IRRE, Aquifer Storage of CO2, $90/bbl Crude

Report
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).
References
•
IWGSCC (Interagency Working Group on the Social Cost of Carbon, US Government), 2013: “Technical
Support Document : Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis –
Under Executive Order 12866, May.
•
Liu, G., E.D. Larson, R.H. Williams, T.G. Kreutz, and X. Guo, 2011: Making Fischer-Tropsch fuels and electricity
from coal and biomass: performance and cost analysis, Energy and Fuels, 25 (1): 415-437.
•
NCC (National Coal Council), 2012: Harnessing Coal’s Carbon Content to Advance the Economy, Environment,
and Energy Security, Washington, DC, 22 June.
•
NETL (National Energy Technology Laboratory), 2010: Cost and Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2, DOE/NETL-2010/1397, November.
•
PALTF (Panel on Alternative Liquid Transportation Fuels of the National Research Council), 2009: Liquid
Transportation Fuels from Coal and Biomass Technological Status, Costs, and Environmental Impacts, a report
prepared in support of the NRC’s America’s Energy Future study (2009), U.S. National Academy of Sciences:
Washington, DC.
•
Rubin, E.S., M.R. Taylor, S. Yeh, and D.A. Hounshell, 2004: Learning curves for environmental technology and
their importance for climate policy analysis, Energy, 29: 1551–1559.
•
Van Noorden, R., 2013: “Europe’s untamed carbon,” Nature, 493: 141-142, 10 January.
•
Wehner, Scott (Chapparal Energy), 2011: “U.S. CO2 and CO2 EOR Developments," 9th Annual CO2 EOR and
Carbon Management Workshop, Houston, 5-6 December 2011.
•
Williams, R.H., 2013: Coal/biomass coprocessing strategy to enable a thriving coal industry in a carbonconstrained world, Cornerstone, 1: (1): 51-59, Copyright © 2013, World Coal Association.

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