very old lines, small- diameter distribution mains, lines with “unpiggable” fittings or tight bends.
ECDA is mandated or allowed by regulations in such cases. It provides targeted corrosion monitoring along buried pipes, and by focusing on electrical signals it can highlight hidden coating failures that might be missed by random digs alone.
Limitations: ECDA does not directly inspect the entire pipe wall. Its accuracy depends on selecting and analyzing indirect indicators; zones with no alarming signals might still have hidden defects. In addition, ECDA requires multiple phases of work (data gathering, surveys, excavation crews) and involves digging up the pipe at numerous points, which adds complexity and cost.
The labor and resources for soil surveys, data interpretation, and excavation can be significant. If indirect tools miss a corrosion site, the defect can only be caught later in a subsequent cycle. Therefore, ECDA results must be carefully validated; in practice the “direct examination” digs are the final confirmation of any identified anomalies.
Use Cases and Scenarios
Piggable Transmission Pipelines: For long, high-pressure oil/gas pipelines of sufficient diameter and with well-defined launchers, ILI is usually preferred. Such pipelines benefit from the high resolution “picture” of wall condition that ILI provides. For example, a gas transmission line in corrosive soil will be pigged with MFL/ UT tools to catch external corrosion “hot spots” along hundreds of miles.
Inline data allows operators to plan repairs precisely and to maintain safe operation with minimal unplanned downtime.
Unpiggable or Small Pipelines: ECDA shines on pipelines where smart pigs cannot go. Distribution pipelines (smaller diameters, many service taps or bends) often use ECDA to meet integrity requirements. Similarly, cross-country pipelines that have certain unpiggable sections (e.g., many block valves, complex geometry, or legacy casings) may use ECDA on those segments.
As one corrosion consultant notes, “inline inspection can be limited due to pipeline geometry; in these situations, an ECDA program is necessary to meet government regulations.”
ECDA is also used on short special sections (casings, road, or river crossings) where pigging is not feasible. Essentially, any pipeline segment that regulators deem externally corrodible but cannot be fully pigged often uses the ECDA process.
High-Consequence Areas (HCAs): PHMSA’s integrity management rules permit either ILI or DA as a reassessment method for HCAs. For some urban pipelines or critical feeders, an operator might choose ECDA to minimize the risk of large-scale shut-ins, or ILI if the pipeline is fully piggable.
The PHMSA gas rule explicitly recognizes that DA (including ECDA) “is needed where ILI or hydrostatic pressure testing cannot be used,” and it can serve as an “effective, equivalent alternative to ILI” in certain cases. In practice, operators often use risk assessments to decide whether pigging or DA best mitigates the threats to each pipeline segment.
Regulatory Standards: Both methods are governed by industry and government standards. NACE SP0502 (now ANSI/AMPP SP0502) specifies the ECDA process. API documents (such as API 1163 for ILI tool qualification, and API 1160 for liquid pipeline integrity management) provide guidance on performing inline inspections and integrity programs.
CSA Z662 (Canadian Oil & Gas Pipeline Systems) and PHMSA regulations (49 CFR 192.925 for gas, 195.452 for liquids) permit ECDA as an alternate integrity assessment method. In summary, either ILI or ECDA (when done according to standards) can fulfill regulatory requirements if applied correctly.
Comparison: Inline Inspection (ILI) vs External Corrosion Direct Assessment (ECDA)
| Criterion | Inline Inspection (ILI) | External Corrosion Direct Assessment (ECDA) |
|---|---|---|
| Technique | Internal inspection using smart pigs (in-line tools run inside the pipeline) | External evaluation using indirect surveys and selective excavation |
| Coverage | Full-length coverage of pipeline interior | Selective, based on indirect survey results and risk segmentation |
| Data Accuracy | High accuracy with quantified measurements (defect size, location, and depth) | Moderate accuracy; relies on indirect indications and spot checks |
| Detectable Anomalies | Metal loss, cracks, geometric deformities, and weld flaws | External corrosion, coating degradation, and soil/environment interactions |
| Pipeline Requirements | Pipeline must be piggable with launch/receive facilities | Suitable for non-piggable pipelines |
| Preparation Required | Cleaning, tool selection, and coordination for launching and receiving tools | Pre-survey planning, indirect inspections, and possible right-of-way digs |
| Data Output | Detailed digital reports with GPS coordinates and defect sizing | Risk-ranked dig sites and qualitative assessment of coating/corrosion |
| Cost | High initial cost, efficient for large segments | Lower initial cost but may increase with extensive excavations |
| Regulatory Acceptance | Strong—widely accepted in industry and regulation (API 1163, PHMSA, etc.) | Accepted per NACE SP0502, but requires validation with direct assessment |
| Limitations | Not applicable for unpiggable, small-diameter, or complex geometry pipelines | Less accurate for internal defects and requires physical access to dig |
| Risk Mitigation | High—precise defect detection supports proactive maintenance | Moderate based on inferred conditions, relies on assumptions |
Selecting the Appropriate Method
Choosing between ILI and ECDA depends on pipeline characteristics, location, and risk profile:
Pipeline Type & Geometry: If the line is piggable (adequate diameter, mostly straight, with launchers), ILI is generally preferred for its thoroughness. For unpiggable segments (e.g., small diameter, many valves, or difficult routing), ECDA becomes necessary. For example, distribution mains and older gathering lines often rely on ECDA.
Location and Impact: In high-consequence or densely populated areas, minimizing downtime is critical. ECDA’s ability to inspect without a full shutdown is a major advantage. Conversely, in remote or easily isolated areas, operators might schedule an ILI run since the impact of a short outage is manageable and the data return is high.
Corrosion Risk: For pipes exposed to aggressive external environments (e.g., very corrosive soil, high humidity), regular ILI (to catch external corrosion) may be combined with ECDA (to double-check any areas of concern). In cases of internal corrosion threats (due to water or impurities in the fluid), ILI also detects metal loss inside the pipe, whereas ECDA does not address internal corrosion.
Regulatory Requirements: If regulations allow multiple options, follow a risk-based approach. A gas transmission operator, for instance, might use ILI for most of the line but plan ECDA in segments where launching a pig is impractical. PHMSA guidance explicitly notes that DA (including ECDA) “may be used as a primary or supplementary method” alongside ILI.
Recommendations
Large-Volume Transmission (Piggable): Use ILI for baseline and reassessment (e.g., MFL/UT runs every 5–7 years). Supplement with ECDA on any non-piggable sections or high-risk tie- ins.
Small or Distributed Systems (Unpiggable): Implement a regular ECDA program per NACE SP0502 (with periodic digs). Where budget allows, consider occasional ILI-like inspections using innovative tools (e.g., tethered crawlers) or substitute ILI for larger laterals.
Mixed Systems: Hybrid strategies are common. For example, piggable mainline sections may be pigged, while lateral lines or plugged sections undergo ECDA. A decision matrix could be: “Is the pipeline segment >4′′ and largely straight with pig launchers? If yes, favor ILI; if no, conduct ECDA.”
Validation and Follow-Up: Regardless of method, always inspect any indications of defects. ECDA’s excavations and any anomalies from ILI data should be validated by engineering analysis (e.g., remaining strength calculations) and repair criteria (ASME B31G or RSTRENG methods).
In summary, Inline Inspection delivers the most detailed integrity data on piggable pipelines, but at a higher cost and preparation effort. ECDA offers a less intrusive, regulatory- compliant alternative for detecting external corrosion where pigging is impractical.
The optimal approach often uses both: ILI for comprehensive coverage, and ECDA to fill gaps and verify external corrosion threats. Operators should weigh pipeline design, environment, and risk to select the method (or combination) that best balances cost, reliability, and operational constraints.
This article was developed by specialist Dushyant Kale and published as part of the fifth edition of Inspenet Brief magazine August 2025, dedicated to technical content in the energy and industrial sector.
