Understanding Coal Power Plant Heat Rate and Efficiency

Proposed U.S. standards for reducing carbon emissions from existing coal-fired power plants rely heavily upon generation-side efficiency improvements. Fuel, operations, and plant design all affect the overall efficiency of a plant, as well as its carbon emissions. This review of the fundamentals of coal plant efficiency, frequent problems that reduce efficiency, and some solutions for improving operation and reducing generation costs should be valuable to plants wherever they are located.

The scene: Twenty years ago, a young engineer stands in front of a group of plaques and awards in the lobby of a large coal-fired power plant. She notes with interest that several of them refer to “best heat rate” awards, and she also notes that the last award is more than three years old. A grizzled station engineer, looking like a coal-dusted Sam Elliott, joins her in front of the display.

“Why did this plant stop winning the heat rate award?” she asks.

“Well ma’am, since we added the scrubbers, there isn’t much point any more. And the other plants went to Powder River Basin (PRB) coal, so they took a heat rate hit too. So, someone just reckoned since we had to give up heat rate to meet emissions limits, there wasn’t much point in having the award anymore.”

Fast-forward to 2014, and the scene is radically different. Advanced coal plant emissions controls are the norm, and PRB coal is in use to some extent at most power plants in the U.S., and the Environmental Protection Agency (EPA) has proposed standards for reducing carbon emissions from existing power plants under Section 111(d) of the Clean Air Act. Comprising a variety of possible methods for reducing carbon emissions, one building block of the EPA plan is improving net plant heat rate (NPHR) by 6% or greater. Although this may sound like a small number to the layperson, power plant engineers know that a 6% heat rate improvement would require a serious commitment on many different levels within their utility.

This article outlines the basics of plant efficiency and heat rate, such that one can quickly understand where the best opportunity for improvement is for a specific generating asset. It then examines ways in which the 6% NPHR goal might be achieved.

Heat Rate Fundamentals

The term “heat rate” simply refers to energy conversion efficiency, in terms of “how much energy must be expended in order to obtain a unit of useful work.” In a combustion power plant, the fuel is the energy source, and the useful work is the electrical power supplied to the grid, the steam heat supplied to an industrial customer or used for heating, or both. Because “useful work” is typically defined as the electricity and steam that is delivered to the final customers, engineers tend to work with the net plant heat rate (NPHR).

In the U.S., heat rate is typically expressed using the mixed English and SI units of Btu/kWh. Though confusing at first, this merely indicates how many Btu/hr of energy are required to produce 1 kW of useful work. Other countries commonly use kJ/kWh, kCal/kWh, or other measures. This article uses the U.S. format.

Because approximately 3,412 Btu/hr equals 1 kW, we can easily determine the thermodynamic efficiency of a power plant by dividing 3,412 by the heat rate. For example, a coal power plant with a heat rate of 10,000 Btu/kWh has a thermal efficiency of 3,412/10,000, or 0.3412 (34.12%).

The Input/Output Method

One of the simplest ways to calculate your NPHR is to divide the Btu/hr of fuel heat input by your net generation (electricity and steam to the customers) in terms of kW. However, determining the heat input can be quite difficult.

In my experience, a minority of combustion power plants have a good measure of their actual fuel burn rate at each unit. An industry rule of thumb is that volumetric feeders are accurate to within +/–5% at best, and gravimetric feeders are accurate to +/–2% at best. In practice, I find that the actual error in fuel burn rate measurement can be from 5% to 10%.

At one power plant I worked at, the only capability for estimating the coal burn rate was to rely on photographs of the coal yard taken by a spritely lady from her Cessna aircraft, and by comparing the estimated stockpile size with train receipts for the month to determine how much coal was burned overall. The potential error for this method could easily be greater than 25%.

Another important factor in heat input measurement is the fuel quality analysis, especially the fuel’s heating value. (See “Primer on Fuel Quality Analysis” in the January 2015 issue for more detail.) Generally speaking, the error in a fuel burn rate calculation cannot be less than the error in the fuel analysis, so choosing one’s sampling methods and frequency carefully will provide greater certainty when calculating the fuel burn rate.

In short, the input/output method is not an ideal method to track the difference in efficiency at your coal-fired power plant unless you have accurate coal feeders (Figure 1) plus an accurate and regular determination of your fuel heating value.

1. Coal feeders are important. Often ignored until something breaks, inaccurate coal feeders can make it difficult to determine your plant heat rate. Courtesy: Una Nowling

The Heat Loss Method and the Three Efficiency Boxes

A significant problem with using the input/output method to determine your heat rate is that, should your heat rate change from one situation to the next, you have no idea of what led to the change. Was the boiler less efficient at burning the fuel? Is turbine efficiency reduced due to high condenser backpressure? Has station service power increased? Because the input/output method treats the power plant as a black box, the engineer must rely on a more accurate method of determining heat rate.

The heat loss method for determining your heat rate essentially breaks the power plant into three subsystems where an energy conversion process occurs:

■ The boiler, where fuel heat is converted to steam energy.

■ The turbine, where steam heat is converted to mechanical rotational energy.

■ The generator, where rotational energy is converted into gross and net electric power.

The heat loss method for calculating heat rate essentially draws a box around each of these subsystems and determines the efficiency of each energy conversion process. The product of all of these conversion efficiency values results in the total net plant heat rate for the power plant:

NPHR, Btu/kW x hr = NTHR, Btu/kW x hr / ( (Boiler Efficiency, % / 100) x (Net Power, kW / Gross Power, kW) )

[Ed.: Equation corrected 12/21/15.]

As we can see from this equation, to reduce the NPHR, we need to increase the boiler efficiency, reduce the net turbine heat rate, or increase the net generation relative to the gross generation.

Boiler Efficiency

Determining your boiler efficiency is effectively determining all of the different inefficiencies resulting from the process of burning fuel to create steam energy. Standards and testing organizations such as the American Society of Mechanical Engineers (ASME) and Deutsches Institut für Normung (DIN) have similar but different metrics for calculating efficiency losses, but from a general standpoint they can be grouped into the following categories.

Sensible Heat Loss. Sensible heat losses can be thought of as heat you can sense directly with a thermometer. For example, combustion air enters your power plant at ambient conditions, and flue gas is exhausted from the cold end of the boiler air heater at some elevated temperature. The closer the exhaust gas is to ambient temperature, the less sensible heat is lost to the environment.

Other sensible heat losses include the heat contained in bottom and fly ash removed from the boiler and pyrites and rock that are rejected from coal mills. The quantity of excess air used for combustion has a significant effect on this loss, as every pound of excess air that travels through the boiler carries with it potentially usable energy.

Latent Heat Loss. Latent heat losses are not easily detectable by a thermometer and are energy losses associated with a phase change of water. When a fuel is burned in a boiler, not only does all moisture contained within the fuel vaporize into steam, but all hydrogen contained within the fuel combusts to form water, which also is vaporized into steam. Unless the temperature of the exhaust gas leaving the boiler air heater is below the boiling point of the water contained within the gas, all of that latent heat of vaporization will exit the boiler and be lost to the environment.

Because latent heat losses are primarily fuel-related, they cannot be easily changed without switching or drying your fuel. (See “Improve Plant Efficiency and Reduce CO2 Emissions When Firing High-Moisture Coals” in the November 2014 issue.)

Unburned Combustible Loss. Unburned combustible losses are efficiency losses from incomplete combustion of fuel in the boiler. This is primarily measured in the form of carbon residue in the ash, but it also includes carbon monoxide (CO) production. These losses are generally influenced by both fuel properties (fuel volatility) and operations practices (excess air level, fuel fineness, and the like). It is important to note that unburned combustible loss is not the same as loss-on-ignition (LOI), as unburned combustible loss is an energy loss, whereas LOI is calculated on a mass basis in the ash.

Radiation and Convection Loss. Utility boilers are enormous equipment systems, with numerous penetrations for tubes and instruments, and a very large surface area exposed to the environment. As a result, no matter how well-designed the insulation is and how diligent plant personnel are in fixing air leaks, energy will still be lost via radiation and convection.

Margin and Unknown Losses. Due to the large size and complexity of the boiler, it is often not practical to measure every single possible source of energy loss from the power plant. As a result, a “margin” or “unknown loss” value is typically used to estimate these losses. Typical values range from 0.5% to 2.0%.

When all of these efficiency losses are taken into account, a typical utility boiler can utilize fuel energy with an efficiency ranging from 83% to 91%.

Improving Boiler Efficiency. Sensible heat losses can be reduced by installing improved combustion controls to allow fine-tuning the excess air level in the furnace operators to reduce the excess oxygen level in the furnace. Preheating combustion air with waste heat from the plant will also increase efficiency, and some plants are considering schemes to use solar thermal collectors as air preheaters during daylight hours.

As latent heat losses are strongly tied to fuel quality, and current boiler designs do not allow for condensing air heaters, outside of switching to a dryer fuel, there is little that can practically be done to reduce latent heat losses.

Unburned combustible losses can be reduced by improved boiler and burner tuning, with some plants able to gain more than 1% in net efficiency as a result of a minor amount of tuning or capital investment.

Turbine Efficiency

Your turbine efficiency is essentially the efficiency of the turbine to convert steam from the boiler into usable rotational energy. A simplified way of viewing your net turbine heat rate (NTHR) is to sum the enthalpy increases of the feedwater and the cold reheat steam across the boiler boundary and divide this by the gross electrical generation.

Determining Turbine Efficiency. As in the case of the overall plant, the turbine cycle heat rate can be expressed on a “gross” or “net” basis. Here the terminology becomes a little tricky, as the gross and net efficiency both utilize the gross output of the generator in their calculations. However, if the power plant has an electric boiler feed pump, then the net turbine heat rate must also subtract out the power consumed by the feed pump; otherwise, that power consumption may skew your NTHR value to appear overly efficient. As a result, our simplified NTHR equation for a single-reheat cycle resembles this:





NTHR = net turbine heat rate, Btu/kWh

HMSOUT = enthalpy of the main steam exiting the boiler envelope, Btu/hr

HFWIN = enthalpy of the feedwater entering the boiler envelope, Btu/hr

HHRH = enthalpy of the hot reheat steam exiting the boiler envelope, Btu/hr

HCRH = enthalpy of the cold reheat steam entering the boiler envelope, Btu/hr

PowerBFP = boiler feed pump power consumption, kW

Improving Turbine Cycle Efficiency. Under ideal conditions, an ultra-supercritical turbine cycle system can convert steam into rotational energy at 54% or higher efficiency, supercritical turbine cycles can achieve 50% efficiency, and subcritical turbine cycles can achieve 46% efficiency. However, the turbine cycle system of your power plant is at least as complex as your boiler system, and there are numerous places for efficiency to be lost.

Bucket tip and packing leakage can constitute 40% of total efficiency loss within the turbine. Nozzle roughness, erosion, and repair can account for 35% of efficiency loss, turbine deposits 15%, and bucket erosion and roughness 10%. Problems in these areas can result in significant efficiency losses: Turbine deposits have been known to cause nearly a 5% efficiency loss and turbine casing leaks as much as a 3% efficiency loss.

It’s vital to know that the turbine is part of a much larger steam and water system that includes condensers, cooling towers, feedwater heaters, deaerators, pumps, and piping—all of which have their own efficiency losses. For example, an increase in condenser backpressure due to dirty tubes of 0.4 inches of mercury can reduce the turbine cycle efficiency by 0.5%. A single split partition plate in a feedwater heater can reduce turbine cycle efficiency by 0.4%. Leaking extraction lines and stuck drain valves can reduce your feedwater heater efficiency, resulting in net cycle losses of greater than 0.5%.

Turbine blade improvements are available for most steam turbines, with improvements of up to 2% possible with a complete replacement of the low-pressure turbine. Even renewable energy can assist with heat rate improvement, as some generators have explored the prospect of solar feedwater heating to boost their turbine cycle efficiency, with some designs able to achieve a peak efficiency improvement of more than 5%. Of course, with all upgrades, you have to examine the economics (see sidebar).

Does it Make Economic Sense?

It’s all very well to propose numerous capital and operations upgrades at your power plant. But which improvements make the most economic sense to the power plant owner? Some plant improvements can be a metaphorical no-brainer, whereas other improvements may require an external market factor, such as a carbon emissions tax, in order to become cost-effective. Table 1 provides a very general ranking of improvements that can be made to pulverized coal-fired power plants, a range of potential heat rate improvements, and their relative economic payback periods. Note that this listing does not include many specific maintenance items that may be found at some power plants, and which may provide large improvements in efficiency when repaired or upgraded.

Table 1. Many options to choose from. Every power plant has unique opportunities for, and challenges to, improving its heat rate. The values show in this table are only general ones based on research from energy efficiency studies. Source: Una Nowling

Electrical Efficiency

For the generator system we are not so concerned about the conversion efficiency of rotational energy to electrical energy, as modern-day generators tend to convert between the two energy types with 98% or greater efficiency. However, a significant portion of the inefficiency seen within this box involves the station service or auxiliary power consumption of the power plant itself.

As most large power-consuming systems at a power plant are needed, little can be gained by eliminating or turning off major equipment systems. Even sacrificing ancillary electrical consumption can have unintended consequences. One scorchingly hot June, I was stationed at a power plant in its engineering office, when a young man from the corporate office had the clever idea of turning off the office lights, bumping the air conditioning to 85F, and unplugging the coffee makers, water fountains, and soda machines. The reasoning was that power prices were more than $1,000/MWh, so he wanted to be able to sell every last Watt possible. What the gentleman had not considered were the potential ramifications of placing a group of plant engineers in a dark, hot office with no cold drinks or coffee. It was not a pretty sight.

As more than 80% of the electrical usage at a power plant is via electrical motors, these should be the primary focus when improving your electrical efficiency. Just the main power plant fans (primary air, forced draft, and induced draft) can consume as much as 2% to 3% of the plant’s gross output. One option for reducing fan power consumption is to use variable-frequency AC drives, especially if the plant tends to operate at lower loads for extended periods of time. Switching all of your main plant fans from conventional to variable-frequency drives could improve your NPHR by more than 0.5%.

Air and gas leakage can account for up to 25% of fan power consumption, so reducing leakage in the air heaters and ductwork can result in a significant fan power savings. Reducing your boiler excess air will reduce fan demand as well. Electrostatic precipitator optimization programs can both increase electrical efficiency and improve particulate collection.

Creative Heat Rate Improvement

Other opportunities that may not appear to affect heat rate may in fact result in significant efficiency improvements.

For example, at one power plant I was told of an improved reclaim hopper design in the coal yard that reduced the time to fill coal bunkers by 2 hours per day. A rough cost-benefit analysis determined that the new hopper design to prevent wet coal from sticking saved a net of $1,700 per year over a five-year period due to reduced coal-handling system operation time. Though that sounds like small potatoes, metaphorically speaking, it also greatly reduced coal yard operator effort during the reclaim process, resulting in a human factors improvement.

Staff at another power plant determined via a fuel quality impact analysis study that the only obstacle preventing them from switching to a higher-heat-content and lower-moisture coal was a sootblower upgrade. Costing a net of $1.3 million, the upgrade resulted in a net improvement in heat rate of more than 2% by allowing use of more-efficient but higher-slagging coals, as well as having a coincident benefit of preventing catastrophic slag falls due to insufficient sootblower coverage. The payback period of this investment was determined to be 18 to 24 months (Figure 2).

2. We did it before—we can do it again. Generators faced with meeting carbon emissions standards should approach the problem from every side of the heat rate equation and work with their experienced staff to find new and innovative ways to get the most out of the coal that they burn. Source: United States Library of Congress (1919)

Final Thoughts

I have never visited a power plant where significant improvements in energy efficiency could not be made. In my lengthy experience, power plant engineers and operators are smart, motivated people who take pride in their job and their plant, and who understand what needs to be done to improve plant efficiency. A century of relatively cheap coal and a focus on plant emissions controls has, unfortunately, taken the focus away from maintaining and improving plant heat rate.

Although some folks in the industry view the proposed EPA carbon emissions standards as an impossible task, many plant engineers and operators I’ve spoken with have been optimistic that they may be given the funding and tools to start winning those heat rate awards once again. ■

Una Nowling, PE (nowlinguc@bv.com) is an adjunct professor of mechanical engineering at the University of Missouri-Kansas City, technology lead for fuels at Black & Veatch, and a POWER contributing editor.