1. Toward BECCS Market Launch via Biomass/Fossil Fuel Coprocessing to Make Synfuels in CO 2 EOR Applications Robert H. Williams Princeton Environmental Institute Princeton University Princeton, NJ USA Presented at Bioenergy and CCS (BECCS): Options for Brazil University of Sao Paulo Sao Paulo, Brazil 13 June 2013

2. Overview Key technological components for BECCS systems can be launched in market and their costs bought down (via LBD) without a carbon policy in systems: – Using captured CO 2 for enhanced oil recovery (NCC, 2012); – Making synthetic fuels or synthetic fuels + electricity via fossil fuel/biomass coprocessing (Liu et al., 2011), exploiting: Scale economies/low average feedstock prices; Inherently low CO 2 capture costs compared to power-only systems; Large economic rents captured for synfuels at high crude oil prices. The economic basis for this argument is presented. It is suggested that a cane residue/shale gas coprocessing option to make low-C synfuels with CCS might be of particular interest to Brazil.

3. Acronyms BTLBiomass to Fischer-Tropsch liquid (FTL) fuels (diesel and gasoline) XBTL-Y%Biomass + X [X = G (natural gas) or C (coal)] to FTL fuels, with Y% biomass XBTLE-Y%X + biomass to FTL fuels + electricity, with Y% biomass EtOHCellulosic ethanol XIGCCIntegrated gasifier combined cycle power plant, where X = B (biomass) or C (coal) NGCCNatural gas combined cycle power plant -VEnergy conversion plant that vents all CO 2 -CCSEnergy conversion plant that captures CO 2 GHGIThe greenhouse gas emissions index) ≡ ratio of “cradle-to-grave” GHG emissions for system to emissions for conventional fossil energy displaced. The latter are assumed to be electricity from new supercritical coal plants venting CO 2 (Sup PC-V) and the equivalent crude oil-derived products. CO 2 EOREnhanced oil recovery by injecting CO 2 into and storing it in a mature oil field Assumed Prices [for fossil fuels, US average levelized prices, 2021-2040, from AEO 2013] Coal$2.5/GJ Natural gas$5.4/GJ for power plants; $4.8/GJ for wellhead-sited synfuel plants Biomass$5.0/GJ

4. Cellulosic EtOH Options EtOH-CCS a,b,d EtOH-V a,b,d Gasoline equiv. capacity, bbls/day1940 Electric capacity, MW e (% electricity)0.62 (0.55)2.0 (1.8) GHGI - 0.210.17 % of feedstock C captured as CO 2 14.50 CO 2 storage rate, 10 6 tonnes/year 0.110 Capital, NOAK plant, $10 6 158156 Power-Only Options BIGCC-CCS b.d NGCC-CCS c CIGCC-CCS c Electric capacity, MW e 118474543 GHGI - 0.930.200.17 % of feedstock C captured as CO 2 90 88.4 CO 2 storage rate, 10 6 tonnes/year 0.711.43.4 Capital, NOAK plant, $10 6 4887131810 a Based on PALTF (2009) and Liu et al. (2011). b Based on Liu et al. (2011). c Based on NETL (2010). d These systems each consume 0.5 million dry tonnes of switchgrass annually.

5. Alternative FTL Fuel Options (based on Liu et al., 2011) Technology options BTL- CCS GBTL- 46%-CCS GBTLE- 34%-CCS CBTL- 38%-CCS CBTLE- 24%-CCS Electric capacity, MW e (% electricity) 14 (9.8) 34 (9.7) 137 (32.7) 29 (8.0) 156 (29.1) Gasoline equiv. capacity, bbls/day 22405380 486058206520 GHGI- 0.950.17 % of feedstock C captured as CO 2 53.740.3 51.753.465.2 CO 2 storage rate, 10 6 t/year 0.440.53 0.851.072.04 Capital, NOAK plant, $10 6 510 640 8509981360 All systems consume 0.5 x 10 6 dry tonnes of switchgrass annually. To realize specified C footprint (GHGI value): XBTLE (X = G or C) require << biomass % than XBTL; C options require << biomass % than G options. GBTL-46%-CCS and CBTLE-24%-CCS have same carbon footprint (GHGI = 0.17) as EtOH-V but require, respectively, only 0.36 and 0.30 times as much biomass to provide 1 GJ of transportation fuel.

6. GBTL-CCS System Configuration In GTL-CCS system, F-T liquids (diesel + gasoline) are made from synthesis gas derived from natural gas in an autothermal reformer (ATR). In GBTL-CCS system, “tarry” synthesis gas derived from biomass (switch- grass is modeled) via gasification is also fed into ATR, which cracks tars. Adding enough biomass to (46%, energy basis) to reduce GHGI to 0.17 (value for switchgrass-derived cellulosic EtOH) increases CO 2 available for capture 3.4 X compared to GTL-CCS; capture cost for NOAK plant is low: ($12/t vs $60/t for NOAK NGCC-CCS).

7. IRRE Screening Analysis for NOAK Plants FOAK and early-mover plants are much more costly than NOAK plants. Thesis: In the absence of a comprehensive C-mitigation policy, those low-C energy options for which NOAK plants offer attractive profitabilities (IRRE values) at the “social price of carbon” (IWGSPC, 2013) warrant government subsidies for technology cost buydown. Will show that GBTL and CBTLE options in CO 2 EOR applications are strong candidates for such technology cost buydown support.

8. IRRE for NOAK Fuel Options Aquifer Storage of CO 2, $90/bbl Crude Oil If synfuel investors in NOAK plants require 20%/y minimum IRRE, no options with aquifer CO 2 storage at indicated social cost of carbon (SCC)warrant government subsidy for technology cost buydown. Social price of CO 2 (leveli- zed over 2021-2040) for US government agencies IRRE, % per year

9. IRRE for NOAK Fuel Options CO 2 EOR, $90/bbl Crude Oil For CO 2 EOR applications at indicated SCC, the GBTL option warrants government subsidy for technology cost buydown. GBTL & CBTLE are much more profitable than BECCS liquid fuel options until very high GHG emissions prices (far in excess of the SCC) are reached. Social price of CO 2 (leveli- zed over 2021-2040) for US government agencies IRRE, % per year

10. IRRE for NOAK Electric Options Aquifer Storage of CO 2, $90/bbl Crude Oil If electric power investors require a minimum 10%/y IRRE for NOAK plants, no options with aquifer CO 2 storage at indicated SCC warrant government subsidy for technology cost buydown But CBTLE and GBTLE are always far more profitable than CIGCC-CCS! Social price of CO 2 (leveli- zed over 2021-2040) for US government agencies IRRE, % per year

11. IRRE for NOAK Electric Options CO 2 EOR, $90/bbl Crude Oil For CO 2 EOR applications at indicated SCC all options but CIGCC-CCS warrant government subsidy for technology cost buydown. CBTLE option offers > 10%/y IRRE even w/o C policy. Social price of CO 2 (leveli- zed over 2021-2040) for US government agencies IRRE, % per year

12. Technology Cost Buydown for Early-Mover GBTL Projects Selling Captured CO 2 for EOR First-of-a-kind (FOAK) costs are estimated via “back-casting” from cost estimates for N th -of-a-kind (NOAK) plants. Assumptions: – FOAK costs = 2.0 X NOAK costs (consistent w/Edwardsport IGCC experience); – Learning rate for capital and O&M costs = historical rate for SO 2 scrubbers (Rubin et al., 2004)—11% for each cumulative doubling of output; – All plants sell captured CO 2 for EOR; – CO 2 purchase price ($/t) at EOR site = 0.444 x (crude oil price, $/bbl) [average for Permian Basin, 2008-2010—see Wehner (2011)]; – CO 2 transport cost = $10/t; – For GBTL projects subsidy must be sufficient to realize IRRE = 20%/y (real); – Subsidies offered as competitively-bid grants (proportional to capture rates); – Subsidies financed from new federal revenue streams from new domestic liquid fuel production;. – Crude oil price = $117/bbl; and – GHG emissions price = $0/t CO 2e.

13. Technology Cost Buydown Subsidy for GBTL-28%-CCS, GHGI = 0.50, in CO 2 EOR Applications Subsidy in $/t of Captured CO 2 Cumulative Number of Plants Built The first 12 plants require subsidy in the absence of C-mitigation policy

14. Government Perspective on GBTL Technology Cost Buydown in CO 2 EOR Applicatons TechnologyGBTL-28%-CCS Gasoline equivalent FTL capacity, barrels/day (electricity % of output)9,040 (9.6) Annual biomass (switchgrass) consumption rate, 10 6 dry tonnes0.5 GHGI0.50 Specific capital cost, $ per barrel of FTL per day 1 st plant195,000 13 th plant126,000 N th plant (N = 59)98,000 Annual CO 2 storage rate, 10 6 tonnes0.63 Barrels of crude oil via EOR per barrel of gasoline equivalent FTL0.22 Crude oil price (levelized price, 2021-2040, AEO 2013 projection)$117/bbl Subsidy, 10 9 $Plant for Which Cumulative New Government Revenues Net of Subsidies Become Positive Net New Federal Revenues for 1 st 12 Projects, $10 9 1 st plantTotal for 12 plants 1.445.346 th 4.48

15. GBTL-CCS for Brazil Using Cane Residues + Shale Gas? Comparing natural gas data for Brazil and US10 12 scf10 9 Nm 3 EJ (LHV) Brazil Data Brazilian shale gas potential50013,400490 Brazilian proved natural gas reserves at end of 20111643015.7 Brazilian annual natural gas consumption rate, 20110.882360.86 US data US shale gas potential86223,100845 US proved natural gas reserves at end of 20112998,030293 US annual natural gas consumption rate, 20112361722.5 Relative to use of cane residues (bagasse + 40% of barboho) for making cellulosic EtOH-CCS, residue use FTL via GBTL-46%-CCS would provide: 2.8 X as much liquid transportation fuel; 54 X as much byproduct electricity; and 4.6 X as much CO 2 (attractive if there are CO 2 EOR opportunities).

16. Conclusions Near-term market launch of GBTL/CBTLE technologies linked to CO 2 EOR applications could facilitate transition to BECCS under C policy Such near-term market launch could help: – Establish biomass supply logistics markets in regions struggling to establish biomass energy industries; – Get the CCS enterprise back on track (van Noorden, 2013). For Brazil, GBTL systems based on cane residues and shale gas might be an important low-C fuel option. Promising potential way forward in Southeastern US for CBTLE concept: transport gasifier in Southern Company’s 580 MW Kemper County CIGCC-CCS plant is capable of coprocessing up to 30% biomass without problems; there are huge woody biomass supplies in region; Southern has good experience with woody biomass supply logistics. High profitabilities of XBTL/XBTLE systems compared to power only systems with CCS suggests need for fundamental rethinking of relative prospects for decarbonizing electricity/transportation sectors (Williams, 2013).

17. References IWGSCC (Interagency Working Group on the Social Cost of Carbon, US Government), 2013: “Technical Support Document : Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis – Under Executive Order 12866, May. Liu, G., E.D. Larson, R.H. Williams, T.G. Kreutz, and X. Guo, 2011: Making Fischer-Tropsch fuels and electricity from coal and biomass: performance and cost analysis, Energy and Fuels, 25 (1): 415-437. NCC (National Coal Council), 2012: Harnessing Coal’s Carbon Content to Advance the Economy, Environment, and Energy Security, Washington, DC, 22 June. NETL (National Energy Technology Laboratory), 2010: Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2, DOE/NETL-2010/1397, November. PALTF (Panel on Alternative Liquid Transportation Fuels of the National Research Council), 2009: Liquid Transportation Fuels from Coal and Biomass Technological Status, Costs, and Environmental Impacts, a report prepared in support of the NRC’s America’s Energy Future study (2009), U.S. National Academy of Sciences: Washington, DC. Rubin, E.S., M.R. Taylor, S. Yeh, and D.A. Hounshell, 2004: Learning curves for environmental technology and their importance for climate policy analysis, Energy, 29: 1551–1559. Van Noorden, R., 2013: “Europe’s untamed carbon,” Nature, 493: 141-142, 10 January. Wehner, Scott (Chapparal Energy), 2011: “U.S. CO 2 and CO 2 EOR Developments," 9 th Annual CO 2 EOR and Carbon Management Workshop, Houston, 5-6 December 2011. Williams, R.H., 2013: Coal/biomass coprocessing strategy to enable a thriving coal industry in a carbon- constrained world, Cornerstone, 1: (1): 51-59, Copyright © 2013, World Coal Association.