Feature: New monitoring methods in the pipeline

Ivan Stubelj, product manager, Emerson Automation Solutions explains how non-intrusive innovations are a game-changer

A pipeline snakes through the desert. Monitoring its integrity and internal corrosion is a challenge.
A pipeline snakes through the desert. Monitoring its integrity and internal corrosion is a challenge.

When it comes to the safe transportation of gases and fluids in the Middle East, pipeline integrity and operating safely and reliably is paramount.

The potential costs of not doing so are huge. The National Association of Corrosion Engineers estimates the global cost of corrosion to be $2.5tn per annum more than the gross domestic product of many nations around the globe.

Many sectors suffer from corrosion, with oil and gas high on the list - and the growth in pipeline construction only adds to vulnerabilities. According to the Pipeline & Gas Journal’s 2017 Worldwide Construction Report, approximately 83,000 miles of new pipelines are planned or under construction worldwide, with 9,217 miles - more than 11% - in the Middle East.

This article looks at internal corrosion and its challenges, the failures and successes of the technologies used to address it, and new innovations in particular, non-intrusive area corrosion monitoring based on the field signature method.

Causes and challenges

Internal corrosion is the deterioration of the metallic structure of the pipe due to an electrochemical reaction between the pipe material and the environment inside the pipe. There are a wide variety of causes for internal corrosion, such as fluid corrosivity, flow velocity, deposit of water accumulation, hydrogen sulphide (H2S) or carbon dioxide (CO2), or other pipeline impurities.

Yet what are the detection challenges in identifying corrosion? There is the need to decipher between localised corrosion – corrosion in small areas or zones on the metal surface – and generalised corrosion, where corrosion is uniformly distributed over a much larger area.

Inorganic acids, salts, CO2, H2S and other components that generate localised corrosion and possible leaks are also often difficult to track, resulting in pipeline failure that carries significant financial risk.

There are also challenges of implementing cost-effective pipeline monitoring over large and remote areas – a particular obstacle in the Middle East, where large desert areas are covered. Communications costs, power, transportation and logistics all need to be taken into consideration.

Assessment methods

One form of instrumented inspection technology is in-line inspection (ILI). ILI covers a wide variety of tools and techniques, such as ultrasonic inspection, magnetic flux inspection, metal loss tools and pigging. Smart pigs, for example, have continued to grow and are playing a key role in detecting stress cracking, and both general and pitting corrosion; with highly tuned sensors, they can gauge the thickness of pipes and identify integrity issues, such as cracks, fissures, erosion and other problems.

ILI techniques, however, need to have pipelines configured to accommodate their tools and often have a wide range of specifications related to pressure, temperature and flow range, tool length and weight, minimum bend ratios, and much more. There are also often access issues, particularly in the lower parts of underground pipelines, and the possibility that transportation in the pipeline might have to be halted.

Direct assessment is another means of analysing pipeline integrity and consists of three key areas: external corrosion direct assessment, internal corrosion direct assessment and stress corrosion direct assessment. Direct assessment is designed to complement detailed ILI-based inspections.

Limitations of direct assessment, however, include, but are not limited, to very short pipeline sub-segments coverage, the subjective operator selection of the excavation location, the levels of expertise during direct examination, the low anomaly identification yield, and the discrete nature of the data points.

Online monitoring

It’s against this context that we turn to an alternative form of integrity assessment - non-intrusive, online corrosion monitoring.

We believe online corrosion area monitoring enhances both ILI and direct assessment by providing continuous information of selected points from virtually all pipeline segments. Figure 1 illustrates how successful pipeline integrity management programmes are dependent on continuous monitoring to identify internal corrosion.

Field Signature Method (FSM) is a key element of non-intrusive, online corrosion monitoring and based on feeding an electric current through a monitored section of a pipe, pipeline or vessel. The applied current sets up an electric field that is monitored as voltage drop values between a set of sensing pins installed on the external pipe wall.

The initial measurement sequence measures the voltage drop between all pairs of sensing pins and is called the field signature. Subsequent measurements are compared to the field signature, where general corrosion can be seen as a uniform increase in voltage drops between all pin pairs and localised corrosion can be seen as a local increase in the values.

It is important to note that corrosion is measured between the sensing pins, meaning the complete monitored area is covered, not just under each sensing pin. This is particularly important for monitoring localised corrosion, such as naphthenic acid corrosion. FSM data can then be plotted as metal loss versus time for the efficient tracking of changes in metal loss or in 3D plots that show the distribution of corrosion over the monitored area.

In addition, corrosion is often at its worst at the bottom section of the pipeline because that is where water is most likely to be present. The digging of pits for large access fittings and retrieval tools can also be expensive.

In such cases, non-intrusive technology such as FSM can be installed directly onto the pipe and after installation soil can be replaced above the pipeline without the need for further access. This not only provides more reliable results, but also reduces the safety risks for Middle East personnel.

Further FSM

Leveraging FSM technology, Emerson is working to develop monitoring solutions that deliver permanent, cost-effective and online area corrosion and erosion monitoring for remote and large area pipelines. Such solutions must distinguish between localised and generalised corrosion, reducing the need for pigging and other costlier inspection methods.

Inorganic acids, salts, CO2, H2S and other components that generate localised corrosion, and that can only be monitored through area measurement technologies, will also need to be tracked in real-time.

In addition, wireless local area network, cellular data transfer protocols and built-in solar power options that reduce maintenance and personnel requirements will also be in demand as such corrosion monitoring technologies are deployed in remote areas in the Middle East.

Armed with comprehensive, real-time pipeline health information, operators can then make better decisions about when and where to conduct pig runs, integrity digs and hydrostatic pressure tests, as well as help increase pipeline availability and transportation capacity.

Industry analysts Research and Markets estimates the Middle East and Africa oil and gas pipeline market is projected to reach more than $10bn by 2022. There is clearly a wide variety of intrusive corrosion monitoring applications available today to protect such pipelines. The emergence of new innovations around FSM provide an important new option - reducing risks while delivering accurate internal corrosion detection in the most remote Middle East oilfields and facilities.


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Oil & Gas Middle East - July/August 2020

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