Performance and Cost Discussion

The tools used for this analysis were based on EPRI's BIOPOWER co-firing model [10]. Input requirements for the model include ultimate analyses of the fuels (chemical composition of the fuels), capacity factor for the power plant , net station capacity, gross turbine heat rate, and percent excess air at which the plant operates. The technical inpu t information used for the model was based on data from a representative Northeast power plant which intends t o implement biomass co-firing [2]. For a given biomass co-firing rate, the model calculates thermal efficiency, chang e in net heat rate, coal and biomass consumption, and reduced SO 2 and CO2 emissions.

The coal was assumed to contain 1.9% sulfur, compared to a 0.02% sulfur content for the biomass. Moisture contents were 7.2% for the coal and 21.5% for the biomass. Ash contents were assumed to be 8.8% for coal and 0.9% for

Table 2. Performance and cost indicators.

Base Case

INDICATOR

1997

2000

2005

2010

2020

2030

NAME

UNITS

+/- %

+/- %

+/- %

+/- %

+/- %

+/- %

Plant Size

MW

100

100|

150

200|

300

400|

General Performance Indicators

Capacity Factor

%

85

85

85

85

85

85

Coal Moisture Content

%

7.2

7.2

7.2

7.2

7.2

7.2

Biomass Moisture Content

%

21.5

21.5

21.5

21.5

21.5

21.5

Annual Energy Delivery

GWh/yr

745

745

1,117

1,489

2,234

2,978

Coal-only Performance Indicators

Efficiency

%

32.9

32.9

32.9

32.9

32.9

32.9

Net Heat Rate

kJ/kWh

10,929

10,929

10,929

10,929

10,929

10,929

Net Power Capacity from Coal

MW

100

100

150

200

300

400

Annual Electricity Delivery from Coal

GWh/yr

745

745

1,117

1,489

2,234

2,978

Coal Consumption

tonnes/yr

276,175

276,175

414,262

552,350

828,525

1,104,699

Annual Heat Input from Coal @ 31,751 kJ/kg

TJ/yr

8,138

8,138

12,206

16,275

24,413

32,550

TOTAL Annual Heat Input

TJ/yr

8,138

8,138

12,206

16,275

24,413

32,550

Biomass Co-firing Performance Indicators

Co-firing Rate (Heat Input from Biomass)

%

10

15

15

15

15

15

Thermal Efficiency

%

32.7

32.5

32.5

32.5

32.5

32.5

Net Heat Rate

kJ/kWh

11,015

11,066

11,066

11,066

11,066

11,066

Net Power Capacity from Coal

MW

90

85

128

170

255

340

Net Power Capacity from Biomass

MW

10.0

15.0

22.5

30.0

45.0

60.0

Annual Electricity Delivery from Coal

GWh/yr

670

633

949

1,266

1,899

2,532

Annual Electricity Delivery from Biomass

GWh/yr

74

112

168

223

335

447

Coal Consumption

tonnes/yr

250,525

237,695

356,542

475,389

713,084

950,778

Biomass Consumption (dry)

tonnes/yr

42,933

64,695

97,043

129,391

194,086

258,781

Annual Heat Input from Coal @ 31,751 kJ/kg

TJ/yr

7,382

7,004

10,506

14,007

21,011

28,015

Annual Heat Input from Biomass @ 19,104 kJ/kg

TJ/yr

820

1,236

1,854

2,472

3,708

4,944

TOTAL Annual Heat Input

TJ/yr

8,202

8,240

12,359

16,479

24,719

32,959

1. The columns for "+/- %" refer to the uncertainty associated with a given estimate

Table 2. Performance and cost indicators. (cont.)

INDICATOR NAME

UNITS

Base Case 1997

2000

2005

2010

2020

2030

Plant Size

100|

200|

400|

Capital Cost ($/kW of BIOMASS power capacity)

Biomass Handling System Equipment Conveyor

Separation Equipment, Conveyor Hogging Tower and Equipment Pneumatic Conveying System (Vacuum) Wood Silo with Live Bottom Collecting Conveyors Rotary Airlock Feeders Pneumatic Conveying System (Pressure) Controls Total Equipment

Biomass Handling System Installation Total Biomass Handling Civil Structural Work Modifications at Burners Electrical Subtotal (A)

Contingency @ 30%, 0.3 * (A) Total Direct Costs (B) Engineering @ 10%, 0.1 * (B) Total Capital Requirement

25 15 25

12.1

53.6 232.3

23.2 255.5

25 15 25

73.0

45.3 118.3

14.5 168.2

50.4 218.6

21.9 240.5

25 15 25

14.4

25 15 25

13.6

65.8

40.9 106.6

13.1 151.5

45.5 197.0

19.7 216.7

25 15 25

63.0

39.1 102.1

28.2

12.5 145.1

43.6 188.7

18.9 207.6

25 15 25

NOTES:

1. The columns for "+/- %" refer to the uncertainty associated with a given estimate

2. Plant construction is assumed to require 1 year for a retrofit to an existing system

Table 2. Performance and cost indicators. (cont.)

Base Case

INDICATOR

1997

2000

2005

2010

2020

2030

NAME

UNITS

+/- %

+/- %

+/- %

+/- %

+/- %

+/- %

Plant Size

MW

100

100|

150

200|

300

400|

Incremental Operation and Maintenance Costs; Incremental O&M = Biomass O&M

- Coal O&M ; Values in ( ) indicate negative costs (i.e., revenues).

Fuel Cost @ $9.14/dry tonne (biomass) *

^/kWh

(.820)

(.817)

(.817)

(.817)

(.817)

(.817)

Fuel Cost @ $51.48/dry tonne (biomass) *

^/kWh

1.622

1.635

1.635

1.635

1.635

1.635

Fuel Cost @ $9.14/dry tonne (biomass) T

^/kWh

(.439)

(.437)

(.437)

(.437)

(.437)

(.437)

Fuel Cost @ $51.48/dry tonne (biomass) T

^/kWh

2.002

2.016

2.016

2.016

2.016

2.016

Variable Costs

^/kWh

Consumables (incl. SO2 credit revenue) 1

(.163)

(.163)

(.163)

(.163)

(.163)

(.163)

Fixed Costs

$/kW-yr

Labor

5.00

5.00

5.00

5.00

5.00

5.00

Maintenance

5.43

5.11

4.81

4.61

4.33

4.15

Total Fixed Costs

10.43

10.11

9.81

9.61

9.33

9.15

Total Operating Costs

@ $9.14/dry tonne (biomass) *

^/kWh

(.842)

(.844)

(.848)

(.851)

(.855)

(.857)

@ $51.48/dry tonne (biomass) *

^/kWh

1.599

1.608

1.604

1.601

1.598

1.595

@ $9.14/dry tonne (biomass) T

^/kWh

(.462)

(.464)

(.468)

(.470)

(.474)

(.477)

@ $51.48/dry tonne (biomass) T

^/kWh

1.980

1.989

1.985

1.982

1.978

1.976

1. The columns for "+/- %" refer to the uncertainty associated with a given estimate

2. Plant construction is assumed to require 1 year for a retrofit to an existing system * Coal cost is assumed to be $39.09/tonne t Coal cost is assumed to be $28.05/tonne i SO2 credit revenues are calculated as follows, with SO 2 credits valued at $110/tonne SO2 = $100/ton SO2:

[(Coal-only - Co-firing) tonnes SO2/yr * (1 allowance/tonne SO2) + (2 allowances/GWh biomass power) * (GWh biomass power/yr)] * ($110/allowance) * (100 0/$) / (kWh biomass power/yr)

Projected annual SO2 savings for each year from 1997 to 2030 are $121,100, $181,600, $272,500, $363,100, $544,700, and $726,300, respectively.

biomass. The coal heating value was 31,751 kJ/kg (13,680 Btu/lb) (dry), while that for the biomass was 19,104 kJ/kg (8,231 Btu/lb) (dry). These values for sulfur, moisture, ash, and heating value were taken directly from tests conducted on the fuel supplies for the representative power plant. They are typical for eastern bituminous coal and hardwoo d biomass [11,12]. According to plant records, the gross turbine heat rate is 9,118 kJ/kWh (8,643 Btu/kWh). A capacity factor of 85% was used, based on historical records at the plant and projected future needs. The resulting estimate d net heat rate for coal-only operation is 10,929 kJ/kWh (10,359 Btu/kWh). This value is typical of high capacity factor coal boilers in the range from 100 MW to 400 MW, and was therefore assumed constant for all cases. Improvements in net plant heat rate for future coal plants were not considered in this analysis. The material and energy balances fo r the year 2000 case are shown in Figure 2.

All system capital costs are due to the retrofit of an existing pulverized coal boiler to co-fire biomass. Costs for th e 1997 case are based on engineering specifications, including materials and sizing of major system components, fro m a feasibility study for a corresponding 10 MW (biomass power) biomass co-firing retrofit at an existing plant [2]. The unit costs for the co-firing retrofit are expressed in $/kW of biomass power capacity, not total power capacity. For each following year, unit costs for larger co-firing systems were scaled down based on the relationship [13] : Cost(B) = Cost(A) * [MW(B) / MW(A)]s, where the scaling factor "s" was assumed to be 0.9. The effect of this scaling relationship is a 10% reduction in $/kW unit costs for a doubling in system capacity (MW). This corresponds t o observed economies of scale for coal power plants [14]. Since the system components are already commerciall y available and no major technological advances are expected, the only reductions in unit capital costs assumed to occur are due to economies of scale, not technological advancements or increased equipment production volumes.

Capital costs include costs for new equipment (e.g., fuel handling), boiler modifications, controls, engineering fee s (10% of total process capital), civil/structural work including foundations and roadways, and a 30% contingency [2] . Cost estimates for the example systems assume that front-end loaders and truck scales are already available at the plant for unloading and pile management. Costs also assume that live-bottom trucks are used for biomass delivery, allowing the avoidance of the purchase of a truck tipper. Land and substation (system interface) costs are zero because existing plant property and the existing substation will be utilized.

Operation and maintenance costs, including fuel costs, are presented in Table 2 on an incremental basis. That is, each O&M cost component listed there represents the difference in that cost component when comparing biomass co-firing operation to coal-only operation. Negative costs, surrounded by parentheses in the table, represent a cost saving in the co-firing operation relative to coal-only operation. Fixed operating costs are broken into two components, labor and maintenance. Estimates of both of these cost components are based on information obtained from plant managemen t at an existing co-firing operation [2]. Fixed labor costs are estimated based on a requirement for one additional operator for each 10 MW of biomass capacity (0.1 operator/MW). The operator manages the biomass deliveries , handling and processing equipment, and is compensated at a loaded rate of $50,000 per year. Annual fixe d maintenance costs are assumed to be 2% of the original capital cost of the co-firing retrofit [15]. Variable operation costs (consumables such as water, chemicals, etc.) are assumed to be the same for co-firing operation and coal-onl y operation, with the exception of the assumed value received for reduced SO2 emissions. The assumed value of an SO 2 allowance is $100/ton SO2 reduced ($110/tonne) and the value is assumed to remain constant throughout the analysi s period. It is also assumed that fossil-based CO 2 emissions savings hold zero financial value; however, this is subjec t to change and could have a large impact on the economics of a co-firing application.

It should be recognized that co-firing retrofit costs are extremely site-specific and can range from $50 to $700/kW [2,4] depending on many factors, including boiler type, amount of biomass co-fired, site layout, existing receiving equipment at the plant, complexity of handling and processing system design, nature of the biomass feedstock, etc. The example used in the present analysis provides a payback period of about three to four years (a typica l

Turbine-Generator Steam (16.5 Mpa, 538 C, 343, 842 kg/hr)

Emissions tonnes/day Flue Gas 12,513 CO2 2,337 SO2 29.2 Net MW Nox 6.9

1000 Partie. 0.4

Turbine-Generator Steam (16.5 Mpa, 538 C, 343, 842 kg/hr)

Comb. Air 12,792.0 tonnes/day

Fly Ash 58.7 tonnes/day

Gypsum Water 0.0 Limestone 0.0 tonnes/day 0.0

tonnes/day

Bottom Ash Coal 14.0 Biomass

766.0 tonnes/day 208.0 tonnes/day tonnes/day

Comb. Air 12,792.0 tonnes/day

Fly Ash 58.7 tonnes/day

Gypsum Water 0.0 Limestone 0.0 tonnes/day 0.0

tonnes/day tonnes/day

Bottom Ash Coal 14.0 Biomass

766.0 tonnes/day 208.0 tonnes/day tonnes/day tonnes/day

Energy Balance

Baseline

Alt. Fuel

Material Balance

Baseline

(GJ/hr)

Coal Only

Cofired

(Mg/hr)

Coal Only

Heat In

Mass In

Coal

1092.9

940.6

Coal

37.1

Wood Blend

__1_6_6_0

Residues

Total

1092.9

1106.6

Limestone

0.0

Heat Out

FGD Water Makeup

0.0

Net steam turbine output

360.1

360.1

Combustion air

_525_3

Auxiliary power use

23.0

23.0

Total

562.4

Condenser

587.0

587.0

Mass Out

Stack gas losses

97.6

112.1

Bottom ash

0.7

Boiler radiation losses

3.4

3.4

Fly ash

2.8

Unburned carbon losses

5.5

4.4

Gypsum

0.0

Unaccounted for boiler heat loss

16.4

___16._6

Flue gas

_5_58_9

Total

1092.9

1106.6

Total

562.4

Plant Performance

Annual Performance

Net Capacity, MW

100.0

100.0

Capacity Factor, %

85.0

Boiler Efficiency, %

88.8

87.7

Coal, 1000 tonnes/yr

276.2

Net Heat Rate, kJ/kWh

10,929

11,066

Alt. Fuel, 1000 tonnes/yr

Thermal Efficiency, %

32.9

32.5

Capacity Factor, %

85.0

85.0

Figure 2. Material and energy balances for 100 MW (Nameplate) boiler at 15% biomass co-firing (see year 2000 case) [10]. Moisture contents were 7.2% for the coal and 21.5% for the biomass.

requirement for capital expenditures by plant managers)--i.e., it represents a realistic installation under presen t economic conditions-assuming a biomass residue supply is available for $9.14/dry tonne ($8.29/dry ton , $0.50/MMBtu) and coal costs at the plant are $39.09/tonne ($35.46/ton, $1.40/MMBtu). The economics are less favorable for coal costs less than $39.09/tonne, especially in areas of the Midwest where prices are as low a s $28.05/tonne ($1.00/MMBtu). More expensive systems which do not provide a similar payback will likely not b e implemented unless the capital expenditure decisions are heavily influenced by other factors such as providing service to a valuable customer, or achieving emissions reductions. To demonstrate the effect of various biomass and coal prices on overall incremental operation and maintenance costs, three more fuel price scenarios are shown in Table 2. Th e fuel price scenarios are:

1. $9.14/dry tonne ($8.29/dry ton, $0.50/MMBtu) biomass costs and $39.09/tonne ($35.46/ton, $1.40/MMBtu) coal costs--This represents an economic scenario where abundant sources of biomass residues are available at a chea p price, while coal prices are near the national average. The resulting simple payback periods range from 4.3 year s for the 1997 base case to 3.3 years in 2030. Under these financial circumstances, a biomass co-firing retrofit i s marginally economical with no additional environmental subsidies. An environmental credit equivalent t o $3.31/tonne ($3.00/ton) of reduced fossil CO 2 emissions would result in a three year simple payback period fo r the year 2000 case.

2. $51.48/dry tonne ($46.70/dry ton, $2.84/MMBtu) biomass costs and $39.09/tonne ($35.46/ton, $1.40/MMBtu) coal costs--This represents an economic scenario where energy crops are the biomass fuel and coal prices are near the national average. Under these financial circumstances, a co-firing retrofit will not pay off without additiona l environmental subsidies. An environmental credit equivalent to $31.42/tonne ($28.50/ton) of reduced fossil CO 2 emissions would be necessary to obtain a three year simple payback period for the year 2000 case.

3. $9.14/dry tonne ($8.29/dry ton, $0.50/MMBtu) biomass costs and $28.05/tonne ($25.45/ton, $1.00/MMBtu) coal costs--This represents an economic scenario where abundant sources of biomass residues are available at a chea p price while coal prices are low. The resulting simple payback periods range from 7.9 years for the 1997 base case to 5.8 years in 2030. Under these financial circumstances, a co-firing retrofit will not pay off without additiona l environmental subsidies. An environmental credit equivalent to $7.72/tonne ($7.00/ton) of reduced fossil CO 2 emissions would be needed to achieve a three year simple payback period for the year 2000 case.

4. $51.48/dry tonne ($46.70/dry ton, $2.84/MMBtu) biomass costs and $28.05/tonne ($25.45/ton, $1.00/MMBtu) coal costs--This represents an economic scenario where energy crops are the biomass fuel and coal prices are low. Under these financial ci rcumstances, a co-firing retrofit will not pay off without additional environmental subsidies. An environmental credit equivalent to $35.82/tonne ($32.50/ton) of reduced fossil CO2 emissions would be needed to achieve a three year simple payback period for the year 2000 case.

It should be noted that cheaper alternatives for biomass co-firing exist. While high percentage co-firing in pulverize d coal boilers represents a large potential market, it is also one of the most expensive co-firing arrangements. In the near term, less costly alternatives such as low percentage co-firing in pulverized coal boilers, low- or mid-percentage co -firing in cyclone boilers, or co-firing in stoker or fluidized bed boilers may be more attractive. Capital costs for thes e options could be less than $50/kW of biomass power capacity. At a capital cost of $100/kW of biomass powe r capacity, the fuel price scenarios described in cases 1 and 3 above would result in simple payback periods of 1.5 an d 2.7 years, respectively, without additional environmental credits.

For each fuel cost scenario, biomass costs are assumed to remain constant (in 1997 dollars) in future years. The 100% residue scenario (#1 from above) is a likely one for the early years of a co-firing retrofit since, in the absence of greater monetary values for SO2 (and CO2) emissions reductions, a cheap source of residue fuel will be required to return th e capital investment in an acceptable period of time (three years or less). A more dependable--but likely more expensive-feedstock in future years may be provided by dedicated energy crops. Once the capital costs have been paid off by fuel cost savings gained from using cheap residues in the initial years, feedstocks from dedicated energy crops may be combined with the remaining available cheap residues.

Coal costs are assumed to remain constant (in 1997 dollars) through future years based on projected stable coal prices [5]. The base year price of $39.09/tonne ($35.46/ton) is near or less than the 1995 average delivered coal price for the following census regions: New England, Middle Atlantic, East North Central, South Atlantic, West South Central, and Pacific Contiguous [16].

It should be recognized that, in a competitive restructured power industry, a major advantage of co-firing is fue l diversification. Plant management will use the fuel mix which will provide the overall lowest production costs onc e all fuel prices, O&M costs, environmental credits, and tax benefits are considered.

Effluent estimates (see Table 3) were derived using ultimate analyses and material balances (material and energ y balances for the year 2000 case were provided in Figure 2). In Table 3, effluent estimates are shown for each year for coal-only operation, co-fired operation, and net reductions due to co-firing. Sulfur dioxide emissions, fossil fuel based carbon dioxide emissions, and ash discharges are all reduced by co-firing. Total estimated emissions of CO 2 from the stack show an increase when co-firing (due partially to the increased net heat rate when co-firing); however, if energ y crops are used as the fuel source, the net CO2 emissions on a full fuel cycle basis will be decreased due to th e absorption of CO2 from the atmosphere by the crops during their growth.

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