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Featured Story – Properly assessing pipeline integrity: An Interview with Leonardo Araya

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August 16, 2021

As a Senior Integrity and Corrosion Engineer, Leonardo Araya has handled a wide variety of issues surrounding pipelines, tanks, and valves. Stainless Steel World Americas was excited to speak with Araya about the several methodologies that are used to assess a pipeline, and explore a few case studies involving valves and the mediation of corrosion in stainless steel and titanium tanks.

By Stephanie Matas and Sarah Bradley

Day-to-day responsibilities

Leonardo Araya’s daily routine is divided in two stages. In the morning, his responsibilities include: preparing client quotes, providing customer service, and liaising with technicians, maintenance, and management teams. In the afternoon, Araya dedicates his efforts to preparing technical reports on any pipeline issues. “First, I check in with the boss who gives me feedback and updates on the pending tasks from the day before. Then, I speak with customers about quotes, pricing, delivery dates, etc. Around midday, I contact the technicians to collect all the field data, which includes any issues they came across in the past 24 hours. I then use this data to prepare my technical reports,” says Araya.

Assessing pipeline integrity

The technical reports Araya prepares address any areas of jeopardized integrity along the pipeline. He mentioned there are three distinct methodologies used to assess the integrity of a pipe.

Hydrostatic testing

Hydrostatic testing is a process in which piping systems, pressure vessels, and gas cylinders can be assessed for strength and leaks. These tests cannot be conducted while the component is in service, nor can they offer continuous monitoring of the equipment for leaks after the test is completed. Components often require hydrostatic testing after a shutdown or repair has been completed in order to validate the equipment that is being placed back in service. For the hydrostatic testing method, water is put into a pipe and pressure is applied; if the pipe breaks it is considered faulty.

“If the pipe passes the test, you can assess if any cracks in the pipe are spreading and determine the lifespan of the pipeline. For pipelines undergoing maximum operating pressures, the lifespan is typically 15 years, then a reassessment procedure should be conducted for a new life span,” Araya comments.

In-line inspection

In-line inspections evaluate the integrity of a pipe or pipeline using ‘smart pigs’ to detect internal damage and irregularities such as corrosion, deformations, and cracks. Intelligent pigging can be done on many types of pipeline sizes without the need to stop the flow of materials. An inspection pig is loaded into a receiver at a valve or pump station that is specially configured for the task. Once received, sealed, and closed, the pig is driven down the line either by a cable (tethered) or by the flow of material (non-tethered). The pig then gathers important data on the presence and location of any irregularities on the inner walls of the pipe.

Araya explains, “The pig uses a magnetic flux, which is trapped by the cylinder of the pipe and due to physics law, creates a magnetic field in the same shape as the cylinder. If any type of corrosion, dent, crack, or other deviation is detected in the magnetic field, the pig receives a signal and alerts operators of the issue.”

Direct assessment

In scenarios where it is not feasible to conduct a hydrostatic test or in-line inspection – this could include varying pipe sizes, bends, or valves – a direct assessment is conducted. “Direct assessment involves plenty of external inspections. The first step is to complete a pre-assessment,” Araya states. “All of the previous data sheets must be reviewed to prepare a feasibility analysis, which determines whether or not it is possible to conduct a direct assessment on the pipeline.”

Sometimes a direct assessment is not possible due to volatile leakage, environmental concerns, or inaccessibility. Once direct assessment is deemed the appropriate method, engineers select the proper tools for the application and head to the field. “We are often walking in what seems like the middle of nowhere, with all this extremely high-level technical equipment, to make the necessary inspection and/or repair,” Araya laughs.

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Cases studies of carbon, stainless steel and titanium tanks

Araya is familiar with many types of high-grade corrosion resistant alloys (CRAs) and the processes used to mitigate the risk of corrosion in each. During one project, Araya conducted an inspection at a paper mill plant, where the facility was required to upgrade a carbon steel tank to a stainless steel model. “That is not a small expense even for one valve, and all the valves at the plant and their welds needed to be changed. The mill had been replacing its carbon steel tank every three years. After careful consideration of its processes and following the behavior of the mill for eight years, it was determined that the carbon steel could withstand corrosion for up to four years, while stainless steel would resist corrosion for 10 to 12 years. By replacing the tank and its material of construction, the application’s lifespan would be increased, significantly changing the cost-benefit relation.”

In some industries, higher-grade alloys such as titanium or Hastelloy® are required for applications that need to withstand more hazardous environments. In one instance, while working in a copper mine, Araya handled the upgrade of a tank from stainless steel to titanium. “Titanium has a very high resistance to most types of corrosion in current thermodynamic and atmospheric conditions,” he explains.

Even when a high-grade material is being used, coatings for tanks should still be considered an asset. “Companies are paying for coatings, so they need to be properly checked and maintained. The lifespan of a coating must be adhered to. Often coatings are applied very well the first time and is expected to last forever, but this is not the case. It does not matter if it has been seven or 20 years since the coating was applied – you must be aware of your coating’s performance.”

Araya notes that while stainless steel tanks have longer lifespans, if the proper maintenance, such as the re-application of passivants, inhibitors, or coatings are not upheld, companies will ultimately lose profit. “You will pay nearly double, if not three times more for a stainless steel tank than you would for a carbon steel tank. It is crucial to consider your coating to protect your material,” he states.

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Managing data and valve assets

Araya considers the data management of assets a statistical process. For example, capability analyses are used to logically estimate where corrosion will appear in the future. “In analyzing the data, you can expect the increase of corrosion rates in some areas.” Araya also breaks the data into two types: data collected and data observed.

To explain further the idea of data collection and observation, Araya detailed a project he had worked on recently. About a year ago in Chicago, Araya and his team installed a data collector in a valve. They studied the valve, put a GPS on it, and collected data for three days from the same sensor point. On days one and two, there was no inconsistent data. But on day three, the readings were considered ‘strange’. “We thought to ourselves, ‘What happened?’” The team examined the fluctuations overnight, including the impact of the rain, to see why the conditions had changed. Moisture is considered conductive and can affect readings, which is why during the dry season, these inconsistencies did not occur.

Upon observation, Araya and his team saw railroad tracks about 300 feet away from the valve, and it was determined that the railroad tracks were conducting an AC current. The tracks ran parallel from the transmission lines, which caused these lines to create an electromagnetic field. This induced an AC current from the railroad tracks, which translated to AC current corrosion on the pipeline, and the pipeline discharged the current at that point. “The first two days registered about 2 amps of current; when it rained, as moisture is very conductive, we had readings above 16 amps. 16 amps of a stray current is not okay, and the operator had no idea,” says Araya. “We were supposed to be conducting a rudimentary inspection and expected nothing out of the ordinary – the report was already technically written, but that is not what happened when we received the data. The data alone means nothing if you do not observe what is happening on the ground. It helps you to better clarify and understand things as well.”

Looking Forward

Araya believes the pipeline industry is moving toward automation and more advanced management technologies. He mentions the adoption of telemetric operations, which allows for the control of excavators, trucks, and other industrial equipment, to be operated remotely off-site. A small group of maintenance people would be left on-site, but most operations in the future could be handled from an office. “Technicians would only be responsible for checking the sensors, cameras, and maintenance for maintaining automation,” Araya explains. In addition, as global temperatures continue to rise, Araya explains it is important that new materials be developed because components like valves will be affected, and their integrities compromised.