Toward BECCS Market Launch via Biomass/Fossil Fuel Coprocessing to Make Synfuels in CO2 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 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 CO2 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 CO2 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. Acronyms BTL Biomass 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 EtOH Cellulosic ethanol XIGCC Integrated gasifier combined cycle power plant, where X = B (biomass) or C (coal) NGCC Natural gas combined cycle power plant -V Energy conversion plant that vents all CO2 -CCS Energy conversion plant that captures CO2 GHGI The 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 CO2 (Sup PC-V) and the equivalent crude oil-derived products. CO2 EOR Enhanced oil recovery by injecting CO2 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 Cellulosic EtOH Options EtOH-CCSa,b,d 1940 0.62 (0.55) - 0.21 14.5 EtOH-Va,b,d 1940 2.0 (1.8) 0.17 0 CO2 storage rate, 106 tonnes/year 0.11 0 Capital, NOAK plant, $106 158 156 Gasoline equiv. capacity, bbls/day Electric capacity, MWe (% electricity) GHGI % of feedstock C captured as CO2 Power-Only Options BIGCC-CCSb.d NGCC-CCSc CIGCC-CCSc 118 474 543 - 0.93 0.20 0.17 % of feedstock C captured as CO2 90 90 88.4 CO2 storage rate, 106 tonnes/year 0.71 1.4 3.4 Capital, NOAK plant, $106 488 713 1810 Electric capacity, MWe GHGI 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. Alternative FTL Fuel Options (based on Liu et al., 2011) GBTL46%-CCS GBTLE34%-CCS CBTL38%-CCS CBTLE24%-CCS 14 Electric capacity, MWe (% electricity) (9.8) Gasoline equiv. capacity, bbls/day 2240 GHGI - 0.95 % of feedstock C captured as CO2 53.7 34 (9.7) 5380 0.17 40.3 137 (32.7) 29 (8.0) 156 (29.1) 4860 5820 6520 0.17 51.7 0.17 53.4 0.17 65.2 CO2 storage rate, 106 t/year 0.44 0.53 0.85 1.07 2.04 Capital, NOAK plant, $106 510 640 850 998 1360 Technology options BTLCCS • All systems consume 0.5 x 106 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. GBTL-CCS System Configuration flue gas unconverted syngas +C1-C4 FT gases recycle compr. unconverted purge gassyngas +C1-C4 FT gases recycle compr. CO 2 removal CO 2 removal steam steam Water Water gasgas shift shift flue gas Power net export Power island island netelectricity export electricity CO2 enriched CO2 enriched streams, sent to streams, sent to upstream CAP. upstream CAP. CO2 removal (Rectisol) Natural gas Natural gas oxygen steam Biomass Chopping & Lock hopper CO2 Autothermal Autothermal reformer reformer CO2 Filter CO2 removal unit CO2 FT FT FT synthesis FT raw raw product (2 Stage) product synthesis HC recovery syngas syngas HC recovery oxygenoxygen steam steam light ends light ends syncrude syncrude F-T F-T refining refining finished gasoline && finished gasoline diesel blendstocks diesel blendstocks Refinery H2 prod. Refinery H2 prod. H2 make-up FB gasifier & Cyclone Dry ash • 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 (switchgrass 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 CO2 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). 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 CO2 EOR applications are strong candidates for such technology cost buydown support. IRRE for NOAK Fuel Options Aquifer Storage of CO2, $90/bbl Crude Oil Social price of CO2 (levelized over 2021-2040) for US government agencies 35 IRRE, % per year 30 25 BTL-CCS, GHGI = - 0.95 EtOH-CCS, GHGI = - 0.21 20 EtOH-V, GHGI = 0.17 15 GBTL-46%-CCS, GHGI = 0.17 CBTLE-24%-CCS, GHGI = 0.17 10 5 0 0 10 20 30 40 50 60 70 80 90 100 GHG Emissions Price, $/t CO2eq If synfuel investors in NOAK plants require 20%/y minimum IRRE, no options with aquifer CO2 storage at indicated social cost of carbon (SCC)warrant government subsidy for technology cost buydown. IRRE for NOAK Fuel Options CO2 EOR, $90/bbl Crude Oil Social price of CO2 (levelized over 2021-2040) for US government agencies 45 IRRE, % per year 40 35 BTL-RC-CCS, GHGI = - 0.95 30 EtOH-CCS, GHGI = - 0.21 25 EtOH-V, GHGI = 0.17 20 GBTL-46%-CCS, GHGI = 0.17 15 CBTLE-24%-CCS, GHGI = 0.17 10 5 0 0 10 20 30 40 50 60 70 80 90 100 GHG Emissions Price, $/t CO2eq • For CO2 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. IRRE for NOAK Electric Options Aquifer Storage of CO2, $90/bbl Crude Oil Social price of CO2 (levelized over 2021-2040) for US government agencies IRRE, % per year 20 15 BIGCC-CCS, GHGI = - 0.93 CBTLE-24%-CCS, GHGI = 0.17 10 GBTLE-34%-CCS, GHGI = 0.17 CIGCC-CCS, GHGI = 0.17 NGCC-CCS, GHGI = 0.20 5 0 0 10 20 30 40 50 60 70 80 90 100 GHG Emissions Price, $/t CO2eq • If electric power investors require a minimum 10%/y IRRE for NOAK plants, no options with aquifer CO2 storage at indicated SCC warrant government subsidy for technology cost buydown • But CBTLE and GBTLE are always far more profitable than CIGCC-CCS! IRRE for NOAK Electric Options CO2 EOR, $90/bbl Crude Oil Social price of CO2 (levelized over 2021-2040) for US government agencies 30 IRRE, % per year 25 20 BIGCC-CCS, GHGI = - 0.93 CBTLE-24%-CCS, GHGI = 0.17 15 GBTLE-34%-CCS, GHGI = 0.17 CIGCC-CCS, GHGI = 0.17 NGCC-CCS, GHGI = 0.20 10 5 0 0 10 20 30 40 50 60 70 80 90 100 GHG Emissions Price, $/t CO2eq • For CO2 EOR applications at indicated SCC all options but CIGCC-CCS warrant government subsidy for technology cost buydown. • CBTLE option offers > 10%/y IRRE even w/o C policy. Technology Cost Buydown for Early-Mover GBTL Projects Selling Captured CO2 for EOR • First-of-a-kind (FOAK) costs are estimated via “back-casting” from cost estimates for Nth-of-a-kind (NOAK) plants. • Assumptions: – FOAK costs = 2.0 X NOAK costs (consistent w/Edwardsport IGCC experience); – Learning rate for capital and O&M costs = historical rate for SO2 scrubbers (Rubin et al., 2004)—11% for each cumulative doubling of output; – All plants sell captured CO2 for EOR; – CO2 purchase price ($/t) at EOR site = 0.444 x (crude oil price, $/bbl) [average for Permian Basin, 2008-2010—see Wehner (2011)]; – CO2 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 CO2e. Subsidy in $/t of Captured CO2 Technology Cost Buydown Subsidy for GBTL-28%-CCS, GHGI = 0.50, in CO2 EOR Applications 225 200 175 150 125 100 75 50 25 0 1 2 3 4 5 6 7 8 9 10 11 12 Cumulative Number of Plants Built The first 12 plants require subsidy in the absence of C-mitigation policy Government Perspective on GBTL Technology Cost Buydown in CO2 EOR Applicatons Technology GBTL-28%-CCS Gasoline equivalent FTL capacity, barrels/day (electricity % of output) 9,040 (9.6) Annual biomass (switchgrass) consumption rate, 106 dry tonnes 0.5 GHGI 0.50 Specific capital cost, $ per barrel of FTL per day 1st plant 195,000 13th plant 126,000 Nth plant (N = 59) 98,000 Annual CO2 storage rate, 106 tonnes 0.63 Barrels of crude oil via EOR per barrel of gasoline equivalent FTL 0.22 Crude oil price (levelized price, 2021-2040 , AEO 2013 projection) Subsidy, 109 $ 1st plant Total for 12 plants Plant for Which Cumulative New Government Revenues Net of Subsidies Become Positive 1.44 5.34 6th $117/bbl Net New Federal Revenues for 1st 12 Projects, $109 4.48 GBTL-CCS for Brazil Using Cane Residues + Shale Gas? 1012 scf 109 Nm3 EJ (LHV) Brazilian shale gas potential 500 13,400 490 Brazilian proved natural gas reserves at end of 2011 16 430 15.7 Brazilian annual natural gas consumption rate, 2011 0.88 236 0.86 US shale gas potential 862 23,100 845 US proved natural gas reserves at end of 2011 299 8,030 293 US annual natural gas consumption rate, 2011 23 617 22.5 Comparing natural gas data for Brazil and US Brazil Data US data 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 CO2 (attractive if there are CO2 EOR opportunities). Conclusions • Near-term market launch of GBTL/CBTLE technologies linked to CO2 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). 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