What is Pipeline Corrosion?

The definition of pipeline corrosion is no different from the corrosion of any other structural material. It is defined as the chemical or electrochemical reaction of a material with its environment, resulting in the deterioration of that material. With respect to a pipeline, there are internal and external environments that can differ significantly and present various corrosion mechanisms that require assessment and management. In most cases, corrosion of pipelines occurs in the aqueous (water) phase, thus an electrochemical reaction predominates.

External Corrosion

External Corrosion

Externally, pipelines suffer from corrosion due to electrical interference and general exposure to moist oxygenated soils, as well as microbial corrosion in anaerobic soils. External corrosion typically results from a combination of coating imperfections, coating degradation and inadequate levels of cathodic protection (CP) reaching the pipe surface.

Even new coatings are not perfect and it is known within the industry which coatings have different issues and degrade fastest. Having seen many data sets relative to coating failure in many different environments (noting for example that even a very good FBE coating may allow isolated deep corrosion pits due to stray current effects), ROSEN has greater knowledge and experience in this area.

A particularly challenging threat is CP shielding, where protection is nominally within specification, but corrosion is active. The best way to identify this is by comparison of repeat in-line inspection (ILI) data, allowing identification of shielding areas where protection levels are within limits but corrosion anomalies are found to be growing. It is known which coating types are ‘shielding’ (for example tape wrap) and which are not, with a commonly susceptible area being the field joints

The time dependence of pipeline material deterioration can therefore vary greatly due to the many factors that influence the corrosion reaction. With pipelines (and other structural assets) there are stresses (e.g. internal pressure loading, external soil loading) exerted on the pipeline material. These stresses, when combined with corrosion, can lead to more severe forms of localized corrosion phenomena, such as stress and fatigue corrosion cracking. Other less common challenges resulting in external metal loss that needs to be diagnosed in order to formulate the necessary integrity response, include AC/DC interference related damage, lightning strikes and bullet impact.

Internal Corrosion

Internal Corrosion

For internal corrosion, sweet (CO2) and sour (H2S) products along with oxidation and microbial activity, present the most common aqueous corrosion problems. Very rarely, high-temperature corrosion mechanisms are encountered in oil and gas transmission and distribution pipelines. Corrosion in pipelines can manifest as localized and/or uniform forms of attack. Which one prevails is highly dependent on the environmental conditions (i.e. temperature, flow rates, composition etc.) to which a pipeline is exposed, as well as the subsequent corrosion mechanism itself.

There are numerous types of corrosion phenomena, which are distinguished according to material, cause and appearance.

Pipeline Corrosion


Principal Corrosion Anomalies, Terms and Definitions

Corrosion engineers use numerous descriptions, terminologies, and acronyms to explain the various corrosion phenomena associated with pipelines. In addition, standards are available and provide guidelines on corrosion definitions. However, this section presents only the more common terms used in the pipeline industry, which in themselves are not exhaustive.

The focus is corrosion; however, to provide a distinction from other unintended metal loss anomalies introduced in the mill, during construction or in-service, other metal loss anomalies are also addressed. While these may be non-corrosion in origin, some can lead to further damage in service due to them promoting corrosion.



Cavitation is considered a special form of Erosion-Corrosion, resulting from the formation of vapor bubbles in the fluid at low pressure regions. These bubbles collapse due to fluctuations in fluid pressure, when it is greater than the vapor pressure of the fluid. The collapse of the vapor bubbles generates shock waves that have a high impact force on the adjacent pipe surface and can result in work hardening, fatigue and cavitation type pitting damage. The high impact forces can cause corrosion inhibitor film stripping and can also remove protective corrosion scales and internal coatings. Cavitation damage often appears as a collection of closely spaced, sharp-edged pits or craters on the surface.

Channelling Corrosion

Channelling Corrosion

Channelling corrosion is a more recent term used to describe the appearance of long axial pipeline corrosion that results in a groove
(or “channel”) in the bottom of a pipeline. It is not considered a corrosion mechanism as such, but is the result of the conjoint action of corrosion and erosion (or flow assisted) mechanisms. It is usually associated with the presence of particulates within the product that remove the corrosion product and thus repeatedly expose bare metal, resulting in higher average corrosion rates. The more aggressive cases are noted in water injection pipelines, where loss of microbial and oxygen control has occurred, and high flow velocities are often present.

Corrosion Fatigue

Corrosion Fatigue

Corrosion fatigue is the acceleration of a fatigue failure resulting from the material being exposed to a corrosive media. In the situation where a material is subject to a cyclic or alternating stress in a corrosive environment, the number of cycles to failure can be significantly reduced. Additionally, the corrosion fatigue failure can occur at lower loads than the mechanical fatigue failure. The final rupture in a corrosion fatigue failure is a brittle fracture and the cracks are more often transgranular in nature, as in stress corrosion cracking, but not branched.

Corrosion Under Insulation

Corrosion Under Insulation (CUI)

Corrosion under insulation (CUI) is commonly associated with aboveground pipelines. There are onshore buried and insulated lines that suffer from CUI, but not many (if any) subsea pipelines. CUI is the corrosion that occurs under both thermal and acoustic insulation due to the presence of free water containing dissolved ionic species. It occurs when water penetrates the insulation, e.g. due to failure of water retention of the insulation or as a result of condensation of humid air. With all the ingredients for corrosion and warm temperatures that accelerate corrosion reactions, it is understandable why CUI is problematic and can result in severe corrosion rates and undesired surprise failures. The presence of the insulation means that CUI can go undetected using external inspection techniques until failure and loss of containment occurs.

Crevice Corrosion

Crevice Corrosion

Crevice corrosion is a form of localized metal loss (similar to pitting) and as the name implies, it occurs in crevices. In a piping system, these are typically present externally between piping and pipe supports and clamps, internally and externally between two adjacent pipe joints (in or near the welding area), and underneath disbonded pipeline coatings (commonly at the top of neoprene splash zone coatings in risers) or below both internal and external deposits. With regards to coating crevice corrosion, it is also often termed “underfilm corrosion” or “filiform corrosion,” which is a more special case. Similarly for deposits, it can also be referred to as “underdeposit corrosion.” In order to develop corrosion, the crevice opening must be such that it allows for and maintains a differential electrolyte concentration cell between the crevice micro-environment and the external bulk environment, which becomes cathodic. The most obvious and common case is a difference in oxygen concentration (differential aeration).
This leads to a change in the micro-environmental conditions, which then become highly conducive to the development of corrosion within the crevice.

Erosion Corrosion and Flow Accelerated Corrosion

Erosion Corrosion and Flow Accelerated Corrosion

Erosion corrosion (EC) and flow accelerated corrosion (FAC) are often used interchangeably, but there are arguably subtle differences in their mechanisms. The term EC describes the intensified development and subsequent rate of metal loss in pipelines caused by the motion of both an erosive and corrosive fluid on the metal surface. The nature of the fluid is such that the mechanical action of impingement and abrasion leads to the removal of any corrosion products, protective films and metal loss through erosion, which is further exacerbated by the corrosion of the exposed metal. Whereas in the case of FAC the fluid is not necessarily erosive in nature, but its fast flow results in the dissolution and removal of corrosion products or protective films, exposing the metal or providing it with a thinner protective film, resulting in a more sustained corrosion rate. Both EC and FAC are cyclic processes that continue up to and beyond perforation of the pipeline.

Galvanic Corrosion

Galvanic Corrosion

Galvanic corrosion simply occurs due to the electrical continuity between two dissimilar metals or alloys when immersed in a conductive aqueous media. The potential difference between the two is the driving force for corrosion and leads to the active dissolution of the more “active” material (the anode) as opposed to the more “noble” (the cathode). With respect to pipelines, galvanic corrosion has both a positive and negative aspect.
In a positive sense, it is the principal of pipeline external cathodic protection. In the case of a sacrificial cathodic protection system, metals and alloys of aluminium, zinc and magnesium are commonly used and sacrificed under galvanic corrosion to protect the more “noble” carbon steel pipeline.
The negative side of galvanic corrosion in pipelines is seen at welds when the weld material does not match the pipeline material and the dissimilar properties drive the corrosion cell. In addition, it can occur at joints, especially when there is an incorrectly specified metal seal ring.
Galvanic corrosion manifests as localized corrosion at the junction between the two dissimilar materials, as this is the shortest path of electrical resistance in the electrochemical circuit.

Intergranular Corrosion

Intergranular Corrosion

Intergranular corrosion (IGC) is also known as intergranular attack (IGA), intercrystaline corrosion or interdendritic corrosion. This form of corrosion attack progresses along the boundaries of the grains that make up the microstructure of metals and alloys. Intergranular corrosion is usually connected to the segregation and precipitation of elements and their enrichment or depletion in or at the grain boundary. This leads to dissimilarity between the grain boundary and the bulk material, and the development of a local galvanic couple. As a consequence, the grain boundary or immediate grain may be either anodic or cathodic, resulting in preferential corrosion of one or the other, and entire grains may be dislodged due to complete deterioration of their boundaries. Grain boundary corrosion is certainly common in alloyed materials that are heat treatment sensitive, such as the austenitic stainless steels. Austenitic stainless steels are prone to a phenomenon referred to as term “Weld Decay” that is a form of intergranular corrosion of the weld caused by incorrect heat treatment and sensitization effects.

Mesa Corrosion

Mesa Corrosion

Mesa (literally “table” in Spanish due to the pit shape) corrosion is characterized by extensive, relatively flat bottomed, steep sided corrosion between areas showing little or no corrosion at all.

Mesa corrosion is a common form of corrosion, where the pipeline is exposed to wet carbon dioxide (CO2) conditions and high temperatures above approximately 60°C. Under these conditions, a protective iron carbonate scale forms relatively quickly on the pipe wall. If these scales are damaged, fresh metal is exposed in conditions where they cannot re-form, and rapid sweet corrosion occurs. This may be the case in turbulent flow regimes. Moving gas produces shear forces under the scales, which then break and expose the bare metal to corrosive conditions.

Microbially Induced Corrosion

Microbially Induced Corrosion (MIC)

Microbially induced corrosion (MIC) is also referred to as microbial corrosion, microbiologically influenced corrosion or simply biocorrosion. It is mainly caused by bacterial contamination of the product transported in the pipeline, when bacteria (particularly sulfate-reducing bacteria (SRB)) become active within slimes and deposits on the pipe walls. This occurs where product velocities are sufficiently low to allow biofilm formation and the establishment of a sessile microbial colony on the pipe wall, leading to a significantly increased pipeline corrosion rate. Unless effective corrosion management strategies are implemented quickly, MIC can lead to rapid localized growth through the wall and loss of containment.

Besides bacteria, micro algae as well as inorganic and organic chemicals may be responsible for the emergence of microbial corrosion in a pipeline.

Microbially induced corrosion commonly occurs as distinct, deep and steep sided pits. When disturbed, the area may smell of hydrogen sulfide (rotten eggs). The corrosion product within the pits is often soft, has no structure and is deep black in color.

Pitting Corrosion

Pitting Corrosion

Pitting corrosion is localized metal loss that takes the form of subsurface “pits” of various shapes: narrow and vertical, elliptical to shallow to the subsurface cavity, and horizontal type shapes.
It is restricted to single points or small areas and emerges in a random pattern. Moreover, the cavities can be open-mouthed, or covered with a semi-permeable membrane of corrosion products.

Pitting corrosion usually occurs where water is present as a separate phase. In gas pipelines, this may be caused by water condensation from the gas phase where the pipeline is cooled, for example by exposure to seawater. In oil pipelines, it may be caused by water dropout. Furthermore, pitting corrosion may occur where a protective coating is damaged or poorly applied to the pipeline. Finally, impurities in the metal structure (such as non-metallic inclusions) may initiate pitting.

Pitting constitutes one of the most dangerous forms of corrosion, as it is very hard to detect and prevent. However, even small pits where the volume of metal loss is minimal can result in a loss of containment, if the pit grows through the pipe wall.



Pooling is a descriptive term for the pattern of corrosion that occurs at the meniscus of an accumulation of water. At low points in pipeline elevation, water can hold up and pool. This results in a concentration of metal loss, which has a ring pattern, where pitting and uniform corrosion are concentrated around the 6 o'clock position in the pipe. Corrosion activity is more significant at the meniscus for a number of reasons, including film stripping due to turbulence at the gas/liquid interface and on-going replenishment of water and corrosive species in the thin meniscus (films within the pool are more stable leading to a lower long-term corrosion rate; and the bulk of the pool tends towards saturation unless water is replaced in sufficient quantities).

Stray-Current Corrosion

Stray-Current Corrosion

Stray-current corrosion describes the concentration of deep corrosion at an isolated location on the pipeline, where there are one or more coating faults. It is caused by the discharge of stray current from the pipe to the soil, e.g. where the pipe provides a preferential flow path for electrical current. The sources of stray current associated with pipelines are:

  • Direct current (DC) stray currents (i.e. electrified railways, neighboring CP systems)
  • Alternating current (AC) stray currents (i.e. HV transmission lines)
  • Telluric stray currents

Typically, the stray corrosion current density is high due to the typically small conductor area at a coating holiday, leading to the typically high rates of attack frequently observed. Stray current may be continuous or intermittent depending on its source.

Stress Corrosion Cracking

Stress Corrosion Cracking (SCC)

Stress corrosion cracking (SCC) is a form of environmentally assisted cracking. It is the brittle fracture of a normally ductile pipeline material as a result of the combined action of a static tensile stress state and the action of a corrosive environment. There are two types of SCC typically associated with pipeline materials:

  • High pH (HPSCC): pH 9 – 13
  • Near neutral pH (NNSCC): pH 5 - 7

For more detailed information on SCC click here.

Top of Line Corrosion

Top of Line Corrosion

Top of line corrosion (TLC) that occurs in pipelines (principally wet gas pipelines), typically refers to corrosion that is present internally between the 10- to 2 o’clock circumferential position. TLC typically results from what is referred to as “moisture dew point” corrosion.
Due to the cooling of the product until the operating temperature is depressed below the dew point of the gas, water condensation occurs on the pipe wall. The condensed water becomes enriched in corrosive species from the gas phase, which increases the corrosivity of the condensed water. The primary corrosive species are the acid gases carbon dioxide (CO2) and hydrogen sulfide (H2S).

Underdeposit Corrosion

Underdeposit Corrosion

The occurrence of underdeposit corrosion, whether due to a differential concentration cell or the establishment of microbially induced corrosion (MIC), is very common within pipelines. There are lots of deposits that can accumulate within pipelines due to the flow dynamics and topography of the line. Deposits such as sand, wax, scales, and organic matter are a few of the more common ones encountered. The deposit basically forms a local environment sheltered from the bulk transmission fluids. The permeable/semi-permeable deposit and lateral space between it and the pipe surface allows for mass transport of corrosion species in and out of the local environment, which leads to the establishment of a differential concentration cell corrosion process or the establishment of microbial corrosion. The way to minimize underdeposit corrosion is to remove any accumulation or prevent the formation of deposits by employing a suitable pipeline cleaning strategy or filtration and chemical management program.

Uniform Corrosion

Uniform Corrosion

Uniform corrosion is also referred to as "general-attack corrosion" or simply as "general corrosion."

As the name suggests, this form of metal loss occurs relatively uniformly over a metal surface rather than forming localized pits. Thus, the corroded areas are large in surface rather than deep. The result is a comparably even thinning of the pipe wall, which may appear on both the exterior and interior sides. Uniform corrosion is characterized by a roughened surface and usually the presence of corrosion products.

An electrochemical process at the surface of the pipe material typically initiates this kind of corrosion attack. Differences in composition or orientation between small areas on the metal surface creates anodes and cathodes that facilitate the corrosion process.

Hydrogen Damage

Hydrogen damage in pipeline materials occurs as a result of the diffusion of atomic (latent) hydrogen into the metal crystalline lattice structure, where it recombines to form molecular hydrogen. In its atomic state, hydrogen is small and mobile within the metal lattice. However, when recombined, the hydrogen molecules are larger and can no longer diffuse. Atomic hydrogen and molecular hydrogen in the metal lattice can lead to the following types of hydrogen damage common to pipelines:

Hydrogen Induced Cracking

Hydrogen Induced Cracking (HIC)

Hydrogen induced cracking (HIC) results from the diffusion and recombination of atomic hydrogen at locations within the metal structure that can facilitate and accommodate molecular hydrogen.
The build-up of molecular hydrogen at these locations, such as inclusions or impurities, results in a build-up in pressure, which leads to the initiation of cracks at these sites. Manganese sulfide (MnS) inclusions or stringers are typical areas associated with HIC in pipeline steels. Other examples of HIC are step-wise cracking (SWC) and stress-oriented hydrogen induced cracking (SOHIC). With SWC, a characteristic ladder appearance of cracking through the pipe wall is observed, resulting from the joining of individual hydrogen induced cracks of adjacent parallel planes. SOHIC presents a similar appearance to SWC; however, it is due to the influence of a local stress, typically the residual stress in the heat-affected zone of welds.

Hydrogen Blistering

Hydrogen Blistering

The mechanism leading to hydrogen blistering is similar to that resulting in hydrogen induced cracking (HIC). Atomic hydrogen diffuses into the steel, recombines to form gaseous molecular hydrogen, causing an internal hydrogen pressure. In pipe steels with lower yield strength (or in soft zones), the increased pressure is absorbed by plastic strain and the development of a blister in the material instead of cracking, as is the case in steels with higher strength.

Hydrogen Embrittlement

Hydrogen Embrittlement

Hydrogen embrittlement is often the term used to describe all hydrogen damage mechanisms. Here it is separated from the other hydrogen damage mechanisms and is described as a decrease in ductility and load bearing capability of the pipe wall after absorption of atomic hydrogen.
Hydrogen embrittlement often results in intergranular brittle fracture of the material. Classically, hydrogen embrittlement is divided into two types:

  • Internal hydrogen embrittlement, where hydrogen diffuses into molten metal during manufacture, and
  • External or environmental hydrogen embrittlement, where hydrogen is introduced into the solid metal through environmental exposure; i.e. contact with soil and chemicals, corrosion processes and cathodic protection.

When talking about hydrogen embrittlement as a mechanism, we are referring to the effect of the hydrogen atom on the materials properties and not the effect of their recombination to form hydrogen molecules.

Sweet and Sour Corrosion

Sweet (CO2) and Sour (H2S) Corrosion

The presence of the acid gases carbon dioxide (CO2) and hydrogen sulfide (H2S) in pipelines containing free water can lead to quite severe corrosion. Both corrosion gases initially form protective corrosion scales of iron carbonate (FeCO3) and iron sulfide (FeS). In the presence of both gases, FeS films will form in preference. In both cases, and even more with FeS, the localized corrosion rates of the exposed pipeline material can be quite severe if the protective films do not form properly or are removed. With the presence of H2S, there is the added problem of hydrogen assisted cracking. Both of these gases pose a significant corrosion threat to pipelines and have formed the basis of many studies to understand the associated mechanisms and their mitigation.

Sulfide Stress Cracking

Sulfide Stress Cracking (SSC)

Sour (hydrogen sulfide (H2S)) service conditions promote hydrogen permeation, which is related to the corrosion reaction and formation of an iron sulfide layer on the material surface. SSC is often termed a special case of hydrogen induced cracking (HIC); it is effectively HIC in the presence of a sour environment as defined by the NACE (AMPP) MR 0175 (now NACE/ISO 1516) standard. This document provides the relevant information on SSC and a material’s susceptibility to it, as well as the conditions for qualification testing a material’s resistance.

Weld Corrosion

Corrosion behavior at welds can be varied and unpredictable, similar to that at parent materials. As with the parent material, welds are susceptible to all types of corrosion phenomena, such as stress corrosion, galvanic corrosion, intergranular corrosion, and microbial corrosion.

All of these can result in the two forms of corrosion, which are simply localized (i.e. pitting) or general uniform corrosion.

There are some more prevalent weld corrosion phenomena that are principally due to variations in microstructure and composition. In addition to microstructure and composition variations and as with parent materials, corrosion at welds has many attributable factors that influence initiation and propagation of weld corrosion, such as porosity, segregation, design and fabrication (technique, sequence) parameters, filler metal selection, and surface finish.

The following types of weld corrosion can occur in pipelines:

Preferential Weld Corrosion

Preferential Weld Corrosion

Preferential weld corrosion is a term principally used to describe the galvanic couple that establishes between the weld filler material and the parent metal. The weld filler metal is anodic with respect to the pipe metal, mainly due to a compositional mismatch between the weld and the parent material, which can also create a microstructural difference. In this case, the cathodic surface area of the pipe is large compared to the anodic surface area of the weld. Therefore, corrosion rates can be relatively high due to the current density at the weld.

Conversely, the opposite may also be the case, where the filler material is cathodic to the parent material. In this case, corrosion of the parent immediately adjacent to the weld may occur, which can have the appearance of corrosion of the heat-affected zone (HAZ).

HAZ Corrosion

Heat-Affected Zone (HAZ) Corrosion

This refers to corrosion that is concentrated in a narrow band on either side of a pipeline weld, within the heat-affected zone (HAZ). This area of the pipeline weld joint has undergone solid-state microstructural changes due to the high temperatures applied in the welding process, but has not melted. Each position in the HAZ has a different susceptibility to corrosion, as during welding each position is exposed to unique thermal conditions that affects its microstructure in slightly different ways.

Selective Seam Weld Corrosion

Selective Seam Weld Corrosion (SSWC)

Selective seam weld corrosion (SSWC – sometimes also selective seam corrosion (SSC)) is a type of metal loss in the bond line region and heat-affected zone (HAZ) of a pipeline's axial seam. This form of localized corrosion attack is characterized by the formation of long, wedge-shaped notches that often contain corrosion products. These grooves may reach critical dimensions that can lead to pipeline failure if not mitigated in time. The term “selective” refers to the fact that this corrosion anomaly affects merely the weld zone and not the adjacent base metal. SSWC occurs in gas and oil pipelines, both internally and externally.

SSWC develops primarily in older vintage pipes, particularly those manufactured prior to 1970 using direct-current electric resistance welding (DC-ERW), low-frequency electric resistance welding (LF-ERW) and flash welding. There are several factors that seem to promote SSWC, including:

  • Exposure to corrosive conditions due to poor or absent coating
  • Ineffective cathodic protection
  • Inclusions and chemistry segregation in the weldment
  • Absence of post-weld normalizing heat treatment (PWHT)

Thanks to improved technology and quality control processes, pipes manufactured after 1970 are usually not affected by SSWC.

Girth Weld Cracking

Girth Weld Cracking

Girth Weld Cracks are usually formed during pipeline construction and can be both hot and cold. Cold cracking in the weld material requires the presence of diffusible hydrogen, stress and a susceptible metal microstructure. Hot cracking depends on the supply of liquid metal at the solidification front, shrinkage stresses across the solidifying weld, and a susceptible weld size.

For more information click here.



Tenting is used to describe external corrosion at a seam weld or spiral weld, due to the applied external pipeline coating forming a “tent” over the weld. The tent results in a small void on both sides of the weld.
If moisture is allowed to enter this void, the resulting corrosion is thus concentrated in the weld area, giving the impression of weld corrosion.

Non-Corrosion Metal Loss Terms and Definitions



The term refers to an electrical arc to a pipeline, buried or above ground. Although of low probability, the arc can result from a ground fault at transmission power lines or similarly a ground lighting strike. Both possibilities result in severe localized metal loss in the pipe wall due to melting of the pipe, with signs of molten material often visible at the arc location. An arc of this kind can be either short or sustained, both of which have the potential to cause failure of the pipeline depending on their respective voltage and current magnitude. Although not necessarily a corrosion phenomenon, a non-penetrating arc can lead to accelerated corrosion at the strike location and is detrimental to the effectiveness of corrosion protection. This means that the pipeline coating and the cathodic protection systems can be damaged, leaving the pipeline exposed to a variety of corrosion problems.

Arc Strike/Burn

Arc Strike/Burn

An arc “strike” or “burn” is a localized heat-affected zone on the surface of the pipe. This type of pipeline anomaly occurs most commonly at a welding error, when a misplaced electrode creates an electric arc outside the welding area. Through rapid uncontrolled heating and cooling of the pipe metal, an arc strike may produce a local area of different metallic crystal structure, intermetallics, precipitates, micro-cracking and localized different physical metal properties (i.e. local hardening and embrittlement), which in turn present a localized area that is of increased risk of accelerated corrosion.



Gouges typically occur in service due to interference from third parties, most commonly from mechanical excavators. The resulting metal loss is often relatively shallow (<15% wall thickness), but the rapid heating from the contact friction and subsequent cooling from the surrounding metal result in a brittle surface layer, due to the formation of martensite. The pipeline is frequently dented during the gouging process and may spring back completely or only partially. However, the stress reversal combined with the brittle surface layer almost always results in cracking at the base of the gouge. These cracks may not be visible, due to smearing of metal over them. Gouges and especially dents with gouges are potentially serious anomalies that are responsible for many in-service failures.

The newly exposed surface of a gouge will be protected from corrosion where CP is satisfactory, but where it is not, corrosion can occur. The residual stresses and material changes at the surface of the gouge lead to a higher energy state than the surrounding pipe, so that the gouge becomes anodic to the undamaged pipe and localized corrosion occurs.

Find out more about pipeline deformations here.


Corrosion is one of the leading causes of pipeline incidents. Improvements in corrosion awareness and management mean that the trend has been downward for several years. Although the number of incidents is slightly lower than those caused by external interference and the consequences less severe, it is essential for pipeline operators to reliably identify, understand, and control the risk of pipeline corrosion.

The main threat posed by corrosion is the reduction of a pipe’s wall thickness. It may result in a significant loss of pipe strength and ultimately cause loss of containment due to a leak or rupture. In the case of a rupture, the resulting damage exceeds the size of the original defect, sometimes by a significant amount if a running fracture occurs due to the decompression behavior of the product.

In the case of localized attack, corrosion may advance to the point of perforation, leading to leakage. Where localized pits interact to behave as an equivalent larger anomaly this can lead to rupture, similar to general wall thinning. If corrosion attacks the area of a seam weld or occurs in combination with cracking, the risk of a rupture increases.

In addition, if corrosion is not effectively addressed through written work plans (mitigation, inspection, risk management), product contamination and an indefinite shutdown of operations can be the consequences. Overall, pipeline corrosion can compromise the safety of the pipeline system.

Present-day manufacturing standards have put in place rigorous quality control and fabrication regulations. Moreover, corrosion control systems such as coatings, cathodic protection, and modern pipeline cleaning techniques, help operators keep the risk of corrosion in check. Nonetheless, the threat is omnipresent and can never be cost effectively prevented completely.

Pipeline operators therefore need to adopt an integrated approach to corrosion management.


A Holistic Approach

Every corrosion anomaly is unique, just as every combination of factors contributing to the development of corrosion in a pipeline is unique. Approaching corrosion management for pipelines with a “big-picture” mindset based on extensive experience working with operators worldwide makes ROSEN your ideal “integrity partner” to successfully control this threat.

The ROSEN Group has developed an integrated framework approach to pipeline integrity management that adapts not only to each type of threat, but also to each individual pipeline. It outlines all the key elements needed to develop a comprehensive and justifiable corrosion management program.
It is a systematic, collaborative approach enabling the management of even the most challenging forms of corrosion attack.

Pipeline Integrity Framework

This Pipeline Integrity Framework incorporates pre-inspection elements that answer critical questions to allow for the selection of the optimal corrosion detection system. In addition, post-ILI elements allow for the most effective decision-making. Furthermore, it includes other components that are essential for a thorough pipeline integrity management strategy, such as data management, training, compliance to codes and regulations, or regular operational cleaning to remove foreign matter or debris to prevent the formation of corrosion and pipe thinning.

The framework continues as a flexible guide through the entire process from inspection to mitigation plans, ultimately resulting in a proper threat management plan. It is modular and adaptable, ensuring a common understanding. This allows operators to choose which elements are relevant to them in reaching their objectives and making the decisions needed for safe and efficient pipeline operation.


In-line inspection is clearly a major part of managing pipeline corrosion. ROSEN operates the largest fleet of metal loss detection tools in the industry. Using liquid-coupled ultrasonic or dry-coupled magnetic flux leakage and internal eddy current technologies, RoCorr in-line inspection services provide reliable corrosion detection, accurate anomaly sizing, and unwanted/unknown connection detection and reporting.

Metal Loss Feature Type Definition by POF

Metal Loss Feature Type Definition by POF
The most appropriate metal loss technology should be selected based on the expected anomaly morphology within the pipeline. This should be based on an initial threat assessment in accordance with best practice and as described, for example, in API 1163.


Pre-ILI Cleaning

In addition to cleaning pipelines at regular intervals, performing cleaning services prior to in-line inspections (ILI) is inevitable in many cases. Cleanliness in pipelines is particularly important for ILI, as the sensor technologies require this to achieve reliable and accurate ILI results. A clean internal pipeline surface, therefore, increases first run success, enables accurate integrity assessments and reduces operational risk and potential costs.

More about our Pipeline Cleaning services.

RoCorr MFL-A

MFL-A (axial magnetic flux leakage)

The power house technology in terms of corrosion detection is based on the high-resolution Magnetic Flux Leakage (MFL) method.
State-of-the-art permanent magnets are used to magnetize the pipe wall to saturation level in the axial direction (typically between 10 kA/m – 30 kA/m). Achieving a high magnetization level is essential for accurate and repeatable sizing and for distinguishing corrosion from other pipeline anomalies, such as inclusions and surface defects.

Under normal conditions (no flaws present), the magnetic flux can travel through the pipeline undisturbed. In the presence of internal or external metal loss, the flux “leaks” out of the pipe wall and the amplitude is recorded by hall-effect sensors. The hall sensors are oriented within the magnetic field and provide coverage of the entire pipe circumference.

The character, amplitude, and various other measurements of the sensor signals are used to determine the depth, length, and width of the detected metal loss.

Technology Benefits:

  • Accurate and precise anomaly classification and sizing
  • High magnetization for high quality of data
  • Best accuracy in anomaly length measurement
  • Reduced tool dimensions and better inspection reliability, as sensors are integrated into a single sensor unit
  • Safe negotiation of dual and multi-diameter pipelines, 1.5D bends and ID reductions up to 15% ID
  • Wide range of tools (sizes from 3" to 56" available)
  • Applicable in both liquid and gas medium

Find out more about our RoCorr MFL-A service .

MFL-A Ultra (axial magnetic flux leakage with Pipeline Imaging and AutoData)

Based on the Magnetic Flux Leakage (MFL) method, our MFL-A Ultra technology is capable of detecting even very small pinholes. By providing lifelike images of a pipe wall’s structure, the exact structure of anomaly groups and complex corrosion anomalies can be defined. With its ultra-high-definition 3D MFL sensors, the MFL-A Ultra technology is able to detect even small changes in the structure of the pipe wall. In addition, AutoData machine learning algorithms allow for a high level of automation, thereby reducing the “human factor” impact. Lifelike images of the interior and exterior pipe wall, combined with automated data evaluation, provide a comprehensive and accurate understanding of the pipeline's structure, offering the following benefits:

  • Avoidance of unnecessary dig-ups
  • Improved integrity and MAOP assessments
  • Detection of very small anomalies, e .g .pinholes down to one millimeter (0.04 inches) in diameter

Find out more about our RoCorr MFL-A Ultra service.

RoCorr MFL-C

MFL-C (circumferential magnetic flux leakage)

The measurement principle of MFL-C is in fact very similar to that of MFL-A, as it also applies magnetic flux leakage. However, the direction of the magnetic field is changed from axial to circumferential.
Tools equipped with this measurement technology circumferentially magnetize the pipe and detect axial features. This makes it suitable for long seam anomaly detection and narrow axial corrosion, channelling, crack-like anomalies and preferential seam weld corrosion.

Find out more about our RoCorr MFL-C service.

IEC (internal eddy current)

The principle behind Internal Eddy Current (IEC) measurements relies on the creation of eddy currents (ECs) within the pipe wall. Based on electromagnetic induction, EC testing involves placing a cylindrical coil carrying an alternating current close to the pipeline wall. The current in the coil generates a changing magnetic field and thus produces eddy currents in the pipe wall. To collect and later assess data, the variations in the phase and magnitude of these currents are monitored by using a second coil, or by marking changes in the current that flows in the primary coil.

The IEC technology accurately detects and sizes shallow internal corrosion anomalies, completely independent of the pipe wall thickness. A few key advantages of EC are:

  • Can be applied in a liquid or gas environment, as well as in cladded pipelines
  • Suitable for extra-heavy-wall pipelines and not affected by heavy-wall segments or crossings
  • Supports the identification of small diameter pitting and pinhole corrosion
  • Provides accurate mapping of internal surface for baseline surveys
  • Allows for accurate differentiation between mid-wall anomalies and small internal pitting
  • The flexible nature of this technology allows for unsurpassed passage capabilities versus all other corrosion inspection tech.

Find out more about our RoCorr IEC service.

UT-WM (ultrasonic testing wall measurement)

UTWM is an appropriate technology for corrosion detection in pipelines transporting liquids. The ultrasound measurement principle is well accepted in the industry for quantitative wall thickness measurement and for the detection and sizing of metal loss anomalies.

This technology uses an ultrasonic transducer to generate an acoustic wave that propagates through the liquid medium and the pipe wall. This transducer is able to record the reflections caused by the internal and external pipe wall. This allows for the thickness of the wall to be assessed and assists in distinguishing between internal and external metal loss.

Optimized to detect and accurately measure internal and external anomalies such as corrosion, laminations, gouging, pitting, narrow axial, preferential seam weld corrosion and other metal loss anomalies, UTWM offers a series of key advantages:

  • Accurate and precise anomaly classification and sizing, particularly regarding general thinning
  • Absolute wall thickness river bottom profile assessment, through high resolution quantitative wall thickness measurement
  • Reliable differentiation between corrosion and laminations

In order to get good data quality and avoid data loss, effective pipeline cleaning is essential.

Find out more about our RoCorr UTWM service.

XYZ Mapping and Routing Technology

XYZ technology provides accurate location and pipeline curvature data useful for the operator’s pipeline GIS, stress modelling, and pipeline movement analysis. In addition, XYZ technology is used to determine the precise location of pipeline anomalies.

Furthermore, XYZ data can also aid in assessing pipeline corrosion; for example areas of internal corrosion caused by water pooling or holdup can be identified, by correlating them with low points and up-slopes in the reported elevation profile of the pipeline. Pipe and other asset crossings can be readily identified in such data and often correlate with concentrations of internal corrosion. The elevation profile can also be used to identify high points, where rocky ground may have resulted in coating damage and/or CP shielding, leading to external corrosion damage. This can be confirmed using the XYZ coordinates together with mapping applications. Such mapping applications can also identify other variations in the external environment that may change the external corrosion susceptibility, for example active and ephemeral river crossings, swamps or road crossings.

In addition, erosion, as well as ground movement, can result in reduced depth of cover, which in turn can increase the pipeline's susceptibility to third-party damage. Using a combination of XYZ mapping data and above-ground profiling data, ROSEN's depth of cover service can quantify the depth of cover and manage the associated threats.

More about our RoGeo XYZ service.

Combined Diagnostic Solutions

Pipelines are exposed to a wide range of potential damage mechanisms, which can interact and pose a high risk to the overall integrity of an asset. Since there is no single inspection technology that can detect and assess all combinations of features, ROSEN offers a variety of different inspection technologies that can be combined on one tool to comprehensively assess different types of threats in one ILI run. The combined evaluation of different data sets thus leads to more accurate and reliable integrity assessments, reducing operational risk.

This variety of combinations includes (but is not limited to) a combination of MFL-A and UTWM technology for high-resolution detection and sizing of internal, mid-wall and external metal loss defects (e.g. MIC, laminations and pitting), wall thickness variations and milling anomalies. In addition, the combination of our MFL-A Ultra, XT and XYZ mapping technologies enables ultra high resolution pipeline mapping, as well as detection and sizing of metal loss and geometry features, such as pinholes, dents and girth weld defects.

Discover the variety of different technology combinations and find out more about our Combined Diagnostic Solutions.


Gathering accurate and complete data for the detection and identification of corrosion anomalies is just one component of a successful and comprehensive pipeline corrosion management strategy. Precise data evaluation, conclusive reporting and meticulous analysis play an equally important role in order to turn these data into knowledge.

Auto Data

AutoData sets entirely new standards in the field of data evaluation.
It deploys machine-learning, adaptive algorithms that are calibrated using high-resolution 3D laser scans of real pipe defects. This means that the evaluation algorithms continuously evolve during their application and therefore constantly improve the quality of their results, leading to a significant increase in defect sizing accuracy.
Large amounts of data are processed automatically within seconds, leading to a significant increase in integrity assessment accuracy.

Find out more about our RoCorr MFL-A Ultra service.

Deep Field Analyze (DFA)

Corrosion experts confirm that it is advantageous if in-line-inspection (ILI) tools can also record the geometry or 3D-profile of metal loss anomalies. This helps to understand the morphology of a corrosion anomaly and provides a better understanding of its behavior.
Precise knowledge of the geometry or contour of an anomaly also helps to further enhance sizing and MAOP confirmation, especially for complex-shaped corrosion and interacting anomalies where effective area methods such as Detailed RStreng can be used.

Laser-like 3D profiling provides a virtual picture of metal loss anomalies found during inspection, showing what is actually in the ground. This additional information results in more effective dig-up prioritization, as well as providing a solution for the verification of anomalies located in difficult-to-access areas. In general, this will support a route to more effective maintenance spending.

Deep Field Analyze (DFA) as part of the Virtual–Dig Up (VDU) Service uses high-quality data from axial and circumferential MFL inspections to provide laser-like 3D profiles of a metal loss anomaly, visualizing the true shape of corrosion or gouging, even before digging up.

Find out more about our Virtual–Dig Up service.

Reporting and Analysis

Close collaboration of expert data evaluators and senior integrity engineers with extensive experience in dealing with corrosion in pipelines ensures credible results and that efforts are focused on critical areas. Properly visualizing data in reporting software covering the entire pipeline provides easy access to the information at hand and is best for reviewing potentially harmful corrosion anomalies.

Find out more about our NIMA Report.


At ROSEN, we deliver industry-leading corrosion assessment support, ensuring that operators get the most from their valuable inspection data.
Our expert team of integrity engineers and technical specialists works closely with customers to provide pragmatic and proactive decision support to ensure operational integrity across the full asset lifecycle.

Fitness for Service Assessment (FFS)

Metal loss anomalies reported by an inspection may affect the safe operation of a pipeline, either immediately or in the future. It is therefore important to assess the remaining strength of the pipeline at an appropriate pressure (for example Design, MOP, MAOP), using industry accepted methods. The dimensions of the anomalies at the time of the inspection together with other pipeline properties (such as diameter, grade and wall thickness) are used in this assessment along with a safety factor, to give the pipeline’s “immediate integrity.”

In addition to the reported dimensions, accurate anomaly classification is key to identifying and understanding the likely cause(s) and credibility of the reported corrosion. Analysis of corrosion patterns is therefore a critical part of the process – if you can understand the cause you have a head start for its management. To understand the nature of that you have to consider both micro and macro views.

External corrosion examples of micro and macro pattern analysis below, show firstly MFL A signals of failure of tape wrap and consequent CP shielding in spirally welded pipe. The second images show failure of the field joint coatings, diagnosed from the plot along the length of the pipeline showing the incidence of corrosion to the nearest girth weld.

Figure 1 – external corrosion from tape wrap failure and CP shielding in spirally welded pipe

Figure 1 – external corrosion from tape wrap failure and CP shielding in spirally welded pipe

Figure 2 – external corrosion from field joint coating failure and CP shielding

Figure 2 – external corrosion from field joint coating failure and CP shielding

The following example shows apparently extensive internal corrosion within a nominally ‘dry’ gas pipeline, when the line is viewed in its entirety. When the line is viewed at a different resolution however, this corrosion is clearly randomly distributed around the circumference in typically joint length bands, which stop and start at girth welds (the vertical lines on the smaller plot). In this case (and looking at other operational data), the damage originated pre-service.

Figure 3 – pre-service internal corrosion in dry gas pipeline

Figure 3 – pre-service internal corrosion in dry gas pipeline

Anomalies which fail an immediate integrity assessment need to be repaired. However, further corrosion growth may cause them to fail in the future.

In order to predict when anomalies may exceed tolerable dimensions, knowledge of corrosion growth rates (CGRs) is required as discussed in the section below. These rates are used to model the growth through wall of corrosion anomalies, in order to predict the latest date at which each anomaly should be investigated in field and then remediated if confirmed to be necessary. Early intervention can save considerable expense as only effective recoating is usually required, but when an anomaly has exceeded the safe operation limit a more expensive repair is needed. The predicted repairs can be used to set a safe re-inspection interval, when the cumulative number (and hence cost) of interventions is compared with the cost of a new inspection.

Find out more about Fitness-For-Service Assessment.

Corrosion Growth Assessment

Corrosion Growth Assessment (CGA)

For effective corrosion management, reliable estimates of the corrosion growth rate are a critical input. Our Corrosion Growth Assessment (CGA) service provides a holistic integrity solution for corroded pipelines. The first stage of CGA is a thorough investigation of all available pipeline data, conducted by experts in integrity and corrosion management, risk and reliability, and flow assurance.
The result is a complete corrosion diagnosis, leading to pipeline segmentations that accurately reflect the variation in internal and external corrosion susceptibility. This is followed by the estimation of historical corrosion growth rates (CGRs), from which characteristic rates are determined for use in future integrity predictions.

The historical corrosion growth distribution can be most accurately estimated for the whole pipeline, by comparing data from repeat inspections. The most accurate comparisons use signal-based approaches on like-for-like technology, notably our AutoSCAN service for ROSEN MFL-A tools. This eliminates the majority of common mode sizing errors, thus minimizing uncertainty in depth difference sizing. We also offer corrosion anomaly “box” matching based on reported listings, but recommend enhancing this with signal data comparison for a sample of anomalies, which is chosen from the automated first stage results. This is best done in runs with the same-vendor/technology, although it is possible to get good results with multi-vendor/technology. The final step of the CGA process is a review of engineering practices, to ensure effective corrosion management.

The ROSEN Group offers three continuously building CGA services, depending on the operator’s goals and needs:

  1. A Corrosion Growth Assessment (CGA) with only box matching
  2. A more refined Corrosion Growth Assessment service (CGApro) that includes box matching with signal matching of select features
  3. A CGApro with AutoSCAN (signal matching of all reported features)

To compare the three, the box matching option provides only an Excel listing; it effectively matches two feature lists from one inspection to the next. In short, integrity engineers align girth welds, log distances, and orientation (o’clock position), and then match each identified feature, allowing corrosion growth rates in millimeters per year to be calculated based on the calculated depth change and time between inspections. The second service provides more detail based on a number of manual signal comparisons and pipeline segmentation, yielding a report with optimized recommended growth rates. The third service, CGApro with AutoSCAN (Automated Signal Correlation and Normalization process), provides signal-to-signal comparison of all reported metal loss indications between two or more inspections, using pattern recognition technology. Historic depth changes can be estimated using the change in signal amplitude and shape. Compared to box matching, corrosion growth rates derived from AutoSCAN are more realistic – and less uncertain.

Find out more about our Corrosion Growth Assessment service.

Corrosion Control and Management

Corrosion Control and Management

Ageing pipelines together with increasing regulatory pressure to demonstrate present and future asset integrity, represent a growing need for a clear and explicit corrosion management policy.

Experts in disciplines such as corrosion, materials and welding, risk, and stress analysis provide valuable consultancy to:

  • Proactively identify all corrosion threats and define related risk
  • Define mitigation controls as necessary and ensure implementation
  • Ensure mitigation controls are effective
  • Establish and implement corrective action as necessary

With an effective optimized pipeline corrosion control and management system in place, operators ensure the health and safety of people and the environment, while increasing operational reliability and production effectiveness. All of these factors contribute to the reduction of capital and operational expenditure (CAPEX & OPEX).


With the amount of collected data steadily growing, the establishment of a system of records where all available data is readily accessible is becoming an increasingly critical issue for pipeline operators. Our asset integrity management solution NIMA offers an intuitive and reliable way to keep pipeline records traceable, verifiable and complete. By providing a well-structured workflow, it supports data analysts with integrating, managing, and maintaining large amounts of location data, together with other asset-related data originating from different systems and in different formats.

Find out more about NIMA.


Companies must ensure a proper knowledge transfer between the departing and the succeeding generations.

ROSEN supports operators with the training and qualification of their personnel by sharing the expertise we have acquired in decades serving the oil and gas sector. We provide well-structured learning programs – made by practitioners for practitioners – that focus on the acquisition of different skillsets, subject knowledge, and practical experience. Training offerings include topics such as:

  • Cathodic Protection and Monitoring
  • External Corrosion and Prevention
  • Internal Corrosion Mechanisms
  • Microbiological Corrosion
  • Pitting Corrosion
  • Stress Corrosion Cracking

Find out more about The Competence Club.


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