- By Adam Booth
- The total amount of steam distributed is always less than the amount of steam produced due to condensation and other losses.
- Proper measurement and monitoring solutions accurately measure and optimize steam distribution.
- When purchasing steam from an external source, it is essential to know the energy content and quality of the steam to ensure accurate custody transfer.
Adding the right instrumentation improves the availability and efficiency of steam distribution systems
By Adam Booth
Steam distribution from the boiler to the points of end use should occur with minimal loss of energy. However, the total amount of steam distributed (figure 1) never matches the amount of steam coming from the boilers because of condensation losses leading to wet steam. Condensate partially leaves the piping via steam traps, and these and other wet steam losses can cause significant measurement errors and increased risk of water hammer, which can damage piping.
Figure 1. Steam distribution piping transfers steam from a boiler to plant systems.
Proper measurement and monitoring solutions accurately measure and optimize steam distribution, including custody transfer. This reduces the risk of water hammer, ensures efficient cooling of superheated steam, and ensures steam dryers and pressure-reducing valves are working as designed. This article describes the instrumentation used in a steam distribution system to solve these problems and achieve these goals.
Balancing the mass and energy in a steam distribution system can be very challenging. The total of the distribution lines will never match the amount of steam leaving the boiler house, because steam loses some of its energy during transport due to condensation. When steam is 90 percent dry it has 10 percent condensate, meaning 10 percent less energy available to heat processes. Wet steam also leads to measurement errors in terms of volume, mass, and energy.
Flowmeters (figure 2) can be used to measure how dry steam is at different points in the distribution systems, and these measurements can be used to improve efficiency.
Figure 2. Key measuring points in steam distribution. T = temperature, P = pressure, F = flow, FY = flow converter, L = level, LS = level switch.
DP flowmeters are often used to measure steam flow. The instruments are composed of a differential pressure flow transmitter and a primary element, the latter of which forms a beneficial blockage in the flow stream. This flow stream constriction results in a reduction in the pressure downstream from the primary element. The DP flowmeter then computes flow rate by sensing the change in pressure downstream and upstream from the primary element. Orifice plates can drift over time, adding up to 1 percent error.
Vortex meters can operate at the high pressures and temperatures characteristic of steam flow, and they offer only slight pressure loss. For district heating applications, volumetric vortex meters work in conjunction with pressure transmitters and temperature sensors.
Traditionally, an additional flow computer was required to calculate the mass and energy flow based on the inputs from the instruments. However, recent advancements have significantly improved the simplicity of these installations. For example, modern two-wire multivariable instruments can provide both pressure and temperature measurements, eliminating the need for additional installation points.
Modern two-wire multivariable vortex flowmeters installed on each of the steam branch lines detect wet steam, accurately measure the dryness fraction, and calculate steam mass and energy.
High ambient and process temperatures can lead to short lifetimes of equipment, even when protected by condensate pots. The electronics of flowmeters should be turned to the six o’clock position if possible, because heat will rise. This means the electronics would be in its direct path if mounted at a 12 o’clock position. Increased temperatures have the potential to damage electronics, which is why it is preferable to rotate the meter body, so electronics are in the 6 o’clock position.
Steam is used for a variety of processes across all industries, and each application requires different quantities and qualities of steam. There are four main types of steam: plant steam, culinary-grade steam, clean steam, and pure steam. For example, culinary-grade steam is used in production of food and beverages. If this steam is not monitored for quality and does not meet its associated standards, it could spoil an entire batch of product leading to waste.
Steam must be supplied in sufficient quantity and at the correct process conditions. If the temperature is too high, product may be lost as noted above, and if the temperature is too low, sterilization or other process procedures might not take place. Along with other factors, pressure controls steam temperature, so precise pressure measurement is highly important.
Corrosion (figure 3) is a persistent challenge in all steam distribution systems. Adding amines to steam can help reduce the risk of corrosion, but these chemicals are relatively costly, so precise metering and good inventory management is required.
Figure 3. Corrosion can be prevented with the addition of amines.
Amines neutralize acid in the steam, thus cutting corrosion. The pH needs to be maintained at 8.2 to 9.0, requiring a pH meter. Level instruments can be used to monitor the level of the amine tank to reorder in time. Amines are typically stored in plastic tanks or chemical totes. The level of product can be measured using free-space radar, which allows for nonintrusive measurement.
Handling heat exchangers
Steam should ideally reach the heat exchanger as 100 percent dry saturated steam for optimal heat transfer to the process. But in practice, steam often has varying degrees of wetness, leading to inefficient heat transfer and increasing the risk of water hammer, which can cause heat exchanger damage.
Heat exchanger instrumentation (figure 4) should be installed to measure the wetness of steam. A multivariable vortex flowmeter can detect wet steam and measure the dryness fraction. Once wetness is measured, steps can be taken to reduce it. Proper selection, installation, and maintenance of steam traps is the most common way to reduce condensation.
Figure 4. Instrumentation on a heat exchanger checks for wetness of steam, temperature, pressure and condensate quality.
Measurement of steam flow (mass and energy) is compensated by pressure, temperature, and dryness fraction. Steam can be superheated or wet at this measuring point, which can lead to water hammer inside the heat exchanger and reduced accuracy of the measurement.
To determine if the condensate can be reused and to reduce the cost of chemical additives, turbidity or conductivity sensors should be installed. A turbidity measurement in the condensate line (Atu in figure 4) checks for particles, and if there are any present the water must be subjected to more treatment before reuse. Leaks in plate heat exchangers (figure 5) can result in product loss because of direct contact between steam and the product, and these leaks are also a potential safety hazard.
Figure 5. Leaks on a plate heat exchanger can be detected by a turbidity sensor.
Checking the turbidity of condensate helps detect leaks. By measuring the turbidity, it is possible to determine if the condensate is contaminated with the process liquid. This would indicate a leak between the plates.
Confirming custody transfer
When purchasing steam from an external source, such as a nearby power plant, it is essential to know the energy content of the steam, and if it is superheated, wet, or dry saturated. Instrumentation (figure 6) is needed to measure the wetness of steam, and hence its value for process heating.
Instrumentation for custody transfer typically includes a DP flowmeter, and pressure and temperature transmitters. Data is compensated in a separate flow computer, which calculates tariff counters and gives a warning if superheated steam gets too close to the saturation point. This can determine the quality of the steam and the amount of energy received.
The custody transfer flow measurement of steam includes mass and energy, which is compensated by pressure, temperature, and dryness fraction. This is because wet steam has a lower energy content than dry steam; therefore compensation by dryness fraction is highly important. Steam bills are calclated based on this measurement; therefore accuracy is of the utmost importance.
Steam monitoring pays off
ArcelorMittal Zenica in Bosnia and Herzegovina produces hot rolled products (rebars, wire rods, mesh, lattice girders, etc.), mainly for the Balkan, E.U., and North African markets. Although steam consumption is very important to the profitability of the company, consumption by different internal customers was only calculated according to empirical standards. The company integrated a turnkey steam monitoring solution into its existing energy monitoring system to improve this situation.
Figure 6. Instrumentation for custody transfer.
Instrumentation (figure 7) included 39 steam measurement systems using Prowirl 72F vortex flowmeters, TR15 temperature sensors, and Cerabar PMP51 pressure transmitters. Each of the 39 measuring points also included an EngyCal energy application manager. The device produces calorimetric calculations according to relevant standards, and it also operates as a gateway to supply data via a fiber optic network to a workstation located at the energy center building.
Figure 7. Steam measurement system with an Endress+Hauser Prowirl 72F vortex flowmeter, TR15 temperature sensor, and Cerabar PMP51 pressure transmitter.
“With the solution and services provided, ArcelorMittal Zenica management is now able to make the right decisions to reduce energy costs,” says Emir Krgo, head of the production sector at ArcelorMittal Zenica. “Taking into consideration the total amount of losses, the cost of the supplied solution, and further investment, the project will provide a return on investment in less than two years.”
Modern instrumentation—such as multivariable vortex flowmeters, turbidity and conductivity sensors, and flow computers—makes it possible for companies to check the quality of steam, whether it is supplied from internal boilers or purchased from an outside source. Instrumentation can monitor and detect if steam is superheated or saturated, and the degree of moisture in steam. It can also calculate energy content and mass flow, and it can be used to detect problems in heat exchangers. An investment in steam monitoring instrumentation therefore pays off quickly, and also improves safety.
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