Permanently installed wireless sensors provide a consistent and regular supply of data on the integrity of steel pipework and structures
Controlling corrosion is one of the largest challenges in the oil and gas industry, with thousands of kilometres of steel incorporated into oil-processing facilities and pipelines exposed to harsh environments. But how is it possible to really know the condition of a 10in-diameter carbon
teel pipeline, for example, that is exposed to internal and external corrosion?
Among a range of corrosion prevention technologies that is being developed at BP is one involving permanently installed ’waveguide’ wireless sensors, termed Permasense, that can measure the thickness of a pipe or a vessel wall to a resolution of 0.1mm.
Any unexpected changes in the wall thickness alerts corrosion engineers to an unduly corrosive process, as noted by an article in BP Magazine.
Wall thickness has always been routinely measured at refineries as part of a corrosion monitoring regime, but never before has such consistent and regular information been available.
Some points in the refinery can be hard to reach, meaning technicians would have to go out with harnesses and take readings from scaffolding.
At BP’s Cherry Point refinery in the US, corrosion engineer Jeff Waytashek explains: “It was a tough job a lot of climbing around and there is the risk to people when you’re dealing with hot pipes.”
On the new sensors, which have been in place at Cherry Point since August 2010, he said: “I’m confident these sensors will be standard in all refineries one day. The data is so remarkable I think this is one tool corrosion engineers won’t be able to live without.
“We found several of the crudes we were using were causing a higher rate of corrosion than other crudes. We then had to figure out how to run them without corroding through the side of the pipe.”
Without the permanent sensors, infrequent information readings would mean that engineers might not be able to identify with confidence the exact process or crude that had the most corrosive effect.
The Permasense wireless sensors are not only permanently installed in Cherry Point, but also at BP’s Gelsenkirchen refinery in Germany, and many other of the company’s refineries across the globe. Thousands more are set for deployment in the US, Europe and Australia.
The success of the sensors in monitoring corrosion has led to BP’s IRF (intelligent resilient framework) technology team trialling these and similar sensors with a view to deploying them in upstream operations over the coming years.
The sensors were first developed by Prof Peter Cawley’s non-destructive evaluation group team at Imperial College, London. The department is concerned with solving real problems in industrial inspection and monitoring.
At the same time, BP was looking for permanently installed monitors that could cope with temperatures at 600°C and provide continuous readings.
Following development of the sensors, a new company was spun out of Imperial College, called Permasense Ltd, which has now commercialised the technology, which is, therefore, now available for use by others interested in tackling corrosion issues at their facilities.
Prof Cawley explains how the sensor works. “The basic idea is like a metal handle of a saucepan. You have the sensor at one end and at the other end it sits bolted to a pipe that reaches 600°C.”
Over the 30cm length of the waveguide, the temperature drops 600°C, with the cool end of the waveguide housing electronics that won’t tolerate high temperatures contained in a bright orange box.
There have been other attempts to develop a similar technology, but they have used the wrong shape for producing the desired signal. In the Imperial design, an ultrasonic pulse is transmitted along the length of the stainless steel waveguide and reaches the joint at the bottom. The pulse transmits into the pipe and then returns to the electronics contained in the orange box on the top, which wirelessly transmits the measurements to the corrosion engineer’s desktop.
Programme manager Steve Orwig has overseen the implementation of the technology. “Having a permanently installed device allows you to get a better trend,” he says. “You can get higher resolution and far better repeatability compared to manual measurements.
“This technology reduces human error and the wireless transmission capability gives us a greater volume of data to detect changes in operations, with higher levels of accuracy.
“The sensors do not do away with corrosion inspectors, but they are freed to devote their skills to higher-level tasks. Asset managers are now able to make better decisions on the time to replace process equipment, and whether to accept crudes that have been shown to have an impact on asset integrity.”
Permasense in action
Greater accuracy, fewer risks
The Permasense system is in operation at BP refineries in Europe and the US. It is offering previously unavailable insights into the integrity of pipework and is augmenting the capability of integrity monitoring activity.
The initiative was part of BP’s Refinery of the Future programme, which looked at applying new technologies to get maximum performance from refining operations.
Developed very much in a partnership between Imperial College London and BP, there was considerable awareness that this technology would have an enormous benefit to the oil and gas industry as a whole. Continuous measurement presents a step change in the determination of corrosion rates and in the accuracy of that determination, Dr Peter Collins, CEO, Permasense Ltd, said in a written statement to Process Engineering.
“We are now in the position of actively working with many of the other major oil and gas producers. The system is also finding application globally, in no small part due to the fact that it is a wireless solution and does not impose the restrictions of cabling,” said Collins. “I can add that no one to date has installed so many wireless sensors in this industry.”
Collins highlights also the potential for reducing the safety risks associated with collecting plant condition data. The system, he said, has been tried and tested in some of the most inhospitable environments and at temperatures ranging from -30°C to +600°C.
Permanently installed sensor systems 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 the strategies to minimise corrosion, such as inhibiter use.
“This enables the asset manager to move beyond merely knowing where corrosion or erosion is occurring to understanding why and at what rate,” said Collins. “This understanding informs better quality decisions, cost-effectively improving plant integrity, and thus safety.
“The system has applications in both upstream and downstream oil and gas facilities and, interestingly, we are already seeing interest from other industry sectors, such as the power and chemical industries.”