Chapter III: Gasification of biomass wastes and residues for electricity production

Co-authors: René van Ree, Lars Waldheim, Eva Olsson, André Oudhuis, Ad van Wijk, Cees Daey-Ouwens, Wim Turkenburg.

Accepted for publication in: 'Biomass and Bioenergy'.

Abstract - The technical feasibility and the economic and environmental performance of atmospheric gasification integrated with a combined cycle of biomass wastes and residues for electricity production are investigated for Dutch conditions. The system selected for study is an Atmospheric Circulation Fluidized Bed Gasifier/Combined Cycle (ACFB/CC) plant based on the General Electric LM 2500 gas turbine and atmospheric gasification technology, including flue gas drying and low temperature gas cleaning (similar to the Termiska Processer AB process). The performance of the system is assessed for clean wood, verge grass, organic domestic waste, demolition wood and a wood/sludge mixture as fuel input.

System calculations are performed with an ASPENplus model. The composition of the fuel gas was derived by lab scale fuel reactivity tests and subsequent model calculations. The net calculated efficiencies for electricity production are between 35.4 - 40.3% (LHV) for the fuels studied, with potential for further improvement. Estimated investment costs, based on vendor quotes, for a fully commercial plant are 1500 - 2300 ECU per kWe-installed.

Electricity production costs, including logistics and, in some cases negative fuel price, vary between minus 6.7 and 8.5 ECUct/kWh. Negative fuel costs are obtained if current costs for waste treatment can serve as income to the facility. Environmental performance is expected to meet strict standards for waste incineration in the Netherlands. The system seems flexible enough to process a wide variety of fuels. The kWh costs are very sensitive to the system efficiency but only slightly sensitive to transport distance; this is an argument in favour of large power scale plants. As a waste treatment option the concept seems very promising. There seem to be no fundamental technical and economic barriers that can hamper implementation of this technology.

 

 1. INTRODUCTION

 At present, in the Netherlands various biomass wastes and residues are landfilled, incinerated, composted or digested. However, landfilling capacity is scarce and a ban on the landfilling of organic materials will be implemented in the short term. Composting gives rise to problems because supply exceeds demand.11,15,37,42 Furthermore, waste incineration combined with electricity production has low conversion efficiencies. This implies that the energetic potential of biomass wastes and residues is poorly utilised.

However, "Biomass fired Integrated Gasifier Combined Cycle" (BIG/CC) technology is a promising alternative to handle organic wastes. The potentially high efficiency compared to mass burning and the potentially low investment costs have been demonstrated in a number of studies.10,14,19,20,21,45

Concerning the BIG/CC technology Faaij et al.14 and van Ree et al.32 have made an inventory of potential technologies. Also a preliminary feasibility study for the Province of Noord-Holland was made.14 The Province of Noord-Holland, supported by utilities and the Netherlands Ministry of Economic Affairs, has taken the initiative to set up a BIG/CC plant. This technology will also be implemented in other countries. In this connection especially the Global Environment Facility World Bank project in Brazil should be mentioned.13

As a waste treatment option, the BIG/CC technology should be capable of meeting the very strict emission standards for waste treatment in the Netherlands. Also it should be flexible enough to deal with a variety of different biomass fuels. In addition the system should be robust, be competitive and have a minimum of technical risks.

BIG/CC units, however, have not yet been constructed on a commercial basis. Cost estimates vary,6,7,20 but the general conclusion is that the first plants will be expensive. A partial solution that can be forwarded is to compensate for the initial high investment costs by using biomass wastes or residues that are available at very low or even negative costs. A disadvantage is that the use of residues complicate the conversion facility because residues and wastes have different properties and a higher degree of contamination compared with clean wood, e.g. from energy farming. The properties of various biomass wastes and residues in the Netherlands is discussed elsewhere.12,15 A detailed system analysis and cost assessment is necessary to provide more insight into the prospects and performance of a BIG/CC system, especially when it is utilised for a variety of biomass fuels. Such an analysis has been carried out for the Province of Noord-Holland and the results are presented in this paper.

 

2. SELECTION AND CHARACTERISTICS OF BIOMASS WASTES AND RESIDUES

 The characteristics of various biomass wastes and residues have been reported elsewhere.12,15 It was shown that the costs of fuels that are available for energy production differ widely, ranging from a negative value of minus 10 up to a positive value of 5 ECU/GJ. Possible biofuels were found to differ substantially with regard to (chemical) composition, moisture and ash content, concentrations of heavy metals and the content of nitrogen, sulphur and chlorine. It was concluded that in order to meet gas turbine constraints, the ash content of the incoming fuel should not be higher than 10-20% of the dry matter content. A moisture content of approximately 70% (wet basis) was considered to be a maximum permissable value (for biomass with a very low ash content). Streams that exceed these limits either have to be treated by other conversion techniques or have to be mixed with cleaner materials in order to meet the maximum permissable values.

The following fuels, representative for the wide variations in fuel characteristics (and prices) and available in sufficient quantities, have been selected for this system analysis:

Table 1 summarises the relevant parameters of the selected fuels.12,15 Representative base values serve as input for the system calculations as well as for the gasification tests and gas composition calculations.

Table 1. Data on moisture, ash and energy content chemical composition and costs of five selected biomass fuels (derived from van Doorn12 and Faaij et al.15).

Fuel type

Clean wood a

Verge grass

Organic Domestic Waste (ODW)

Demolition wood

Sludge

Unit

moisture contentc

50

60

54

20

20 b

% of wet fuel

ash contentc

1.3

8.4

18.9

0.9

37.5

% of dry fuel

LHV (as recieved)

7.7

5.4

6.4

13.9

8.8

MJ/kg a.r.

HHV (as recieved)

9.6

7.4

8.3

15.4

9.9

MJ/kg a.r.

Composition

 

 

 

 

 

% on moisture and ash free basis (maf))

C

49.10

48.70

51.90

48.40

52.50

 

H

6.00

6.40

6.70

5.20

7.20

 

O

44.30

42.50

38.70

45.20

30.30

 

N

0.48

1.90

2.20

0.15

6.99

 

S

0.01

0.14

0.50

0.03

2.74

 

Cl

0.10

0.39

0.3

0.08

0.19

 

Available amounts in the Netherlands

 

 

 

 

gross availaility

13

4

6

3

4

PJLHV/year

net availability

9

4

3

2

4

PJLHV/year

Cost range

 

 

 

 

 

 

minimum

43

-99

-107

-137

-95

ECU/dry ton

maximum

50

11

-46

-11

-38

ECU/dry ton

 a Thinnings from commercial forestry are selected. Composition data for poplar wood are presented.

b The moisture content of sludge from waste water treatment plants is originally as high as 80 - 90%. After mechanical dewatering and drying, the moisture content is decreased. 20% is taken here as a representative value.38

c Given moisture and ash contents are considered to representative for the biomass fuels as recieved at the conversion facility.

The compositions of the fuel gas produced by the gasifier varies according to the fuel used. The gas compositions are derived from lab scale fuel reactivity experiments and from subsequent separate gasifier model calculations.25 The results of this exercise per selected fuel are given in table 2. These results will serve as input for further system modelling.

Table 2. Fuel gas composition data for various biomass fuels, resulting from fuel reactivity experiments and ACFB gasifier model calculations for each fuel performed by TPS25. These gas compositions serve as input data for ASPENplus modelling.

 

Clean wood

Verge grass

Organic Domestic Waste

Demolition wood

20% Sludge (maf) + 80% dem.wood (maf)b

Unit

Gasifier air

 

 

 

 

 

 

flowrate

1.40

1.48

1.6

1.26

1.41

kg/kg wet fuela

temp

400

400

400

400

400

oC

Dolomite consumption

 

 

 

 

 

flowrate

0.0268

0.0279

0.0279

0.0257

0.0261

kg/kg wet fuel

Fuel gas produced

 

 

 

 

 

flowrate

2.37

2.40

2.42

2.27

2.30

kg/kg wet fuel

temp

900

900

900

900

900

oC

Fuel gas composition

 

 

 

 

vol % wet gas

C2H6

0.02

0.02

0.02

0.02

0.02

 

C2H4

0.94

0.87

0.77

0.98

0.88

 

CH4

2.82

2.61

2.81

2.93

2.63

 

CO

17.22

14.94

13.98

18.31

15.18

 

CO2

12.22

12.09

11.80

11.67

12.22

 

H2

13.25

12.42

11.27

15.07

12.37

 

H2O

13.55

14.49

13.71

13.85

14.34

 

N2

39.20

41.64

44.59

36.64

41.04

 

O2

0.00

0.00

0.00

0.00

0.00

 

Ar

0.47

0.50

0.54

0.44

0.49

 

NH3

0.27

0.33

1.00

0.07

0.78

 

H2S

0.00

0.03

0.03

0.01

0.04

 

HCN

 

 

 

 

 

ppm level

HCl

0.03

0.07

0.00

0.02

0.01

 

molar mass

24.86

24.99

25.28

24.28

25.75

kg/kmol

tar residues

12

11

10

12

13

g/kg wet fuel

fly ash particulates

0.036

0.083

0.152

0.032

0.045

kg/kg wet fuel

ash

65

87

95

61

84

weight% of fly ash

LHV (wet gas)c

5.22

4.74

4.39

5.59

4.82

MJ/Nm3 (wet)

LHV (30 oC)d

5.77

5.31

4.86

6.21

5.6

MJ/Nm3 (at 30 oC)

Gasifier ash

 

 

 

 

 

 

flowrate

0.0158

0.0158

0.0357

0.0017

0.0785

kg/kg wet fuel

ash

90

90

90

90

95

wt % gasifier ash

 a Moisture content of all the ingoing fuels to the gasifier are set at 15% to permit comparison of the required heat demand for drying. Consequences for resulting low heating values of the fuel gas (in case of verge grass and organic domestic waste) will be discussed later.

b Maf: moisture and ash free; mass fraction of the mixture determined by the minimally required heating value for the gas turbine.

c Heating value of the gas after the tar cracker.

d Heating value of the gas after the wet scrubber (water condensed at 30 oC)).

 

3. SYSTEM DESIGN AND PERFORMANCE

3.1 System selection and modelling

The selected gasification process is similar to Termiska Processer AB (TPS) technology which makes use of an Atmospheric Circulating Fluidized Bed (ACFB) gasifier followed by a separate CFB tar cracker.4,41,42,43 The main reasons for selecting this process and subsequent low temperature gas cleaning are that it is expected to be able to deal with various biomass fuels with varying fuel properties and degrees of contamination. Moreover, all parts of the system have been proven commercially. There are however still some technical uncertainties, particularly with regard to the integration of various parts, such as the coupling of the gasifier to a gas turbine and a system integrated dryer.6,7

The gas turbine selected for this study is the General Electric LM2500. This results in a system with a capacity of approximately 30 MWe.18 Major arguments for selecting this turbine are that it is under development for low calorific gas applications as part of the GEF World Bank project in Brazil13, it is relatively small in size and it therefore requires a relatively modest quantity of fuel. Furthermore, a STIG version of this turbine (STeam Injected Gas turbine) is available which allows larger differences in mass flows, which is necessary to operate on the low calorific gas produced by a direct gasifier.2,3,8,33 Being an aeroderivative, this turbine combines a relatively high efficiency with a high turbine outlet temperature which results in good conversion efficiencies of the combined cycle plant.3

The basic BIG/CC design is shown in figure 1. After gasification of the biomass, the resulting fuel gas is cracked in a tar cracker using dolomite as a catalyst. The gas is cooled and particulates and alkalis are removed by a baghouse filter. Remaining contaminants, mainly ammonia, are removed in a wet scrubber. Before combustion in the (modified) combustion chamber, the fuel gas is compressed. After steam production, the flue gas is led to a fuel gas dryer in order to dry wet fuels to required gasifier specifications.

Figure 1. Scheme of the considered integrated direct atmospheric gasification combined cycle system based on TPS-gasification technology.

Table 3 summarises the main parameters of the selected system components. Data about these components have been derived partly from the literature, but especially by consulting various suppliers. A more detailed description of the system configuration is given by van Ree et al.31

Table 3. Technical data on system components. Data are derived from literature and specific information from manufacturers. More detailed information is given in background reports from van Ree et al.31 and Faaij et al.57


 dryerb Direct rotary drum dryer, 13.8 ton water ev./hr. Mass flows and temperatures for fuel of approx. 50% moisture: 'Dry' flue gas: 78 kg/s, 200 oC 1.1 bar, 'wet' flue gas 81.5 kg/s, 80 oC, 1.1 bar.31

gasifiera ACFB type TPS technology, 1.3 bar, 900 oC (depends on fuel), heat loss 2% of thermal input. Bed material: sand. Gasifier air: 1.3 bar, 400 oC25

tar cracker CFB reactor using dolomite, pressure 1.3 bar, 900 oC25

fuel gas coolers: 900 to 140 oC (Q approx. 14 - 15 MWth depending on the fuel), pressure drop 0.1 bar.31

dust filter Baghouse filter, pressure drop 0.05 bar.48

fuel gas scrubber Spray tower using recirculating water: mass flow 73 kg/s, pressure 1.3 bar, temperature 25 oC, pressure 0.05.47

fuel gas compressor multi stage compressor with intercooling. Cooling duty 2.3 MWth, isentropic eff. 0.78, mechanical eff. 0.998, pressure ratio: Pin/Pout + 33/1.1)31,34

gas turbineb General electric LM 2500 (modified for LCV gas). Pressure drop over valves to inlet combustion chamber: 10 bar, heat loss 2 MWth.

Compressor mass flow: 65 kg/s, Tout:459 oC, mass flow turbine blade cooling: 7 kg/s, isentropic eff.: 0.91

Combustion chamber: pressure: 23 bar, mass flows and T out depending on fuel type.

Expander: Mass flow flue gas and Tin depending on the fuel type, pressurein: 23 bar, isentropic eff.: 0.89, pressure flue gasout: 1.1 bar. Generator efficiency. 0.99.18,29,56

Ambient air: 15 oC, 1 bar, composition (vol %): 1.01 H2O, 77.29 N2, 20.75 O2, 0.03 CO2, 0.92 Ar.

Heat Recovery Steam Generatorc Superheater 1: 40 bar, 450 oC, superheater 2: 40 bar, 440 oC, air preheater for gasifier and tar cracker air: 400 oC, evaporator: 40 bar, 256 oC, economizer: 240oC, minimum pinch air preheater (g/g): 15 oC, mimimum pinch (g/l) 20 oC. Total pressure drop from feedwater to superheated steam: 4 bar.

Mass flow of flue gas and steam produced depend on type of fuel. Steam conditions 450 oC, 40 bar.

Steam turbine Two-stage partly condensing steam turbine; 40 bar, 450 oC to 8.1 bar to 0,07 bar

Isentropic eff. 0.735, mechanical eff. 0.99, generator eff. 0.99

Steam/water cycle Condensor: 0.07 bar, using surface water. Eff. water pump: 0.82

Deairator: 3.6 bar, minor steam consumption of 8.1 bar

Water pumps: pressures from 0.07 to 3.8 to 45 bar. Eff. 0.99


aMass flows of gasifier air, dolomite consumption and ash production for selected fuels are given in table 2.

bTemperatures of incoming and outgoing gas for the dryer, combustion temperatures and gas turbine expander outlet temperature, depend on the type of fuel8 and are given with the results of the model calculations.

c Steam system defined in van Ree et al.31

ASPENplus is used as a modelling tool for system calculations. With an ASPENplus model mass flows, related emissions and the system performance have been calculated for various fuels. The gasification process itself is not modelled in ASPENplus. The gasifier and tar cracker are modelled as a black box for which the input (parameters incoming fuel) and output (calculated gas compositions on the basis of experiments) are known (see table 2). The results of the calculations per fuel are given in table 4. Detailed descriptions of the process conditions are given in a background report.31

Table 4. Input data and results of ASPENplus system calculations with various fuels.

 

Clean wood

Verge grass

Organic domestic waste

Demolition wood

Mixture sludge/demolition wood

Biomass fuel

 

 

 

 

 

fuel input (kg/s)

9.30

12.71

12

5.27

total: 6.65

moisture (%)

50

60

54

20

20

ash (w/w%) d.b.

1.32

9.8

18.9

0.9

av. 11.1

LHV (a.r.)b

7.7

5.4

5.9

13.9

8.4 - 13.9

HHV (a.r.)b

9.6

7.4

7.8

15.4

10.0 - 15.4

Dryer

 

 

 

 

 

moisture after drying (%)

15

15

15

15

15

flue gas dryer Tin - Tout (oC)

195 - 71

276 - 67

292 - 117

179 - 165

179 - 165

Fuel gas

 

 

 

 

 

LHV (MJ/nm3; 30 oC)

5.77

5.31

4.86

6.21

5.60

flow (Nm3/s)

10.55

11.46

12.50

9.79

10.87

E-input (MW)

60.85

60.85

60.75

60.80

60.87

gas turbine expander inlet temperature (oC)

1150

1136

1122

1160

1145

steam production (kg/s)

11.8

9.85

9.50

12

11.60

Energy balance

 

 

 

 

 

input: LHV (MWth)

72.0

68.8

70.6

73.1

81.9

input: HHV (MWth)

89.6

94.2

93.2

81.2

92.3

output: Gas turbine (MWe)

26.3

26.7

27.1

25.9

27.1

Steam turbine (MWe)

10.3

8.5

8.2

10.4

10.1

Gross (MWe)

36.6

35.2

35.3

36.3

37.2

Electricity consumption of the system

 

 

 

 

dryer (MWe)

0.33

0.44

0.39

0.19

0.19

fuel gas compressor (MWe)

6.53

7.27

8.10

5.94

7.29

gasifier air compressor (MWe)

0.22

0.24

0.28

0.21

0.24

pumps (MWe)

0.43

0.43

0.43

0.43

0.43

Total (MWe)

7.51

8.38

9.20

7.01

8.15

Net Output (MWe)

29.0

26.8

25.6

29.3

29.0

Net system efficiency (LHV a.r.)b,c

40.3

39.0

36.3

40.0

35.4

Net system efficiency (HHV a.r.)b,c

32.4

28.5

27.5

36.1

31.5

 aThe ratio between sludge and demolition wood in mixture is chosen to give a fuel gas with a heating value of 5.6 MJ/Nm3. The ratio is 20% sludge and 80% demolition wood, based on moisture and ash free composition (maf).

ba.r. implies fuel with moisture content as received at the gate of the facility.

cGenerally speaking the system efficiency decreases with increasing ash content of the fuel. This is mainly due to increased work by the fuel gas compressor because the heating value of the fuel gas drops with higher ash contents. Also the combustion temperature decreases with lower heating values of the fuel gas.

 

3.2 System efficiency

 As shown in table 4 the net overall senergy conversion efficiencies of the system (LHV basis) ranges from 35.4 for the wood/sludge mixture to 40.3 for clean wood. As expected, higher ash contents result in lower conversion efficiencies. The same is found for fuels with a higher moisture content. However in addition several remarks about, these results have to made: The calculated efficiencies are obtained for specific fuels and for system operation at a design point. It might be in practice that the dryer, feed system, gasifier, fuel gas compressor, etc. would all have to be designed due to specific boundary conditions, which could possibly result in a lower conversion efficiency.

For all fuels the heating values of the fuel gas, which serve as input for the calculations, exclude non-condensable tars due to uncertainties in the measurements and difficulties to extrapolate lab results to a full scale plant. It therefore is uncertain to what extent these tars (which are not removed during gas cleaning) appear in the gas in reality. The tars could increase the heating value of the gas by 3 - 6%.25 Since this effect has not been taken into account in the calculations, the efficiencies presented are somewhat pessimistic. It should be kept in mind that a 6% higher heating value of the gas could increase the net conversion efficiency by approximately 2 percentage points.

Another point is that the heat rate degradation of the gas turbine during its lifetime will have a negative influence on the efficiency. The turbine is maintained at regular intervals where upon the efficiency is restored to its original level. However, even with a normal maintenance schedule a 3-4% drop in efficiency of the gas turbine during its lifetime is observed.29 This is partly compensated by a higher expander outlet temperature which permits increased steam production. Overall, the loss in efficiency will be approximately 2-3%.

The drop in efficiency as calculated for verge grass and organic domestic waste (see table 4) is due to the steam system selected. The higher heat demand for drying these wet fuels means that the maximum amount of steam produced and superheated is limited by the minimum pinch point of 15 oC for preheating of air in the heat recovery steam generator (HRSG). If the gasifier air temperature would be lowered somewhat (e.g. 380 oC instead of 400 oC which is selected) the steam system would operate at selected design conditions. Lowering the gasifier air temperature would also cause a slight decrease in the heating value of the gas, but the influence of this decrease on the conversion efficiency is very limited.25 These parameters are not optimised in this project.

The limits of the system with regard to the quality of the incoming biomass are approximately 10 - 20% (for wet biomass) and a moisture content of approximately 70% (for biomass with low ash content). More ash causes a leaner gas, which requires more compression work and lowers the combustion temperature of the gas turbine. Fuels that are too wet require so much waste heat for drying that steam production drops. Verge grass and especially organic domestic waste produce fuel gas with a heating value below the 5.6 MJ/Nm3 that is required for the gas turbine. This problem could be solved by more extensive drying. Verge grass meets the required heating value already at a moisture content of 12% instead of the 15% that is taken as starting point in table 4. This will have very little influence on the overall efficiency, as steam production is only slightly decreased.

Concerning organic domestic waste a moisture content of less than 3% is required to produce a fuel gas with a heating value of 5.6 MJ/Nm3. The required drying to achieve this will reduce the steam production drastically and might cause unacceptable emissions because the temperature in the dryer will rise and volatile fractions in the biomass might evaporate. There are, however, several issues that must be kept in mind: non-condensable tars had been excluded, which could represent 3-6% additonal heating value. Also the required heating value of 5.6 MJ/Nm3 might prove to be a conservative constraint. Lower heating values might be allowable with the LM 2500 and certainly with the use of specially developed combustion chambers. To make to processing of organic domestic waste feasible one can as well add wood with a low ash content (demolition wood). Another possible improvement option is heat recovery from the ash stream back to the gasifier thus limiting heat losses and reducing the problem of maximum permissable ash contents. However, the costs of this option are not evaluated in this paper.

3.3 Environmental performance

The emissions after combustion are investigated and compared with Dutch emission standards. First of all, in table 5 the standards for the required fuel gas quality of the LM2500 gas turbine are given. The gas cleaning system will have to meet these standards anyway in order to prevent excessive wear and corrosion of the gas turbine.

Table 5. Maximum permissable concentrations of contaminants in the flue gas stream to the GE LM 2500 turbine.6,29

 Component

Maximum allowed concentrations in the flue gas flow to the expander (ppbw)a

Calculated maximum allowable concentrations in a typical biogas (ppbw)

Solid particles:

 

 

d < 10 m m.

600

3000

10 < d < 13 m m.

6

30

d > 13 m m.

0.6

3

Lead

20

100

Vanadium

10

50

Alkalis (Na + K + Li)

4

20

Calcium

40

200

Alkali-Metal Sulphates

12

60

Chlorides

500

2500

Condensable tars

-

0.008 mg/Nm3

 aParts per billion weight. This is the concentration after combustion so the permissable concentration in the fuel gas is a factor 5 higher (values for operation on natural gas). Values in the second column are calculated from the first. When Low Calorific Value gas is used the dilution is approximately a factor 6 - 7 depending somewhat on the composition of biomass used (compared to a factor 5 for natural gas).

 Table 6 presents the standards of gaseous emissions applicable in the Netherlands for waste incineration (the so called BLA standards) and power generation. The first column shows the strictest set of emission standards and is considered to applicable to a unit that uses biomass wastes and residues.

 - Dust emissions are determined by the limits set by the gas turbine and are thus very low. The dust concentration after combustion is lower than the emission constraint in the BLA; the baghouse filter and scrubber together are capable of meeting this constraint.

 - Up to 90% of HCl is removed in the tar cracker and the remaining part is bound to (lime) particulates at 140 oC in the baghouse filter. In Lassing et al.25 it is concluded that almost 100% HCl will be removed. Any HCl that remains will dissolve in the scrubber. HCl emissions from the system will therefore be negligible.

 - The emissions of hydrocarbons, CO, PCDDs (Poly Chlorine Dibenzo Dioxins) and PCDFs (Poly Chlorine Dibenzo Furanes) after combustion are determined completely by

 Table 6. Relevant emission standards for combustion of solid and gaseous fuels.

Component

BLA mg/Nm3 a

BEES mg/Nm3 b

EC-standards for stationary coal fired plants mg/Nm3

Dust

5.0

5

20

HCl

10.0

 

 

HF

1.0

 

 

CO

50.0

 

 

Organic compounds (as C)

10.0

 

 

SO2

40.0

35

200 (for 90% S removal with Flue Gas Desulphurisation)

NOx

70.0

(65 g/GJ * gas turbine eff.)/30

100

Total heavy metals (Sb/Pb/Cu/Mn/V/Sn/As/Co/Ni/Te)

1.0

 

 

Cd and compounds

0.05

 

 

Hg and compounds

0.05

 

 

Total PCDD's and PCDF's

0.1 ng(1-TEQ)/Nm3

 

 

 aBLA (Besluit Luchtemissies Afvalverbranding; Decision on Air Emissions Waste Incineration) represents emission standards for waste incineration in the Netherlands and are at present the strictest in the world.

bThe BEES (Besluit Emissie-eisen Stookinstallaties Milieubeheer; Decision on Emission Regulations for Heat Installations) is applicable to boilers of electricity production facilities.

 

the specifications of the gas turbine. Because of the high temperature in the gasifier and reducing conditions before combustion in the turbine those compounds are not formed. These specifications are such that all constraints stated in table 5 are met when the gas turbine operated with natural gas. This is not expected to be different when the turbine is fired with LCV gas. CO emissions will however be higher compared to the use of natural gas because of lower combustion temperatures, but they will not exceed the above-mentioned standard.56

 - NOx: There are two sources of NOx; thermal NOx and combustion of ammonia present in the fuel gas. With regard to thermal NOx, state-of-the-art GE gas turbines have emission factors as low as 15 ppmv (with 15% oxygen in the flue gas). The lower combustion temperatures obtained by using LCV gas (approx. 1150 oC instead of 1230 oC) will reduce the thermal NOx formation even below the level of 15 ppm.29,56

Ammonia is produced during gasification. The NH3 concentrations in the fuel gas given in table 2 do not include the removal of NH3 by dolomite. Per biomass stream the NH3 flows in the system are given in table 7. Test results have shown that, depending on the nitrogen content in the fuel, N is only partly converted to NH3. Lassing et al.25 indicate that between 35% (Miscanthus, waste wood) and 80% (sludge) of the nitrogen in the fuel is not found as NH3 in the gas. Mechanisms are not fully understood but a large fraction is probably converted to molecular nitrogen.

The permissable level of NOx emissions is 70 mg/Nm3 (see table 6). This standard will be exceeded by all fuels, as shown in table 7, even when partial conversion to N2 is taken into account. The estimates for the fraction of fuel N that is converted to N2 are given as well. Ammonia dissolves well in water and can be removed from the fuel gas using a wet scrubber. The removal efficiency of the scrubber needs to be approximately 80% (for organic domestic waste) to meet the NOx standard. The efficiency can be increased by increasing the water flow or even by adding an acid (such as H2SO4) to the scrubber water. Discharge of the scrubber waterinto the (aerobic) waste water treatment system for conversion to nitrate can be considered, but the costs involved are very high (Costs are determined by the oxygen demand in aerobic waste water treatment plants; they amount to 0.47 ECU/kg O2 which is typical for Dutch conditions. Ammonia is converted to nitrate in waste water treatment plants giving an oxygen consumption of 4.57 g O2 per g N52. This will lead to waste water treatment costs of approx. 1 Million ECU/year for organic domestic waste and for a plant operating for 7400 hours per year at full load per year at full load).

In this study it is assumed that ammonia is stripped from the scrubber water and removed. Ammonia can possibly be used as a fertiliser.

 Table 7. NH3 flows, estimated molecular nitrogen formation and related NH3 flows and NOx formation without removal by a scrubber. Volume flows are derived from the ASPENplus calculations.

  fuel

Clean wood

Verge grass

Organic Domestic Waste

Demolition wood

Sludge/wood mixture

Volume flow wet gas (Nm3/sec)

10.55

11.46

12.5

9.79

11.49

NH3 vol% fuel gas

0.27

0.33

1

0.07

0.78

Estimate % N2 formation from fuel N

50

50

80

35

75

NH3 flow through scrubber (kg NH3/hr)

40

55

72

12

62

mg NOx/Nm3 without removal

729

905

2651

190

2025

 

To some extent ammonia will interact with thermal NOx in the combustion chamber and reduce NOx emissions by the formation of molecular nitrogen. The degree of this interaction is not known.

 - SO2 emission levels will depend on the concentration of sulphur in the fuel and on the efficiency of removal in various gas cleaning components. The sulphur content of the fuel and in the fuel gas (H2S) differ widely as shown in table 2. Part of this sulphur will react with lime in the cracker to form CaS. When the sulphur content is more than 0.1% dry matter in the biomass, chemical equilibrium is reached in the gasifier, which leads to a H2S concentration of approximately 200 - 300 ppm in the fuel gas25. This equilibrium state is reached for sludge, verge grass and organic domestic waste, leading to SO2 concentration in the flue gas of approximately 100 mg/Nm3, which exceeds the mentioned constraint of 40 mg/Nm3, so measures have to be taken.

H2S dissolves very poorly in water. Adding a base (NaOH) to the water stream will convert H2S to Na2S, which dissolves well in water. Depending on the standards for surface water near the plant, the waste water stream may or may not be discharged directly into the surface water. In the latter case, costs of operation will increase as a result of waste water treatment at central facilities. It is also possible to precipitate Na2S which produces a removable solid salt.

In this study it is assumed that all H2S is removed by sodium hydroxide in a wet scrubber. Table 8 shows the H2S concentrations in the fuel gas for the selected fuels. For verge grass, organic domestic waste and the wood sludge mixture a concentration of 200 ppm is assumed.25 For demolition wood and thinnings it is assumed that 70% of the sulphur in the fuel is bound to lime. The related NaOH consumption (for 100% reaction of H2S to Na+ and S2-) is given as well. It is assumed that Na2S is removed from the scrubber as a solid salt.

 Table 8. H2S flows in the fuel gas and corresponding NaOH consumption for 100% sulphur removal.

  Demolition wood

Sludge/wood mixture

       

 

 

 

 

 

 

mass flow H2S in the fuel gas (g/sec)

0.55

3.57

3.94

1.64

3.57

Corresponding NaOH consumption (kg/hour)

2.31

15.08

16.64

6.92

15.08

 

- Heavy metals will evaporate partly in the gasifier, most probably to a far greater extent than would happen under combustion conditions. The reducing atmosphere will prevent oxidation of the metals allowing more evaporation in metallic form. Cooling will condense the metals. All condensation temperatures are above 140oC which is the temperature level to which the gas is cooled before it is passed through the baghouse filter. At the moment of writing no experimental data are available on behaviour of heavy metals under gasification conditions but it seems likely that all metals will condense out during gas cooling.27 Possibly some remaining metals will be washed out in the scrubber.

The gasifier ash and the fly ash will contain the heavy metals that were present in the fuels. The distribution of the various metal will depends on the gasification temperature and the type of fuel. Volatile metals (lead, cadmium, mercury) will concentrate in the fly ash since they evaporate to a greater extent and condense during gas cooling.53

 - No analysis was made of the emission of fluorides, but the figures available for the fluoride content in demolition wood (less than 0.00003 wt% dry matter26) are extremely low.

 The most important unknown factor for the emissions is the flue gas dryer. The flue gas entering the drier at a temperature of approximately 200oC will cause organic compounds to evaporate and will lead to the formation of dust in the dryer. To reduce dust emissions the flue gas will be passed through cyclones (which is standard equipment for such dryers). The level of hydrocarbon emissions is unknown; possibly additional filters or water scrubbers will be required to meet emission standards.

Another option is to use a steam dryer, which has no effect on the system efficiency31 but dries the fuel indirectly thus preventing emission of dust and hydrocarbons. The main disadvantage of using steam drying is that investment costs will increase. In addition more waste water will be produced (although this can be led to a central waste water treatment facility). In this study we consider the conventional rotary dryer, taking investment costs for filters into account.

Also from storage (smell) and from the wet scrubber (waste water) emissions will occur As discussed the scrubber water will contain ammonia, which is the main contaminant. The presence of other compounds and possibly metals will depend on the fuel, although the foregoing gas cleaning steps in principle remove tars, dust and metals. Experimental data on this issue are lacking at the moment.

The ash stream from the gasifier and the baghouse filter is another emission from the system. Ash from clean wood like thinnings could be used as fertiliser, although this will depend on specific standards applicable. Contaminated fuels (like waste wood and sludge) will produce ash that has to be landfilled.

 A BIG/CC system capable of converting a wide variety of fuels, needs to be equipped with a two-stage scrubber with two adsorption units (one with water or acid for ammonia removal and one with an alkaline for sulphur removal). This will increase investment costs and, depending on the fuel, lead to the consumption of NaOH (and H2SO4).

The extent to which sulphur is bound to dolomite and the degree to which fuel nitrogen is converted to molecular nitrogen have to be investigated in more detail in relation with gasification conditions and dolomite quality. However, the behaviour of the tar cracker is very promising in these perpects.44

With the proposed gas cleaning concept, the BIG/CC system seems to be capable of meeting the severe emission standards for waste incineration.

 

4. COST ANALYSIS

(All cost figures mentioned are given in ECUs of 1995. Cost figures were generally obtained in Dutch guilders and converted to ECUs (rate 1 Dfl. = 2.15 ECU (1995)).

 In this chapter the electricity production costs will be calculated and discussed with respect to the different biofuels. Investment costs, operation and maintenance costs and the costs of logistics for collecting and transporting the fuel will be presented and discussed. Costs will be presented in ranges for minimum and maximum electricity production or waste treatment costs. The discounting method used is based on annuity.

4.1 Investment costs

The investment costs are mainly determined by consulting manufacturers of various system components. Cost figures will, when possible and applicable, be presented in ranges so that uncertainties can be visualized. Total minimum and maximum investment costs are determined by summating the low cost per system component and low engineering costs for the minimum cost case and summating the highest component costs and high engineering costs for the maximum cost case. A first plant will involve high engineering costs. After a number of plants have been built, engineering costs are expected to drop.13 The high cost case should therefore reasonably represent the costs of a first commercial plant, the low cost case the costs of a plant after a number of similar (identical) plants have been built. The costs of a first unit however, may well lay above the maximum cost level given here, since uncertainties in the performance, required testing programs and potential higher costs because of specified guarantees which are a crucial aspect for a new system.

Vendor quotes are used for all system components, except the gasifier and tar cracker, because only a small number of these components have been realized till present. Concerning the gasifier, expert opinions are used to estimate the costs of a gasifier based on the TPS-concept. With additional information about the size, materials used and process conditions of an existing similar gasifier (in Grève, Italy) a cost estimate is made using known factors for steel and cement processing for comparable process equipment such as hot blast furnaces. The investment costs of the tar cracker are assumed to be equal to the gasifier since the design and size are similar as well. The uncertainties of such exercises are large but exclude the engineering and development costs.

Other relevant cost factors such as civil works, control systems and interest during construction are obtained from cost data of comparable installations.

The investment costs of the system components are given in table 9. Where possible ranges are given.

Table 9. Costs of system components in millions of ECUs.

 

Component costs

(MECU's)

Percentage of investment costs

Explanatory notes

 

min

max

min

Max

 

Pre-treatment

 

 

 

 

 

conveyers

0.26

0.26

0.6%

0.4%

Assuming total 100 m of conveyers is required on the terrain. Cost figures from9

grinding

0.3

0.3

0.7%

0.5%

Cost figures from30

storage

0.74

0.74

1.7%

1.3%

Assuming storage capacity is sufficient for five days full load operation. Cost figures from17.

dryer

3.5

5.6

7.8%

9.3%

Cost range taken from30. A wide cost range is found for dryers.

Gasification system

 

 

 

 

 

gasifier

1.4

2.3

3.1%

3.9%

Cost estimate based on estimated volumes of lining and steel, evaluated with comparable equipment such as hot blast furnaces and data from the TPS gasification plant in Grève Chianti.5

tar cracker

1.4

2.3

3.1%

3.9%

Investment costs of the tar cracker assumed to be equal to the gasifier, because of similar size, design and process conditions.

cyclones

0.9

1.9

2.1%

3.1%

Cost estimate for four cyclones with the same lining as the gasifier and tar cracker.

fuel feeding

0.3

0.3

0.6%

0.5%

Two double screw feeders with rotary valves required. Costs figures taken from30.

Gas cleaning

 

 

 

 

 

gas cooling

2.1

2.1

4.8%

3.6%

 

baghouse filter

1.2

1.2

2.6%

2.0%

Cost figures from48.

condensing scrubber

0.9

1.9

2.1%

3.1%

Range for a single or two-stage scrubber. Investment costs for wet gas cleaning are increased by 1 million ECU when additional measures are required to remove large quantities of sulphur and nitrogen.47

Compressor

1.4

1.9

3.1%

3.1%

Cost figures from34.

Combined Cycle

 

 

 

 

Cost figures for the combined cycle and components from29,31.

gas turbine

9.3

11,6

20.8%

19.5%

STIG version LM 2500 including generator

modifications LCV gas

0.5

0.9

1%

1.6%

Additional costs for adaptations to LCV gas

HRSG

2.4

2.4

5.4%

4.1%

HRSG for modest steam conditions of 40 bar.

Steam turbine + condensor

3.2

3.2

7.2%

5.4%

 

water + steam system

0.3

0.3

0.6%

0.4%

 

cooling

0.3

0.3

0.6%

0.5%

Presence of surface water is assumed, no cooling tower required.

'Overall'

 

 

 

 

 

control systems

4.7

2.3

10.4%

3.9%

The degree of automation determines the costs of the control system. For a combined cycle alone 0.5 - 9 MECU is possible.29 The range given here is an assumption. More extensive control implies fewer personnel for operating the plant which is the reason why the low costs are given for the maximum cost case.

civil works

3.5

4.2

7.9%

7%

Percentage of total investments45

electrical system

2.8

3.4

6.3%

5.6%

Percentage of total investments45

buildings

0.3

0.3

0.7%

0.5%

Assuming that an office, laboratory and porters building are required. Based on9

engineering 3 - 4% of total investment costs

1.1

1.7

2.4%

2.8%

Engineering costs at level for electricity generation plants, assuming known technology is used.55

project contingency

-

5.1

-

8.6%

Project contingency is only included in the high cost estimate; 10% of investments.

Interest during construction

1st year

0.4

0.8

1%

1.3%

Expected construction time two years; investment in first year 25% of total.

idem 2nd year

1.3

2.3

2.9%

3.9%

Investment in second year 75% of total.

Total investment costs

44.6

59.7

 

 

 

 

Figure 2 presents the breakdown of investment costs for the high cost case (clean wood as fuel). In this case a substantial project contingency is included, which is expected to be unnecessary in the low cost case where it is assumed that a number have been built already. The total investment costs range from 45 - 60 million ECU.

 

Figure 2. Breakdown of investment costs (high cost case) for the selected ACFB/CC system based on the GE LM 2500 as obtained in this study. Total investment costs amount 60 million ECU1994. 'Overall' covers civil works, engineering, buildings and piping.

The gasifier and cracker do not dominate the overall investment costs; they represent 9 - 12% of the total. The Combined Cycle unit which represents one third of the investment costs, is the major component. The entire pre-treatment system is a significant cost factor as well (between 10 - 12% of total investment), although uncertainties on this part are large. However, when only one type of biofuel is used, the pre-treatment could remain relatively straight forward. However, when a variety of very different fuels is to be applied, different feeding lines might be required which will increase investment costs, Especially possibly required densification or even pelletising equipment for a fuel like verge grass would raise the costs of the pre-treatment (Pelletising is an expensive pre-treatment option. Feenstra et al. report pelletising costs of about 8 ECU/tonne when done at the conversion facility itself.17 This excludes drying. Only pelletising (excluding drying) of wood and other biomass residues in a separate facility (20-40 ktonne capacity/year) cost about 15 ECU/tonne.57

However, densification may well be sufficient for feeding fluffy biomass material to gasifier operating at near atmospheric pressure. Such feeding would also be favoured from energy point of view since pelletising requires substantial electricity and heat input. More practical experience with fluff feeding of fuels like verge grass and organic wastes is desired). Costs might also increase because of required additional equipment attached to the dryer to prevent the emission of dust and smell, although the investment costs of the dryer already include various filters.

The costs of land and possibly of additional infrastructure are not taken into account. These factors depend strongly on the exact location of a conversion unit.

4.2 Operational costs

The costs of operation include: personnel, maintenance and insurance. Variable costs relating to the operation of the plant are costs of the catalyst (dolomite) and costs of ash disposal, which can both be derived from the gas composition data in table 2. Water use and costs of waste water treatment and additives are included when necessary. Relevant costs figures for the operation of the plant are given in table 10.

Table 10. Costs of operation; input parameters for Dutch conditions.

 Cost category

Costs

Description, assumptions and sources

maintenance

2% of investment costs per year

Assumption based on normal operation of power plants.55

personnel

32,500 ECU per person per year

5 crews of 2 - 4 persons for shift work

4 persons other activities. With a more advanced control system fewer personnel are required.

water

0.37 - 1.4 ECU/m3

Water consumption is expected to be minimal. The steam system is a condensing system and the waste water stream from the scrubber is expected to equal the condensed water from the fuel gas.9

dolomite

27.9 ECU/tonne

Dolomite consumption is given per stream in.25

ash disposal

46.5 ECU/tonne

ash disposal costs will vary with location and degree of contamination. Tariffs for landfilling will be increased to the level of waste incineration (116 ECU/ton).1

NaOH

1302 ECU/tonne

Cost figure for bulk quantities of solid NaOH.54

insurance

1% of annual depreciation

Data from composting and digestion plants.22

 

Figure 3 presents the annual operational costs per fuel, assuming base load operation (75% load factor in the maximum cost case and 85% in the minimum cost case).

It is assumed that NH3 and sulphurs can be removed by several wet scrubbing steps. Although additional investment costs for extensive scrubbing are included in the economic evaluation a more detailed study of this component is desired.

 4.3 Logistics

 he results of a logistic study concerning the supply of biomass waste streams for a BIG/CC unit in the Province of Noord-Holland are used.17 To calculate the costs of the fuel, including transport, a number of assumptions were made regarding average transportation distances, location of the conversion facility, source location of the fuel, supply patterns of fuels and type of transport. Other relevant aspects which are taken into account are drying during storage, costs and capacity of storage and pre-treatment (chipping or pelletising) of fuel before it reaches the conversion facility. These data have been calculated for a number of potential fuels (thinnings, prunings, demolition wood, waste paper and sludge). To determine the average transportation distances, several locations for the BIG/CC system and various source locations were selected. In general these distances are substantial (75 km one way for thinnings, which covers a large part of the Netherlands). In general it is concluded that transport by road, central storage and pre-treatment (at the conversion facility) is the cheapest route. Here, the minimum cost scenario's for transport, storage and pre-treatment are used for further calculations. For the collection and transport costs of organic domestic waste and verge grass other sources are used.28,37,46

 Figure 3. Breakdown of the calculated minimum and maximum operation and maintenance costs of electricity production with the selected ACFB/CC system as a function of the fuel. Differences are caused particularly by ash disposal costs. Ash disposal costs for thinnings can be zero when the ash is used as fertilizer, although this is not shown in the graph.

 Table 11 summarizes the minimum cost scenarios for logistics regarding the selected fuels. Pre-treatment of wastes before it reaches the central facility is logically possible49, but in all cases central pre-treatment is cheaper and costs of chipping and drying are therefore included in the conversion costs.

 4.4 Cost of electricity and waste treatment

 The calculated minimum and maximum costs of electricity and waste treatment are given in table 13. Real interest rates, lifetime, load factor and construction time are given in table 12. The minimum costs scenario shows the cases in which all parameters (investments, fuel costs, costs of logistics, load factor, etc.) are the lowest. The maximum cost cases represent the results in which all parameters result in the highest costs. For verge grass, organic domestic waste and the sludge-wood mixture, additional investments are included to cover a more extensive scrubbing unit.

Table 11. Minimum cost scenarios for logistics: all transport by road and all pre-treatment centralized at the gasification plant.

 

Thinningsa

Verge grass

ODWc

Demolition woodb

Sludge

assumed moisture content (%)d

50

60

54

15

20

density (ton dry matter/m3)

0.15

0.16

0.5

0.213

0.56

average transport distance (km) (two way)

150

 

30 - 50

89

58

Transport costs (ECU/wet tonne)e

5.44

4.65 - 9.30

6.97 - 11.62

3.22

2.11

transfer & storage costs (ECU/wet tonne)f

0.29

0.32

0.22

0.63

0.23

Total costs logistics (ECU/wet tonne)

5.73

4.97 - 9.62

7.19 - 11.84

3.85

2.34

 aThinnings are expected to be delivered as chips. Partial storage at lower landing (in the forest) is assumed.

bWaste wood is expected to be delivered in shredded form. Costs of shredding are already included in the fuel costs (presented in table 1). The material is supplied by specialized companies.23,24

cTransport costs for ODW are relatively high since they include the collection of waste in residential areas and the high moisture content46. Also for verge grass the costs are relatively high because of high moisture content and inclusion of hauling costs (mowing).28,37

dMoisture content assumed for transport costs. Especially for sludge and verge grass the moisture content can vary considerably.

eRoad transport is in all cases more economic. Specific data for road transport in the Netherlands: for a capacity of 25 ton or 80 m3 the costs are 0.91 ECU/km with an average speed of 50 km/h.17

fTransfer costs are 0.16 ECU/m3 (capacity 170 m3/h) for a shovel and 0.11 ECU/m3 (capacity 275 m3/h) for a crane.17 One transfer is assumed for all fuels.

 

Table 12. General economic parameters and assumptions as used in this study.

  

minimum cost case

maximum cost case

Real interest rate (%)

4

6

Expected lifetime of the plant (years)

25

20

Load factor

0.85 (7400 hours)

0.75 (6750 hours)

Construction time (years)

2

2

 

Figure 4 shows the breakdown of (annual) electricity production costs in capital cost, operation and maintenance cost, fuel cost and logistics. For thinnings the fuel costs represent half of the electricity production costs. All other fuels in the minimum cost case show that strongly negative costs biomass wastes compensate all other costs. Figure 5 shows the electricity production costs in ECU/kWh assuming the negative value of the fuel (that represent waste treatment costs) serves as income to the plant. This leads to wide ranges in, and potentially negative, electricity production costs.

The costs of electricity (COE) cover a wide range, namely from minus 6.7 up to plus 8.6 ECUct/kWh. When the fuel costs are set at zero, electricity costs are 2.9-4.8 ECUct/kWh compared to 4 ECU ct/kWh for average Dutch electricity production cost (in 199435).

 Table 13. Results for the selected fuels. Outcomes are presented in ranges based on the uncertainties (ranges) about investment costs, ranges of (negative) fuel costs, transport and other parameters.

 

Clean wood

(thinnings)

Verge grass

Organic Dom. Waste

Demolition wood

Sludge and wood mixture

 

min

max

min

max

min

max

min

max

min

max

Biomass fuel

 

 

 

 

 

 

 

 

 

 

fuel cost (ECU/wet ton)

27.9

32.6

-60.5

7.0

-65.1

-27.9

-116.3

-9.3

-109.7

-16.8

moisture content (w.b.)

50

50

60

60

54

54

20

20

20

20

ash content (d.b.)

1.32

1.32

9

9

18.9

18.9

0.9

0.9

8.2

8.2

LHV (GJ/wet ton)

7.74

7.74

5.41

5.41

5.88

5.88

13.86

13.86

12.3

12.3

Total cost of logistics

(ECU/wet ton)

5.73

5.73

4.97

9.62

7.19

11.84

3.85

3.85

3.42

3.42

System parameters

 

 

 

 

 

 

 

 

 

 

LHV efficiency (%)

40.3

40.3

39.0

39.0

36.3

36.3

40.1

40.1

35.4

35.4

fuel input (wet ton/hour)

33.5

33.5

45.8

45.8

43.2

43.2

19.0

19.0

23.9

23.9

fuel input (MWth)

72.0

72.0

68.8

68.8

70.6

70.6

73.1

73.1

81.9

81.9

net power output (MWe)

29.0

29.0

26.8

26.8

25.6

25.6

29.3

29.3

29.0

29.0

dolomite consumption (ton/hour)

1.13

1.13

0.90

0.90

1.07

1.07

1.77

1.77

2.01

2.01

total ash production (ton/hour)

1.4

1.4

2.6

2.6

4.8

4.8

1.9

1.9

4.2

4.2

NaOH required kg/hour)

2.3

2.3

15.1

15.1

16.6

16.6

6.9

6.9

15.1

15.1

Costs of operation

 

 

 

 

 

 

 

 

 

 

maintenance (kECU/yr)

893

1,195

893

1,195

893

1,195

893

1,195

893

1,195

personel (kECU/yr)

456

781

456

781

456

781

456

781

456

781

dolomite (kECU/yr)

234

208

186

166

220

195

365

324

415

369

ash disposal (kECU/yr)

467

414

878

779

1,659

1,473

655

582

1,437

1,276

NaOH consumption (kECU/yr)

22

20

145

129

160

142

67

59

145

129

insurance (kECU/yr)

29

52

29

52

29

52

29

52

29

52

Total oper. costs (kECU/yr)

2,100

2,670

2,611

3,129

3,441

3,867

2,464

2,993

3,253

3,829

fuel costs (kECU/yr)

6,914

7,161

-20,473

2,097

-20,816

-7,921

-16,331

-1,160

-19,424

-2,709

costs logistics (kECU/yr)

1,420

1,260

1,683

2,892

2,301

3,363

542

481

607

539

Fuel costs at plant (kECU/yr)

8,333

8,422

-18,790

4,990

-18,516

-4,558

-15,789

-678

-18,817

-2,170

Reimbursementsb

 

 

 

 

 

 

 

 

 

 

produced electricity (kECU/yr)

5,197

4,614

4,803

4,264

4,582

4,068

5,246

4,657

5,192

4,610

installed power (kECU/yr)

2,836

2,836

2,621

2,621

2,500

2,500

2,863

2,863

2,833

2,833

Total (kECU/yr)

8,033

7,450

7,424

6,886

7,082

6,568

8,108

7,520

8,025

7,443

Total investment costs (kECU)

44,632

59,734

45,802

61,051

45,802

61,051

44,632

59,734

45,802

61,051

Depreciation costs (kECU/yr)

2,857

5,208

2,932

5,323

2.932

5,323

2,857

5,208

2,932

5,323

Main economic parameters

 

 

 

 

 

 

 

 

 

 

kWh costs (ECUct/kWh)a

6.2

8.5

-6.7

7.6

-6.4

2.8

-4.8

3.9

-5.9

3.7

ECU/kW installed

1537

2057

1707

2275

1789

2385

1523

2038

1579

2105

Waste treatment costs (ECU/ton)

-12

2

-6

5

-2

9

-20

6

-10

11

 a Calculated power production costs include the present biomass fuel cost levels, which are negative in the case of verge grass, ODW, demolition wood and sludge. The calculated waste treatment costs show that those streams have a value (negative treatment costs) as a fuel: the reimbursements from electricity production are higher than the depreciation and operation and maintenance costs. When this value is recognized the (negative) cost of the fuel might increase, especially when large quantities of a stream are utilized.

b Reimbursement levels for electricity produced decentrally are 2.42 ECUct/kWh and 98 ECU/kWe installed.50,51

 

Figures 6 and 7 show the sensitivity of the electricity production costs to variation in various parameters. The best way of reducing the COE is to increase the system efficiency. An increase in efficiency up to 50 percent points will bring the COE down by 25%. Such an improvement is possible with improved system integration and gas turbines, (possibly with intercooling). A high load factor (and high reliability) is crucial for obtaining low electricity production costs.

Figure 4. Breakdown of the minimum and maximum calculated yearly costs of electricity production with the selected ACFB/CC system as a function of the biomass waste and residue streams.

Figure 5. Minimum and maximum calculated value of the electricity production costs with the selected ACFB/CC system as a function of the fuel (including fuel costs).

Figure 6. Sensitivity of electricity production costs to load factor, lifetime, investment costs, net efficiency and interest rate. Percentual variations per parameter show the percentage change in the kWh costs. 100% represents the average case for all relevant parameters. Values used for this sensitivity analysis refer to the clean wood case.

Figure 7. Sensitivity of electricity production costs to the fuel price and to the distance over which the fuel and the fuel is transported. Values used for clean wood case.

Another important outcome is the low sensitivity of kWh costs to the transportation distance. Selected scenarios for various fuels already include substantial transport distances, but even when biomass is transported from all over the Netherlands (100 km diameter) the kWh costs are only modestly affected. The COE are obviously dominated by the fuel costs.

Waste treatment costs are calculated by considering the value of electricity produced by the plant. Reimbursement levels for decentrally produced power are 2.42 ECUct per kWh produced and 98 ECU per kW installed per year in the Netherlands.50,51 The results for the waste streams considered are given in table 13; also for thinnings, although this stream should not be seen as waste. In several cases the reimbursements paid for decentralised power production in the Netherlands, which thus serve as income to the facility, outweigh the costs of the plant operation. This results in negative waste treatment costs for all minimum cost cases.

The waste treatment costs (and efficiency) are compared with other state-of-the-art waste treatment options for organic waste in table 14. From the point of view of both efficiency and costs, gasification appears favourable compared to the main alternatives currently available.

Table 14. Comparison of the BIG/CC concept with composting, anaerobic digestion and large-scale waste incineration in the Netherlands with respect to waste treatment costs and conversion efficiency.

waste treatment option

costs per ton of waste treated [ECU/tonne)

efficiency of conversion to electricity (% LHV)

ACFB/CC concept in this study

- 20 – 11

35 - 40%

large-scale waste incineration1

56 – 111

12 - 22%

anaerobic digestion22

28 – 118

approx 12 %a

composting22

28 – 78

energy input approx. 30 kWh/tonne

 aThe net energy yield of digestion depends on the utilisation of the produced biogas. Utilisation in a gas engine is assumed here.

 

 5. DISCUSSION

 The main arguments for selecting the GE LM 2500 and an ACFB gasification process were that the BIG/CC system could be constructed in the near future and the system should be flexible enough to treat various biomass residues and wastes. This fixes the scale of the system and excludes other (pressurized and indirect) gasification processes. In the longer term other systems should be considered as well, especially for systems that are used for clean fuels only or for the production of methanol and hydrogen.

 The modelling has been performed relatively statically. For example, the behaviour of the gas turbine (combustion temperature, mass flows, behaviour in part load conditions and operation on LCV gas below 5.6 MJ/Nm3) is dealt with relatively simply. More sophisticated dynamic modelling, however, is not useful at this stage because more experimental data need to be collected first. Dynamic aspects of the system, such as system behaviour with fluctuating fuel gas compositions and heating values have to be investigated by testing, e.g. on pilot scale. A related issue is the extent to which the dryer can produce biomass with a constant moisture content and can be regulated to respond to fluctuations in the compostion (moisture and ash) of the biomass delivered. There is also the (slight) risk of dust explosion under certain conditions. Flue gas drying is selected here since it seems to be the cheapest and simplest way to reduce the moisture content of the biomass fuels. However, steam drying can provide a good (though somewhat more expensive) alternative when flue gas drying meets problems in this respect.

 Further improvements in the investigated system are possible. One shaft arrangement, a modified turbine combustion chamber and expander inlet, allowing higher combustion temperatures, higher steam temperatures and pressures, and especially scale-up are the main options to obtain higher efficiency and lower costs per kWh. Further system integration can lead to a better use of the available waste heat. On the longer term intercooling of the gas turbine compressor can be an interesting improvement option. The constraints on ash and moisture might be loosened to some extent by further system improvements. These improvements include heat recovery from the gasifier ash that allows higher ash contents, use of various waste heat sources for fuel drying that reduce waste hear requirements from the flue gas and especially modified combustor design that could allow fuel gas with lower heating values.

 From an environmental point of view the flue gas dryer is the most uncertain factor. Dust emissions can be controlled by using cyclones. Emission of hydrocarbons and possibly ammonia and other compounds might be too high unless precautions are taken. Experimental data are needed so that the emission levels for drying can be confirmed. Additional filters (for reducing dust and smell) might be necessary. Steam drying can also be considered, for it will hardly influence system efficiency, although it will increase the investment costs to a limited extent.31

 Investment costs are based on vendor quotes mainly. Uncertainties are included by presenting cost ranges and differences in engineering costs. The high cost estimate (2300 ECU/kW; for the most contaminated fuel) seems representative for a first fully commercial plant. The low cost figure (1500 ECU/kW) is an estimate of the obtainable cost level after a number of identical plants with this capacity (30 MWe) have been constructed. For comparison: Elliott13 suggests a cost level of 3000 U$/kWe-installed (2230 ECU/kW) for a first BIG/CC (25 MWe), potentially going down to 1300 U$/kWe-installed (970 ECU/kWe) for the tenth identical plant.

Not only lower investment costs but especially a further increase in efficiency will have a significant influence on the costs per installed kWe. The low cost estimate presented should therefore not be seen as the cost level for the longer term. In order to obtain insight in such figures further study on long term developments of system components and further system integration as discussed above is required.

Investment costs and operational costs might however increase when more extensive pre-treatment would be necessary. A multi-fuel plant might require different storage bunkers and sizing equipment. For example, experience with feeding fuels like grasses into gasification equipment is still very limited and densification might be required, which will increase handling costs. These aspects are mentioned only briefly here but deserve more attention.

Although logistics appeared to be a relatively small cost factor (especially in relation to the transport distance) it has been dealt with in a relatively simple way. The logistics can become quite complex, specially when a variety of biomass streams is involved. Organizational aspects, variations in availability, storage required and back-up fuel, especially in winter months, are issues that require more detailed study.

 A crucial factor in the overall economic performance are the (negative) biomass fuel costs. Negative biomass costs, due to present waste treatment costs, can even give rise to negative electricity production costs. However, future developments, and especially an increased demand for biomass residues for energy applications might increase those costs and thus affecting the COE. This aspect was not part of the analysis given here.

 

6. CONCLUSIONS

The BIG/CC atmospheric gasification process based on TPS gasification technology coupled to a General Electric LM 2500 gas turbine seems flexible enough to deal with a wide variety of fuel properties. 'Difficult' biomass fuels like sludge, with a very high ash content or very wet streams (or a combination of these such as organic domestic waste), can only be used to a limited extent and have to be mixed with cleaner materials.

The limits of what the proposed concept can handle are: ash contents 10-20% (for dry fuel) and moisture contents around 70% (for ash free fuels). These limits are due to the gas turbine which requires gas with a minimum heating value of 5.6 MJ/Nm3.

Model calculations for thinnings, verge grass, organic domestic waste, demolition wood and a wood-sludge mixture have yielded net system efficiencies that vary between 35.4 and 40.3% (LHV basis). These calculated efficiencies make it possible to compare the performance of the system when using different fuels. However, it should be noted that optimization of the system is still possible.

The system concept seems capable of meeting the strict environmental standards that are applicable to waste incineration in the Netherlands. The behaviour of the flue gas dryer is the most uncertain factor in this respect. If fuels like sludge, organic domestic waste and verge grass are used, H2S has to be removed from the fuel gas in order to meet emission standards. Adding a basic such as sodium hydroxide to the scrubber medium is an option. Ammonia has to be removed from the fuel gas in all cases to meet NOx standards. For a system capable of using a wide variety of biofuels a two-stage scrubber is recommended.

The investment costs cover a relatively wide range: 1500 - 2300 ECU/kW, with a total investment of 45 - 60 million ECU1995 for a 25 - 29 MWe plant. A first fully commercial plant (with still higher engineering and development costs) will be on the upper side of this range. When similar plants (of the same concept and scale) are built, engineering costs will become less important and the cost will be on the lower side of this range. Demonstration units, or installations which are semi-commercial and preceeding fully commercial facilities may however lead to cost levels above the mentioned figures becuase of required extensive testing and engineering. More experience with BIG/CC systems will rationalize the design and equipment costs. Major cost reductions for this concept seems especially possible by improving the conversion efficiency and thus lowering the costs per kWe-installed.

The calculated kWh costs vary between minus 6.7 to plus 8.6 ECUct/kWh. This very wide range is caused in the first place by the present very wide ranges of fuel costs.

In several cases (verge grass, demolition wood) negative fuel costs compensate for all other costs of the plant, which results in negative electricity production costs. The upper range represents a plant with investment costs at about 2060 ECU/kWe and thinnings for fuel (4 ECU/GJLHV, which is comparable to the projected costs for energy crops). The overall electricity production costs strongly depend on the fuel costs, but for most biomass available biomass wastes and residues in the Netherlands the COE can compete with current power production costs. Larger scale conversion units seem attractive because of the low sensitivity of the COE for the transportation distance and the importance of high efficiency, especially when high cost fuels such as thinnings or energy crops are used.

As a waste treatment facility the BIG/CC concept seems to be very attractive compared to other treatment options currently applied to biomass waste streams: landfilling, waste incineration, anaerobic digestion and composting. Costs per tonne of waste treated are far lower and the efficiency is highly favourable.

From this research it is concluded that gasification of biomass residues and waste streams is technically and economically feasible and is likely to cause limited environmental impacts. No fundamental technical problems hamper the implementation of this option. However, more experimental data on biomass drying with flue gas and gas turbine tests will have to be collected. Dynamic system behaviour (sensitivity for fluctuations in fuel gas quality and mass flows) and pre-treatment and feeding non-woody materials should be investigated by practical experience.

Acknowledgements - The authors are grateful for the sponsoring of CEC DG XII, within the framework of the EC JOULE II+ program. Co-sponsoring was provided by the Noord-Holland gasification project and NUTEK. The authors also wish to express their gratitude to the many people that provided information and discussed specific technical aspects. Special thanks are due to Chuck Nielson and Doug Shafer of General Electric, Arnoud Carp of Hoogovens Technical Services BV., Garrett Blaney of the Electricity Supply Board International, Erik Larson of the Princeton University and Bertil Prins and Harry Steenhuis of Thomassen Stewart and Stevenson International BV. The authors are grateful to Sheila McNab for linguistic assistance.

 

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