Harnessing Coal’s Carbon Content to Advance the Economy, … · 2013. 8. 12. · New build coal...

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APPENDICES

Harnessing Coal’s Carbon Content to Advance the Economy, Environment, and Energy Security

National Coal Council

June 22, 2012

STUDY CHAIR Richard A. Bajura

COAL POLICY COMMITTEE CHAIR

Fredrick D. Palmer

EXECUTIVE VICE PRESIDENT & CHIEF OPERATING OFFICER Robert A. Beck

TECHNICAL WORK GROUP CHAIR

Frank Clemente

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Harnessing Coal’s Carbon Content to Advance the

Economy, Environment, and Energy Security Appendix 3A.................... Page 3

Appendix 3B..................... Page 22

Appendix 6A...................... Page 26

Appendix 6B...................... Page 26

Appendix 6C...................... Page 29

Appendix 7........................ Page 30

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Appendices for Chapter 3

Appendix 3A: Technical and Economic Background Analysis in Support of Chapter 3

3A1. Introduction

Appendix 3A includes:

• Elaboration of Section 3.4b of Chapter 3: Framework for Economic Analysis for CO2 Capture Technologies (see Section 3A.2).

• Definition of acronyms used in Appendix 3A and in main text of Chapter 3 (see Section 3A.3).

• Additional analyses of synfuels and coproduction systems.

• Additional comparisons of major CO2 capture options considered in Chapter 3.

Analyses relating to the last two bullets are presented in the tables and figures of Appendix 3A, which are introduced in Section 3A.4:

• System characteristics for the various capture technologies compared in Chapter 3 and in the figures of Appendix 3A are listed in Tables 3A1, 3A3, and Tables 3A5-3A8.

• Table 3A2 presents a comparison of modeling for IGCC and supercritical coal plants

carried out by NETL and EPRI and shows when the analyses of these two organizations are compared on a self-consistent basis the economic performances estimated by these organizations are very similar.

• Table 3A4 shows when the methodology developed for the synfuels and coproduction

analyses in Liu et al. (2011) is applied to IGCC systems, economic performances are essentially the same as in DOE NETL (2010).

3A.2 Elaboration of Section 3.4b: Framework for Economic Analysis of CO2 Capture

Technologies

All analyses in Chapter 3 and Appendix 3A that involve comparisons of capture options are for costs in constant $2007 (zero inflation) for construction as of that year. Synfuel and coproduction analyses are based largely on Liu et al. (2011), Larson et al. (2012), and Liu et al. (2010). In these studies total plant cost (TPC) estimates were made on a component-by-com-ponent basis, with adjustments to 2007$ as needed using the Chemical Engineering Plant Cost Index. These studies were carried out in a manner aimed at being as consistent as possible with the US DOE NETL (2007) Baseline Power Study, with an update in the present NCC study analysis to be consistent with the US DOE NETL (2010) Baseline Power Study Update.

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The assumptions for the financial analysis are: • The (Owner’s cost)/[Total plant cost (TPC)] ratio =

o 0.228 for new construction [this is the average for the 12 cases in the DOE NETL (2010) Baseline Power Study Update], and

o 0.202 for CCS retrofits [this is the average for 3 cases in draft NETL oxy-combustion retrofit study Matuszewski (2012)]

• 45/55 debt/equity ratio • All calculated costs and exogenous prices expressed in constant $2007 • Real (inflation-corrected) costs of capital:

o 3.3%/year for debt for all calculations, and o 9.0%/year for equity [for calculations of CO2 capture cost, levelized cost of

electricity (LCOE), levelized cost of fuel (LCOF), and breakeven crude oil price (BECOP)]

• 38% combined federal/state corporate income tax rate • Property tax & insurance = 2% of TPC per year (included in the capital charge rate). • 20-year economic life & physical life for plants. • Construction duration and TPC payment distribution over construction period =

o 5 years for synfuel & coal power plants (15%, 20%, 25%, 30%, 10%), and o 3 years for NGCC, CCS retrofits, and small low-C fuel plants (30%, 60%,10%).

The real (inflation-corrected) multiplier of TPC in calculations of CO2 capture cost, LCOE, LCOF, BECOP, and internal rate of return on equity (IRRE) calculations = CCR*IDCF, where • CCR = capital charge rate, and • IDCF = interest during construction factor. Based on the above financial assumptions, the values of these quantities for all but IRRE calculations are presented in Display 3A1: Display 3A1: TPC Multipliers for the Comparative Economic Analyses CCR IDCF New build coal power plants, synfuel plants, and coproduction plants 0.151 1.136 PC retrofit plants (post-combustion and oxy-combustion), CO2 pipelines 0.149 1.052 NGCC power plants 0.151 1.052

Capacity factors for comparative analyses are assumed to be:

• 67% for existing coal plants (US average for coal power in 2010), • 40% for new NGCC plants, • 80% for new IGCC plants, • 85% or new pulverized coal plants, and • 90% for synfuel and coproduction plants.

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The reference crude oil price and the biomass prices are assumed to be $90/b and $5.0/GJ

($5.28/MM Btu), respectively. The assumed coal and natural gas prices are US average levelized prices for power generators over the period 2016-2035 as projected for the Reference Scenario of the Energy Information Administration’s Annual Energy Outlook 2012 Early Release report:

• Coal: $2.31/GJ ($2.44/MM Btu) • Natural gas: $4.95/GJ ($5.22/MM Btu)

It is assumed for IRRE, BECOP, and LCOE calculations that the selling price of synfuels equals the U.S. average refinery-gate price of crude oil products displaced. It is assumed that long run marginal cost of NGCC-V electricity sets the average market price for electricity, or more specifically, for IRRE, BECOP, and LCOF calculations it is assumed that the average electricity selling price is the LCOE for a NCC-V plant operated at 40% capacity factor ($66.3/MWhe) when the GHG emissions price is $0 per metric ton of CO2eq. 3A.3 Definitions of Acronyms The acronyms used in the tables and figures of Appendix 3A as well as in the main text of Chapter 3 are presented in Display 3A2:

Display 3A2: Acronyms XTL X to finished FTL fuels (diesel/jet, gasoline) and electricity, where X=coal (C),

coal + biomass (CB), or natural gas + biomass (GB) XTLmax FTL synthesis with recycle of unconverted syngas to maximize FTL output

(electricity is minor byproduct) XTLcoprod FTL synthesis in once-through (OT) configuration and “mild “ CO2 capture;

unconverted syngas used to make electricity in combined cycle power plant as a major coproduct

XTLAcoprod Like OT except with “aggressive” CO2 capture CBTG Coal + biomass to finished gasoline, LPG, and electricity CBTGcoprod Refers to CBTG systems in which some syngas is bypassed around the synthesis

reactors to provide electricity as a major coproduct PC Pulverized coal power plant WO Written-off - refers to existing pulverized coal power plant Sub/Sup Subcritical/supercritical – refers to pulverized coal power plant USC Ultra-supercritical – refers to pulverized coal power plant IGCC Coal integrated gasifier combined cycle power plant NGCC Natural gas combined cycle power plant V Coproduct CO2 is vented Cap Coproduct CO2 is captured 3A.4 Introduction to the Tables and Figures of Appendix 3A

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The 10 tables and 12 figures presented in Appendix 3A are listed in Display 3A3 and Display 3A4, respectively. The reader might consider approaching these tables and figures starting with the figures and their captions (which can be considered a supplemental story to the main text of Chapter 3), referring to the tables only as needed.

Display 3A3: Tables in Appendix 3A Tab. # Description 3A1 Describes the 12 new-build power generating technologies described in US DOE NETL (2010). 3A2 Compares NETL [US DOE NETL (2012c)] and EPRI [EPRI (2011) and Dalton et al. (2012)] analyses for

PC and IGCC technologies. This shows that when the analyses of these two organizations are compared on a self-consistent basis the estimated economic performances estimated are very similar

3A3 Describes post-combustion capture retrofit and rebuild (IGCC and coproduction) capture options for existing coal power plant sites

3A4 Compares modeling results from Liu et al. (2011) and US DOE NETL (2010) for GEE gasifier-based IGCC. This shows when the methodology developed for the synfuels and coproduction analysis in Liu et al. (2011) is applied to IGCC systems, economic performances are essentially the same as in US DOE NETL (2010) when the comparison is made on a self-consistent basis.

3A5 Describes new-build oxy-combustion (current and advanced) and advanced post-combustion capture technologies, based on recent NETL reports (US DOE NETL, 2012a; 2012b)

3A6 Describes Babcock and Wilcox oxy-combustion retrofit design 3A7 Describes F-T synthesis recycle configurations designed to maximize liquid fuel production and once-

through configurations designed to provide electricity as a major co-product 3A8 Describes systems for making low-carbon fuels in the forms of F-T fuels derived by coprocessing coal and

biomass, F-T fuels derived from biomass, and cellulosic ethanol – all based on switchgrass as the biomass feedstock

3A9 Provides the information needed to understand why the slopes of some LCOE vs GHG emissions price curves in Fig. 3A10 are sharply downward sloping

3A10 Provides the information needed to understand why the slopes of some LCOF vs GHG emissions price curves in Fig. 3A12 are sharply downward sloping

** Display 3A4: Figures in Appendix 3A

Fig. # Description 3A1 Schematic of a coal F-T synfuel plant in a recycle configuration 3A2 Schematic of a coal F-T synfuel plant in a once-through configuration 3A3 IRRE vs CO2 selling price for recycle and once through coal F-T synfuels plants selling CO2 into EOR

markets for a $90/bbl crude oil price 3A4 IRRE vs CO2 selling price for recycle and once-through coal F-Tsynfuels plants selling CO2 into EOR

markets for a $115/bbl crude oil price 3A5 Schematic of an MTG plant based on co-gasifying coal and biomass 3A6 Carbon balances for an MTG plant coprocessing 5% biomass—the graph shows how a 50% reduction in

GHG emissions for liquid fuels can be realized in such a plant by coprocessing only 5% biomass 3A7 Schematic of a once-through F-T synfuel plant coprocessing natural gas and biomass 3A8 Schematic of a once through F-T synfuel plant based on coal and biomass gasification via separate

gasifiers and “mild” CO2 capture 3A9 Schematic of a F-T once-through synfuel plant based on coal and biomass gasification via separate

gasifiers and “aggressive” CO2 capture 3A10 LCOE vs GHG emissions price curves for alternative electricity options in the long-term 3A11 Breakeven crude oil price vs GHG emissions price curves for two coproduction options 3A12 LCOF vs GHG emissions price curves for alternative low-C transportation fuel options

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Table 3A1: Modeling by NETL for Alternative New-Build Coal Electricity-Generation Technologiesa Electric conversion technology GE IGCC CoP IGCC Shell IGCC Subcritical Supercritical NGCC CO2 capture approach Pre-combustion Pre-combustion Pre-combustion Post-combustion Post-combustion Post-combustion CO2 fate V Cap V Cap V Cap V Cap V Cap V Cap Capacity factor 0.80 0.80 0.80 0.80 0.80 0.80 0.85 0.85 0.85 0.85 0.40 0.40 Fuel input capacity, MM Btu/hour HHV 5,447 5,681 5,366 5,649 5,094 5,428 5,103 7,175 4,778 6,601 3,773 3,773 Power output capacity, MWe 622 543 625 514 629 497 550 550 550 550 555 474 Generation, 106 MWh/year 4.36 3.81 4.38 3.60 4.41 3.48 4.10 4.10 4.10 4.10 4.14 3.53 Heat rate, Btu/kWh HHV 8,756 10,458 8,585 10,998 8,099 10,924 9,277 13,046 8,687 12,002 6,798 7,968 HHV efficiency 0.390 0.326 0.397 0.310 0.421 0.312 0.368 0.262 0.393 0.284 0.502 0.428 TPC, $/kWe 1987 2711 1913 2817 2217 3181 1622 2942 1647 2913 584 1226 Assumed (Owner’s Cost)/TPC 0.228 0.228 0.228 0.228 0.228 0.228 0.228 0.228 0.228 0.228 0.228 0.228 Total overnight cost (TPC + OC), $/kWe 2440 3329 2349 3459 2722 3906 1992 3613 2023 3577 717 1506 Emission rate, lb per MWh CO2 1723 206 1710 217 1595 218 1888 266 1768 244 804 94 GHG (CO2e) 1809 309 1795 325 1675 326 1979 394 1854 362 1039 369 GHGI 0.98 0.17 0.97 0.18 0.90 0.18 1.07 0.21 1.00 0.12 0.56 0.20 CO2 capture, metric tons/MWh 0 0.841 0 0.895 0 0.890 0 1.08 0 1.00 0 0.385 LCOE, $/MWh Capital 48.65 66.38 46.84 68.98 54.29 77.89 37.38 67.80 37.96 67.13 26.48 55.59 Variable O&M 7.30 9.33 7.20 9.81 7.75 9.95 5.15 9.16 5.04 8.73 1.32 2.56 Fixed O&Mb 5.60 7.08 5.62 7.49 5.81 7.78 3.47 5.15 3.54 5.16 2.96 5.01 Fuel 21.34 25.49 20.92 26.80 19.74 26.62 22.61 31.80 21.17 29.25 35.51 41.62 GHG emissions (@ $0/t CO2eq) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Credit for CO2 EOR (@ $0/t CO2) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Total LCOE 83 108 81 113 88 122 69 114 68 110 66 105 Capture cost, $/t CO2, for which reference technology is: Same technology-V 30.2 36.3 38.9 41.8 42.6 100.1 Supercritical coal-V 48.3 50.7 61.3 42.6 42.6 96.4 Minimum Dispatch Cost (MDC), $/MWh 28.6 34.8 28.1 36.6 27.5 36.6 27.8 41.0 26.2 38.0 36.8 44.2

a Based on US DOE NETL (2010) except that financial and other economic assumptions are from Section 3A.2. b Fixed O&M cost values are lower than those reported in US DOE NETL (2010) because for the present analysis property taxes and insurance (PTI) are included in the carrying charge factor multiplying TPC in the LCOE calculation (see Section 3A.2), while in the NETL analysis PTI is included in the FOM.

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Table 3A2: NETL and EPRI Modeling of Near-Term Nth–of-a-Kind New-Build Electricity-Generation Technologies (80% CF, $2.0/MMBTU coal, $0/t CO2eq GHG emission price)

Electric conversion technology IGCC, pre-combustion CO2 capture Pulverized coal, post-combustion CO2 capture Modeling carried out by NETLa EPRIb NETLa EPRIb Constant dollar vintage: 2011 $ December 2010 $ 2011 $ December 2010 $ Low or high estimate of capital cost? One case only Low High High One case only Low High High Is CO2 vented (V) or captured (Cap)? V Cap V Cap V Cap V Cap Heat rate, Btu/kWh HHV 8,840 10,800 8,940 11,000 8,690 12,000 8,750 11,800 Fuel input capacity, MM Btu/hour HHV 5,450 5,680 5,360 5,500 4,780 6,600 6,560 7,080 Power output capacity, MWe 617 529 600 500 550 550 750 600 Electricity Generation (EG), 106 MWh/y 4.32 3.71 4.21 3.51 4.10 4.10 5.26 4.21 Total plant cost (TPC), $106 1486 1783 1560 1710 1900 1090 1951 1500 1725 2460 TPC, $/kWe 2410 3374 2600 2850 3800 1981 3548 2000 2300 4100 Total overnight cost, $/kWe (TPC + project/site-specific costs + OC) 2977 4150 3150 3450 4600 2477 4411 2400 2760 4920 Fixed O&M (FOM) cost, $/kW-yc 47d 61d 74 97 32d 46d 48 79 Variable O&M (VOM) cost, $/MWhc 9.5 9.3 2,3 3.3 7.7 13.2 3.0 3.8 CO2 Emission rate, lb/MWh 1740 214 1850 318 1770 244 1860 250 CO2 capture rate, metric tons/MWh 0 0.863 0 0.887 0 0.997 0 1.022 CO2 captured (%) 0 90.3 0 86.0 0 90.3 0 90.0 LCOE, $/MWh Capitale 59.0 82.6 63.7 69.8 93.0 48.5 86.9 49.0 56.3 100.4 Total O&M 16.4 21.2 12.9 17.1 12.2 19.7 8.8 15.0 Coal 17.7 21.5 17.9 22.0 17.4 24.0 17.5 23.6 CO2 transport/storage cost @ $10/t CO2 - 8.6 - 8.9. - 10 -

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Total LCOE 93 134 94 101 141 78 141 75 83 149 Capture cost, $/t CO2 for which reference technology is:

Same technology-V 37f NA - 36f - 53f NA - 55f Supercritical coal-V 55f NA - 56f - 53f NA - 55f

a Based on US DOE NETL (2012c). This forthcoming report updates GEE radiant quench IGCC and supercritical PC cases from US DOE NETL (2010), with capital and O&M costs that reflect a shift from 2007 to 2011 as the base year for cost estimation. This report also includes analyses of plants having zero liquid discharge (ZLD) designs, but the data reported here are for non-ZLD designs. b Based on Tables 1-2 and 1-3 in EPRI (2011) and updates (Dalton et al., 2012). The capture options are for cases without technological improvement, and the capture cost (CC) for each of these systems is estimated as CC ≡ [(LCOE for high -cost capture case) – (CO2 transport and storage cost) – (LCOE for high-cost venting case)]/(CO2 capture rate). c The NETL and EPRI FOM and VOM costs are not directly comparable. NETL includes maintenance material as a variable cost, whereas EPRI counts all maintenance costs (material and labor) as fixed costs. That is why the EPRI FOM appears higher, but the EPRI VOM appears lower. Still, total O&M costs are lower for EPRI than for NETL, but capital charges are higher for EPRI than for NETL. Nevertheless, NETL and EPRI estimates of capture costs for both IGCC and PC plants, calculated either way in the last two lines of the table, are essentially the same.d These fixed O&M cost values are lower than those reported in US DOE NETL (2012c) because for the present analysis property taxes and insurance (PTI) are included in the carrying charge factor multiplying TPC in the LCOE calculation (see note e), while in the NETL analysis PTI is included in the FOM. e For all LCOE calculations it is assumed that the ratio OC/TPC = 0.228, which implies that the carrying charge factor (CCF), the multiplier of TPC/(annual electricity generation) in the LCOE calculation = (CCR = 0.151)*(IDCF = 1.136) = 0.172 (see Section 3A.2).. f Capture costs highlighted in red are estimated under identical assumptions; likewise capture costs highlighted in blue are estimated under identical assumptions.

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Table 3A3: Modeling of Alternative Options for Retrofits or Rebuilding at Existing Coal Power Plant Sites @ $0/t CO2eq GHG Emissions Price, $0/t CO2 Selling Pricea Type of plant WO Existing Retrofit Rebuild options Capture approach Post-combustion CO2 capture Pre-combustion CO2 capture Energy conversion technology Subcritical coal IGCC CTLcoprod CBTGcoprod CBTLcoprod CBTLAcoprod GBTLcoprod CO2 fate V Cap Cap V Cap Cap-5.0% Cap-40% Cap-29% Cap-3.2% Cap-34% Capacity factor 0.67 0.85 0.80 0.90 0.90 0.90 0.90 0.90 0.90 0.90 Coal input capacity, MM Btu/hour HHV 5,504 5,977 13,232 9,257 3,448 5,514 0 0 Natural gas input capactity, MM Btu//hour HHV 0 0 0 0 0 0 10,254 4,359 Biomass input capacity, MM Btu/hour (106 dry metric tons/year) 0 0 0

487 (0.23)

2,254 (1.0)

2,254 (1.0) 334 (0.15)

2,254 (1.0)

Synfuel output capacity, MMBtu/hour LHV - - 3,949 3,330 1,732 2,346 3,021 2,112 Synfuel output capacity, bbls/d gasoline equivalent 0 - 19,865 16,749 8,714 11,800 15,198 10,624 (LPG/gasoline) output ratio LHV - - 0.102 - - - - Power output, MWe 543 398 543 646 543 347 257 287 644 300 Generation, 106 MWh/year 3.18 2.97 3.81 5.10 4.28 2.74 2.03 2.27 5.08 2.37 TPC, $106 - 683b 1450 2460 2550 2550 1430 1790 1600 1240 Assumed [Owner’s Cost (OC)]/TPC - 0.203 0.228 0.228 0.228 0.228 0.228 0.228 0.228 0.228 Total overnight cost (TPC + OC), $106 - 822 1780 3020 3130 3130 1750 2190 1960 1520 GHGI 1.19 0.23 0.15 1.31 0.69 0.50 0.099 0.094 0.50 0.14 Electricity GHG emission rate, lb CO2eq/MWh

CO2 capture rate, metric tons/MWh (106 t/y) 0 1.17

(3.47) - - 1.17

(4.95) 1.64

(4.50) 1.12

(2.27) 1.64

(3.72) 0.42

(2.13) 0.78

(1.85) Crude oil via CO2 EOR (@ 0.3 t CO2 purchased per incremental bbl), bbls/d 37,400 - - 50,200 45,600 23,000 37,700 21,600 18,800 LCOE, $/MWh Capital 0 36.1 65.3 83.0 102.2 159.8 120.8 135.3 54.0 95.2 O&M 13.6 20.6c 18.1 23.0 28.4 40.9 33.5 37.5 12.6 22.2 Fuel 24.7 33.7c 26.8 49.9 59.4 72.4 79.0 88.1 85.9 115.4 Credit for FTL coproduct @ $90/bbl crude - - -120.2 - 143.1 - -132.6 -150.6 -92.2 -138.4 Credit for gasoline coproduct @ $90/bbl crude - - - - -188.8 - - - - Credit for LPG coproduct @ $90/bbl crude - - - - -17.6 - - - - Total LCOE 38.4 90.4 110 36 47 67 101 100 60 94 Makeup (via NGCC-V @ 40% CF) as % of total electricity 6.6 0 0 0 13.8 36.1 28.6 0 25.4 Average LCOE for total electricity 38.4 88.8 110 36 47 67 88 91 60 87 Capture cost, $/t CO2 (Reference: Same technology-V) 43.0 30 - 15 NC 15 21 NC 33

a Based on Liu et al. (2010; 2011) except that: (i) financial and other economic assumptions are from Section 3A.2, and (ii) the PC Cap retrofit analysis is described in the notes below. b In estimating capital costs EPRI (in its IECOST User’s Manual) recommends typically multiplying the greenfield capital cost by 1.3 (medium difficulty) to get he retrofit capital cost. This approach is followed adopted here in the following manner: the TPC for the post-combustion retrofit is assumed to be 1.3 X incremental TPC in shifting from Sub PC-V to Sub PC capture ($1320/kWe) for a new plant—see Tab. 3A1. c Energy balances and O&M cost estimates for the post-combustion retrofit analysis are from Simbeck and Roekpooritat (2009).

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Table 3A4: Comparing NETL and Princeton ESAG Modeling of GEE IGCC Options Modeling by: NETLa Princeton ESAGb Technology: GEE Radiant Quench GEE Simple Quench CO2 fate V Cap V Cap Capacity factor 0.80 0.80 0.80 0.80 Fuel input, MM Btu/hour HHV 5,447 5,681 5,653 5,980 Power output, MWe 622 543 622 543 Generation, 106 MWh/year 4.36 3.81 4.36 3.81 Heat rate, Btu/kWh HHV 8,756 10,458 9,087 11,008 HHV efficiency 0.390 0.326 0.375 0.310 TPC, $/kWe 1987 2711 1951 2,665 Assumed (Owner’s Cost)/TPC 0.228 0.228 0.228 0.228 Total overnight cost (TPC + OC), $/kWe 2440 3329 2396 3273 Emission rate, lb/MWh CO2 1723 206 1748 170 GHG (CO2e) 1809 309 1837 278 GHGI 0.98 0.17 0.99 0.15 CO2 capture rate, metric tons/hour - 457 - 480 CO2 capture, metric tons//MWh - 0.84 - 0.88 LCOE, $/MWh Capital 48.65 66.38 47.78 65.26 O&M 12.90 16.41 12.38 16.92 Fuel 21.34 25.49 22.15 26.83 GHG emissions (@ $0/t CO2eq) 0 0 0 0 Credit for CO2 EOR (@ $0/t CO2) - 0 - 0 Total LCOE 82.9 108.3 82.3 109.0 Capture cost, $/tonne of CO2 with reference technology: Same technology-V 30.2 - 30.2 Sup PC-V 48.3 - 46.7 Minimum Dispatch Cost (MDC), $/MWh 28.6 34.8 29.3 36.7

a Based on US DOE NETL (2010) except that financial and other economic assumptions are from Section 3A.2. b Based on Liu et al. (2011) except that financial and other economic assumptions are from Section 3A.2.

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Table 3A5: Modeling by NETL for Alternative Advanced New-Build Coal Electricity-Generation Technologiesa Energy conversion technology Supercritical coal Ultra-Supercritical coal Capture approach Oxy-combustion Post-combustion CO2 fate V Cap V Cap Technology status Current Advanced Current Advanced Capacity factor 0.85 0.85 0.85 0.85 0.85 Fuel input, MM Btu/hour HHV 4,778 6,402 4,721 4,414 5,137 Power output, MWe 550 550 549 550 550 Generation, 106 MWh/year 4.10 4.40 4.09 4.10 4.10 Heat rate, Btu//kWh HHV 8,687 11,639 8,595 8,025 9,339 HHV efficiency 0.393 0.293 0.397 0.425 0.365 TPC, $/kWe 1647 2617 2250 1547 2347 Assumed (Owner’s Cost)/TPC 0.228 0.228 0.228 0.228 0.228 Total overnight cost (TPC + OC), $/kWe 2022 3214 2762 1900 2883 Emission rate, lb/MWh CO2 1,768 0 0 1,633 181 Fuel cycle GHG (CO2e) 1,854 115 85 1,712 273 GHGI 1.00 0.062 0.046 0.92 0.15 CO2 capture, metric tons//MWh 0 1.08 0.78 0 0.78 LCOE, $/MWh Capital 37.96 60.32 51.85 35.66 54.10 Variable O&M 5.04 6.32 4.08 4.57 7.24 Fixed O&M 3.54 4.73 4.11 3.36 4.52 Fuel 21.17 28.37 20.95 19.56 22.76 GHG emissions (@ $0/t CO2eq) 0.00 0 0 0 0 Credit for CO2 EOR (@ $0/t CO2) 0.00 0 0 0 0 Total LCOE 67.7 99.7 81.0 63.2 88.6 Capture cost, $/tonne of CO2 with reference technology: Same technology-V - 29.8 17.0 - 32.6 Sup PC-V - 29.8 17.0 - 26.8 Minimum Dispatch Cost (MDC), $/MWh 26.2 34.7 30.5 24.1 30.0

a The advanced oxy-combustion option is the “cumulative technology case” in NETL (2012a) that considers the potential impact of success in pursuing several advanced several technologies options simultaneously. The advanced post-combustion option is Case 5D in NETL (2012b) which involves use of membrane capture technology and shockwave CO2 compression technology in an advanced ultra-supercritical PC plant. Financial and other economic assumptions are from Section 3A.2

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Table 3A6: Modeling by Babcock and Wilcox of Oxy-Combustion Capture Retrofita Type of plant WO Existingb Retrofit Electric conversion technology Supercritical coal Capture approach Oxy-combustion CO2 fate V Cap Capacity factor 0.67 0.85 Fuel input, MM Btu/hour HHV 4,763 4,763 Power output, MWe 550 428.6 Generation, 106 MWh/year 3.22 3.19 Heat rate, Btu/kWh 8,660 11,114 HHV efficiency 0.394 0.307 TPC, $/kWe - 1992 Owner’s Cost (OC) @ 0.203*TPC - 404 Total overnight cost (TPC + OC), $/kWe - 2396 Emission rate, lb/MWh CO2 1,735 223 Fuel cycle GHG (CO2e) 1,821 332 GHGI 1.00 0.18 CO2 capture, metric tons/MWh 0 0.93 LCOE, $/MWh Capital 0 41.87 Variable O&M 5.60 14.41 Fixed O&M 4.97 6.72 Fuel 21.11 27.09 GHG emissions (@ $0/t CO2eq) 0 0 Credit for CO2 EOR (@ $0/t CO2) 0 0 Total LCOE 31.7 90.3 Makeup (via NGCC-V @ 40% CF) as % of total electricity 0.72 Average LCOE for total electricity 31.7 89.9 Capture cost, $/t CO2 (Reference: same technology venting CO2) 62.7 Minimum Dispatch Cost (MDC), $/MWh 26.7 41.5

a Based on Farzan et al. (2010) and McDonald (2012) for a case involving use of Illinois # 6 coal and for capture of 90% of the produced CO2 except that the except that financial and other economic assumptions are from Section

3A.2.

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Table 3A7: Comparing Alternative New-Build Coal Fischer-Tropsch Liquid (CTL) Plant Designs FTL conversion technology CTLmax, large scale CTLcoprod, large scale CTLmax, modest scale CTLcoprod, modest scale Is CO2 vented (V) or captured (Cap)? V Cap V Cap V Cap V Cap Capacity factor 0.90 0.90 0.90 0.90 0.90 0.90 0.90 0.90 Coal input capacity, MM Btu/hour HHV 25,792 28,358 12,230 13,232 FTL output capacity, MM Btu/hour LHV 10,780 8,463 5,111 3,949 FTL output capacity, bbls/d 50,000 39,300 23,700 18,300 Power output, MWe 404 295 1385 1164 192 140 646 543 Generation, 106 MWh/year 3.19 2.33 10.93 9.18 1.51 1.10 5.10 4.28 TPC, $106 4.85 4.91 4.75 4.91 2.51 2.55 2.46 2.55 Assumed (Owner’s Cost)/TPC 0.228 0.228 0.228 0.228 0.228 0.228 0.228 0.228 Total overnight cost (TPC + OC), $106 5.95 6.03 5.84 6.03 3.08 3.13 3.02 3.13 GHGI 1.70 0.89 1.30 0.69 1.70 0.89 1.30 0.69

CO2 capture rate, kg/gge of liquid fuel (106 metric tons/year) - 12.8 (9.5) - 18.0

(10.6) - 12.8 (4.5) - 18.0

(4.9) Crude oil output capacity via CO2 EOR (@ 0.3 t CO2.barrel), bbls/d 96,800 - 107,500 - 45,900 - 50,200 LCOF, $/gallon of gasoline equivalent Capital 1.11 1,13 1.39 1.44 1.22 1.23 1.54 1.60 O&M 0.31 0.31 0.39 0.40 0.34 0.34 0.43 0.44 Fuel 0.66 0.66 0.93 0.93 0.66 0.66 0.93 0.93 GHG emissions price @ $0/t CO2eq 0 0 0 0 0 0 0 0 Credit for electricity coproduct @ 66.3/MWhe -0.28 -0.21 - 1.23 - 1.04 - 0.28 - 0.21 - 1.23 - 1.04 Credit for CO2 sold for EOR @ $0/t CO2 - 0 - 0 - 0 - 0 Total LCOF 1.80 1.90 1.47 1.73 1.93 2.03 1.67 1.93 Capture cost, $/t CO2 (Reference technology: same technology-V) 7.5 - 14.3 - 7.8 - 14.7

a Based on Liu et al. (2011) except that financial and other economic assumptions are from Section 3A.2.

14

Table 3A8 Alternative Low-C Transportation Fuel Options, Each Consuming 0.50 x 106 Tons/y of Switchgrass, CO2 Storage in Deep Saline Formationsa Technology: BTLmax CBTLmax CBTLcoprod CBTLAcoprod Cellulosic EtOH CO2 vented (V) or captured (Cap)? V Cap Cap-45% Cap-40% Cap-29% V Cap Capacity factor 0.90 0.90 0.90 0.90 0.90 0.90 0.90 Coal input capacity, 106 MM Btu/hour HHV 0 1,254 1,576 2,521 0 0 Biomass input, capacity, MM Btu/hour HHV 1,030 1,030 1,030 1,030 1,030 Ratio of biomass energy input to transportation fuel output, LHV energy basis 2.16 0.99 1.21 0.90 2.49 2.49 Transportation fuel output capacity, MM Btu/hour 446 970 792 1073 386 Transportation fuel output capacity, bbl/d of gasoline equivalent 2241 4882 3984 5395 1941 1941 Power output capacity, MWe 19.3 14.2 24.3 117.5 131.4 2.0 0.6 Generation, 103 MWh/year 152 112 192 927 1037 16.0 4.9 TPC, $/106 408 415 732 764 938 156 158 Assumed (Owner’s Cost)/TPC 0.228 0.228 0.228 0.228 0.228 0.228 0.228 Total overnight cost (TPC + OC), $106 501 510 899 938 1152 192 194 GHGI 0.063 - 0.94 0.029 0.099 0.094 0.16 - 0.21

CO2 capture rate, kg/gge of liquid fuel (106 metric tons/year) - 14.2

13.5

18.8

22.8

- 4.3

CO2 transport & storage cost, $/mt CO2 - 14.8 11.4 10.5 8.7 - 35.1 LCOF, $/gallon of gasollne equivalent (gge) Capital 2.10 2.14 1.73 2.21 2.00 0.93 0.94 O&M 0.63 0.64 0.52 0.66 0.60 0.71 0.72 Fuel 1.39 1.39 0.99 1.33 1.23 1.60 1.60 CO2 transport and storage cost 0 0.21 0.15 0.20 0.20 0 0.15 GHG emissions for a GHG emissions price of $0/t CO2eq 0 0 0 0 0 0 0 Credit for electricity coproduct @ 66.3/MWh -0.33 -0.24 -0.19 -1.12 -0.92 -0.04 -0.012 Extra cost for EtOH transport to refueling station - - - - - 0.19 0.19 Total LCOF 3.78 4.13 3.20 3.28 3.10 3.39 3.58

a Based on Liu et al. (2011) except that the financial and other economic assumptions are from Section 3A.2. The information in this table provides the basis for the LCOF vs GHG emissions price curves presented in Fig. 3A12. Energy balances, capital cost, and O&M costs for the cellulosic ethanol option with CO2 vented are from PALTL (2009); the CO2 capture variant of this option was developed in Liu et al. (2011). For all systems considered here the financial and other economic assumptions are from Section 3A.2.

15

Table 3A9: “Effective” Net GHG Emissions for Evaluation of LCOE for Electricity Options, When 100% of Emissions Are Charged to Electricity (lb CO2eq per MWhe) (a) GHG emissions for

system (b) GHG emissions credit for crude oil products displaceda

Effective net emissions for evaluating LCOE: (c ) = (a) - (b)

NGCC-V 1039 0 1039 Advanced post-combustion capture 273 0 273 Advanced oxycombustion capture 85 0 85 CTLcoprod-Cap 2390 1550 839 CBTLAcoprod-Cap-29% 337 1740 -1403 ** Table 3A10: “Effective” Net GHG Emissions for Evaluation of LCOF for Low-C Fuels. When 100% of Emissions Are Charged to Liquid Fuels (lb CO2eq per gallon of gasoline equivalent) (a) GHG emissions for system (b) GHG emissions credit for

electricity displaced (assumed to be NGCC-C)a

Effective net emissions for evaluating LCOF: (c ) = (a) - (b)

EtOH-V 4.09 0.62 3.47 EtOH-Cap -5.07 0.19 -5.26 BTLmax-V 2.09 5.11 -3.02 BTLmax-Cap -29.16 3.76 -32.92 CBTLmax-Cap-45% 0.85 2.95 -2.10 CBTLcoprod-Cap-40% 5.12 17.50 -12.39 CBTLAcoprod-Cap-29%

4.24 14.45 -10.21

Gasification& Quench

Grinding & Slurry Prep

oxygen

water

coal

SyngasScrubber

Acid GasRemoval

F-TRefining

F-TSynthesis

CO2

FlashRefrigeration

Plant

slag

Flash

methanol

CO2

syngas

Water GasShift

150 bar CO2to pipeline

Regenerator

H2S + CO2To Claus/SCOT

HC

Recovery

RecycleCompr.

finished gasoline & diesel blendstocks

unconverted syngas+ C1 - C4 FT gases

raw FT product

Refinery H2 Prod

syncrudelight ends

purge gas PowerIsland

net exportelectricity

gascooling

expander

ATRoxygen steam

flue gas

Fig. 3A1: Coal to Fischer-Tropsch (F-T) Liquids System in Recycle Configuration with CO2 Cap-ture (CTLmax-Cap) Designed to Maximize Conversion to Synthetic Liquid Fuels As modeled in Liu et al. (2011), coal is gasified in a GEE entrained flow gasifier. After syngas clean-up, the H2/CO ratio is adjusted to 1.0 in a water-gas shift reactor, and crude diesel + naphtha are produced in a slurry-phase F-T syn-thesis reactor with an iron catalyst. The unconverted syngas is recycled back through the synthesis reactor after passing through an autothermal reformer (ATR) that converts C1 to C4 gases into mainly CO and H2. Purge gases are burned to make electricity in a steam turbine power plant. CO2, accounting for 52% of the coal’s carbon, is removed upstream of synthesis along with H2S. The latter is recovered and converted to elemental S in a Claus plant. Capturing the CO2 requires only CO2 compression. In modeling this and alternative synfuel systems, it is assumed that captured CO2 is compressed to 150 bar. In this system design crude diesel and naphtha are refined to finished diesel and gasoline. For this system GHGI = 0.89 (see Table 3A7).

16



oxygen

water

coal

SyngasScrubber

Acid GasRemoval

F-TRefining

F-TSynthesis

CO2

Flash

slag

Flash

CO2

syngas

Water GasShift


Regenerator


HC Recovery



raw FT product

Refinery H2 Prod

syn-crude

light ends

GTCCPowerIsland


gascooling

expander

CO2 Rem

oval

CO2 enriched methanol

flue gas

methanolmethanol RefrigerationPlant

Saturator

OxygenPlant N2 to gas turbine

N2

air

Figure 3A2: Coal to Fischer-Tropsch (F-T) Liquids System in Once-Through Configuration with “Mild” CO2 Capture (CTLcoprod-Cap), Providing Electricity as a Major Coproduct Like the system shown in Figure 3A1 except the syngas is passed only once through the synthesis reactor. Syngas unconverted in a single pass through the synthesis reactor is burned in the gas turbine combustor of a combined cycle power plant. Heat recovered as steam from the synthesis reactor provides some of the electricity produced in the steam turbine bottoming cycle. Under mild capture conditions there is no ATR, but rather the C1 to C4 gases are burned along with the unconverted syngas to make power in the combined cycle. CO2 is captured downstream as well as upstream of synthesis because the assumed iron catalayst has water gas shift activity. For this system, GHGI = 0.69 (see Table 3A7).

17

Fig. 3A3: Real Internal Rate of Return on Equity (IRRE) for Modest-Scale CTL Plants (described in Table 3A7) Selling Captured CO2 for EOR When the Crude Oil Price is $90/bbl. The CO2 selling price at which it becomes more profitable to capture CO2 is about twice as large for CTLcoprod as for CTLmax but is still modest compared to selling prices needed to make CO2 capture profitable for power-only systems. This figure shows that for $90/bbl crude oil CTLcoprod-Cap is slightly more profitable than CTLmax-Cap.

18

Figure 3A4: Figure 3A3: Real IRRE for Modest-Scale CTL Plants Described in Table 3A7 Selling Captured CO2 for EOR When the Crude Oil Price is $115/bbl. At this higher oil price the CTLmax-Cap option is slightly more profitable than the CTLcoprod-Cap option.

Acid Gas Removal

Methanol Synthesis

Methanol Recovery

MTG reactor Refining

Refrigeration plant

Flash

Flash

Regeneration

Methanol

CO2

CO2

H2 S + CO2

To Claus/SCOT

150 bar CO2To pipeline

Water

Purg

e ga

s

Crude

Methanol

Finished Gasoline

LPG

Fuel gasRecycle Compr.

Recycled Syngas

saturator

Water Gas

Shift

CO2

removal

CO2 Enriched methanol

Methanol

SteamGTCC Power Island

N2

Flue gas

Net export electricity

Grinding & Slurry Prep.

Gasification & Quench

Syngas Scrubber

Water Gas ShiftCoal

Water Slag

Oxygen plant

Air

Gas cooling

Oxygen

TorrefactionBiomass

Syngas Bypass?

Torrefied biomass

Fig. 3A5: Coal/Biomass Co-Gasification of Coal and Torrified Biomass to Make Gasoline (via MTG) + Electricity via CBTGcoprod-Cap. Synfuel or coproduction systems coprocessing modest amounts of biomass with coal are likely to involve cogas-ification. Cogasification would be facilitated if the fibrous biomass were first torrefied to destroy its fibrous nature so that the coal can be milled like coal to small particle sizes. The system shown above involves cogasification of coal and torrefied biomass (wheat straw) in a Shell dry-feed entrained flow gasifier to make gasoline and electricity in a “partial-bypass” system configuration based on the methanol to gasoline (MTG) process. Some syngas from the gasifier bypasses the synthesis reactors so as to increase the electricity fraction of the product mix beyond the fraction that would be realized in a once-through system configuration. The system produces LPG (a propane /butane mixture) as a byproduct of making gasoline (@ 0.10 MM Btu LPG per MM Btu of gasoline). In the present analysis [based on Larson et al. (2012)], attention is focused on a system configuration (CBTGcoprod-Cap-5.0% - see Table 3A3 and Figure 3A5) for which the biomass input is 5% of the total energy input and GHGI = 0.50).

19

Figure 3A6: How 50% Reduction in GHG Emissions for Gasoline + LPG Is Realized for CBTG-coprod-Cap-5.0% (using “closed-loop” biomass) In Larson et al. (2012), the CBTG-coprod-Cap-5.0% system (see Table 3A3) is designed with just enough biomass input (5.0% on an energy basis) to realize a GHGI = 0.50 for this coproduction system. The five bars in the above graph show how a 50% reduction in system-wide GHG emissions is realized with this modest amount of biomass:

• 1st Bar shows fuel-cycle-wide GHG emission rate for crude oil-derived gasoline + LPG displaced • 2nd and 3rd bars show carbon balance for the energy conversion plant (carbon output = carbon input) • 4th bar shows fuel-cycle-wide GHG emissions by component (+tive and –tive elements) • 5th bar shows net fuel-cycle-wide GHG emissions for this system with 5% biomass

Credit for emissions from electricity in 4th bar{@ (GHGI = 0.50) *[841 kg CO2eq/MWhe (rate for new Sup PC-V)]}: = (0.109 MWhe/GJ gasoline)*(420 kg CO2eq/MWhe) = 46.1 kg CO2eq or 12.6 kg Ceq per GJ gasoline

Autothermal reformer Refinery H2 prod.

F-T refining

HC recovery

raw FTproduct

Power island

syncrude finished gasoline & diesel blendstocks

flue gas

net export electricity

unconverted syngas+C1-C4 FT gases

light ends

Natural gas

oxygen steam

syngas

Water gas shift

CO2 rem

oval

CO2 enriched streams, sent to upstream CAP.

steam

FT synthesis

Chopping & Lock hopper

Biomass

oxygen steam

CO2

FB gasifier & Cyclone

Dry ash

Filter CO2 removal unit

CO2H2 make-up

Figure 3A7: Coproduction of F-T liquids and electricity from natural gas and biomass in a once-through system configuration with “mild” CO2 capture via GBTLcoprod-Cap For a system modeled in Liu et al. (2010) biomass (switchgrass) is gasified in a GTI fluidized bed gasifier. An auto-thermal reformer (ATR) simultaneously reforms natural gas into syngas and serves as a tar cracker for tarry syngas from the GTI biomass gasifier. Crude diesel and naphtha are synthesized using a cobalt F-T catalyst and refined onsite to finished diesel and gasoline. A GHGI = 0.50 can be realized using 3.2% biomass (GBTLcoprod-Cap-3.2%e—see Tab. 3A3).

20

FB Gasifier& Cyclone


oxygen

biomass TarCracking

steam

CO2



oxygen

water

coal

SyngasScrubber

Acid GasRemoval

F-TRefining

F-TSynthesis

CO2

Flash

slag

Flash

CO2

syngas

Water GasShift


Regenerator


HC Recovery



raw FT product

Refinery H2 Prod

syn-crude

lightends

GTCCPowerIsland


gascooling

expander

dry ash

gascooling

Filter

CO2 Rem

oval


flue gas


Figure 3A8: Coal + Biomass to Fischer-Tropsch (F-T) Liquids n Once-Through System with “Mild” CO2 Capture Providing Electricity as a Major Coproduct (CBTLcoprod-Cap) If eventually the U.S. were to enact a carbon mitigation policy, a continuing large role for coal in providing synthetic fuels would be enabled by coprocessing with coal substantial amounts of biomass, and for such systems use of separate gasifiers for coal and biomass may be preferred because of the higher efficiencies compared to cogasification. The system shown here, modeled in Liu et al. (2011), is like the CTLcoprod-Cap system shown in Figure 3A2 except that it includes a separate GTI fluidized bed gasifier that proceses syngas that is blended with coal-derived syngas for further processing. Such a system coprocessing 40% biomass on an energy basis (CBTLcoprod-Cap-40%) would have GHGI = 0.099 (see Table 3A3).

FB Gasifier& Cyclone


oxygen

biomass TarCracking

steam

CO2



oxygen

water

coal

SyngasScrubber

Acid GasRemoval

F-TRefining

F-TSynthesis

CO2

Flash

slag

Flash

CO2

syngas

Water GasShift


Regenerator


HC Recovery



raw FT product

Refinery H2 Prod

syn-crude

lightends

GTCCPowerIsland


gascooling

expander

dry ash

gascooling

FilterATR

oxygen steam

CO2 Rem

oval


flue gas


Water GasShift

Fig. 3A9: Coal + Biomass to Fischer-Tropsch (F-T) Liquids in Once-Through System with “Aggressive” CO2 Capture Providing Electricity as a Major Coproduct (CBTLAcoprod-Cap) This system is the same as that shown in Figure 3A8 except that it involves extra CO2 capture after synthesis via autothermal reforming (ATR) of C1-C4 gases + water gas shift + additional CO2 removal equipment downstream of synthesis. At high biomass coprocessing rates, the more capital-intensive “aggressive” capture system offers electricity at a lower LCOE (see Fig. 3A10) and synfuels at a lower LCOF (see Figure 3A12) than a “mild” capture system having the same GHGI value and the same biomass input level. This rather surprising finding arises because for the aggressive capture system configuration the average feedstock cost is lower (biomass is much more costly than coal) and because of scale economy benefits: advantages that more than offset the energy and cost penalties of the ATR – see Liu et al. (2011) for details. The focus of the present analysis is on such a system coprocessing 29% biomass on an energy basis (CBTLAcoprod-Cap-29% - see Table 3A3), for which GHGI = 0.094.

21

Figure 3A10: Levelized Cost of Electricity (LCOE) vs. GHG Emissions Price for Alternative Electric Generating Options in the Longer-Term, Assuming CO2 Storage in Deep Saline Formations This graph shows how alternative electric generating options in the longer term compare under a carbon mitigation policy. The NCC-V plant is described in Table 3A1. The written-off (WO) existing PC-V plant and coproduction options are described in Table 3A3. The advanced post-combustion and oxy-combustion options are described in Table 3A5. Since GHGI ≈ 0.1 for the options coprocessing biomass, one might expect their LCOE values to rise slowly with GHG emissions price, but instead they decline! This is because GHG emissions enter the LCOE calculations not only as a charge for a system’s GHG emissions but also via a GHG emissions credit arising from selling the synfuels coproducts. It is assumed that these coproducts are sold at the refinery gate prices of the crude oil products displaced, including the value of fuel cycle wide GHG emissions for these crude oil derived products. Since these credits are much greater than the system-wide emissions, the “effective” net emissions for the LCOE calculations are strongly negative (see Tab. 3A9). As a result LCOE values decline sharply as the carbon mitigation policy becomes more stringent. For the reasons discussed in the caption for Figure 3A9, the “aggressive” capture option outperforms the “mild” capture option for the options that coprocess coal and biomass. Notably, for a GHG emissions price of $100/t, the LCOE for CBTLAcoprod-Cap-29% is only slightly higher than the LCOE for a written-off pulverized coal plant (WO PC-V) when the GHG emissions price is $0/t.

Fig. 3A11: Breakeven Crude Oil Price (BECOP) vs GHG Emissions Price for Two Coproduction Options, Assuming CO2 Storage in Deep Saline Formations Successful establishment of coal-based synfuels in the market might eventually drive down the world oil price. But, investors in CO2 capture systems coprocessing substantial amounts of biomass would be well protected against the risk of sustained low oil prices in the presence of a strong carbon mitigation policy—e.g., the BECOP would be about $50/b when the GHG emission price is $100/t CO2eq for the CBTLcoprod-Cap-29% option.

22

Figure 3A12 : Levelized Cost of Fuel (LCOF) and Fuel Value [in $/gallon of gasoline equivalent (gge)] vs GHG Emissions Price for Alternative Low-Carbon Fuel Options in the Longer-Term, Assuming CO2 Storage in Deep Saline Formations The options compared are those described in Table 3A8, assuming in all cases that the amount of biomass (in the form of switchgrass) is consumed at a rate of 0.5 million short tons per year. The CBTLcoprod-Cap-40% and CBTLAcoprod-Cap-29% options are the same as those considered for the construction of Fig. 3A13, except in the present case the systems use about ½ as much biomass annually. Also included in the comparison are a coal/biomass coprocessing option (45% biomass) that is designed to maximize liquid fuel output (CBTLmax-Cap-45%), two biomass-only recycle systems [one venting CO2 (BTLmax-V) and one with CO2 capture (BTLmax-Cap)], and two cellulosic ethanol opions – one venting CO2 (EtOH-V) and one capturing the pure CO2 from the ethanol fermenter (EtOH-Cap). All systems are discussed in detail in Liu et al. (2011). Notably, the LCOF declines sharply with GHG emissions price for BTLmax-Cap, CBTLcoprod-Cap-40%, and CBTL-OTA-CCS-29% options. In the BTLmax-Cap case this arises largely as a result of the strong negative emission rate for this option (GHGI = - 0.94). In the case of these two coal/biomass corpocessing options (for which GHGI ≈ 0.1) it is because GHG emissions enter the LCOF calculations not only as a charge for the system’s GHG emissions but also via a GHG emissions credit arising from selling the electricity coproduct. It is assumed that this electricity is sold at a price equal to the LCOE value for a NGCC-V plant operated at 40% capacity factor, including the value of fuel-cycle-wide GHG emissions for such a plant. As this credit is greater than the fuel cycle wide GHG emissions for the plant, the net “effective” emissions for the LCOF calculations are strongly negative (see Table 3A10), so that the LCOF curves for these options are sharply downward sloping. The rising economic benefit of CO2 capture with increasing GHG emissions price is quite modest for EtOH-Cap, whereas it is substantial for BTLmax-Cap. The reason is that in the EtOH-Cap case only 15% of the carbon in the biomass is stored underground vs 52% for the BTLmax-Cap case (note from Table 3A8, the CO2 storage rate per gge is 3.3x as large for BTLmax-Cap as for EtOH-Cap). Although GHGI is lower for CBTLmax-Cap-45% (0.029) than for CBTLAcoprod-Cap-29% (0.094), the LCOF for CBTLmax-Cap-45% declines only slowly with GHG emissions price largely because this option provides only a modest amount of coproduct electricity, so that the coproduct emissions benefit for the LCOF calculation is small (see Table 3A10). Despite the fact that biochemical processes such as cellulosic ethanol are much less capital intensive than the thermochemical proceses considered here for biomass and biomass + coal, cellulosic ethanol is never the least costly option. Also, neither of the BTLmax options is ever the least costly option – largely because of the high biomass price compared to the coal price and the scale economy effect which drives up substantially the capital cost for a plant making liquid fuels from biomass only. This figure shows that CBTLAcoprod-Cap-29% offers the least costly low-C liquid fuel among all the compared options and that, for a $90/bbl crude oil price, this option becomes competitive with the equivalent crude-oil derived products at a GHG emissions price of $55/t. At a $100/t GHG emissions price the LCOF for this option is $2.64/gge. For comparison, the U.S. average refinery gate price of gasoline in 2011 was $2.69/gge when expressed in $2007, the base year dollars for this economic analysis.

23

Appendix 3B: Background on Synthetic Fuels Technologies

The commercially available synthetic fuel options are the Fischer-Tropsch liquids (FTL)

process and the methanol-to-gasoline (MTG) process. Both technologies make synthetic fuels

from synthesis gas (a gaseous mixture made up mainly of CO and H2), which can be derived

from coal or from biomass or from coal + biomass via gasification and from natural gas via

reforming (also known as “natural gas gasification”).

3B.1 Fischer-Tropsch Liquids Technology

FTL technology was invented in the 1920s by Franz Fischer and Hans Tropsch working

at the Kaiser Wilhelm Institute in Germany. The technology provides from synthesis gas

synthetic middle distillates and naphtha. The middle distillates can be diesel or jet fuel or both.

The naphtha generated by FTL systems can be sold as a chemical or upgraded to gasoline for use

as a transportation fuel.

FTL technology based on coal gasification (CTL technology) became commercially

established around 1983 when Sasol built two plants in South Africa for which the CTL output

capacity is 140,000 bbl/d. Moreover, significant CTL capacity-build is starting to occur in China.

There is also about 250,000 bbl/d of synfuels capacity operating outside the U.S. involving

natural gas conversion to liquids (GTL technology).

All commercial FTL plants around the world were designed to maximize fuels

production, in that the light gases and unconverted synthesis gas from the synthesis reactors are

recycled to maximize the yield of fuel products (little or no net electricity is produced for export

from the FTL production site).

3B.2 Methanol to Gasoline Technology Methanol to gasoline (MTG) technology (see Box 3B1) is much less familiar than FTL

technology but it is also commercially available. Both ExxonMobil and Haldor Topsøe offer

technologies for synthesizing gasoline from methanol, but only the ExxonMobil process has

operated commercially. The Mobil MTG technology was developed in the late 1970s to produce

gasoline from feedstock sources such as coal and natural gas.

http://en.wikipedia.org/wiki/Haldor_Tops%C3%B8e�

24

Because of the then high price of crude oil, the New Zealand Government decided in

1979 to build a commercial 14,500 bbl/d natural gas to methanol plant and then via MTG a

gasoline plant in Motunui, NZ. The plant ownership was 75% NZ Government and 25%

ExxonMobil. The plant started up in 1985 and operated successfully for 10 years producing

gasoline for use in New Zealand. With the sharp drop in crude oil price and the rising price of

methanol on the world market, it became more profitable to sell the methanol than to convert it

to gasoline and the MTG portion of the plant was closed.

Recently, MTG technology has been resurrected in Shanxi Province, China, where the

Jincheng Anthracite Mining Group (JAMG) methanol-gasoline (MTG) project producing 2,300

bbl/d of gasoline was launched in 2009 using the ExxonMobil MTG technology. In the U.S.,

DKRW is planning a coal MTG project at Medicine Bow Wyoming (see discussions in Chapters

3 and 6).

Box 3B1: Gasoline Production via the Exxon Mobil MTG Process

MTG technology involves three essentially independent technology steps which in an actual plant are closely integrated.

The first step in the production of gasoline from carbonaceous feedstocks is gasification to produce syngas and its clean-up for use in chemical synthesis. This can involve gasification of natural gas (otherwise known as natural gas reforming), coal, coal and biomass, or just biomass. These technologies are all commercially robust with the exception of biomass gasification which is “commercially ready” but needs further demonstration and the associated learning-by-doing which could potentially make it commercially robust.

The second step is the synthesis of methanol from the syngas. This is commercially very robust with plants in several parts of the world producing methanol via syngas from coal and with world-scale, single-train methanol plants, based on synthesis gas derived from natural gas, producing 5,500 tonnes of methanol per day. In these systems gasification and methanol synthesis are typically tightly integrated to improved system efficiencies.

The third step is the conversion of the methanol to gasoline in an MTG reactor. Because the reaction is highly exothermic it is typically carried out in two reaction steps, the first involves dehydration of methanol to dimethyl ether (DME); and the second the conversion of DME to gasoline. This latter step involves a shape-selective catalyst ZSM-5 which has the ability to produce only gasoline-range hydrocarbons with just the right composition and properties (e.g. octane 86), so that the C5+ material can be blended directly into the gasoline pool with no further upgrading. Some LPG (which is also a fuel of commerce) is produced as a byproduct.

All systems built and being planned involve use of a fixed-bed MTG synthesis reactor, because of its overall simplicity in making gasoline directly. A fluid-bed version has been developed and demonstrated at intermediate scale. The latter would be better for larger-scale applications, facilitating realization of various economies of scale. In this case, the lighter hydrocarbons produced would be used in alkylation to produce additional high octane components for higher octane blended gasoline.

25

References for Chapter 2 Appendices

Dalton et al., 2012: Private communication to Bob Williams from Stu Dalton and others at EPRI, 6 April. EPRI (Electric Power Research Institute), 2011: Program on Technology Innovation: Integrated Generation Technology Options, 1022782, Technical Update, June. Farzan, H., D. McDonald, R. Prabhakar, B. Sass, and J. Figueroa, 2010: “Development of cost effective oxy-combustion for retrofitting coal-fired boilers,” DE-FC26-06NT42747, 2010 NETL CO2 Capture Technology Meeting, 14 September. Larson, E., R. Williams, and T. Kreutz, 2012: Energy, Environmental, and Economic (E3) Analysis of Design Concepts for the Co-Production of Fuels and Chemicals with Electricity via Co-Gasification of Coal and Biomass with CCS, Final Report to the National Energy Technology Laboratory for work completed under DOE Agreement DE-FE0005373, May (forthcoming)

Liu, G, R.H. Williams, E.D. Larson and T.G. Kreutz, 2010: “Design/economics of low-carbon power generation from natural gas and biomass with synthetic fuels co-production,” 10th International Conference on Greenhouse Gas Technologies (GHGT-10), Amsterdam, Sept. 19-23, 2010.

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. Matuszewski, Michael (NETL), 2012: Private communication to Bob Williams regarding internal NETL oxycombustion retrofit study, 28 February. McDonald, Dennis, 2012: Private communication to Bob Williams from Dennis McDonald at Babcock and Wilcox, 17 May. US DOE NETL, 2007: Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Revison 1, DOE/NETL-2007/1281, August. US DOE NETL, 2008: Pulverized Coal Oxycombustion Power Plants, Revision 2, DOE/NETL-2007/1291, August. US DOE NETL, 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. US DOE NETL, 2012a: Advancing Oxycombustion Technology for Bituminous Coal Power Plants: An R&D Guide, DOE/NETL-2010/1405, February. US DOE NETL, 2012b: Current and Future Technologies for Power Generation with Post-Combustion Carbon Capture. DOE/NETL-2012/1557, 16 March.

26

US DOE NETL, 2012c: Draft of Supplemental Analysis for Baseline Studies - GEE IGCC and SC PC Zero Liquid Discharge Plants, DOE/NETL-341/102011, forthcoming. PALTF (National Research Council’s Panel on Alternative Transportation Fuels for America’s Energy Future study), 2009: Liquid Transportation Fuels from Coal and Biomass Technological Status, Costs, and Environmental Impacts, U.S. National Academy of Sciences: Washington, DC, 2009. Simbeck D, and W. Roekpooritat, 2009: “Near-term technologies for retrofit CO2 capture and storage of existing coal-fired power plants in the United States,” White Paper in MIT: Retrofitting of Coal-Fired Power Plants for CO2 Emissions Reduction, An MIT Energy Initiative Symposium, 23 March 2009.

27

Appendices for Chapter 6

Appendix 6A: Tables Summarizing Implications of the Two Thought Experiments

Table 6A1: Electricity Generation, Natural Gas & Coal Requirements, and GHG Emissions Avoided for Thought Experiments

Electricity generation, in 106 MWh/year

Natural gas for

NGCC-V,

Quads/year (coal use

relative to coal

use by WO PC plants

displaced)

Greenhouse gas

emissions avoided, million metric tons of

CO2eq/year Tech-

nology PC-Cap

Retrofit GBTLcoprod

-Cap-3.2% CBTGcoprod

-Cap-5.0% NGCC

-V

Total WO PC

electricity displaced

Elec-

tricity Syn-

fuels Total

TE #1 318 0 0 22 340 0.15 (1.3) 268 0 268 TE #2 0 45 199 32 276 0.22 (1.9) 141 101 242

Table 6A2: Synfuel & Crude Oil Production & Capital Investment Requirements for

Plants Providing CO2 for EOR in Thought Experiments

Synfuels production (S) in million barrels/day of gasoline equivalent

and crude oil production (C) in million barrels/day of crude oil TPC + OC,

except for

NGCC-V

makeup,

$109

Technology PC-Cap Retrofit GBTLcoprod -Cap-3.2%

CBTGcoprod -Cap-5.0%

Totals

Type of Fuels produced S C S C S C S C TE #1 0 3.40 0 0 0 0 0 3.40 88 TE #2 0 0 0.12 0.17 1.10 3.23 1.22 3.40 245

Appendix 6B: On Technology Choice and Location for a FOAK CO2 EOR-Linked

Coproduction Plant Coprocessing Coal and Biomass

Appendix 6B is an elaboration of the discussion in Section 6.8 on choosing for a coproduction demonstration project: (i) technological components and (ii) site.

28

Choosing technological components for the demonstration project

The choice of technological components for the demonstration project is guided by planning

goals of maximizing prospects for success and speeding the technology on to commercial

robustness. The demonstration project should not be thought of as R&D or a technology

development project. This principle might be satisfied by designing a coproduction system made

up entirely of components that are either commercial or near-commercial. In what follows

technology choices are discussed for several key system parts:

Gasification: One possibility for gasification would involve separate gasifiers – one optimized

for coal and other for biomass. However, suitable stand-alone biomass gasifiers are not yet estab-

lished in the market, whereas there has already been much experience since 2006 cogasifying

successfully up to 30% biomass (weight basis) with coal in a dry-feed entrained flow gasifier at

the Buggenum IGCC project in The Netherlands. This experience suggests that choosing co-

gasification based on a dry-feed en-trained-flow gasifier would be a relatively low-risk

technological choice for a demonstration project.

Biomass feeding: Feeding biomass into a high-pressure, entrained-flow gasifier is challenging –

requiring grinding fibrous biomass to very small particle sizes, a difficult process. The fibrous

nature of biomass can be destroyed via a slow cooking process known as torrefaction that yields

a hydrophobic “coal-like” product that can readily be milled to small particle sizes in the same

manner that coal is milled. A recent analysis suggests that cogasification of torrefied biomass

with coal, while reducing the technical risks of cogasification to make synthetic fuels, is also

likely to be slightly less costly than cogasification of biomass with coal (Larson et al., 2012).

Torrefaction technology is being demonstrated at commercial scale for woody biomass in three

plants in Europe that began operating near the end of 2010 at production scales of 35,000 –

60,000 tonnes per year (Kleinschmidt, 2011). Torrefaction of herbaceous biomass is more

challenging (EPRI, 2010), but the technology is being developed [e.g., torrefaction of corn stover

is being investigated (Grotheim, 2010)]. The least technologically risky option would be to use

torrefied woody biomass for a commercial-scale demonstration.

Biomass feedstock choice: The project developer must secure a reliable supply of biomass to

meet the lifetime needs of the demonstration project, which would typically have a targeted

lifetime of 20 years. One of the main challenges is that for most biomass feedstocks the logistics

for providing a secure long-term supply have not been worked out. If woody biomass turns out

29

to be the main targeted feedstock for a demo project, consideration might be given to making

poultry litter a complementary biomass feedstock. The logistics for providing a secure long-term

supply of poultry litter for energy projects have advanced to a high degree as a result of the

experiences at the eight poultry litter combustion-based power plants around the world – one of

which is a 55 MWe plant at Benson, Minnesota, consuming 730,000 metric tons of poultry litter

annually. Athough there is no commercial experience with poultry litter torrefaction, torrefying

poultry litter might prove to be much less challenging than torrefying woody or herbaceous

biomass, because only the bedding material in the litter (typically < 8% of the litter) is fibrous

and is often pine shavings, which are of course “woody” (Fraser, 2012).

Synthesis technology: For synthesis, consideration should be given to the fact that MTG

technology is simpler and more fully developed than FTL technology for application at the

relatively small scale that is likely to characterize a FOAK project.

Choosing a site for the demonstration project

As pointed out in Chapter 3, FOAK coproduction plants selling captured CO2 into an

EOR market will not be able to offer such attractive economics as the NOAK plants discussed

there. The heuristic FOAK cost calculations presented in Box 3-1 of Chapter 3 suggest that

demonstrations will probably require a facilitating public policy that would provide financial

incentives. Moreover, these calculations underscore the importance of choosing a site for the

project so as to minimize the needed incentive for the demonstration project.

There are several reasons for choosing a Southeastern site near the Gulf of Mexico:

• First, construction costs here are typically 10-15% less than elsewhere in the U.S.;

• Siting there would enable selling CO2 into EOR markets with minimal need for new CO2

pipeline construction;

• There are abundant supplies of relatively low-cost woody biomass in the region;

• There are five Southeastern states that produce more than 1 million tonnes/y of poultry litter

(Perara et al., 2010) that might be secured in long-term contracts at attractive prices (Jenkins,

2012).

30

Appendix 6C: R&D Priorities for Advancing Coproduction with Coal/Biomass

Coprocessing

Appendix 6C is an elaboration of the discussion in Section 6.8 on R&D priorities related

to CO2 EOR-linked coproduction involving coal/biomass coprocessing – focusing on R&D

aimed at: (i) helping ensure the success of the demonstration project, and (ii) advancing

technologies that could enable larger biomass percentages to be used in the longer term.

R&D in Support of the Commercial Demonstration Project

Perhaps the most important contribution DOE could make in support of the demonstra-

tion project would be to support R&D relating to biomass feeding into entrained flow gasifiers,

including R&D on alternatives to lock-hopper feeders, on torrefaction (e.g. of poultry litter), and

on biomass drying. An important R&D issue relating to torrefaction is whether torrefied biomass

can be used in water-slurry-fed entrained flow gasifiers (Larson et al., 2012). A high R&D

priority relating to cogasification is to advance torrefaction for herbaceous biomass feedstocks.

R&D Priorities for the Longer Term

For the longer-term, when the percentage of biomass coprocessed might increase to

~30%, it would be desirable for the DOE to support not only advanced concepts relating to

cogasification but also coprocessing via separate gasifiers for coal and biomass, because biomass

and coal are very different feedstocks. Biomass can be gasified at much lower temperatures than

coal because it is more reactive. Gasifying biomass in a high-temperature entrained-flow gasifier

leads to efficiency losses that are likely to become more significant in terms of overall system

economics as the biomass percentage increases. Gasifiers optimized for biomass are likely to be

some variant of a fluidized-bed gasifier, for which the DOE should provide R&D support, at

least until the technology is successfully established in the market. R&D priorities for such

gasifiers include options for tar cracking/light hydrocarbon reforming (the latter needed to avoid

coking in synthesis), hot filtration, and optimization of tar cracking and particulate filter

configurations (e.g., must filter be upstream of tar cracker to avoid ash-softening problems?).

Finally, because systems coprocessing large biomass percentages (~ 30%) will tend to be

limited in scale (typically providing < 10,000 bbls/d of synfuels) it is desirable to explore

concepts that would improve the economics of such small-scale systems – via concepts such as

31

use of compact equipment and construction approaches that involve more factory construction at

the expense of less field construction, which is inherently more costly.

References for Chapter 6 Appendices 8, 2010

Coda, B., M.K Cieplik, J.M. Jacobs, and J.H.A Kiel, 2009: Impact of Biomass Co-Firing on Ash

Formation and Ash Behavior in IGCC Plants, ECN-C--04-069, ECN, The Netherlands.

EPRI, 2010: Small-Scale Testing of Woody and Herbaceous Biomass Torrefaction and

Pelleting, 2020508, Program on Technology Innovation, EPRI, Palo Alto, CA, April

Fraser, Rupert (Fibrowatt USA, Langhorne, PA), 2012: Private communication to Jim Katzer,

Sharon Tucker, and Robert Williams, 28 March.

Grotheim, K., 2010: Torrefaction and Densification of Biomass Fuels for Generating Electricity,

Milestone Number: 07, Contract Number RD3-4 (Project funding provided by customers of Xcel

Energy through a grant from the Renewable Development Fund), 31 August.

Jenkins, Eric (Fibrowatt USA), 2012: Private communication to Jim Katzer, Sharon Tucker, and

Robert Williams, 2 April.

Kleinschmidt, C.P. (KEMA Nederland BV), 2011: Overview of International Developments in

Torrefacton, KEMA Nederland BV, Aenhem, The Netherlands

Larson, E., R. Williams, and T. Kreutz, 2012: Energy, Environmental, and Economic (E3)

Analysis of Design Concepts for the Co-Production of Fuels and Chemicals with Electricity via

Co-Gasification of Coal and Biomass with CCS, Final Report to the National Energy Technology

Laboratory for work completed under DOE Agreement DE-FE0005373, May (forthcoming)

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.

32

Perara, R., P. Perera, R.P. Vlosky, P. Darby, 2010: Potential of Using Poultry Litter as a

Feedstock for Energy Production, Working Paper # 88, Louisiana Forest Products Development

Center, Louisiana State University Agricultural Center, Baton Rouge, Louisiana, 15 July.

Appendix for Chapter 7: CO2 Storage Potential in Coals and Shales

a. Estimates of Geologic Storage Potential in Unmineable Coal Seams: Work sponsored by the IEA Greenhouse Gas Program (IEA GHG) in 1998 estimated that the total worldwide potential for CO2-ECBM is approximately 68 trillion cubic feet (Tcf), with about 7.1 billion metric tons (or Gigatonnes, Gt) of associated CO2storage potential. Without the application of ECBM, total non-commercial CO2storage potential in deep coal seams was estimated to be 20 to 50 times greater. The DOE/NETL Carbon Sequestration Atlas of the United States and Canada estimates that there is 60 to 117 Gt (65 billion to 128 billion tons) of potential CO2 storage potential in unmineable coal areas distributed over 21 states and one Canadian province.1

This should be considered an upside estimate, unconstrained by methane production efficiency, injectivity constraints, or other technical and economic constraints. The methane recovery potential through the application of ECBM was not assessed.

A more recent report by Advanced Resources International prepared for DOE/NETLin 2003 concluded that the estimated CO2storage capacity of U.S. coal beds was estimated to be about 90 Gt, with about 38 Gt was in Alaska, 14 Gt in the Powder River basin, 10 Gt in the San Juan basin, and 8 Gt in the Greater Green River basin. Again, this should be considered an upside estimate.The ECBM recovery potential associated with this storage potential was estimated to be over 150 Tcf, with 47 Tcf in Alaska, 20 Tcf in the Powder River Basin, 19 Tcf in the Greater Green River Basin, and 16 Tcf in the San Juan Basin.2

b. Estimates of Geologic Storage Potential in Gas Shales To date, no estimate has been made of the global CO2 storage potential in shales. One effort is underway, sponsored by the IEA GHG under contract to ARI, to estimate the global CO2 storage potential in shales, and to update estimates of the CO2 storage potential in coal seams, with results expected in late 2012. The Kentucky Geological Survey (KGS) developed initial volumetric estimates of the CO2storage capacity of the Carbonaceous (black) Devonian gas shales that underlie approximately two-thirds of Kentucky, and concluded that as much as 28 Gt could be stored in the deeper and thicker parts of these shales.3

7

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasIII/index.html Reeves, S.R., Assessment of CO2 Sequestration and ECBM Potential of U.S. Coalbeds, Topical Report, DOE Contract No. DE-FC26-00NT40924, February 2003 Nuttall, Brandon; Cortland F. Eble; James A. Drahovzal, and Mark Bustin, Analysis of Devonian Black Shales for Potential Carbon Dioxide Sequestration and Enhanced Natural Gas Production, Report DE-FC26-02NT41442 prepared by the Kentucky Geological Survey, University of Kentucky, for the U.S. Department of Energy, National Energy Technology Laboratory, December 30, 2005.

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasIII/index.html�

33

Based on data for the adsorption of CO2onto organic shales of 14 to 136 standard cubic feet (scf) per ton of shale at 400 psi and defined Marcellus Formation characteristics, NETL used the same procedure as KGS to estimate the CO2storage potential across the entire Marcellus Shale Formation in the Appalachian Basin in the eastern U.S., and estimated that the Marcellus shale has the potential to store from 17 to 166 Gt of CO2.4

One effort sponsored by DOE/NETL is underway by Advanced Resources Intrnational to assess the factors influencing effective CO2 storage capacity and injectivity in selected gas shales in the Eastern United States.5

One output of this effort will be basin-level estimates of the CO2 storage capacity the Marcellus and Utica shales in the eastern U.S. Preliminary estimates assuming an average recovery efficiency of 25% in the Marcellus would indicate potential CO2 storage capacity on the order of 80 Gt, but that number could be revised based on ongoing research.

c. Research on Recovering Methane and Storing CO2 in Coal Seams: ECBM technology is still in the development phase. Based on efforts to date, coal swelling is observed as perhaps the most significant barrier to CO2 injection into coal seams. As coal adsorbs CO2, the coal swells in volume, resulting in a decrease in porosity and permeability, which restricts the flow of CO2 into the formation and impedes the recovery of displaced methane. The most high-profile ECBM research pilot took place in Alberta, Canada; starting in 1997. The project showed that even in tight reservoirs, continuous CO2 injection is possible and that the injected CO2 remains in the reservoir while increasing sweep efficiency. This project was the first to assess using CO2/nitrogen (N2) mixtures to possibly overcome the limitations from swelling associated with injecting pure CO2.6

These impacts have also been well documented at the Tiffany ECBM pilot in the San Juan Basin of New Mexico, the only long-term N2-ECBM pilot conducted to date,7,8 as well as in Australia.9

U.S. Department of Energy/National Energy Technology Laboratory, Impact of the Marcellus Shale Gas Play on Current and Future CCS Activities, August 2010 (

These results indicate that in cases where the rank and permeability are not adequate for ECBM and storage operations, there may be opportunities to look for pulsing and or mixing

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/Marcellus_CCS.pdf) http://www.netl.doe.gov/publications/factsheets/project/FE0004633.pdf “Coalbed Methane, A Fossil Fuel Resource with the Potentialfor Zero Greenhouse Gas Emissions – the Alberta, CanadaProgram 1996 -2009: A Summary,” (http://www.cslforum.org/publications/documents/Alberta_ECBM1996_2009_summary.pdf) Advanced Resources International, Inc.; “The Tiffany Unit N2 – ECBM Pilot: A Reservoir Modeling Study”, prepared for U.S. Department of Energy Project Number: DE-FC26-0NT40924, June, 2004. Reeves S. R.; “Geological Sequestration of CO2 in Deep, Unmineable Coalbeds: An Integrated Research and Commercial-Scale Filed Demonstration Project”, SPE 71749, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, September 30-October 3, 2001. Day, Stuart, Robyn Fry, and Richard Sakurovs, “Swelling of coal in carbon dioxide, methane and their mixtures,” International Journal of Coal Geology, Vol. 93, April 2012, pp. 40-48

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/Marcellus_CCS.pdf�

http://www.netl.doe.gov/publications/factsheets/project/FE0004633.pdf�

http://www.cslforum.org/publications/documents/Alberta_ECBM1996_2009_summary.pdf�

34

N2 into the injection stream to improve injectivity during storage and ECBM operations.10 The DOE Regional Carbon Sequestration Partnerships (RCSPs)11 have performed five CO2-ECBM demonstration projects for exploring the efficacy of conducting storage operations in deep, unmineable coal seams. The DOE-sponsored Coal-Sequestration Consortium has also been underway for some time with the purpose of advancing the science of CO2storage in unmineable coal seams and gas shale reservoirs.12

Internationally, work is also underway in Australia, Japan, Poland, Switzerland, UK, Norway, Germany, the Netherlands and China.

Review of these efforts to date highlights the following key lessons applicable to CO2-ECBM and CO2 storage in coal beds:13

With a depleted reservoir due to previous gas production operations, initial injection rates can be quite robust. Injection rates will decline due to re-pressurization and swelling of the coal reservoir. The presence of hydraulic fractures complicates the injection operation. N2 may be a strong indicator of pending breakthrough. No leakage has been detected. d. Research on Recovering Methane and Storing CO2 in Gas Shales: Research on the potential for recovering methane and storing CO2 in gas shales is less advanced than that for coal seams. Ongoing reservoir characterization and reservoir simulation work is demonstrating that the basic concept that shales can store CO2 based on trapping through adsorption on organic material (similar to coals), as well as with the natural fractures within the shales, is scientifically possible, although this has not been demonstrated on a field scale. Some report the ratio of CO2 adsorbed to methane desorbed could be as high as 5 to 1.14

Still lacking, however, is sufficient testing of this concept with site-specific geologic and reservoir data and detailed reservoir simulation, verified by field tests, in a variety of gas shale settings.

For gas shales in the Eastern U.S., where at least some data are available, well log data for selected wells have been correlated to regional cross sections to develop preliminary estimates of theoretical maximum CO2 storage capacity in shale gas basins, though these estimates have yet to be published. In this work, total organic content (TOC), density porosity and water saturation were calculated from well logs to estimate effective, or gas-filled, porosity. Adsorbed methane and CO2 content were extrapolated based on available CO2 and methane adsorption isotherms. Total methane gas in-place as adsorbed gas and “free” gas (non-adsorbed gas in effective porosity) were calculated for each study well.

Schepers, Karine, Anne Oudinot, and Nino Ripepi, “Enhanced Gas Recovery and CO2 Storage in Coal Bed MethaneReservoirs: Optimized Injected Gas Composition for Mature Basinsof Various Coal Rank – Part 2,” presented at the AAPG Eastern Section Meeting, Arlington, VA, September 25 - 27, 2011 http://www.netl.doe.gov/technologies/carbon_seq/infrastructure/rcsp.html http://www.coal-seq.com/index.asp Koperna, George J., and David Riestenberg, “Carbon Dioxide Enhanced Coalbed Methane and Storage: Is There Promise?” SPE Paper SPE 126627-PP, presented at the 2009 SPE International Conference on CO2 Capture, Storage, and Utilization held in San Diego, California, USA, 2–4 November 2009. Nuttall, Brandon; Cortland F. Eble; James A. Drahovzal, and Mark Bustin, Analysis of Devonian Black Shales for Potential Carbon Dioxide Sequestration and Enhanced Natural Gas Production, Report DE-FC26-02NT41442 prepared by the Kentucky Geological Survey, University of Kentucky, for the U.S. Department of Energy, National Energy Technology Laboratory, December 30, 2005.

http://www.netl.doe.gov/technologies/carbon_seq/infrastructure/rcsp.html�

http://www.coal-seq.com/index.asp�

35

Individual well results were extrapolated to obtain estimates of total gas in-place and maximum CO2 storage capacity for selected areas for the Marcellus and Utica shales in New York, Pennsylvania, Maryland, West Virginia, and Ohio where depth to Marcellus was greater than 3,000 feet deep and the thermal maturity was greater than 1% Ro on the most recent USGS thermal maturity map for the Marcellus.15 This effort builds upon previous work on the CO2 storage potential in gas shales supported by the New York State Research and Development Authority (NYSERDA),16and Kentucky Geological Survey (KGS).17,18 Researchers at Stanford University are also investigating the feasibility of geologic CO2 sequestration in shale gas reservoirs.19

e. Potential Economic Implications of CO2 Storage in Shales and Coals: The same engineering techniques for enhancing methane production from gas shales and coals – dense well spacing, horizontal drilling, and/or hydraulic fracturing – will also likely be needed to enhance CO2 injectivity and storage in these formations. This conclusion is supported by small scale field tests and associated simulation work, but no large scale tests have yet to be conducted in either coal or shales, and with the only moderately sized injection test in coal seams being the Pump Canyon demonstration project in the San Juan basin in the south western U.S., where about 18,000 tons of CO2 were injected over a 12-month period.20

Work examining the potential economic implications of CO2storage in coal seams and shales is quite limited, although there is more field-test experience upon which to draw insights. Most economic studies have been on hypothetical case studies,21,22

which may not necessarily reflect “real-world” conditions.

Gale and Freund report that since 1996, 57 million cubic meters (2 Bcf) of CO2 have been stored in coal seams. They also concludes that based on current costs and performance, CO2-ECBM may be profitable in the US at well-head natural gas prices of US $1.75 to $2.00/Mcf. Given this, they concluded based on an analysis of representative CO2-ECBM projects that 5 to 15 Gt of

http://www.netl.doe.gov/publications/factsheets/project/FE0004633.pdf New York State Energy Research and Development Authority, Overview of CO2 Sequestration Opportunities in New York State, August 2006, and http://www.nyserda.org/en/About/Newsroom/2008-Announcements/2008-01-14-Studies-Explore-Carbon-Sequestration.aspx Nuttall, Brandon; Cortland F. Eble; James A. Drahovzal, and Mark Bustin, Analysis of Devonian Black Shales for Potential Carbon Dioxide Sequestration and Enhanced Natural Gas Production, Report DE-FC26-02NT41442 prepared by the Kentucky Geological Survey, University of Kentucky, for the U.S. Department of Energy, National Energy Technology Laboratory, December 30, 2005, and http://www.uky.edu/KGS/kyccs/ekyshale.htm Advanced Resources International, Inc., Reservoir Modeling and Simulation of the Devonian Gas Shale of Eastern Kentucky for Enhanced Gas Recovery and CO2 Storage, report prepared for the Kentucky Geological Survey, January, 2010 http://energy.gov/articles/department-energy-announces-15-projects-aimed-secure-co2-underground-storage Koperna, George J. Jr., Anne Y. Oudinot, Glenn R. McColpin, Ning Liu, Jason E. Heath, Arthur Wells, and Genevieve B. Young, “CO2-ECBM/Storage Activities at the San Juan Basin's Pump Canyon Test Site, “ SPE Paper 124002 presented at the SPE Annual Technical Conference and Exhibition, , New Orleans, Louisiana, 4-7 October 2009 Bromhal, Grant S., W. Neal Sams, Sinisha, A. Jikich, TurgayErtekin, and Duane H. Smith, “Assessing Economics for Sequestering CO2in Coal Seams with Horizontal Wells,” paper presented at the 3rd Annual Sequestration Conference, Alexandria, VA, May 3-6, 2004 Davis, Darrell, Anne Oudinot, and Aiysha Sultana, “CoalSeqV2.0 Screening Model &Economic Sensitivity Study,” paper presented at the Third International Forum on Geologic Sequestration of CO2 in Deep, Unmineable Coalseams, Baltimore, MD, March 25 & 26, 2004

http://www.netl.doe.gov/publications/factsheets/project/FE0004633.pdf�

http://www.nyserda.org/en/About/Newsroom/2008-Announcements/2008-01-14-Studies-Explore-Carbon-Sequestration.aspx�

http://www.nyserda.org/en/About/Newsroom/2008-Announcements/2008-01-14-Studies-Explore-Carbon-Sequestration.aspx�

http://www.uky.edu/KGS/kyccs/ekyshale.htm�

http://energy.gov/articles/department-energy-announces-15-projects-aimed-secure-co2-underground-storage�

36

CO2 could conceivably be stored at a net profit, while about 60 Gt of sequestration capacity may be available at moderate costs of under $50/tonne CO2.23

The 2003 ARI report (prepared for DOE/NETL) estimated that between 25 and 30 Gt of CO2was estimated to economical to store (assuming wellhead natural gas prices of $3.00/Mcf), and 80 to 85 Gt of storage potential was estimated at costs of less than $5/ton (U.S.). These estimates did not include any costs associated with CO2capture and transportation, and only represent geologic sequestration. Some critical questions that need to be addressed when understanding enhanced coal and shale recovery and CO2storage include: • What type of power plant provides best sequestration economics? • What coal and shale reservoir environment provides best economics (e.g. permeability,

depth, rank/TOC, rate, spacing, etc.)? • What gas composition provides best storage economics? • Are Greenfield or Brownfield projects better? • What conditions provides best enhanced recovery economics? • How sensitive are results to hydrocarbon prices? • How might CO2emission reduction credits impact the results? • How important is scale? • How important is distance between source and sink?

Gale, John and Paul Freund, “Coal-Bed Methane Enhancement with CO2 Sequestration Worldwide Potential,” Environmental Geosciences, Volume 8, Issue 3, pages 210–217, September 2001

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