Ultrasound and radar are far from new technologies, but the use of sound waves to measure flow and radio waves to measure level are catching on in the nuclear industry. By Greg Keller
Ultrasonic flow measurement and radar level measurement are about the most accurate methods available and are widely used in many industries worldwide, including in newer reactors.
The use of these technologies is also now being considered for spent fuel pool level monitoring, and for flow measurement in existing nuclear power plants, in spite of radiation and cost-related challenges.
The technologies are being considered for two main reasons. The technical reason is they are extremely accurate. For radar level measurement, the accuracy is often in the 0.1 to 0.2 inch range; for ultrasonic flow measurement, fractions of a percent. The second reason is commercial: radar and ultrasonic instruments are as ubiquitous in new industrial facilities as cell phones are in the hands of teenagers.
If the operators of nuclear plants could continue to purchase the same equipment originally installed in plants decades ago, they probably would. Equipment replacement decisions considered no-brainers in non-nuclear industries are not so simple when the high cost of engineering is considered. Engineering cost is one big reason why nuclear plants do not rush out and embrace the newest technologies, and another big reason is equipment qualification.
The idea behind equipment qualification is simple: if a piece of equipment has a safety-related function, before we can install it we must first prove it can perform that function at the end of its qualified life, often under the accident conditions that will prompt that function.
The cost to qualify new equipment is high, even for a nearly-equivalent replacement. When the replacement item introduces a new failure mechanism, we enter design-change space and we’re lucky if we can keep the cost to a six-figure number.
Herein lies the challenge with both ultrasonic flow measurement and radar level measurement: both use digital electronics, which do not fare well when exposed to radiation and may cause equipment to malfunction or fail.
Everyone in this industry understands the concepts of time, distance, and shielding when it comes to minimizing radiation exposure. For installed equipment, time is not a variable that can be affected. That leaves distance and shielding or a combination of both. The unique challenge with operating units is that the plant is already built, with certain tanks and vessels located close to high radiation sources.
So-called ‘third-party qualifiers’ are good at determining whether equipment will pass qualification, and if they feel it’s necessary, will make modifications before beginning the qualification process. Common modifications include adding supports for seismic rigidity, replacing certain ‘soft’ parts such as O-rings with materials known to handle radiation or temperature better, or shielding sensitive electronic components from electromagnetic or radio-frequency interference (EMI/RFI). Digital equipment, however, cannot be qualified without very extensive modification.
Radar level measurement
There are several legacy level measurement technologies, but the primary one actually uses a pressure transmitter placed at the bottom of the tank to measure pressure or differential pressure and converts that to height. Since the dimensions of the vessel are known, this can be converted to gallons or other unit of measure.
Radar level transmitters measure actual level by transmitting waves down an antenna or through the air and measuring the time for those waves to return. They can compensate for agitation and in some industries measure multiple levels of stratified media such as water and oil.
One nuclear plant application that is seeing more radar level measurement is spent fuel pools (SFP).
For SFP level measurement regulators in the USA and France have added a twist; they want redundant technologies. The thought being that if the SFP level is measured using pressure and a second pressure transmitter is installed, an accident condition that renders the first transmitter inoperable or inaccurate is likely to affect the second one in the same way. So in addition to pressure, plants are turning to radar for SFP level.
The two primary radar level technologies are guided-wave and through-the-air. With guided-wave there is an antenna extending into the pool the full length of measurement. The radio waves ride down the antenna, bounce off the surface of the water, and ride back up the antenna to the instrument, which measures the time delay and converts this to level.
Through-the-air radar is similar, but the antenna does not contact the water; the radio waves travel through the air, bounce off the surface and return. This might seem like choosing between a corded phone and cordless, but nearly all plants are choosing the guided-wave.
The selection of guided-wave radar is driven more by technology and qualification. Both radar technologies use digital circuitry and the SFP could emit high radiation levels, but the guided wave instrument itself was easier to separate into a more robust antenna section with the delicate digital portion being remote.
In the time since radar has been considered for SFP level, which was after the 2011 Fukushima Daiichi disaster, the manufacturers of guided wave radar have been increasing the distance between the antenna and digital components. The technical issue they have been dealing with is the signal quality. And as of this writing, the delicate digital components can be located sufficiently remotely to permit a long qualified life and accurate level measurement.
Guided wave radar use signal in the range of 1 to 2 GHz, while non-contact radar works in dedicated frequency bands like 5GHz, 10 GHz, 24 GHz or even 80 GHz.
One could say that there is a potential risk of interference between RF users. For both radar systems, the signal is first sent by the antenna, reflected by the medium to be measured and received by the antenna up to the radar electronics.
Typically the burst of waves can be in the range of few nanoseconds up to few milliseconds depending on the exact signal processing settings. The time slot is very narrow and any signal outside of that will be rejected.
On top of that, highly-directional antennas are used for non-contact radar, and only the signals conducted to the probe of the guided-wave radar sensor are taken into account. This dramatically reduces the risk of interference with other spectrum users.
Additionally, both radar systems comply with FCC/IC regulations, and some of them offer a higher protection level against external electromagnetic fields up to 20V/m.
Ultrasonic flow measurement
Ultrasonic flow measurement is best explained with an analogy. If you were to measure the time it takes to row a canoe diagonally across a river in a straight line and in the same general direction as the flow and compare it to the time it takes to row back to the original point on the same line, you’d find it takes longer when you’re heading against the flow. It turns out that the different in difference in time is directly proportional to the speed of flow. Ultrasonic flow measurement uses this same principle.
Sensors are placed in diagonal pairs across a cylindrical flow path. Sound waves are transmitted from one sensor to the other and then back and the difference in transit time is measured and converted to flow. Depending on the accuracy needed, instruments may have several pairs of sensors. The most accurate flow meters, such as those used to measure feed water flow, have ten or more pairs of sensors.
Multiple sensor pairs increase the accuracy because they can compensate for laminar flow, turbulence, and other hydrodynamic effects that challenge the accuracy of other flow measurement methods. Older flow measurement methods may require the use of flow straighteners upstream of the device to minimize turbulence. Ultrasonic flow measurement devices, such as those manufactured by Caldon and KROHNE, can eliminate the need for flow straighteners.
Unlike radar level measurement where the advantage is primarily accuracy, ultrasonic flow measurement can often lead to an increase in efficiency because many legacy flow measurement devices measure the pressure drop across a flow restriction. In other words, there is a flow restriction. From the perspective of the fluid in a system, an ultrasonic flow measurement device is just another piece of pipe. It offers no flow restriction.
Ultrasonic feed water flow meters can actually allow plants to generate more power. Feedwater flow is a very accurate measurement of reactor power — much more accurate than measuring neutrons. If you know the mass flow rate and the temperature of both the feed water and steam, the thermal output of the reactor is a simple calculation (given other known factors). In a closed-loop system, power is equal to mass flow rate M times specific heat transfer coefficient C (a fixed number known to plant design) times change in temperature [MC(Th-Tc)].
However, if the feedwater flow measurement instrument error is ±5%, the plant can only operate at 95% of the rated power. Highly-accurate ultrasonic flow measurement of ±0.5% accuracy (or better) allows the plant to operate much closer to the limits. Ultrasonic flow meters are used for ‘custody transfer’, that is, sale of oil or gas from for example an oil derrick to a ship with accuracies up to 0.15%. A 4.5% increase in thermal power makes ultrasonic flow measurement an absolute necessity for any power uprate.
Feedwater temperature is also required, but the flow meter automatically does this as well. Its measurements of flow can be used to calculate the speed of sound in the medium (distance/(echo time/2)), since the speed of sound is inversely proportional to the density of the medium it is travelling through, and the density of water decreases in almost a linear fashion with temperature. In fact ultrasonic flow meters can produce a better average temperature than traditional thermometers because the acoustic signals travel through the feedwater at multiple levels.
Most flow measurement instruments are not in high-radiation environments. For mild radiation environments, permanent shielding can often be used to protect the delicate electronics and permit qualification. Newer polymer-based shielding materials are easier to mould and use than lead in such applications.
About the author
Greg Keller, strategic business development manager, AZZ | NLI, 7410 Pebble Drive, Fort Worth, Texas 76118