March 2012

Special Report: Corrosion Control

Consider a new monitoring system to prevent corrosion

This innovative, continuous supervising method collects real-time data on important asset health

Collins, P., Permasense

A combination of aging plants, greater fluid corrosiveness and tightening of health, safety, security and environment (HSSE) requirements has made corrosion management a key consideration for refinery operators. The prevention of corrosion/erosion through live monitoring provides asset and integrity managers with a real-time picture of how their facility is coping with the high demands placed upon it by corrosive fluids. This information can assist in risk management and auditing. Continuous measurement presents a step change in the level of corrosion rates that can be determined and the accuracy of that determination.

Plant integrity.

Steel pipework and vessels are always at risk of corrosion or erosion. Unless monitored, there is a risk of failure, which may impact the safety of workers and the environment. The financial costs of operational interruption, repairs and reputational damage must also be considered.

As oil and gas operators produce and process ever more corrosive or erosive hydrocarbon streams, the demands on plant metallurgy steadily increase. Permanently installed sensor systems can deliver a continuous picture of asset condition over time, at a comparable cost to that of a single manual inspection. This picture can be correlated with process conditions that may be causing corrosion or erosion, and strategies to minimize corrosion, such as inhibitor use. With such knowledge, the asset manager can move beyond merely knowing whether corrosion or erosion is occurring, to understanding why and at what rate. This understanding enables operators to make better-informed decisions.

Need for continuous monitoring.

There are various established techniques for the periodic assessment of pipe and vessel integrity. The drivers of corrosion and erosion—process conditions, crude constituents and abrasive solids—and the inhibitors to hold corrosion rates in check are familiar.

Periodic inspections do not, however, deliver continuous pipework condition data that can be correlated with either corrosion drivers or inhibitor use to understand the impact of process decisions and the inhibitor usage on plant integrity. Manual acquisition of ultrasonic wall thickness data is also frequently associated with repeatability limitations and data-logging errors.

Permanently installed sensor systems, on the other hand, deliver continuous high-quality data. The ultrasonic sensors can be installed on pipes and vessels operating at up to 600°C (1,100°F). These sensors have also been certified as intrinsically safe for use in most hazardous environments. The system has been proven in operation over a number of years in refinery environments, and more recently in upstream facilities.

Continuous monitoring installation data can validate that, when corrosion is occurring, it is often an intermittent process rather than a continuous event. It is in such cases that it is particularly valuable to be able to correlate thickness data over time with process and/or inhibitor parameters. Moreover, the data highlights which prevention or mitigation strategies are most effective.

System design.

At the core of the continuous monitoring system is an ultrasonic sensor mounted on stainless steel (SS) waveguides. The waveguides isolate the sensor electronics from extreme temperatures and guide the ultrasonic signals to the pipe wall and back without excessive signal degradation or distortion. The system can monitor pipe wall thicknesses in the range of 3 mm to 40 mm (1⁄8 in. to 1½ in.) and can be applied on a wide range of steels and other alloys. Frequent measurement of wall thickness allows for metal loss detection at the level of 10s of microns.

Each sensor is equipped with a radio, and communicates with other sensors and a gateway (base station) within a 50-m (55-yd) range. The sensors form a mesh or wireless network that does not require previous installation of wireless nepetwork infrastructure (Fig. 1). Each sensor radio can also act as a relay, or repeater, enabling the network to span hundreds of meters from the gateway.


  Fig. 1. Wireless communication of the continuous corrosion
  monitoring system.  

The data is channeled via the gateway to a database on a connected computer. If, as is the typical case, this computer is networked, then browser-based visualization software enables the corrosion/inspection engineers to view the data at their desks. The data can also be exported in any of the file formats required by the various process monitoring applications, enabling seamless transfer and read-in to those packages and, thus, correlation with the process data at the sensor location.

The principles of the system were developed by the world-leading nondestructive testing research group at the Imperial College London, led by Professor Peter Cawley. It was refined and proven over several years of collaboration with BP refineries. The experience gained in this collaboration helped produce the robustness required for harsh refining environments. The system was conceived from the outset to be cost-effective for large-scale deployment.

Cost-effective for large-scale deployment.

The sensors are battery powered. Thus, no cabling is required, which minimizes the installation costs and imposes fewer restrictions for remote areas and for large-scale deployments.

The sensor is secured on the pipe/vessel by means of two studs that are welded onto the pipe. For pipe-wall temperatures below 100°C, the studs can also be welded onto girth clamps, which are themselves mounted on the pipe. Stud mounting allows for dry coupling; no couplant is required between the waveguide tip and the pipe wall. This, together with multi-year battery life, eliminates the need for expensive maintenance access between turnarounds.

Stud-based mounting also enables geometric flexibility and reduces installation time to just minutes. A two-person installation team can typically install 50 sensors per day.

Robust wireless communication.

The sensor has been designed using high-grade materials to allow for many years of continuous operation. A number of systems have been in uninterrupted operation for three years. To ensure that the system performs in the event of a blockage of an individual pathway or the loss of a sensor, there are multiple pathways for data transmission through the mesh back to the gateway (Fig. 1), which guarantees data retrieval.

The gateway channels data transmitted from all the sensors located in the network. Typically, wall thickness measurements are sent every 12 hours. This interval can be changed at any time for any sensor, to as little as a few minutes if necessary, depending on the monitoring or metal loss determination requirement at that location.

Data is stored in the computer database to guarantee security. This also allows the user to view a full history of data readings, and build a clearer picture of corrosion and erosion rates.


 The system has a wide range of applications in the hydrocarbon processing industry. At present, nearly 20 refineries now use this corrosion monitoring system and it is in use on virtually all crude unit lines, air coolers, furnaces, heat exchangers, pumps, amine units, cokers and cracking units. Pipe materials include carbon, chrome and stainless steel. Typical locations for sensor installation are on elbows, which are known as thin spots, and areas of particular turbulence. Older units, particularly those operating outside of design specifications, are worthy of attention.

The system allows facility operators to monitor locations continuously without the repeated cost of access. By correlating metal loss data with process data (composition, hold-up, temperature), a true understanding can be gained of what changes in parameters are driving corrosion and erosion processes.

This understanding is enabling operators to make better-informed decisions about changes according to these parameters to minimize the impact of corrosion on their plant. Furthermore, users are now optimizing their inhibitor and biocide use, by level and location, based on insights gained from the data.

Continuous monitoring on near-end-of-life lines enables turnarounds to be scheduled with much greater confidence. In a recent example, a system installed on a line with an expected remaining life of 12 months enabled line replacement to be postponed by a very valuable six months. Plus, the used sensors were recovered for re-installation elsewhere.

Inspector safety.

In plants with aggressive rates of corrosion, particularly where corrosion is intermittent and the remaining life is uncertain, frequent manual inspection is common. Where operating temperatures are sufficiently high and a shutdown is necessary for safety reasons to enable manual inspection, the lost production can come at a high cost.

Some locations in a facility can be hard to reach; thus, technicians incur safety risks in gaining access. Where high pipework and vessel temperatures are involved, ensuring technician safety during manual inspection becomes even more challenging.

Permanently installed systems reduce the safety risks associated with collecting plant condition data. In several chemical production facilities, corrosion monitoring system users have also been able to eliminate the periodic shutdowns that they had previously required to enable operator access. The installed systems are also now delivering data where inspector availability is limited or where access is difficult for environmental reasons, such as in Arctic locations.

Gelsenkirchen experience.

Corrosion monitoring was conducted on cast carbon steel U-bends with a wall thickness of approximately 25 mm (1 in.), operating at 380°C (720°F) in the Gelsenkirchen refinery operated by BP to ensure continued safe operation (Fig. 2). Since the high temperature prevented accurate manual ultrasonic wall-thickness measurement, and would have exposed inspectors to significant hazard, the continuous monitoring system was installed, as shown in Fig. 3. This secured operation with confidence until a turnaround. The system has been delivering reliable measurement data for three years.


  Fig. 2. Measured wall thickness for sensors installed on
  one carbon-cast steel U-bend in the field.  


  Fig. 3. Monitoring data of the carbon steel U-bend at
  BP’s Gelsenkirchen refinery.  

New monitoring method.

Operating companies using the continuous corrosion monitoring solution have a more accurate and timely understanding of the corrosion and erosion rates occurring in their facilities. Where inhibitors are in use, the system is giving a greater understanding of their effectiveness. The real-time data allows potential corrosion hotspots to be remotely monitored, at time intervals of the operator’s choosing. This insight allows asset managers to make more informed decisions, to the benefit of plant integrity, safety and operating costs.

The system has been tried and tested in some of the most inhospitable environments, and it operates at pipework temperatures from –30°C to 600°C (–20°F to 1,100°F). It allows operators the freedom to choose monitoring locations irrespective of how inaccessible they are, thanks to the use of ultrasonic sensors and wireless networks for data retrieval. Having already been installed for a number of years in BP refineries across the world, the system has now been adopted by other super-major and privately held refinery operators in the US, Germany and Canada. This technology is making a real difference in an industry facing new challenges every day. HP

The author 

Peter Collins is the CEO of Permasense. Dr. Collins joined the Permasense board in 2010, and he is responsible for the overall development of the company. Already an experienced entrepreneur, he has held board-level technical and operational roles in public and private companies with $100 million+ revenues. His previous roles include operations director at Sondex plc, which specializes in the engineering and manufacture of directional drilling and formation evaluation systems and wireline tools for the production of oil and gas. He was earlier technical director at PII Ltd. and a manager at management consultancy Arthur D. Little Ltd. Dr. Collins holds a PhD in computational fluid dynamics from Imperial College London, a BE degree in mechanical engineering from the University College Dublin, and an MBA from INSEAD. 

The Author

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