formazione e controllo di inquinanti nella combustione...

Formazione e Controllo di Inquinanti nella Combustione

Impianti di trattamento effluenti

Tecnologie di combustione e

Corso di Laurea Magistrale in Ingegneria Chimica/

Ingegneria Energetica

Tecnologie di combustione e gassificazione di combustibili

solidi

Prof. L.Tognotti / Ing. E. BiaginiDipartimento di Ingegneria Civile e Industriale

Anno Accademico 2014-2015

Combustion and gasificationtechnologies (solid fuels)

• Combustion

– pulverized coal firing systems

– fixed bed combustors (grates)

– fluidized bed systems

• Co-combustion

• Pyrolysis

• Gasification

Combustion of solid fuels

• Transformation of the chemical energy contained in the fuel

into heat (main product) through a complex combination of

chemical reactions and physical phenomena. Further products:

gaseous emissions and solid residues (bottom and fly ash).

• Combustor / boiler:• Combustor / boiler:

PLANT SIZE

FUEL SIZE

THERMAL SEVERITY (HR)

0.5 MW 10 MW 100 MW 250 MW 1000 MW

fixed moving

fluidizedfluidized bedsbeds

circulatingbubbling pulverized

fixedfixed bedsbeds / / gratesgrates entrainedentrained bedsbeds

10 cm 1 cm 1 mm 100 µm 10 µm

10°C/s 102 °C/s 103 °C/s 104 °C/s 105 °C/s1°C/s

• Combustor / boiler:

According to the air velocity,

the bed material has different

stages of fluidization:

Combustion of solid fuels – PF systems

• Pulverized coal fired power plant:

Fuel supplyand preparation(milling, drying)

Fuel

Flue gas

FurnaceSteam generation

Gas cleanup

TurbinePower generation

Condenser

Air

Flue gas

Solid residues

Rejected heatPower

Combustion of solid

fuels – PF systems

• Pulverized coal fired

power plant:


• Pulverized coal fired power plant. Reference data (Spliethoff 2010)

Gross (Net) rated power 740 (690) MW

Efficiency 39%

Capacity 2250 t/hCapacity 2250 t/h

Auxiliary power requirement 50 MW

Mechanical capacity of feed pump 21 MW

Air ratio 1.3

Live steam condition 209 bar, 535°C

Steam generator efficiency 94%

Exhaust steam pressure 0.055 bar



Different dispositions of

burners for optimizing

temperature fields and

Cross sectional area heat

release rate (MW/m2)

5-6.5 for oil, natural gas

4-5 for hard coal

3-4 for brown coal

Air is used to dry the

coal, transport it

through the

pulverizer, classify it,

and transport it to the

burner. Pneumatic

transport

10-20 m/s

temperature fields and

residence time Volumetric heat release rate

(kW/m3)

220-230 for oil, natural gas

140-160 for hard coal

100-120 for brown coal

Coal particles 10-100 µm

Typical residence time in

the furnace 2-5 s


• Pulverized coal fired power plant. Effect of moisture in coal on

pulverizer capacity (Perry’s):


Fluidynamics and thermal field are mainly

determined by burners configuration and

secondary air velocity.

foulingslagging


• The purpose of the burner is to produce an adequate flow pattern for

mixing and stable combustion. The injection has impact on the near-

burner area, i.e. on ignition and pollutant formation.

• A substantial fraction of the ignition energy has to be provided by

recirculation of hot flue gas. The ignition can be enhanced by finer

milling and air preheating.milling and air preheating.

• Circular burners are widely used in horizontally fired furnaces and are

capable of firing pulverized coal, oil, and gas.

• Low-NOx burners are designed to delay and control the mixing of

coal and air in the main combustion zone. This combustion approach

can reduce NOx emissions from coal burning by 40 to 50 percent.

• Because of the reduced flame temperature and delayed mixing in a

low-NOx burner, unburned carbon emissions may increase in some

applications and for some coals.


Flow and temperature

fields

Tangential firing Opposed firing


• Pulverized coal fired power plant. Design issues:

- specification of the design fuel and range of fuels fired;

- planned operated regimes (base, mid-range and peak loads);

- legislative directives (e.g. emission limits);- legislative directives (e.g. emission limits);

- efficiency (process complexity, materials, costs);

- instrumentation and control equipment;

- planned lifetime (200’000 h of operation).


• Pulverized coal fired power plant. Investment costs:

7%

6%Steam generator, gas cleanup

37%

21%

15%

14%

7%

6% cleanup

Turbine, steam cycle

Instrumentation and control

Civil works

Project costs

Mechanical constructions


• Pulverized coal fired furnace. Design aims:

- stable ignition (furnace section from free expansion of the flame);

- complete burnout (furnace height from char particle residence time);

- prevention of slagging and corrosion inside the furnace (coals with

high slagging tendency will require a larger cross section; it depends

also on the furnace exit temperature FET):

0

20

40

60

80

0 400 800 1200 1600Fu

rna

ce

he

igh

t(m

)

Fuel input (MW)

Burnout limit

FET 1100°C

FET 1230°C


• Pulverized coal fired furnace. Fouling and slagging zones:


• Pulverized coal fired furnace. Prevention of fouling and corrosion on

convective heating surfaces:

Presence of Na / K in coal ash and SO3 / HCl in flue gas promotes deposition and

corrosion of the heating surface (formation of alkali sulfates in molten phase

at 600-700°C). Presence (or addition) of Ca / Mg in the fuel reduces corrosion.at 600-700°C). Presence (or addition) of Ca / Mg in the fuel reduces corrosion.

For coals with high slagging tendency, large spacings of steam tubes are chosen.

Depending on the hardness of the deposits and considering the thermal shock of

the boiler material, removal by blowing is possible, using steam, water or air.

Slagging and fouling indexes:

• viscosity temperature (from ash fusion test) problems for T250poise < 1400°C

• basic/acid index B/A=(Fe2O3+CaO+MgO+Na2O+K2O)/(SiO2+Al2O3+TiO2)

problems for B/A > 0.5

• slagging index RS = B/A * S (S sulfur) problems for RS > 0.6


Cyclone furnaces

• In cyclone firing the coal is not pulverized but is crushed to 4-mesh

(4.76-mm) size and admitted tangentially with primary air to a

horizontal cylindrical chamber, called a cyclone furnace, which is

connected peripherally to a boiler furnace.

• Secondary air is admitted tangentially , so that almost all of the coal

burns within the chamber. The combustion gas then flows into theburns within the chamber. The combustion gas then flows into the

boiler furnace.

• In the cyclone furnace, finer coal particles burn in suspension and the

coarser ones are thrown centrifugally to the chamber wall, where

most of them are captured in a sticky wall coating of molten slag. The

slag drains continuously into the boiler furnace and thence into a

quenching tank.

• A typical firing rate is about 18.6 GJ/(h×m3).


Cyclone furnaces

• Cyclone burners and furnace


Biomass furnaces

• Biomass combustion is mainly used for heat production in small

/ medium scale units such as wood stoves, log wood boilers,

pellet burners, wood chip furnaces, straw-fired furnaces.

• District heating systems are often in the size range from 0.5 to

5 MWth with some applications up to 50 MWth.5 MWth with some applications up to 50 MWth.

• CHP production with biomass is applied by:

– steam cycles (Rankine cycle) with steam turbines and steam engines,

– organic Rankine cycles (ORC) with power outputs of 0.5 - 10 Mwe,

– Stirling engines (10 kWe to 100 kWe) and EFMGT systems.

• Co-firing in fossil-fired power stations enables the advantages

of large size plants (>100 MWe), which are not applicable for

dedicated biomass combustion due to limited local biomass

availability.


Biomass furnaces

• Grate furnaces are the most

common systems for small

scale applications;

• The grate can be fixed

(inclined) or moving. Primary

air is used to burn the biomassair is used to burn the biomass

and cool the metal of the

grate.

• Grate furnaces can also be

applied for high ash and water

content. Beside conventional

grate furnaces operated with

whole bales, cigar burners and

other specific furnaces are in

operation.


Biomass furnaces


Biomass furnaces

• Efforts in the area of grate-firing of biomass:

• Pollutant emissions: The incomplete combustion gives rise to higher

emissions of CO, hydrocarbons (CxHy), tar, poly aromatic hydrocarbons

(PAH) and incompletely burned char from biomass combustion in grate-

fired boilers. Concerns for high Cl and N content of some biomass.

• Deposit formation and corrosion: Grate-firing of some biomass fuels with a• Deposit formation and corrosion: Grate-firing of some biomass fuels with a

high Cl content (e.g. straw) and alkali compounds may suffer from severe

deposition and corrosion problems. Deposits reduce both the heat transfer

ability of combustor surfaces and the overall process efficiency, while

corrosion reduces the lifetime of the equipment. Deposition and corrosion

depend not only on fuel properties but also on combustion environments

(e.g., atmosphere, temperatures, and mixing).

• Experimental and modelling studies: experimental investigation provides

combustion related data for model validation. Modelling of biomass

conversion in the fuel bed should be coupled with computational fluid

dynamics (CFD) simulations, for modellig the mixing, combustion, and

pollutant formation.


Biomass furnaces

• Grate furnaces : schematization of phenomena occurring during the combustion

of biomass.

Yin et al. PECS 2008


Biomass furnaces

• Grate furnaces : schematization of phenomena occurring during the combustion

of biomass. The knowledge of the phenomena in the fuel bed is important for

optimizing the gas-phase combustion above the bed.

fuel inlet

fuel inlet


Biomass furnaces

• Grate furnaces: schematization of phenomena occurring during the

combustion of biomass. The releases of volatiles affects the heat output

from the grate area and the stability of combustion. The flame propagation

also plays an important role in the release of NOx precursors, particulate

matter formation precursors, and other pollutant formation precursors.


Biomass furnaces

• Grate furnaces : schematization of phenomena occurring during the

combustion of biomass. Combustion of volatiles in the chamber.


Biomass furnaces

• Grate furnaces : Deposits on superheater in upper furnace during firing

straw at Masnedø CHP plant. (Yin et al. PECS 2008)


Biomass furnaces

• Ash behaviour.


Biomass furnaces

• Mechanisms that control deposition and maturation of ash deposits

TUBE


Biomass furnaces

• Relationship between the deposit viscosity and the deposit strength. Cases

are ordered in the sequence of decreasing viscosity


Biomass furnaces

• the major factor influencing the

thermal conductivity of an ash deposit

is the structure, i.e. if the deposit is

particulate, sintered or fused


Biomass furnaces

• Grate furnaces : Mechanisms of deposit formation and corrosion of tubes.

The volatile alkali inorganic vapours and fine particles may contribute to

the initial deposit formation while the inert non-volatile ash particles

contribute to the build-up of the deposit.


Biomass furnaces

• Possible solutions to the problems of deposition and high temperature

corrosion during biomass combustion:

Use of additives, to raise the melting temperatures of the ash formed

during biomass combustion, or to prevent the release of gaseous KCl, or

react with KCl to form less corrosive components, or to combine thereact with KCl to form less corrosive components, or to combine the

effects. Examples: Al2O3, CaO, MgO, CaCO3 MgCO3 and kaolin. Also

aqueous solution of ammonium sulphate sprayed in the combustion zone.

Cofiring with coal, peat or sludge.

Use of new alloys or new forms of ceramic composite coating (for

mitigating corrosion).

Reduction of surface temperatures of super-heaters.


Biomass furnaces

• Cigar burner for bales (straws from agricultural residues). A piston

pushes the bale inside a feeding tunnel, in which the biomass

devolatilizes. The oxidation of the charrified material in the combustion

chamber occurs at 900°C (to avoid deposition of low melting ash).


Biomass furnaces

• Underfeed rotating grates. The grate is coned shaped. The rotation

increase the mix of the biomass. Primary air is fed just above the

biomass bed.


Biomass furnaces

• To achieve complete burnout and high efficiencies in small scale combustion,

downdraft boilers with inverse flow have been introduced.


Biomass furnaces

• Understoker furnaces are

mostly used for wood

chips and similar fuel with

relatively low ash content.

Special types of furnaces

have been developed forhave been developed for

straw that has very low

density and is usually

stored in bales.


Biomass furnaces

• ORC Organic Rankine Cycle is based on a closed Rankine cycle performed

adopting a suitable organic fluid (e.g. silicon oil) as working fluid. Note that at

small scales, the classic water Rankine Cycle becomes inefficient and

expensive owing to the high temperatures and pressures required.

(da Turboden)


Biomass furnaces

• ORC cycle: energy balance.


Biomass furnaces

• EFMGT (Externally Fired Micro Gas Turbine) cycle is based on a Brayton

cycle. The combustion air is used as working fluid.


Biomass furnaces

Main application: decentralized heat and power generation (0.1-1 MW)

ORC cycle (PROS)

• low mechanical stress and high turbine

efficiency;

• long operational life (no erosion/corrosion);

• no water treatment system required;

EFMGT cycle (PROS)

• completely automatic plant;

• versatility on feedstock;

• no auxiliary fuel need;

• no pressurized/dangerous fluids used;

Specific biomassconsumption

(kg/kWhe)

Electricalefficiency

(%)

Heat topowerratio

Available HeatTemperature

(°C)

Specific cost(€/kWe)

ORC 2.5-3.5 11-13 5:1 40-80 5-7’000

EFMGT 2.5-4 9-12 3:1 40-80 7-8’000

RSE (Steam engine) 4-5 8-9 6:1 100-150 5-6’000

SE (Stirling) 3.5-4 8-10 5:1 60-85 6-8’000

Gasification ICE 1.2-1.7 25 1.5-2:1 70-80 / 500 4-5’000

• no water treatment system required;

• good partial load performance .

• no pressurized/dangerous fluids used;

Fluidized beds

According to the air velocity, the bed material has different stages of fluidization:

Fluidized beds

• A fixed or packed bed refers to a bed of stationary particles residing on a

perforated grid, through which a gas flows. The gas exerts a drag force on

the particles, causing a pressure drop across the bed. The pressure drop per

unit height of a packed bed, ∆P/L, of uniformly sized particles, dp is

correlated as (Kozeny-Carman, 1927-37):

where, ε is the void fraction in the bed, φ is the sphericity of bed solids, µ is the

dynamic viscosity, and ρg is the density of the gas. The superficial gas

velocity, U is defined as the gas flow rate per unit cross section of the bed.

180180

Fluidized beds

• If the gas-flow rate through the fixed bed is increased, the pressure drop due

to the fluid drag continues to rise, until the superficial gas velocity reaches a

critical value known as the minimum fluidization velocity, Umf. At the

velocity where the fluid drag is equal to a particle’s weight less its buoyancy,

the fixed bed transforms into an incipiently fluidized bed. Since the pressure

drop across the bed equals the weight of the bed, the fluid drag FD is writtendrop across the bed equals the weight of the bed, the fluid drag FD is written

as:

where A and L are the cross-sectional area and height of the bed, respectively.

The minimum fluid velocity at which the bed just becomes fluidized (Umf)

may be obtained by:

The values of the empirical constants C1 and C2 as taken from experiments are

27.2 and 0.0408, respectively (Grace, 1982).

Fluidized beds

According to the air velocity, the bed material has different stages of fluidization:

fixed bed fluid bed

Bed expansion (H bed

height, ε voidage)

Fluidized beds

• A fluidized bed demonstrates all the characteristics of a fluid.

• The static pressure at any height is approximately equal to the weight of the

bed solids per unit of cross-sectional area above that level.

• Particles are well mixed, and the bed maintains a nearly uniform

temperature throughout its body when heated.

Fluidized beds

Classification of solid powders according to Geldart:

cement

light dust

quartz sand

alumina

talc

flour

steel

large

particles

Fluidized beds


• GROUP A. These particles are typically in the range of 30 to 100 µm (for

ρ=2500 kg/m3). These particles fluidize well, but expand considerably after

exceeding the minimum fluidization velocity and before bubbles start

appearing. Many circulating fluidized bed systems use Group A particles.

• GROUP B. These particles are normally in the range of 100 to 500 µm (for• GROUP B. These particles are normally in the range of 100 to 500 µm (for

ρ=2500 kg/m3). They fluidize well, and bubbles appear as soon as the

minimum fluidization velocity is exceeded. The majority of the fluidized bed

boilers use this group of particles.

• GROUP C. These particles are very fine and are typically smaller than 30 µm

(for ρ=2500 kg/m3). The interparticle forces are comparable to the

gravitational force on these particles. So, these particles are very difficult to

fluidize. An attempt at fluidization often results in channelling.

• GROUP D. These are the coarsest of all particles (>500 µm) (for ρ=2500

kg/m3). They require a high velocity to fluidize these solids. Spouted beds

and some bubbling fluidized bed boilers can operate on this size of solids.

Fluidized beds


Combustion of solid fuels – Fluidized beds

Classification of solids according to Geldart:

Fluidized beds

• For Group B and D particles, a further increase in gas flow besides the

minimum fluidization can cause the excess gas to flow in the form of

bubbles. The gas–solid suspension around the bubbles and elsewhere in the

bed is called the emulsion phase. The superficial gas velocity through this

phase is of the order of Umf and it has a characteristic voidage εmf.

• A fluidized bed of Group A particles does not start bubbling as soon as the• A fluidized bed of Group A particles does not start bubbling as soon as the

superficial velocity exceeds Umf, but instead the bed starts expanding. The

bubbles start appearing when the superficial gas velocity exceeds another

characteristic value called minimum bubbling velocity (Umb).

• Bubbles are essentially gas voids with little or no solids. Due to the buoyancy

force, bubbles would rise through the emulsion phase, by-passing the

particles. The bubble size increases with particle diameter, excess gas

velocity, (U - Umf), and with its distance above the distributor or grid of the

bed. The bubbles can coalesce and grow only to a maximum size, beyond

which they collapse.

Fluidized beds

• The bubbles erupt on the surface of a bubbling bed ejecting solids which

travel up through the freeboard. The solid concentration reduces along the

height but remains unchanged beyond the TDH.

Fluidized beds

• The air distribution grate supports the bed materials and homogeneously

distributes the fluidizing gas into the bed of solids.

• Nonuniform distribution of air may result in erosion, plugging, back-sifting, and

collapse of the bed due to agglomeration.

Fluidized beds

• The function of the air box is to distribute the air under the grid as uniformly

as possible.

Air plenum with side-entry air Flow-straightening vanes can help uniform

distribution of air in the plenum chamber

Fluidized beds

• A bubbling fluidized bed boiler would normally have an open space above its

bed surface, known as freeboard. Each bubble carries some solids upwards

in its wake. Bubbles erupt at the surface of the bed, throwing or entraining

particles into the freeboard above. Due to their momentum and local gas

drag, the entrained particles travel upwards through the freeboard.

• Since the fluid drag is not necessarily greater than the weight of all particles• Since the fluid drag is not necessarily greater than the weight of all particles

or groups of particles, some of the particles may disengage from the gas in

the freeboard, returning to the dense bed due to gravitational force. This

process of disengagement reduces the upward flux of particles exponentially

along the height of the freeboard.

• Beyond a certain height, only a negligible amount of particles disengage from

the gas to return to the dense bed. This height is known as transport

disengaging height (TDH). Beyond this height, only particles whose weight is

sufficiently small to be balanced by the fluid drag are carried up. More

specifically, particles with terminal velocities lower than the superficial

velocity in the freeboard are carried away (elutriation).

Fluidized beds

• An important consideration is to minimize the entrainment of unburnt

carbon by choosing a freeboard exceeding or close to the transport

disengaging height (TDH). Estimating TDH:

Fluidized beds

• Bubbles are likely to have a limited exchange of gas with the emulsion phase.

Burning fuel particles, requiring oxygen, generally reside in the emulsion

phase. In the absence of efficient gas exchange between the two phases,

there is major bypassing of oxygen.

• Some mixing of the oxygen from the bubble and emulsion phases occurs in

the splash zone immediately above the bed surface. Fine particles couldthe splash zone immediately above the bed surface. Fine particles could

receive the oxygen here and continue to burn in the freeboard.

• The amount of gas passing through the emulsion phase is equal to that

required for minimum fluidization, AUmf. Therefore, the remaining gas, A(U-

Umf) passes through the bubble phase. The equivalent volume diameter db,

of a bubble at a height Z, above the distributor is a function of the nozzle

area of the distributor A0, and the superficial gas velocity through the bubble

phase. It can be estimated by (Darton 1977):


• Exchange between bubble and emulsion phases:

SAND PARTICLESSAND PARTICLES


Modelling a fluidized bed:

FREEBOARD

exit

PF

R

SPLASHING REGION

Gas inlet

Fuel feeding

dense

phase

bubble

phase

CSTR

PF

R

CSTR

BED REGION

Fluidized beds

• BUBBLING TO TURBULENT TRANSITION

The pressure drop across a turbulent bed fluctuates rapidly. As the velocity is

increased, the amplitude of fluctuation increases, reaching a peak at the

velocity uc. It then reduces to a steady value as the fluidizing velocity is

increased further to the velocity uk. The transition from a bubbling to

turbulent bed does not take place sharply at one velocity.turbulent bed does not take place sharply at one velocity.

The gas–solid contact in this regime is good and the reactor performance

approaches that of an ideal back-mix reactor. Heat transfer coefficients in

turbulent regimes are lower than those in the bubbling bed regime, but that

is due to the lower solid concentration in a turbulent bed.

There is no well-established correlation for calculating the velocity of transition

from the bubbling to turbulent bed. However, some correlations (Grace,

1982) based on small-diameter beds (with ρpdp in the range 0.05 to 0.7

kg/m2) are:

Fluidized beds

• TERMINAL VELOCITY OF A PARTICLE

Consider a particle falling freely from rest and accelerating under gravity in an

infinite and stationary medium. The buoyancy force and the fluid drag

oppose the effect of gravity. The particle accelerates until it reaches an

equilibrium velocity called the terminal velocity.

The drag force on the particle is related to the kinetic energy of the fluid and theThe drag force on the particle is related to the kinetic energy of the fluid and the

projected area of the particle, and is defined as:

Fluidized beds

• TERMINAL VELOCITY OF A PARTICLE

If both the gas and particle move upwards with velocities U and Us, respectively,

the particle will experience a fluid drag due to the relative velocity (U – Us)

resisting its fall. Thus, the force balance under steady state can be written as:

Gravitational force = Buoyancy force + Drag forceGravitational force = Buoyancy force + Drag force

The velocity of the particle when the gas velocity U is zero, is known as the

terminal velocity, Ut. The terminal velocity is essentially the slip velocity

between the fluid and particle in a pneumatic transport. For spherical

particles:

Fluidized beds

• FAST FLUIDIZED BED (CIRCULATING BEDS)

In the context of its use in Circulating

fluidized bed (CFB) boilers, the fast

fluidized bed may be defined as a high

velocity gas–solid suspension where

particles, elutriated by the fluidizing gas

RISER

particles, elutriated by the fluidizing gas

above the terminal velocity of individual

particles, are recovered and returned to

the base of the furnace at a rate

sufficiently high to cause a degree of solid

refluxing that will ensure a minimum

level of temperature uniformity in the

furnace.

The furnace of a typical circulating fluidized

bed operates in a regime lying between

turbulent fluidization and pneumatic

transport.

A fast fluidized bed is comprised of solid

agglomerates moving up and down in a very dilute

dispersion of solids.

(P. Basu 2006)

DOWN COMER


• In fluidized-bed combustion (FBC) fuel is burned in a bed of particles

supported in an agitated state by an upward flow of air introduced via an air

distributor. The bed particles may be sand or ash derived from the fuel, but

usually they are a sulfur sorbent, like limestone or dolomite.

• Fluidized beds have inherently good heat-transfer characteristics, and these

ensure even temperatures within the combustor and high flux rates toensure even temperatures within the combustor and high flux rates to

steam/water cooling circuits.

• The good gas-solids contacting promotes effective sulfur capture and allows

high combustion efficiency to be achieved at temperatures significantly lower

than those of a pulverized coal furnace (typically 1116 K compared to over

1589 K).

• These lower temperatures also result in reduced slagging and fouling

problems and significantly lower NOx formation. This latter benefit, in

conjunction with the reduced SO2 emissions, constitutes one of the great

advantages of fluidized-bed combustors: in situ pollution control.


• There are two types of FBC unit distinguished by their operating flow

characteristics: bubbling and circulating. These two types operate at

atmospheric pressure, AFBC, or at elevated pressure, PFBC.

• Pressures for PFBC are in the range 0.6 to 1.6 MPa (90 to 240 psia).

• Typical superficial fluidizing velocities are tabulated as follows.

Atmospheric Pressurized

Bubbling 1.5–2.7 m/s 1–1.2 m/s

Circulating 3.7–7.3 m/s 3.7–4.3 m/s


• Stationary or bubbling fluidized

bed (SFB) as well as circulating

fluidized bed (CFB) boilers are

applied for large-scale

applications and often used for

waste wood or mixtures ofwaste wood or mixtures of

wood and industrial wastes, e.g.,

from the pulp and paper

industry


• COMBUSTION IN BUBBLING BEDS

In bubbling beds a large proportion of the noncombustible feedstock, mainly

sorbent derived, remains in the combustor, forming the bed. Bed depth is

maintained by draining off excess material. Most of the gas in excess of that

required for minimum fluidization appears as bubbles (voids), and these carry

particles upward in their wake, promoting the rapid vertical mixing within theparticles upward in their wake, promoting the rapid vertical mixing within the

bed that results in the even temperatures characteristic of FBC units.

Bed temperature is controlled by heat transfer to in-bed boiler tubes and/or to

the water-wall tubes used to enclose the furnace. Some units have

experienced metal loss from these tube surfaces, a combined effect of erosion

and abrasion, and suitable protection needs to be provided. Protective

measures include surface coatings such as plasma-sprayed metal coatings

incorporating silicon carbide, and metal fins to disrupt the solids-flow pattern.

The particulates leaving the boiler with the flue gas consist of unreacted and

spent sorbent, unburned carbon, and ash. Multiclones after the convection

pass remove much of the particulate matter and recycle it to the combustor,

increasing the in-furnace residence time and improving combustion efficiency.


• COMBUSTION IN CIRCULATING BEDS

CFBs operate at higher velocities, and virtually all the solids are elutriated from

the furnace. The majority of the elutriated solids, still at combustion

temperature, are captured by reverse-flow cyclone(s) and recirculated to the

foot of the combustor.

The foot of the combustor is a potentially very erosive region, as it contains largeThe foot of the combustor is a potentially very erosive region, as it contains large

particles not elutriated from the bed, and they are being fluidized at high

velocity. Consequently, the lower reaches of the combustor do not contain

heat-transfer tubes and the water walls are protected with refractory.

The furnace temperature is controlled by heat transfer through the exposed

upper water-wall tubes. As the units increase in size, more heat-transfer

surface is required than is provided by the walls.


• Typical fluidized bed boiler plant firing solid fuels

• 110 MWe CFB boiler

Combustion of

solid fuels –

Fluidized beds


Combined under-bed and over-bed feeders for

bubbling fluidized bed boilers


Simplified flow diagram for atmospheric circulating fluidized bed combustor

(with external heat exchanger)


Simplified flow diagram for atmospheric bubbling fluidized bed combustor:


Particle temperature and main phenomena of combustion in fluidized bed:


• Effect of bed temperature and reactivity of fuel on the combustion efficiency

of a bubbling fluidized bed:


• Corrosion and erosion could take place simultaneously in some places.

• Part of the ash deposited inside the furnace can melt and cause slagging. If the

ash is deposited in the gas duct downstream of the furnace, the phenomenon

is called fouling, which does not involve melting of the ash.


• Although the bed material (sand, silicon dioxide) melts at 1450°C, the eutectic

mixture with sodium formed melts at 874°C. For potassium salt, the eutectic

mixture will melt at 754°C. This makes the particle surface sticky disturbing the

fluidization and generating local hot spots. Hot spots lead to agglomeration

and sintering. Bed agglomeration (clinkering) leads to particle growth and

hence alters the size distribution of particles in the beds.hence alters the size distribution of particles in the beds.

single sandparticle

agglomerate formation-

bindingmaterial rich

inpotassium


• The fifteen largest Bubbling fluidized bed boilers that fire biomass (BFB)

Feedstock origin: L (Local), I (Import), M (Mixed), ? (Not known). IEA 2013


• The 15 largest circulating fluidized bed boilers (CFB) Feedstock origin: L (Local),

I (Import), M (Mixed), ? (Not known)


Grates Bubbling (BFB) and circulating

(CFB) fluidized beds

Pulverized fuel (PF)

firing systems

Advantages:-Relatively minor fuelrequirement-Clear design-Simple operation-Low auxiliary power demand

Advantages:-Flue gas cleaning can consist only in particulate removal

Disadvantages:-Complex operation

Advantages:-Large capacities-High power density-Good burnout-Utilizable ash

-Low auxiliary power demand-Relatively low NOx emissions-Partial desulfurization bylimestone addition

Disadvantages:-High UBC (2-4%)-High flue gas temperaturesdue to limited air preheating-Unsuitable for fine grainedfuels

-Complex operation-High thermal inertia-High limestone demand for sulfur capture-Ash not utilizable without treatment

Advantages of CFB against BFB:-Better burnout-Lower limestone demand for sulfur capture-Lower emission values-No in-bed heating surfaces at risk of erosion-Better power control

Disadvantages:-Relatively major fuelpreparation requirement-Complex operation-Flue gas cleaning neededfor particulates, SO2 and NOx.

Co-combustion

• Co-combustion of biomass with coal leads to a substitution of

fossil fuels and to a net reduction of CO2 emissions.

• A co-utilization of biomass with other fuels can be

advantageous with regard to cost, efficiency, and emissions.

Lower specific cost and higher efficiencies of large plants can beLower specific cost and higher efficiencies of large plants can be

utilized for biomass and emissions of SOX and NOX can be

reduced by co-firing.

• Attention must be paid to increased deposit formation in the

boiler and limitations in ash utilization due to constituents in

biomass, especially alkali metals and chlorine.

• The share of biomass is usually limited to approximately 5-10%

of the fuel input.

Co-combustion

• Three options for co-utilization of biomass with coal:

– (a) Co-combustion or direct co-firing (most common option): The

biomass is directly fed to the boiler furnace (fluidized bed, grate,

or pulverized combustion), if needed after physical preprocessing

of the biomass such as drying, grinding, or metal removal. For low

cofiring levels (5-8%), biomass can be combined with coal prior to

the pulverizers. For moderate (8-15%) levels, a separate biomass

preparation and delivery system should be provided. For higher

levels, a fluidized bed could be used.

– (b) Indirect co-firing: The biomass is gasified and the product gas

is fed to a boiler furnace (thus a combination of gasification and

combustion).

– (c) Parallel combustion: The biomass is burnt in a separate boiler

for steam generation. The steam is used in a power plant together

with the main fuel.

Co-combustion

• Effects of Co-combustion on plant operation.

• Negative effects of co-firing are:

– additional investment cost for biomass pretreatment and boiler

retrofitting,

– higher operation cost due to increased fouling and corrosion,– higher operation cost due to increased fouling and corrosion,

– a possible decrease of the electric efficiency,

– potential poisoning of SCR catalyst,

– possible reduction in the efficiency of electrostatic precipitator.

• Finally, the ash quality can be negatively influenced mainly by

alkali metals and chlorine contained in biomass, and also the

content of unburnt carbon can increase.

Co-combustion

• Effects of Co-combustion on Emissions.

• Co-firing can have several effects on the emissions and the plant

operation: positive effects are that SOx and NOx emissions usually

decrease due to the lower sulfur and nitrogen content in biomass

than in coal. Synergic benefits are also observed for NOx reduction

due to the high volatile content of biomass (air/fuel staging,

reburning) and formation of NH3 instead of HCN in primary

combustion zone.

• Alkali components in biomass ash can have an effect of SOx removal.

• Since biomass has a high volatile content, it can also be used as

reburn fuel for NOx reduction from the coal combustion, which gives

a further potential for significant decrease of the NOx emissions.

• Also emissions of heavy metals are reduced due to the lower content

in biomass than in coal.

Co-combustion

• Reburning, or fuel staging, means injection of a secondary fuel downstream

of the main combustion zone in order to establish a fuel-rich zone, where

nitric oxide, NO, is reacted by hydrocarbons to mainly HCN and NH3. In the

burnout zone, final combustion takes place with reduction of NO by reaction

with the nitrogen compounds formed in the reburning zone.

• The amount of fuel injected is in the order• The amount of fuel injected is in the order

of 10 to 20 % of the boiler’s total fuel

power.

• Originally, the secondary fuel (the co-fuel)

was natural gas, whose task is to provide

hydrocarbons.

• Later, it was found that reburning also

works well with biomass, if the grinding is

sufficient to produce fine fuel particles,

together with sufficient residence time and

temperature in the furnace for burnout of

the char particles.

Co-combustion

• Co-firing and full scale coal to biomass conversion could be a solution

to meet short term renewable targets in both EU and US.

• The fifteen largest pulverized firing boilers that co-fire biomass based

on their biomass consumption capacity usage:

Co-combustion

• Co-combustion in Italy:

• Sulcis-2 CFBC (ENEL): Circulating fluidized bed technology (Alstom

Power), 320 MWe, 40% efficiency, with wood chip-coal co-

combustion, since 2006, designed and realized for this asset.

• Characteristics:• Characteristics:

– 15% biomass (thermal) cofiring ratio, max 45 t/h,

– desulfurization with limestone inside the fluid bed,

– 850°C,

– limits: NOx 200 mg/Nm3, SO2 200-400 (depending on the amount

of local coal used) mg/Nm3, Dust 40 mg/Nm3.

+ Fusina 3 & 4, 320 MWe, RDF(5%)-coal co-combustion (pulverized), 35%

efficiency

Thermochemical processes(solid fuels)

• Coal to fuels

Thermochemical processes(solid fuels)

• Biomass can be used for fuels and products that would

otherwise be made from fossil fuels:

BIOMASS

BIOREFINERY

BIOMASS

BIOENERGY BIOMATERIALSCHEMICALS

- heating

- electricity

- biofuels

- syngas

- methanol

- …

- bioplastics

- biosolvents

-

Pyrolysis

• Pyrolysis is the thermal decomposition of an organic material in

absence of oxygen.

• Many processes exist based on different ways of providing the

necessary heat (partial oxidation, heat carriers, heat

exchangers), different operating conditions (varyingexchangers), different operating conditions (varying

temperature, heating rate, residence time) and selectivity.

• 3 macro-products can be obtained:

– char (solid) can be used as fuel, activated carbon, biochar;

– gas (4-8 MJ/Nm3) is generally burned to provide the process heat;

– tar (bio-oil) is a mix of organic compounds and water. After

separation the NCV is 20-25 MJ/kg and thus can be used as fuel.

As a matter of fact, it is unstable and corrosive (high O content)

and requires an upgrading step.

Pyrolysis

• Products of pyrolysis. Selectivity:

– char yield is favored by slow heating, long residence time, relatively low

final temperature (350-500°C) (slow pyrolysis and carbonization);

– tar (bio-oil) is favored by high heating rate (>100°C/s), short residence

time (<1 s) and moderate temperature (450°C for biomass and 550-600°C

for coal) (flash or fast pyrolysis, liquefaction);for coal) (flash or fast pyrolysis, liquefaction);

– gas is favored by high heating rate and high temperature (>700°C

favoring tar cracking) and relatively long residence time (1-5 s). The

presence of catalysts can maximize the yield in H2 or CH4.

(%wt typical yields) Bio-oil Char Gas

Slow pyrolysis 30 35 35

Fast pyrolysis 75 12 13

Gasification 3 10 87

Pyrolysis

• Slow pyrolysis. Biomass is pyrolysed at slow heating rates (5–7 K/min)

generally in fixed bed reactors. This leads to less liquid and gaseous

product and more of char production.

• Fast pyrolysis. It involves rapid heating (100°C/s) of biomass to

increase the yield of liquid product. Fast pyrolysis is successful with

most of fluidized bed reactors. offering high heating rates, rapid de-most of fluidized bed reactors. offering high heating rates, rapid de-

volatilization, easy control, easy product collection.

• Flash pyrolysis is the process in which the reaction time is of only few

seconds or even less. The heating rate is very high. This requires

special reactor configuration (entrained flow or fluidized bed

reactors) and small particles (100–250 µm) for producing biooil.

• Catalytic biomass pyrolysis is introduced to improve the quality of the

oil produced.

Pyrolysis

• Products of fast pyrolysis from a biomass at different temperatures

60

70

Yie

lds o

f p

rod

ucts

(%

wt)

char

0

10

20

30

40

50

200 300 400 500 600 700

T (°C)

Yie

lds o

f p

rod

ucts

(%

wt)

bioolio

chargas

Pyrolysis

• Biomass pyrolysis plant (Dynamotive, 100t/d, West Lorne) with

bubbling fluidized bed.

Pyrolysis

• Pilot pyrolysis plant (30 kg/h, Netherlands) with a cyclone reactor.

Pyrolysis

• Pilot pyrolysis plant (NREL) with an ablative reactor. Ablative pyrolysis

processes involve the contact between the biomass residue and a hot

reaction surface, which also performs mechanical ablation of the

biomass surface removing the char layers formed.

Conceptual scheme of the ablative pyrolysis of wood

on a rotating dish

Pyrolysis

• Comparison and perspectives of pyrolysis technologies

Pyrolysis

• Pyrolysis oil utilization options

Pyrolysis

• Biooil characteristics and composition

(possible recovery of specific chemicals)

%wt

Pyrolysis

• Industrial scale fast pyrolysis plants currently and recently operating

and their status in the end of 2012 (IEA).

Gasification

• Thermal conversion of a solid fuel in syngas through

partial oxidation / gasification reactions.

• Gasifying agent: air, enriched air, oxygen (/steam)

• Raw syngas formed mainly of (N2), CO and H2, with

significant amount of CO2, H2O, CH4, pollutantsignificant amount of CO2, H2O, CH4, pollutant

precursors, tar and dust.

• After appropriate gas cleanup, possible uses of syngas for

combustion (boiler, engine, turbine for CHP production)

or chemical synthesis.

• Possible IGCC application, more feasible for medium-large

scale plants (>50 MW) due to complexity and high costs.

Gasification

• Different types of gasification reactors

Gasification

• Size plant/gasifier type

GAS CLEANUP

RAW SYNGAS

100 1

fluidfluid bedbed downdraftdowndraftupdraftupdraft

10dust

tar 30 1100

g/Nm3

SYNGAS USE

50 1

engineengine synthesissynthesisturbineturbine

20

100 150

mg/Nm3

Gasification

Downdraft Updraft Bubbling Circulating Entrained

Top (°C) 700-1200 700-900 < 900 < 900 1500

Tgas (°C) 700 200-400

Fuel size

(mm)

20-100 5-100 0.5-5 0.5-5 < 0.5

Ash

(% dry)

0.5

(max 6)

1.4

(max 25)

<25 <25 high

(% dry) (max 6) (max 25)

Pros •Simple technology

•Low costs

•High thermal coefficient

•High reaction rate

•Uniform temperature

•Medium-large scale plants

•Large scale plants

•High efficiency

•Possible inert solid

residuesRelatively low

dust and tar

syngas

Relatively

high

moisture

fuel

Cons Only small scale plants

(40-1000 kW)

•High tar and dust syngas

•Complex technology

•Specific range of fuel size

•Complex technology

•Specific range of fuel

size

•High costsSpecific range

of fuel size and

moisture

High tar

syngas

Gasification

Gasification

• Biomass gasification: state of the art and predictions

Gasification

• Fixed bed downdraft gasifier at CRIBE (Centro Interuniversitario Biomasse per Energia, S.Piero a Grado – PI):

Loading LC max

Vegetable-oil towers

CondenserFlare

possible inclusion ofinternal combustion

engine for CHP production

Biomass

Tank

Loading

System

Gasifier

LC min

Air

To water

collection

Particulate

Cyclone

Condenser

Sawdust

Filters

Bag

Filter

Chiller

Blower

from cooling tower

to water

collection

TC0

FI

TC1

TC2

TC3

∆P

∆P

∆P ∆P ∆P

∆P

Cooler

Venturi

40-80 kg/h of biomass (15% moisture, 20-80 mm),

syngas LHV 5-6 MJ/Nm3,

potential electric efficiency 22-26%

Gasification

• Main reactions in the fixed downdraft gasifier:

Gasification

• Gasifier model:

DECOMP

MIXHEAT

air inlet

biomass inlet

H-DEVO

H-IN

BLOCK GASIFIER

pyrolysis model:

- TD equilibrium

- kinetic model

- structural model

MIX1

H-IN

REACT

H-REC

SEPASH

air inlet

(or O2/steam )

ash

syngas

H-REACT

H-REC

DISP

- structural model

gasification model:

- TD equilibrium

- kinetic model

- correlations

Gasification

• Updraft gasifier pilot plant (1800 kW)

Gasification

• FLUIDIZED BED GASIFICATION

In a fluidized bed gasifier, air and fuel are mixed in a hot bed of granular solids

such as sand. Due to the intense gas–solid mixing in a fluidized bed, the

different zones — drying, pyrolysis, oxidation, reduction — cannot be

distinguished, but the temperature is uniform throughout the bed.

Contrary to fixed bed gasifiers the air-to-fuel ratio can be changed, and as aContrary to fixed bed gasifiers the air-to-fuel ratio can be changed, and as a

result the bed temperature can be controlled easily.

The product gas will however, always contain some tar, which needs to be

removed. Furthermore, high solid conversion is hardly achieved. Particle

entrainment from a bubbling bed also contributes to the loss in a gasifier.

The other important problem with FB gasifiers is the slow diffusion of the oxygen

from the bubbles to the emulsion phase, which creates oxidizing conditions in

the whole bed decreasing the gasification efficiency.

The circulating fluidized bed (CFB) can get around this problem by providing

longer solid residence time within its solid circulation loop.

Gasification

• FLUIDIZED BED GASIFICATION

Fluidized bed is especially good for biomass gasification. So far as coal

gasification is concerned, fluidized beds have found only limited application

because of their low carbon conversion efficiency, which results from the

relatively low bed temperatures (800 to 1000°C) needed to avoid ash

agglomeration.agglomeration.

Since fluidized bed gasifiers operate at relatively low temperatures, most reactive

and high-ash content fuels, depending on ash chemistry, can be gasified in

such beds without the problem of ash sintering and agglomeration.

Also, fluidized bed gasifiers can be operated on different types of fuels or a

mixture of different fuels. This feature is especially attractive for biomass

fuels, such as agricultural residues and wood, that may be available for

gasification at different times of the year.

Gasification

• This is an atmospheric-pressure air-blown

gasifier operating in a circulating fluidized

bed. Depending on the fuel and the

application, it operates at a temperature

within the range of 800 to 1000°C.

• The hot gas from the gasifier passes• The hot gas from the gasifier passes

through a cyclone, which separates most

of the solid particles associated with the

gas and returns them to the bottom of the

gasifier. An air preheater is located below

the cyclone to raise the temperature of

the gasification air and indirectly the

temperature level inside the gasifier.

Gasification

• The integrated gasification combined-cycle (IGCC) process involves

complete gasification of the fuel. The cooled, medium-heating-value

gas is desulfurized and dedusted, and burnt in the combustor of a gas

turbine to produce electricity.

• Waste flue gas from the turbine is used to heat the water for the

boiler. Steam from the boiler produces additional electricity in aboiler. Steam from the boiler produces additional electricity in a

steam turbine.

• The combined efficiency of this process is in the range of 42 to 45%.

The waste gas leaves the gas turbine at a relatively low temperature,

thus it cannot produce high-temperature steam.

• The cost-effectiveness and overall plant availability of this system

have to be evaluated against other options. The power generation

cost is not yet competitive with conventional plants, but government

supports and emission credits might make this option viable.

Gasification

ExhaustExhaust gasgas

HeatHeat

Integrated combined-cycle plant

(scheme)

Gasification

Combined-cycle plant using

partial gasification of coal

Gasification

• The dual bed gasifier was developed to gasify biomass indirectly to produce a

medium heating value gas. The design employs two CFBs — one acting as a

char combustor and the other serving to gasify the biomass.

• In the gasifier section, the solid biomass particles come into contact with hot

sand or other bed material, and are converted to gas and char.

• The char particles carried over from the gasifier burn inside the char• The char particles carried over from the gasifier burn inside the char

combustor and heat the bed material accompanying the char particles.

• The hot sand particles separated by the cyclone of the CFB combustor enter

the gasifier to heat the biomass particles fed to it.

• The gas from the gasifier is cooled, cleaned and compressed before entering

the combustion chamber of the IGCC plant or any other application point. It

contains (virtually) no nitrogen and the process does not require ASU.

• The circulation of solids between the two CFB legs is a major challenge in this

type of gasifier.

Gasification

• The dual bed gasifier:

Gasification

• The largest operational biomass gasifiers. Feedstock origin: L (Local), I

(Import), M (Mixed), ? (Not known).

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