Flow Accelerated Corrosion (FAC)


Flow accelerated corrosion (FAC), also termed flow assisted corrosion, is a phenomenon wherein carbon steel components with a protective film oxide degrade over time. FAC occurs only when the fluid is moving (not static), when it contains water, and is unsaturated in iron.

It is imperative to understand FAC since it is different from simple erosion — the mechanisms of these two processes are different. In short, FAC does not require particle impingement, cavitation or bubbling, which produce crater-like wear. The dissolution of the protective oxide layer that is typically poorly soluble is achieved through various means like the combination of mass transfer, water chemistry and electrochemical actions.

Flow accelerated corrosion (FAC) is mostly observed in steam lines in power plants, components made up of carbon steel, tubing and vessels that are exposed to flowing water (single-phase) or wet steam (two-phase). The most vulnerable areas of FAC include bends/elbows, tees, orifices, and any location where turbulent flow exists. In fact, FAC can be modeled as a turbulent mass transfer process [1].

In carbon steels, FAC occurs under well-known and specific parameters. The primary parameters include pH value, oxygen content, temperature and water velocity. Two major methods for avoiding or at least significantly mitigating this issue in operating plants are available. Often, the easiest method is to change the water chemistry by raising its pH and creating an oxidizing environment. If this is not sufficient, or if other factors e.g., presence of copper-alloy components prevent this, it may be inevitable to replace carbon steel tube sections facing wear with a more resistant material, such as low-alloy steel containing some chrome [2].

The major non-destructive testing challenges in inspecting for flow accelerated corrosion are:

· Steam-lines operate at elevated temperatures like 450 to 500, making in-service nondestructive testing (NDT) difficult

· Considerable downtime due to removal of insulation and re-insulation post-inspection required for nondestructive testing (NDT)

· FAC is an internal wall loss phenomenon that requires ultrasonic thickness testing (UTT), pulsed eddy current testing (PECT), and/or remote visual inspection (RVI) for detection

· Shutdown is mandatory for nondestructive evaluation (NDE)

FAC inspection using PECT and UTT

The Pulsed Eddy Current Testing (PECT) technology was originally developed and patented by Shell Oil & Gas in the 1990s. The PECT method measures the differences between the conductivity and permeability of different metals, and the quantity of those metals in comparative readings. Typically, a test involves inspecting the insulated component, identifying a consistent area of thicker metal, and place the reference point (RP) in the middle of that area. The client has to make this area accessible for inspection by removing the insulation so that an Ultrasonic Thickness Testing (UTT) can be performed and used as a RP for normalization. As a result, some limited insulation removal is often required to quantify metal loss with PECT. Subsequently, the software normalizes the dataset, and compares all data to the RP thickness, converting them all from a percentage to an average wall thickness. Figure 1 shows an example PECT grid marked out on a steam line elbow. Figure 2 shows and example UTT grid marked out on a steam line elbow.

Figure 1: Example pulsed eddy-current grid marked up on a 10” steam line.

Figure 2: Example ultrasonic thickness testing grid marked up on a 10” steam line.

FAC inspection using RVI

Remote Visual Inspection (RVI) is a subset of Visual Testing (VT) which involves the use of camera(s) mounted on a robot/drone to inspect tight and (often) impossible to reach sections. In this case, a remotely operated robot with a high resolution camera and high-intensity lighting system is used to maneuver through straight and elbowed sections of pipe. Example images are provided below in Figures 3 and 4. In many instances, the steam line pipe inside diameter is contaminated with scale and sludge that impacts robotic mobility and direct visual access to the desired surface inspection. Varying degrees of scale and sludge build-up are shown below. In Figure 3, it is impossible to inspect the pipeline due to volume of the scale and sludge. In Figure 4, approximately 60% of the surface is inspectable. Therefore, there is some inherent risk that taking the steam line out of service for robotic RVI inspection may not yield meaningful results.

Figure 3: Straight section of pipe starting at 2.4 ft. Approximately 10% ID observable.

Figure 4: 90-degree elbow observed at 12.4 ft. Only 60% of the ID observable. Remaining surface inhibited by deposit/corrosion buildup

Figure 4 shows a 90-degree elbow that was inspected using RVI. Significant deposition can be observed in the figure. Deposition is a major concern in steam lines, and steam generating equipment in general. The coalescing of material causes overheating and can also result in corrosion by association. Advances in boiler performance have allowed the use of ultrapure water to be fed to such systems, however, purification to this level requires a significant overhead expense [3].

The most common contaminants include elements like magnesium, copper, calcium, iron, aluminum, and compounds like silica, silt (mixture), and oil. Most deposits can be categorized as either (1) scale that crystallized directly or (2) transported by flowing water, having originated elsewhere [3]. Scale is caused by salts that have limited solubility — however not completely insoluble (in boiling water). The salts will precipitate via evaporation on-site and have a fairly homogenous composition and crystal structure. It is important to remember that the composition of scale will vary from boiler to boiler — calcium silicate in one and sodium iron silicate in another.

The crystallization of scale is a slow process, thereby hard and dense, which makes some forms of scale extremely hard to remove via any treatment. In a similar vein, sludge deposits baked in place due to high temperatures can also be tenacious — resisting removal, including chemical treatment. The formation of sludge is via a different mechanism however, chiefly advection.


Pulsed eddy current testing (PECT), ultrasonic testing (UTT), and remote visual inspection (RVI) are three candidate nondestructive testing (NDT) methods for flow area corrosion (FAC) detection in steam lines. PECT is performed from outside surface and required minimal insulation removal which is a tremendous cost benefit. There are some limitations to PECT including volumetric and a large footprint. Ultrasonic thickness testing (UTT) can be performed independently or at select locations based on PECT test results. UTT limitations include the requirement for insulation removal and density of grid required for meaningful coverage. Remote visual inspection (RVI) with a robotic crawler is effective on uncontaminated pipe with a convenient insertion point. There is some inherent risk that taking the steam line out of service for robotic RVI inspection may not yield meaningful results.


[1] https://www.epri.com/research/products/1015072

[2] https://tetra-eng.com/en/resources/technical-white-papers/30-white-papers/198-fac

[3] https://www.suezwatertechnologies.com/handbook/chapter-12-boiler-deposits-occurence-and-control

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