PTQ Q1 2024 Issue

Refractory detection system and floating roof protection

New refractory detection system monitors skin temperatures in Claus or thermal oxidisers as well as SMRs, gasifiers, and emissions from floating roof tanks

Bob Poteet and Andrea Biava WIKA Haytham Al-Barrak and Mahendran Sella Saudi Aramco

T here are many applications in the process industries where detecting a hotspot on the outside of an oper- ating unit can bring safety and protection of valua- ble assets, such as the refractory detection system (RDS) under discussion. This technology can be used in a variety of applications, such as in the Claus section of a sulphur recovery unit (SRU). An installation was recently completed at the Aramco gas plant. The results Aramco saw in its investigation after six months of run-time (now 12 months running) will be discussed, in addition to some other applications. The device’s potential applications are only limited by the pro- cessor’s imagination (see Figure 1 ). So, what exactly is this technology? The heart of the system is a special sheath (typically 4.5mm or 3/16in) made of 316SS that only reads out the highest temperature anywhere along the sheath. To install the system on a Claus unit, first divide the unit into zones, which are areas designated for sensing. As illustrated, there can be anywhere from one to six zones in most Claus units, depending on the licensor or operator’s preference. The readout from each zone will resemble a type K ther - mocouple, but it indicates the hottest area in a zone. You will not know where the hotspot is in the zone, but you will be aware that one exists so that appropriate action can be taken (see Figure 2 ). This technology has been successfully running on a Claus unit for more than 12 years at a major refinery in Italy. Refractory problems in Claus or thermal oxidisers For many operators of SRU plants, detecting refractory problems in the Claus unit can keep them up at night. If the refractory starts to fail, a situation may occur where the hot gasses hit the carbon steel shell and damage or lead to failure of the wall of the reactor. Many ways to detect this have been tried, but they all have limitations. Some have tried thermal imaging, but the problem with rain shields, cowlings, and insulation can be a real barrier. A couple of points should be noted: • This is not a thermocouple. Modern transmitters have self-diagnostics built in, and readings below 120°C are not reliable. While we can prove the system is working at installation, you will have to start the unit without a stable

reading. Older transmitters can be used that read below 0°C, but careful consideration would need to be made in the evaluation process • Above 400°C, the readings will lose their reliability again, but they have done their job. No damage will occur to the system until it reaches 900°C. Uncertainties The industry standard has been to attach thermocou- ples, but nobody knows how many to install. As a result, many installations do not have any thermocouples at all. Thermocouples can indicate the temperature of a specific point, but temperature excursions in other areas will go undetected. If a reactor with thermocouples could be cov - ered, costs increase substantially. The American Petroleum Institute (API) states that an operator should have a system so that an ‘accurate shell temperature measurement system under the shroud should be included in the ETPS design.’ They also request routine thermal imaging of the external shell to spot-check the thermocouples. This can be a maintenance headache if fol- lowed as it is intended.

Figure 1 Refractory failures at high temperatures are difficult to pinpoint.

PTQ Q1 2024