Pipeline Integrity Management

*Published in World Pipelines Magazine

Oil and gas pipelines have been around for well over a century, and some of the earliest constructed are still in service today.  Although early pipelines were made of wood, and in the past few decades plastics and composite materials have increased in popularity, the vast majority of pipelines in service today are constructed with steel.

Like any pipe material, steel pipe has its downfalls. Steel has a propensity to dent, buckle, corrode and crack when exposed to the environment.  Steel pipeline’s carrying combustible hydrocarbons are buried underground with typically ~1 meter (3 feet) of cover to protect them.  In order to mitigate corrosion, pipelines are covered with a protective coating, utilize cathodic protection (CP), and have their pressure regulated to reduce crack formation and propagation.

Despite all of the design innovations made over the past century, it has not been enough to prevent failures – even the most recently constructed pipelines.  Weather cycles, frost heaves, and road loadings cause physical damage to the pipeline and protective coating.  Operational errors and material defects cause the steel to succumb after years of relentless pressure cycles from the pipeline product itself.  Therefore, proactive pipeline inspections are needed to identify defects, before they cause a leak or rupture.

Pipeline integrity can be validated and assessed using three primary techniques: hydro-testing, the use of Inline Inspection (ILI) tools, and Direct Assessment.


Hydro-testing became common practice for pipelines in the 1940s. The process involves taking the pipeline out of service and purging the product, then the pipeline is pressurized above the maximum operating pressure (MOP) with the intent to determine the ability to operate the pipeline at MOP.  While hydro-testing is still widely used today, there are several drawbacks to the process. The water used in hydro-testing is considered hazardous material after being used, meaning owners incur the additional risk and cost associated with disposing of the water after testing. The information gained from the test is also limited in that it provides no information of the actual condition of the pipe, coating, or surrounding environment.

Hydro-testing can also promote internal corrosion of pipelines, especially if the water used is not properly treated for microbiologically influenced corrosion (MIC) and chlorides. Internal corrosion usually occurs if the pipeline is not properly cleaned and dried after the test.  Hydro-testing can also result in pressure reversals, which worsen the integrity of the pipeline [1].  Finally, the pipeline may be required to be out of service for a significant amount of time, resulting in a significant loss of revenue.

Inline Inspection

ILI tools – which are commonly referred to as smart pigs – were developed in the 1960s and commercialized in the 1970s.  These tools are designed to survey the conditions of the pipeline wall with limited disruption and can identify and quantify the corrosion and cracking in steel pipelines [2].  Magnetic flux leakage (MFL) and ultrasonic testing (UT) are common ILI tools used widely by owners today.

ILI is a significant part of pipeline integrity management, and promote safe, efficient and cost-effective pipeline operation [2].  However, it is important to remember that ILI is just a subset of a family of inspection tools used to verify pipeline fitness for service.  As with any inspection technology, ILI tools have a threshold for detection – the tools are unable to reliably detect anomalies that are below their design specifications’ detection ability. Also, internal pipeline inspections are primarily reactive, requiring the damage or wall loss to occur before defect detection is possible.

Direct Assessment (DA)

The most recently developed solution for pipeline integrity management is Direct Assessment (DA), which is a structured, iterative integrity assessment protocol used by pipeline operators to assess and evaluate the integrity of their pipelines.

Adoption and demand for DA is increasing in modern integrity programs due to more stringent industry regulations, aging pipeline networks, limitations of alternate inspection techniques, and the fact that roughly 70 percent of pipelines within North America are difficult to pig.  Direct assessment surveys provide pipeline owners with important information on both the pipeline’s condition and its surrounding conditions, both of which can lead to degradation and eventual failure.

The Stages of Direct Assessment

It should be noted that geotechnical, dent, and buckle threats are not specifically addressed with any of the DA techniques.  All DA protocols are four-step iterative processes which include a Pre-Assessment, an Indirect Inspection, a Direct Examination and a Post-Assessment.  Inspections involve the integration of as much pipeline available integrity data as possible, which includes physical characteristics and operational history, historical and multiple indirect inspections, and direct pipe surface examinations.

In the pre-assessment step, historic and current pipeline data is collected to determine whether DA is feasible, define DA regions, select indirect inspection tools and determine if additional integrity data is needed.

The second step in DA methodology involves the use of non-intrusive and aboveground techniques. These tools assess the effectiveness of the coating and cathodic protection for pipeline external corrosion assessment (EDCA an ECCDA), and predictive modelling, or critical angle calculations for pipeline internal corrosion assessment (ICDA) to identify and define areas susceptible to internal corrosion.

For external corrosion assessment, the state of cathodic protection, coating and soil resistivity are critical factors in determining high-risk areas. For internal corrosion assessment, fluid flow, mass transfer, solid accumulation, mineral scales, corrosion products, and MIC are critical components [3].  For stress corrosion cracking, critical factors include operating stresses, operating temperatures, distance from a compressor station, age of the pipeline, and coating type.

The direct examination step involves the analysis of pre-assessment and indirect inspection data to select sites for excavation and examination of pipe surface. This process validates the inspection data and provides a first-hand evaluation of the pipe surface and surrounding environment.

Finally, the post-assessment phase involves the analysis and integration of integrity data collected from the previous three steps to assess the effectiveness of the DA process and determine the necessary reassessment intervals.

There are six DA standards developed by National Association of Corrosion Engineers (NACE) and they include:

2002 -NACE SP0502-2010 ECDA (External Corrosion Direct Assessment)

2004 -NACE SP0204-2008 SCC-DA (Stress Corrosion Cracking Direct Assessment)

2006 -NACE SP0206-2006 DG-ICDA (Dry Gas Internal Corrosion Direct Assessment)

2008 -NACE SP0208-2008 LP-ICDA (Liquid Petroleum Internal Corrosion Direct Assessment)

2010 -NACE SP0110-2010 WG-ICDA (Wet Gas Internal Corrosion Direct Assessment)

2010 -NACE SP0210-2010 ECCDA (External Corrosion Confirmatory Direct Assessment)

DA is also covered in ASME B31.8S (Section 6.4).  In the United States, DA is covered in US Code of Federal Regulation CFR 49 Part 192.923 (for natural gas pipelines) and 195.888 (for liquid hazardous pipelines).  It is now one of the three accepted inspections (ILI and Hydro-testing being the other two) allowed for oil and gas pipelines.

Identifying Pipeline Anomalies Using Directing Assessment

When completing a DA inspection, there are three types of anomalies that owners are aiming to identify:

1.         External Corrosion (EDCA and ECCDA)

2.         Internal Corrosion (dry gas, wet gas, and liquid petroleum ICDA)

3.         Stress Corrosion Cracking (SCCDA).

Due to the serious consequences of corrosion and leaks in underground pipelines, external corrosion direct assessment (ECDA), and external corrosion confirmatory direct assessment (ECCDA) – as described in ANSI/NACE SP0502 and NACE SP0210 – were developed in an attempt to proactively prevent external corrosion and ensure the integrity of oil and gas pipelines that are difficult to pig.

ECDA is a continuous improvement process intended to identify and address locations at which corrosion activity has occurred, is occurring, or might occur. For instance, ECDA identifies areas where coating defects have already formed, and can ascertain where cathodic protection is insufficient and corrosion is possible, before major repairs are required.

The success of any ECDA requires strong knowledge of the soil/environment, pipeline material, coating, cathodic protection, and foreign/interference current on the pipeline. Also, the accurate selection of susceptible areas for external corrosion relies on using at least two complementary advanced aboveground inspection techniques. These aboveground indirect inspection techniques may include: direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG) surveys, a cathodic protection close interval potential survey (CP CIPS), alternating current—current attenuation (ACCA) and side drain (for bare or ineffectively coated pipelines) surveys. Normally these aboveground inspections are used in conjunction with pipe locating.

The development of internal corrosion in pipelines is partly because of its complex nature and interaction between constituents that are found in transported gas and liquid products (e.g., oxygen, carbon dioxide, hydrogen sulfide, chloride, bacteria, etc.). When in the presence of water, these contaminants can lead to conditions conducive to the occurrence of internal corrosion. The susceptible locations for internal corrosion are usually where liquids, solids and gas accumulate. In order to ensure that susceptible locations along the pipeline are prevented from internal corrosion, internal corrosion direct assessment methodology is implemented.

Internal Corrosion Direct Assessment (ICDA) methodology has been developed to verify pipeline integrity, especially for pipelines that are not able to accept inline inspection (ILI) tools. ICDA includes Wet Gas Internal Corrosion Direct Assessment (WG-ICDA), Dry Gas Internal Corrosion Assessment (DG-ICDA) and Liquid Petroleum Internal Corrosion Direct Assessment (LP-ICDA). WG-ICDA (NACE SP110-2010) is used in pipelines that assumes that water, or a combination of water and hydrocarbons can be present in the pipeline. It is intended for onshore and offshore systems where liquid to gas ratio is small. It tends to identify locations in the pipeline where corrosion is expected to be severe. DG-ICDA (NACE SP206-2006) is applicable to pipelines that transport gas that is normally dry, but may suffer infrequent upsets, which may introduce water to the pipeline. LP-ICDA (NACE SP208-2008) is employed to assess the susceptibility of internal corrosion on pipelines that transport incompressible liquid hydrocarbons that normally contain less than 5 percent base sediment and water. The success of any ICDA process is dependent on using an accurate corrosion model to predict a precise elevation profile in order to determine susceptible locations for internal corrosion.

DA technology has also proven successful in stress corrosion cracking direct assessment (SCCDA), offering pipeline operators a comprehensive pipeline integrity management portfolio. SCCDA (referenced in NACE SP0204-2008 and ASME B31.8S) is a proactive structured process that seeks to improve pipeline safety by assessing and reducing the impact of stress corrosion cracking. Stress corrosion cracking can occur at neutral or high pH when susceptible pipeline material is exposed to stress, specific susceptible temperature, and a corrosive environment.

The Benefits of Direct Assessment

Direct Assessment is non-intrusive and inspections can be completed during normal operation of the pipeline.  DA is also a proactive integrity management tool that can find anomalies before they become critical defects, while traditional ILI tools are reactive in that they identify existing pipeline damage.

While hydro-testing and ILI tools are an important part of integrity management, the development of DA provides pipeline owners with another solution to identify at-risk areas of pipe before they become a major problem. A combined integrity approach that employs DA can help pipeline owners ensure containment and prevent costly, reputation-harming pipe failures.


1.    Pipeline Research Committee, American Gas Association, NG-18 Report No. 111 (Nov. 3, 1980)

2.    NACE 35100, In-Line Inspection of Pipelines, NACE International, May 2012

3.    NACE Training Course, Direct Assessment, NACE International, November 2012