Liquid Fuels Production Cost and Performance

Scale is an important factor when considering coal (or biomass) to liquid transportation fuels. Larger scale plants mean lower costs per barrel of liquid fuel product. A 50,000 bpd liquid transportation fuels plant consumes over five times as much coal and emits over three times as much CO2 as does a 500 MWe IGCC power plant.

Yet, a plant of this size would produce less than ~0.3% of the U.S. daily liquid transportation fuels demand. The total life-cycle emission of CO2 from the coal to fuels process is markedly larger than for that for fuels derived from petroleum if carbon capture and sequestration (CCS) is not employed. Without CCS, FT synthesis of liquid transportation fuels emits about twice as much CO2, including the combustion of the fuel, as compared with crude oil-derived fuels. With CCS, the full life-cycle CO2 emissions for liquid transportation fuels produced from coal can be comparable with the total emissions from petroleum-based liquid transportation fuels. However, for liquid transportation fuels produced from coal or biomass, CCS does not require costly separation of CO2 as is required in power generation. Instead, the CO2 separation is a required, integral part of the process and thus, is included in the process and the cost of producing the fuel, independent of whether the CO2 is vented or compressed further, transported and geologically stored.

The cost and performance of various technologies for converting coal, biomass, and coal/biomass into liquid transportation fuels are summarized below. Several recent studies have evaluated the economics of both FT synthesis of fuels, and synthetic natural gas production [8-12]. For FT synthesis of fuels, reported capital costs ranged from $42,000 to $63,000/bpd capacity, of which the FT reactor and associated equipment accounted for from $15,000 to $35,000/bpd of the costs. These costs are for different dates in time and have different bases and assumptions, and different levels of performance. NETL recently expanded its estimates to include thermochemical production of liquid fuels from coal and biomass [13].

To obtain consistent updated estimates for liquid transportation fuels synthesis from coal and biomass, Williams and coworkers at the Princeton Environmental Institute [14] carried out an extensive design and evaluation study using the same cost bases and assumptions used for the estimation of power generation costs from coal and biomass summarized in Chap. 2. Tables 3.3 and 3.4 summarize the key parameters. Details of the work are covered in the paper on "Fischer-Tropsch Fuels from Coal and Biomass" [15]. Since the routes considered here involved gasification of the coal or biomass feedstock, the front part of the plant is the same as used for power generation from coal or biomass by gasification with the exception of size. This difference was typically accounted for by a different numbers of trains.

Table 3.3 Key economic and operating parameters used in estimates of conversion of coal and biomass to liquid transport fuels

Base year for capital costs, Gulf Coast

Mid-2007

Capital charge rate, % of total TPIa per year

14.4

Interest during construction (3 years), % of TPCb

7.16

O&M, % of TPC per year

4.00

Capacity factor of fuel plants

90%

aTPI is total plant investment = TPC plus interest during construction TPC is Total Plant Cost="overmight" capital investment to construct plant aTPI is total plant investment = TPC plus interest during construction TPC is Total Plant Cost="overmight" capital investment to construct plant

Table 3.4 Key analytical data on feedstocks used in estimates of conversion of coal and biomass to liquid transport fuels

Coal, Illinois #6, Herrin

Wt% moisture (AR) 11.1 Biomass, switchgrass

Wt% moisture (AR) 15

Gasification of coal utilized a GE/Texaco entrained-flow gasifier, and gasification of switch grass (or other biomass) utilized an oxygen-steam blown fluid-bed gasifier. Costs were updated to a 2007-cost basis using the Chemical Engineering Plant Construction Cost Index. Technology required for gas clean-up, for water-gas shift to achieve the desired H2 to CO ratio for synthesis, and that for the separation of CO2 from the H2 plus CO stream was then integrated into the technology chain. The required synthesis gas conversion technology (FT or methanol/MTG) was then integrated with the front-end of the process (gasification, clean-up, etc.), and the needed refining was added to the back-end to produce liquid transportation fuels that meet current fuel standards. Power generation technology was added to the back end to produce electricity from purge gas and other fuel gas streams. Mass and energy balances were carried out using Aspen Plus to allow sizing of the equipment. The typical process configuration involved recycle of the unconverted synthesis gas exiting the reactor, back to the reactor to increase conversion to liquid transportation fuels, referred to as recycle (RC). These RC cases included designs without geologic storage (venting the separated CO2, (V)) and with geologic storage of CO2 (CCS). Light-end hydrocarbon products and purge synthesis gas were burned in a power block to generate electricity. Some of the design options involved use of the unconverted synthesis gas after passing through the reactor once (no recycle) and gaseous hydrocarbons for enhanced power generation in a combined-cycle power block. These are referred to as "once through" or OT options. These OT configurations produce larger quantities of electric power (35+% for OT vs. ~ 10% for RC), in addition to liquid transportation fuels. The results for RC configurations are summarized in Table 3.5.

Table 3.5 Summary of cost and performance of coal and biomass to liquid transportation fuels process technologies: recycle cases producing maximum liquid fuels [14] key economic and operating parameters are given in Tables 3.3 and 3.4

Coal to liquids Via FT

Coal to liquids via MTG

Biomass to liquids via FT

Coal/biomass to liquids via FT

CO, Vented w CCS

CO, vented w CCS

CO, Vented w CCS

CO, Vented w CCS

Performance

Coal feed.

tonnes/day (AR) Biomass feed.

tonnes/day (AR) Plant efficiency.

%(LHV) Carbon in feed, kg/s Dissel. bbl/day Gasoline, bbl/day Power exported, MWs CO, captured and stored, kg/s Total CO, emitted per gal fuel, kg/gal Life-cycle CO, emitted, kg/gal Total fuel life-cycle CO,/LC petiCO, COSTS

Total plant Cost, m $ Specific plant cost, $bbl/day

24,300

28,700 21,300 427 0

25.4

24,300 0

28,700 21,300 317 338

11.5

20,800 0

50,000 147 0

2.08

21,100 0

50,000

1.17

25.30

2.90

26.2

10.6

1.23

5,740 4,260 74 73

11.2

(continued)

Table 3.5 (continued)

Coal to liquids Via FT

Coal to liquids via MTG

Biomass to liquids via FT

Coal/biomass to liquids via FT

CO, Vented

w CCS

CO, vented

w CCS

CO, Vented

w CCS

CO, Vented

w CCS

Inv. Charge, 2007 $/

8.42

8.53

7.37

7.49

12.43

12.65

11.34

11.52

C3J Fuel (LHV)

Cost cost @ $1.71/CJ

4.14

4.14

3.83

3.88

0.00

0.00

3.34

2.34

(HHV)

Biomass cost @ $5/GJ

0.00

0.00

0.00

0.00

11.88

11.88

5.24

5.24

(HHV)

Oper&Main @ 496

2.18

2.21

1.91

1.94

3.23

3.28

2.94

2.99

of TPC/year

Co-Product electricity

-2.26

-1.68

-1.08

-0.89

-2.07

-1.45

-2.57

-1.97

@ 6.0 c/kWh

CO, disposal Cost

0.00

0.49

0.00

0.43

0.00

1.29

0.00

0.89

Total fuel cost, $/GJ

12.48

13.71

12.00

13.86

25.47

27.66

19.30

21.01

(LHV)

Total fuel cost, $/gge

$1.50

$1.64

$1.44

$1.54

$3.05

$3.32

$2.31

$2.52

Breakeven oil price,

$56

$68

$47

$51

$127

$139

$93

$103

$/bbl

Cost of CO, avoided4

11

10

20

15

vs. Same

technology w/o

capture, $/tonne

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