Coalto Liquid Fuels

Figures 3.5, 3.6, and 3.7 show the process configurations for coal-to-liquid fuels using FT and MTG technologies in the recycle configuration with CO2 vented and with CCS. The only difference in the process configuration for the CCS case vs. the CO2-venting case is the addition of CO2 compression. For a facility producing 50,000 bbl/day of liquid transportation fuels, with the CO2 being vented, the total plant cost (TPC) is estimated at $4.9 billion or $97,600 per stream-day-barrel, which equals TPC/50,000 barrels per day. This results in a projected fuel cost of $1.50 per gallon of gasoline equivalent, gge1. The capital charge is the largest component in this cost, and coal cost is next largest component at about one-half the investment charge per gallon of gasoline equivalent (Table 3.5).

This results in a breakeven crude oil price2 of $56 per barrel for these cost and economic assumptions [16]. The addition of geologic CO2 storage (CCS) adds slightly to the total plant cost, the cost of the fuels produced, and the breakeven crude oil price, but these impacts are not large because the CO2 capture and separation is a required integral component of the fuels synthesis process whether or not CCS is practiced. The transport and geologic storage costs decrease with increasing amounts of CO2 transported and geologically stored using the latest cost estimates, and CTL plants produce very large amounts of CO2. These costs are significant but not a major cost of the fuels production. These costs could also change substantially with location. Thus, the cost of CO avoided3 is low, and is estimated to be about $11/tonne of CO. This is much less than the avoided cost for power generation which is in the $40/tonne of CO2eq range (IGCC).

Without CO2 compression, transport, and geologic storage, the CTL plant emits 1.8 times as much CO2 as is emitted in the combustion of the FT fuels produced in the plant. When the life-cycle greenhouse gas (LC GHG) emissions are estimated for petroleum-based diesel and gasoline produced from crude oil using the GREET model, and the LC GHG emissions are estimated for the FT fuels produced here, including GHG emissions in coal mining and in transportation4 [15, 18], the ratio

1 For mixed liquid products such as gasoline and diesel and for uniform comparison, all production costs were expressed in terms of $ per gallon of gasoline equivalent, gge.

2 The breakeven crude oil price (BEOP) is the crude oil price in $/bbl at which the wholesale price of the petroleum-derived products would equal the calculated cost of the production of the FT fuels on a $/GJ basis. The BEOP was determined by using the average difference between the crude acquisition cost and the wholesale price of the products between 1990 and 2003, in 2007 $. This averaged 32.3 0/gal for gasoline and 24.9 0/gal for diesel fuel (an additional 5 0/gal was added to account for the cost of producing low sulfur diesel ( [16], EIA, 2008)).

3 Cost of CO avoided is estimated as {[levelized FT liquid product cost (in $/GJ) for CCS design] minus [levelized FT liquid product cost for vent design]} divided by {[greenhouse gas emissions (in tonnes CO2,eq per GJ of liquid product) for vent design] minus [ greenhouse gas emissions (in tonnes CO2eq per GJ of liquid product) for CCS design]}

4 The non-conversion plant components of greenhouse gas emissions were estimated from GREET version 1.8. Production, transportation and refinery green house gas emissions for petroleum-derived fuels were also estimated from GREET. (Argonne National Laboratory, Transportation Technology R&D Center, 2008. The Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET ) Model [17]).

Pfd For Fischer Troph Process
Fig. 3.5 Schematic of a coal-to-liquid fuels plant using the Fischer-Tropsch synthesis process, with CO, venting [15, 17]
Fig. 3.6 Schematic of coal-to-hquid fuels plant using the Fischer-Tropsch synthesis process, with compression of CO, for transport and geologic storage [15, 17]

air u coal

Oxygen plant


Grinding & Slurry Prep*


Gasification & Quench

Syngas Scrubber

Water Gas Shift

Acid Gas Removal

~r slag gas cooling

Recycle Compr.

flue gas t recycled purge gas syngas

Power Island

^net export electricity

LPG + fuel gas

Methanol Synthesis

Methanol Recovery methanol.

MTG Reactor

^Finished Gasoline


Refrigeration Plant

CO, water

Flash ri h2s + co2

To Claus/SCOT


Fig. 3.7 Schematic of coal to gasoline process utilizing methanol synthesis followed by methanol to gasoline (MTG) technology [18]

of LC GHG emissions for the CTL fuels to that for the crude oil-based fuels is 2.18 (Table 3.5). If the CO2 that is already separated from the synthesis gas, as part of the synthesis process, is compressed, transported, and geologically stored, the ratio of the LC GHG emissions for the FT produced fuels to that for the petroleum-based fuels becomes 1.03. Thus, with geologic CO2 storage, coal-based liquid transportation fuels can be essentially equivalent to petroleum-based transportation fuels with respect to their LC GHG emissions.

This estimate is based on the assumption that the electricity sold to the grid displaces electricity, and its associated CO2 "content", generated by an IGCC power plant with CO2 venting in the case of an FT plant with venting; and displaces electricity generated by an IGCC power plant with CCS (90% removal) in the case of an FT plant with CCS. The CO2 accounting approach used for the electricity displaced can obviously change the ratio of LC GHG emissions for the FT fuels relative to the same amount of petroleum-derived fuels; but because the electricity output represents only about 12% of the product out on an energy basis, the impact is not large. Based on the plant configuration used here, the coal to liquid fuels process captures and sequesters about 85% of the CO2 that the plant emits without CCS. The ratio of LC GHG emissions for FT-derived fuels from CTL to that for petroleum-derived fuels could be less than 1.0 if changes in process configuration and operation were made to capture and sequester more CO2, but this would incur additional cost. The detailed design choices would be driven by economic analysis if there were no policy requirements on relative emissions for synthetic fuels production.

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