This article describes common pipeline failure mechanisms and the philosophy and methodology for risk based pipeline inspection.

Pipeline Degradation Mechanisms

Damage is defined as an undesired physical deviation from a defined baseline condition that can be detected by an inspection technique or combination of techniques. The reasons for damage can be grouped into the following three categories:

  • Event-based damage, for example, a dropped object, dragging trawl gear, landslide, or dropped anchor;
  • Condition-based damage, for example, a change in pH, change in operating parameters, or a change in CP system;
  • Time-based damage, for example, corrosion, erosion, or fatigue. An RBI assessment considers the following reasons for damage to a pipeline:
  • Internal corrosion;
  • External corrosion;
  • Internal erosion;
  • External impact;
  • Free-spans;
  • On-bottom stability.

Each of these damage reasons is detailed in the next section for a pipeline system with respect to the likelihood of occurrence and the consequence of failure.

Assessment of PoF Value

In this section, the models for assessing the various reasons for damage are described. The user should keep in mind that these models are intended to be conservative, identifying an inspection plan based on a minimum level of provided data. As an alternative to an inspection plan, a more detailed assessment or remedial actions could also be proposed. Proper actions and measures should be taken to ensure the integrity of the pipeline when the inspection outcome and risk assessment indicate that the risk is close to or exceeding the risk limit. These measures can include closer inspection, or mitigation actions as reduced pressure or fitness for service assessment.

Internal Corrosion

Internal corrosion is the major factor of wall thinning during operation. Corrosion is a complex mechanism, depending on fluid composition, presence of water, operational changes, etc.

For an RBI qualitative assessment, the PoF for a pipeline is classified based on the following information:

  • Outcome of last inspection, if any;
  • Time since last inspection, if any;
  • Corrosivity based on the product;
  • Monitoring and maintenance level.

The category of PoF at the time of inspection is determined based on the inspection findings of an insignificant, moderate, or significant level of observed corrosion defects.

Also the PoF increases with time due to potential growth of corrosion defects. The corrosion rate is dependent on the corrosivity of the product. Except for the most corrosive products, credit is given for a good condition monitoring level, which is a measure of the follow-up of the operator. In the corrosion quantitative assessment, internal corrosion damage may be caused by different mechanisms of corrosion degradation. In hydrocarbon pipeline systems, corrosion damage may be due to the following items:

  • CO2 corrosion;
  • H2S stress corrosion cracking (SSCC);
  • Microbiological-induced corrosion (MIC).

The annual failure probability is calculated for both burst and leak failure modes, based on the PoF calculation procedure for metal loss defects. The most important input parameters are whether the corrosion takes place, and the corrosion rate. The factors affecting the corrosion rate can be summarized as follows:

  • Material;
  • Product type;
  • Water content;
  • Temperature;
  • CO2 partial pressure;
  • Inhibition efficiency (if any);
  • Flow regime.

The following items should be considered in order to calculate the PoF using the structural reliability method:

  • Outer diameter;
  • Internal pressure, maximum allowable operating pressure (MAOP);
  • Nominal wall thickness;
  • Material strength, SMTS;
  • Commissioning year.

External Corrosion

Normally pipelines are protected against external corrosion by a corrosion coating that covers the complete external surface of the pipeline. An impressed current cathodic protection (ICCP) system in conjunction with sacrificial anodes is used in pipeline systems when the corrosion coating of a pipeline is damaged. External coating damage could be caused by impacts from vessels, anchors, trawls, etc. In practice, external corrosion is normally not a big problem for the submerged section of a submarine pipeline.

  • Outcome of last inspection, if any;
  • Time since last inspection, if any;
  • Abnormal anode depletion inspection, if any;
  • IC “potential” readings, if any;
  • Operating temperature.

The PoF increases with time due to potential growth of corrosion defects. Even though the corrosion occurs in the splash zone, the temperature of the riser surface is assumed to be equal to the operation temperature, which is used for the calculation of corrosion rate.

Internal Erosion

Erosion is not a common reason for pipeline failures. However, for highvelocity fluid containing sand particles, erosion could occur, especially at bends, at reduced diameters, and where pipeline connections or other geometrical details are present. Erosion is usually not a problem if the velocity is less than about 3 to 4 m/s. The erosion rate is proportional to the mass of sand in the fluid, and large particles cause more severe erosion than smaller particles. The velocity is a very important parameter when considering erosion, because the erosion rate is proportional to the power of 2.5 to 3.0 for the velocity. The defect characteristics of internal erosion can be similar to corrosion defects, and the same inspection categorization as for corrosion defects is used.
Pof Category for Internal Erosion

The PoF increases with time due to the potential growth of the erosion defects. The erosion rate is dependent on the velocity of the product. High velocities will result in a more rapid increase in the PoF, and the number of years for a one-unit increase of PoF is therefore dependent on sand (product) velocity.

External Impact

Damage due to an external impact may arise from dropped objects, anchor impacts, anchor dragging, trawling, boat impacts on risers, fish-bombing, etc. An external impact is an event-based damage reason, and if the annual probability of an impact is constant, the PoF is also close to constant. An inspection will have no or limited impact on the PoF, but it is still preferable to inspect the line at regular intervals.

The PoF category for an external impact for a pipeline is based on the following information:

  • Outcome of last inspection, if any;
  • Trawling activity;
  • Pipeline diameter and concrete coating thickness;
  • Buried;
  • Marine operation activity


Free-spans occur in almost every pipeline, unless special conditions exist (e.g., burial). Seabed scouring is one of the major reasons for free-spans. Free-spans may be subject to in-line or cross-flow vibrations, which can eventually lead to fatigue failure.
PoF Categories for External Impact from Trawling
PoF Category Dependent on Inspection Outcome of Maximum Free-Span Length

To assign an inspection program for free-spans, a detailed assessment should be performed. The PoF in the initial assessment is assumed not to increase with time to initiate a detailed assessment. For the PoF evaluation, keep in mind that free-spans in soft soils tend to shift positions and change in length. For free-span records in soft soil, special consideration is made for a static span.

On-Bottom Stability

Offshore pipelines may move under strong current conditions if the pipeline has insufficient capacity to ensure on-bottom stability. Except for smalldiameter pipelines, a weight coating is often required to obtain sufficient stability. Concrete coating is normally used as a weight coating. Such a coating also protects the pipeline system against external impacts. In an RBI qualitative assessment, the PoF category for the on-bottom stability of a pipeline is based on the following information:

  • Outcome of last inspection, if any;
  • Time since last inspection, if any;
  • Buried or not;
  • Location (onshore/offshore).

Assessment of CoF Values

The CoF is measured in terms of safety, economic loss, and environmental pollution.

Safety Consequences

Safety consequences considers personnel injury or loss of life, which can be obtained from quantitative risk assessment (QRA) studies and presented in terms of potential loss of life (PLL).

Safety Consequence Rankings

Economic Consequences

The direct economic loss should be the spill volume of oil or gas and the repair costs. However, the deferred production time should be considered if there is a need to repair equipment. The repair can be divided into two parts, namely, consequences for a leak and consequences for a rupture. The repair consequence is also dependent on the location of the failure (e.g., above water, splash zone area, or underwater). Economic consequences due to a business interruption or deferred production relate to the costs due to the shutdown of the pipeline. An important factor to be considered is the redundancy in the system, whereby production is maintained by using bypass lines.

Environmental Consequences

Environmental consequences are concerned with the impact on the environment of various types of product releases. The volume of oil dispersed in water can be modeled using software called Adios. The severity of any environmental pollution is determined by the volume of oil dispersed in water and the local conditions, for example, the fishing resources. The environmental pollution ranking is determined by the recovery years of the natural resource, which is decided by the recovery of the local resource and local governmental efforts.

Risk Identification and Criteria

Risk for a pipeline is calculated by this equation:
Economic Consequence Rankings

Risk ¼ PoF CoF Note that risk criteria can be qualitative or quantitative.


[1] M. Humphreys, Subsea Reliability Study into Subsea Isolation System, HSE, London, United Kingdom, 1997.

[2] Det NorskeVeritas, OREDA Offshore Reliability Data Handbook, fourth ed., Det Norske Veritas Industri Norge as DNV Technica, Norway, 2002.

[3] Mott MacDonald Ltd, PARLOC 2001, The Update of the Loss of Containment Data for Offshore Pipelines, fifth ed., HSE, London, United Kingdom, 2003.

[4] Norwegian Technology Standards Institution, CO2 Corrosion Rate Calculation Model, NORSOK Standard No. M-506, (2005).

[5] M.H. Stein, A.A. Chitale, G. Asher, H. Vaziri, Y. Sun, J.R. Collbert, Integrated Sand and Erosion Alarming on NaKika, Deepwater Gulf of Mexico, SPE 95516, 2005, SPE Annual Technical Conference and Exhibition, Dallas, Texas, 2005.

[6] O.H. Bjornoy, C. Jahre-Nilsen, O. Eriksen, K. Mork, RBI Planning for Pipelines Description of Approach, OMAE2001/PIPE-4008, OMAE 2001, Rio de Janeiro, Brazil, 2001.

[7] American Society of Mechanical Engineers, Manual for Determining the Remaining Strength of Corroded Pipelines, ASME B31G-1991, New York, 1991.

[8] Det Norske Veritas, Corroded Pipelines, DNV-RP-F101, 2004.