Modeling and Optimization of Biomass Gasification Systems

Technical University of Denmark

Department of Mechanical Engineering

Modeling and optimization

of biomass gasification systems

“a Biomass Integrated Gasification Combined Cycle plant”

Master Thesis

May 2009

Author: Luca Carlassara

Supervisor: Masoud Rokni

External supervisor: Thomas Norman

Abstract

Modeling and optimization of biomass gasification systems by Luca Carlassara, supervisor

Masoud Rokni, external supervisor Thomas Norman (B&W Vølund), Department of

Mechanical Engineering, Technical University of Denmark, Lyngby, Denmark.

Background. Biomass gasification is an energy conversion method suitable for power

production and is a sustainable solution thanks to its carbon neutrality. In this work a Biomass

Integrated Gasification Combined Cycle plant (BIGCC) is studied. The fuel consists of wood

chips. The top and the bottom cycle are respectively a gas engine and a Rankine cycle. The

plant size is set to 5MW electrical power. The system is modeled, using the software DNA,

and optimized in order to achieve higher efficiency.

Results. The optimization is carried out changing the bottom cycle parameters and proposing

major improvements. Two optimized configurations that differ from the adopted bottom cycle

are considered. The overall efficiency (LHV) of the first configuration, which uses a simple

steam cycle, is equal to 40,3%. In the second configuration reheating is implemented and the

efficiency raises to 40,8%

Conclusions. The study expresses the advantages of this kind of plant: a small combined

plant, carbon neutral, without need for external water supply and with high electrical

efficiency, improved by the optimization.

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Table of contents

Chapter 1: Introduction .................................................................................................................................... 1

Chapter 2: Biomass energy conversion ............................................................................................................ 3

2.1 Energy from biomass .............................................................................................................................. 3

2.2 Carbon neutrality .................................................................................................................................... 3

2.3 Conversion of biomass into energy......................................................................................................... 3

2.3.1 Direct combustion ........................................................................................................................... 4

2.3.2 Gasification ..................................................................................................................................... 4

2.3.3 Liquefaction..................................................................................................................................... 4

2.3.4 Anaerobic digestion ......................................................................................................................... 5

Chapter 3: Biomass Gasification ...................................................................................................................... 7

3.1 Biomass gasification process .................................................................................................................. 7

3.1.1 Drying ............................................................................................................................................. 8

3.1.2 Pyrolysis .......................................................................................................................................... 8

3.1.3 Oxidation ......................................................................................................................................... 9

3.1.4 Reduction ........................................................................................................................................ 9

3.2 Gasifiers ............................................................................................................................................... 10

3.2.1 Fixed bed gasifier .......................................................................................................................... 10

3.2.2 Fluidized bed gasifier .................................................................................................................... 13

3.3 Heat and electricity generation from syngas ......................................................................................... 13

3.3.1 Gas engine ..................................................................................................................................... 13

3.3.2 Brayton cycle ................................................................................................................................. 13

3.3.3 Rankine cycle ................................................................................................................................ 15

3.3.4 Combined cycle ............................................................................................................................. 15

3.3.5 Fuel cell system and Stirling engine .............................................................................................. 16

Chapter 4: Plant description ........................................................................................................................... 19

4.1 General description ............................................................................................................................... 20

4.2 Fuel handling module ........................................................................................................................... 20

4.3 Gasifier module .................................................................................................................................... 21

4.4 Gas cleaning ......................................................................................................................................... 22

4.5 Gas engine module ............................................................................................................................... 22

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4.6 Tar and water treatment ........................................................................................................................ 23

4.7 Furnace ................................................................................................................................................. 23

4.8 Flue gas heat exchangers ...................................................................................................................... 24

4.9 Steam cycle .......................................................................................................................................... 24

4.10 Scrubber ............................................................................................................................................. 24

Chapter 5: Modeling ....................................................................................................................................... 25

5.1 Flow sheet ............................................................................................................................................ 25

5.2 Gasifier ................................................................................................................................................. 27

5.3 General description ............................................................................................................................... 31

Chapter 6: Basic configuration ....................................................................................................................... 33

Chapter 7: Optimization ................................................................................................................................. 37

7.1 Optimization criteria ............................................................................................................................. 37

7.2 Heat needs and sources evaluation. ...................................................................................................... 38

7.3 Engine cooling water system ................................................................................................................ 39

7.4 Configuration of the secondary heat exchangers .................................................................................. 41

7.5 Simple steam cycle ............................................................................................................................... 45

7.6 Reheating steam cycle .......................................................................................................................... 53

7.7 Condensation pressure .......................................................................................................................... 58

Chapter 8: Optimized plant results ................................................................................................................. 61

8.1 Optimized plant results ......................................................................................................................... 61

8.2 Losses analyses..................................................................................................................................... 64

Chapter 9: Other issues................................................................................................................................... 67

9.1 Switching to natural gas. ...................................................................................................................... 67

9.2 Increase of the power output adding natural gas. .................................................................................. 70

9.3 Water supply to the plant ...................................................................................................................... 72

9.4 District heating ..................................................................................................................................... 72

9.5 District cooling ..................................................................................................................................... 75

9.6 Syngas bypass ...................................................................................................................................... 77

Chapter 10: Conclusions ................................................................................................................................ 81

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Chapter 11: Further work ............................................................................................................................... 83

List of symbols ............................................................................................................................................... 85

Bibliography ................................................................................................................................................... 87

Chapter 1: Introduction

1

Chapter 1: Introduction

This work is performed as master thesis in Engineering Design and Applied Mechanics and is based on an

industrial case provided by the company Babcock and Wilcox Vølund.

The company has to deliver a project concerning the design of a Biomass Integrated Gasification Combined

Cycle power plant (BIGCC)1 to be built in Southern Italy. In order to meet the need for local biomass supply

a small size plant (5MW electrical power) is chosen. The fuel consists of wood chips obtained mainly from

forestry. The principal parts of the system are an updraft gasifier, two gas engines and a steam cycle. The

gasifier is fed with biomass and produces syngas and tar. The syngas is burnt in the engines (top cycle) and

the engine flue gas is used as source of oxygen for the combustion of tar, which takes place in the furnace.

Doing so, the flue gas thermal energy from the top cycle is recovered in the bottom cycle. The furnace flue

gas is sent to a heat recovery steam generator (HRSG) to drive a Rankine cycle (bottom cycle).

The tasks of the work are the modeling and the optimization of the plant. The study focuses on the overall

energy system and not on the modeling of the particular gasifier. The target efficiency is about 40% that, if

achieved, will fully express the potential of this technology: a small combined plant, with high electrical

efficiency, carbon neutral and without need for external water supply.

First of all a preliminary overview of the different biomass energy conversion technologies is given (chapter

2), focusing on biomass gasification (chapter 3). Afterwards the analyzed BIGCC plant is described in details

(chapter 4). The model is built (chapter 5), adopting DNA as simulation tool, and the first results from the

basic configuration are shown (chapter 6). Then optimization is performed in order to fulfill the efficiency

target (chapter 7) and the results from the optimized configurations are listed (chapter 8). Some other issues

as district heating, district cooling, natural gas usage and syngas bypass are discussed (chapter 9). Finally

conclusions (chapter 10) and suggestions for further work (chapter 11) are given.

1 The definition of combined cycle plant is used in this work in its more general meaning as plant that employs more

than one thermodynamic cycle. The cycles have to be coupled, for example by the top cycle flue gas thermal energy.

The more appropriate term for the studied system is “Integrated Biomass Gasification Gas Engine Combined Cycle

plant”, which is definitely too long, and it is abandoned in favor of “Integrated Biomass Gasification Combined Cycle

plant” (IBGCC).

Chapter 2: Biomass energy conversion

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Some issues related to biomass energy and the principal conversion methods applied in industry for electric

power and heat production are examined.

2.1 Energy from biomass

Biomass energy is based on the capture and the storage of chemical energy by green plants. This process is

called photosynthesis and determines the reduction of atmospheric carbon dioxide. The leaves work as

collectors and the plant stores the energy in complex compounds, which are rich in carbon. About 50% of the

weight of dry wood is carbon.

Even if the process can convert about 1% of the solar energy available into chemical energy, the amount of

the terrestrial biomass is so large that the annual energy storage due to photosynthesis is about 10 times the

world annual energy consumption (Hall et al., 1993).

The most interesting source of biomass for energy generation comes from waste correlated to other

productions (mainly for human and animal alimentation). The use of this kind of resources assures cheap fuel

and does not require dedicated fields for energy production or conversion from food to energy production.

Another important resource is the forestry biomass, especially if such areas are actively managed.

Biomass is considered as a local resource, since the transport of the material from the production area to the

transformation field may be very costly. Generally it is assumed that the available biomass is within an 80

km radius (Goswami, 2008). In order to get the maximum cost efficiency, the facilities have to be built close

to the source. The possibility of using different kinds of biomass in the same plant may result in a decrease of

price and more security of supply.

2.2 Carbon neutrality

An advantage of using biomass as energy source is its carbon neutrality. This expression means that if the

amount of live biomass is regenerated, the amount of carbon dioxide released to the atmosphere during the

combustion of biomass (or of its secondary products) is equal to the amount taken and stored by the plants.

Consequently the managed usage of biomass as energy source does not increase the quantity of carbon

dioxide in the atmosphere.

2.3 Conversion of biomass into energy

There are many approaches to convert biomass into energy, the most important in industry are:

Direct combustion

Gasification

Liquefaction

Anaerobic digestion

Modeling and optimization of biomass gasification systems

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2.3.1 Direct combustion

The direct combustion of biomass in order to get energy for cooking and for heating spaces is a very ancient

technology. Nevertheless the combustion of biomass in an unvented and indoor environment is responsible

for the production of toxic or hazardous gases as carbon monoxide, nitrogen oxides, hydrocarbons, organic

compounds, aldehydes, aromatics and ketones. The emission of these unwanted gases increases with the

moisture content. When complete combustion occurs, the efficiency is improved and the unwanted gas

emissions are decreased. This is the case of direct combustion in a well vented area that takes place in the

new domestic stoves and boilers where biomass substitutes fossil fuels.

On large scale, for example, biomass is reduced into fine pieces and burns in a combustion chamber, which

is connected to a gas turbine, but separated by a filter. This system is called close coupled turbine. Generally

in this kind of power plant only one third of the inlet energy is converted into electrical energy, the

remaining two thirds develop heat. It results in quite low electrical efficiency. If the produced heat can be

used for industrial manufacture, space heating, district heating and other applications, the overall efficiency

may be increased.

Another possibility is using external combustion both for a Brayton or a Rankine cycle. In this configuration

the fuel is combusted outside the cycle and a heat exchanger provides the heat for the fluid in the cycle.

2.3.2 Gasification

The process of gasification is explained in details in chapter 3. Basically it is the conversion of biomass into

producer gas and ash. The process is performed at high temperature in a reactor called gasifier. The

gasification agent is usually oxygen, or air, and water. The producer gas consists mainly of components with

a significant heating value (carbon monoxide, methane, hydrogen and tar), nitrogen, carbon dioxide and

water. Nitrogen is present as a consequence of the use of air to supply oxygen. Generally the producer gas

requires a specific treatment in order to be used for power and/or heat generation in conventional plants.

2.3.3 Liquefaction

It is possible to convert biomass into liquid fuels that can be used for transportation applications, for

example. The two most important bio-fuels are ethanol and bio-diesel.

Ethanol is obtained by the fermentation of sugarcane or starch crops. The process is composed of three

phases: grinding, hydrolysis and fermentation. Acids or enzymes (around one part over 100 by weight) and

yeast addition are needed. Only the carbohydrates are converted. If other components of the biomass, such as

protein, oil and fiber, may be valuable for other production, these substances have to be separated before

hydrolyses and fermentation.

Bio-diesel is obtained by extraction of seed oil from a wide variety of plant species (for example soya bean,

sunflower, cottonseed, corn and groundnut). The process starts with the crushing of the seeds to release the

oil. Mechanical pressing is used when the oil content in the seeds exceed 20%. In the case of lower content, a

solvent extraction is needed. The oil is rich in triglycerides of fatty acids, which are too viscous and too little

volatile to be used without prior processing in the normal diesel engines. Therefore they are converted into

methyl esters or ethyl esters of fatty acids, known as bio-diesel, and the secondary product glycerol.

Triglycerides may also be obtained from waste oils and animal fats and from microorganisms (yeasts, algae,

fungi).


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The producer gas that results from biomass gasification can be used to manufacture liquids for transportation

as: methanol, ethanol, alcohols and Fischer-Tropsch liquids, which are mixtures of light hydrocarbon gases,

paraffinic waxes and alcohols. Generally these processes require a defined ratio of carbon monoxide and

hydrogen and a certain purity of the inlet gas. Usually a treatment downstream the gasification process is

needed.

2.3.4 Anaerobic digestion

The anaerobic digestion process is the conversion of biomass into methane gas and humus materials, thanks

to the use of microorganisms in absence of oxygen. Usually the process is executed in a reactor. The term

digestion has to be differentiated by the term fermentation, which gives alcohol or lactic acid as product. The

produced gas, mainly methane, may be used in different kinds of plants to generate heat and/or power.

Chapter 3: Biomass Gasification

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The phases of the gasification process are explained. The most important kinds of gasifiers and the relevant

technologies to obtain electric power and heat from the producer gas are described.

3.1 Biomass gasification process

Gasification is a thermal chemical process that converts a solid fuel rich in carbon, as biomass, into a gas,

called producer gas (or syngas), and some secondary liquid and solid products. The biomass gasification

process is composed of four phases and the actual sequence depends on the gasification system applied. The

phases of gasification are:

Drying

Pyrolysis

Oxidation

Reduction

A general scheme of the gasification phases, which is not intended to be exhaustive, is shown in Figure 3.1

and is built following the wet wood in its transformation to ash and released products. The full explanation of

the occurring reactions is given further in this chapter.

Figure 3.1. Gasification phases. The wet wood is dried and releases water. The pyrolysis converts the dry wood

into char (a solid substance rich in carbon), tar and other gases. The char faces reduction and oxidation. The

actual sequence of these two processes is defined by the gasifier type. During reduction char is converted mainly

into carbon monoxide, hydrogen, methane, carbon dioxide and water. Oxidation is the combustion of char and

releases carbon monoxide, carbon dioxide and energy. The remaining solid that does not react is called ash. The

gasification product is a gas mixture with a relevant heating value called producer gas.


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3.1.1 Drying

Biomass contains usually a large amount of water. Wood chips, for example, may easily achieve moisture

values around 55% in weight.

Drying is the gasification phase that occurs at lower temperature (100-150°C), ideally purely physical. At

this temperature the water in the fuel evaporates and the steam diffuses towards the external atmosphere due

to a negative gradient of concentration. In the case of gasification, if the drying process is retarded (low

drying speed) the amount of unburnt carbon becomes larger, which is of course an unwanted effect. The

drying speed is affected by thermal conductivity of the fuel and by the fuel packing.

Drying requires energy to occur, in the form of heat. The energy consumption is due to water heating, water

evaporation, steam superheating and fuel heating up to the drying zone leaving temperature. Equation 3.1

defines the energy balance for the drying phase.

indwateroutdsteamfuelindoutdfuel ThThMOImTTcpMOImQ ____ @@1 Eq.3.1

Where:

Q [W] is the heat rate needed for drying

fuelm [kg/s] is the flow rate of wet fuel

MOI [ ] is the fuel moisture given by the ratio between water mass on wet fuel mass.

cp [J/(kgK)] specific heat of the dry fuel

hsteam@Td_out is the enthalpy of the steam calculated at the outlet temperature

hwater@Td_in is the enthalpy of the water calculated at the inlet temperature

3.1.2 Pyrolysis

Pyrolysis is a thermo-chemical process that converts the fuel, in the current case biomass, into:

char

ashes

volatiles

The reactions, which are quite complex, may be simplified by the following relation (Bauen, 2004):

CmnmCHHC mn 44 4 Eq.3.2

Char is a solid matter very rich in carbon. The volatiles are mainly gases as carbon monoxide CO, carbon

dioxide CO2, hydrogen H2, water H2O and hydrocarbons as methane CH4. Tar is also present in the volatiles.

Tar is a mixture of condensable organic molecules with a high molecular weight and has a high heating

value, but it is corrosive and sticky, causing damages to gas engines and turbines. Usually it is treated by

thermal cracking or partial oxidation. Thermal cracking occurs when, due to an external heat source, the long


9

molecules are converted into gases as H2, CO, CO2 and other hydrocarbons, at high temperature. The partial

oxidation is an under-stechiometric reaction of tar and oxygen, which results in heat and gases. Gas cleaning

is also an option to get rid of particles and tar.

Pyrolysis starts at around 120-150°C with the depolymerization of the fuel molecules. The different

components of biomass react at different temperatures. In the wood2, for example, hemicelluloses reacts at

200-300°C, cellulose at 250-400°C and lignin at 300-500°C. The global reaction is usually considered as

having an overall enthalpy of reaction very close to zero.

The main factors that drive the reaction are particles size, porosity and heating rate. Particle size and porosity

are influencers of heat and mass transfer. It is experienced that tar amount increases and char and gas

production decrease, when the heating rate increases.

3.1.3 Oxidation

In the zones that are rich in oxygen, which is under-stechiometric anyway, oxidation occurs between 700°C

and 2000°C. Part of the char is combusted. Oxidation is the main source of energy for the gasification

process, being strongly exothermic. The main reactions of oxidation follow (Bauen, 2004):

Reaction Enthalpy of reaction

COOC 221 -123,1 kJ/mol Eq.3.3

22 COOC -405,9 kJ/mol Eq.3.4

The ratio between the two reactions is governed by temperature. At high temperature the first reaction is

dominant, at low temperature the second one.

A secondary reaction is also present, completing the oxidation of carbon monoxide (Bauen, 2004).

Reaction Enthalpy of reaction

2221 COOCO -282,8 kJ/mol Eq.3.5

This reaction is very sensitive to temperature variation and it is almost negligible below 700°C.

During this phase, a portion of the tar may be partially oxidized and a portion of the gases may be oxidized.

3.1.4 Reduction

Reduction is the conversion of char into ash and gases, in a virtually oxygen-free atmosphere, thanks to

carbon dioxide, water or hydrogen. Water may be inserted in the form of steam, mixed with the gasification

agent flow.

There are six main reactions occurring (Bauen, 2004):

2 Wood is composed of cells made of microfibrils of cellulose (40-50%), and hemicellulose (15-25%) impregnated with

lignin (15-30%). Cellulose is a polysaccharide with formula (C6H10O5)n. Hemicellulose is defined as a matrix

polysaccharides. While cellulose is crystalline, hemicellulose is amorphous. Lignin is a complex organic compound.


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Reaction Denomination Enthalpy of reaction

COCOC 22 Badouard 159,7 kJ/mol Eq 3.6

22 HCOOHC Steam carbon 118,7 kJ/mol Eq 3.7

422 CHHC Hydrogasification -87,4 kJ/mol Eq 3.8

222 HCOOHCO Water gas shift -40,9 kJ/mol Eq 3.9

OHCHHCO 2423 Methanation -206,3 kJ/mol Eq 3.10

These reactions occur at temperature around 800-1000°C. Generally high temperature increases the velocity

of the endothermic3 reactions; on the other hand low temperature advantages the exothermic

4 reactions.

When the reduction is completed all the char becomes either gas or ash. Part of the tar may be gasified

during the reduction phase.

The final product of the gasification process is a mixture of gases called producer gas or syngas (CO, CO2,

H2O, H2, CH4, hydrocarbons and N2, if air is used as gasification agent), condensable tar and ash. An amount

of energy may also be present in the form of thermal energy of the syngas. Tar, in case that its amount is

large, is treated further, while ash is simply stored and eliminated.

3.2 Gasifiers

The biomass gasification process occurs in a reactor called gasifier. The main criterion for defining a gasifier

is its internal configuration. Gasifiers may be fixed bed or fluidized bed. The most common types are three:

Fixed bed gasifier:

Updraft gasifier

Downdraft gasifier

Fluidized bed gasifier

3.2.1 Fixed bed gasifier

The fixed bed gasifiers are characterized by a fixed reaction zone sustained by a grate, which eventually

rotates. Usually the fuel comes from the top of the gasifier, both in the concurrent and in the countercurrent

reactor. They are suitable for small and medium plants, since in a larger gasifier it is possible to face

problems related to inhomogeneous mass and heat transfer. The size, biomass energy input, may be around

1MW for the downdraft and 10MW for the updraft. Often air is part of the gasification agent and

consequently the heating value of the syngas is not very high due to the presence of nitrogen. The

temperature in the gasifier may vary in the range between 200°C and 1500°C from zone to zone. The main

3 Endothermic: a process or reaction that absorbs heat.

4 Exothermic: a process or reaction that releases heat.


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advantages are the high carbon conversion factor, the relative clean syngas and the possibility of using large

biomass particles (wood chips for example).

Updraft gasifier (countercurrent)

Figure 3.2 describes the position of the different zones in the updraft gasifier.

Figure 3.2. Updraft gasifier. The gasification agent is introduced from the bottom of the gasifier and biomass

from the top. The two streams proceed in opposite direction.

In the countercurrent reactor the biomass is inserted from the top, while the gasification agent, usually steam

and air, from the bottom, through the grate. The producer gas is extracted from the top.

The wet fuel encounters the drying zone, where the water leaves the biomass. The heat needed for drying is

taken from the hot gases, which are flowing from the bottom to the top. The dry wood reaches temperature

around 200-300°C before entering the pyrolysis zone, where the biomass is converted into char, gases and

condensable tar. The char goes into the reduction zone, at around 700-900°C. The carbon reacts with H20,

C02, and H2 and results in the production of CO, CH4 and H2. The remaining char goes in contact with the

incoming gasification agent, which is rich in oxygen at this point. Oxidation occurs, generating the heat

needed for the whole gasification process. Finally the ash is eliminated from the bottom of the grate. The

gases leave the top of the gasifier at a relative low temperature, in some cases lower than 100°C, due to the

fact that the last phase that they encounter is drying.


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Since the pyrolysis zone is far from the combustion zone, the pyrolysis temperature is quite low. Therefore a

relevant amount of tar is produced, which is a disadvantage because, for many applications, gas cleaning

may be required. On the other hand, since the syngas is extracted at a low temperature, the conversion factor

is high.

Downdraft gasifier (concurrent)

Figure 3.3 describes the position of the different zones in the downdraft gasifier.

Figure 3.3. Downdraft gasifier. Biomass in inserted from the top and the gasification agent from the side. The

two streams proceed in the same direction through the oxidation and reduction zone.

In the concurrent reactor the fuel is introduced from the top and the gasification agent from a side, where

oxidation occurs. The producer gas is extracted from the bottom of the gasifier and hence biomass and gas

are moving in the same direction through the oxidation and reduction zone. So the actual sequence of phases

that biomass encounters are: drying, pyrolysis, oxidation and reduction. Since the oxidation happens close to

the pyrolysis zone, the pyrolysis temperature is high, resulting in a lower tar amount compared to the updraft

gasifier, which is the biggest advantage of the downdraft technology. The section of the gasifier is gradually

reduced in the oxidation zone, in order to localize and have a better thermal cracking of the tar produced by

the pyrolysis. The producer gas leaves the reduction zone at high temperature and, to recover part of the heat,

may be guided in a duct in contact with the gasifier external wall to exchange energy with the drying and

pyrolysis zones. But still the syngas has a high temperature, which is not always easy to exploit, resulting in

a lower conversion efficiency compared to the updraft gasifier.


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Another disadvantage of the downdraft gasifier is the relative high amount of ash in the syngas, due to the

fact that oxidation is close to the outlet point.

3.2.2 Fluidized bed gasifier

The fluidized bed gasifier is a completely different concept. The flowing gasification agent, which is blown

at high velocity from the bottom, mixes biomass particles, oxidizer, hot gases and the bed material. The bed

material consists of very small particles of inert material (a siliceous sand), which avoid sinterization, and

catalysts, which decrease the tar amount and control the syngas composition. The temperature is very

homogeneous and usually lower than in the fixed bed gasifiers, being around 750-900°C. The gasification

phases are not spatially localized.

This type of gasifier generates a high tar amount, due to the low temperature, difficulties in controlling the

process and the need for creating a pressure in the reactor, usually. The main advantages are a very high heat

transfer and high reaction velocity, thanks to the high turbulence, that assures compactness, useful especially

in large scale plants. The carbon conversion is high and it is flexible to the changes in biomass moisture and

fast to turn on and off.

3.3 Heat and electricity generation from syngas

Syngas is usually used to generate power and/or heat. The main possibilities in this sense are:

Gas engine

Brayton cycle

Rankine cycle

Combined cycle

Fuel cell system and Stirling engine

3.3.1 Gas engine

In this application a gas reciprocating engine is used to convert the chemical energy of the syngas into

electrical power and eventually cooling heat. The available engines have a power output from 10kW up to

10MW and an electrical efficiency that ranges between 25 and 40%. Part of the energy results in thermal

energy of the flue gases and engine cooling heat, the rest is dissipated in losses. The syngas has to be cleaned

before the utilization, since tar and particles result in wear, deposition and coking. The syngas inlet

temperature has to be as lower as possible to inject the maximum amount of energy into the cylinders.

3.3.2 Brayton cycle

The Brayton cycle, called also gas turbine cycle and given in Figure 3.4, is composed of a compressor, a

combustion chamber and a turbine. The compressor takes air from the environment and sends the

compressed fluid to the combustion chamber where the syngas, which has to be cleaned, is burnt. The hot

gas is expanded in the gas turbine, resulting in power and thermal energy of the flue gas. The system results


14

in power output that reaches tens of megawatts and efficiency around 30%. The cleaning required is more

stringent than the one for gas engine. Erosion and corrosion are very dangerous when temperature and flow

velocity get very high.

Figure 3.4. Brayton cycle with producer gas cleaning. In order to use the producer gas in a conventional gas

turbine cycle, fuel cleaning is required to prevent blades damages due to particles and tar.

The addition of a heat exchanger, as shown in Figure 3.5, allow having the combustion chamber after the

turbine. The heat is transferred from the flue gas to the compressed air. In this way only high temperature air

flows through the turbine and advanced cleaning is not needed. Generally this system results in higher stack

temperature and lower efficiency.

Figure 3.5: Brayton cycle with external heating. It possible to burn the producer gas using the hot air that has

been expanded by the gas turbine and exchange heat with the compressed air through a heat exchanger.

Consequently only air flows in the gas turbine and advanced gas cleaning is not required.


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3.3.3 Rankine cycle

The producer gas obtained by the gasification process may be used to generate steam for a Rankine cycle,

called also steam cycle, in a boiler. Gas cleaning is usually not needed since the two fluids are separated. In a

simple cycle the high pressure and high temperature steam generated in the boiler is expanded in a steam

turbine, generating mechanical power. The stream at the turbine outlet is then condensed and pressurized by

a pump, and is sent again to the boiler. Usually a feedwater heater and/or a deaerator are present. Usually, at

small scale, Rankine cycles result in low efficiencies (15-35% for plants smaller than 50MW electricity) and

cannot take advantage of their economy of scale. Nevertheless they may be applied to combined cycles

successfully, as explained in the next paragraph.

3.3.4 Combined cycle

It is possible to combine a Brayton cycle (top cycle) and a Rankine cycle (bottom cycle). The concept, which

is shown in Figure 3.6, consists in the recovery of the hot flue gas, which is generated by the Brayton cycle,

through a Heat Recovery Steam Generator (HRSG), basically a set of heat exchangers that produces steam

for the Rankine cycle. The steam generated by the HRSG is expanded in a steam turbine, generating power.

Afterwards the steam, usually saturated, condensates and heat is released to the environment (or to the

district heating system, if present). Finally the feed-water is compressed by a pump and sent again to the

HRSG. Combining the two cycles and recovering part of the thermal energy of the flue gases result in high

efficiency between 47% and 52%.

A gas engine may also be combined with a Rankine cycle as Figure 3.7 shown. Under this condition, since

the flue gas temperature is lower than in the Brayton cycle, an additional firing helps to achieve the

temperature required by the steam superheating.

Figure 3.6. Combined plant with Brayton and Rankine cycle. The producer gas is cleaned and sent to the

combustion chamber of a gas turbine cycle (top cycle). The hot flue gas from the turbine outlet is used in a heat

recovery steam generator to provide a Rankine cycle (bottom cycle) with steam. Eventually an additional burner

may be implemented to increase the available temperature.


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Figure 3.7. Combined plant with gas engine and Rankine cycle. The producer gas is cleaned and sent to the gas

engine that takes air from the environment. Part of the energy goes in the engine cooling water stream. The hot

flue gas from the engine outlet is used in a heat recovery steam generator to provide a Rankine cycle (bottom

cycle) with steam. Eventually an additional burner may be implemented to increase the available temperature.

3.3.5 Fuel cell system and Stirling engine

Fuel cell system and Stirling engine are components that may be used in combination with biomass

gasification.

In order to use the producer gas obtained by biomass gasification in a fuel cell system, gas cleaning is needed

to avoid damages to the stack. The industrial development of fuel cell systems is still in progress. Through

this technology is possible to obtain high efficiency, but the production is limited in size at around 1 MW at

the moment.

The Stirling engine is an external combustion engine and consequently syngas cleaning is needed only to

preserve the heat exchanger. The producer gas is burnt and the flue gas transfers heat to the working fluid

through the heat exchanger. The commercial size is in the order of hundreds of kilowatts and the efficiency

of the system may achieve values in the range between 15 and 20%.

These two technologies are expected to be relevant in future, achieving higher efficiencies and larger size.

The resume of the discussed plant configurations is given in Table 3.1, showing the respective typical

efficiency and plant size.


17

Table 3.1. Efficiency (LHV) and suitable size for plants that use producer gas as fuel. The size is limited by the

available gasifiers and by the fact that biomass is a local source of energy.

Plant type Power Efficiency

LHV [%]

Size–order of

magnitude (MW)

Reference

Gas engine 25-40 0,01-10 Bauen (2004)

Rankine cycle 15-35 1-100 Bauen (2004)

Brayton cycle ̴ 30 0,1-10 Bauen (2004)

Combined cycle (Brayton+Rankine) 47-52 1-100 Bauen (2004)

Combined cycle (Gas engine+Rankine) 40-505 1-10 Bauen (2004)

Fuel cell system 35-60 0,01-1 Larminie (2003)

Stirling engine ̴ 20 0,01-0,1 Jensen (2002)

5 The efficiency of the combined cycle between a gas engine and a steam cycle is an estimate. The gas engine efficiency

is considered in the range 25-40%. The steam cycle has an efficiency of 30% and the engine flue gas usage is set to

90%.

Chapter 4: Plant description

19


The biomass integrated gasification combined cycle plant (BIGCC) that is analyzed in this work is described

by its components.

The general scheme of the studied plant is shown in Figure 4.1.

Figure 4.1. BIGCC plant. The gasifier is fed with wood chips, air and steam and generates producer gas. The gas

is cleaned and burnt into two gas engines (top cycle). The flue gas enters the furnace where tar coming from the

tar and water treatment system is combusted. The furnace flue gas provides the HRSG and the secondary heat

exchangers with heat. The generated steam is used in a Rankine cycle (bottom cycle).


20

4.1 General description

The analyzed plant is defined as Integrated Biomass Gasification Combined Cycle (IBGCC). The size of the

plant is set to around 5MW, which is suitable since biomass is a local resource, as underlined in chapter 2.

The plant is characterized by an updraft gasifier that converts wood chips into producer gas. The inlet wood

chips deliver a chemical energy flow (13MW). The producer gas, which leaves the gasifier at 75°C, is

separated in syngas (10MW) and tar (3MW). The dry syngas is burned into two gas engines, generating

power (4 MW) and cooling heat (2MW). The flue gas leaves the engines at 400°C and goes into a furnace

where tar is burnt. The hot gas, now at around 700°C, is used in a heat recovery steam generator that

produces steam for a Rankine cycle (1MW). The given power values are only indicative, based on the low

heating value (LHV). The results from the calculation are shown in chapter 6.

In order to have a detailed explanation of the plant, the description is performed component by component.

4.2 Fuel handling module

The wood chips are taken by the fuel crane from a store and released into the feeding system, driven by two

rotating screws. The material has to fulfill the requirements given in Table 4.1 and 4.2, which are defined by

Babcock and Wilcox Vølund for the gasifier located in Harboøre. The same kind of gasifier is used in the

current project.

Table 4.1 Wood chips properties.

Property Unit Amount

Density kg/m3 200-350

Moisture content % in weight 35-50

Lower heating value MJ/kg 8.4-11.6

Ash content % in weight 0-2

Ash softening temperature °C >1000


21

Table 4.2. Wood particle size distribution

Size Dimension (upper limit) Quantity

Small 3,15 mm <4%

Fine 8 mm <8%

Medium 16 mm <25%

Large/extra large/excess size 63 mm >60%

Excess length 10 100-200 mm long (D<10mm) <6%

Excess length 20 200-300 mm long <1,5%

4.3 Gasifier module

The reactor is an updraft gasifier: the fuel is inserted from the top of the gasifier and the gasification agent, a

mixture of air and steam at 150°C, is supplied through the rotary grate. A fan provides the system with air

that is humidified evaporating water, and then the mixture is superheated.

The reactor works almost at atmospheric pressure.

In the gasifier the chemical reactions occur. From the top of the reactor the producer gas is extracted and

from the bottom the residual ash is removed. The ash mass flow is very low.

The producer gas leaves the gasifier at 75°C. The relative low temperature compared with the temperature

inside the gasifier (above 1000°C) is due to the wood drying process heat demand, which is the last zone

faced by the producer gas before leaving the gasifier. An example of producer gas chemical composition,

when the fuel is wood chips with 45% moisture, is given in Table 4.3. The data is based on experiments

carried out by Babcock and Wilcox Vølund with reference to the gasifier placed in Harboøre. It is interesting

to notice that the sum differs to 1 since steam and air are added to the fuel in the gasifier. Water is added, as

said, in the form of steam and developed by the gasification process.

In order to use the producer gas in the gas engine, particles and tar have to be removed, since both of them

are dangerous for the engine.


22

Table 4.3. Producer gas composition. Wood moisture equal to 45%

Component Amount kg/kg wet fuel

CH4 0,0265

H2 0,0165

CO 0,3557

CO2 0,1400

O2 0,0055

H20 0,4978

N2 0,4494

Tar 0,1084

Particles 0,0016

4.4 Gas cleaning

The producer gas goes into a gas cooler, where is cooled down to about 45°C by a cold water stream. Part of

the water and almost all the tar condensate and are separated from the rest of the producer gas. Also the main

part of the particles is collected. This separated mixture is treated afterwards.

The producer gas goes in the electrostatic precipitator, where the remaining particles are removed. The

producer gas after cleaning and removal of water is called syngas, for simplicity.

4.5 Gas engine module

The syngas pressure is raised by a booster fan, so it is adequate for the gas engine. A splitter is used in order

to send a minor part of the syngas into the furnace. This is done, even if it decreases the plant efficiency, in

order to achieve a better combustion in the furnace. The amount of bypassed syngas has not been defined yet

and is considered negligible in the following calculations. The effect of the syngas bypass is discussed in

section 9.6.

The main part of the syngas goes into the engines, where it burns together with air (over stechiometric). The

engine produces power and cooling heat. Part of the energy is dissipated in losses. The remaining energy

leaves the component as high temperature flue gas, around 400°C. The engine cooling heat is removed by a

water stream that provides heat for some needs in the plant. The amount of cooling heat that is not used in

the system is released in the environment through a cooler.


23

4.6 Tar and water treatment

The mixture of water, tar and particles, which comes from the cooler and from the electrostatic precipitator,

is collected in the condensate tank. In the tank the heaviest part of the tar, called heavy tar, accumulates at

the bottom by gravity and it is removed. The remaining part, called tarwater, is circulated by a pump to the

tar water heater, where the water evaporates and is separated by the light tar. Light tar and heavy tar are sent

to the furnace. The heat necessary for evaporating the water is taken by a closed loop that uses pressurized

water as media from the furnace flue gas. A sketch of the tar and water treatment system is given below in

Figure 4.2.

Figure 4.2. Tar and water treatment system. The condensate, which comes from the gas cooler and from the

electrostatic precipitator, enters the condensate tank. Heavy tar is separated by gravity and the remaining part

of the stream, called tarwater is heated in the tarwater heater. The water part is evaporated. Light tar is

collected. The closed loop of pressurized water provides the tar water heater with heat, coming from the furnace

flue gas, thanks to one of the secondary heat exchangers.

4.7 Furnace

The flue gas from the engine, the light tar, the heavy tar and the steam (from the tar and water treatment)

burn inside the furnace. There is no need for air supply since the engine flue gas is still rich in oxygen.

Additional syngas from the splitter may be used in order to get a better combustion. The furnace flue gas

temperature is around 700°C. The steam from the tar and water treatment is sent to the furnace, with the side

effect of lowering the temperature, to avoid a further water treatment for removing the organic residues. The

separation between water and light tar is made in the tar and water treatment system in order to have better

light tar combustion.


24

4.8 Flue gas heat exchangers

Some heat exchangers provide the following heat transfers with heat taken from the furnace flue gas.

Steam turbine cycle (economizer evaporator superheater)

Water and air preheating for the gasification process, up to 150 °C

125° closed loop for the tarwater heater

4.9 Steam cycle

Part of the thermal energy of the flue gas from the furnace is used to generate steam for a Rankine cycle. The

cycle is assumed as a simple single pressure cycle, at this point. The saturated liquid coming out from the

condenser is pressurized by a LP pump. The feed-water is heated up to 93°C by the engine cooling water

system and enters the HP pump. Then the feed-water goes into the heat recovery steam generator (HRSG:

economizer, evaporator and super-heater), where the flue gas exchanges energy with the steam cycle. The

steam proceeds into the turbine, where it is expanded and generates mechanical power. The steam/liquid

mixture out of the turbine comes back to the condenser.

4.10 Scrubber

The flue gas, coming from the secondary heat exchangers, goes to a scrubber where it is cooled down and the

particles are removed by a filter. Part of the condensate water is used for feeding the gasifier. In this way no

external source of water is needed. The rest of the water fulfills the requirements to be discharged into

municipal system. The flue gas leaves the plant through a chimney.

Chapter 5: Modeling

25

Chapter 5: Modeling

The applied modeling method is documented, with focus on the gasifier model assumptions. DNA is selected

as simulation tool.

5.1 Flow sheet

In order to model the plant described in chapter 4, the tool DNA is selected. DNA is a general energy system

simulator for both steady-state and dynamic calculations, developed at DTU. The modeling is performed

using components and nodes, where the components are the energy system components and the nodes define

the flows (fluids, heat, and energy) at different points of the system6

For having a better understanding, a flow sheet is presented in Figure 5.1 related to the DNA file

“IBGCC_basic.dna”, which is the model for the basic configuration. The numbers refer to the nodes. The

nodes list and the DNA code (IBGCC_basic) are given in appendix.

6The explanation of the simulation tool DNA is given in a PhD thesis by Elmegaard B. (1999)


26

Figure. 5.1. Flow sheet (ref. IBGCC_basic.dna). The boxes, the lines and the numbers represent respectively the

components, the streams and the nodes.

Chapter 5: Modeling

27

The assumptions that are imposed to model the gasifier are described below. Afterwards the system flows are

explained.

5.2 Gasifier

The predefined GASIFI_3 is selected. It has three input flows: air (gas mixture), steam (steam real fluid),

fuel (solid) and two outputs: producer gas (gas mixture) and ash (solid). The component is an equilibrium

gasifier and does not take into account tar in the producer gas. Furthermore the chemical substances that are

present in the tar (CH3COOH, C6H5OH mainly) are not modeled in the DNA libraries.

Since the focus of this master thesis project is on the whole system, it is decided that the predefined gasifier

is used without any modification and light and heavy tar are treated as additional fuels and directly inserted

into the furnace. In order to do so, some assumptions have to be made.

1) The gasification process works as an equilibrium process, except that a certain amount of carbon,

hydrogen, oxygen, energy and mass is stored in the tar and does not take part in the reactions.

2) The mass flow of the tar is so small compared to the water amount that its effect in the tar-water

treatment system is negligible. Tar may be treated as a solid fuel.

3) The chemical composition of the syngas does not influence the performance of the plant. Only

syngas mass flow and heating value are relevant.

Assumption 1. In order to apply the first assumption, the concept of the no-tar-wood is introduced. The no-

tar wood is defined as the wood that participates in the gasification process. This modified wood is created,

balancing mass flow, element content, water content and energy as the difference between wood and tar

(both heavy and light tar). The modified wood is called “no-tar-wood” and is the stream that provides the

gasifier component with fuel.

Assumption 2. In the whole process tar is separated from the other flows quite early. Tar and water

condensate in the gas cooler, which is placed after the gasifier. The lack of tar in the condensate only slightly

decreases the mass flow of the cooling stream, with negligible influence on the plant power production and

efficiency.

Then heavy tar is separated by gravity and the rest of the condensate, which is called tar-water and is a

mixture of water and light tar, goes in the tar-water heater. Here water is evaporated and light tar is heated up

to 106°C. Since the energy needed to evaporate water is much higher than the energy for heating the light tar,

it is possible to neglect the presence of light tar in the tar-water heater.

Assumption 3. The chemical composition of the syngas has a very small influence on the system behavior,

when mass flow, heating value and water content are matched. In the gas engine all the syngas is burnt (or in

the burner_1 in the case of syngas bypass) and all the chemical components are fully oxidized. This results in

a flue gas that is not dependent on the actual syngas, but only on the inlet wood element composition.

The introduction of the main substances composing tar in the DNA libraries and the implementation of a

model of the gasifier that permits the matching of the producer gas chemical composition are suggested as a

further work, but not discussed in this study, since the focus is on the overall system and not on the particular

gasifier.


28

The no-tar-wood is modeled as a solid, which is defined in DNA by the element content (carbon C, hydrogen

H, oxygen O, in the current case), water content and heating value.

An excel file is implemented to perform this calculation, based on:

1. Total mass balance:

woodtarnotarheavytarlightwood mmmm *

2. Element mass balance (dry based):

woodtarnowoodtatnowoodtarnoitarheavytarheavytarheavyi

tarlighttarlighttarlightiwoodwoodwoodi

mmoixmmoix

mmoixmmoix

1,1,

1,1,

**

3. Water mass balance:

woodtarnowoodtarnotarheavytarheavytarlighttarlightwoodwood mmoimmoimmoimmoi **

4. Energy balance:

woodtarnowoodtarnotarheavytarheavytarlighttarlightwoodwood mLHVmLHVmLHVmLHV **

The values for wood, light tar, heavy tar and particles, shown in Tables 5.1, 5.2, 5.3, come from experiments

carried out by Babcock and Wilcox Vølund for the gasifier that is located in Harboøre, under three different

moisture conditions 35% 45% 55%. They are used as source of data. Heavy tar* is a mixture of heavy tar

and particles, since the particles are separated together with the heavy tar. The no-tar-wood values are

calculated by the four balances discussed previously.

Table 5.1. Fuel data for the 35% moisture case.

Mass flow

[kg/s]

xC xO xH Water % on

weight

LHV

[kJ/kg]

wet wood 1,000 0,50 0,44 0,06 35,00 11680

light tar 0,0701 0,46 0,47 0,07 0,00 15240

heavy tar* 0,0598 0,75 0,19 0,06 0,00 30360

no-tar-wood 0,8701 0,49 0,45 0,06 40,14 10110


Mass flow

[kg/s]

xC xO xH Water % on

weight

LHV

[kJ/kg]

wet wood 1,000 0,50 0,44 0,06 45,00 9370

light tar 0,0623 0,46 0,47 0,07 0,00 15980

heavy tar* 0,0475 0,75 0,19 0,06 0,00 30370

no-tar-wood 0,8902 0,49 0,45 0,06 50,55 7790

Chapter 5: Modeling

29


Mass flow

[kg/s]

xC xO xH Water % on

weight

LHV

[kJ/kg]

wet wood 1 0,50 0,44 0,06 55,00 7230

light tar 0,0552 0,46 0,47 0,07 0,00 17160

heavy tar* 0,0344 0,75 0,19 0,06 0,00 30380

no-tar-wood 0,9104 0,49 0,45 0,06 60,41 5750

The gasifier parameter called “gasification equilibrium temperature” is set in order to obtain the mass flow

and the LHV of the syngas consistent with the data provided by the company. This parameter is not a

physical temperature in any zone of the gasifier. The real process is far from equilibrium and is strongly

dependent on the actual geometry. For these reasons it has been decided to adjust the model of the gasifier

according to the available experimental data.

“Non equilibrium methane” seems not to have any effect on the syngas mass flow, heating value and

chemical composition. The value is set at 0,6.

“Water to fuel ratio” and “C conversion” are defined according to how the process is performed in relation

to the amount of steam in the oxidizer agent and to the measured ash production. The pressure is atmospheric

and pressure drop is not considered.

Table 5.4 shows the parameters used in the modeling under the three different moisture conditions. These

values result in the matching of syngas mass flow (after cleaning) and heating value. The comparison

between experimental data and model data is given in Table 5.5. Since the variations are lower than 1%, they

are considered as a good approximation of the system for the current purposes.

Table 5.4. Gasifier model parameters.

Moisture [%] Pressure

[bar]

Gasification

equilibrium

T [°C]

Pressure

ratio

Water to fuel

ratio C conversion

Non

equilibrium

methane

35 1 1727 0 0.12 0.995 0.6

45 1 1525 0 0.12 0.995 0.6

55 1 1345 0 0.11 0.995 0.6

Table 5.5. Comparison between experimental and model data.

Moisture [%] Exp syngas

mass flow

[kg/s]

Exp syngas

LHV[kJ/kg]

Model syngas

mass flow

[kg/s]

Model LHV

[kJ/kg]

Variation on

mass flow

Variation on

LHV

35 1,110 7761 1,121 7742 1,0% 0,2%

45 1,053 6580 1,056 6520 0,3% 0,9%

55 0,953 5523 0,946 5536 0,7% 0,2%


30

The conversion factor gives a measure of the amount of input energy that is converted into producer gas.

Two definitions are suggested. The first relation takes into account only the (dry and cleaned) syngas as

converted energy, while the second considers also tar and particles.

energyagentongasificatiwoodmwoodLHV

syngasmsyngasLHVCF

____

__1_

energyagentongasificatiwoodmwoodLHV

tarmtarLHVsyngasmsyngasLHVCF

____

____2_

The experimental results obtained under the three moisture conditions are given in Table 5.6

Tab 5.6. Conversion factor under the three moisture conditions

Moisture [%] CF_1[%] CF_2[%]

35 73,1 98,3

45 71,2 97,8

55 69,0 96,1

The percentage of the energy stream of syngas, light tar, heavy tar and losses related to the energy inlet, is

shown in Figure 5.2.

Chapter 5: Modeling

31

Figure 5.2. Energy streams at the gasifier module outlet in function of the wood moisture content. The energy

that enters the gasifier module is converted in producer gas chemical energy (composed of syngas, heavy tar and

light tar) and a small amount of energy is lost in the form of ash and producer gas thermal energy.

5.3 General description

As a general description, the different flows are explained.

Flue gas flow

Three fuels are present in the model: no-tar-wood, tar_1 (light tar) and tar_2 (heavy tar and particles). The

no-tar wood goes into the gasifier (gasifier) together with air and steam. The gasifier gives producer gas and

ash as output. The syngas goes into the cooler (cooler), where dry syngas and (tar)water (water in the model)

are cooled down by a water stream and separated. The dry syngas proceeds to the gas booster (booster).

Afterwards the splitter (split) can send part of the syngas to the furnace (in the calculation the bypassing

syngas amount is set to zero; the effect of the syngas bypass in discussed in chapter 9). The syngas enters the

gas engine (engine), where air is supplied. In reality two identical gas engines are used, but the model uses

only one component, for simplicity. The engine produces cooling heat and electrical power. The flue gas

from the engine flows into the mixer (mixer), where is mixed with the steam from the tarwater treatment

system. The stream encounters three burners (burner_1, burner_2, burner_3) that burn respectively syngas

from the splitter, Tar_1 and Tar_2. The high temperature gas is sent to a series of heat exchangers. In the

basic model the sequence is: HRSG (SH, EVA, ECO), air preheating to the gasifier (PRE_H_A2 and

PRE_H_A1), water preheating to the gasifier (PRE_H_W3, PRE_H_W2, PRE_H_W1) and closed loop for

the tar treatment (HE_125). The flue gas goes to the cooling tower (cooler2) where water condensates. The

water stream is split (split2) and part is sent to the gasifier.


32

Steam cycle flow

The HRSG produces steam for the Rankine cycle, composed by a steam turbine (turbine), a condenser

(cond), a low pressure pump (LP_pump), a feed water heater (FEEDW_H_ENG) and a high pressure pump

(HP_pump).

Tarwater flow

In the model the tarwater stream is replaced by a water stream, as discussed before.

The tarwater coming from the cooler, which is placed after the engine, enters the pump (tw_pump) and the

tarwater preheater (TW_PREH_ENG) and goes to the tarwater heater (tw_heater). Here a stream of

pressurized water coming from the heat exchanger HE_125 exchange energy with the tarwater to evaporate

water. The steam, which is a real fluid at this point, is converted into an ideal gas by a utility component

(con) and mixed with the flue gas from the engine (mixer).

Engine cooling water flow

A heat source (heatsource_ENG) takes heat from the engine cooling and heats up a stream of water from

88°C to 98°C. This stream is used in four different heat exchangers to preheat different flows

: feed-water heating (FEEDW_H_ENG)

tarwater preheating (TW_PREH_ENG).

air preheating (A_PREH_ENG)

water preheating (W_PREH_ENG)

The remaining heat is released in a heat sink (HEATSINK).

In the basic configuration only the feed water heating is performed.

The model is built and used to calculate the performance of the basic configuration given in chapter 6.

Chapter 6: Basic configuration

33


The basic plant configuration is discussed and the results from the DNA simulation are shown.

The producer gas that is generated in the gasifier is cooled (water is removed) and sent to the engine. The

outlet flue gas, rich in oxygen, is mixed with the steam from the tar water treatment system and sent to the

burners where light tar and heavy tar are burnt generating a high temperature flue gas used in the HRSG and

in the secondary heat exchangers.

The engine properties, given by the supplier, are listed in Table 6.1.

Table 6.1. Engine properties.

Electrical efficiency

[%]

Cooling efficiency

[%]

Losses [%]

Engine 40,0 18,8 13,4

The engine cooling heat is used only to heat up the steam cycle feed-water up to 93°C. Energy from the

engine cooling water is still available and in the basic configuration is simply released to the environment by

a heat sink.

The first basic configuration for the bottom cycle implements a simple steam cycle. The condenser and

turbine inlet properties are given in Table 6.2:

Table 6.2. Condenser and turbine properties.

T [°C] P [bar] Isentropic efficiency (%) Mechanical efficiency [%]

Condenser 45,81 0,1 - -

Turbine inlet 450 45 85 98

Some heat exchangers between the flue gas from the burners and flows in the plant are needed. The sequence

is shown in Table 6.3, starting from the heat exchanger that faces the highest flue gas temperature.


34

Table 6.3. Sequence of the heat exchangers.

Heat Recovery Steam Generator Function

SH Steam superheating

EVA Water evaporation

ECO Water economizing

Secondary HEs Function

PRE_H_A Gasification air preheating

PRE_H_W_3 Gasification water preheating (superheating)

PRE_H_W_2 Gasification water preheating (evaporation)

PRE_H_W_1 Gasification water preheating (economizing)

HE_125°C Closed loop for the tar water heater

The 45% moisture corresponds to the design point and is considered.

The minimum pinch point is set to 5K in each of the heat exchangers resulting in a stack temperature equal

to 110°C. The available heat for the HRSG range between the furnace outlet temperature, which is equal to

709°C, and 336°C, which the secondary heat exchanger inlet temperature.

The input energy, which is the sum between the input energy of no-tar-wood, heavy tar and light tar, is equal

to 13,4 MW and gives an output power around 5MW, which is the desired plant size.

The main results for the basic configuration are given in Table 6.4.

Tab 6.4. Results from the calculation for the basic configuration.

Property Value Unit

Inlet energy 13422 kW

Engine(s) power out 3945 kW

Engine cooling heat 1854 kW

Engine outlet temperature 401 °C

Furnace outlet temperature 709 °C

Flue gas mass flow 7,55 kg/s

Stack temperature 110 °C

Steam cycle mass flow 1,24 kg/s

Turbine generator power 1185 kW

Outlet steam quality 90,2 %

Condensation heat 2679 kW

Energy consumptions 52 kW

Net power 5077 kW

Overall efficiency (LHV) 37,83 %


35

This basic plant overall efficiency (LHV) results in 37,83%. Many improvements are possible. First of all,

the engine cooling heat may be used to preheat other streams in the system. A new secondary heat

exchangers configuration is needed to decrease the stack temperature and, as consequence, to increase the

energy available for the HRSG is needed. Also the steam cycle may be improved optimizing the turbine inlet

temperature and pressure or suggesting a more complex cycle. These arguments are discussed in chapter 7.

Chapter 7: Optimization

37


The optimization process starts with the definition of criteria. The engine cooling water system and the

secondary heat exchangers configuration are defined and consequently the available heat for the HRSG is

set. The bottom cycle is selected as a simple cycle and then updated to a reheating cycle. Finally the

possibility of decreasing the condensation temperature is examined.

7.1 Optimization criteria

The 45% moisture case is optimized in this chapter. This value corresponds to the design moisture, meaning

that the wood has to be close to this value for having good plant efficiency and well controlled gasification

process. If the moisture is higher (55%) the efficiency is decreased due to the higher energy consumption for

the tarwater treatment. In this case it is possible to introduce a fuel drying treatment in order to lower the

water content to 45% and increase the plant efficiency. If the moisture is lower (35%), the tar may be too

sticky introducing treatment and combustion problems. In this case water is added to the wood.

The optimization is performed with the target of achieving high efficiency. A satisfying overall efficiency

(LHV) target is set to 40%.

In order to perform the optimization some boundary conditions are imposed.

1) The gasification process is already optimized and is kept unchanged as well as the tar water treatment

process, which is considered as selected. Only the usage of heat for the tar water treatment is optimized.

2) The engine module (booster and gas engine) is already chosen and the air-syngas ratio is set in order to

achieve the highest flue gas temperature suggested by the producer (about 400°C). This temperature

gives the best utilization of the flue gas in the bottom cycle and does not influence the power production

of the top cycle.

3) The minimum temperature difference between a fluid and the flue gas in each of the heat exchangers has

to be equal or higher than 5K (pinch point higher than 5 Kelvin). This requirement is defined in order to

keep a reasonable heat exchanger size (and cost).

The gas engine and the steam turbine properties, given by the supplier, are shown in Table 7.1.

Table 7.1. Gas engine and steam turbine properties.

Electrical efficiency

[%]

Cooling efficiency

[%]

Losses

[%] Maximum flue gas

temperature [°C]

Engine 40,0 18,8 13,4 400

Isentropic efficiency [%] Mechanical efficiency

[%]

Steam turbine 85,0 98,0


38

First of all, the heat needs and sources are taken into account to maximize the available heat for the heat

recovery steam generator.

7.2 Heat needs and sources evaluation.

Some needs for heating are required by the gasification process: the gasifier has to be provided with steam

and air at 150°C (water preheating eco, eva, sh and air preheating) and the tarwater treatment uses a

pressurized hot water flow to separate water and tar (125°C loop). The other heat needs are related to the

steam cycle (feedwater preheating, economizing, evaporation, superheating).

There are two available sources. The high temperature source is the furnace flue gas and the low temperature

source is the engine cooling water.

The flows are listed in Table 7.2 and Table 7.3. The data for the steam cycle , which refers to the conditions

of the basic configuration described in chapter 6, is given as function of the unknown mass flow “m” that has

to be maximized, after having fulfilled all the other needs in the system.

Table 7.2. Streams and needs for heating

Stream Mass Cp heva Mass*cp Tin Tout Energy

kg/s kJ/(K*kg) kJ/kg kW/K °C °C kW

GASIFICATION

Water preheating eco 0,15 4,19 - 0,629 50 99,6 31

Water preheating eva 0,15 ∞ 2258 ∞ 99,6 99,6 339

Water preheating sh 0,15 2,04 - 0,306 99,6 150 15

Air preheating 0,70 1,01 - 0,707 25 150 88

125°C loop 18,22 4,24 - 77,253 105 125 1545

STEAM CYCLE

Feedwater heater m* 4,20 - 4,20*m 46 93 197*m

Economizer m 4,44 - 4,44*m 93 257,44 730*m

Evaporator m ∞ 1676 ∞ 257,44 257,44 1676*m

Super heater m 2,73 - 2,73*m 257,44 450 525*m

Tab 7.3. Sources of heat

Fluid Mass Cp heva Mass*cp Tin Tout

kg/s kJ/(K*kg) kJ/kg kW/K °C °C

Flue gas 7,51 1,25 9,388 710,44 100 (guess) 5746

Engine cooling

water 44,05 4,21 185,451 98 88 1854


39

Figure 7.1 represents the needs for heat in function of the required temperature range. The dotted vertical

lines represent the maximum temperature that the two sources, engine cooling water and furnace flue gas, are

able to achieve.

Figure 7.1. Needs for heat listed according to the temperature. The rectangles represent the needs for energy in

the respective range of temperature. The evaporator results in only a line, due to the fact that evaporation occurs

at constant temperature. The vertical dotted lines are the heat sources: the engine cooling water, which is the one

at lower temperature, and the furnace flue gas. The amount of required heat below the engine cooling water line

may be satisfied, at least partially, by this source.

7.3 Engine cooling water system

The engine cooling heat is exchanged to a water stream between 88 and 98°C. It is the lowest temperature

heat source and, when it is possible, it is used as first choice, in order to save the highest temperature heat

source, the furnace flue gas, for higher temperature users. Consequently the flows that are partially in this

temperature range (water preheating eco and air preheating) are split, as in Table 7.4. The temperature T1

and T2 are unknown and they are determined by the configuration of the engine cooling water system.

The feedwater preheating is completely performed by the engine cooling water system.


40

Table 7.4. Splitting of water preheating eco and air preheating flows.

Stream Mass Cp Mass*cp Tin Tout Energy

kg/s kJ/(K*kg) kW/K °C °C kW

Water preheating eco 0,15 4,19 0,629 50 99,6 31,20

(1) 0,15 4,19 0,629 50 T1*

(2) 0,15 4,19 0,629 T1 99,6

Air preheating 0,70 1,01 0,707 25 150 88,38

(1) 0,70 1,01 0,707 25 T2*

(2) 0,70 1,01 0,707 T2 150

(*)The temperatures T1 and T2 are determined by the engine cooling system configuration.

The tarwater has to be heat up and evaporated from 43°C to 106°C. In the basic model it is performed by a

closed loop that range between 125°C and 105°C that uses energy from the flue gas. It is possible to perform

the first phase of the tarwater heating thanks to the engine cooling (up to a temperature T3) and the second

phase using energy from the 125°C loop (in this case the mass flow needed in the 125°C loop becomes, of

course, lower). The result of this operation is shown in Table 7.5 and in Table 7.6. The temperature T3 is

unknown; it is determined by the configuration of the engine cooling water system.

Table 7.5. Splitting of tar-water treatment

Stream Tin [°C] Tout [°C] Energy [kW]

Tar water treatment, phase (1) 43 T3 1545

Tar water treatment, phase (2) T3 106 (steam)

(*)The temperatures T3 is determined by the engine cooling system configuration.

The engine cooling water system is defined in Figure 7.2. In each of the heat exchangers the minimum pinch

is set to 5K. A change in the steam cycle will affect the whole engine cooling water system, but modestly. It

is assumed that a pressure drop of 0,1bar occurs in each of the components.

The feedwater heater is placed in first position, facing the engine cooling water first. In this way a high

feedwater temperature is achieved (93°C) and, since the condition is close to saturation (pressure=1,1bar), a

low amount of oxygen is dissolved in the water, protecting the components from corrosion. A further

increase of the feedwater temperature may be dangerous because cavitation may occur in the HP-pump.

The other heat exchangers are sorted to maximize the use of the engine cooling heat. The selected sequence

is given in Table 7.6 and Figure 7.2. The values are related to the case of the simple steam cycle

450°C/45bar.


41

Table 7.6. Engine cooling water temperature and heat exchanged at different points of the system

Fluid in [°C] Fluid out [°C] Cooling in [°C] Cooling out [°C] Heat [kW]

Feedwater heater 45,83 93,00 98,00 96,59 262

Tarwater treatment (1) 43,01 91,59=T3 96,59 95,91 125

Air preheating (1) 25,00 90,91=T2 95,91 95,66 46

Water preheating eco (1) 50,01 90,66=T1 95,67 95,54 25

Heat sink/cooler - - 95,54 88,00 1396

Figure 7.2. Engine cooling water system. The engine cooling heat is removed by a water stream between 88°C

and 98°C that is driven by a pump. The hot water is sent to some heat exchangers to heat four flows: feedwater

for the steam cycle, tarwater, air for gasification and water for gasification. The heat that is not used is released

to the environment.

7.4 Configuration of the secondary heat exchangers

The remaining needs for heating have to be fulfilled by the flue gas and are listed in Table 7.7, starting from

the lowest temperature.


42

Table 7.7. Heating to be performed by the flue gas

Fluid Mass Cp heva Mass*cp Tin Tout Energy

kg/s kJ/(K*kg) kJ/kg kW/K °C °C kW

SECONDARY HEX.

Water preheating eco (2) 0,15 4,19 - 0,629 90,66 99,61 5,62

Air preheating (2) 0,70 1,01 - 0,707 90,91 150,00 41,77

Water preheating eva 0,15 ∞ 2257,5 ∞ 99,61 99,61 338,63

Water preheating sh 0,15 2,04 - 0,306 99,61 150,00 15,42

125°C loop* 16,73 4,24 - 70,935 105,00 125,00 1419

HRSG

Economizer m 4,44 - 4,44*m 93,00 257,44 730*m

Evaporator m ∞ 1676 ∞ 257,44 257,44 1676*m

Super heater m 2,73 - 2,73*m 257,44 450,00 525*m

(*)The amount of mass flow needed for the 125°C loop is lower than in Table 7.2 due to the introduction of

tarwater preheating.

In order to achieve a higher efficiency, the heat available for the steam cycle has to be maximized. This is

done by the identification of the heat exchangers configuration that assures the lowest stack temperature. Of

course, in all the following cases, the HRSG (super-heater, evaporator and economizer) faces the highest flue

gas temperature. The problem consists in finding the sequence of secondary heat exchanger that gives the

highest amount of heat for the HRSG.

The description of three different configurations for the secondary heat exchangers follows.

Configuration 1

In this configuration the first heat exchanger that faces the flue gas is the 125°C loop heat exchanger. The

complete sequence is given in Table 7.8.

Table 7.8. Configuration 1: Sequence of heat exchanger and relative temperatures.

Position Component Function Flow side Flue gas side

Tin [°C] Tout [°C] Tout [°C] Tin [°C]

1 PRE_H_A Air preheating (2) 90,91 150 309,51 314,09

2 PRE_H_W_3 Water preheating sh 99,61 150 307,83 309,51

PRE_H_W_2 Water preheating eva 99,61 99,61 270,21 307,83

PRE_H_W_1 Water preheating eco (2) 90,66 99,61 269,58 270,21

3 HE_125°C 125°C loop 105,00 125,01 110,00 269,58

The water pre heating may be performed in just one heat exchanger, since the three phases are consecutive.

The minimum number of heat exchanger is three.


43

Configuration 2

In this configuration the first heat exchanger that faces the flue gas is the water preheating heat exchanger.

The complete sequence is given in Table 7.9.

Table 7.9. Configuration 2: Sequence of heat exchangers and relative temperatures.



1 PRE_H_A Air preheating (2) 90,91 150,00 303,78 308,37

2 PRE_H_W_3 Water preheating sh 99,61 150,00 302,05 303,78

3 HE_125°C 125°C loop 105,00 125,01 143,94 302,05

4 PRE_H_W_2 Water preheating eva 99,61 99,61 104,65 143,94


In this case the water preheating has to be split in two different heat exchangers in order to fulfill the

requirement of 5K temperature difference between the two fluids. The first heat exchanger is composted by

the economizer and the evaporator for water preheating. The second, placed after the HE_125,°C is the

super-heater. The minimum number of heat exchanger in this case is four.

Configuration 3

In this configuration the air preheating heat exchanger is also split in two. The first, which warms up the air

to 98,95°C, faces the flue gas with the highest temperature. The complete sequence is given in Table 7.10.

Table 7.10. Configuration 3: Sequence of heat exchangers and relative temperatures.



1 PRE_H_A2 Air preheating (2) B 98,95 150 303,78 307,75

2 PRE_H_W_3 Water preheating sh 99,62 150 302,09 303,78

3 HE_125°C 125°C loop 105,00 125,01 143,98 302,09

4 PRE_H_W_2 Water preheating eva 99,61 99,61 104,61 143,98


5 PRE_H_A1 Air preheating (2) A 90,91 98,95 103,29 103,95

In this case five heat exchangers are needed. The additional heat exchanger may be very simple to realize

and it may be economically feasible, even if the decrease of stack temperature is modest.

Table 7.11 resumes the secondary heat exchangers configurations. Configuration 3 permits a lower stack

temperature, equal to 103,29°C and gives a larger interval of temperature available for the HRSG.

Consequently it is selected.


44

Table 7.11. Comparison of the relevant temperatures in the three configurations.

Unit C1 C2 C3

Tin_HRSG [°C] 708,69 708,69 708,69

Tout_HRSG [°C] 314,09 308,37 307,75

Tstack [°C] 110,00 103,95 103,29

Figure 7.3 describes the third secondary heat exchangers configuration (C3), which has been chosen.

Figure 7.3: Secondary heat exchangers configuration 3. This configuration gives the lower stack temperature

and is therefore selected. The flue gas goes first into the HRSG and then into the five secondary heat exchangers.


45

7.5 Simple steam cycle

After having defined the secondary heat exchangers configuration and set the interval of temperature

available for the HRSG, different pressure and temperature are imposed to the bottom cycle, which is a

simple steam cycle. A sketch of the bottom cycle is given in Figure 7.4

Figure 7.4. Simple steam cycle. The furnace flue gas is used in a HRSG. The superheated steam is expanded into

a steam turbine, which generates electrical power. The outlet stream is sent to the condenser and then to the low

pressure pump, where is pressurized up to 1.1bar. The feedwater is heated up to 93°C by the engine cooling

water and pressurized by the high pressure pump. The feedwater enters the HRSG, which is composed of

economizer, evaporator and superheater.

The heat available from the furnace flue gas has been calculated in the previous paragraph and ranges

between 708,69°C, which is the furnace flue gas temperature, and 307,75°C. The lower limit for the

temperature is set according to the need for heat of the secondary heat exchangers. The configuration of the

secondary heat exchangers number 3 is used.

The starting point is the simple steam cycle with turbine inlet temperature equal to 450°C and turbine inlet

pressure equal to 45bar. Condensation is performed at the pressure of 0,1bar that corresponds to 45,81°C (the

possibility of decreasing the condensation temperature is discussed in paragraph 7.7).

The pressure drop in the HRSG at the steam side is assumed to be 1bar. The steam turbine efficiencies are in

Table 7.1.

In order to have a clear understanding of the plant performance different efficiency are defined, based on the

low heating value (LHV). The first efficiency (Eq.7.1) is related to the overall plant. The second (Eq.7.2) and

the third (Eq.7.3) refers to the steam cycle only. The difference between the two is whether the engine

cooling heat used in the steam cycle is considered or not for the efficiency calculation.


46

kWLHVmLHVmLHVm

kWnsconsumptiopowerpowerturbinepowerengineefficiencyoverall

tarlighttarlighttarheavytarheavywoodtarnowoodtarno __*__

Eq.7.1

kWQQ

kWnconsumptiopowerpumppowerturbineefficiencycyclesteam

coolingengineHRSG

Eq.7.2

kWQ

kWnconsumptiopowerpumppowerturbineefficiencycyclesteam

HRSG

* Eq.7.3

Where:

mi, mass flow of the fuel I [kg/s]

LHVi, low heating value of the fuel I [kJ/kg]

Engine power, electrical power from the engine [kW]

Turbine power, electrical power from the steam turbine [kW]

Power consumption, power consumption due to gas booster and pumps [kW]

Pump consumption [kW]

QHRSG, heat recovered by the steam cycle from the flue gas into the HRSG [kW]

Qengine cooling, part of the engine cooling heat for warming up the water in the steam cycle [kW]

Four cases are evaluated, changing turbine inlet temperature (TiT) and turbine inlet pressure (TiP).

Case number Description Results TS diagram

1 TiP is equal to 45bar, TiT varies between 450°C and 600°C Table 7.12 Figure 7.5

2 TiP is equal to 140bar, TiT varies between 450°C and 600°C Table 7.13 Figure 7.6

3 TiT is equal to 450°C, TiP varies between 45bar and 140bar Table 7.14 Figure 7.8

4 TiT is equal to 550°C, TiP varies between 45bar and 140bar Table 7.15 Figure 7.9


47

7.4.1 Simple steam cycle configuration: case 1. Turbine inlet pressure is equal to 45bar, turbine inlet

temperature varies between 450°C and 600°C.

Table 7.12. Simple steam cycle configuration: case 1. TiP=45bar. Results

Turbine inlet temperature [°C] 450 500 550 600

Evaporation temperature [°C] 257,44 257,44 257,44 257,44

Evaporation pinch point [K] 154,15 150,25 146,66 143,31

Steam quality [.] 0,902 0,927 0,951 0,973

Steam mass flow [kg/s] 1,33 1,28 1,23 1,19

Condenser heat [kW] 2866 2833 2799 2771

Economizer heat [kW] 969 932 898 866

Evaporator heat [kW] 2226 2141 2063 1991

Superheater heat [kW] 698 821 932 1037

Feedwater heat (eng. cooling) [kW] 262 251 242 234

Turbine power gen. [kW] 1268 1290 1314 1339

Steam cycle net_power [kW] 1262 1284 1308 1333

Steam cycle efficiency (LHV) [%] 30,37 30,98 31,62 32,29

Steam cycle efficiency* (LHV) [%] 32,41 32,92 33,59 34,23

Overall power output [kW] 5161 5183 5208 5233

Overall efficiency(LHV) [%] 38,45 38,62 38,80 38,99

Figure 7.5 Simple steam cycle configuration. case 1. TiP=45bar and variable TiT. T-Q diagram.


48

7.4.1 Simple steam cycle configuration: case 2. Turbine inlet pressure is equal to 140bar, turbine inlet

temperature varies between 450°C and 600°C

Table 7.13. Simple steam cycle configuration: case 2. TiP=140bar. Results

Turbine inlet temperature [°C] 450 500 550 600

Evaporation temperature [°C] 336,67 336,67 336,67 336,67

Evaporation pinch point [K] 145,41 136,76 129,51 123,14

Steam quality [.] 0,816 0,847 0,875 0,901

Steam mass flow [kg/s] 1,40 1,33 1,27 1,22

Condenser heat [kW] 2737 2699 2664 2629

Economizer heat [kW] 1642 1559 1489 1428

Evaporator heat [kW] 1497 1421 1358 1302

Superheater heat [kW] 754 914 1046 1163

Feedwater heat (eng. cooling) [kW] 273 256 242 238

Turbine power gen. [kW] 1420 1442 1465 1487

Steam cycle net power [kW] 1400 1423 1447 1470

Steam cycle efficiency (LHV) [%] 33,60 34,29 34,99 35,58

Steam cycle efficiency* (LHV) [%] 35,95 36,54 37,16 37,75

Overall power output [kW] 5299 5322 5345 5369

Overall efficiency (LHV) [%] 39,48 39,65 39,83 40,00

Figure 7.6 Simple steam cycle configuration: case 2. TiP=140bar and variable TiT. T-Q diagram.


49

When a certain turbine inlet pressure is set (Case 1 TiP=45bar, Case 2 TiP=140bar), an increase of the

turbine inlet temperature produces a decrease of the steam mass flow generated by the HRSG. The effect on

the heat transferred in the different zones of the HRSG is that the superheater heat raises while the

economizer and the evaporator heat diminish, resulting in a smaller pinch point under this range of

conditions. The overall efficiency increases, when the turbine inlet temperature increases from 450°C to

600°C of about 0,5% for both the cases, as Figure 7.7 shows.

Figure.7.7. Case 1 and case 2. Overall efficiency (LHV) in function of the turbine inlet temperature. The two

curves differ from the turbine inlet pressure. The curve that refers to a higher inlet pressure results in a higher

overall efficiency in the entire considered range of temperature. The slope of the curves is almost constant when

the temperature varies.


50

7.4.2 Simple steam cycle configuration: case 3. Turbine inlet temperature is equal to 450°C, turbine

inlet pressure varies between 45bar and 140bar.

Table 7.14. Simple steam cycle configuration: case 3. TiT=450°C. Results

Turbine inlet pressure [bar] 45 60 80 105 140

Evaporation temperature [°C] 257,44 275,59 295,01 314,61 336,67

Evaporation pinch point [K] 154,15 149,56 145,85 143,95 145,41

Steam quality [.] 0,902 0,883 0,863 0,842** 0,816

Steam mass flow [kg/s] 1,33 1,34 1,35 1,37 1,40

Condenser heat [kW] 2866 2828 2792 2762 2737

Economizer heat [kW] 969 1097 1247 1416 1642

Evaporator heat [kW ] 2226 2103 1951 1767 1497

Superheater heat [kW] 698 694 696 711 754

Feedwater heat (eng. cooling) [kW] 262 263 264 267 272

Turbine power gen. [kW] 1268 1309 1349 1385 1420

Steam cycle net power [kW] 1262 1301 1338 1370 1400

Steam cycle efficiency (LHV) [%] 30,37 31,30 32,18 32,92 33,61

Steam cycle efficiency* (LHV) [%] 32,41 33,41 34,36 35,18 35,95

Overall power output [kW] 5161 5200 5237 5269 5299

Overall efficiency (LHV) [%] 38,45 38,74 39,02 39,26 39,48

** The steam quality at the turbine outlet has to be at least 85%. The values are too low.

Figure. 7.8 Simple steam cycle configuration: case 3. TiT=450°C and variable TiP. T-Q diagram.


51

7.4.3 Simple steam cycle configuration: case 4. Turbine inlet temperature is equal to 550°C, turbine

inlet pressure varies between 45bar and 140bar.

Table 7.15. Simple steam cycle configuration: case 4. TiT=550°C. Results

Turbine inlet pressure [bar] 45 60 80 105 140

Evaporation temperature [°C] 257,44 275,59 295,01 314,61 336,67

Evaporation pinch point [K] 146,66 140,80 135,45 131,42 129,51

Steam quality [.] 0,951 0,933 0,915 0,897 0,875

Steam mass flow [kg/s] 1,23 1,24 1,25 1,26 1,27

Condenser heat [kW] 2799 2762 2726 2694 2664

Economizer heat [kW] 932 1014 1148 1296 1489

Evaporator heat [kW] 2063 1943 1795 1616 1358

Superheater heat [kW] 898 936 951 981 1046

Feedwater heat (eng. cooling) [kW] 242 243 245 246 247

Turbine power gen. [kW] 1314 1354 1393 1428 1465

Steam cycle net power [kW] 1308 1347 1383 1415 1447

Steam cycle efficiency (LHV) [%] 31,62 32,56 33,41 34,18 34,94

Steam cycle efficiency* (LHV) [%] 33,59 34,59 35,52 36,33 37,16

Overall power output [kW] 5208 5245 5282 5314 5345

Overall efficiency (LHV) [%] 38,80 39,08 39,35 39,59 39,83

Figure 7.9 Simple steam cycle configuration. Case 4. TiT=550°C and variable TiP. T-Q diagram.


52

When a certain turbine inlet temperature is set (Case 3 TiT=450°Cbar, Case 4 TiT=550°C), an increase of

the turbine inlet pressure produces an increase of the steam mass flow generated by the HRSG. The effects

on the heat transferred in the different zones of the HRSG is that the evaporator heat diminishes while the

economizer and superheater heat raise, resulting in a smaller pinch point under this range of conditions. The

overall efficiency increases, when the turbine inlet pressure increases from 45bar to 140bar, of about 1% for

both the cases, as Figure 7.10 shows.

Figure 7.10. Case 3 and Case 4. Overall efficiency (LHV) in function of the turbine inlet pressure. The two curves

differ from the turbine inlet temperature. The case at higher turbine inlet temperature shows a higher overall

efficiency in the entire range of inlet pressure taken into account. The slope of the curves decreases when the

pressure increases.

Considering the four cases, it is clear that, the increase of the turbine inlet pressure or/and temperature in

these ranges, results in a higher overall efficiency.

Since the mass flow in the steam turbine is quite small, it is not possible to reach very high pressure and

temperature. A very high turbine inlet pressure results in too small first stage blades, which are difficult to

produce. A high turbine inlet temperature gives problems in terms of corrosion, especially if it is not possible

to cool such small blades. The industrial limit for the turbine inlet temperature for a steam turbine of this size

is assumed to be 550°C, while the limit in terms of pressure is set at 140bar. Turbines with these

characteristics are available in the market. Siemens and GE produce pre-design components in the range of

1-2MW power output with inlet pressure of 131 and 140 bar and inlet temperature of 530 and 540°C

respectively. The main properties of the selected steam cycle are given in Table 7.16.


53

Table 7.16. Main properties of the selected simple steam cycle.

Temperature

[°C]

Pressure

[bar]

Isentropic efficiency

[%]

Mechanical

efficiency [%]

Condenser 45,81 0,1 - -

Turbine inlet 550 140 85 98

This simple steam cycle configuration gives an overall efficiency, LHV based, equal to 39,83%. In order to

improve this result, reheating is introduced in the next paragraph.

7.6 Reheating steam cycle

The opportunity of increasing the efficiency through reheating is suggested by the large temperature

difference between the flue gas and the steam cycle. In order to model the reheating cycle, two turbines, high

pressure (HP_turbine) and low pressure (LP_turbine), take the place of the steam turbine and an additional

heat exchanger, super-heater (SH_2), is added as first heat exchanger that encounters the hot flue gas. The

scheme of the configuration is shown in Figure 7.11.

Figure 7.11. Reheating steam cycle configuration. Reheating is implemented through the additional superheater

and the two stage turbine. Steam is extracted at an intermediate pressure and superheated again.


54

When the turbine is split in two different stages, the isentropic efficiency definition fails in the description.

The same value of isentropic efficiency applied to the two stages results in a different overall isentropic

efficiency that also changes with the intermediate pressure.

In order to avoid this problem, the polytropic efficiency is introduced by using a different DNA component

called TURBINE_3, defined by two parameters, polytropic efficiency and number of integration steps.

Setting the polytrophic efficiency at 78,4% results in the overall isentropic efficiency equal to 85%. The

number of integration steps is 100. The polytropic efficiency effect is independent by the intermediate

pressure, as Table 7.17 shows for some values of the intermediate pressure.

Table 7.17.Comparison between one stage turbine with isentropic efficiency and two stage turbine with

polytropic efficiency, for different intermediate pressures

Polytropic

efficiency

Overall

isentropic

efficiency

Steam quality Δh [kJ/kg] Δh error [%]

One stage turbine 0,850 0,901 1244,4 -

Two stage turbine 1 bar 0,784 0,901 1244,4 0,00




The error does not influence the results of the optimization, since is very low. Using the setting above,

reheating is applied under two different temperature conditions, 450°C and 500°C. Different intermediate

pressures are tested for the two cases. The results are listed in Table 7.18 and 7.19.

Table 7.18. Effect of reheating up to 450°C in function of intermediate pressure

Intermediate pressure [bar] no RH 3,86 6 12 18 24 30 36 42 60

Steam mass flow [kg/s] 1,27 1,05 1,07 1,11 1,13 1,16 1,18 1,19 1,21 1,25

Hp-stage gen power [kW] - 748 693 592 523 469 424 385 350 263

Lp- stage gen power [kW] - 719 791 902 971 1022 1064 1099 1130 1203

Net steam cycle power [kW] 1447 1452 1469 1478 1478 1475 1471 1467 1463 1448

Engine cooling heat usage [kW] 247 204 208 215 220 226 229 231 235 243

Hp stage outlet temperature [°C] - 142,37(s) 177,58 241,44 282,98 314,48 340,13 361,92 380,93 427,11

Lp stage outlet temperature [°C] 45,81(s) 96,40 66,16 45,81(s) 45,81(s) 45,81(s) 45,81(s) 45,81(s) 45,81(s) 45,81(s)

Steam quality [ ] 0,875 1,000 1,000 0,981 0,960 0,944 0,932 0,921 0,912 0,890

Overall net power output [kW] 5345 5352 5367 5377 5377 5374 5371 5366 5362 5347

Steam cycle efficiency [%] 34,94 35,43 35,81 35,97 35,93 35,80 35,68 35,56 35,43 35,00

Steam cycle efficiency* [%] 37,16 37,29 37,72 37,96 37,96 37,88 37,78 37,67 37,57 37,19

Overall efficiency [%] 39,83 39,87 39,99 40,06 40,06 40,04 40,01 39,98 39,95 39,84


55

Table 7.19. Effect of reheating up to 550°C in function of intermediate pressure

Intermediate pressure [bar] no RH 3,86 6 12 18 24 30 36 42 120

Steam mass flow [kg/s] 1,27 0,99 1,01 1,04 1,07 1,08 1,10 1,11 1,13 1,25

Hp-stage gen power [kW] - 707 654 557 491 440 397 360 327 51

Lp- stage gen power [kW] - 781 858 977 1045 1096 1136 1170 1199 1420

Net steam cycle power [kW] 1447 1474 1498 1519 1521 1521 1517 1514 1510 1453

Engine cooling heat usage [kW] 247 192 196 202 208 210 214 216 220 243

Hp stage outlet temperature [°C] - 142,37(s) 177,86 241,68 283,19 314,48 340,13 361,92 380,93 526,17

Lp stage outlet temperature [°C] 45,81(s) 154,27 120,12 70,59 45,81 45,81(s) 45,81(s) 45,81(s) 45,81(s) 45,81(s)

Steam quality [ ] 0,875 1,000 1,000 1,000 0,998 0,983 0,972 0,962 0,954 0,889

Overall net power output [kW] 5345 5373 5396 5419 5421 5420 5417 5413 5409 5352

Steam cycle efficiency [%] 34,94 36,07 36,63 37,08 37,08 37,06 36,93 36,84 36,70 35,12

Steam cycle efficiency* [%] 37,16 37,85 38,47 39,01 39,06 39,06 38,96 38,88 38,78 37,31

Overall efficiency [%] 39,83 40,03 40,21 40,37 40,39 40,38 40,36 40,33 40,30 39,88

The variation of the high pressure turbine outlet temperature in function of the intermediate pressure, which

is shown in Figure 7.12, imposes a limit to the possible range of intermediate pressure. At about 3,86bar the

steam at the HP turbine outlet achieves the saturation temperature that is an unwanted event. The reheater is

designed to perform superheating only and the presence of liquid is not allowed.

The increase of the intermediate pressure results in a higher HP turbine outlet temperature. At a certain point

this temperature may achieve the reheating temperature. If this event occurs, the heat exchange is not

performed and the condition converges to the simple cycle. The limit is at 71bar, when reheating is set at

450°C, and at 140bar, for the reheating at 550°C, since the turbine inlet temperature and reheating

temperature are equal.

Figure 7.12. Reheating steam cycle. HP turbine outlet temperature in function of the intermediate pressure. At

71bar the temperature equals the first reheating condition (450°C), at 140 bar the second (550°C).


56

Figure 7.13 shows the overall efficiency (LHV) in function of the intermediate pressure, when reheating is

performed at 450°C and 550°C. The dotted constant line represents the simple steam cycle configuration. In

the all range of pressure considered, the efficiency is increased compared to the simple steam cycle

configuration. Both the curves present a maximum at a certain intermediate pressure, which is around 12bar

for reheating up to 450°C and 18bar for reheating up to 550°C. The presence of this maximum may be

explained by two concurrent effects. When the intermediate pressure is very low, reheating heat is added at

low pressure, depleting the efficiency of the cycle and resulting in a high LP turbine outlet temperature,

which is an energy loss. When the intermediate pressure is very high, the case converges to the simple cycle,

since the high pressure stage expansion becomes negligible. From these two effects, considered as extreme

cases, it is concluded that at a certain intermediate pressure the efficiency is maximized, due to the fact that

the cycle has a higher average top temperature. The maximum overall efficiency is respectively 40,06%, for

reheating at 450°C, and 40,37%, for reheating at 550°C.

Figure 7.13. Reheating steam cycle configuration. Overall efficiency (LHV) in function of the intermediate

pressure. The curve that refers to the higher reheating temperature shows a higher efficiency for the whole

range of intermediate pressure. For a high intermediate pressure the solution converges to the simple steam cycle

efficiency.

Consequently reheating at 550°C is selected, at the intermediate pressure of 18bar, resulting in a 0,56% more

efficiency respect to the simple steam cycle configuration. In order to apply this improvement, an additional

super heater and a turbine with extraction are needed. For the selected case, the main properties of the cycle

are shown in Table 7.20, the heat exchanger conditions are shown in Table 7.21 and the T-Q diagram in

Figure 7.14. The heat exchanger configuration refers to Figure 7.11. Since the heat required by reheating is

smaller than the heat required by superheating, the reheater faces the flue gas first, in order to keep a larger

temperature difference for the superheater.


57

Table 7.20. Main properties of the selected reheating steam cycle.

Temperature

[°C]

Pressure

[bar]

Polytropic

efficiency [%]

Mechanical

efficiency [%]

HP Turbine inlet 550 140 78,4 98,0

LP Turbine inlet 550 18 78,4 98,0

Condenser 45,81 0,1 - -

Table 7.21. Heat exchanger conditions for reheating up to 550°C with intermediate pressure at 18bar.

Q [kW] Tin water [°C] Tout water [°C] Tin flue gas [°C] Tout flue gas [°C]

Reheater 630 283 550 709 647

Superheater 877 337 550 647 558

Evaporator 1139 337 337 558 440

Economizer 1249 93 337 440 308

Figure 7.14. Reheating steam cycle configuration. T-Q diagram for reheating up to 550°C and intermediate

pressure equal to 18bar.


58

7.7 Condensation pressure

The saturated mixture of steam and water at the turbine outlet condensates at 0,10 bar and at the

correspondent temperature of about 46°C. A decrease of the condensation pressure (and temperature, since

saturation occurs) results in a higher steam turbine power output. This is due to the fact that a lower

condensation pressure introduces a higher pressure ratio for the steam turbine and in the consequent lower

outlet steam temperature or quality (if saturated). The condensation temperature diminution is limited by the

steam quality at the turbine outlet, which usually has to be larger than 85% to avoid corrosion, and by the

availability of an appropriate cooling fluid.

The effect of a decreased condensation pressure is studied for the simple cycle and for the reheating cycle

configuration. It has been experienced that the optimum intermediate pressure in the reheating cycle is not

influenced noticeably by this change of condensation pressure; therefore the 18bar intermediate pressure is

kept. The results of the decreased condensation temperature are shown in Table 7.22 for the simple steam

cycle case, in Table 7.23 for the reheating cycle and are resumed in Figure 7.15.

Table 7.22. Effect of condensation pressure decrease, simple steam cycle configuration.

Condensation pressure [bar] 0,10 0,09 0,08 0,07 0,06 0,05

Condensation temperature [°C] 45,81 43,76 41,51 39,00 36,16 32,87

Steam quality [%] 0,875 0,873 0,870 0,867 0,863 0,859

Steam turbine gen power [kW] 1465 1477 1492 1508 1528 1547

Overall net power output [kW] 5345 5358 5373 5389 5406 5428

Overall efficiency (LHV)[%] 39,83 39,92 40,03 40,15 40,28 40,44

Table 7.23. Effect of condensation pressure decrease, reheating steam cycle configuration.

Condensation pressure [bar] 0,10 0,09 0,08 0,07 0,06 0,05

Condensation temperature [°C] 45,81 43,76 41,51 39,00 36,16 32,88

Steam quality [%] 0,998 0,995 0,991 0,987 0,982 0,976

Steam turbine gen power [kW] 1538 1565 1565 1581 1599 1609

Overall net power output [kW] 5421 5434 5448 5464 5482 5503

Overall efficiency (LHV)[%] 40,39 40,49 40,59 40,71 40,84 41,00


59

Figure 7.15. Overall efficiency (LHV) in function of condensation pressure. Simple and reheating cycle

configuration. When the condensation pressure decreases, which results in the lowering of the condensation

temperature due to saturation, the plant efficiency increases.

The condensation pressure is set to 0,06bar and results in 0,45% more overall efficiency for both the simple

cycle and reheating cycle configuration. This condensation pressure refers to a temperature around 36°C,

which is suitable under a large number of environmental conditions when water, for example from a river, is

available as coolant. If such a coolant is not available, it may be possible to use a cold water storage, in order

to take advantage of the temperature difference between night and day.

As an example, the dimensioning of a cold water storage is calculated.

The environment conditions do not permit to have water that is cold enough during the day (12h). Cold water

is available during the night, at 20°C. Considering a pinch point in the condenser equal to 5K, the

temperature difference of 11K is available for the cold water storage. During the night the water from the

environment is used and, at the same time, the tank is filled. During the day the cold water from the tank is

used completely. Heat losses are not taken into account. The dimensioning of the storage is given in Table

7.24.


60

Table 7.24. Dimensioning of the water storage.

Simple cycle Reheating cycle

Condensation pressure 0,06 bar 0,06 bar

Condensation temperature 36,16 °C 36,16 °C

Available water during night 20°C 20°C

Pinch temperature 5K 5K

Temperature difference 11K 11K

Released heat 2652 kW 2528 kW

Energy released during day (12h) 115GJ 109GJ

Storage volume m3 2489 2359

The storage results in a container volume of 2500 m3 that may be a cylinder 14 m high and with a diameter of

15m. It is quite large for the plant size, but not unfeasible.

The pressure in the condenser is set at 0,06bar, resulting in a condensation temperature of 36°C

Chapter 8: Optimized plant results

61


The results from the optimization are given for the two different configurations, with simple steam cycle and

with reheating steam cycle.

8.1 Optimized plant results

The optimization of the plant is concluded, considering the two configurations, without and with reheating.

The main properties and results of the optimized plant for the simple cycle case are given in Table 8.1 and

for the reheating cycle case in Table 8.2.


62

Table 8.1. Optimized simple steam cycle configuration. Results.

Property Value Unit

Energy

Inlet wood LHV energy 13422 kW


Steam turbine gen power out 1528 kW

Net power output 5406 kW

Overall efficiency LHV 40,28 %

Gasifier module

Wood inlet mass flow 1,43 kg/s

Dry Syngas outlet mass flow 1,50 kg/s

Light tar outlet mass flow 0,0888 kg/s

Heavy tar+particles outlet mass flow 0,0677 kg/s

Condensate water 0,62 kg/s

Wood LHV 9370 kJ/kg

Dry Syngas LHV 6560 kJ/kg

Light tar LHV 15980 kJ/kg

Heavy tar+particles LHV 30370 kJ/kg

Engine

Power output 3945 kW


Released engine cooling heat 1356 kW

Used engine cooling heat 498 kW

Engine cooling inlet temperature 88 °C

Engine cooling outlet temperature 98 °C

Engine cooling mass flow 44,06 kg/s

Other losses 1321 kW


Flue gas temperature 401 °C

HRSG-Steam cycle

HRSG gas side mass flow 7,55 kg/s

HRSG gas side inlet temperature 709 °C

HRSG gas side outlet temperature 308 °C

Steam mass flow 1,27 kg/s

Turbine inlet pressure 140 bar

Condenser pressure 0,06 bar

Condenser released heat 2657 kW

Turbine inlet temperature 550 °C

Condenser temperature 36 °C

Turbine generator power 1528 kW

Steam cycle net power 1507 kW

Secondary heat exchangers



63

Table 8.2. Optimized reheating cycle configuration. Results.

Property Value Unit

Energy

Inlet wood LHV energy 13422 kW


HP Steam turbine gen power out 492 kW

LP Steam turbine gen power out 1108 kW

Net power output 5482 kW

Overall efficiency LHV 40,84 %

Gasifier module

Wood inlet mass flow (*) 1,43 kg/s

Syngas outlet mass flow 1,50 kg/s

Light tar outlet mass flow 0,0888 kg/s

Heavy tar+particles outlet mass flow 0,0677 kg/s

Condensate water 0,62 kg/s

Wood LHV 9370 kJ/kg

Syngas LHV 6560 kJ/kg

Light tar LHV 15980 kJ/kg

Heavy tar+particles LHV 30370 kJ/kg

Engine

Power output 3945 kW


Released engine cooling heat 1385 kW

Used engine cooling heat 469 kW

Engine cooling inlet temperature 88 °C

Engine cooling outlet temperature 98 °C

Engine cooling mass flow 44,06 kg/s

Other losses 1321 kW


Flue gas temperature 401 °C

HRSG-Steam cycle

HRSG gas side mass flow 7,55 kg/s

HRSG gas side inlet temperature 709 °C

HRSG gas side outlet temperature 308 °C

Steam mass flow 1,07 kg/s

Condenser temperature 36 °C

Condenser pressure 0,06 bar

Condenser released heat 2532 kW

HP Turbine inlet pressure 140 bar

HP Turbine inlet temperature 550 °C

LP Turbine inlet pressure 18 bar

LP Turbine inlet temperature 550 °C

HP Turbine generator power 492 kW

LP Turbine generator power 1108 kW

Net steam cycle power 1583 kW

Secondary heat exchangers



64

Both the analyzed configurations result in an overall efficiency above 40% and therefore the target is

achieved. It is demonstrated that the introduction of the reheating cycle increases the overall efficiency from

40,3% to 40,8%. The reheating cycle requires a steam turbine with an extraction and an additional heat

exchanger in the HRSG. The higher complexity of the second configuration results in higher cost of the

plant. The adoption of one of the two solutions has to be evaluated through economic calculation, for

example using the pay-back period analyses. The economic evaluation of the two configurations is beyond

the scope of this work and consequently both are kept as options.

The flow sheet, nodes sheet and DNA code for the simple cycle configuration (IBGCC_opt_ng) and for the

reheating cycle configuration (IBGCC_RH_opt_ng) are given in appendix.

8.2 Losses analyses

The results from the loss calculation are given in Table 8.3, for the simple cycle configuration, and Table 8.4,

for the reheating cycle configuration, based on the high heating value (HHV) and on the low heating value

(LHV). The two calculations differ when water evaporation occurs, since for the LHV calculation the

evaporation in the tar water treatment is a loss of energy. On the other hand the flue gas energy in the LHV

calculation is lower, due to the fact that the water condensation heat is not taken into account.

Table 8.3. Results from the losses analyses. Simple steam cycle configuration.

Component Source of loss Energy MW

(HHV based)

% of the input

(HHV based)

MW

(LHV based)

% of the input

(LHV based)

Gasifier Ash 0,11 0,7 0,11 0,8

Water preheting Evaporation 0 0 0,34 2,5

Syngas cooler Released heat 1,58 9,9 0,16 1,2

Tar water treatment Evaporation 0 0,0 1,42 10,6

Engine Losses 1,32 8,2 1,32 9,8

Engine Cooling system Released heat 1,34 8,4 1,34 10,0

Turbine Efficiency 0,03 0,2 0,03 0,2

Steam cycle condenser Released heat 2,65 16,5 2,65 19,7

Flue gas Thermal energy 3,59 22,4 0,64 4,8

Total losses 10,62 66,3 8,01 59,7

Net power production 5,41 33,7 5,41 40,3

Energy input (wood) 16,03 100,0 13,42 100,0


65

Table 8.4. Results from the losses analyses. Reheating steam cycle configuration.

Component Source of loss Energy MW

(HHV based)

% of the input

(HHV based)

MW

(LHV based)

% of the input

(LHV based)

Gasifier Ash 0,11 0,7 0,11 0,8

Water preheating Evaporation 0 0 0,34 2,5

Syngas cooler Released heat 1,58 9,9 0,16 1,2

Tar water treatment Evaporation 0 0,0 1,42 10,6

Engine Losses 1,32 8,2 1,32 9,8

Engine Cooling system Released heat 1,40 8,8 1,40 10,4

Turbine Efficiency 0,03 0,2 0,03 0,2

Steam cycle condenser Released heat 2,52 15,8 2,52 18,8

Flue gas Thermal energy 3,59 22,4 0,64 4,8

Total losses 10,55 65,8 7,94 59,2

Net power production 5,48 34,2 5,48 40,8

Energy input (wood) 16,03 100,0 13,42 100,0

The Sankey diagram, Figure 8,1, gives a qualitative visualization of the behavior of the energy system in

terms of streams and losses. In the current case it is drawn according to the Low Heating Value calculation

(LHV).


66

Figure 8.1. Sankey diagram based on the LHV calculation. The diagram shows the main energy flows in the

system and the relative losses qualitatively. The preheating of the gasification agent results in partially in a loss,

due to water evaporation, and partially in energy recirculation.

Chapter 9: Other issues

67


The use of natural gas as additional fuel, the amount of water consumption and production, the opportunity

of district heating or cooling and the effect of syngas bypass are analyzed.

9.1 Switching to natural gas.

In many cases it is important to assure a regular power output even when, for example, the biomass supply is

limited or temporary stopped, especially when the plant has to provide a remote area with electricity. This

kind of plant permits to mix syngas and natural gas in the gas engine and to burn additional natural gas in the

furnace, keeping the same power output for the gas engine and the steam turbine when the gasifier load is

decreased. The extent of the possibility of switching to natural gas and the effect on the efficiency is studied.

In order to model this condition in DNA, a mixer (mixer_ng) is added before the gas engine, to mix syngas

and natural gas, and an additional burner (burner_4) is added as the last stage in the furnace. The engine and

turbine power outputs are fixed.

The results of the calculation are given below in Table 9.1 and 9.2, when the gasifier is fed with a decreasing

amount of biomass, for the simple cycle and for the reheating cycle configuration. The effect on the

efficiency is shown in Figure 9.1.

Table 9.1. Natural gas replaces producer gas, for the simple cycle configuration. Gas engine and steam turbine

power output are kept constant.

Natural gas input energy/

Total input energy [%] 0% 25% 50% 75% 100%

Syngas mass flow [kg/s] 1,50 1,13 0,75 0,38 0

Light tar [kg/s] 0,089 0,067 0,044 0,022 0

Heavy tar [kg/s] 0,068 0,051 0,034 0,017 0

Natural gas engine [kW] 0 2468 4934 7402 9862

Natural gas furnace [kW] 0 425 854 1281 1996

Engine flue gas mass flow [kg/s] 6,77 6,74 6,70 6,66 6,63

Engine flue gas temperature [°C] 401 401 401 401 401

Furnace flue gas mass flow [kg/s] 7,55 7,33 7,11 6,89 6,67

Furnace flue gas temperature [°C] 709 687 665 640 645

Economizer outlet gas temperature [°C] 308 265 217 164 142

Stack temperature [°C] 103 103 103 103 142

Engine power output [kW] 3945 3945 3945 3945 3945

Steam turbine gen power output [kW] 1528 1528 1528 1528 1528

Net power [kW] 5407 5417 5428 5438 5453

LHV efficiency [%] 40,28 41,80 43,42 45,17 45,98


68

Table 9.2. Natural gas replaces producer gas, for the reheating cycle configuration. Gas engine and steam

turbine power output are kept constant.

Natural gas input energy/

Total input energy [%] 0% 25% 50% 75% 100%

Syngas mass flow [kg/s] 1,50 1,13 0,75 0,38 0

Light tar [kg/s] 0,089 0,067 0,044 0,022 0

Heavy tar [kg/s] 0,068 0,051 0,034 0,017 0

Natural gas engine [kW] 0 2468 4934 7402 9862

Natural gas furnace [kW] 0 431 854 1441 2242

Engine flue gas mass flow [kg/s] 6,77 6,74 6,70 6,66 6,63

Engine flue gas temperature [°C] 401 401 401 401 401

Furnace flue gas mass flow [kg/s] 7,55 7,33 7,11 6,89 6,67

Furnace flue gas temperature [°C] 709 688 665 658 673

Economizer outlet gas temperature [°C] 308 265 217 184 177

Stack temperature [°C] 103 103 103 124 177

Engine power output [kW] 3945 3945 3945 3945 3945

HP steam turbine gen power output [kW] 492 492 492 492 492

LP steam turbine gen power output [kW] 1108 1108 1108 1108 1108

Net power [kW] 5482 5493 5505 5515 5528

LHV efficiency [%] 40,84 42,38 44,03 45,21 45,67


69

Figure 9.1. Overall efficiency (LHV) when natural gas replaces producer gas, for the simple cycle and for the

reheating cycle configuration. The switching to natural gas results in an increase of efficiency since the losses

related to the gasification process are proportionally decreased. The change of slope is due to the fact that the

stack temperature has to be raised.

The efficiency increase, when natural gas replaces producer gas, is caused by the fact that the gasification

process loses energy in the gasifier and in the tar-water treatment. This second contribution is the largest.

When natural gas is introduced the amount of wood to be fed in the system is decreasing and these losses as

well, proportionally. Therefore the overall efficiency (LHV) becomes higher.

When 0%, 25% and 50% of the input energy is given by natural gas, the reheating cycle configuration

efficiency is higher than the simple cycle efficiency, as expected. At 75% the stack temperature of the

reheating cycle has to be increased up to 124°C in order to keep the 5K pinch point in the HRSG, due to the

lowering of the furnace outlet temperature. This fact explains why the efficiency of the reheating cycle

configuration decreases and gets closer to the simple cycle configuration value. When the whole energy is

provided by natural gas (100%), the reheating cycle configuration stack temperature is set at 177°C and the

one for the simple cycle configuration at 142°C. At this point the efficiency of the plant with reheating is

lower than the one without reheating.

The use of natural gas is possible for the entire range of load, since the engine volume flow decreases as well

as the volume flow and the temperature in the furnace.

The small increase of the net power output is due to lower power consumption of the syngas booster, placed

before the gas engine.


70

It is concluded that the same plant may result in a higher efficiency if natural gas replaces producer gas

obtained by biomass gasification. This conclusion may drive to the idea that it is better to use natural gas

instead than biomass, but some considerations have to be taken into account:

The production of natural gas requires energy, which is not considered here. Instead the whole

process from wood chips to syngas and tar is taken into account for the biomass gasification.

Biomass is a carbon neutral energy source, while natural gas is not.

The price of the two fuels is different generally.

The amount of carbon dioxide that is produced if natural gas is used in place of biomass results in

20800t/year. The calculation is given in Table 9.2.

Table 9.2. CO2 production when natural gas is used in place of biomass.

Property Value

C mass/natural gas mass 0,75

CO2 mass/natural gas mass 2,75

Natural gas mass /power 0,044

Power/ year 172 TJ/year

Fuel mass/year 7560 t/year

CO2 mass /year 20800 t/year

9.2 Increase of the power output adding natural gas.

In order to take advantage of the high prices during the daily peaks or to provide the network with more

electricity, the power output may be increased of 10%, for example.

In this calculation it is assumed that the engine and the steam turbine can give a 10% higher power. The

gasifier load is 100% and it is not possible to increase further. The extra power is obtained thanks to

additional natural gas that is supplied to the engine and to the furnace. The results of the calculation are

given in Table 9.3 and 9.4 for the simple cycle and reheating cycle case.


71

Table 9.3. 10% extra power is obtained by additional natural gas. Results for the simple cycle configuration.

Gasifier load 100% 100%

Power output increase 0% 10%

Syngas mass flow [kg/s] 1,50 1,50

Light tar [kg/s] 0,089 0,089

Heavy tar [kg/s] 0,068 0,068

Natural gas engine [kW] 0 988

Natural gas furnace [kW] 0 170

Engine flue gas mass flow [kg/s] 6,77 7,44

Engine flue gas temperature [°C] 401 401

Furnace flue gas mass flow [kg/s] 7,55 8,22

Furnace flue gas temperature [°C] 709 701

Economizer outlet gas temperature [°C] 308 293

Stack temperature [°C] 103 103

Engine power output [kW] 3945 4340

Steam turbine gen power output [kW] 1528 1680

Net power [kW] 5407 5952

Overall efficiency (LHV) [%] 40,28 40,82

Table 9.4. 10% extra power is obtained by additional natural gas. Results for the reheating cycle configuration.

Gasifier load 100% 100%

Power output increase 0% 10%

Syngas mass flow [kg/s] 1,50 1,50

Light tar [kg/s] 0,089 0,089

Heavy tar [kg/s] 0,068 0,068

Natural gas engine [kW] 0 988

Natural gas furnace [kW] 0 170

Engine flue gas mass flow [kg/s] 6,77 7,44

Engine flue gas temperature [°C] 401 401

Furnace flue gas mass flow [kg/s] 7,55 8,22

Furnace flue gas temperature [°C] 709 701

Economizer outlet gas temperature [°C] 308 292

Stack temperature [°C] 103 103

Engine power output [kW] 3945 4340

HP steam turbine gen power output [kW] 492 541

LP steam turbine gen power output [kW] 1108 1219

Net power [kW] 5482 6035

LHV efficiency 40,84 41,39


72

As explained in section 9.1, the addition of natural gas increases the overall efficiency, due to the diminution

of the losses introduced by the gasification process.

9.3 Water supply to the plant

Water is collected by the system in the scrubber, as condensate from the flue gas, just before the chimney.

Part of this water amount is used in order to provide the gasifier with steam, used as gasification agent. In

this way not only water is saved, which may be also not available in remote areas, but also energy, since the

water from the downstream cooler is already at 50°C

The water production and consumption are given in Table 9.5, the wood mass flow is used as reference.

Table 9.5. Water consumption and production in the plant

Absolute value kg/s Relative value kg/kg_wood

Wood 1,43 1,00

Water (gasification agent) 0,15 0,10

Water production (downstream cooler) 0,74 0,52

Water surplus 0,59 0,41

9.4 District heating

It is interesting to study how the plant has to change in order to generate not only electrical power, but also

district heating, in case that a district heating network is available. The effect of these changes on the

efficiency of the combined heat and power plant is studied. The definition of power efficiency and heat and

power efficiency are given below:

kWLHVinletenergy

kWouputheatusefulnetkWouputpowernetefficiencypowerandheat

kWLHVinletenergy

kWouputpowernetefficiencypower

The output temperature of the common district heating systems is around 90°C and the inlet temperature is

around 60-70°C.

The amount of engine cooling heat that is not used for other purposes fits with the conditions for district

heating, since the engine cooling water is between 98°C and 88°C. The results are shown, compared with the

no district heating case, for the simple cycle in Table 9.6 and for the reheating cycle in Table 9.7.


73

Table 9.6. District heating from engine cooling. Simple cycle configuration.

Property No DH DH_engine Unit

Inlet wood energy (LHV) 13422 13422 kW

Engine(s) power out 3945 3945 kW

Steam turbine gen power out 1528 1528 kW

DH from engine cooling heat 0 1356 kW

Net power output 5406 5406 kW

Total DH 0 1344 kW

Power efficiency (LHV) 40,28 40,28 %

Heat and Power efficiency (LHV) 40,28 50,39 %

Table 9.7. District heating from engine cooling. Reheating cycle configuration.

Property No DH DH_engine Unit

Inlet wood LHV energy 13422 13422 kW


HP Steam turbine gen power out 492 492 kW

LP Steam turbine gen power out 1108 1107 kW



Total DH 0 1384 kW

Power efficiency LHV 40,84 40,84 %

Heat and Power efficiency LHV 40,84 51,15 %

Additional energy for district heating may be taken from the condensation heat released by the steam cycle.

In order to achieve a cooling water temperature high enough for this purpose, the condensation pressure has

to be increased up to 0,85bar, resulting in a condensation temperature at 95°C (5K pinch point in the

condenser). This pressure change decreases the turbine power output. Furthermore the engine cooling heat

cannot warm up the feedwater, already above 93°C, but it is used for district heating. The results are given in

Table 9.8 for the simple cycle and Table 9.9 for the reheating cycle configuration.


74

Table 9.8. District heating from engine cooling and condenser. Simple cycle configuration.

Property No DH DH_engine

+condenser

Unit





DH from condenser 0 2714 kW


Total DH 0 4369 kW



Table 9.9. District heating from engine cooling and condenser. Reheating cycle configuration.

Property No DH DH_engine

+condenser

Unit






DH from condenser 0 2662 kW


Total DH 0 4296 kW



In Table 9.10 the different efficiencies, power efficiency and heat and power efficiency, under the three

different conditions, for both the simple and reheating cycle configuration are compared:

1. No district heating

2. District heating from engine cooling only

3. District heating from engine cooling and condenser cooling water.

The reheating steam cycle configuration with district heating performed by the engine cooling heat and by

the condenser results in the highest heat and power efficiency.


75

Table 9.10. District heating. Comparison between different cases.

Configuration Power efficiency

(LHV) [%]

Heat and power

efficiency (LHV) [%]

Simple cycle no DH 40,28 40,28

Simple cycle DH_engine 40,28 50,39

Ssimple cycle DH_engine+condenser 37,67 70,22

Reheating cycle no DH 40,84 40,84

Reheating cycle DH_engine 40,84 51,15

Reheating cycle DH_engine+condenser 38,06 70,07

9.5 District cooling

The heat released from the engine cooling water system and, eventually, the heat released by the steam cycle

condensation (if condensation is set to 0,85bar and 95°C) may be used in order to generate chilling water for

a district cooling system. It is possible to recover the low temperature waste heat through an absorption

chiller driven by a hot water stream. The coefficient of performance of the absorption cooling process is

defined by the ratio between the cooling effect and the heat consumption from the hot water stream.

waterhot

cooling

Q

QCOP

The main characteristic of the considered absorption cooling system are given in Table 9.11.

Table 9.11. Absorption cooling system properties.

Property Value Unit

Hot water inlet temperature 90 °C

Hot water outlet temperature 85 °C

Chilling water inlet temperature 12 °C

Chilling water outlet temperature 6 °C

COP 0,7 -

Two cases are presented. In the first case only the waste heat from the engine cooling system is used, in the

second case the condensation pressure in the steam cycle is increased up to 0,85bar and also the released heat

from the condenser is available. The two cases are listed in Table 9.12 and 9.14 for the simple steam cycle

configuration and in Table 9.13 and 9.15 for the reheating steam cycle configuration.


76

Table 9.12. District cooling from engine cooling. Simple cycle configuration.

Property No DC DC_engine Unit




Waste engine cooling heat 0 1356 kW


Total DC 0 949 kW


Cooling and Power efficiency LHV 40,28 47,35 %

Table 9.13. District cooling from engine cooling. Reheating cycle configuration.

Property No DC DC_engine Unit







Total DC 0 969 kW



Table 9.14. District cooling from engine cooling and condenser. Simple cycle configuration.

Property No DC DC_engine

+condenser

Unit





Waste heat from condenser 0 2714 kW


Total DC 0 3058 kW




77

Table 9.15. District cooling from engine cooling and condenser. Reheating cycle configuration

Property No DC DC_engine

+condenser

Unit






Waste heat from condenser 0 2662 kW


Total DC 0 3007 kW



The different cases considered are resumed in Table 9.16.

Table 9.16. District cooling. Comparison between different cases.

Configuration Power efficiency

(LHV) [%]

Cooling and power

efficiency (LHV) [%]

Simple cycle no DC 40,28 40,28

Simple cycle DC_engine 40,28 47,35

Simple cycle DC_engine+condenser 37,67 60,45

Reheating cycle no DH 40,84 40,84

Reheating cycle DC_engine 40,84 48,06

Reheating cycle DC_engine+condenser 38,06 60,47

The complementary implementation of district heating, in winter, and of district cooling, in summer, results

in a solution that decreases extremely the amount of waste energy.

9.6 Syngas bypass

A certain amount of syngas may bypass the engine and enter the furnace in order to achieve better

combustion conditions. Of course a decrease of the overall efficiency is expected, since energy is introduced

in the bottom cycle, instead than in the top cycle. The calculation is performed considering a range of

bypassing syngas between 0% and 10% of the total syngas amount. The results are given in Table 9.17 for

the simple steam cycle configuration and in Table 9.18 for the reheating steam cycle configuration and

shown in Figure 9.2


78

Table 9.17. Simple cycle configuration. Effect of the syngas bypass on overall efficiency.

Amount of bypassing syngas

Property unit 0,0% 2,5% 5% 7,5% 10%

Inlet wood LHV energy kW 13422 13422 13422 13422 13422

Furnace flue gas mass flow kg/s 7,55 7,42 7,29 7,16 7,03

Furnace flue gas temperature °C 709 735 763 791 820

Engine(s) power out kW 3945 3849 3751 3652 3554

Steam turbine gen power out kW 1528 1597 1671 1745 1819

Net power output kW 5406 5382 5356 5331 5305

Overall efficiency LHV % 40,28 40,10 39,91 39,72 39,53

Table 9.18. Reheating cycle configuration. Effect of the syngas bypass on overall efficiency

Amount of bypassing syngas

Property Unit 0,0% 2,5% 5% 7,5% 10%

Inlet wood LHV energy kW 13422 13422 13422 13422 13422

Furnace flue gas mass flow kg/s 7,55 7,42 7,29 7,16 7,03

Furnace flue gas temperature °C 709 735 763 791 820

Engine(s) power out kW 3945 3849 3751 3652 3554

HP Steam turbine gen power out kW 492 525 538 562 586

LP Steam turbine gen power out kW 1108 1159 1212 1265 1319

Net power output kW 5482 5461 5439 5417 5395

Overall efficiency LHV % 40,84 40,69 40,52 40,36 40,20


79

Figure 9.2. Overall efficiency in function of syngas bypass. Simple and reheating configuration. The syngas

bypass results in a noticeable diminution of efficiency due to the fact that energy is added to the bottom cycle

instead than to the top cycle.

When syngas bypasses the engine and enters the furnace, the overall efficiency decreases noticeably. The

diminution of the overall efficiency when 10% of the syngas bypasses the engine is around 0,75% for the

simple cycle configuration and 0,64% for the reheating cycle configuration. Thereby the amount of

bypassing syngas has to be minimized by an appropriate furnace design.

Chapter 10: Conclusions

81

Chapter 10: Conclusions

Conclusions and suggestions are discussed.

Model

The plant modeling is performed using the tool DNA. The gasifier model is based on experimental data for a

particular updraft gasifier placed in Harboøre. An identical reactor is used in the current project. This

solution assures the validity of the gasification model for the actual purpose.

Small combined cycle and efficiency

The analyzed plant is defined as Integrated Biomass Gasification Combined Cycle. The fuel is biomass in the

form of wood chips and is converted into producer gas by an updraft gasifier. The gas cleaning is performed

to separate dry syngas and tar. The dry syngas provides the top cycle with energy, while tar and the flue gas

from the engine are the source of energy for the bottom cycle. The top and the bottom cycle are respectively

a gas engine and a Rankine cycle. The plant size is around 5MW.

The optimization results in two different configurations that differ from the adopted bottom cycle.

The first configuration is implemented with a simple steam cycle. The overall efficiency (LHV) is calculated

to be 40,3%. The second configuration introduces reheating in the steam cycle. In this case the efficiency

raises up to 40,8%. Since the improvement obtained by the introduction of the reheating system is not very

large, a specific economic evaluation is required to select one of the two configurations.

In case that district heating and/or district cooling are available options, it is possible to recover part of the

waste heat from the engine cooling system and from the condenser. The system, for both the configurations,

may achieve a heat and power efficiency around 70% through the introduction of district heating and a

cooling and power efficiency around 60% through the introduction of district cooling .Hence it is suggested

to combine district heating, in winter, and district cooling, in summer, if possible.

Carbon neutrality

The examined power plant uses wood, a carbon neutral energy source. In fact if the live biomass is replaced,

the carbon stored by the plants balances the carbon dioxide released in the process. If the same plant is

supplied with natural gas, 20800 tons of carbon dioxide will be released per year.

Fuel flexibility

The producer gas coming from the gasifier may be partially or completely replaced by natural gas. This

opportunity is very important in case that the biomass supply is interrupted temporary.


82

If the gas engine and the steam turbine can run at higher load, for example 10% more when the gasifier is

under full load condition, natural gas may be used as additional fuel to increase the power output. This

option could be applied to take advantage of the electricity price variation during the day.

The utilization of natural gas in place of wood or as additional fuel results in a higher overall efficiency,

since the gasification process introduces losses. Of course carbon neutrality is negatively affected.

No need for external water supply.

The plant does not need external water supply and is a net producer of water. The water coming into the

system as wood moisture is partially recycled as gasification agent. The remaining part leaves the system in

the downstream cooler as condensate. It is concluded that the plant may be used in areas where water is an

important and critical good.

Chapter 11: Further work

83

Chapter 11: Further work

Some suggestions for further work are listed.

Tar water treatment. The tar water treatment adopted is easy to control and does not require expensive

equipments. Nevertheless it introduces a remarkable energy loss due to the evaporation of a quite large water

amount present in the tarwater stream. A more sophisticate treatment may be studied to achieve a higher

overall efficiency.

Part load. The analyzed plant combines the power obtained by two gas engines and a steam turbine. A

certain degree of decoupling of the top and the bottom cycle exists and can be exploited to run the plant

under part load. The storage of tar, which has a relevant heating value, gives the opportunity of turning off

the steam cycle and using only the gas engines, even when the gasifier is under full load condition. Different

part load combinations may be evaluated to take advantage of the variation in time of the electricity price

and to develop an efficient strategy in case of maintenance.

Gasification model. The gasifier model adopted in this work does not permit to forecast different

gasification conditions, since it is based on experimental data for a particular gasifier. The development of a

flexible gasifier DNA component, which includes tar as output, could give the opportunity of analyzing other

different solutions.

Different kinds of plants. In the studied plant the syngas, which is obtained by the gasification process, is

combusted in a gas engine. Nevertheless this fuel fits many other components, traditional machines, like gas

turbines, and innovative systems, like fuel cells. The use of these technologies introduces issues in terms of

gas cleaning, since particles and tar may damage the turbine and dirty the fuel cell stack. In the case of a

plant based on a fuel cell system, the size is limited because large components have not been produced yet.

However the examination of different kinds of biomass gasification applications may result in feasible and

efficient plants

Co-firing. Biomass gasification technology is also interesting when it is used to provide an already-existing

plant with additional energy. For example, it is possible to introduce reheating in a waste or fossil fuel fired

steam cycle plant using extra heat obtained by syngas combustion. In this way the energy mix is improved in

the direction of renewable sources, without the need for building a complete new plant, resulting in a smaller

cost of the intervention.

List of symbols

85

List of symbols

CF_1 gasification conversion factor (only syngas) [ ]

CF_2 gasification conversion factor (syngas and tar) [ ]

cp specific heat [J/(kg K)]

h enthalpy [J/kg]

HHV high heating value [J/kg]

m mass [kg]

m mass flow [kg/s]

MOI moisture content, wet wood weight based [ ]

LHV low heating value [J/kg]

Q heat rate [W]

TiP turbine inlet pressure [bar]

TiT turbine inlet temperature [°C]

xC carbon amount related on the dry wood, weight based [ ]

xO oxygen amount related on the dry wood, weight based [ ]

xH hydrogen amount related on the dry wood, weight based [ ]


86

Bibliography

87

Bibliography

Ahrenfeldt J., (2007) “Characterization of biomass producer gas as fuel for stationary gas engines in

combined heat and power production”.

Basu P., (2006)“Combustion and gasification in fluidized beds”

Bauen A., (2004), “Encyclopedia of energy”, “Biomass gasification”.

Elmegaard B., (1999), “Simulation of Boiler Dynamics - Development, Evaluation and Application of a

General Energy System Simulation Tool”, Ph.D. Thesis, Department of Energy Engineering, DTU.

Goswami D. Y., Kreith F., (2008), “Energy Conversion”, Overend R.P., Wright L.L, chapter 3.

Hall D. O., Rosillo-Calle F., Williams R. H., and Woods J., (1993), “Biomass for energy: supply prospects In

Renewable Energy: Sources for Fuels and Electricity”, T. B. Johansson, H. Kelly, A. K. N. Reddy, and R. H.

Williams, eds., pp. 593–651.

Hordeski M.F, (2006), “Alternative fuels: the future of hydrogen”, chapter 7.

Jensen N., Werling J., Carlsen H., Henriksen U., (2002), “CHP from updraft gasifier and Stirling engine”.

Kreith F., Goswami D. Y., (2007), “Handbook of Energy Efficiency and Renewable Energy”, chapter 25

written by Kayhanian M. and Tchobanoglous G. and Brown R. C..

Larminie J., Dicks A., (2003), “Fuel cell systems explained”.

Quaak P., Knoef H., Stassen H.E., (1999), “Energy from biomass: a review of combustion and gasification

technologies”.

Saravanamuttoo H.I.H., Rogers G.F.C., Cohen H., (2001), “Gas Turbine Theory”.

Sunggyu L., Speight J. G., Sudarshan K. L., (2007), “Handbook of Alternative Fuel Technologies”, chapter

12.

Winandy J.E., Rudie A.W., Williams R.S., Wegner T.H., (2008), “Integrated Biomass Technologies: a future

vision for optimally using”.


88

Technical University of Denmark

Department of Mechanical Engineering

Modeling and optimization

of biomass gasification systems

“a Biomass Integrated Gasification Combined Cycle plant”

Appendix

May 2009

Author: Luca Carlassara

Supervisor: Masoud Rokni

External supervisor: Thomas Norman

Modeling and optimization of biomass gasification systems. Appendix

A-2

IBGCC basic configuration. Flow sheet.

A-3

Appendix

......................................................................................................................................................................

IBGCC basic configuration .......................................................................................................................... 5

IBGCC basic configuration. Flow sheet. ...................................................................................................... 6

IBGCC basic configuration. Nodes sheet ..................................................................................................... 7

IBGCC basic configuration. DNA code. .................................................................................................... 10

IBGCC optimized configuration................................................................................................................. 17

IBGCC optimized configuration. Flow sheet. ............................................................................................ 18

IBGCC optimized configuration. Nodes sheet............................................................................................ 19

IBGCC optimized configuration. DNA code. ............................................................................................. 23

IBGCC optimized configuration with reheating ......................................................................................... 31

IBGCC optimized configuration with reheating. Flow sheet. ..................................................................... 32

IBGCC optimized configuration with reheating. Nodes sheet. ................................................................... 33

IBGCC optimized configuration with reheating. DNA code. ..................................................................... 37


A-4


A-5

IBGCC basic configuration

Simple steam cycle 45/0,1bar-450°C

Secondary heat exchanger configuration number 1

Engine cooling heat only for feedwater heating


A-6


IBGCC basic configuration. Nodes sheet

A-7


Component Media Description

gasifier - GASIFI_3 1 solid wood_notar no-tar-wood int

2 STANDARD_AIR air in

3 STEAM H-F steam in

4 SyngasWet wet syngas out 80 Ash ash out

300 HEAT heat

cooler GASCOOL1

4 SyngasWet syngas wet in

41 Syngas syngas dry out

42 STEAM-HF condensate water 60 STEAM cooling water in

61 STEAM cooling water out

301 HEAT heat

booster COMPRE_1

41 Syngas syngas in

43 Syngas syngas out 370 HEAT heat

470 MECH_POWER power consumption

split SPLITTER

43 Syngas Syngas in

44 Syngas Syngas out to the engine

45 Syngas Syngas out to the furnace (bypass)

engine ENGINE_1

22 STANDARD_AIR air in 44 Syngas syngas in

32 Flue_Engine engine flue gas out

400 ELECT_POWER electrical power production

303 HEAT losses 500 HEAT engine cooling heat

conv STHF2H2OG 434 STEAM-HF steam from tarwater treatment real gas in

435 STEAM_(I.G.) steam from tarwater treatment ideal gas out

mixer MIXER_01

435 STEAM_(I.G.) steam from tarwater treatment ideal gas in

32 Flue_Engine engine flue gas in

33 MIX gas mixture out

burner_1 GASBUR_2

33 MIX gas mixture in 45 Syngas bypassing syngas in

7 Flue_Burner_1 flue gas out

306 HEAT heat

burner_2 SOLBUR_4

7 Flue_Burner_1 flue gas in

6 Tar_1 light tar 71 Flue_Burner_2 flue gas out

81 ASH_1 ash

304 HEAT heat

burner_3 SOLBUR_4


16 Tar_2 heavy tar 72 Flue_Burner_3 flue gas out

82 ASH_2 ash

305 HEAT heat

ECO HEATEX_1

732 Flue_Burner_3 flue gas in 73 Flue_Burner_3 flue gas out

50 STEAM feedwater in

511 STEAM saturated water out

340 HEAT heat

EVA HEATEX_1


511 STEAM saturated water in


A-8

512 STEAM saturated steam out

341 HEAT heat

SH HEATEX_1


731 Flue_Burner_3 flue gas out 512 STEAM saturated steam in

51 STEAM superheated steam out

342 HEAT heat

turbine TURBIN_1

51 STEAM superheated steam

54 STEAM expanded steam/water 401 MECH_POWER mechanical power production

generator SIM_GENE 499 ELECT_POWER electrical power production

399 HEAT heat loss

401 MECH_POWER shaft power

cond STECON_0

54 STEAM expanded steam/water

55 STEAM condensed water 308 HEAT released heat

LP_pump LIQPUM_1 55 STEAM water in

56 STEAM compressed water out

411 ELECT_POWER power consuption

HP_pump LIQPUM_1

57 STEAM water in

50 STEAM compressed water out 412 ELECT_POWER power consuption

PRE_H_A2 HEATEX_1 73 Flue_Burner_3 flue gas in



2 STANDARD_AIR air out 339 HEAT heat





PRE_H_W3 HEATEX_1



343 STEAM saturated steam in

3 STAM superheated steam out 329 HEAT heat

PRE_H_W2 HEATEX_1 753 Flue_Burner_3 flue gas in



343 STAM saturated steam out 349 HEAT heat



31 STEAM water in

344 STEAM saturated water out 319 HEAT heat

HE_125 HEATEX_1



204 STEAM-HF pressurized water in (cold) 203 STEAM-HF pressurized water out (hot)

320 HEAT heat

tw_pump LIQPUM_1

42 STEAM-HF tarwater in

431 STEAM-HF tarwater out

403 ELECT_POWER power consumption


A-9

tw_heater HEATEX_1 203 STEAM-HF pressurized water in

202 STEAM-HF pressurized water out


433 STEAM-HF steam out 330 HEAT heat

tw_comp COMPRE_1 COMPRE_1 433 STEAM-HF steam in

434 STEAM-HF steam out

442 HEAT heat

443 ELEC_POWER power consumption

pump_125 LIQPUM_1

202 STEAM-HF pressurized water in 204 STEAM-HF pressurized water out


cooler2 GASCOOL1


76 Exaust flue gas out



331 HEAT heat

split2 SPLITTER

77 STEAM-HF condensate water in

78 STEAM-HF not used water out 79 STEAM-HF water for gasification out

pump_wg LIQPUM_1 78 STEAM-HF water for gasification in

93 STEAM-HF water for gasification out

508 ELEC_POWER power consuption

HEATSOURCE_ENG HEATSRC0

990 STEAM-HF engine cooling water in

991 STEAM-HF engine cooling water out 500 HEAT engine cooling heat

FEEDWATER_H_ENG HEATEX_1 991 STEAM-HF engine cooling water in

992 STEAM-HF engine cooling water out


57 STEAM feedwater out 309 HEAT heat

TW_PREH_ENG HEATEX_1




432 STEAM-HF tarwater out 312 HEAT heat

A_PREH_ENG HEATEX_1 993 STEAM-HF engine cooling water in


92 STANDARD_AIR gasification air in

91 STANDARD_AIR gasification air out 311 HEAT heat

W_PREH_ENG HEATEX_1 994 STEAM-HF engine cooling water in


93 STANDARD_AIR gasification water in

31 STANDARD_AIR gasification water out 310 HEAT heat

HEATSINK HEATSNK0



997 HEAT released heat

PUMP_ENG LIQPUM_1

996 STEAM-HF engine cooling water in 990 STEAM-HF engine cooling water out



A-10

IBGCC basic configuration. DNA code.

C IBGCC plant

C BASIC CONFIGURATION

C fuel moisture 45%

C HE_125 as last heat exchanger

C engine cooling heat only for feedwater preheating

TITLE Biomass gasification

C Wood_ notar composition

SOLID Wood_notar H .06 O .45 C .49 S .0 ASH .0

+ LHV 18200 CP 1.9 MOI 0.502

C Light Tar compositon

SOLID Tar_1 H .07 O .47 C .46 S .0 ASH .0

+ LHV 15980 CP 1.35 MOI 0

C Heavy Tar composition (plus particles)


+ LHV 30365 CP 1.35 MOI 0.0

MEDIA 1 Wood_notar 4 SyngasWet 80 Ash

C Gasifier

C Variable constitution parameter: Number of calculated gas components 8

C 1 : Inlet fuel

C 3 : inlet water

C 2 : inlet air

C 4 : outlet gas

C 5 : outlet ash

C 300: heat loss

C Integer Parameters: Calculated gas compounds H2 (1), N2 (3), CO (4),

C CO2 (6), H2O (7), H2S (9), CH4 (11), Ar (36)

C Real parameter: Pressure 1 bar, Eq. temperature 800 degC, Pressure ratio 1,

C Water-to-fuel ratio 0, carbon conversion factor 1,

C non-equilibrium methane.

STRUC Gasifier GASIFI_3 8 1 3 2 4 80 300 1 3 4 6 7 9 11 36 /

1 1525 0 0.12 0.995 0.6

ADDCO Q Gasifier 300 0

ADDCO P 1 1

ADDCO P 80 1

ADDCO M Gasifier 1 1.269

ADDCO T Gasifier 1 25


START M Gasifier 80 0.1

START Y_J SyngasWet H2 0.134 Y_J SyngasWet N2 0.226 Y_J SyngasWet CO 0.095

START Y_J SyngasWet CO2 0.086

START Y_J SyngasWet H2O-G 0.451 Y_J SyngasWet H2S 0

START Y_J SyngasWet AR 0 Y_J SyngasWet CH4 0.008

START X_J Ash C 0 X_J Ash ASH 1

C Gas cooling for separating water from the syngas

C 4 : Syngas_wet in

C 41 : Syngas_dry out

C 42 : Water out

C 60 : Cooling media, water in

C 61 : Cooling media, water out

C 301 : External heat

MEDIA 60 STEAM 41 Syngas

STRUC Cooler GASCOOL1 4 41 42 60 61 301 0.22 0

ADDCO T Cooler 41 43

ADDCO Q Cooler 301 0

ADDCO T Cooler 60 20 T Cooler 61 50 P 60 1

START M Cooler 41 -1.39 M Cooler 60 12

START M Cooler 42 -0.59

START Y_J Syngas H2 0.220 Y_J Syngas N2 0.372 Y_J Syngas CO 0.157

START Y_J Syngas CO2 0.138 Y_J Syngas H2O-G 0.096 Y_J Syngas NH3 0

START Y_J Syngas H2S 0 Y_J Syngas CH4 0.013 Y_J Syngas AR 0

C Booster for overcoming pressure drop

C 41 : Syngas in

C 43 : Syngas out

C 370: heat

C 470: power


A-11

STRUC Booster compre_1 41 43 370 470 1 1

ADDCO P 43 1

START T Booster 43 60

START W Booster 470 18

C splitter: the syngas flow may be spitted

C 43: syngas in

C 44: syngas out to the furnace

C 45: syngas out to the engine

STRUC split splitter 43 44 45

ADDCO m split 45 -0.001

START t split 44 35

C Engine

C 22 : air

C 44 : syngas

C 32 : flue gas

C 400: power production

C 303: heat loss

C 500: Heat production, engine cooling

C Parameter 1: Pressure ratio

C Parameter 2: lambda

C Parameter 3: elctrical efficiency

C Parameter 4: heat efficiency

C Parameter 5: loss coefficient / efficiency

STRUC ENGINE ENGINE_1 22 44 32 400 303 500 1 2 0.40 0.188 0.134

VARPA ENGINE 2 T ENGINE 32 401

MEDIA 22 STANDARD_AIR 32 Flue_Engine

ADDCO T ENGINE 22 25

START M ENGINE 22 5

START P 22 1

START Y_J Flue_Engine O2 .115 Y_J Flue_Engine N2 .717

START Y_J Flue_Engine H2O-G 0.084

START Y_J Flue_Engine CO2 0.076

START P 32 1

START E ENGINE 400 -2700

START Q ENGINE 500 -1100

C ******************************************************

C Furnace

C ******************************************************

C Utility component to convert real steam to ideal gas

C 434 : steam-hf

C 435 : ideal gas

struc conv sthf2h2og 434 435

MEDIA 435 STEAM_IG

C Mixer steam and flue gas from engine

C 435: steam in

C 32 : flue gas from the engine in

C 33 : mix

STRUC Mixer mixer_01 435 32 33

MEDIA 33 MIX

START Y_J MIX CO2 .093 Y_J MIX N2 .708

START Y_J MIX H2O-G 0.096 Y_J MIX 02 0.094

START Y_J MIX AR 0.009

C Burner1: syngas

C 33 : mixture of flue gas from the engine and steam

C 45 : syngas from the splitter

C 7 : flue gas out

C 306: heat

STRUC Burner_1 GASBUR_2 33 45 7 306 800 1

MEDIA 7 Flue_Burner_1

VARPA Burner_1 1 Q Burner_1 306 0

start y_j Flue_Burner_1 O2 0.1 y_j Flue_Burner_1 N2 0.9

START T Burner_1 7 420

START M Burner_1 7 -7

C Burner2: light_tar

C 7 : flue gas in

C 6 : light tar in

C 71 : flue gas out

C 81 : ash


A-12

C 304: heat


STRUC Burner_2 SOLBUR_4 7 6 71 81 304 6 1


START Y_J Flue_Burner_2 CO2 .093 Y_J Flue_Burner_2 N2 .708

START Y_J Flue_Burner_2 H2O-G 0.096 Y_J Flue_Burner_2 02 0.094

START Y_J Flue_Burner_2 AR 0.009



ADDCO T Burner_2 6 35

ADDCO M Burner_2 6 0.0888

START M Burner_2 81 0


MEDIA 6 Tar_1

MEDIA 81 ASH_1

START X_J ASH_1 ASH 1

C Burner3: heavy tar

C 71 : flue gas in

C 16 : heavy tar in

C 72 : flue gas out

C 82 : ash

C 305: heat













MEDIA 16 Tar_2

MEDIA 82 ASH_2


C ******************************************************

C HRSG

C ******************************************************

C ECONOMIZER

C 732: flue gas in (coming from evaporator)

C 73 : flue gas out

C 50 : water in 93°C

C 511: water out

C 340: heat

MEDIA 50 STEAM

STRUC ECO heatex_1 732 73 50 511 340 0 1

ADDCO Q ECO 340 0

START T ECO 73 307.75

C EVAPORATOR

C 731: flue gas in (coming from superheater)

C 732: flue gas out

C 511: saturated water in

C 512: saturated steam out

C 341: heat

STRUC EVA heatex_1 731 732 511 512 341 0 0

ADDCO Q EVA 341 0

ADDCO X EVA 511 0.00001

ADDCO X EVA 512 0.99999

START T EVA 512 250

START T EVA 732 400

C SUPERHEATER

C 72 : flue gas in (coming from furnace)

C 731: flue gas out

C 512: saturated steam in

C 51 : superheated steam out

C 342: heat

STRUC SH heatex_1 72 731 512 51 342 0 0

ADDCO Q SH 342 0

ADDCO T SH 51 450

START M SH 512 1.23

START T SH 731 610


A-13

C Steam turbine

C 51 : Steam in (from superheater)

C 54 : Saturated water-steam out

C 401: power

STRUC Turbine TURBIN_1 51 54 401 0.85

ADDCO P 54 0.1

START T Turbine 54 45.8

START W Turbine 401 -1250

C generator

C 499 : electrical power out

C 399 : dissipated heat

C 401 : mechanical power in

struc generator sim_gene 499 399 401 0.98

START Q generator 399 -30

C condenser

C 54 : saturated water-steam in

C 55 : water out

C 308: released heat

STRUC Cond STECON_0 54 55 308 0

start X Cond 54 0.86

start Q Cond 308 -2600

start T Cond 55 45.8

C LP_pump

C 55 : water in

C 56 : pressurized water out

C 411: heat

STRUC LP_Pump LIQPUM_1 55 56 411 0.9

ADDCO P 56 1.1

START E LP_Pump 411 20

C HP_pump

C 57 : water in


C 412: heat

STRUC HP_Pump LIQPUM_1 57 50 412 0.9

ADDCO P 50 46

START E HP_Pump 412 20

C ***********************************************************************

C Secondary heat exchagers. Configuration 1.

C ***********************************************************************

C gasification air preheating 2

C 912 : air in

C 2 : air out 150°C

C 73 : flue gas in

C 74 : flue gas out

C 339 : heat=0

STRUC PRE_H_A2 heatex_1 73 74 912 2 339 0 0

ADDCO T PRE_H_A2 2 150

ADDCO Q PRE_H_A2 339 0

START T PRE_H_A2 74 304


C 91 : air in


C 74 : flue gas in

C 752 : flue gas out

C 369 : heat=0


ADDCO T PRE_H_A1 912 98.95


START T PRE_H_A1 752 103.25

C gasification water preheating 3: superheating

C 752 : flue gas in


C 343 : steam in

C 3 : steam out 150°C

C 329 : heat=0

STRUC PRE_H_W3 heatex_1 752 753 343 3 329 0 0


A-14

ADDCO T PRE_H_W3 3 150

ADDCO Q PRE_H_W3 329 0

START T PRE_H_W3 753 303

C gasification water preheating 2: evaporation

C 753 : flue gas in


C 344 : saturated water in

C 343 : saturated steam out

C 349 : heat=0


ADDCO X PRE_H_W2 343 1



C gasification water preheating 1: economizing

C 754 : flue gas in


C 31 : water in

C 344 : saturated water out

C 319 : heat=0




START T PRE_H_W1 755 103.95

C HE for 125°C for tarwater treatment

C 755 : flue gas in

C 75 : flue gas out

C 204 : closed loop water in at 106°C

C 203 : closed loop water out at 125°C

C 320 : heat

STRUC HE_125 heatex_1 755 75 204 203 320 0 0.001

ADDCO T HE_125 203 125

ADDCO T HE_125 204 105

ADDCO Q HE_125 320 0

ADDCO T HE_125 75 110

START T HE_125 755 303

START M HE_125 204 16.9

START T HE_125 203 125

C **********************************************************

C tarwater treatment

C **********************************************************

C Tarwater pump for overcoming pressure drop

C 42 : Tarwater in

C 431 : Tarwater out

C 403 : power

STRUC tw_pump LIQPUM_1 42 431 403 1

ADDCO P 431 1

start T tw_pump 431 45

C Tarwater heater



C 432 : water to be evaporated

C 433 : steam at 106°C

C 330 : heat

MEDIA 202 STEAM-HF

STRUC TW_heater heatex_1 203 202 432 433 330 0 0

ADDCO T TW_heater 433 106

ADDCO Q TW_heater 330 0

START T TW_heater 203 125

C Fan for steam

C 433 : steam in

C 434 : steam out

C 442 : heat

C 443 : power

STRUC tw_comp compre_1 433 434 442 443 1 1

START T tw_comp 434 107

START Q tw_comp 442 10

START W tw_comp 443 10

C Pump for Closed loop 125

C 202 : water in


A-15

C 204 : water out

C 506 : power

struc pump_125 liqpum_1 202 204 506 1

ADDCO P 204 3

C **********************************************************

C Flue gas treatment

C **********************************************************

C Gas cooling/Scrubber

C The gas is cooled in order to condensate the water before the cimney

C 75 : flue gas in

C 76 : flue gas out

C 77 : condensated water

C 62 : cooling water in

C 63 : cooling water out

C 331: heat

MEDIA 62 STEAM 76 Exaust

STRUC Cooler2 GASCOOL1 75 76 77 62 63 331 0.0 0

ADDCO T Cooler2 76 50

ADDCO Q Cooler2 331 0

ADDCO T Cooler2 62 10 T Cooler2 63 50 P 62 1

START M Cooler2 77 -0.5 M Cooler2 62 12

START Y_J Exaust CO2 .093 Y_J Exaust N2 .708

START Y_J Exaust H2O-G 0.096 Y_J Exaust 02 0.094

START Y_J Exaust AR 0.009

C Splitter

C part the condensate water is used in the gasifier

C 77: condensate water in

C 78: condensate water out to the gasifier

C 79: condensate water out, not used

STRUC split2 splitter 77 78 79

start t split2 78 50

C Pump for gasifier water

C 78 : water in

C 93 : water out

C 508 : power

STRUC pump_WG liqpum_1 78 93 508 1

C **********************************************************

C engine cooling water system

C **********************************************************

C Cooling heat source

C The cooling heat from the engine is used for generating a water stream

C between 98°C and 88°C

C 990 : cooling water at the engine inlet (88°C)

C 991 : cooling water at the engine outlet (98°C)

C 500 : cooling heat

struc heatsource_ENG heatsrc0 990 991 500 0.1

media 990 STEAM-HF

ADDCO P 990 1.6

START m heatsource_ENG 990 43.82

ADDCO T heatsource_ENG 990 88


C Feedwater preheater

C 56 : steam cycle water in

C 57 : steam cycle water out

C 991 : engine cooling water in

C 992 : engine cooling water out

C 309: heat (engine cooling)=0

STRUC FEEDW_H_ENG heatex_1 991 992 56 57 309 0.1 0

ADDCO Q FEEDW_H_ENG 309 0

ADDCO T FEEDW_H_ENG 57 93

START T FEEDW_H_ENG 56 96

START T FEEDW_H_ENG 992 98

C tarwater preheating using engine cooling

C 431 : tarwater in

C 432 : tarwater out 95°C




STRUC TW_PREH_ENG heatex_1 992 993 431 432 312 0.1 0


A-16

ADDCO Q TW_PREH_ENG 312 0

C NOT PRESENT IN THE BASIC CONFIGURATION

ADDCO T TW_PREH_ENG 432 43.01

START T TW_PREH_ENG 431 43

START M TW_PREH_ENG 431 0.61

START T TW_PREH_ENG 993 96

C air preheating for the gasifier using engine cooling

C 92 : air in 25°C

C 91 : air out

C 311 : heat external source=0



STRUC A_PREH_ENG heatex_1 993 994 92 91 311 0.1 0

ADDCO Q A_PREH_ENG 311 0


ADDCO T A_PREH_ENG 91 25.01

ADDCO T A_PREH_ENG 92 25

START T A_PREH_ENG 994 95.81

C water preheating for the gasifier using engine cooling


C 31 : water out




MEDIA 31 STEAM-HF 92 STANDARD_AIR

STRUC W_PREH_ENG heatex_1 994 995 93 31 310 0.1 0

ADDCO Q W_PREH_ENG 310 0


ADDCO T W_PREH_ENG 31 50.02

START T W_PREH_ENG 93 50


START M W_PREH_ENG 31 -0.14

C heat sink for the not used engine cooling heat

C 997 : released heat



STRUC HEATSINK heatsnk0 995 996 997 0.1

START T HEATSINK 996 88

START Q HEATSINK 997 -1400

C Engine cooling water Pump

C 996 : water in

C 990 : water out

C 507 : power

STRUC pump_ENG liqpum_1 996 990 507 1

START E pump_ENG 507 3

IBGCC optimized configuration

A-17

IBGCC optimized configuration

Simple steam cycle 140/0,06bar-550°C


Engine cooling heat used for feedwater heating, tarwater, air and water preheating.

Possibility of using natural gas in the engine and in the furnace


A-18

IBGCC optimized configuration. Flow sheet.

IBGCC optimized configuration. Nodes sheet.

A-19







300 HEAT heat

cooler GASCOOL1





301 HEAT heat

booster COMPRE_1

41 Syngas syngas in



split SPLITTER

49 Syngas syngas in

43 Syngas syngas out to the engine

44 Syngas syngas out to the furnace (bypass)

mixer_ng MIXER_01

43 Syngas syngas in 200 NATURAL_GAS natural gas in

201 GasMix gas mixture out

engine ENGINE_1


201 GasMix gas mixture in

32 Flue_Engine engine flue gas out 400 ELECT_POWER electrical power production

303 HEAT losses

500 HEAT engine cooling heat

conv STHF2H2OG

434 STEAM-HF steam from tarwater treatment real gas in


mixer MIXER_01

435 STEAM_(I.G.) steam from tarwater treatment ideal gas in 32 Flue_Engine engine flue gas in


burner_1 GASBUR_2

33 MIX gas mixture in

45 Syngas bypassing syngas in

7 Flue_Burner_1 flue gas out 306 HEAT heat

burner_2 SOLBUR_4 7 Flue_Burner_1 flue gas in

6 Tar_1 light tar in


81 ASH_1 ash 304 HEAT heat

burner_3 SOLBUR_4


16 Tar_2 heavy tar in

72 Flue_Burner_3 flue gas out 82 ASH_2 ash

305 HEAT heat

burner_4 GASBUR_2


244 NATURAL_GAS natural gas in


ECO HEATEX_1


A-20



50 STEAM feedwater in 511 STEAM saturated water out

340 HEAT heat

EVA HEATEX_1



511 STEAM saturated water in 512 STEAM saturated steam out

341 HEAT heat

SH HEATEX_1



512 STEAM saturated steam in 51 STEAM superheated steam out

342 HEAT heat

turbine TURBIN_1



401 MECH_POWER mechanical power production

generator SIM_GENE

499 ELECT_POWER electrical power production 399 HEAT heat loss


cond STECON_0


55 STEAM condensed water


LP_pump LIQPUM_1

55 STEAM water in 56 STEAM compressed water out


HP_pump LIQPUM_1

57 STEAM water in



PRE_H_A2 HEATEX_1



2 STANDARD_AIR air out

339 HEAT heat

PRE_H_A1 HEATEX_1




369 HEAT heat

PRE_H_W3 HEATEX_1



3 STAM superheated steam out

329 HEAT heat

PRE_H_W2 HEATEX_1



343 STAM saturated steam out 349 HEAT heat



31 STEAM water in

344 STEAM saturated water out 319 HEAT heat

HE_125 HEATEX_1


A-21




320 HEAT heat

tw_pump LIQPUM_1




tw_heater HEATEX_1




330 HEAT heat

tw_comp COMPRE_1 COMPRE_1

433 STEAM-HF steam in 434 STEAM-HF steam out

442 HEAT heat


pump_125 LIQPUM_1

202 STEAM-HF pressurized water in

204 STEAM-HF pressurized water out 506 ELEC_POWER power consumption

cooler2 GASCOOL1 75 Flue_Burner_4 flue gas in


77 STEAM-HF condensate water

62 STEAM cooling water in 63 STEAM cooling water out

331 HEAT heat

split2 SPLITTER


78 STEAM-HF not used water out


pump_wg LIQPUM_1

78 STEAM-HF water for gasification in 93 STEAM-HF water for gasification out






FEEDWATER_H_ENG HEATEX_1



57 STEAM feedwater out

309 HEAT heat

TW_PREH_ENG HEATEX_1




312 HEAT heat

A_PREH_ENG HEATEX_1


92 STANDARD_AIR gasification air in

91 STANDARD_AIR gasification air out 311 HEAT heat

W_PREH_ENG HEATEX_1 994 STEAM-HF engine cooling water in


93 STANDARD_AIR gasification water in

31 STANDARD_AIR gasification water out 310 HEAT heat

HEATSINK HEATSNK0


A-22




PUMP_ENG LIQPUM_1



IBGCC optimized configuration. DNA code.

A-23


C IBGCC plant

C fuel moisture 45%

C optimized simple cycle

C TiP=140bar TiT=550°C

C Condensation P=0.06bar

C Secondary heat exchanger configuration 3

C Possibility of using additional natural gas




+ LHV 18200 CP 1.9 MOI 0.502



+ LHV 15980 CP 1.35 MOI 0



+ LHV 30365 CP 1.35 MOI 0.0


C Gasifier


C 1 : Inlet fuel

C 3 : inlet water

C 2 : inlet air

C 4 : outlet gas

C 5 : outlet ash

C 300: heat loss


C CO2 (6), H2O (7), H2S (9), CH4 (11), Ar (36)





1 1525 0 0.12 0.995 0.6


ADDCO P 1 1

ADDCO P 80 1











C 4 : Syngas_wet in C 41 : Syngas_dry out

C 42 : Water out















A-24


C 41 : Syngas in

C 49 : Syngas out

C 370: heat

C 470: power


ADDCO P 49 1

start T Booster 49 60

start W Booster 470 18


C 49: syngas in





START t split 44 35

MEDIA 200 NATURAL_GAS

MEDIA 201 GasMix

C Mixing natural gas and syngas

C 43 : syngas in

C 200 : natural gas in

C 201 : gas mixture out

STRUC mixer_ng mixer_01 43 200 201

ADDCO T mixer_ng 200 25

START M mixer_ng 200 0.01

START T mixer_ng 201 65

START Y_J GasMix H2 0.220 Y_J GasMix N2 0.372 Y_J GasMix CO 0.157

START Y_J GasMix CO2 0.138 Y_J GasMix H2O-G 0.096 Y_J GasMix NH3 0

START Y_J GasMix H2S 0 Y_J GasMix CH4 0.013 Y_J GasMix AR 0

C Engine

C 22 : air

C 201 : syngas(+natural gas)

C 32 : flue gas


C 303: heat loss











ADDCO E ENGINE 400 -3945

START M ENGINE 22 5

START P 22 1




START P 32 1


C ******************************************************

C Furnace

C ******************************************************


C 434 : steam-hf

C 435 : ideal gas

struc con sthf2h2og 434 435

MEDIA 435 STEAM_IG


C 435: steam in


C 33 : mix


MEDIA 33 MIX



A-25



C Burner1: syngas



C 7 : flue gas out

C 306: heat







MEDIA 6 Tar_1

MEDIA 81 ASH_1


C 7 : flue gas from burner 1

C 6 : light tar in


C 81 : ash

C 304: heat














MEDIA 16 Tar_2

MEDIA 82 ASH_2



C 16 : light tar in


C 82 : ash

C 305: heat
















C Burner4: natural gas




C 356: heat





ADDCO P 244 1

START y_j Flue_Burner_4 O2 0.1 y_j Flue_Burner_4 N2 0.9

START M Burner_4 722 -7.33


C ******************************************************

C HRSG


A-26

C ******************************************************

C ECONOMIZER


C 73 : flue gas out


C 511: water out

C 340: heat

MEDIA 50 STEAM

STRUC ECO heatex_1 732 73 50 511 340 0 1

ADDCO Q ECO 340 0


C EVAPORATOR


C 732: flue gas out


C 512: satureted steam out

C 341: heat

STRUC EVA heatex_1 731 732 511 512 341 0 0

ADDCO Q EVA 341 0

ADDCO X EVA 511 0.00001

ADDCO X EVA 512 0.99999

START T EVA 512 250

START T EVA 732 400

C SUPERHEATER


C 731: flue gas out



C 342: heat

STRUC SH heatex_1 722 731 512 51 342 0 0

ADDCO Q SH 342 0

START M SH 512 1.23

ADDCO T SH 51 550

START T SH 731 610

C Steam turbine



C 401: power

STRUC Turbine TURBIN_1 51 54 401 0.85

ADDCO P 54 0.06

START T Turbine 54 45.8

START W Turbine 401 -1250

C generator




struc generator sim_gene 499 399 401 0.98

START Q generator 399 -30

C condenser


C 55 : water out






C LP_pump

C 55 : water in


C 411: heat



ADDCO P 56 1.1

C HP_pump

C 57 : water in


C 412: heat



ADDCO P 50 141


A-27

C ***********************************************************************


C ***********************************************************************


C 912 : air in


C 73 : flue gas in

C 74 : flue gas out

C 339 : heat=0






C 74 : flue gas in


C 343 : steam in


C 329 : heat=0






C 752 : flue gas in




C 320 : heat

STRUC HE_125 heatex_1 752 753 204 203 320 0 0.001

ADDCO T HE_125 203 125

ADDCO T HE_125 204 105


START T HE_125 753 145

START T HE_125 752 303

START M HE_125 204 16.9

START T HE_125 203 125


C 753 : flue gas in




C 349 : heat=0






C 754 : flue gas in


C 31 : water in


C 319 : heat=0




ADDCO T PRE_H_W1 755 103.95


C 91 : air in


C 755 : flue gas in

C 75 : flue gas out

C 369 : heat=0





C **********************************************************



A-28

C **********************************************************


C 42 : Tarwater in


C 403 : power


ADDCO P 431 1


C Tarwater heater





C 330 : heat

MEDIA 202 STEAM-HF





C Fan for steam

C 433 : steam in

C 434 : steam out

C 442 : heat

C 443 : power






C 202 : water in

C 204 : water out

C 506 : power


ADDCO P 204 3

C **********************************************************


C **********************************************************



C 75 : flue gas in

C 76 : flue gas out




C 331: heat










C Splitter








C 78 : water in

C 93 : water out

C 508 : power


C **********************************************************


A-29


C **********************************************************








media 990 STEAM-HF

ADDCO P 990 1.6










STRUC FEEDWATER_H_ENG heatex_1 991 992 56 57 309 0.1 0

ADDCO Q FEEDWATER_H_ENG 309 0

ADDCO T FEEDWATER_H_ENG 57 93

START T FEEDWATER_H_ENG 56 50



C 431 : tarwater in





STRUC F_PREH_ENG heatex_1 992 993 431 432 312 0.1 0

ADDCO Q F_PREH_ENG 312 0

ADDCO T F_PREH_ENG 432 91.37

START T F_PREH_ENG 431 43

START M F_PREH_ENG 431 0.61



C 92 : air in 25°C

C 91 : air out











C 31 : water out









START T W_PREH_ENG 995 95.45










C 996 : water in


A-30

C 990 : water out

C 507 : power



C NG=25%

simul





C NG=50%

simul





C NG=75%

simul





C NG=+10%

simul






IBGCC optimized configuration with reheating

A-31

IBGCC optimized configuration with reheating

Reheating steam cycle 140/0,06bar-550°C, reheating T=550°C


Engine cooling heat used for feedwater heating, tarwater, air and water preheating.

Possibility of using natural gas in the engine and in the furnace


A-32

IBGCC optimized configuration with reheating. Flow sheet.

IBGCC optimized configuration with reheating. Nodes sheet.

A-33







300 HEAT heat

cooler GASCOOL1





301 HEAT heat

booster COMPRE_1

41 Syngas syngas in



split SPLITTER

49 Syngas syngas in

43 Syngas syngas out to the engine

44 Syngas syngas out to the furnace (bypass)

mixer_ng MIXER_01

43 Syngas syngas in 200 NATURAL_GAS natural gas in

201 GasMix gas mixture out

engine ENGINE_1


201 GasMix gas mixture in

32 Flue_Engine engine flue gas out 400 ELECT_POWER electrical power production

303 HEAT losses


conv STHF2H2OG

434 STEAM-HF steam from tarwater treatment real gas in


mixer MIXER_01

435 STEAM_(I.G.) steam from tarwater treatment ideal gas in 32 Flue_Engine engine flue gas in


burner_1 GASBUR_2

33 MIX gas mixture in

45 Syngas bypassing syngas in


burner_2 SOLBUR_4 7 Flue_Burner_1 flue gas in

6 Tar_1 light tar in


81 ASH_1 ash 304 HEAT heat

burner_3 SOLBUR_4


16 Tar_2 heavy tar in

72 Flue_Burner_3 flue gas out 82 ASH_2 ash

305 HEAT heat

burner_4 GASBUR_2


244 NATURAL_GAS natural gas in


ECO HEATEX_1


A-34



50 STEAM feedwater in 511 STEAM saturated water out

340 HEAT heat

EVA HEATEX_1



511 STEAM saturated water in 512 STEAM saturated steam out

341 HEAT heat

SH HEATEX_1




342 HEAT heat

HP_turbine TURBIN_3




generator1 SIM_GENE



SH2 HEATEX_1




362 HEAT heat

LP_turbine TURBIN_3




generator2 SIM_GENE



cond STECON_0


55 STEAM condensed water


LP_pump LIQPUM_1

55 STEAM water in 56 STEAM compressed water out


HP_pump LIQPUM_1

57 STEAM water in



PRE_H_A2 HEATEX_1




339 HEAT heat








3 STAM superheated steam out


A-35

329 HEAT heat

PRE_H_W2 HEATEX_1



344 STEAM saturated water in 343 STAM saturated steam out

349 HEAT heat

PRE_H_W1 HEATEX_1



31 STEAM water in 344 STEAM saturated water out

319 HEAT heat

HE_125 HEATEX_1




320 HEAT heat

tw_pump




tw_heater HEATEX_1




330 HEAT heat

tw_comp COMPRE_1 COMPRE_1

433 STEAM-HF steam in 434 STEAM-HF steam out

442 HEAT heat


pump_125 LIQPUM_1

202 STEAM-HF pressurized water in

204 STEAM-HF pressurized water out 506 ELEC_POWER power consumption

cooler2 GASCOOL1 75 Flue_Burner_4 flue gas in


77 STEAM-HF condensate water

62 STEAM cooling water in 63 STEAM cooling water out

331 HEAT heat

split2 SPLITTER


78 STEAM-HF not used water out


pump_wg LIQPUM_1

78 STEAM-HF water for gasification in 93 STEAM-HF water for gasification out






FEEDWATER_H_ENG HEATEX_1 991 STEAM-HF engine cooling water in



57 STEAM feedwater out 309 HEAT heat

TW_PREH_ENG HEATEX_1 992 STEAM-HF engine cooling water in





A-36

312 HEAT heat

A_PREH_ENG HEATEX_1



92 STANDARD_AIR gasification air in 91 STANDARD_AIR gasification air out

311 HEAT heat

W_PREH_ENG HEATEX_1



93 STANDARD_AIR gasification water in 31 STANDARD_AIR gasification water out

310 HEAT heat

HEATSINK HEATSNK0




PUMP_ENG LIQPUM_1



IBGCC optimized configuration with reheating. DNA code.

A-37


C IBGCC plant

C fuel moisture 45%

C optimized reheating cycle

C TiP=140bar TiT=550°C T_reheating

C Condensation P=0.06bar

C Secondary heat exchanger configuration 3

C Possibility of using additional natural gas




+ LHV 18200 CP 1.9 MOI 0.502



+ LHV 15980 CP 1.35 MOI 0



+ LHV 30365 CP 1.35 MOI 0.0


C Gasifier


C 1 : Inlet fuel

C 3 : inlet water

C 2 : inlet air

C 4 : outlet gas

C 5 : outlet ash

C 300: heat loss



A-38

C CO2 (6), H2O (7), H2S (9), CH4 (11), Ar (36)





1 1525 0 0.12 0.995 0.6


ADDCO P 1 1

ADDCO P 80 1











C 4 : Syngas_wet in

C 41 : Syngas_dry out

C 42 : Water out














A-39



C 41 : Syngas in

C 49 : Syngas out

C 370: heat

C 470: power


ADDCO P 49 1

start T Booster 49 60

start W Booster 470 18


C 49: syngas in





START t split 44 35


MEDIA 201 GasMix

C Mixing natural gas and syngas

C 43 : syngas in


C 201 : gas mixture out

STRUC mixer_ng mixer_01 43 200 201

ADDCO T mixer_ng 200 25

START M mixer_ng 200 0.01

START T mixer_ng 201 65

START Y_J GasMix H2 0.220 Y_J GasMix N2 0.372 Y_J GasMix CO 0.157

START Y_J GasMix CO2 0.138 Y_J GasMix H2O-G 0.096 Y_J GasMix NH3 0

START Y_J GasMix H2S 0 Y_J GasMix CH4 0.013 Y_J GasMix AR 0


A-40

C Engine

C 22 : air

C 201 : syngas(+natural gas)

C 32 : flue gas


C 303: heat loss












START M ENGINE 22 5

START P 22 1




START P 32 1


C ******************************************************

C Furnace

C ******************************************************


C 434 : steam-hf

C 435 : ideal gas

struc con sthf2h2og 434 435

MEDIA 435 STEAM_IG


A-41


C 435: steam in


C 33 : mix


MEDIA 33 MIX




C Burner1: syngas



C 7 : flue gas out

C 306: heat







MEDIA 6 Tar_1

MEDIA 81 ASH_1



C 6 : light tar in


C 81 : ash

C 304: heat





A-42











MEDIA 16 Tar_2

MEDIA 82 ASH_2



C 16 : light tar in


C 82 : ash

C 305: heat

















A-43

C Burner4: natural gas




C 356: heat





ADDCO P 244 1

START y_j Flue_Burner_4 O2 0.1 y_j Flue_Burner_4 N2 0.9

START M Burner_4 725 -7.33


C ******************************************************

C HRSG

C ******************************************************

C ECONOMIZER


C 73 : flue gas out


C 511: water out

C 340: heat

MEDIA 50 STEAM

STRUC ECO heatex_1 732 73 50 511 340 0 1

ADDCO Q ECO 340 0


START M ECO 50 1.2

C EVAPORATOR


C 732: flue gas out


C 512: satureted steam out

C 341: heat


A-44

STRUC EVA heatex_1 731 732 511 512 341 0 0

ADDCO Q EVA 341 0

ADDCO X EVA 511 0.00001

ADDCO X EVA 512 0.99999

START T EVA 512 250

START T EVA 732 400

C SUPERHEATER


C 731: flue gas out



C 342: heat

STRUC SH heatex_1 722 731 512 51 342 0 0

ADDCO Q SH 342 0

ADDCO T SH 51 550

C Steam turbine HP stage


C 541 : Steam out

C 401: power

STRUC HP_Turbine TURBIN_3 51 541 401 0.784 100

ADDCO P 541 18

START T HP_Turbine 541 300

START W HP_Turbine 401 -700

C HP generator




struc generator1 sim_gene 499 399 401 0.98

start Q generator1 399 -100

C Reheating

C 725 : flue gas in


A-45


C 541 : steam in

C 542 : steam out

C 363 : heat=0

STRUC SH2 heatex_1 725 722 541 542 362 0 0

ADDCO Q SH2 362 0

ADDCO T SH2 542 550

C Steam turbine LP stage

C 542 : Steam in


C 411: power

STRUC LP_Turbine TURBIN_3 542 54 411 0.784 100

ADDCO P 54 0.06

START T LP_Turbine 54 60

START W LP_Turbine 411 -700

C LP generator




struc generator2 sim_gene 498 398 411 0.98

start Q generator2 398 -100

C condenser


C 55 : water out






C LP pump


A-46

C 55 : water in


C 421: heat


ADDCO P 56 1.1


C HP pump

C 57 : water in


C 422: heat


ADDCO P 50 141


C ***********************************************************************


C ***********************************************************************


C 912 : air in


C 73 : flue gas in

C 74 : flue gas out

C 339 : heat=0






C 74 : flue gas in


C 343 : steam in


A-47


C 329 : heat=0






C 752 : flue gas in




C 320 : heat

STRUC HE_125 heatex_1 752 753 204 203 320 0 0.001

ADDCO T HE_125 203 125

ADDCO T HE_125 204 105


START T HE_125 753 145

START T HE_125 752 303

START M HE_125 204 16.9

START T HE_125 203 125


C 753 : flue gas in




C 349 : heat=0






C 754 : flue gas in


A-48


C 31 : water in


C 319 : heat=0




ADDCO T PRE_H_W1 755 103.95


C 91 : air in


C 755 : flue gas in

C 75 : flue gas out

C 369 : heat=0





C **********************************************************


C **********************************************************


C 42 : Tarwater in


C 403 : power


ADDCO P 431 1


C Tarwater heater




A-49



C 330 : heat

MEDIA 202 STEAM-HF





C Fan for steam

C 433 : steam in

C 434 : steam out

C 442 : heat

C 443 : power






C 202 : water in

C 204 : water out

C 506 : power


ADDCO P 204 3

C **********************************************************


C **********************************************************



C 75 : flue gas in

C 76 : flue gas out



A-50



C 331: heat










C Splitter








C 78 : water in

C 93 : water out

C 508 : power


C **********************************************************


C **********************************************************





A-51





media 990 STEAM-HF

ADDCO P 990 1.6










STRUC FEEDWATER_H_ENG heatex_1 991 992 56 57 309 0.1 0

ADDCO Q FEEDWATER_H_ENG 309 0

ADDCO T FEEDWATER_H_ENG 57 93




C 431 : tarwater in





STRUC F_PREH_ENG heatex_1 992 993 431 432 312 0.1 0

ADDCO Q F_PREH_ENG 312 0

ADDCO T F_PREH_ENG 432 91.37


START M F_PREH_ENG 431 0.61



A-52


C 92 : air in 25°C

C 91 : air out











C 31 : water out









START T W_PREH_ENG 995 95.45











A-53

C 996 : water in

C 990 : water out

C 507 : power



C **********************************************************

C NATURAL GAS SIMULATIONS

C NG=25%

C simul

C ADDCO M Burner_4 244 0.0088

C ADDCO M Gasifier 1 0.95175



C NG=50%

C simul





C NG=75%

C simul


C ADDCO T PRE_H_W1 755 124.5




C NG=additional +10%

C simul




A-54



C ADDCO E ENGINE 400 -4340

Modeling and Optimization of Biomass Gasification Systems

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Transcript of Modeling and Optimization of Biomass Gasification Systems