Design of a 50 kWe Bio-oil Fueled Rankine Cycle Cogeneration

Power Plant

Angela Hsu

A thesis submitted in partial fulfillment of the requirements for the degree of

BACHELOR OF APPLIED SCIENCE

Supervisor: J. S. Wallace

Department of Mechanical and Industrial Engineering University of Toronto

March 2007

ABSTRACT

The objectives of this thesis are to design a 50 kWe bio-oil fueled Rankine cycle cogeneration power plant and to determine the feasibility of constructing and operating such a plant. A simulation model was constructed to incorporate the properties and characteristics of each component and the operational limits of the entire system. The results of the simulation indicate a maximum electrical efficiency of 3.45 percent and a maximum cogeneration efficiency of 85 percent, both occurring at 100 percent process load demand. An economic analysis was conducted to compare the cost of generating heat and electricity using the system to the current cost of purchasing energy from a utility supplier. The total annual cost of the system is approximately US$313,000. The total annual cost of purchasing the equivalent amount of energy generated by the system is US$484,600 at 100 percent process load demand and US$435,600 at 89 percent process load. The results from the technical and economical analyses indicate the system is only economically feasible if cogeneration is implemented. The system does not generate enough electricity to be economical without implementing cogeneration.

ii

ACKNOWLEDGEMENTS

I would like to take this opportunity to thank Professor James S. Wallace for his guidance

and support throughout the project. His first-hand experience and knowledge of the energy

generation sector provided clear and insightful direction for the project. I would like to thank

my parents for their love and support throughout my life. Last but not least, I would like to

thank my fiance for supporting me through this entire project.

iii

TABLE OF CONTENTS TABLE OF CONTENTS ..................................................................................................... IV LIST OF FIGURES ..............................................................................................................VI LIST OF TABLES .............................................................................................................. VII LIST OF EQUATIONS.....................................................................................................VIII CHAPTER 1: INTRODUCTION......................................................................................... 1

1.1 THESIS OVERVIEW ..................................................................................................... 1 1.2 OBJECTIVES ............................................................................................................... 1

CHAPTER 2: BACKGROUND AND THEORY ............................................................... 3 2.1 BIO-OIL...................................................................................................................... 3 2.2 THE RANKINE CYCLE................................................................................................. 6 2.3 COGENERATION OR COMBINED HEAT AND POWER (CHP)....................................... 11

CHAPTER 3: LITERATURE REVIEW........................................................................... 12 3.1 BIO-MATTER FOR ENERGY PRODUCTION ................................................................. 12 3.2 BIO-POWERED SYSTEMS .......................................................................................... 13 3.3 A NON-BIO-POWERED RANKINE ENGINE ................................................................ 17

CHAPTER 4: SYSTEM AND PARTS REQUIREMENTS ............................................ 19 4.1 OVERALL SYSTEM REQUIREMENTS.......................................................................... 19 4.2 STEAM TURBINES AND ELECTRIC GENERATORS ...................................................... 20 4.3 BOILER SPECIFICATIONS .......................................................................................... 24 4.4 PUMPS...................................................................................................................... 26 4.5 CONDENSATE TRAPS................................................................................................ 29 4.6 PRESSURE REDUCING VALVE................................................................................... 30 4.7 HEAT EXCHANGER................................................................................................... 31 4.8 STEAM SEPARATOR AND WATER STORAGE TANKS ................................................. 32

CHAPTER 5: TECHNICAL ANALYSIS ......................................................................... 34 5.1 THERMODYNAMIC LIMITATION................................................................................ 34 5.2 MODEL ASSUMPTIONS ............................................................................................. 35 5.3 SYSTEM SET-UP ....................................................................................................... 35 5.4 SIMULATION ............................................................................................................ 36 5.5 SIMULATION RESULTS ............................................................................................. 40

CHAPTER 6: ECONOMIC ANALYSIS........................................................................... 43 6.1 COST SUMMARY ...................................................................................................... 43 6.2 ELECTRICITY COST PER KILOWATT-HOUR............................................................... 44 6.3 HEATING COST PER KILOWATT-HOUR..................................................................... 45 6.4 COST FOR BOTH ELECTRICITY AND HEAT ................................................................ 46 6.5 ECONOMIC SENSITIVITY ANALYSIS ......................................................................... 46

iv

CHAPTER 7: DISCUSSION AND RECOMMENDATIONS......................................... 49

7.1 DISCUSSION ............................................................................................................. 49 7.2 RECOMMENDATIONS................................................................................................ 51

CHAPTER 8: CONCLUSION............................................................................................ 52 REFERENCES...................................................................................................................... 53 APPENDIX A: FULL SCHEMATIC OF A 50 KWE BIO-OIL FUELED POWER PLANT................................................................................................................................... 56 APPENDIX B: TURBINE EFFICIENCY CALCULATION.......................................... 57 APPENDIX C: SIMULINK MODEL AND FORMULAE.............................................. 58 APPENDIX D: SIMULATION RESULTS ....................................................................... 64 APPENDIX E: ECONOMIC ANALYSIS SUPPLEMENTAL DATA........................... 67 APPENDIX F: EQUIPMENT COST SOURCES............................................................. 71

v

LIST OF FIGURES Figure 1: Simple Rankine Cycle .............................................................................................. 6 Figure 2: Pre-heating of Feedwater Steam (Heat Exchanger) ................................................. 8 Figure 3: Regeneration Direct Heat Transfer from Turbine ................................................. 9 Figure 4: Regeneration Open Feedwater Heater................................................................. 10 Figure 5: Steam Reheat.......................................................................................................... 10 Figure 6: Bio-oil Fueled Cogeneration Power Plant Schematic (Simple) ............................. 19 Figure 7: Turbosteam BP50 Turbine Genset [16].................................................................. 23 Figure 8: Clayton E-154 Steam Generator [18]..................................................................... 25 Figure 9: Clayton Feedwater Pump [18]................................................................................ 28 Figure 10: Federal Pump Type VRC Condensate Return Unit [21]...................................... 28 Figure 11: Spirax Sarco FT14 Ball Float Steam Trap [22].................................................... 29 Figure 12: How a Spirax Sarco Ball Float Steam Trap Works [22] ...................................... 30 Figure 13: Spirax Sarco Pilot Operated Self-Actuated Pressure Reducing Valve [24]......... 31 Figure 14: Shell and Tube Heat Exchanger ........................................................................... 31 Figure 15: Armstrong Heat Exchanger [25] .......................................................................... 32 Figure 16: Steam Separator.................................................................................................... 33 Figure 17: Feedwater Tank Inlet Enthalpy Results................................................................ 41 Figure 18: Electrical Efficiency Results ................................................................................ 41 Figure 19: Cogeneration Efficiency Results .......................................................................... 42 Figure 20: Pump 1 Inlet Enthalpy.......................................................................................... 50 Figure A-1: Full Schematic of a 50 kWe Bio-oil Fueled Power Plant................................... 56 Figure C-1: Simulink Model Part 1 ....................................................................................... 58 Figure C-2: Simulink Model Part 2 ....................................................................................... 59 Figure D-1: Electrical Efficiency Results, All Process Load Demand Levels ...................... 64 Figure D-2: Cogeneration Efficiency Results, All Process Load Demand Levels ................ 64 Figure D-3: Pump 1 Inlet Enthalpy Results, All Process Load Demand Levels ................... 65 Figure D-4: Feedwater Tank Inlet Enthalpy Results, All Process Load Demand Levels...... 65 Figure D-5: Fuel Rate Results, All Process Load Demand Levels........................................ 66 Figure D-6: Additional Mass Flow Rate Results, All Process Load Demand Levels ........... 66

vi

LIST OF TABLES Table 1: Comparison between Induction and Synchronous Generators [14] ........................ 22 Table 2: Turbosteam BP-50 Turbine Specifications [16] ...................................................... 23 Table 3: Clayton E-154 Steam Generator Specifications [19]............................................... 26 Table 4: Comparison between Positive Displacement and Roto-dynamic Pumps [20] ........ 27 Table 5: System Component Efficiencies.............................................................................. 34 Table 6: Mathematical Approximations of Thermodynamic Values .................................... 37 Table 7: Simulation Input Parameters.................................................................................... 38 Table 8: Simulation Output Parameters................................................................................. 39 Table 9: Electricity Cost per Kilowatt-hour at Various Bio-oil Costs................................... 47 Table 10: Annual Equivalent System Cost at Various Interest Rates.................................... 48 Table B-1: State Values to Calculate Turbine Efficiency...................................................... 57 Table E-1: Equipment, Operation and Maintenance Costs.................................................... 67 Table E-2: System Energy Output Values ............................................................................. 67 Table E-3: Electrical Cost per Kilowatt-hour ........................................................................ 68 Table E-4: Household Energy Consumption [32] ................................................................. 68 Table E-5: Cost of Purchasing Electricity from Utility Supplier [33] ................................... 69 Table E-6: Household Annual Heating [32] .......................................................................... 69 Table E-7: Residential Gas-fired Water Heater Information [35] ......................................... 69 Table E-8: Cost of Purchasing Natural Gas for Heating from Utility Supplier [36] ............. 70

vii

LIST OF EQUATIONS Equation 1: Rankine Cycle Efficiency..................................................................................... 8 Equation 2: Cogeneration Power Plant System Efficiency.................................................... 11 Equation 3: Turbine Efficiency.............................................................................................. 23 Equation 4: Carnot Efficiency ............................................................................................... 34 Equation 5: Cost per Kilowatt-hour Formula ........................................................................ 44 Equation 6: Annualized Equivalent Cost Formula [31]......................................................... 45 Equation B-1: Turbine Exhaust Steam Quality (Isentropic).................................................. 57 Equation B-2: Turbine Exhaust Steam Enthalpy (Isentropic) ............................................... 57 Equation B-3: Turbine Efficiency.......................................................................................... 57 Equation C-1: Turbine Outlet Formulae ................................................................................ 60 Equation C-2: Steam Separator Formulae ............................................................................. 60 Equation C-3: Mass Flow Rate Formulae.............................................................................. 60 Equation C-4: Condensate Tank Formulae............................................................................ 61 Equation C-5: Pump 1 Formulae ........................................................................................... 61 Equation C-6: Feedwater Heater Formulae ........................................................................... 61 Equation C-7: Feedwater Tank Heat Loss Formulae............................................................. 62 Equation C-8: Feedwater Tank Formulae.............................................................................. 62 Equation C-9: Pump 2 Formulae ........................................................................................... 62 Equation C-10: Power Formulae ........................................................................................... 63 Equation C-11: Heat Formulae .............................................................................................. 63 Equation C-12: Efficiency Formulae ..................................................................................... 63

viii

CHAPTER 1: INTRODUCTION

1.1 Thesis Overview

This thesis aims to analyze the efficiency and economics of a bio-oil fueled Rankine cycle

cogeneration power plant with a gross power output of 50 kWe. The service area of the

power plant is located within the northern regions of the province of Ontario.

The power plant utilizes water as the working fluid. Water is readily available and relatively

inexpensive to acquire. The system components required are those found in standard steam

cycle-based power plants. These include a steam turbine and generator set, a steam generator

and pumps. This thesis outlines the criteria used in the component selection process to

achieve the desired design.

Cost is almost always the primary consideration for any design project. As part of this thesis,

an economic analysis is performed to determine the feasibility of developing the small-scale

cogeneration power plant in Northern Ontario.

Steam turbines with power outputs less than several hundred kilowatts have relatively low

efficiencies compared to the several hundred megawatt output units used in traditional power

generation. However, the combination of a growing need for alternative energy sources, the

relatively small environmental impact of small-scale cogeneration systems and the growing

interest in distributed power generation systems requires that studies, such as the one

presented in this thesis, be conducted.

1.2 Objectives

The thesis consists of two main objectives: design a cogeneration power plant to meet the

design objectives and conduct a technical and economic analysis of the power plant to

determine the feasibility of constructing and operating the power plant.

1

The design objectives include the following. The power plant must generate 50 kWe, utilize

water/steam as the working fluid, the chosen components must be commercially available

and non-customized, and the steam generator must be capable of burning bio-oil.

As part of the technical analysis Simulink, a sub-program of Matlab, is used to simulate the

plant performance. Current energy rates are used for the economic analysis.

2

CHAPTER 2: BACKGROUND AND THEORY This chapter provides theory and background information regarding bio-oil, the Rankine

cycle, and cogeneration.

2.1 Bio-oil

Bio-matter Sources

Bio-oil is derived from bio-matter. The two main sources of bio-matter used in the

production of bio-oil are energy crops and wastes [1]. Energy crops are plants that are

specifically grown for fuel production, and wastes include plant, animal, and human activity

wastes, such as landfill garbage [1]. This project will utilize bio-oil generated from plant and

animal waste.

Energy Crops

According to Boyle [1], the growing interest in energy crops is due to several reasons:

1. The need for alternatives to fossil fuels to reduce net CO2 emissions

2. The search for indigenous alternatives to imported oil

3. The problem of surplus agricultural land

Depending on the location and the availability of land, different energy crops can be grown

to satisfy local energy needs [1].

Boyle [1] discusses two categories of energy crops: woody plants and others. Woody plants

are grown using the short rotation forestry (SRF) method, also known as the short rotation

coppice (SRC) method [1]. The SRF/SRC method is as follows [1]. Fast-growing trees are

planted 10,000 to 15,000 per hectare and are cut down close to the ground after a year of

growth. The trees re-grow and continue to grow for 2 to 4 years before they are cut again.

This cycle can be repeated for up to 30 years.

Agricultural crops such as sugar cane, maize and miscanthus (a grassy plant) are widely

grown for use as bio-fuel [1]. The advantages of agricultural crops include high yields, the

3

use of conventional farming techniques, and flexible land use as a result of the annual cycle

of the crop [1].

The specific types of energy crops grown vary widely and are dependent on the availability

of land, sunlight exposure, climate, and soil conditions.

Wastes

Boyle [1] lists four categories of waste suitable for use as bio-fuel.

1. Wood residues

2. Temperate crop wastes

3. Tropical crop wastes

4. Animal wastes

The background information presented in the sections below was extracted from Boyle [1].

Wood Residues

Currently, the majority of wood residues from tree-trimming and plantation thinning are

usually left at the site to ensure nutrients are returned to the soil. Due to the large amounts of

space required to transport the residues it was traditionally more economical to leave the

residues at the site. With the development of new harvesting techniques, a fraction of the

residues can be transported to power plants as fuel for heat and/or power generation.

It is recognized that the removal of these residues from the site will decrease the amount of

nutrients returning to the soil. However, the long term affects of residue removal on soil

nutrient levels have not been determined and are beyond the scope of this thesis.

Temperate Crop Wastes

Each year more than one billion tons of wheat and corn residues are generated. In the past,

the excess crops were burned in the field. This practice was later banned due to high levels

of pollution. Now the residues are used to generate bio-gas for the local area.

4

Straw is another plentiful crop waste. However, straw is considered a relatively expensive

fuel due to its low mass density. Transportation and storage is expensive since a lot of space

is required. A solution to this problem is the production of high-density (1 ton per cubic

meter) pelletted straw. The pelletted straw requires less space to transport and store.

Tropical Crop Wastes

The residues from sugar and rice, the two main tropical crops, are already being used as fuels

around the world. The fibrous residue of sugar cane, bagasse, is used in sugar factories to

generate steam and electricity. Even though transportation of bagasse is costly, the sale of

the generated electricity often produces enough profit to cover the costs. The bagasse could

also be used to produce ethanol, which further increases its appeal as a fuel source.

Animal Wastes

Animal manure accounts for 10 percent of the methane emissions in the United States. This

methane can be harnessed for use as bio-gas through anaerobic digestion. Anaerobic

digestion utilizes bacteria to break down the organic material to produce bio-gas. The

remaining residue from the process can be used as fertilizer.

Poultry litter, and other wastes similar in water content, can be used in combination with

wood shavings and straw in direct combustion power generation. This is suitable in rural

areas where farming is prevalent.

To summarize, the type of organic waste used to produce bio-oil will differ depending on

what is available. In temperate climates, wood residues and temperate crop wastes are

plentiful. Animal waste may also be available if the climate is suitable for animal farms. In

tropical climates, all four types of wastes may be plentiful.

Pyrolysis: The Production of Bio-oil

Bio-oil is produced through the process of pyrolysis. As explained by Boyle [1], pyrolysis is

a process where the volatile compounds of bio-matter are collected and condensed to produce

bio-oil. This is achieved by heating bio-matter with low levels of oxygen. A variation on the

5

above mentioned process is fast pyrolysis. Fast pyrolysis, as described by Blackaby [2],

exposes the bio-matter to temperatures as high as 500C with almost no oxygen to produce

bio-oil. The resulting bio-oil is typically acidic [1] and very viscous [2]. This makes bio-oil

a difficult fuel to work with. However, the energy content of bio-oil is approximately half

that of crude oil [1]. Taking into consideration the availability and energy content, bio-oil is

an attractive fuel source.

Bio-oil Summary

Bio-oil is produced using one or more types of organic waste through the process of

pyrolysis. The location of the power plant will determine which category of organic waste is

used to produce bio-oil. The cogeneration power plant for this thesis is intended for Northern

Ontario and other similar locations. This eliminates tropical crop wastes since such crops

cannot be grown in such northerly climates.

2.2 The Rankine Cycle

Steam power plants utilize the Rankine cycle. A simple Rankine cycle consists of four main

stages: work input, heat input, work output, and heat output.

Figure 1: Simple Rankine Cycle

6

Work Input

Work input into the system is accomplished using one or several water pumps. Water

returning from the process heater is usually at a saturated liquid state at a low pressure

(atmospheric or sub-atmospheric). The water entering the boiler is required to be at a much

higher pressure, thus one or several pumps are required to increase the pressure of the

saturated liquid water.

Heat Input

A boiler (or steam generator) introduces heat into the system. The boiler heats the liquid

water converting it into steam. The steam is usually heated until it reaches the superheated

steam region to maximize the efficiency of the system. If the steam does not reach the

superheated region, at the very least, it must be at the saturated vapour state. This ensures

high quality steam passes through the steam turbine. A high quality steam consists largely of

steam and a small fraction of condensate (as suspended water droplets). Steam containing a

large fraction of water droplets can damage a turbine as the mixture passes through.

Work Output

To harness the energy contained within the steam, a steam turbine is used to convert the

thermal energy into mechanical energy. Steam passing through the turbine blades expands

and rotates the turbine shaft. The turbine shaft is connected to an electrical generator which

harnesses the mechanical energy and converts it into useable electrical energy.

Heat Output

The steam exiting the turbine is a low pressure, high quality two-phase mixture. Water

pumps cannot handle high-quality two-phase mixtures, thus the steam must be condensed

back into a liquid state. This is accomplished through a process heater. The process heater

extracts the latent heat contained within the mixture, condensing the mixture to the saturated

liquid state.

Efficiency

The cycle efficiency is conventionally calculated as the net work over the net heat input.

7

boiler

pumpsturbine

in

inout

in

net

QWW

QWW

QW ===

Equation 1: Rankine Cycle Efficiency

Cycle Efficiency Improvements

There are several variations of the Rankine cycle in which the overall efficiency of the

system can be increased. These variations include pre-heating the feedwater, regeneration,

superheating, and re-heating.

Pre-heating

Pre-heating the feedwater increases the temperature of the water entering the boiler. This

reduces the amount of heat input from the boiler and increases the cycle efficiency. This can

be accomplished through regeneration or the use of a heat exchanger.

Figure 2: Pre-heating of Feedwater Steam (Heat Exchanger)

Regeneration

There are two methods of regeneration. Both methods utilize the high temperature, high

quality steam passing through the turbine. The first method involves passing the saturated

liquid from the condenser through the turbine for pre-heating. This is similar to what occurs

within a heat exchanger. The heat in the steam passing through the turbine is transferred to

8

the condensate which causes the steam to condense inside the turbine. However, this method

has two major problems. The heat transfer area in the turbine is minimal, and the turbine exit

steam is of very high moisture content. Exit steam with high moisture content indicates a

large region within the turbine where a two-phase mixture existed. As stated above, this is

undesirable.

Figure 3: Regeneration Direct Heat Transfer from Turbine

The second method involves the extraction of high temperature and high quality steam. This

extracted steam is used in either an open or closed feedwater heater to increase the

temperature of the feedwater. An open feedwater heater allows direct mixing of the high and

low temperature fluids. A closed feedwater heater is essentially a shell and tube heat

exchanger. The high temperature and high quality steam can be extracted either from the

turbine or the boiler. Extracting the steam from the turbine does not reduce the quality of the

steam at the turbine exit. This method is advantageous since the heat transfer rate between

the two streams of hot and cold fluid is much higher than in the previous method, and the

turbine exhaust steam is unaffected.

9

Figure 4: Regeneration Open Feedwater Heater

Superheating

As stated earlier, superheating the steam involves heating the steam until it reaches the

superheated region. Superheating increases the cycle efficiency by increasing the work

output.

Re-heating

Re-heating takes the exhaust steam from a high pressure turbine and re-heating the steam

prior to passing the steam through a low pressure turbine. This increases the amount of work

extracted, increasing the cycle efficiency.

Figure 5: Steam Reheat

10

2.3 Cogeneration or Combined Heat and Power (CHP)

Traditional power generation only utilizes the electrical energy produced by the turbine-

generator set. The turbine exhaust steam usually contains insufficient energy for further

electrical energy generation. The heat in the exhaust steam is typically rejected to large

bodies of water or the atmosphere as waste heat [3].

In a cogeneration power plant, the thermal energy removed at the condenser is used either to

pre-heat the working fluid within the system [3] or used as process heat to satisfy other

heating loads, such as space or water heating [4].

The cogeneration system efficiency is calculated as the sum of the net work and the useable

heat retrieved over the heat input.

( ) ( )boiler

retrievedpumpsturb

in

outnetoncogenerati Q

QWWQ

QW =+=

Equation 2: Cogeneration Power Plant System Efficiency

The increase in system efficiency is realized by reducing or eliminating the need to generate

the equivalent amount and quantity of steam using a separate boiler.

11

CHAPTER 3: LITERATURE REVIEW

This chapter reviews and summarizes research relevant to bio-powered systems. The

systems discussed include bio-mass gasifier gas turbines and bio-oil turbines. A solar-

powered/fuel-assisted Rankine engine is also presented as a point of comparison for this

project.

3.1 Bio-matter for Energy Production

Fossil fuels became the primary energy source when higher temperatures were required by

industrial processes. These higher temperatures could not be achieved by burning bio-matter.

Despite that, bio-matter still plays a significant role in energy production. According to Bain

and Overend [5], bio-power is the single largest source of non-hydro renewable energy in the

United States. The average size of existing bio-power plants is 20 MW with an average bio-

mass-to-electricity efficiency of 20 percent [5]. A power plant as small as 20 MW has

several disadvantages. The small size leads to higher capital costs per kilowatt-hour of

power produced [5]. Low efficiency ratings result in increased sensitivity to fluctuations in

the price of fuel [5]. The result is an increase in the cost of electricity to 8 to 12 cents per

kilowatt-hour [5]. In Ontario, the average cost of electricity is 6 Canadian cents per kilowatt-

hour [6], not including other charges. Bio-power is currently too expensive to compete with

traditional power generation in densely populated areas. However, in rural areas where the

cost of electricity is higher than in cities, bio-power may be more economical.

Bain and Overend [5] suggest three methods to lower the cost of utilizing bio-matter. These

methods are applicable both in rural and suburban areas.

1. Co-firing

2. Gasification

3. Direct-fired combustion

12

Co-firing

The first cost reduction method suggested by Bain and Overend [5] is to co-fire bio-mass

with coal in existing systems. The authors state this would lower the capital investment

since only slight modifications to existing systems are required.

Gasification

Gasification is the process in which the volatile compounds in the bio-matter are extracted in

either air or steam to produce a medium to low energy bio-gas [5]. Bio-gas is used as fuel

in a gasification combined cycle (GCC) which consists of a gas turbine topping cycle and a

steam turbine bottoming cycle [5]. According to the authors, the first generation of bio-

matter GCC systems could have efficiencies double that of current coal-based GCC systems.

In CHP applications, bio-matter GCC systems have the potential to achieve 80 percent

efficiency [5]. Higher cycle efficiency results in a lower cost per kilowatt-hour.

Direct-fired combustion

Direct-fired combustion involves burning bio-matter to produce heat. The resulting

combustion gases are used to produce steam in a Rankine cycle [5]. The efficiency of the

steam system can be increased by 10 percent by incorporating re-heat, regeneration and other

efficiency boosting methods [5].

The three cost reduction methods described above lower the costs of utilizing bio-energy

either through raising the efficiency of the system or by reducing the investment costs

required. The implementation of these solutions leads to promising future prospects for bio-

energy as a source of power.

3.2 Bio-powered Systems

Bio-mass Gasifier Gas Turbine Power Generation

Bio-mass gasifier gas turbine technology combines advanced Brayton cycle power

generation with bio-mass gasifiers [7]. Larson and Williams [7] states the unit capital costs

of gas-turbine systems are relatively low and insensitive to size. Larson and Williams [7]

13

also believe the advantage of gas turbines lies in the ability to achieve higher peak cycle

temperatures than steam turbines, thus achieving higher cycle efficiencies. Although

commercial bio-matter gas turbines are currently unavailable, Larson and Williams [7] have

listed three cycles that could potentially be converted into biomass-integrated gasifier/gas

turbine (BIG/GT) systems.

1. Steam-injected gas turbine

2. Intercooled steam-injected gas turbine

3. Combined cycle

According to Larson and Williams [7], both BIG/GT and double-extraction/condensing

steam turbine (CEST) cogeneration systems convert 60 percent of the energy in bio-mass

fuel into steam and electricity. However, BIG/GT systems produce three or more times the

amount of electricity of CEST systems, making them a prime candidate for power

generation. Larson and Williams [7] discuss several BIG/GT projects that were underway

during the time the article was written. Two of these projects will be briefly discussed below

according to the information extracted from Larson and Williams [7].

Combined cycle district-heating cogeneration in Varnamo, Sweden

This was the first BIG/GT Combined Cycle plant. The plant has a nominal electrical output

of 6 MW and a nominal thermal output of 9 MW. To generate the stated outputs, 20 MW of

bio-mass input is required. The plant was modeled around a modified European Gas Turbine

Typhoon gas turbine and became fully operation in October 1995.

IVOSDIG cycle in Finland

The IVOSDIG cycle utilizes wet feedstocks. The wet fuel is dried in a pressurized dryer to

produce high pressure steam. This high pressure steam is recovered and injected into the gas

turbine. The system has a nominal output of 92 MW and an efficiency of 35 percent when

utilizing 70 percent moisture content peat.

With relatively low capital costs, insensitivities to sizing, and reasonably high cycle

efficiency, BIG/GT systems are a very promising technology as illustrated by the two

14

projects discussed above. However, BIG/GT systems may be unsuitable for rural areas.

Transporting the bio-matter from rural areas to gasification plants to produce bio-gas may be

more costly than locally preparing the bio-matter for direct firing. This is due to the lower

population density of rural areas. Lower population density means less power demand. This

results in a higher cost of power on a per kilowatt basis. This is also a reason why small-

scale power generation is more cost-effective than traditional centralized power generation.

Centralized power generation requires expensive power lines to be installed to transport

power. Small distributed power plants, such as the one developed for this thesis, will

eliminate the need for expensive electrical towers.

Bio-oil Gas Turbine

Blackaby [2] discusses modifications made to a GT2500 gas turbine which will be

summarized in the following paragraphs. A Canadian-based company, Orenda Aerospace

Corporation, in collaboration with a Ukrainian manufacturer, Zorya-Mashproekt, modified

the GT2500 system at a DynaMotive power plant to utilize bio-oil. Due to the viscous nature

of bio-oil, the oil is pre-heated prior to entering the high pressure pumps.

The West Lorne bio-oil plant located 50 kilometers southwest of London, Ontario produces

70 tons of bio-oil per day. The oil is used to power the GT2500 gas turbine, which produces

2.5 MW of electricity. This is enough electricity to meet the demands of the Erie Flooring

plant. The remaining electricity is exported to the local grid. The surplus heat generated by

the turbine is used to generate 12,000 pounds of steam per hour for the Erie Floorings

industrial operation. The plant has entered into a 3 year contract with a third party for the

sale of excess bio-oil.

Blackaby [2] also mentions a new project between DynaMotive and an Ojibway community

in Northwestern Ontario. Alex Peters, President of the Whitefeather Forest Management

Corporation, is quoted by Blackaby [2] as saying: Our community runs on fuel oil

generators, so we have to fly in fuel, which is very expensive. But we have all these trees we

can get the bio oil out of.

15

Many rural communities are surrounded by an abundance of bio-matter that could be

converted into bio-oil for energy production. Utilizing bio-oil CHP systems, bio-oil may be

the most cost-effective energy production method.

Other Bio-powered Systems

BIG/GT systems are not the only bio-powered systems currently under development. Bain

and Overend [5] provides four examples of other bio-powered technology. The examples

discussed below were extracted from Bain and Overend [5].

Gasifier spark ignition engine in Littleton, Colorado

The CPC project consists of a fixed-bed downdraft gasifier. The gasifier feeds gas to a spark

ignition engine which is coupled to a generator. The system capacity ranges from 12 kW to

25 kW. Two units have been installed: one in the Philippines and the other in California

(both in 2001).

Stirling engine in Indianapolis, Indiana

The heat used to drive the Stirling engine comes from the combustion gases of a modified

pellet stove (burner). A large portion of the heat from the exhaust gases of the engine is

recovered and transferred to the incoming combustion gases, thus improving the overall

efficiency. The system is designed for 3 kW to 18 kW and is being targeted at residential

and small industrial markets.

Microturbine in Mission Viejo, California

Flex Energies has designed and fabricated a 30 kW proof of concept Flex-MicroturbineTM.

The unit is designed to utilize very low heating value gases (3.7 MJ/Nm3) with very low

emission levels. Once the proof of concept design is successfully tested, three additional

prototypes will be designed. The prototypes will be tested using landfill gas, anaerobic

digester gas, and gasification producer gas.

16

Fluid Bed Gasifier CHP plant in Orinda, California

The Carbona Corporation plans to design, fabricate and prototype a CHP system that will

utilize a fluid bed gasifier to fuel internal combustion engines. The 5 MW electric and 9 MW

hot water system will be located in Denmark for residential heating. Wood chips will be the

fuel source.

As the above projects illustrate, there are many technologies that can utilize bio-matter for

power generation. Further research and development into each technology will reveal which

is most suitable for each application (industrial, residential, etc.).

3.3 A Non-Bio-Powered Rankine Engine

As a point of comparison for the work developed in this thesis, the work conducted by Gari,

Khalifa and Radhwan [8] regarding a solar-powered/fuel-assisted Rankine engine for power

generation in Jeddah, Saudi Arabia will be discussed briefly.

The solar-powered Rankine engine steadily generates 36 kW of electrical power using steam

at 230C. The steam is produced using a boiler which is connected to a heated oil loop. The

oil loops are heated using 400m2 of single-axis tracking concentrating parabolic-trough

collectors and an auxiliary gas-fired heater. With a two-stage turbine, the systems

theoretical efficiency is 23.2 percent.

Gari, Khalifa and Radhwan [8] discuss another study where solar energy was used to

generate steam at 100C. This steam was then superheated to 600C, doubling the system

efficiency as compared to Organic Rankine cycles operating at similar solar collector

temperatures. The same study showed a seasonal thermal efficiency of 14.6 percent can be

achieved in Phoenix, Arizona utilizing a 200m2 evacuated-tube collector, a 10-stage turbine

and an air-cooled condenser.

The two examples illustrate why alternative fuel power generation is only beginning to be

considered. The efficiencies achieved are quite low and are not acceptable for centralized

17

power generation stations. However, these efficiencies may be acceptable in rural areas

where the cost of electricity is much higher than in cities.

18

CHAPTER 4: SYSTEM AND PARTS REQUIREMENTS This chapter presents the overall system requirements for this project. The requirements for

the individual components of the system are also discussed.

4.1 Overall System Requirements

The power plant for this project is a cogeneration power plant with a gross output of 50 kWe.

The system utilizes a Rankine cycle with the inclusion of a pre-heat stage. Water is the

working fluid chosen for the system. The steam is heated using the combustion gases from a

bio-oil fired steam generator. The thermal energy from the turbine exhaust steam is used by

a heating process, such as building radiators or hot water heaters, instead of being passed

through a condenser.

To achieve the desired outputs, several key pieces of equipment are required. A steam

turbine coupled with an electric generator, an oil-fired steam generator, pumps, condensate

traps, pressure reducing valves, a heat exchanger, a steam separator and water storage tanks.

A detailed schematic of the power plant is available in Appendix A.

Figure 6: Bio-oil Fueled Cogeneration Power Plant Schematic (Simple)

19

4.2 Steam Turbines and Electric Generators

Steam Turbines

The most important component of the system is the steam turbine. The turbine converts the

thermal energy in the steam into mechanical energy. As high pressure steam passes through

the turbine, the steam expands and hits the turbine blades, causing the turbine shaft to rotate.

This rotation generates mechanical energy that can be harnessed and converted into

electricity.

Steam turbines typically have power outputs in the megawatt or gigawatt range. This ensures

high efficiency and high power output required by large power generation facilities. A

kilowatt sized steam turbine is rare since the system efficiency would be comparatively low

and the amount of power produced would not satisfy the needs required by large cities. In

distributed power generation systems, multiple kilowatt sized steam turbine would provide

the power necessary for the surrounding area.

There are several types of steam turbines commonly used in power generation. These

include condensing, extraction, re-heat, and non-condensing turbines. Each turbine type will

be briefly discussed below.

Condensing Turbines

In a condensing turbine, the steam is expanded well below atmospheric pressure to extract

the maximum amount of energy from the steam [10]. The sub-atmospheric exhaust steam

does not contain enough energy for use in any other application. This type of turbine is

suitable for use in centralized power generation facilities, where maximum energy extraction

from the steam is a priority.

Extraction Turbines

Extraction turbines allow high pressure and high temperature steam to be extracted from an

intermediate area of the turbine [11]. The extracted steam can be used in a re-heat process or

used in a regeneration process to pre-heat the boiler feedwater [11] as stated in section 2.2.

20

Re-heat Turbines

Re-heat turbines are similar to extraction turbines, however the steam extracted from an

intermediate section of the turbine is re-heated close to its original temperature, and re-

introduced back into the turbine [12]. As stated in section 2.2, this re-heat process greatly

improves the efficiency.

Non-Condensing Turbines

In a non-condensing turbine, the steam exits the turbine at a pressure above atmospheric [10].

The turbine exhaust steam still contains enough energy to be used in other processes, such as

heating [10].

A backpressure turbine is a type of non-condensing turbine. The steam exits the turbine at a

specific pressure, the system back pressure. Back pressure is the pressure applied at the

exhaust region of the turbine [13].

Electric Generators

Almost as important as the steam turbine is the electric generator. An electric generator

converts the mechanical energy provided by the steam turbine into useable electrical energy.

There are two types of electric generators: induction and synchronous. A brief overview of

each generator type is presented below.

Induction Generator

An induction generator is an electric generator that receives its excitation from the utility

[14]. This means the generator cannot produce any voltage on its own, and that the

frequency and voltage of the power produced is governed by the frequency and voltage of the

power from the incoming utility line [14]. An induction generator runs at a speed that is

determined by the utility and is slightly higher than its synchronous speed [14], the speed at

which the magnetic field in the motor is rotating [15].

21

Synchronous Generator

A synchronous generator is able to produce its own power and regulate its own voltage

without being connected to the utility [14]. This means a synchronous generator can operate

in parallel with the utility or operate independently (stand alone) [14]. Synchronous

generators require a speed reduction gear [14]. When a synchronous generator is used, the

turbine is designed to spin at whatever speed provides the maximum efficiency. Thus, a

speed reduction gear is required to reduce the turbine rotation speed to a speed suitable for

the generator [14]. Table 1 provides a comparison of the characteristics of the two types of

generators.

Table 1: Comparison between Induction and Synchronous Generators [14]

Induction generators Synchronous generators Parallel or stand-alone? Can only run in parallel with

the utility. Cannot provide back-up power during utility outage.

Can run in parallel or stand-alone. Can provide back-up power.

Typical price comparison*

Under 700 kW, less expensive. Over 700 kW, less expensive.

Power factor issues Should not be used for more than about 1/3 of total plant electrical load.

Can be used to improve power factor. Can provide up to 100% of plant load or more.

Complexity The common perception is that synchronous generators are complex and difficult to operate. With modern electronics, this is no longer an issue.

* Prices compared include turbine, generator, and complete switchgear, including circuit breaker, utility grade electrical protection, synchronizing equipment as required, and turbine controls

Turbosteam BP-50 Turbine Generator Set

The turbine for this project must produce a gross electrical output of 50 kW. The

Turbosteam BP-50 Turbine Genset meets the required electrical output. The Turbosteam

BP-50 Turbine is a backpressure steam turbine that can be coupled with either a synchronous

electric generator or an induction generator. A synchronous generator is chosen to allow for

power generation independent from the provinces electrical grid. This is particularly

important when provincial power lines are damaged.

22

Figure 7: Turbosteam BP50 Turbine Genset [16]

The turbine and generator set includes a turbine, generator, pressure transmitter, generator

control panel and turbine control panel [9]. The pressure transmitter monitors the pressure at

the turbine exit and sends a signal to the pressure controller [9]. The generator controller

then opens or closes the turbine throttle to maintain the low pressure set-point [9].

The turbine efficiency is calculated using a simple relation shown in Equation 3 and the

information in Table 2. The turbine efficiency is calculated to be 32 percent. Detailed

calculations are available in Appendix B.

Table 2: Turbosteam BP-50 Turbine Specifications [16]

Inlet Pressure 160 psig (174.696 psia) Inlet Temperature Saturated (371F) Exhaust Pressure 12 psig (26.696 psia) Mass Flow Rate 3880 lbs/hr Electrical Power Output 50 kW Generator Efficiency [9] 95%

isentropic

actualturbine W

W=

Equation 3: Turbine Efficiency

23

4.3 Boiler Specifications

Another crucial component is the steam generator, also known as the boiler. The basic

function of a boiler is to transform the working fluid from the liquid phase to the gaseous

phase. To accomplish this, fuel is burned in a combustion chamber to produce high

temperature combustion gases. The heat is transferred from the combustion gases to the

working fluid as the working fluid passes through the boiler in metal tubes.

The types of combustion fuel commonly used in power generation include natural gas, light-

oils, diesel, and coal. The type of combustion fuel used dictates the specifications of the

boiler. In addition to being able to utilize the selected fuel, the boiler must also be able to

provide enough steam at the correct conditions to satisfy the various system components,

such as the turbine.

Clayton E-154 Steam Generator

The 50 kWe power plant for this project utilizes bio-oil as a fuel source. The selected boiler

must therefore be highly resilient due to the corrosive and viscous nature of bio-oil. The

Clayton E-154 Steam Generator is chosen for this project as it is able to burn number 6 oil.

Number 6 oil is similarly viscous but less corrosive than bio-oil. Therefore, if the Clayton E-

154 Steam Generator can burn number 6 oil, it should be capable of burning bio-oil, although

corrosion may be an issue in the long term.

The Clayton Steam Generator system includes a steam generator skid, a water treatment skid

and a feedwater receiver skid [17]. The steam generator skid includes the mounting, piping

and wiring for the steam generator and all the components for the water treatment skid [17].

The water treatment skid includes all the mounting, piping and wiring found on the feedwater

receiver skid, water softeners, a chemical feed system, blowdown equipment and booster

pumps, if necessary [17]. The feedwater skid includes the mounting, piping and wiring

necessary for the feedwater receiver [17].

24

The specifications for the Clayton E-154 Steam Generator are shown in Table 3. The E-154

model is capable of providing steam at a mass flow rate of 5175 pounds per hour. The

turbine only requires 3880 pounds of steam per hour, thus the steam generator will be

running at 75 percent of its design capacity.

A feature of the Clayton E-154 is its counter-flow design. The feedwater is pumped up to the

top of the boiler unit and travels down the boiler in a helical path [18]. This maximizes the

heat transfer between the combustion gases and the fluid.

Included in the package is a mechanical separator. The mechanical separator ensures the

steam leaving the boiler has a quality of 99.5 percent (or higher) [18]. Any moisture that is

separated out is returned to the steam generator via a steam trap and a feedwater tank [18].

Figure 8: Clayton E-154 Steam Generator [18]

25

Table 3: Clayton E-154 Steam Generator Specifications [19]

Boiler Horsepower 150 BHP Heat Input 5,907,353 Btu/hr Heat Output 5,175 lbs/hr Oil Consumption at Max. Steam Output (No. 2 oil) 42.0 gal/hr Oil-Fired Efficiency (at 75% firing rate) 85% Electric Motor: Pump (65-300 psi) 5 HP Dimensions (Length x Width x Height) 144 in x 88 in x 102 in

4.4 Pumps

The purpose of a pump is to add energy to a fluid. There are two classes of pumps: positive

displacement pumps and roto-dynamic pumps. A brief description of each pump type is

presented below.

Positive Displacement Pumps

A positive displacement pump utilizes volume change to move fluid. A pump cavity opens

and the fluid enters the pump [20]. The pump cavity closes and the fluid is forced out

through the pump with the aid of a piston, diaphragm, or rotor [20]. There are two main

classifications of positive displacement pumps: reciprocating and rotary. Reciprocating

pumps utilize a piston or diaphragm moving in a back and forth motion to move the fluid. A

human heart is an example of a reciprocating pump [20]. Rotary pumps utilize one or more

rotating rotors to move the fluid. A screw pump is an example of a rotary pump [20].

Roto-dynamic Pumps

A roto-dynamic pump does not utilize a change in volume to move the fluid. The pump adds

momentum to the fluid via fast-moving blades or vanes [20]. The fluid increases momentum

as it moves through the open passages inside the pump [20]. The high velocity of the fluid is

converted to a pressure increase when the fluid exits into a diffuser section of the pump [20].

Roto-dynamic pumps can be classified into three categories depending on the direction the

fluid takes when exiting the pump. The three categories of pumps are: centrifugal (or radial),

axial, and mixed (between radial and axial) [20].

26

Table 4 compares the characteristics of the two types of pumps.

Table 4: Comparison between Positive Displacement and Roto-dynamic Pumps [20]

Positive Displacement Roto-dynamic Flow Rate Up to 100 gal/min. Up to 300,000 gal/min. Fluid Viscosity

Can handle high-viscosity fluids. Can handle low-viscosity fluids.

Pressure Very high pressure rise (300 atm). Moderate pressure rise (a few atm).

Priming Mostly self-primng. Requires priming. Performance At constant shaft rotation speed,

produces nearly constant flow rate and virtually unlimited pressure rise.

Continuous constant-speed variation of performance. At zero flow, maximum pressure rise. At maximum flow rate, zero pressure rise.

Effects of Viscosity on Performance

Little effect on performance. Increasing viscosity sharply degrades pump performance.

Two pumps are required for this project: a feedwater pump and a condensate pump. Both

pumps must be capable of delivering a mass flow rate of 3880 pounds per hour to ensure

continuous re-circulation of the working fluid.

Feedwater Pump

The feedwater pump delivers water from the feedwater tank to the boiler. As stated in

section 4.3, the feedwater pump is included in the Clayton E-154 Steam Generator system.

The Clayton feedwater pump is a positive displacement diaphragm pump that is driven by an

electrical motor. The pump uses a flexible multi-layer rubber membrane and hydraulic oil to

move the working fluid. The reciprocating drive pistons do not come into contact with the

working fluid. Instead, the pistons displace the hydraulic oil which displaces the membrane.

The Clayton pump has a maximum capacity of 5175 pounds per hour. The system

requirement for the pump is a capacity of 3880 pounds per hour, thus the Clayton pump

satisfies the design requirement.

27

Figure 9: Clayton Feedwater Pump [18]

Condensate Pump

The condensate pump delivers water from the condensate tank, which holds the condensate

from the process load and various steam traps, to the feedwater tank and feedwater heater.

The condensate pump chosen for the project is the Type VRC condensate pump from Federal

Pump Corp. The unit includes a condensate receiver, a pump, and a float switch [21]. The

receiver is made of cast iron and is designed to vent to the atmosphere [21]. The condensate

pump itself is a bronze-fitted centrifugal pump [21]. The float switch is mounted and wired

on the condensate return unit and allows automatic operation of the pump [21]. The VRC-

620-2 condensate pump will have a discharge pressure of 20 psi above the inlet pressure and

a pump capacity of 9 GPM (equivalent of 4497 pounds per hour) [21].

Figure 10: Federal Pump Type VRC Condensate Return Unit [21]

28

4.5 Condensate Traps

The primary function of a condensate trap (or steam trap) is to separate and collect the

moisture present in the steam. Condensate traps are particularly important during system

start-up. During the start-up phase the piping throughout the system is cold. When the hot

steam encounters the cold pipes, the steam condenses. If the condensate is not separated out,

there is an increased potential for corrosion and damage throughout the system, particularly

at the turbine. Condensate traps also separate air and other impurities from the steam.

Condensate collected by the traps is re-directed back to the condensate tank.

Figure 11: Spirax Sarco FT14 Ball Float Steam Trap [22]

Once the system reaches steady state, the pipes are warm and the amount of condensate

throughout the system greatly reduces. Only a few of the traps are utilized during steady

state operation. The Spirax Sarco FT14 Ball Float Steam Trap was chosen for its durability.

The steam trap works by allowing air to by-pass the main valve through a thermostatic air

vent during start-up [22] (Figure 12-1). As condensate is collected the ball float is raised and

the lever mechanism opens the main valve [22] (Figure 12-2). Hot condensate flows through

the main valve, but closes the air vent [22]. When steam enters the trap, the ball float drops

and closes off the main valve, this prevents live steam from passing through [22].

29

Figure 12: How a Spirax Sarco Ball Float Steam Trap Works [22]

4.6 Pressure Reducing Valve

A pressure reducing valve (PRV) is used to reduce the pressure of a working fluid. Pressure

reducing valves are often used in steam plants to reduce the high pressure steam generated by

the boiler or from turbine exhaust to a lower pressure to be used in another application.

There are two main types of PRVs: self-acting and pneumatic control [23]. Self-acting

valves can operate without external power while pneumatic control valves require a

pneumatic signal and actuator to operate [23].

The system utilizes two PRVs. One is used to relieve the pressure in the system when the

process load is operating at less than 100 percent load. The other is used to extract steam

from the boiler into the feedwater tank to maintain the condensate within the tank at a certain

temperature. The Spirax Sarco Pilot Operated Self-Actuated PRV was chosen for this

project. The pilot operated PRV is extremely accurate, easy to adjust, and has the capability

to be turned on and off [23].

30

Figure 13: Spirax Sarco Pilot Operated Self-Actuated Pressure Reducing Valve [24]

4.7 Heat Exchanger

The function of a heat exchanger is to transfer energy in the form of heat from a high

temperature fluid stream to low temperature fluid. The heat transfer occurs mainly through

convection. A common heat exchanger type is the shell and tube heat exchanger. The low

temperature fluid enters from one end of the exchanger via tubes. The high temperature fluid

enters from the other end of the exchanger in a cavity around the tubes. Typically the two

fluids flow in opposite directions, towards then away from each other, and around baffles to

increase heat transfer. Baffles are dividers positioned perpendicular to the length of the tubes

which are used to direct the flow of the high pressure fluid.

Figure 14: Shell and Tube Heat Exchanger

Fluid temperature plays an important role in heat exchanger performance since heat transfer

is dependent on the temperature difference between the two fluids. It is often desired to have

a large temperature difference between the two fluids.

31

In addition to a large temperature difference, the available surface area also plays an

important role. In a typical shell and tube heat exchanger the low temperature fluid travels

through many small diameter tubes. This drastically increases the surface area available for

load. The Armstrong WS Heat Exchanger was chosen for this project. The

rmstrong Heat Exchanger features a removable tube bundle as a standard feature [25]. A

heat transfer.

The heat exchanger is used to pre-heat the boiler feedwater using steam that is not required

by the process

A

removable tube bundle allows for easier maintenance operations. The chosen unit is a 4-pass

model comprised of copper tubes, carbon steel baffles, and cast iron head [25].

Figure 15: Armstrong Heat Exchanger [25]

4.8 Steam Separator and Water Storage Tanks

team SeparatorS

in a two-phase mixture. This is used

hen very high quality steam is required for an application. A steam separator can be easily

a T-configuration from piping joints, as shown in Figure 16. The two-

ondensate will be directed to the condensate tank.

A steam separator separates the steam and condensate

w

constructed using

phase steam mixture enters the T-joint and hits the back of the joint. The steam, of lower

density, flows upward to the next part of the process and the condensate, of higher density,

flows downwards to a condensate trap.

The steam separator will be located downstream of the turbine exhaust. The separated steam

will proceed to the process load and the c

32

Figure 16: Steam Separator

Water storage tanks

Water storage tanks are used the condensate from various

oints throughout the system. The tanks are also used to hold a small amount of condensate

operates uninterrupted during times of brief system disruption. The

nk collects condensate from the process load and the steam traps throughout the system.

to equalize the temperature of

p

to ensure the system

tanks are also used to help system start-up by supplying condensate to the pumps and boiler.

The system contains two water storage tanks: a feedwater tank and a condensate tank. The

feedwater tank pre-heats the boiler feedwater using steam from the boiler. The condensate

ta

33

CHAPTER 5: TECHNICAL ANALYSIS

his chapter presents the thermodynamic limitation of the designed system, the assumptions

input and output parameters relevant to

e simulation model, and an explanation of the system set-up.

Rankine cycle is usually designed to maximize the temperature difference between the

sure state to maximize the system efficiency. The

aximum temperature for this system is constrained by the steam turbine to 371F. The

T

used in the construction of the simulation model, the

th

5.1 Thermodynamic Limitation

A

highest pressure state and the lowest pres

m

turbine exhaust steam is passed through heating loads, such as a radiator, thus the minimum

temperature for this system is the saturation temperature at atmospheric pressure, 212F. The

Carnot efficiency (maximum theoretical efficiency) for this system is calculated to be 19.13

percent.

( )( ) 1913.0831

672146037146021211 ==+

+==H

Lcarnot T

T

Equation 4: Carnot Efficiency

The actual system efficiency will be much lower than the Carnot efficiency. The Carnot

efficiency assumes the components within the system are ideal with 100 percent efficiency.

In reality, this is not the case. in the system have less than

t Efficiency [%]

Most of the components utilized

100 percent efficiency, as listed in Table 5.

Table 5: System Component Efficiencies

System ComponenTurbine 32

Generator [9] 95 Boiler Firing Rate 85-87*

Condensate Pump 65**

Feed mp water Pu 6 **5Process Load 1 *00**

*B at partial lo wer at higher load ** y for optim ance ** all of steam is co ensed in heating load

oiler efficiency higher Typical pump efficienc

ad and loal perform

* Assumed efficiency; nd

34

5.2 Model Assumption

Prior to the construction regarding the operation

r to allow for a simpler model. Refer to Figure 6 or Appendix

for the system schematic.

oad.

to be fully condensed to a

- e pressure loss caused by the fluid traveling from the

- is considered to be negligible as the components

- exchanger) is assumed to be perfectly insulated.

F.

The heat loss

- the process load is assumed to enter the condensate tank at 122F

he system presented in Figure 6 or Appendix A, is designed to provide the maximum

cess load demand level. To achieve maximum electrical output,

ere must always be the maximum amount of steam passing through the turbine. When the

process load is below 100 percent, the excess steam not utilized by the process load must be

s

of the simulation model, some assumptions

of the system are made in orde

A

- The steam leaving the boiler is at the saturated vapour state.

- The piping between the system components is assumed to be perfectly insulated, with the

exception of the process l

- The steam passing through the process load is assumed

saturated liquid at atmospheric pressure.

Pump 1 will compensate for th

process load to the boiler.

The pressure drop across all other piping

are assumed to be located close to each other.

The feedwater heater (heat

- The steam (shell side) in the feedwater heater is assumed to be fully condensed at the

shell side outlet.

- The inlet water to pump 2 is assumed to be a saturated liquid at 26.7 psia.

- The pressure and temperature inside the feedwater tank is assumed to remain constant at

26.7 psia and 244

- Heat loss occurs at the feedwater tank due to conduction and convection.

remains constant.

The condensate from

and atmospheric pressure due to heat and pressure loss through the return piping.

5.3 System Set-up

T

electrical output at any pro

th

35

diverted elsewhere. The excess steam is diverted through a piping section parallel to the

process load. The steam in this section passes through a pressure reduction valve (PRV).

The PRV allows the turbine to operate at the design condition by maintaining the turbine

exhaust pressure at 26.7 psia. Without the PRV the pressure at the turbine exhaust would

increase and reduce the operating efficiency of the turbine.

The diverted steam still contains useable energy. Rather than waste the energy in the steam,

the steam is used to pre-heat the feedwater. This is accomplished by using a heat exchanger

(feedwater heater). The diverted steam occupies the shell side of the heat exchanger while

e feedwater occupies the tube side. The steam is assumed to be fully condensed at the shell

nk will be at a lower temperature and pressure. To mitigate this,

eam from the boiler outlet will be diverted to the feedwater tank. A pressure reduction

sed to simulate the system performance. Various input and output parameters

re necessary to perform the analysis. The parameters are either a result of equipment

to facilitate system operations.

yed in Table 6.

th

side outlet. This condensate then travels through a steam trap (ST6) to reduce the pressure to

atmospheric where the condensate combines with condensate returning from the process load

and the steam separator.

As stated in section 5.2, the pressure and temperature inside the feedwater tank is assumed to

remain constant at 26.7 psia and 244F. However, when the process load demand is high, the

feedwater entering the ta

st

valve (PRV2) will be necessary to ensure the pressure at the boiler exhaust is at design

conditions.

5.4 Simulation

Simulink is u

a

constraints or are chosen

To allow for flexibility in parameter adjustments, such as pressure, saturated steam properties

were plotted in Microsoft Excel and a trendline was used to approximate the relationships

between various properties. The approximations are displa

36

Table 6: Mathematical Approximations of Thermodynamic Values

Saturated Liquid State, P in ]/[0952.0ln0839.0

]/[619.81 2808.0

mf

mf

RlbBtuPslbBtuPh

+==

psia [3] 26384911614f PPPPPv ++=

103109101101103 5

]/[0161.0107 35 mlbftP ++ Saturated Vapour State, P in psia [3]

]/[9769.1ln0815.0]/[5.1105 0152.0

RlbBtuPslbBtuPh

mg

mg

+==

Compressed Region, h in

d 5]

Btu/lbm anT in F [2

]/[016.0108102 3728 mcompressed lbfthhv ++= ]/[533.309886.0 mcompressed lbBtuTh =

Tables 7 and 8

complete Simu

present the parameters used in the Simulink model. Appendix C contains the

link model as well as the formulae used within the m del. o

37

Table 7: Simulation Input Parameters

Input Parameters

Category Variable Name

in Simulink Model

Description Value

(Imperial Units)

Value (SI Units)

p_turb_in [psia] 1204.5 [kPa] Turbine inlet pressure 174.7

p_turb_out Turbine outlet pressure 26.7 [psia] 184.1 [kPa] eta_turb Turbine efficiency 0.3 0.3191 191 Turbine

m Steamturbine 3[lb 1760 [kg/hr]_steam

flow rate to 880 m/hr]

p_pump1_in Pa] Pump 1 inlet pressure 14.7 [psia] 101.3 [kp_pump1_out Pump 1 outlet pressure 34.7 [psia] 239.2 [kPa] Pump 1 eta_pump1 Pump1 efficiency 0.65 0.65 p_pump2_in re ia] Pa] Pump 2 inlet pressu 26.7 [ps 184.1 [k

p_pump2_out ure ia] Pump 2 outlet press 174.7 [ps 1204.5 [kPa] Pump 2

eta_pump2 Pump2 efficiency 0.65 0.65

Atank Surface area of feedwater tank 40.10 [ft3] 1.13548 [m3]

h Feedwater tank convective heat transfer coefficient

1.76 [Btu/hft2F]

] 10 [W/m2K

k Feedwater tank thermal

th tion) ]

conductivity (wifibreglass insula

0.023 [Btu/hftF

0.04 [W/mK]

Tt nternal .53 [C] Feedwater tank itemperature 243.55 [F] 117

Tamb perature

] C] Ambient tem(tank external surface temperature)

43.4 [F 23.0 [

tin Feedwater tank wall thickness (with insulation)

1.97 [in] 0.05 [m]

Feedwater Tank

Tinf Environment temperature 68 [F] 20 [C]

eta_boil Boiler cy 0.85 0.85 efficienBoiler el [27] oil 82520 q_fu Heating value of bio- [Btu/gal] 23 [MJ/L]

Net Power eta_gen fficiency 0.95 0.95 Generator e

PRV p_prvout ing valve sure a] Pressure reduc#1 outlet pres 20 [psia] 137.9 [kP

Process ss load ]

3 Load h_Lout

Enthalpy of procereturn condensate

90.08[Btu/lbm

209.5[kJ/kg]

38

Table 8: aramSimulation Output P eters

Output Parameters Category Variable Name

ink Modein l

Description Simulh_Tin enthalpyTurbine inlet [Btu/lbm] s_Tin Turbine inlet entropy [Btu/lbmR] h_Tou y [Btu/lbm] t_act Turbine outlet actual enthalpqual_Tout_act tual quality Turbine outlet acw_turb Turbine work output [Btu/lbm] h_SSout Enthalpy of steam branch of steam separator

[Btu/lbm] h_ST5 Enthalpy of condensate bran h ofc steam separator

[Btu/lbm] h_FWHout Feedwater heater shell side outlet enthalpy

[Btu/lbm] h_pump1_in Pump 1 inlet enthalpy [Btu/lbm] v_pump1_in Pump 1 inlet specific volume [ft3/lbm] w_pump1_in Pump 1 work input [Btu/lbm] h_pump1_out_act mPump 1 outlet actual enthalpy [Btu/lb ] h_FWT_in Feedwater tank inlet enthalpy [Btu/lbm] h_pump2_out_act mPump 2 outlet actual enthalpy [Btu/lb ] h_pump2_in Pump 2 inlet enthalpy [Btu/lbm] w_pump2 Pump 2 work input [Btu/lbm] v_pump2_in Pump 2 inlet specific volume [ft3/lb ] mq_boil Boiler heat input [Btu/lbm]

Internal Output Variables

q_Load Load heat output [Btu/lbm] m_SSout Mass flow rate through steam branch of steam

separator [lbm/hr] m_ST5 Mass flow rate through condensate branch of

steam separator [lbm/hr] m_Load Mass flow rate through p or cess load [lbm/hr] m_PRV Mass flow rate through pr essure reduction valve

[lbm/hr]

Mass Flow Rates

m_add Additional mass flow rate into feedwater tank [lbm/hr]

QFWT Feedwater tank heat out [kW] Heat t Input/Outpu Q_boil Boiler input power [kW]

Ppump1 Pump 1 power [kW] Ppump1 Pump 2 power [kW] Pgen Net power output [kW]

Power Input/Output

Pturb Turbine power output [kW] Fuel Rate t Fuel_do Fuel input rate [kW]

eta_cogen Cogeneration efficiency [%] Efficiencies eta_elec Electrical efficiency [%]

39

5 tion

The results from th ion indicate ncy of 3.45 percent and

a m ogen iency of 8 0 percent process load

demand.

cess load demand varies, so do several characteristics of the system. The

ynamics, thus the minimum process load demand for this is 89 percent. This

mitation essentially disregards all data for the system below a process load demand level of

the boiler to feedwater tank. This efficiency is higher since the amount of heat

put at the boiler would be lower.

.5 Simula Results

e simulat a maximum electrical efficie

aximum c eration effic 5 percent, both occurring at 10

As the pro

feedwater tank inlet enthalpy is of particular interest. As the process load demand decreases

below 89 percent the feedwater tank inlet enthalpy becomes negative. This violates the laws

of thermod

li

89 percent.

The following figures illustrate the change in the feedwater inlet enthalpy, electrical

efficiency and cogeneration efficiency between 80 percent and 100 percent process load

demand. Figure 19 also illustrates the cogeneration efficiency if additional steam was not

diverted from

in

Appendix D presents additional figures with the entire process load demand range.

40

Feedwater Tank Inlet Enthalpy at Different Process Load Demands

-100

-75

-50

-25

0

25

50

75

100

80 85 90 95 100

Process Load Demand [%]

Feed

wat

er T

ank

Enth

alpy

[B

tu/lb

m]

FWT Inlet Enthalpy

FWT Inlet Enthalpy,h_FWT>=0

Figure 17: Feedwater Tank Inlet Enthalpy Results

Electrical Efficiency at Different Process Load Demand Levels

2.5

2.6

2.7

2.8

2.9

3

3.1

3.2

3.3

3.4

3.5

80 85 90 95 100

Process Load Demand [%]

Elec

tric

al E

ffici

ency

[%]

Electrical Efficiency

Electrical Efficiency withNegative h_FWT

Figure 18: Electrical Efficiency Results

41

Cogeneration Efficiency at Different Process Load Demand Levels

50

55

60

65

70

75

80

85

90

95

80 85 90 95 100Process Load Demand [%]

Cog

ener

atio

n Ef

ficie

ncy

[%]

CogenerationEfficiency

CogenerationEfficiency, NoAdditional Heatat FeedwaterTank

CogenerationEfficiency withNegativeh_FWT

Figure 19: Cogeneration Efficiency Results

42

CHAPTER 6: ECONOMIC ANALYSIS This chapter presents an economic analysis of the designed 50 kWe power plant. In addition

to capital costs, annual operation and maintenance costs will also be considered. To provide

a thorough analysis of the economic nature of this project, a comparison with current energy

rates will be conducted. Haliburton, Ontario is chosen as the location for comparison.

Haliburton is 3 hours northeast of Toronto. The cost at which bio-oil becomes viable will

also be analyzed.

6.1 Cost Summary

The capital cost of equipment and the annual costs of operation and maintenance are

considered for this project. The system is relatively small compared to centralized power

generation stations, thus it is assumed that the entire system will be able to fit into an existing

facility. This eliminates the costs associated with constructing a new housing facility, such

as land, construction, piping, and wiring costs.

As stated in section 5.2, the major components of the system are assumed to be located

relatively close to each other. Therefore, the cost of piping required between the components

is considered to be negligible when compared to the cost of the major components (i.e.

turbine and boiler) and are excluded from the analysis.

The installation cost for a piece of equipment can vary greatly depending on the size of the

installation and the level of expertise required. For this project, the steam generator and the

turbine are the two components that require installation expertise provided by the supplier.

The other components are comparatively simpler and cost significantly less to install.

Therefore, an installation cost of 50 percent of the total purchase price of the equipment is

estimated to be sufficient.

The cost of bio-oil is estimated to be approximately double the cost of number 2 heating oil

since bio-oil is not as widely used. The current cost of number 2 heating oil in the United

43

States is approximately 245 US cents per gallon (65 US cents per litre) [28]. Thus, the cost

of bio-oil is 490 US cents per gallon (130 US cents per litre).

To ensure the plant is operating at optimal performance, the major components must be

maintained. Annual maintenance costs for all the equipment are estimated to be 3 percent of

the total capital cost (US$5700 per year). This is based on the annual maintenance cost of

the University of Toronto Mississauga Campus microturbine system, which is roughly 3.5

percent of the capital cost.

The system is assumed to require minimal operation supervision. The majority of the

operational cost is due to the need to supply the steam generator with bio-oil. This can be

accomplished at a relatively low cost either by utilizing a very large holding tank for the fuel

which would require infrequent re-filling (i.e. every other day), or by having an existing

operator re-fill a moderately sized fuel holding tank once or twice a day. Either option

results in a relatively low labour cost estimated to be US$15000.

The lifetime of the system is estimated to be 20 years. At the end of 20 years, it is assumed

that none of the components are salvageable.

A complete listing of the relevant costs is located in Appendix E.

6.2 Electricity Cost per Kilowatt-Hour

One of the main objectives of this thesis is to determine the financial feasibility of

constructing and operating the system. To achieve this objective, the cost per kilowatt-hour

of energy must be determined. The cost per kilowatt-hour can be calculated using Equation

5.

][[$]/$kWhGenerationPowerAnnual

CostEquivalentAnnualkWh =

Equation 5: Cost per Kilowatt-hour Formula

44

The annual equivalent cost includes the annualized equivalent cost of the initial capital cost.

Assuming an inflation rate of 2.1 percent [29] and a mortgage rate of 6.35 percent [30], based

on historical data, an initial interest rate of 10 percent is selected. Based on a lifetime of 20

years, the annualized equivalent of the initial capital cost is calculated to be US$22,904.86

using Equation 6, which converts a present cost into an equivalent annual cost over a certain

time period. The total annual equivalent cost of the system is US$313,014.94.

( ) ( )

++= 111 N

N

iiiPAE

where

P = present cost

N = time period

i = interest rate

Equation 6: Annualized Equivalent Cost Formula [31]

From the simulation, the system provides a net power output of 49.3521 kW. Assuming the

system operates 24 hours a day, for 360 days a year (5 days for equipment maintenance) the

plant produces 426,402 kilowatt-hours each year. Substituting these values into Equation 5,

the resulting cost is US$0.7341 per kilowatt-hour. This is over 8 times the cost of purchasing

electricity from the electrical grid (US$0.0912 per kilowatt-hour; calculations in Appendix

E).

6.3 Heating Cost per Kilowatt-Hour

In addition to producing electricity, the system also produces heat that can be used for water

or space heating. The cost per kilowatt-hour of producing this heat is also calculated using

Equation 5. However, the amount of power generated (as heat transferred) varies depending

on the process load demand. Thus the cost per kilowatt-hour of producing this heat also

varies. For all levels of demand, the cost of producing the heat is less than the cost of

purchasing heat from a conventional supplier. The cost of purchasing from a supplier

includes the cost of purchasing natural gas as well as the cost of purchasing two gas-fired hot

45

water heaters (each assumed to have a life of 10 years). At maximum process load demand it

costs US$0.0301 per kilowatt-hour to produce the heat whereas it costs US$0.0429 per

kilowatt-hour to purchase it.

6.4 Cost for both Electricity and Heat

On a per kilowatt basis, it is more cost effective to purchase electricity from a utility service

than to produce electricity. However, it is more cost effective to produce heat through the

system than to purchase the heat from a utility service. Thus, the results of the preliminary

economic analysis seem to be contradictory. This is explained by the way the above analysis

was conducted. The system is a cogeneration system, thus producing both heat and

electricity. However, a consumer purchases heat and electricity separately and at different

rates. Thus, an analysis that separates the heat and electricity generated by the system does

not fully encompass the systems true economic nature.

To sufficiently determine the economic nature of the bio-oil fueled system, the annual cost of

operating the system is compared to the annual cost of purchasing an equivalent amount of

heat and electricity from a utility service. The annual equivalent cost of the system is

US$313,014.94, as stated in section 6.1. The annual equivalent cost of purchasing both

electricity and heat from a utility service is US$484,572.53 at 100 percent process load

demand. At 89 percent process load demand (minimum operating point), the annual

equivalent cost of purchasing energy is US$435,546.93. These numbers indicate the system

becomes much more economical when cogeneration is implemented.

6.5 Economic Sensitivity Analysis

The following analysis attempts to determine the economic sensitivity of the system to the

price of bio-oil and the assumed interest rate. Cogeneration will not be taken into account in

the bio-oil cost analysis, but will be included in the interest rate analysis.

46

Sensitivity to the Price of Bio-oil

Electricity is currently sold at 9.12 US cents per kilowatt-hour. This price includes all the

extraneous costs included on an electricity bill (i.e. customer charge, delivery charge, etc.).

Table 9 shows the cost per kilowatt-hour of utilizing only the electricity generated at various

bio-oil costs. The analysis indicates that even if the bio-oil was free, the cost of utilizing

only electricity using this system will still be greater than purchasing electricity from the

electric