Overcoming Level Gauging Challenges In

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PR_0317_Cover.indd 1 2/28/17 7:23 AM Overcoming level gauging challenges in BOILERS Stability and efficiency through changing load requirements require sophisticated level measuring technology | By Matthew Brummer, Emerson Automation Solutions

or large boiler applications, particu- into a system against electricity produced, typical- to raise the temperature of the condensate just larly those in which steam is used to ly British thermal units (Btu)/kilowatt hour (kWh). before it is injected back into the boiler. This can F drive turbines and produce power, The amount of heat energy (Btu) is divided by the drive a major improvement in overall boiler per- accurate level measurements at criti- amount of electricity generated (kW) over time. formance. cal points in the process are necessary, but they Essentially, the heat rate indicates how much fuel A typical feedwater heater uses a tube-and-shell can be particularly challenging. A high degree of must be burned to generate a specific amount of design in which it pumps water through the tubes accuracy can provide greater operational efficien- electricity, and the lower this number is the better. surrounded by steam that is diverted away from cy and avoid conditions that might cause degrada- Obviously, the heat rate has a substantial effect the turbine (see Figure 2). While this reduces the tion or failure of equipment such as the turbine. on the efficiency of a plant. For a medium-sized amount of steam available for the turbine, the gains This article focuses on level measurements for utility operation of 500 megawatts (MW), a 1 per- realized more than make up for the loss because two specific applications: feedwater heaters and cent improvement in heat rate can save $500,000 the overall amount of fuel consumed goes down. boiler drums. The basic methods used in these in fuel. Consequently, feedwater heaters are used Typically, the feedwater temperature increases applications are examined, and case studies illustrate each approach. Depending on a given Figure 1. Reheating feedwater plant’s configuration, either — or possibly both before it is pumped back into the boiler improves overall efficiency. — application could reside at a single location. All graphics courtesy of Emerson Automation Solutions Application 1: Feedwater heaters When steam comes out of the exhaust vent of a turbine, it goes into a condenser where it is suf- ficiently cooled to condense back into water (see Figure 1). This creates a negative pressure on the back side of the turbine as well as a larger pressure differential from the inlet, which helps pre- pare the water to be sent back to the boiler and used again. Water coming out of the condensers is hot, but if further heated, it can increase boiler efficiency. The colder the feedwater is the harder the boiler has to work to return it to steam at the desired pressure. This effort is quantified as a boiler’s “heat rate,” which is the measure of energy put

Copyright © 2017 by Grand View Media. All rights reserved. No part of this publication may be reproduced, distributed, or transmitted in any form or by any means, including photocopying, recording, or other electronic or mechanical methods, without the prior written permission of the publisher, except in the case of brief quotations embodied in critical reviews and certain other noncommercial uses permitted by copyright law. The material in all Grand View Media publications is copyrighted and may be reprinted by permission only. Reprinted with the permission of Grand View Media and the author[s]. Figure 2. Steam intro- duced into the shell heats condensate flowing through the tubes. “A typical feedwater heater uses a tube-and-shell design in which it pumps water through the tubes surrounded by steam that is diverted away from the turbine.” from 110ºF to 570ºF as it passes through this heat º exchanger. This is significant since even a 5 F Pressure (psig) Temperature (deg F) Water Specific Gravity Percent Error from SG of 1 increase reduces the heat rate by 0.1 percent, so small improvements add up over time. 100 338 0.897 10.3

200 388 0.866 13.4 Maintaining correct level While this concept is very straightforward, complica- 300 421 0.844 15.6 tions emerge when trying to control steam flow to the 400 448 0.825 17.5 feedwater heater. The steam is in the shell and heats the liquid through the tubes. To get maximum heat 500 470 0.816 18.4 transfer and efficiency, the steam should condense 600 489 0.808 19.2 fully within the heater, so there should be some water 700 505 0.778 22.2 accumulation inside. Any steam blown out represents unrecovered heat, and the water accumulation helps 800 520 0.764 23.6 protect against tube leaks, so some condensate within 900 534 0.752 24.8 a specific level range is desirable. At the same time, too much condensate accumulating in the heater reduces 1000 546 0.739 26.1 efficiency. The tubes should be mostly exposed to the Table 1. The degree of error characteristic of DP level instruments and float level sensors increases as pressure and temperature levels increase. steam for maximum heat transfer. The worst situation arises when the steam section becomes fully flooded with condensate. This Real-world level solution in the heater — affect density and, therefore, the not only drastically reduces efficiency, it also can A three-unit coal-fired facility that burns low- accuracy of the level reading, the system did not cause condensate to back up all the way to the tur- sulfur coal in the western United States wanted make an adequate correction. So, as the tempera- bine, blasting water into the blades along with steam. to improve its level measurements. Units 1 and 2 ture changed due to variable unit loading, so did This can damage the blades and reduce turbine life, of the facility are conventional sub-critical designs the level, even though the indicator said it was potentially causing catastrophic failure of the tur- from the 1970s. Unit 3, constructed in 2010, is consistent (see Table 1). It was not uncommon bine. Effective level control to protect against turbine super-critical and has extensive emission con- to have a 20 percent error, which caused a loss in water induction is so critical that American Society of trols. All three units have similar feedwater heater efficiency. Mechanical Engineers (ASME) Code PG.60.1.1 calls trains, each with three heaters connected in series. To solve this problem, the plant installed a for feedwater heaters to be outfitted with two direct- Until recently, the feedwater heaters were outfit- Rosemount Model 5300 guided wave radar (GWR) level readings via sight glasses or one direct-level ted with pneumatic systems built around triple- level instrument (see Figure 3) on one of the feed- reading combined with two indirect readings, plus redundant, differential pressure (DP) level mea- water heaters in a three-heater train as a test. This high-level switches. suring systems. While the operators understood technology was selected for several critical that changes in density — related to temperature operational characteristics: • Level measurement independent of density changes lime dryers and baghouses to remove particulate • Able to withstand the high temperatures and pressures emissions from the flue gas. Reducing overall fuel characteristic of the application consumption reduces output of all pollutants, • No moving parts so less ammonia is necessary to neutralize NOx, • No need for ongoing calibrations or zeroing less carbon must be injected to control mercury • Largely unaffected by changes within the vapor space emissions, and particulate emissions in general are reduced. These are more difficult to quantify GWR instruments can be equipped with a reference reflec- directly, but are clearly improvements on all fronts. tor able to determine when changes within the application are severe enough to affect reading accuracy. The reflector is a step Application 2: Maintaining boiler drum change in the probe diameter. A portion of the microwave pulse stability sent down the probe is reflected by this step, and the transmit- While the population of operating conventional ter is able to detect this partial echo in addition to the echo coal-fired power plants is declining, combined- from the liquid surface. cycle gas turbine (CCGT) facilities are growing in Since its distance is fixed, the reference measurement will number due to low gas prices and environmental always be the same when ambient. When vessel conditions aspects of older technologies becoming more prob- within the unit change (increase or decrease in temperature), lematic. But whether fired by coal or capturing heat an offset in the reflector pulse will occur. The transmitter from gas turbine exhaust, most boiler designs use characterizes the difference and uses it to calculate the steam a drum to circulate the boiling water and collect dielectric in real time, which is applied as a corrected offset steam (see Figure 4). to the liquid level reading. So, for example, if the indicated Controlling level in an industrial heater drum distance to the reference reflector changes by 5 percent, the instrument will apply compensation to the liquid level reading based on this disparity. That way, the radar is always accurate throughout startup, shutdown “GWR instruments can be equipped with a and load changes. reference reflector able to determine when The plant combined this technology with new Global Performance Advisor (GPA) soft- changes within the application are severe ware connected to the larger distributed control enough to affect reading accuracy.” system (DCS) for the plant. This GPA software helped the plant create control room graphics capable of monitoring performance of the feedwater heater much more closely. It added the ability to calculate heater terminal temperature differences and drain cooler approach temperatures so they could be compared to the design values to optimize throughput. Once implemented, the actual efficiency realized matched design capabilities closely, even through multiple plant loading changes. Once the new approach had operated for some time, the plant recognized a 2ºF increase across the single heater in the train. The plant upgraded the other two heaters in the same way to gain a 6ºF improvement across the train. For this plant, a 6ºF increase reduced the heat rate by 13.4 Btu/ kWh, or about 0.12 percent. This might not sound like much, but for a 500-MW unit, it translated into cost savings in excess of $70,000 per year, resulting in a pay-back time of eight months. Extrapolating the solution to the whole plant would result in approximately $200,000 in savings each year. In addition to the energy savings, the plant also realized a reduction in wear on equipment as Figure 3. GWR level in- well as environmental improvements. The facil- struments are well-suited to the external level ity is an extremely clean-burning coal plant with measuring configuration low-nitrogen-oxide (NOx) burners, selective-cat- common in boilers. alytic-reduction systems, sulfur-dioxide-reducing

18 Processing | MARCH 2017 “Controlling level in an industrial heater drum is critical, and control begins with accurate level measurement.”

is critical, and control begins with accurate level Early experiments showed GWR could also be measurement. Most boilers will trip if the level gets fooled, producing readings with a 20 percent error too high to avoid sending water into the steam because a change in the DK of the steam caused it line. They also trip if the level gets too low because to miscalculate the distance to the liquid surface this could cause the boiler to run dry. Depending (see Figure 5). Some units allowed users to add on the size of the boiler, a level deviation of as little a compensation factor manually, which helped. as 2 or 3 inches can cause a trip. However, when operating conditions changed, so Maintaining this critical level is easier said than did the DK. done because a boiler drum is a very turbulent and The same self-compensation capability men- Figure 4. Keeping enough water circulating while maintaining dry chaotic place with high temperature and pressure. tioned earlier also solves a similar problem in steam requires precise level control The separation between liquid and gas becomes this application. When a GWR instrument is able in a chaotic environment. harder to define due to the vapor and changing liq- to measure the distance to its reference reflec- uid density. Many of the traditional methods used tor, it can calculate its own compensation factor to measure level do not work well. dynamically, even when the DK of the steam is costs hundreds of thousands of dollars per hour. Generally, the preferred level-controlling meth- constantly changing. This dynamic vapor com- Since the area was prone to occasional freezes od is DP, but changes in density can add a high pensation can reduce level measurement errors to during the winter, the DP instruments were pro- degree of error — up to 30 percent (see Table 2). less than 2 percent, even in dynamic conditions, tected in an enclosure with the impulse lines heat For example, if the turbine is run hard, and more while eliminating the maintenance problems traced. Even with these precautions, the heat trac- steam is pulled from the boiler, more bubbles will related to impulse lines. ing was not fully effective, and the plant experi- erupt in the liquid, reducing density. Based on a enced multiple trips each winter. Getting the plant DP reading, the drum will appear to be experi- Balancing boiler drum level stabilized after a trip normally involved operator encing a drop in level when actually level has not A 900-MW CCGT plant in the southeastern U.S. overtime to get things thawed and back in opera- changed at all. Often plants have a compensa- was struggling with a level-controlling problem. tion. These losses provided additional motivation tion mechanism for temperature or pressure in It was using DP level instruments in a two-out- to find an alternative. the DCS; however, it usually does not represent of-three (2oo3) voting scheme to keep its three The plant changed all three boilers to instru- what is truly happening in the drum, nor do boilers on an even keel. Under normal conditions ments equipped with dynamic vapor compensation these mechanisms compensate for errors in spe- it operates at 2,300 psi and 650ºF at the drums. capabilities. The instruments were mounted in cific gravity occurring in the tubing from ambient During peak demand, production value is more external bypass chambers, and the plant’s con- temperature changes. than $1,000 per MW, so any unplanned shutdown trol system retained the 2oo3 voting scheme. The Most plants try to avoid drifting readings by using multiple DP instruments in voting Temperature Pressure (psig) DK of Liquid DK of Vapor Error in Distance (%) schemes, but this does not correct the basic (deg F) problem. Moreover, most of these instruments 100 1 73.95 1.001 0.0 are installed using impulse lines, which can clog 200 14 57.26 1.005 0.2 or freeze, obstructing the reading and leaving 300 72 44.26 1.022 1.1 operators blind. 400 247 34.00 1.069 3.4 One choice some users have experimented 500 681 25.58 1.18 8.6 with, which has been proven capable of avoid- 600 1543 18.04 1.46 20.9 ing the density problems of DP measurements, 618 1740 16.70 1.55 24.5 is GWR. Deploying GWR instruments helped 649 2176 14.34 1.80 34.2 users overcome the density variations, and these 676 2611 11.86 2.19 48.0 instruments were able to tolerate the tempera- 691 2900 9.92 2.67 63.4 tures and pressures involved, though some units 699 3046 8.90 3.12 76.6 were thrown off by the variability of the dielectric 702 3120 Above the critical point, distinct liquid and gas phases do not exist. constant (DK) caused by saturated steam within the drum. Table 2. Specific gravity and dielectric constant values change with temperature and pressure, and both are capable of disrupting level measurements. to changes in liquid density and temperature. Even in situations in which the DK of vapors is variable, the ability of GWR instruments to self compensate extends accuracy and reliability. In more general level measuring applications, having a probe to guide the microwave signal helps overcome some problems associated with non-contact radar and ultrasonic technologies such as ghost readings from mixer blades, heavy vapors, condensation, ladders and other internal obstructions. The ability for the signal to follow the guide provides a positive reading even in a variety of difficult applications. GWR level instruments are an excellent choice Signal Curve Before Dynamic Vapor Compensation for many difficult applications, particularly those Signal Curve After Dynamic in which it is important to have precise level mea- Vapor Compensation surement in a challenging environment. Figure 5. Dynamic vapor compensation is necessary to avoid measurement errors caused by changes in radar pulse speed in the vapor space of the drum.

Matt Brummer studied electrical engineering at North Dakota State new configuration met all the ASME B31.1/BPV1 A solution for many applications University and proceeded to work in assuring customer solutions in code requirements. After the installation, the plant As shown in these two examples, GWR level automation. He is the field level specialist leader for North America at survived the winter with no outages, or even near instruments are very practical for boilers, deaera- Emerson Automation Solutions. misses, related to boiler drum level measurement, tors, feedwater heaters, LP/IP/HP heaters and allowing the instruments to pay for themselves other steam drums. They are particularly well suit- Emerson Automation Solutions after just one winter, according to the site engi- ed to mounting in bridles, similar in orientation to www.emerson.com neering manager. existing sight glass installations. They are immune