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By Rajesh Nogaja, Power Industry Manager, Emerson Process Management; and Mark Menezes, Measurement Business Manager (Canada), Emerson Process Management
Today’s coal-fired power plants are safer, more efficient, more reliable and more environmentally friendly than ever before. A key challenge remains load maneuverability-how quickly can the plant increase output when demand increases to prevent a brownout? Nuclear power plants-similar to “alternative” technologies such as wind, tidal and geothermal-cannot quickly increase output on demand and so are usually base loaded. Coal-fired plants or incinerators can respond over minutes, to provide secondary grid support. Most valuable-but requiring response in seconds-is primary frequency support, usually provided by relatively fuel-expensive natural gas turbines.
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Improving the maneuverability of a coal-fired plant to allow it to participate in primary frequency support will reduce generation cost and minimize brownouts. The challenge is to do so without compromising efficiency or emissions. This article describes an approach-activation of stored energy-that is cost-effective and applicable to both greenfield and brownfield installations. It requires a new control philosophy, plus the correct application of new level and flow measurement “best practices.”
Primary Frequency Support
Electric energy cannot be stored in large quantities to buffer demand. Instead, when demand significantly exceeds generation, the frequency of the electricity grid falls. This may disconnect some generating stations or consumers, causing islanding or brownouts. To avoid this fall in grid frequency, some generating stations must participate in frequency support. When demand increases, these stations have to feed more power into the grid to obviate frequency drops, complete grid collapse and blackouts.
Different types of load fluctuations require different types of frequency support.
Scheduled load changes are taken care of by secondary frequency support. Participating units adapt their power generation according to dispatcher demand signals, with response times in minutes. Much more stringent is primary frequency support, which balances power generation and consumption for unscheduled load changes. For a stable grid some agencies recommend that a unit should be able to increase its power output by 2.5 percent in 5 seconds, and by 5 percent within 30 seconds1. Due to this extremely fast required response, a coal-fired power plant participating in primary frequency support may experience difficult unit coordination control, lower efficiencies and higher environmental emissions.
The conventional way to increase sustained power output is to operate the unit in “valves wide-open” (VWO) condition, with the steam turbine admitting maximum steam flow and the boiler matching the steam demand by over-firing, that is, burning more fuel and air. Such a process is neither energy efficient nor environmentally friendly. An alternative method for increasing the power output rapidly-5 percent in 30 seconds-demands activation of stored energy. This requires throttling of low-pressure pre-heaters’ condensate and complete or partial stoppage of extraction steam to low-pressure heaters. Extraction steam is instead made to pass through the last turbine stage and augments the generated megawatts.
The difficulty lies in coordinating and effectively managing the sudden increased water flows in the system. This requires precise level measurement and set point control in three tanks within a narrow band to ensure process safety. These are the deaerator, the condenser and the boiler drum itself. If the levels are well controlled, the boiler is capable of quickly responding to load swings.
Managing changing loads also requires improved flow control of combustion air, stack gas and natural gas. Otherwise, even if the levels are controlled during a rapid load swing, safety and environmental compliance can be compromised.
Pressure and Radar Level Measurement “Best Practices”
The most common approach to measuring boiler drum level is by using a differential pressure transmitter to measure hydrostatic head, from which level is inferred after compensating for changing density with an additional gauge pressure transmitter. Users will normally use the compensated drum level measurement as the primary control input, the “first element.” The measurement of steam flow from the boiler is also useful; changes in steam flow will obviously cause changes in level, so are corrected in advance via a feed-forward circuit, the “second element.” Since the user can’t be sure that the feedwater control valve positioner is entirely accurate, feedwater flowrate is usually measured directly-the “third element”-and matched to steam flow rate via cascade control. The best possible accuracy and response time is critical for all of these measurements, so the user should apply the “best practices” for flow measurement, described in later sections.
The condenser and deaerator tanks operate at much lower pressures and temperatures than the boiler drum. This means that instead of inferring level from hydrostatic pressure, the user can measure level directly using a top-down, guided wave radar transmitter, yielding higher accuracy and reliability. This wave-guide can usually be inserted directly into the existing displacer cage or bridle, minimizing installation cost and downtime.
A “top-down” radar measurement works by measuring low long it takes for a radar wave to travel to and from a surface. Since the speed of the radar wave is known-the speed of light-this gives the distance to the surface. Radar waves propagate freely through a material with low dielectric, but are reflected back strongly from a surface with high dielectric. In typical applications, including water, the vapor space above the liquid is the low dielectric and the liquid surface is high.
Radar offers the advantages of any top-down technology, such as ultrasonic or capacitance, but with a much more robust and reliable signal2:
- Unlike with displacers, pressure-based level or ultrasonic, radar accuracy is unaffected by changes in fluid or vapor space properties, including viscosity, conductivity, density and temperature.
- Guided wave radar is virtually unaffected by turbulence and vibration.
- Although the liquid level must be of sufficiently high dielectric-to-reflect, and the vapor space must be of sufficiently low dielectric to pass (some of) the radar waves, changes in dielectric within those limits do not affect accuracy, as with capacitance.
- Even though radar transmitters contain no moving parts and require no routine maintenance, in the event of failure modern guided wave radar transmitters allow the user to replace electronics without breaking the process seal. This speeds repair time, and eliminates the need for isolation valves.
The key challenge with any radar-based level measurement is ensuring a sufficient signal-to-noise ratio. Focusing the wave down a wire or tube maximizes signal strength, while minimizing noisy spurious reflections. Modern designs use “dynamic gain,” which optimizes signal strength based on the height of the individual vessel, particularly useful for vessels much shorter than the transmitter’s maximum range.
For all of these applications, the user must ensure that the devices have been designed to maximize reliability; robust, dual-compartment housings are particularly important. Further improvements in reliability can be obtained by using redundant level transmitters, with backup switches and electronic gauging with indication instead of sight glasses. Switches and gauges should include self-diagnostics, and support automatic checking. This enables dynamic testing, which is more comprehensive than a simple test of electrical integrity.
Best Practices for Fuel, Air and Steam
While level control is critical, rapidly changing loads also require improved flow control of combustion air, stack gas, natural gas, steam and water. Otherwise, during rapid load swings efficiency, safety and environmental compliance can be compromised.
Excess air is not only expensive in wasted fuel, but can lead to NOX and SOX emissions. Excess fuel can cause smoking and a safety risk from unburned fuel in the stack. Correct flow measurement also helps the operator balance furnace pressure, to avoid blowing out the flame. Steam and water flowrates are used in the “second and third elements” of feedwater control and help improve the control of heat transfer processes.
Two key “best practices” for flow measurement include:
- Density compensate air, gas and steam flow measurements
- Optimize installed repeatability for wide turndown
In virtually every gas and steam flow application, the user is concerned with either mass - lb/hr, kg/s, etc - or “standard” volumetric flow - scfm, NCMH, and so on. Variations in fluid density, caused by changes in flowing pressure and temperature, must be corrected to obtain an accurate flow measurement3. Since these density swings are affected by flowrate (friction), barometric pressure, ambient temperature and other conditions, they are not repeatable.
In custody-transfer applications, the user, of course, corrects for density variation using independent pressure and temperature transmitters and a gas density calculation such as AGA-3. In non-custody applications, the user should quantify the error caused by density variation, and determine if the errors are large enough to justify compensation. Familiar mechanical engineering calculations can quantify frictional and other pressure losses, and spreadsheets are available from suppliers. (The freeware spreadsheet P&T.xls is available at www.rosemount.com/dpflow to quantify density variation from user-entered flow conditions, including piping layout.)
If warranted, density compensation can be achieved cost-effectively and conveniently with a flowmeter. Such a device can combine a flowmeter with the needed pressure/temperature measurements and flow computer needed for density compensation.
Users expect that their smart transmitters will provide high accuracy and repeatability. Unfortunately, supplier performance specifications are often valid only under laboratory conditions. In the “real world,” many devices sometimes perform significantly worse. Although this comment applies to many measurements-for example, pressure, temperature, level and so on-for illustration consider the an orifice flowmeter, which is DP transmitter with 0.1 percent accuracy installed on an orifice plate. Will the complete measurement system provide 0.1 percent, 1 percent or 10 percent flow repeatability?
The first step is to identify factors that will cause a transmitter to be less accurate and repeatable outside of a laboratory. For a DP transmitter, key factors include ambient temperature variation, high or varying static pressure, and drift/stability. Next, quantify the impact of these real-world conditions for the given application and transmitter of interest, using published specifications. Finally, recognize that small errors at full scale can become magnified at the flow of interest. As seen in Table 1:
- Trivial errors at 100 percent flow become dominant at lower flows
- Transmitters with identical “laboratory” accuracies provide dramatically different performance in the real-world
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Even though the two 0.075 percent transmitters have the same reference accuracy, the better transmitter is less affected by these real-world effects. Note also that the real-world effects for all three transmitters overwhelm their reference/laboratory accuracies.
While these errors may seem small at 100 percent flow, since the errors are fixed over the entire transmitter range, and DP flow 2, small errors at 100 percent-and small differences in transmitter accuracy-are magnified at lower flowrates, as seen in Table 2.
Conclusions from this typical application:
- Measurement repeatability of combustion air and natural gas are critical at the lowest flows. At a flow of 25 percent, the analog transmitter contributes ±10 percent repeatability.
- The “reference accuracy” of a transmitter is not useful for predicting installed repeatability. The two 0.075 percent transmitters differ by nearly ±8 percent at a flow of 12.5 percent. In practice, the “better” transmitter could operate at a much lower “low fire” than the “worse” transmitter.
- The user can control some of the factors affecting installed repeatability. For example, more frequent calibration will improve repeatability. However, it will also increase maintenance costs. An obvious corollary is that a better transmitter can be calibrated less frequently-reducing maintenance cost-yet still provide acceptable repeatability.
- Even the “better” smart transmitter suffers from very poor performance-and dominates overall flow system performance-at the very lowest flowrates.
Low Flow Characterization
Reputable suppliers minimize real world effects by characterizing (sometimes called “footprinting”) their transmitters over a broad operating range. Completely different from calibration, characterizing a transmitter involves exposing it to a range of conditions (in particular, ambient temperature) and observing the impact on the measurement. Better smart transmitters include a built-in temperature sensor to measure ambient temperature -during operation in the field, observed ambient temperature variations can be automatically compensated in the microprocessor.
Suppliers normally characterize transmitters using reference inputs evenly distributed over the transmitter’s entire range. The benefit of this approach is that it provides transmitters which can be used in a broad range of applications. Unfortunately, while it maximizes flexibility, evenly distributed characterization is not optimized for flow applications, because:
- Half the characterization points are negative, hence not useful in the vast majority of (uni-directional) flow applications.
- The positive points, while evenly distributed by DP, are clustered towards the high flows due to the square root relationship between DP and flow.
The result of this clustering is that no characterization is performed between 0 percent and 45 peercent flow, which is where the flowmeters provide the worst repeatability. To avoid this problem, users should instead ask their supplier to provide their flow transmitters “characterized for flow.” As shown in Figure 5, for these transmitters the supplier will apply the majority of the characterization effort to low-flow conditions, where the DP transmitter accuracy has the greatest impact on flowmeter performance. This will provide significantly better real-world performance at low flows, essentially doubling turndown.
As noted previously, this methodology and approach can apply not only to the example given of a DP-Flowmeter, but to any measurement application and technology. Quantify real-world effects, then work with the equipment supplier to optimize performance in the specific application.
The level and flow measurement best practices described above are a necessary first step to allowing a power plant operator to participate in primary frequency support, reducing generation cost and minimizing brownouts. Evolving from current to “new best practice” requires not only technology, but also application support and training. The savvy power plant operator will draw not only on internal resources, but on the expertise of local integrators and instrumentation suppliers. If necessary, gain experience with unfamiliar technology and practices on low-risk applications, then apply them to the critical applications described above for the highest possible benefit.
References
1. Lausterer, G. K., “Improved Maneuverability of Power Plants for Better Grid Stability”, IFAC/CIGRE Symposium on Control of Power Plants and Power Systems, August 1997.
2. Ortenberg, T., “Developing Trends and Case Studies in Level Measurement”, Canadian School of Hydrocarbon Measurement, March 2006.
3. Miller, R.W., Flow Measurement Engineering Handbook, McGraw-Hill, 1996.
4. Menezes, M., “Calculating and Optimizing Repeatability of Natural Gas Flow Measurement”, Pipeline & Gas Journal, July 2001.
Authors: Rajesh Nogaja is Power Industry Manager at Emerson Process Management and Mark Menezes is Measurement Business Manager (Canada) for Emerson Process Management.
CODE CHANGES HELP UTILITY WORKERS CHOOSE APPROPRIATE PERSONAL PROTECTIVE EQUIPMENT
Electrical safety has been the subject of considerable attention since the late 1990s, with particular focus on arc flash and blast hazards that face personnel when they work on energized electrical equipment.
OSHA (29 CFR 1910.333) and the NFPA 70E® Standard for Employee Safety in the Workplace 2004 edition (Article 110.8(A)(1)) both make it clear that a fundamental requirement of electrical safety is to place all equipment in an electrically safe work condition before anyone works on or near it, unless the employer can demonstrate that the conditions meet certain specific requirements for exemption to that rule. This process, called “lockout/tagout” must be performed only by qualified persons wearing the appropriately rated electrical personal protective equipment (PPE). Once the lockout/tagout process is completed, the equipment is determined to be in an electrically safe work condition.
NFPA 70E is a voluntary consensus standard which does not apply to the electric utility industry. NFPA 70E 2004 Article 90.1(B)(5) specifically excludes installations under the exclusive control of an electric utility. Furthermore, the electric utility industry has a separate OSHA standard that addresses safe work practices and methods (29 CFR 1910.269). OSHA has recently issued a revision to the Code of Federal Regulations, called the Final Rule, which revises the existing OSHA standard by updating it with references to NFPA 70E to make it more consistent with the more recent editions of that safety standard. The Final Rule becomes effective on August 13, 2007, but these revisions will still not render it applicable to the electric utility industry.
It is common for electric utility facilities to have greater electrical hazards than those in general industry. While this condition in the electric utility environment might imply a more substantial hazard, the quality of electrical safety programs, worker qualifications and training in the utility industry are generally much better than those found in general industry, which has an offsetting effect on the overall risk exposure. While NFPA 70E does not apply directly to the electric utility industry, many utilities are adopting the NFPA 70E standards because they recognize that these standards are comprehensive and are in some cases adaptable and useful in their overall safety program efforts.
Generating plant operations is one area where NFPA 70E is particularly well suited and adaptable to electric utility operations, because the electrical distribution equipment, work tasks and specific task length are similar to what is found in a typical industrial manufacturing plant.
Choosing the right PPE
With the recent codes and standards development activity that focuses on electrical workplace safety, both in the commercial sector and the electric utility sector, it is not surprising that some confusion might arise as employers attempt to understand and comply. One area that facility electrical personnel don’t understand well is the use of task tables in the NFPA 70E for choosing PPE.
For facilities that have not yet completed an arc flash hazard analysis, an alternate method of choosing PPE is available. Table 130.7(C)(9)(a) in NFPA 70E 2004 lists various types of electrical equipment and voltage classes, with different tasks listed for each equipment type. For each specific work task, the table shows the level of PPE that is appropriate, as well as the voltage-rated gloves and insulated tools recommended for that particular task.
The level of PPE recommended in the tables is usually adequate under a wide range of conditions. However, great care must be taken to follow the footnotes that apply to each equipment type. Usually a footnote specifies the range of available fault current in thousands of amperes, as well as the clearing time of the upstream protective device in seconds or cycles. Additionally, in some cases these footnoted values have been changed by a Tentative Interim Amendment (TIA). Where Tentative Interim Amendments exist, they will be noted in the back of the NFPA 70E.
When using these tables, care must be taken to make sure that the application falls within the range of available fault current and device clearing time that is shown in the footnotes before using the values recommended in the tables. In many cases, the available fault current and device clearing time information will not be readily accessible to the user without having access to an accurate short circuit and coordination study. It is tempting for facility personnel to estimate the available fault current and device clearing time to expedite the decision and complete the work. But this could have dire consequences for the worker who needs to be protected for the potential arcing hazard. If the actual conditions fall considerably outside of the limits of available fault current and device clearing time, it is likely that the PPE chosen to protect the worker will not be adequate if an arcing fault occurs.
The best practice to avoid such situations is to commission an arc flash hazard analysis as soon as possible. Completing this study puts facility owners and managers in a much better position to protect personnel against arc flash hazards by helping workers choose the appropriate amount of PPE for any task.-By Joseph Weigel, Product Manager, Square D Services, Schneider Electric
