Ultrasonic Measuring Technology Updated with Permasense Design

The continuing need for greater safety, efficiency and productivity in the upstream and downstream oil and gas industry, particularly in today’s environment of low oil prices and reduced capital spending, means that technologies that can reduce costs and enhance operational decision-making will be key to enhancing profitability.

An official with UK-based Permasense, which has supplied 12,000 sensors to the oil and gas industry since 2010, said the company is selling confidence to the oil and gas industry in the current downturn with its permanently installed, ultrasonic, wireless, wall thickness monitoring sensors. Initially focused on the downstream market, the company now offers its technology to the upstream market, including offshore platforms, floating production storage and offloading vessels, onshore production fields and liquefied natural gas plants, Iain Fullerton, upstream business manager, told Rigzone.

“Wireless sensors placed in the field and delivering data automatically and directly to the desks of the engineers who need the data can provide substantial cost savings over manual or cabled data acquisition,” said Fullerton.

Spun out of research from Imperial College in London, Permasense’s technology utilizes ultrasonic wall thickness measurement, a technology that has been used in the oil and gas industry for around 60 years. The principle is that an ultrasonic wave is excited from the outside of the pipe or vessel which travels to, and reflects back from, the inside surface of the pipe wall. From the time it takes the ultrasonic wave to travel back to the outside of the metal, and knowing how fast the wave will travel in metal, the thickness can be calculated, said Fullerton.

In corrosion inspection for refineries, corrosion probes and manual ultrasonic inspection are the two most commonly used tools. Corrosion probes, which have been used since the 1960s, rely on an intrusive instrument with a sacrificial tip. The tip sits in the process fluid and is normally made from the same material as the surrounding equipment. As the sacrificial tip corrodes, its electrical resistivity changes, which is recorded externally, usually on a locally mounted data logger, but these are also increasingly available wirelessly connected, according to an August 2015 Permasense white paper.

However, these probes have a number of disadvantages, such as the center line measured corrosion may not be the same as the corrosion rate at the wall, particularly for corrosion mechanisms where shear velocity effects can change the corrosion rate experienced at the pipe wall, according to the paper. The tip often corrodes away after two to three years or less, while many refineries are now operating more than five years between major turnarounds, meaning the tip will usually need to be replaced on the run. Despite safety procedures and training, several well-documented safety incidents caused by probes being ejected at high velocity under residual pressure. Some companies have banned removal of intrusive probes while the plant is running. As a result, these plants operate blind from a corrosion standpoint, for the final, and most critical, one or two years of the cycle between tunarounds.

Manual ultrasonic inspection can be reliable, but completing a full set of measurements for a medium-sized refinery with 80,000-plus corrosion measurement points is very time consuming and labor intensive, such that the wall thickness at an individual low to medium risk point may only be measured every two to three years, according to the paper.

“It is therefore very difficult to make measurements in key locations with enough frequency to measure corrosion rates with any confidence, or to link periods of high wall loss to specific feedstocks or process operations, which require measurements on the time scale of days to be useful.”

Other disadvantages include repeatability and reproducibility errors, permanent damage to equipment due to temperatures above 212 degrees Fahrenheit (100 Celsius) and safety risks associated with high temperatures.

Permasense addresses issues with manual ultrasonic measure with its waveguide design. Made from stainless steel – a poor conductor of heat – the waveguides ensure that electronics are safely kept away from the hot metal surface of up to 1,100 Fahrenheit (600 Celsius). The waveguides guide the ultrasonic wave from the sensor electronics down to the pipe or vessels or back, while holding the sensor electronics away a potentially hot pipe or vessel. As with manual ultrasound, the time-of-flight difference between the surface wave signal and the first reflection from the internal metal surface provides the wall thickness measurement.

Each sensor has a measurement footprint of approximately 35 cubic feet (1 cubic meter), similar to a manual ultrasound inspection, meaning the likelihood of a single sensor detecting a localized corrosion attack is small. Thus, sensors are installed as multi-point arrays at the highest risk locations. The smaller the affected area in proportion to the equipment being monitored, the more sensors are needed to achieve 90 percent confidence in detecting the onset of localized corrosion activity.

The sensors form a mesh, with multiple wireless pathways available for robust and reliable communication of data from the sensors back to the desk of engineers who need the data to make better informed operational decisions, Fullerton noted.  The Permasense technology – which is battery-powered and doesn’t require cabling – also can be quickly and easily deployed in almost any location where internal corrosion or erosion are causes for concern to the ongoing integrity and availability of an asset, Fullerton noted.

The company recently introduced a major advance to its technology with the Adaptive Cross Correlation (AXC) ultrasonic signal processing method. AXC uses a previously recorded waveform to improve the resilience of the measurement when the internal metal surface morphology is very rough, and where normal ultrasonic wall thickness measurements can break down. Additionally, AXC further enhances the repeatability of the measurements, meaning the even smaller levels of corrosion or erosion can be detected in a matter of days, according to the white paper.

For upstream use, the same measurement principles apply. Generally, the metalwork operating temperatures are lower than in refining. Permasense did not need to make any changes to the technology to adapt it for upstream; the sensors are mounted magnetically to the pipework or vessels and do not require removal of external protective coatings, said Fullerton.


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Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com

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