INCREASING EFFICIENCY OF AN EXISTING PC BOILER USING …

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FINAL TECHNICAL REPORT

February 1, 2013, through July 31, 2014

Project Title: INCREASING EFFICIENCY OF AN EXISTING PC BOILER

USING VFDS AND IMPROVED HEAT EXCHANGERS

ICCI Project Number: 13/5A-1

Principal Investigator: Dr. James Mathias, Southern Illinois University

Project Manager: Joseph Hirschi, Illinois Clean Coal Institute

ABSTRACT

This study examined options for increasing the overall efficiency of a coal-fired power

plant by decreasing the auxiliary power load using variable frequency drives (VFDs) on

various motors and by improving heat transfer occurring in the power cycle. The study

was conducted at Southern Illinois Power Cooperative’s Lake of Egypt power plant. The

goal was to identify reductions in auxiliary power that would reduce the parasitic load on

the power plant by 1% and to identify areas of increased heat transfer that would increase

overall plant efficiency by 1%.

In power plants, gas and liquid flowrates are often controlled using dampers or valves

while motors powering pumps and fans stay at full speed resulting in a significant amount

of wasted electrical power. Recognizing this, the host plant installed VFDs on two forced

draft fans supplying air to the cyclone boiler and on two booster fans pushing air through

the scrubber. Energy savings and efficiency improvements resulting from that effort

were analyzed and documented. Then, six additional motors were evaluated for potential

energy savings resulting from installation of VFDs. Results indicate that using VFDs

achieves annual savings totaling 38.5 GWh, or a 2.05% increase in overall plant

efficiency. Total project costs are estimated to be $2.5 million resulting in a simple

payback period of less than two years assuming 0.04 $/kWh.

In addition to the parasitic load on the power plant, energy is also lost due to poor heat

recovery prior to exhaust gases leaving the system. For every degree reduction in the flue

gas temperature by means of heat recovery that is reused elsewhere in the cycle,

2,000 MMBtu of coal could be saved annually. Five heat recovery options were

examined with coal drying proving to be the most viable use of waste heat recovered

from the flue gas. With that option, coal could be upgraded from 11,000 to 11,740 Btu/hr

resulting in savings of $2.28 million annually for a payback period of just 2.1 years. For

this scenario, heat recovery results in a 120°F degree reduction in flue gas temperature

amounting to a 2.54% increase in cycle efficiency.

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EXECUTIVE SUMMARY

With the United States (US) Environmental Protection Agency (EPA) having proposed

more stringent emissions regulations, maintaining and improving cycle efficiency is of

utmost importance to coal-fired power plants striving to reduce emissions and operating

costs. To that end, variable frequency drive (VFD) controls were installed on blowers

supplying air to a pulverized coal boiler (Unit 4) capable of generating 173 MW at

Southern Illinois Power Cooperative’s (SIPC’s) Lake of Egypt power plant. A

preliminary analysis of this effort indicated that VFDs reduced auxiliary power use and

created significant energy savings (Achelpohl, 2014). The purpose of this project was to

document those reductions and savings and to identify and evaluate additional VFD

applications throughout the same plant, which also has a fluidized bed boiler (Unit 123)

capable of generating 120 MW. Furthermore, areas in which improved heat transfer

could boost cycle efficiency were examined.

This study first examined VFDs installed in the previous project to determine how much

energy is being saved (Task 1). Next, several additional motors were analyzed for

potential VFD installation (Task 2). Task 3 determined how much cycle efficiency could

be improved if additional heat were recovered from the flue gas. Then, the best way to

recover and utilize that heat was examined (Task 4). Finally, the entire steam cycle was

analyzed to determine any potential improvements from using heat exchanges as

feedwater heaters (Task 5).

VFDs have proven to be an extremely viable method of saving energy in the right

application. Applications with significant energy saving potential include:

Motors that are oversized for their design load.

Motors that start and stop frequently.

Motors that produce a flow of air or liquid that is significantly controlled by a

valve or damper (throttled).

Initial VFD installations were on Unit 4’s two booster fans and two forced draft (FD)

fans totaling 14,000 HP. Total project cost was $2.9 million, of which $2 million was

provided by government grants. With annual savings of about $900K, this project

achieved a quick payback period even if grants had not been available.

Additional motors analyzed for VFD use included Unit 123’s primary, secondary, and

induced draft (ID) air blowers and Unit 4’s boiler feed and condensate pumps. Each

motor showed potential savings of greater than 40% with three cases exceeding 60%. If

all six VFDs were installed as suggested, potential energy savings could be $1.54 million

annually on a total of 14,600 HP, which is even higher than the initial VFD installation.

With a total project cost near $2.5 million, return on investment could be seen in less than

two years.

The fluidized bed boiler (Unit 123) has flue gas stack temperatures that are regularly

320°F. This is a significant amount of energy that if recovered could help improve

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efficiency by up to 2.54%; however, due to a number of compounding factors the energy

is not recovered easily or cheaply. The major cost is due to the need for a special heat

exchanger. As stack temperature is reduced, there is a greater risk of corrosive

condensate that will likely destroy both the stack and any components inside. Thus,

recovering any additional energy from the flue gas calls for a condensing heat exchanger

set-up that is protected from any corrosive condensate.

There are very few industrial heat exchanger options capable of condensing flue gas and

recovering both sensible and latent heat from it. While the technology exists, it is most

often geared toward natural gas power plants where economic feasibility is much better

due to the fuel’s higher cost, a larger percentage of latent heat available, as well as less

corrosive chemicals in the flue gas.

If a condensing heat exchanger were to be implemented, the heat could be utilized in one

of many ways. Selling to a nearby industry is the simplest and has the lowest capital

cost; however, it is only an option if such an industry were readily available. Preheating

the combustion air at this plant would be very appealing if there were a way to modify

the existing steam-to-air heat exchanger, lowering the total project cost significantly.

Coal drying seems to be a great use of waste heat and is the most economically viable

option; however, it would be even more effective if higher temperature heat were

available or used with coal that is higher still in moisture content. Heating the feedwater

may be a good use of recovered heat in other plants; however, in this plant there is not

enough heat available to completely satisfy the heater’s needs, plus the length of the run-

around loop requires a premium cost to build and run. Organic Rankine cycles proved to

provide a decent amount of power; however, it is still much too low to have a payback

period that would justify the cost of the entire system.

While each project is feasible in principle and each has decent output, the total cost of

recovering most of the waste heat potential is still not economically feasible due to the

high cost of the condensing heat exchanger. The one exception to this is the coal dryer,

which has an excellent payback period. It should be noted that along with any energy

savings comes a reduction in CO2 emissions, which could make any application much

more appealing as EPA requirements continue to become more stringent.

In the final task, the steam cycle analysis did not yield results that would suggest

improvements that could be made in any of the feedwater heaters. All of these heaters

performed at an effectiveness above 77%, with most even in the mid 90% range. This

leaves little room for improvement, let alone any gains that would justify upgrades. Any

changes would have a payback period much too great to justify costs needed for

improvement.

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OBJECTIVES

The purpose of this project was to determine energy efficiency gains by implementation

of variable frequency drives and additional heat transfer capability, as well as to

determine the feasibility of initial cost of investment for each project. These objectives

were accomplished by completing the following five major tasks:

Task 1 Conduct a thorough analysis of variable frequency drives (VFDs) already

installed at the host facility and determine energy savings that are being

achieved.

Task 2 Analyze six other motors which likely have the best potential to result in

savings by implementing VFD technology.

Task 3 Determine the overall plant efficiency increase that can be attained by

improved heat recovery in the flue gas stack.

Task 4 Determine the dew point of the flue gas as well as the best way to recover

additional energy from the stack.

Task 5 Examine five heat exchangers in the plant that have the largest approach

temperature.

INTRODUCTION AND BACKGROUND

Growing energy demand and increasing emphasis on cleaner emissions has caused the

cost of generating electricity to rise and many people have begun looking for more

efficient and/or alternative sources. Most of the United States (US) has been powered by

coal-fired electricity generation for years (US EIA, 2011); yet recent climate change

concerns have begun to erode coal’s market share. In an attempt to remain viable, many

coal-fired plants are looking for ways to compete with natural gas prices and renewable

energy mandates. To do this it is necessary to improve efficiency to meet both consumer

cost and environmental requirements. An increase in efficiency could either reduce fuel

consumption and emissions produced or allow for higher overall power generation to

meet demand without increasing plant size, fuel usage, or emissions. Both scenarios help

make coal a more viable source of energy (Achelpohl, 2014).

There are a few key ways to improve the efficiency of a power plant. The first is to

improve the amount of heat gained from the combustion of the coal. This can be done by

reducing the heat lost at the boiler by the use of additional insulation. The second is to

use more efficient components such as the turbines, generators, or burners. The third is

to reduce the amount of auxiliary power used by the plant. One method of doing this is

to use VFDs on motor driven blowers and pumps. The fourth is to recover as much of

the wasted heat as possible to be reused in the process. This can be done by adding or

improving heat exchange capabilities within various plant systems. This study focuses

on the last two options.

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A mid-sized coal-fired power plant operated by Southern Illinois Power Cooperative

hosted this study. The plant has two completely independent systems. Both are typical

Rankine cycles (Moran and Shapiro, 2008), but each has a different type of steam boiler.

Unit 123 has three turbines supplied by a circulating fluidized bed boiler. The other

system, Unit 4, has one turbine supplied by a common pulverized coal boiler. Unit 123

has a total combined capacity of 120 MW and Unit 4 has a capacity of 173 MW.

In completing this study, a few assumptions were made. All monetary savings are based

on $0.04/kWh for the cost of electricity, which is an average cost determined by the

power plant. All payback periods are based on simple accrual at 0% interest. Flue gas

temperatures used in Tasks 3 and 4 are assumed to be constant at 320°F for the entire

year. Turbine calculations in Task 4 – Case 4 assume turbine efficiencies do not change

regardless of how much steam passing through each stage. Calculations in Task 5 are

based on continuous operation at full load as this was the only steady-state data available.

Variable Frequency Drives

Each system in the host power plant consists of many motors, which were analyzed to

determine where energy could be saved. Auxiliary power is the amount of power used by

these motors and other devices during the power generation process. This generally

includes blowers for air and pumps for working fluid and cooling water. A reduction in

auxiliary power can translate into significant energy savings. This can be accomplished

by installing VFDs on motors. VFDs are used to control the speed of a motor’s shaft.

Prime candidates for VFDs are motors powering devices whose fluid flow output varies

over time or motors powering devices that spend much of their time operating at

conditions that are below the design load.

There are three main types of VFDs: mechanical, hydraulic, and electrical (Saidur et al.,

2011). This study utilizes electrical VFDs, which work by taking typical 60 Hz AC

electricity, converting it to DC electricity, and then discharging pulses of energy that

resemble AC electricity, but at lower frequencies (Dieckmann et al., 2010a) as shown in

Figure 1. The solid blue line represents 60 Hz AC typically supplied to motors and

colored blocks represent electrical pulses output from the VFD to motors with blue

blocks at 60 Hz and orange blocks at 40 Hz. These electrical pulses are in the form of a

sine wave at differing frequencies, causing the motor to run at a different speed. When

an AC motor is powered with energy at a lower frequency, it slows down allowing for

significant energy savings. Figure 2 is a schematic of a VFD system with 60 Hz AC

power entering a control box where it is converted to DC power before pulses of

electrical energy in the form of a sine wave are sent to the motor (Battish, 2011). There

is also a “reference” control loop that measures a desired parameter such as motor speed,

flowrate, temperature, etc. and then sends control signals to the VFD.

It is estimated that 60% of US power generation is used for electric motors representing a

large potential market for VFD use (Lönnberg, 2007). Heating and cooling systems have

utilized VFDs on smaller motors for variable speed compressors and blowers and reduced

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energy usage by about two-thirds (Dieckmann and Brodrick, 2010). Recently, cost and

reliability issues that had previously limited VFD use on large motors in many power

generation applications have been remedied. For example, electrical currents would

travel down the motor’s shaft and discharge through lubricant to bearings causing

lubricant breakdown and electrical pitting on bearing surfaces leading to vibrations and

eventual failure (Bloch, 2010). This has been fixed by electrically grounding the shaft.

Much of the VFD operation is not a simple linear relationship due to many complex

variables (Sun et al., 2013), which caused control issues. Control schemes have

improved, but previous methods of control are often left in place as a fail-safe option.

Figure 1: Sample of VFD Transformed Sine Wave (Achelpohl, 2014)

Figure 2: VFD Set-up Diagram

In pumping applications, a motor and pump are designed for maximum expected load;

however, the normal operating load is often much lower than the design load (Dieckmann

et al., 2010b). Because the desired load is lower than the design load, many facilities will

throttle the fluid by means of a valve, inlet guide vane, or damper (Bhaduri, 2001). This

could be compared to driving a car with one foot depressing the accelerator so the engine

-5000

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-1000

0

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0 0.005 0.01 0.015 0.02 0.025 0.03

Vo

lts

Seconds

VFD 60 Hz VFD 40 Hz AC 60 Hz DC

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runs at maximum power and then controlling the vehicle’s speed by applying brakes.

Using a VFD to control motor speed is akin to controlling vehicle speed using the

accelerator pedal instead of the brake pedal.

The energy saved by slowing a motor down can be proven with the affinity law. This law

states that the minimum amount of power required to generate flow varies with the cube

of the pumped fluid’s flowrate (Bernier and Bourret, 1999). For example, if flowrate is

lowered from 100 cfm to 50 cfm, the power requirement theoretically drops to 1/8th

the

original power (Su, 2011). While this is the ideal, a cubic relationship is not completely

accurate due to losses in the VFDs themselves plus the fact that pumps’ and motors’

efficiencies will vary at different speeds. Instead of assuming the cubic relationship,

which can result in overestimating savings by 7-74% depending on the size of the motor

(Bernier and Bourret, 1999), this study involves a more detailed energy analysis that

incorporates changes in efficiency for both motor and VFD at each load level.

Energy losses due strictly to the VFD’s function are nominally 1.8% (Ramey, 2012).

Even with these losses, reducing a fan’s speed, even if only 15-20%, can result in

significant energy savings. Another benefit of VFD controls is they allow for softer starts

(Phillips, 2004) when a motor uses significantly more than normal operating power.

Softer stops and slower motor speeds can also reduce vibrations, noise level, and

maintenance (Eisenhauer and Williams, 2011). Figure 3 shows power usage for a VFD-

controlled motor versus that of the same motor operating with 60 Hz AC electricity and

flow being throttled by a control valve with the difference being the amount of energy

that could be saved by using a VFD. The VFD power takes into account the minimum

pumping power needed (affinity laws), the efficiency of the motor, and the efficiency of

the VFD itself. The total amount of energy savings will vary based on the application.

Figure 1: VFD vs. Valve Control Power Comparison (Bhaduri, 2001)

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Improved Heat Exchange

Coal-fired power plants have many areas in which heat may be recovered, such as

economizers, feedwater heaters, and super heaters. Improving heat exchange in older

plants may be accomplished with newer, more efficient heat exchangers or by increasing

the size of the heat exchanger. This study considers recovering additional heat in the flue

gas stack by means of a heat exchanger that condenses water moisture from the exhaust,

hereinafter called a condensing heat exchanger. This technology is similar to that used by

a high efficiency condensing furnace in a residential home.

When higher efficiency furnaces were introduced in 1979, non-condensing furnaces with

a burner had a maximum efficiency of around 60%. Pulse furnaces, which generated a

spark for combustion (as opposed to using a pilot light) and an automated damper,

operated at near 80% efficiency. High efficiency furnaces entered the market with an

efficiency of greater than 82% (Brodrick and Moore, 2000) and condensing furnaces

today can reach efficiencies upwards of 90%.

As seen in Figure 4, a high efficiency furnace actually has two heat exchangers, a

primary and a secondary. The primary heat exchanger is very similar to the heat

exchanger in normal furnaces. The secondary heat exchanger must be made of a material

that will withstand the corrosion caused by condensed water, yet is still thermally

conductive. Different alloys of stainless steel were originally used in residential furnaces,

but more recent furnaces use non-metal coatings to protect areas where condensation

occurs (Brodrick and Moore, 2000).

Figure 2: Diagram of a Typical High Efficiency Condensing Furnace (Formisano, 2014)

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These same condensation problems are seen in the flue gas of a power plant. Flue gas

from coal firing contains different chemicals than flue gas from natural gas firing. It is

required to go through pollution control devices where it can condense into a liquid

containing corrosive chemicals such as sulfuric acid that will damage unprotected

surfaces very quickly. If heat exchange will result in condensation, the heat exchanger

must be protected as well as the stack itself. Special alloys and composites comprised of

different combinations of nickel, phosphorus, and copper have proven to protect against

corrosion from flue gas condensate (Liu et al., 2010). Teflon has been applied to the

outside of heat exchanger tubes during their production. Fiberglass reinforced plastic is

commonly used to protect non heat exchanging surfaces such as the stack itself.

If heat (energy) is to be recovered, it should be utilized. Typically heat recovered from

flue gas is low grade heat, which can limit its usability. The Lindal diagram in Figure 5

shows many industrial processes that are capable of utilizing low grade heat. Thus, one

option for using recovered heat is to sell it to an industrial processing plant. An abundant

supply of low grade heat could be an incentive for a company to build such a plant next

to the power plant.

Figure 3: Lindal Diagram (Colorado Geological Survey, 2011)

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Within the plant a few potential uses of the energy are preheating combustion air, coal

drying, heating feedwater, or running an organic Rankine cycle (ORC). The first two

options would reduce the amount of coal input needed while producing the same amount

of power; the latter two would allow for additional electricity to be generated.

In terms of their thermodynamic process, ORCs are essentially the same as a typical

steam Rankine cycle with the only difference being the working fluid. Instead of water,

an organic working fluid, such as a refrigerant that boils at a much lower temperature but

at the same pressure, is used to drive a turbine. ORC’s can utilize heat as low as 165°F

making them an ideal use for low grade heat. The cost of an ORC system ranges from

$1,300 to $3,000 per kilowatt (Arvay et al., 2011). Pay back periods have been as low as

2.5 years; however, this is assuming an electrical cost of $0.15/kWh. Electrical costs this

high are typically only found in Europe or in residential areas. Using the power plant’s

cost of $0.04/kWh to supply power, the payback period would be much longer.

EXPERIMENTAL PROCEDURES

TASK 1: Document Cost of and Energy Savings from Initial VFD Installations

An earlier project supported by the State of Illinois added VFD controls to two forced

draft blowers (4000 HP each) and two booster blowers (3000 HP each) on Unit 4 at the

Lake of Egypt power plant. Installation cost data was provided by the utility company.

To document energy savings, electrical current data for each motor was collected prior to

VFD installation as well as after installation. Current was used because the plant does

not record power used by motors. Due to the timing of air tube repairs that altered

airflow and power required by these blower motors, only 8.5 months of data was accurate

prior to VFD installations. A full year of data was collected post VFD installation.

With this data, a relationship between power used by each fan and total power produced

by Unit 4 was created both pre-VFD and post-VFD as shown in Figure 6, which is a

sample of the data for Forced Draft Blower A. While a clear trend is seen in the data,

there is some spread. Prior to VFD installation, this was likely due to weather changes.

Weather changes were also a factor post-VFD installation, but changes in operators likely

contributed as well.

The amount of time spent operating at various output levels was also analyzed. As seen

in Table 1, the largest percentage of operating time for Unit 4 was at 78% of full load.

As previously discussed, operating at less than full load for extended periods of time

allows for significant energy savings potential.

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Figure 4: Sample Data from Forced Draft Blower A

Table 1: Typical Unit 4 Operation

Unit 4

Gross MW

% of Max

Unit 4

Output Hours

% of

Operating

Year

110 61% 9 0%

115 64% 1 0%

120 67% 634 7%

125 69% 246 3%

130 72% 87 1%

135 75% 98 1%

140 78% 2555 29%

145 81% 493 6%

150 83% 358 4%

155 86% 299 3%

160 89% 269 3%

165 92% 303 3%

170 94% 431 5%

175 97% 1005 11%

180 100% 592 7%

Total 7380 84%

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Energy savings was determined by comparing actual energy used by each motor with

what energy usage would have been with VFDs during the period of data collection prior

to VFD installation. Using Equation 1, power usage was calculated for every hour of

data for both the actual pre-VFD motor current and a post-VFD motor current calculated

using the previously determined relationship between power used and power generated.

The power factor for a typical three-phase motor is about 0.9, while a motor controlled

with a VFD has a power factor of 1.0. Large motors at the plant operate at 4160 V.

√ ( ) ( ) (1)

The difference between the two calculated powers is the amount of power saved. These

savings were added up for the full 8.5-month period of data collection prior to VFD

installation and then extrapolated to a full year. An estimate of $0.04/kWh was assumed

for monetary calculations. Table 2 illustrates the procedure for one motor.

Table 2: Example of Task 1 Procedure

TASK 2: Identify Additional VFD Applications Based on Energy Savings and Cost

The procedure for this task is much more involved than the analysis done in Task 1 due

to so much data available for other motors and the lack of post-VFD data for any of these

motors. Motors considered for VFD application fit the criterion that a VFD generates

significant savings for motors operating in throttled applications or that are rarely at full

load. Motors fitting these operating conditions include primary, secondary (over-fire),

and induced draft (ID) air blowers for the circulating fluidized bed boiler (Unit 123) as

well as condensate and boiler feed pumps for Unit 4. For each motor, one year

(excluding shut-down periods) of fluid flowrate data was collected and compiled and then

a flowrate profile in 5% increments that spans a full year was created. Then energy use

was calculated at each flowrate for two scenarios - without a VFD and with a VFD.

A sample of the first scenario for one motor is shown in Table 3. The “% Motor Power

Needed” column is based on a curve fit to a motor that has been throttled similar to that

shown in Figure 6. The amount of power a motor uses drops slightly when its load is

reduced by throttling, thus creating this curve. The power used at each condition for the

entire year is then calculated using Equation 2 to create the final column.

Plant Gross

MW Produced

Motor

(amps)

Energy Used

Hourly (kW)

Motor

(amps)

Energy Used

Hourly (kW)

Energy Used

Hourly (kW) Cost ($)

200 450 2893 317 2260 633 25.31$

175 419 2693 284 2024 669 26.76$

150 388 2493 250 1787 706 28.22$

125 357 2293 217 1551 742 29.68$

100 326 2093 184 1315 778 31.13$

Pre-VFD Post-VFD Savings

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Table 3: Sample Calculations for Primary Air Blower without VFD

( ) ( )

( ) (

) (2)

The approach for the scenario with a VFD incorporated all of the different efficiencies

from the line to the pump as shown in Figure 7.

Figure 5: VFD System Efficiencies (Bernier and Bourret, 1999)

A sample of the second scenario for the same motor is shown in Table 4. Calculations

incorporate the same flow profile as the first scenario so that the same operational year is

compared. The “Minimum Power WRT Full Load” column refers to the minimum

theoretical power needed to pump the fluid at that condition based on affinity laws (WRT

means “with respect to”), which is essentially the power required at the shaft going into

the pump.

( ) (3)

Values in this column are then divided by the motor’s efficiency at that pumping flowrate

or motor speed to produce the value in the “Power into Motor WRT Full Load” column

as seen in Equation 4. This is the power necessary in the wires going into the motor.

(4)

% of

Design

Flow

% Hours of

Operation

% Motor

Power

Needed

Existing annual

non-VFD energy

use (kWh)

50% 2% 82% 309,357

55% 5% 84% 833,643

60% 6.9% 87% 1,204,590

65% 26.2% 89% 4,640,489

70% 40.8% 90% 7,387,730

75% 16.7% 92% 3,093,132

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This value is then divided by the “VFD Efficiency at Condition” to give the “Power into

VFD WRT Full Load” as seen in Equation 5. This is power going into the actual VFD.

(5)

This value is finally used in Equation 6 to calculate the total energy used at this operating

condition over the operating year.

( ) ( )

( )

(6)

Table 4: Sample Calculations for Primary Air Blower with Proposed VFD

For both scenarios, total energy for all conditions over the operating year is summed.

The difference between these two summations is the total savings if a VFD were to be

installed on the motor.

TASK 3: Calculate Increase in Efficiency by Using Energy from Exhaust Gases

The objective of this task was to determine the overall increase in plant efficiency if

additional heat were to be recovered from the flue gas. Unit 4 flue gas was not

considered as it has a scrubber and other emissions equipment that lowers flue gas

temperature to near 120°F. Flue gas from the Unit 123 CFB is regularly near 320°F

allowing for a large amount of potential heat recovery.

Calculating the overall increase in efficiency required determining coal cost and energy

content, as any energy recovered would directly result in a reduction of coal use when

determining monetary savings. The amount of energy required per unit of electrical

power (MW) produced by the plant and typical flue gas flowrates were also required.

Thermophysical properties of air were obtained from Engineering Equation Solver

(EES). Recovered energy was calculated using Equation 7 and then multiplied by the

cost and energy content of coal ($2/MBtu) to determine hourly savings.

( ) ( ) (7)

% of

Design

Flow

% Hours of

Operation

Minimum

Power WRT

Full Load

Motor

Efficiency at

Condition

Power into

Motor WRT

Full Load

VFD

Efficiency at

Condition

Power into

VFD WRT

Full Load

New energy use

using hours of

operation (kWh)

50% 2% 12.1% 84.5% 14.3% 89.5% 16% 59,960

55% 5% 16.1% 89.5% 17.9% 92.3% 19% 191,885

60% 6.9% 20.9% 92.4% 22.6% 93.9% 24% 334,728

65% 26.2% 26.5% 93.9% 28.3% 94.7% 30% 1,562,471

70% 40.8% 33.1% 94.8% 35.0% 95.2% 37% 2,997,514

75% 16.7% 40.8% 95.5% 42.7% 95.5% 45% 1,497,768

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The efficiency increase of the plant with respect to the nominal efficiency can be found

using Equation 8 where energy recovered (see Equation 7) is divided by the current

efficiency of the cycle (12,000,000 Btu/hr/MW) and then divided by the average energy

generation of the plant.

( ) (

)

(

) ( )

(8)

TASK 4: Determine How to Utilize Heat Recovered from Exhaust Gases

The objective of this task was to determine at what temperature flue gas condenses and

how to best recover and utilize the wasted energy found in Task 3. This required an

energy analysis to determine feasible temperatures of a run-around loop obtained by

transferring recovered energy from the flue gas. Then five cases were examined to

determine their ability to utilize the recovered heat and to assess their economic

feasibility. Case 1 considered selling the waste heat to a nearby manufacturer. Case 2

used the heat to help preheat combustion air going into the boiler. Case 3 utilized the

heat in a coal dryer. Case 4 transferred the heat to the lowest pressure feedwater heater to

reduce the amount of steam extracted from the turbine. Case 5 used the heat to power an

organic Rankine cycle (ORC).

A condensing flue gas heat exchanger was discussed with a qualified consultant and it

was determined that the project is possible (Burch, 2014). It has rarely been implemented

in coal-fired power plants due to the low cost of coal and the fact that flue gas from a

coal-fired boiler has less latent heat content than flue gas from other fuels; however, there

is still a significant amount of recoverable energy. One possible configuration is shown

in Figure 8. The heat exchanger would be Teflon-coated and the stack would be

fiberglass-reinforced plastic to protect them from corrosive condensation.

Each case requires a condensing heat exchanger in the exhaust stack to recover energy

from the flue gas as well as a loop containing a fluid, likely water, to transfer the

recovered heat from the stack heat exchanger to the area of the plant in which it will be

utilized. A schematic of the proposed system is shown in Figure 9.

Case 1: Selling Waste Heat to a Nearby Manufacturer

This case pumps the recovered heat by means of a run-around loop to a nearby industry

plant of some sort. For this case, the utility company would need to lure a manufacturer

to build nearby the power plant. This manufacturer would be one that typically acquires

heat needed for processes by burning natural gas. Potential industries that may be

interested in purchasing the waste heat are identified in Figure 5.

16

Figure 6: Condensing Heat Exchanger (Condensing Heat Exchanger Corp., 2014)

Figure 7: Schematic of System to Distribute Recovered Waste Heat

17

Case 2: Preheating Combustion Air

This case utilizes the recovered heat in a heat exchanger to preheat combustion air prior

to entering the boiler. Currently steam is used to preheat air so that it will not condense

on any of the injectors. If recovered heat is used to preheat air, this steam could instead

be sent through the turbine to create additional power.

The proposed system incorporates a liquid-to-air heat exchanger similar to an

economizer; however, instead of air heating liquid, liquid heats combustion air with

energy recovered from the stack. For this case, a full energy analysis was completed

using EES to determine how much heat could actually be transferred to combustion air.

Calculations began by determining how much energy could be recovered from the flue

gas (Equation 7). Knowing the difference in enthalpies required, a stack exit temperature

leaving the proposed condensing heat exchanger of 200°F was chosen based on what

would be a feasible effectiveness of the air-to-water heat exchanger and knowing that the

stack temperature is regularly at 320°F.

Next, the flowrate of the heat transfer fluid loop was calculated using Equation 9. The

temperature of the fluid entering the stack heat exchanger is 130°F, which was chosen

based on having at least 50°F difference between the stack exit temperature and the

temperature of the ambient air that will be heated. Thus, the temperature of the fluid

leaving the condensing heat exchanger is 260°F based on a feasible effectiveness of heat

exchange between this fluid loop and the combustion air.

(

)

(

)

(

)

(9)

Finally, the enthalpy of heated air was determined using Equation 10. Using this

thermophysical property, the preheated combustion air temperature was determined.

(10)

Case 3: Drying Coal

This case utilizes the recovered heat in a coal dryer to reduce the moisture content of coal

entering the boiler for combustion. This results in a decrease in the total amount of coal

needed to produce the same amount of power. Data regarding the amount of waste heat

available and its temperatures were sent to Carrier Vibrations Inc. for a project quote and

analysis of potential improvements to coal quality.

Case 4: Heating Feedwater

This case transfers the recovered heat to the lowest pressure feedwater heater of Unit 4’s

steam cycle. Feedwater entering the heater is at 106°F and the hot water from the

18

condensing heat exchanger was predicted to be at 260°F. Equation 11 shows how the

total heat requirement of the heater was found. Steam is typically extracted from the

turbine and used to heat the feedwater. By using recovered energy to heat the feedwater

instead of steam, the steam is instead passed through the final stages of the turbine to

create additional power. Equation 12 was used to determine the flowrate of additional

steam available to pass through the turbine and to determine how much power is made.

(

) ( ) (11)

(

)

( ) ( ) (12)

Case 5: Organic Rankine Cycles

This case makes use of the recovered heat by powering an organic Rankine cycle (ORC).

The additional power made by the ORC is then sold for profit. The ORC would be

purchased as a complete system and all energy calculations were completed by the

manufacturer. A typical ORC system schematic is shown Figure 10. Data regarding

stack temperatures and flowrates were collected and provided to the manufacturer to

complete their analysis.

Figure 8: Schematic of Typical ORC (Hattiangadi, 2013)

19

TASK 5: Examine Heat Exchangers at the Plant

Based on a recommendation from the company hosting the study, low- and high-pressure

feedwater heaters on Unit 4 were evaluated for potential to increase the plant’s overall

efficiency by making improvements to them. Analysis of these heaters required an in-

depth study of Unit 4’s entire steam cycle, which is shown in Figure 11.

In Unit 4, the main steam from the boiler first enters the high-pressure turbine where the

first amount of steam is extracted and the remaining steam continues back through the

reheat cycle. After the reheat cycle, steam enters the intermediate pressure turbine where

the second amount of steam is extracted at two different stages and the remaining steam

finishes through the turbine before entering the low pressure turbine. Here the working

fluid splits in opposite directions with multiple extraction points. Once the steam has

been expanded to its lowest pressure, it enters the condenser where it is then condensed.

At this point the working fluid is referred to as condensate, until it reaches the deaerator,

after which it is referred to as feedwater.

Low- and high-pressure feedwater heaters are similar to that seen in Figure 12. Each

extraction steam line is piped to one of the feedwater heaters. The extraction steam then

condenses within the heater as it transfers heat to the condensate/feedwater. The

condensation from the extraction steam collects at the bottom of the heater to maintain a

consistent level that is monitored. This condensate leaves the heater through a drip line

where it passes through a valve lowering the pressure to that of the lower heater and the

drips partially consist of vapor. This vapor then joins the next lower pressure extraction

steam in the subsequent heater.

To properly analyze each heater, data was collected regarding steam, feedwater, and

condensate flowrates as well as temperatures and pressures at each necessary state point.

This data is seen in Table 5. The entire cycle was then modeled using EES.

Calculations in the software included results of effectiveness of each heater as well as the

turbine efficiency at each steam extraction point. Effectiveness was defined as the actual

amount of heat transferred (Equation 13), compared to the maximum amount of heat

transfer possible (Equation 14). The maximum heat transfer was defined as the enthalpy

difference between saturated steam and entering feedwater. Effectiveness was then the

ratio between the actual and maximum heat transfers (Equation 15). Turbine efficiencies

were calculated using classic methods based on the actual drop in enthalpy compared to

the isentropic drop in enthalpy (Equation 16).

( ) (13)

( ) (14)

(15)

(16)

20

Figure 9: Unit 4 Steam Cycle

21

Figure 10: Diagram of a Typical Closed Feedwater Heater (Moran and Shapiro, 2008)

Table 5: Feedwater Heater State Point Data

RESULTS AND DISCUSSION

TASK 1: Document Cost of and Energy Savings from Initial VFD Installations

The total savings in terms of power and dollars resulting from the initial VFD installation

project is seen in Table 6. Figure 13 shows total costs for the installation broken down by

project cost category. State and federal government grants provided $2 million of the

total $2.9 million cost of the project. This resulted in a simple payback period of

approximately one year; without grants the simple payback period would be just over

three years. The initial VFD installations have now been in operation for three years

without any major maintenance issues.

State

Point Description

Temperature

(°F)

Pressure

(psia)

Flowrate

(kpph)

12 Entering lowest pressure feedwater heater 4-1 106 91.7 911

13 Entering feedwater heater 4-2 156 108.7 911

14 Entering feedwater heater 4-3 195 105.7 911

15 Entering Deaerator 266 81.7 911

16 Entering feedwater heater 4-5 320 2408 1414

17 Entering feedwater heater 4-6 355 2215 1414

22

Table 6: Total Savings of Task 1

Figure 11: Project Cost Breakdown

TASK 2: Identify Additional VFD Applications Based on Energy Savings and Cost

After completing a detailed energy analysis, energy saving results for VFD installations

on five additional motors is shown in Table 7. Due to a lack of flowrate data for the ID

blower, calculations for this motor are a conservative estimate based on combined

flowrates of primary and secondary air blowers. If operating flowrate were available for

the ID blower, a more detailed analysis could suggest savings of as much as $410,000

annually. Operating hours in a year vary slightly due to differences in years that the data

was collected. There is also a difference between Unit 123 and Unit 4 in the amount of

time spent in shut-down periods. Data for primary, secondary, and ID air fans was

collected while Unit 123 was operating above 80 MW, and data for pumps was collected

while Unit 4 was operating above 100 MW. Total energy savings for the proposed VFD

installations is 38.5 GWh, which amounts to approximately 2.05% increase in overall

cycle efficiency. All monetary savings were evaluated based on a $0.04/kWh.

Annual savings kWh

$ (assuming

$0.04/kWh)

FD A 5,489,277 219,571

FD B 5,992,786 239,711

Booster A 5,652,144 226,086

Booster B 5,626,483 225,059

Total 22,760,690 910,428

23

Table 7: Summary of Task 2 Savings

A summary of total project costs for Task 2 can be seen in Table 8. Housing costs for

VFDs will vary based on the space in which they are placed. A quote from a nearby

contractor was obtained for a 416 square foot building for housing VFD for the three

blowers for the CFB if there is adequate space available, otherwise each could be housed

individually. Each VFD requires two feet of overhead clearance for ventilation and three

feet of clearance around the unit for maintenance. Clearance space around VFDs could

be shared if two VFDs were placed facing each other. A factory authorized start-up and

testing procedure must be completed on each installed VFD and will take a minimum of

four days per VFD. Project management and engineering costs were scaled from the

previous project analyzed in Task 1. VFD prices and startup costs were quoted by a local

electrical equipment supplier (Baker, 2014). With a total cost of about $2.5 million, the

project has a simple payback period of less than two years.

Table 8: Summary of Task 2 Project Costs

TASK 3: Calculate Increase in Efficiency by Using Energy from Exhaust Gases

Task 3 results show that for every 1°F reduction of the flue gas temperature by means of

heat recovery that is reused elsewhere in the cycle, 2,000 MMBtu of coal is saved

VFD Cost

Motor MWh $ MWh $ MWh $ % $

PRIMARY AIR 3500 7670 17,951 718,030 6,925 277,003 11,026 441,026 61% 412,000

SECONDARY AIR 1000 7552 4,933 197,309 1,628 65,133 3,304 132,175 67% 197,500

ID BLOWER 3500 7553 18,352 734,098 10,997 439,873 7,356 294,225 40% 412,000

BOILER FEED (A) 3000 7390 15,334 613,356 8,541 341,629 6,793 271,727 44% 412,000

BOILER FEED (B) 3000 7390 14,945 597,795 6,721 268,839 8,224 328,956 55% 412,000

CONDENSATE 600 7233 2,882 115,260 1,120 44,813 1,761 70,447 61% 185,000

Total 14,600 38,464 1,538,556$ 2,030,500$

Blo

wer

sPu

mps

Pre VFD Post VFD SavingsOperating

Hours

Power

(hp)

Project Summary Unit Cost Unit Size (HxWxD)

Primary Air 412,000$ 103.7x174x49.5 in.

Secondary Air 197,500$ 103.7x122x43.4 in.

ID Fan 412,000$ 103.7x174x49.5 in.

Boiler Feed (A) 412,000$ 103.7x174x49.5 in.

Boiler Feed (B) 412,000$ 103.7x174x49.5 in.

Condensate 185,000$ 103.7x48x48 in.

VFDs Sub-Total 2,030,500$ -

Project Management and

Engineering 300,000$ -

Testing for Suitabliity on Boiler Feed

Water Pumps ($15,000 per pump) 30,000$ -

Structure to House VFDs (Primary,

Secondary, and ID Air Blowers only) 32,000$ 11x26x16 ft.Startup Procedure ($12,000 per VFD) 60,000$ -

Project Total 2,452,500$ -

VFD

Info

A

ddit

iona

l Co

sts

24

annually. Heat recovery resulting in a 120°F reduction, as suggested in Task 4, amounted

to a 2.54% increase in cycle efficiency, as shown in Figure 14. This is approximately a

0.87% increase in total plant efficiency.

Table 9: Savings Relative to Temperature Reduction

Figure 12: Plant Efficiency Gains by Stack Temperature Reduction

Exhaust gas

lowered by (°F)

Annual Coal

Cost Saved

10 40,054$

20 80,075$

30 120,064$

40 160,020$

50 199,946$

60 239,841$

70 279,708$

80 319,547$

90 359,359$

100 399,145$

110 438,906$

120 478,643$

25

A system in which flue gas enters another heat exchanger, similar to a second

economizer, and partially condenses prior to leaving the stack was determined to be

suitable for this application. There are very few manufacturers of heat exchangers

capable of withstanding the corrosive nature of coal flue gas condensate. Condensing

Heat Exchanger Corp. makes a system in which the heat exchanger tubes are coated in

Teflon and the exhaust stack is made of fiberglass-reinforced plastic to withstand the

corrosive condensate. They determined a cost estimate of approximately $2 million

(Brooks, 2014) for a system of suitable size for the power plant evaluated in this project.

TASK 4: Determine How to Utilize Heat Recovered from Exhaust Gases

Case 1: Selling Waste Heat to a Nearby Manufacturer

Task 3 results showed that there would be approximately 2.4 million therms available to

sell annually. Over the past five years, the industrial cost of natural gas has varied from

$0.34 to $0.75 per therm, averaging around $0.53 per therm. This equates to $1.27

million if the plant were able to sell all of the recovered heat to a nearby industry at a

similar price. Total cost was almost $3 million with the heat exchanger being the majority

of the cost as shown in Table 10. It is unlikely a company could be lured to build next to

the plant if the energy were to be sold at market cost; thus, assuming the plant could sell

the energy at 50% of market value, the payback period would be 4.6 years.

Table 10: Case 1 (Selling Energy) Project Material Costs

Case 2: Preheating Combustion Air

Parametric tables in EES allowed for determination of recovered heat quantities that were

then transferred to the combustion air. This process suggests that it is practical to recover

heat from the stack resulting in the stack temperature dropping from 320°F to 200°F.

This amount of recovered energy allows for combustion air to be preheated from 70°F to

190°F resulting in a yearly savings of 244 MMBtu in coal usage. At present, the plant

requires 12 MMBtu per MWhr produced. With the energy recovered in this case, the

heat requirement for one MWhr drops to 11.7 MMBtu, an improvement of 2.54%. Total

cost was about $3.3 million with annual savings of nearly $410,000 resulting in an 8.1-

Part/Model Supplier Deliverable Quantity Cost

Condensing Heat Exchanger Condensing Heat Exchanger Corp 30 mmBTU/hr 1 2,000,000$

Pump, Centrifugal, CI, 15 HP,

3CCW3 Grainger

350 GPM (125

FT of head) 2 7,600$

3 in. Standard-Wall Black Steel

Threaded Pipe (4457K67) McMaster-Carr 10.5 FT 115 22,658$

Pipe Insulation, Seam-Seal, 3

1/2 In, 6 Ft (2CKP7) Grainger 6 Ft 202 11,595$

Low-Pressure Pipe Couplings

(44605K82) McMaster-Carr 3 in. 115$ 4,309$

Estimated Installation 842,325$

Total 2,888,487$

26

year simple payback period. A summary of material costs is provided in Table 11

showing that the heat exchanger is the major cost.

Table 11: Case 2 (Preheating Air) Project Material Costs

Case 3: Drying Coal

A quote from Carrier Vibrating Equipment indicates that drying coal with recovered heat

could upgrade the coal from 11,000 Btu/lb to 11,740 Btu/lb (Mueller, 2014) with

moisture content reduced from 11% to 5%. This results in coal use being lowered by

almost 50,000 tons/year. A 13'-10" wide x 33'-0" long stationary fluidized bed with in-

bed heat exchangers was quoted for this project. The cost of the coal dryer and some

auxiliary equipment such as supply and exhaust fans was $1.45 million. Total cost

including the run-around loop and condensing heat exchanger was about $4.8 million as

shown in Table 12 and additional operating costs for pumps and fans was approximately

$180,000/year. Net annual savings amounted to nearly $2.28 million resulting in a 2.1-

year simple payback period.

Table 12: Case 3 (Drying Coal) Project Material Costs


Condensing Heat Exchanger Condensing Heat Exchanger Corp 30 MBTU/hr 1 2,000,000$

Air Preheater/Heat Exchanger *estimated 30 MBTU/hr 1 173,125$


3CCW3 Grainger

350 GPM (125







(44605K82) McMaster-Carr 3 in. 38 1,424$

Estimated Installation 1,136,964$

Total 3,330,445$



Coal Drying System Carrier Vibrating Equipment, Inc.

108 tons/hr

of coal 1 1,450,000$


3CCW3 Grainger

350 GPM (125

FT of head) 3 11,400$








Total 4,782,433$

27

Case 4: Heating Feedwater

Heat recovered from the flue gas stack is equivalent to 73% of the heat currently supplied

to the lowest pressure feedwater heater. Using it for that purpose allows additional steam

to pass through the low-pressure turbine. Determining the efficiency of final stages of

the turbine was difficult due to uncertainties about the quality of fluid leaving the turbine

so an efficiency of 70% was assumed based on other nearby stages. The additional steam

passing through the turbine generated an additional 0.522 MW of electrical power. Total

cost was about $3.4 million as shown in Table 13 with annual savings of nearly $170,000

resulting in a 20.1-year simple payback period.

Table 13: Case 4 (Heating Feedwater) Project Material Costs

Case 5: Organic Rankine Cycles

Two manufacturers provided quotes for an ORC system. The first manufacturer, Infinity

Turbine, offered ORCs with radial turbines, identified herein as Turbine A. Their largest

was the IT250 Radial Outflow Turbine. It has a maximum output of 0.25 MW and

utilizes 11 MMBtu of heat input. With about 30 MMBtu available, three of these

systems would be needed at a cost of $500,000 each (Giese, 2014). Total cost for a

Turbine A system was about $4.8 million with annual savings of nearly $240,000

resulting in a simple payback period of 20.1 years.

The second manufacturer, Transpacific Energy, offered an ORC system with an axial

turbine, identified herein as Turbine B. Their quote was for a system costing $3 million

that provides a gross power output of 1 MW (Sami, 2014). Total cost for a Turbine B

system was about $6.8 million with annual savings of nearly $320,000 resulting in a

simple payback period of 21.3 years. A summary of project costs for both Case 5 options

is provided in Table 14.



Plate Heat Exchanger RS Means 2200 GPM 1 165,000$


3CCW3 Grainger

350 GPM (125









Total 3,363,390$

28

Table 14: Case 5 (ORC System) Project Material Costs

A summary of total cost, predicted annual savings, and payback period for each case is

provided in Table 15. For cases that generate additional power, monetary savings were

determined assuming an electricity cost of $0.04/kWhr. In the other cases, any energy

recovered and reused in the cycle directly resulted in a reduction in the amount of coal

used. Thus, energy content and cost of coal was used to determine monetary savings.

Installation costs for large items such as the condensing heat exchanger, coal dryer, and

ORC systems were assumed to be one-third of the material cost, which is experience with

the large VFD installation project analyzed in Task 1 (Achelpohl, 2014). For all other

materials such as piping, the installation cost was assumed to be equal to the material cost

based on a professional engineer’s recommendation (Green, 2014).

Case 1 requires the lowest investment to implement in terms of total cost; however,

predicted annual savings for Case 3 is clearly superior to the other options and makes it

the option with the shortest payback period.

Table 15: Total Cost and Payback Period for All Cases




3CCW3 Grainger

350 GPM (125








Pre ORC Total 2,023,678$

(A) IT250 Radial Outflow

Turbine (x3) Infinity Turbine 0.75 MW 1 1,500,000$

(B) ORC System (Axial Turbine) Transpacific Energy 1 MW 1 3,000,000$

(A) Estimated Installation 1,297,355$

(B) Estimated Installation 1,797,355$

Project Total (A) With Infinity Turbine 4,821,033$

Project Total (B) With Transpacific Energy Turbine 6,821,033$

Case Purpose Total Cost

Predicted Annual

Savings

Payback Period

(years)

Case 1 Selling Energy 2,888,487$ 625,000$ 4.6

Case 2 Preheating Air 3,330,445$ 409,139$ 8.1

Case 3 Drying Coal 4,782,433$ 2,276,144$ 2.1

Case 4 Heating Feedwater 3,363,390$ 167,040$ 20.1

Case 5 (A) ORC 4,821,033$ 240,000$ 20.1

Case 5 (B) ORC 6,821,033$ 320,000$ 21.3

29

TASK 5: Examine Heat Exchangers at the Plant

A temperature versus entropy diagram of the Unit 4 cycle is shown in Figure 15. Results

showing heater effectiveness are provided in Table 16. Each heater’s effectiveness was

examined at full load, as this was where the system operates almost all of the time, and

this was deemed to be adequate. These results show that any changes made to the

existing system would not be economically feasible or prudent.

Figure 13: Temperature vs. Entropy Diagram of Unit 4 Cycle

Table 16: Results of Heater Effectiveness Analysis

Heater Effectiveness

Low Pressure 4-1 0.9615



Deaerator 0.9297

High Pressure 4-5 0.7787

High Pressure 4-6 0.8253

1801.1 psia

30

CONCLUSIONS AND RECOMMENDATIONS

VFDs

VFDs were cost effective for all six motors examined.

If there is adequate space, appropriate ambient temperature, and dust control,

all six motors are recommended to be fitted with VFDs.

Waste Heat Recovery

Heat in the flue gas stack is free, but recovering and utilizing it is not free.

A condensing heat exchanger protected from corrosion is expensive, but it is

still a viable option.

Selling recovered heat to a nearby manufacturer or utilizing it in a coal dryer

are the best options and both are worth pursuing further.

Feedwater Heaters

All feedwater heaters in the model facility are working properly and

efficiently.

Many of the temperatures and pressures of drips did not correspond to

saturated conditions. Using the saturation temperature related to the pressure

produced logical results. It is recommended to check temperature sensors and

their locations.

With properly written equations, Engineering Equation Solver (EES) can

automatically calculate turbine efficiencies, effectiveness of heat exchangers,

and quality of steam at any condition and plot results.

ACKNOWLEDGEMENTS

The principal investigator would like to thank the Illinois Clean Coal Institute (ICCI) and

Dr. Hirschi for their funding, support, and assistance during this project. Likewise, the

cooperation and assistance provided by Southern Illinois Power Cooperative (SIPC) in

regards to data collection and knowledge of plant systems, especially the work of Clark

Madden and Scott Achelpohl, is greatly appreciated. Also, the assistance given by Justin

Harrell, Physical Plant Engineer at SIUC, and his background working with variable

frequency drives is sincerely valued and was extremely beneficial in getting the project

started in the right direction. Finally, the principal investigator would like to thank

graduate assistant, Jeff Green, for his efforts with the project.

31

REFERENCES

Achelpohl, S., 2014. “Installation and Results of Variable-Frequency Drives at a Mid-

Sized Power Generation Facility.” ASHRAE Transactions 120.2.

Arvay, P., Muller, M.R., Ramdeen, V., and Cunningham, G., 2011. “Economic

Implementation of the Organic Rankine Cycle in Industry.” American Council for

an Energy-Efficient Economy, Summer Study on Energy Efficiency in Industry:

12-22.

Baker, J., 2014. “Variable Frequency Drive Costs.” Project Quote from Flanders Electric

provided to J. Green.

Battish, R., 2011. “The 4-1-1 on Variable-Frequency Drives.” EC&M Electrical

Construction & Maintenance 110.5: 12-16.

Bernier, M.A. and Bourret, B., 1999. “Pumping Energy and Variable Frequency Drives

Drives.” ASHRAE 41.12: 37-40.

Bhaduri, A., 2001. “The Use of Variable Frequency Drives in Existing HVAC

Installations.” Indian Society of Heating, Refrigerating and Air-Conditioning

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Bloch, H.P., 2010. “Variable Speed Drives; Bearings (Machinery); Machine Parts --

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Brodrick, J.R. and Moore, A., 2000. “Conquering Corrosion.” ASHRAE Journal 42.4: 29-

35.

Brooks, J., 2014. “Condensing Heat Exchanger Costs.” Project Quote from Condensing

Heat Exchanger Corp. provided to J. Mathias.

Burch, T., 2014. “Condensing Heat Exchanger Information.” Personal Communication

between J. Green and Auburn University Visiting Assistant Professor.

Colorado Geological Survey, 2011. “Geothermal - Direct Use.” Colorado Department of

Natural Resources.

Condensing Heat Exchanger Corp., 2014. “CHX™: Engineered to Perform New or

Retrofit.” http://www.chxheat.com/perform.html, Accessed September 12.

Dieckmann, J. and Brodrick, J., 2010. “VFDs for Residential Systems.” ASHRAE Journal

52.8: 66-68.

Dieckmann, J., McKenney, K., and Brodrick, J., 2010a. “Variable Frequency Drives, Part

1: The Technology.” ASHRAE Journal 52.4: 60-62.

32

Dieckmann, J., McKenney, K., and Brodrick, J., 2010b. “Variable Frequency Drives, Part

2: VFDs for Blowers.” ASHRAE Journal 52.5: 58-62.

Eisenhauer, J. and Williams, D., 2011. “Variable-Frequency Drive Improves Boiler

Operation.” Heating/Piping/Air Conditioning Engineering 83.1: BSE18-BSE21.

Formisano, B., 2014. "Anatomy of a High Efficiency Condensing Furnace."

http://homerepair.about.com/od/heatingcoolingrepair/ss/Anatomy-Of-A-High-

Efficiency-Condensing-Furnace.htm, Accessed September 4.

Giese, G., 2014. “ORC System Quote.” Project Quote from Infinity Turbine provided to

J. Green.

Green, R., 2014. “Estimating Installation Costs.” Personal Communication with J. Green.

Hattiangadi, A., 2013. “Working Fluid Design for Organic Rankine Cycle (ORC)

Systems.” Master’s Thesis, Delft University of Technology, pg. 2.

Liu, G., Yang, L., Wang, L., Wang, S., Chongyang, L., and Wang, J., 2010. “Corrosion

Behavior of Electroless Deposited Ni–Cu–P Coating in Flue Gas Condensate.”

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Lönnberg, M., 2007. “Variable Speed Drives for Energy Savings in Hospitals.” World

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Moran, M.J. and Shapiro, H.N., 2008. Fundamentals of Engineering Thermodynamics.

Wiley, Hoboken, NJ, 6th

Ed.

Mueller, R., 2014. “Coal Dryer Quote.” Project Quote from Carrier Vibrating Equipment


Phillips, J., 2004. “Side-by-Side Test Verifies VFD Energy Saving.” HPAC Heating,

Piping, Air Conditioning Engineering 76.5: EGB18-EGB19.

Ramey, Joseph T. "Variable Frequency Drives for Centrifugal Pumps." Chemical

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“Applications of Variable Speed Drive (VSD) in Electrical Motors Energy

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Sami, S, 2014. “ORC System Quote.” Project Quote from Transpacific Energy, Inc.


33

Su, H., 2011. “Modeling of Proposed Changes to SIUC Central Heating, Air

Conditioning, and Power Plant Incorprating Variable Frequency Drives and High

Efficiency Turbine.” Master’s Thesis, Southern Illinois University.

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Frequency Induction Motor Drive System.” Transactions of the Institute of

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Source.” US Department of Energy.

34

APPENDICES

35

Appendix A: Nomenclature

CFB Circulating Fluidized Bed

cfm cubic feet per minute

Cp Specific heat of feedwater

hin Enthalpy before turbine expansion

hnew Enthalpy of flue gas after losing heat to heat exchanger

horiginal Enthalpy of flue gas prior to heat removal

hout Actual enthalpy after turbine expansion

h'out Ideal enthalpy after turbine expansion

HX Heat exchanger

ICCI Illinois Clean Coal Institute

Flowrate

ηm Efficiency of Electric Motor

ηturbine Efficiency of turbine

ηvfd Efficiency of Variable Frequency Drive

ORC Organic Rankine Cycle

p Efficiency of Pump

Pin Required electrical power going into VFD

Pm Electrical power going into motor

Pshaft Shaft power going into pump

Ptheo Theoretical pumping power

Qactual Actual heat transferred

Qf.w. Flowrate of feedwater

Qthemaxo. Theoretical Maximum heat transferred

Tf.w. in Temperature of feedwater entering heater

Tf.w. out Temperature of feedwater exiting heater

TSat. Ext. Steam Saturation temperature of extraction steam

VFD Variable Frequency Drive

WRT With respect to

36

Appendix B: Variable Frequency Drive Calculator Sample

PR

IMA

RY

AIR

BLO

WER

Thro

ttlin

g C

oe

ffic

ien

ts

76

70

Op

erat

ing

Ho

urs

C0

0.5

52

1C

00

.96

74

11

01

1C

00

.97

$0

.04

0el

ectr

ic c

ost

($

/kW

h)C

10

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70

C1

-19

.99

40

27

84

C1

-26

.42

36

10

24

35

00

Mo

tor

Ho

rsep

ow

er (

No

min

al)

C2

-0.1

90

0C

20

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54

74

86

C2

0.0

34

02

11

18

60

%P

um

p E

ffic

ien

cy

33

88

.03

Pu

mp

Des

ign

BH

P

(SH

AFT

PO

WER

)W

eigh

t0

.01

LB/G

allo

n

96

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Mo

tor

Effi

cien

cy @

Des

ign

Lo

ad6

5IN

WC

97

%M

oto

r D

esig

n L

oad

89

9K

LB/H

R

75

%M

oto

r Lo

ad B

EP5

.37

5FT

32

72

.83

7D

esig

n L

oad

Mo

tor

Po

wer

14

97

66

6.6

67

GP

M

% o

f D

esig

n

Flo

w

% H

ou

rs o

f

Op

erat

ion

% M

oto

r

Po

wer

Nee

ded

Exis

tin

g an

nu

al n

on

-

VFD

en

ergy

use

(kW

h)

Min

imu

m

Po

wer

WR

T

Full

Load

Mo

tor

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cien

cy a

t

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nd

itio

n

Po

wer

into

Mo

tor

WR

T

Full

Load

VFD

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icie

ncy

at C

on

dit

ion

Po

wer

into

VFD

WR

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ll Lo

ad

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ergy

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usi

ng

ho

urs

of

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erat

ion

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ngs

(Dif

fere

nce

)

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58

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5.5

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49

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1%

00

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%

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64

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%

20

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7%

00

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13

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58

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25

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0%

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23

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60

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30

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3%

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37

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7.0

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2.0

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0%

06

2.9

%

35

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0%

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34

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1,5

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5

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4

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97

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4

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%

80

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94

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31

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96

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51

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95

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54

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47

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8

40

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85

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96

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7,4

22

5

9.3

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6.4

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1.6

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4%

31

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0

3

1.6

%

90

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97

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6

7

0.4

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6.6

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6.4

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6%

1,9

74

2

1.5

%

95

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99

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82

.8%

96

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85

.8%

96

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89

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9.8

%

10

0%

01

00

%9

6.6

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6.1

%1

00

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96

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10

4%

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%

10

5%

10

1%

11

1.8

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17

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97

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12

1%

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11

0%

10

2%

12

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%9

3.8

%1

37

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97

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14

1%

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11

5%

10

3%

14

6.9

%9

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60

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96

.8%

16

6%

-62

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12

0%

10

4%

16

6.9

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8.4

%1

88

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96

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19

6%

-91

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Tota

l1

00

%1

7,9

50

,74

6

6,9

25

,08

7

Co

st7

18

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0$

$2

77

,00

3

Savi

ngs

$4

41

,02

6

VFD

En

ergy

Cu

rren

t En

ergy

39

%

Mo

tor

Co

eff

ice

nts

Var

iab

le F

req

ue

ncy

Dri

ve

Co

eff

icie

nts

Dis

char

ge P

ress

ure

Des

ign

Flo

w

Des

ign

Hea

d

Des

ign

Flo

w

37

Appendix C: Pump Inspection Quote

38

Appendix C: Pump Inspection Quote (continued)

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