June 2016, Vol. 243, No. 6


Corrosion Management of Pipelines, Onshore Facilities More Important than Ever

By Marta Castillo, Manager, Pipeline Integrity, Wood Group Mustang

Some pipelines and onshore facilities deteriorate slowly during operation and in certain cases have been reliable for more than their estimated lifetime. Other installations, however, exhaust their useful life after only two to five years of operation.

There are numerous factors that affect the life of a pipeline and onshore facilities. These include construction quality, coatings, cathodic protection (CP) systems, the nature of the product or fluid, the external environment, operating conditions, materials selected and quality of after-installation maintenance.

Ongoing Corrosion Problem

Corrosion is one of the leading causes of failures in both gas and hazardous liquids onshore transmission pipelines in the United States. It also is a threat to gas distribution mains and services, as well as to oil and gas gathering systems. Corrosion causes billions of dollars in damages each year. As a result of this deterioration process, pipeline sections often have to be removed from service and replaced.

Internal and external corrosion have been responsible for a high percentage of the significant incidents on pipelines transporting gas and crude oil. The financial amount and effort involved was – in the majority of the cases – expended after the problem occurred. But, was there a similar effort in prevention?

Pipe failures can be due either to leaks or ruptures with differing results. Leaks from a liquid line can contaminate the soil, groundwater or surface water. Ruptures in a gas pipeline are more likely to cause an explosion and fire, thus resulting in more fatalities and injuries, on average.

Many factors that complicate the investigation or mitigation of corrosion include:

  • Inadequate understanding of the soil and environment surrounding a buried pipeline or other installation.
  • Variations in the oxygen, moisture content, contaminants and chemical composition of the soil surrounding the pipe, which can act as concentration cells that promote corrosion.
  • Coating degradation due to ultraviolet (UV) exposures, H2S presence, bacteria or other microorganisms present in the soil and at girth welds.
  • Disbonding of coatings from the pipe surface, allowing groundwater to contact the steel.
  • Corrosive species in the fluid, which make it difficult to determine whether internal corrosion is occurring.
  • Bacteria corrosion that makes sampling complicated and detection procedures not available for field inspection.
  • Required excavation to inspect pipe and coating anomalies.
  • Stray currents from nearby buried structures that can interfere with the cathodic-protection system.

Thus, the pipeline engineer is faced with a challenging problem – preventing corrosion in a long and frequently large-diameter metal structure contained within a unique environment of predominantly undetermined chemical and physical properties – without the means for direct observation of the majority of the structure.

Risks from Corrosion

Corrosion can lead to the gradual reduction of the wall thickness of the pipe, resulting in loss of strength. This loss can cause the pipeline to leak or rupture due to internal pressure stresses unless the corrosion is repaired, the affected pipeline section is replaced, or the operating pressure of the pipeline is reduced. Corrosion-created weaknesses also make the pipe more susceptible to third-party damage or overpressure events.

Gas pipelines: Typically, sales-quality dry natural gas will not corrode pipeline interior surfaces. However, as it comes from the well, natural gas may contain small amounts of contaminants such as water, carbon dioxide and hydrogen sulfide. If the water condenses, it can react to form an acid that might collect in a low spot and cause internal corrosion.

Liquid pipelines: Similarly, internal corrosion can occur in pipelines carrying corrosive liquids or contaminants. Liquid pipelines can experience internal corrosion anywhere along their length where electrolytes or solids drop out and wet the surface or provide a place for electrolytes to collect.

Many of the corrosion mechanisms are dependent on factors such as the local soil resistivity and chemistry along the pipeline’s route, the transported fluid’s molecular composition, the operating pressure and temperature, metallurgical material selections, reservoir dependencies, aerobic and anaerobic bacteria dependencies.

Therefore, the principal types of corrosion-management systems need to be implemented based on actual survey data and laboratory information received and analyzed during the detailed engineering and design phase of the work.

Corrosion Management

An effective corrosion-management program promotes early identification of potential threats and outcomes and resolves problems at the earliest possible stage. Effective corrosion-control programs go beyond minimum code requirements to anticipate problems and proactively apply appropriate preventive and mitigative measures.

Therefore, CP systems should be part of any newly built, below-grade pipeline design. Adequate CP can reduce the corrosion rate to levels below 0.01 millimeters/year, which is considered to be within acceptable limits. Also, internal corrosion-control methods (chemical injection and material selection, for example) should be considered if potential corrosive conditions are identified.

A corrosion-management plan needs to be proactive, not reactive, considering different steps in the process to prevent early stage corrosion and avoid sudden and unexpected failures that lead to costly repairs and replacement. Regular operator monitoring, inspections and maintenance can assess the rate of change in physical condition. These procedures will give a more accurate idea of how much longer a pipeline can be expected to operate safely and be used to plan for remedial action.

The operating history and other data relative to each system should be reviewed and analyzed to identify existing and possible future threats; these threats may be system specific. Threats to be analyzed include corrosion, natural forces, excavation damage, other outside force damage, material or weld failure, equipment malfunction, and inappropriate operation.

The evaluation should consider several corrosion sources: internal, external, environmentally influenced stress cracking, bacteria (MIC), alternating current (AC)-induced, selected seam and corrosion at the welds. Once the corrosion threats have been identified, the risk assessment for corrosion must be evaluated.

A successful corrosion-management program will implement three key phases:

Phase 1, Diagnosis – prediction, risk and threat assessments: Assessing pipeline system risk is the product of evaluating the probability of corrosion threats and the possible consequence. Risk potential for pipeline systems includes a host of issues – environmental, material, consequence, operations and practical factors. Prioritizing the risk is the process of evaluating and rating the threats to each system and in relationship to the threats affecting other systems. Prioritization will be used as a guideline for establishing assessment schedules. Assessing and prioritizing risks is a continual process. Risk assessments should be conducted periodically and when conditions change.

At this phase, records research and data collection need to be executed to identify threats to the asset and what operating conditions may cause internal or external corrosion. This includes performing a resource inventory of existing pipeline system data followed by a risk assessment. The amount and type of data to be needed will vary depending on the threat being assessed. Databases should be created that contain information about  operating condition, history of the pipeline operation, maintenance data, material, history of failures, leaks (if any) so that corrosion models and risk analyses can be run. Planning for collection and maintaining data can be used as a geographical integrated system (GIS), database, spreadsheets, or other tools.

Phase 2, Corrosion control – implementing actions to control corrosion: Once threats are identified, a corrosion-control plan needs to be implemented. Methods to control external corrosion may include cathodic protection, coatings, chemical injection (inhibitors, biocides, scavengers), corrosion-resistant alloys or other non-metallic materials. Internal corrosion control might rely on internal coatings of various types.

Phase 3, Corrosion monitoring – follow-up strategy: A complete strategy for corrosion monitoring enables online real-time data acquisition of corrosion rates at strategic points related to higher predicted corrosion rates or locations where corrosion control with chemical injection is used.

Corrosion sensors used in online monitoring can be located in critical equipment and piping sections that inspection methods are unable to access. The sensors can provide real-time information on corrosion activity and corrosion upsets with operating conditions, and allows proactive implementation of corrective action before corrosion failures occur.

Figure 1 shows the three phases of a corrosion-management plan. More details can be included on each phase, depending on the corrosion threats and the methods to control and prevent leaks or corrosion failures.



Both corrosion-management and pipeline-integrity management plans, while different, are instrumental in ensuring pipeline safety and performance. It is important that engineers design pipeline corrosion-control methods for internal and external protection. If they do not, corrosion issues may result in more costs associated with failures, adjustment of the design to install corrosion control methods after the system is in operation, and additional replacement and repairs.

These extra costs, in many ways, can be avoided or at least minimized if a corrosion management plan is considered from the beginning of the project.


Author: Marta Castillo has over 20 years of experience in pipeline integrity and corrosion management and is Pipeline Integrity Director at Wood Group Mustang in Houston. She holds a degree in mechanical and metallurgy engineering from Universidad Simón Bolivar in Venezuela and a Master of Science degree in materials science and engineering from Case Western Reserve University, OH.

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