williams 2012
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7/28/2019 Williams 2012
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Enhanced Oil Recovery (EOR) Applications of CO2 Captured in Making
Transportation Fuels Plus Electricity from Natural Gas and BiomassR.H. Williams
CMI Carbon Capture Group
Introduction Previous Capture Group research (Liu et al. 2010) showed that CCS
systems coprocessing 1/3 biomass and 2/3 natural gas could provide FTL
and coproduct electricity with ~ 10% of GHG emissions of fossil energy
displaced at attractive costs under a C-mitigation policy (e.g., Fig. 1).
Although a comprehensive US C-mitigation policy is not likely in the near
term, there is an opportunity to take first steps along a path to
coproduction of low-C transportation fuels and electricity by tying
together three threads of industrial interest:
Maximizing returns on new plants replacing coal (> 30 GW of coalpower to be retired by 2020)
GTL as result of high oil/natural gas price ratio (Fig. 2)
CO2 EOR (e.g., Energy Secretary Chu has asked the National Coal Council
to prepare for him a report on opportunities to advance CCS
technologies by using captured CO2 for EOR).
Cai et al(2011)
Findings Unlike NGCC plants, coproduction plants would be able to defend high
design capacity factors in economic dispatch competition (see Fig. 5) and
force down capacity factors of power-only competitors as their
deployment on the electric grid increases.
At high plant-gate CO2 prices PC-CCS retrofit is most profitable option,
but at CO2 prices < $30/t, coproduction options are more profitablewith GBTL-OT-CCS-3.2% being most profitable, offering real IRRE >
10%/y even for $0/t CO2 selling price (see Fig. 6).
Coproduction plants could compete in remote EOR markets if an
adequate trunk CO2 pipeline capacity were in place and in so doing
would be more profitable investments than NGCC-V (see Fig. 6).
Construction permitting should be easier/faster for rebuilds at
brownfield sites where coal plants are being retired than at greenfield
sites.
There will soon be many brownfield sites in the Ohio River Valley (ORV)
where > 40% of US coal capacity to be retired by 2020 capacity is located
and also many shale plays (see Fig. 7).
If both natural gas/biomass and coal/biomass coproduction plants were
built at sites of old coal power plants in the ORV, they might pool their
captured CO2 for transport via trunk CO2 pipelines to the EOR sites inGulf regionperhaps tying in to Denburys planned Rockport to Tinsley
pipeline (see Fig. 8).
Both coproduction plant designs (Tab. 1) could provide electricity with
GHG emissions low enough to meet proposed EPA rules for new power
plants if full fuel-cycle-wide GHG emissions were taken into account.
The synthetic liquid fuels provided by these coproduction plants would
meet GHG emissions requirement for Advanced Biofuels under RFS2
Mandate, but would not qualify as advanced biofuels under the
Mandate in its present form.
CMI Annual Meeting, 17-18 April 2012
References:
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. 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.
Autothermalreformer
RefineryH2 prod.
F-Trefining
HCrecovery
rawFTproduct
Powerisland
syncrude finished gasoline&diesel blendstocks
fluegas
netexportelectricity
unconverted syngas
+C1-C4FT gases
lightends
Naturalgas
oxygensteam
syngas
Watergasshift
CO
2removal
CO2 enrichedstreams, senttoupstreamCAP.
steam
FTsynthesis
Chopping &Lockhopper
Biomass
oxygen steam
CO2
FBgasifier&Cyclone
Dryash
FilterCO2
removal unit
CO2 H2 make-up
FIG. 1: Natural gas + biomass to FTL fuels + electricity in once-through
system configuration with mild CO2 capture (OTonly naturallyconcentrated CO2 streams are captured); GTI fluidized bed gasifier for biomass
(switchgrass); Autothermal reformer (ATR) simultaneously reforms natural gas
into syngas and serves as tar cracker for tarry syngas from GTI biomass
gasifier; Liquid phase FT synthesis with Co catalyst.
FIG. 2: Crude oil-to-natural gas spot price ratio.
TAB. 1: Some Coal-, NG-, Coal/Biomass-, and NG/Biomass-Based Energy Alternatives for Sites of Old Coal Power Plants (WO PC-V).
The greenhouse gas emissions index (GHGI) is defined as the fuel cycle-wide GHG emissions for production and consumption divided by
the GHG emissions of the fossil energy displaced, assumed to be electricity from a new supercritical coal plant and the equivalent crude
oil-derived products.
Technology
Options
106 t/y of
biomass
(% bio, HHV)
Output capacities
GHGICO2 stored, 10
6 t/y
(% feedstock C)
Total plant
cost, $106Transport fuel,
B/D ge (%, LHV)
Electricity
MWeWO PC-V 0 (0) 0 543 1.19 0 0
PC-CCS retrofit 0 (0) 0 398 0.23 3.47 (90) 752
Rebuild Options
NGCC-V 0 (0) 0 555 0.56 0 (0) 326
NGCC-CCS 0 (0) 0 475 0.20 0.64 (90) 581
GBTL-CCS-3.2% 0. 15 (3.2) 16,000 (58) 644 0.50 2.1 (46) 1598
CBTG-CCS-5.0% 0.23 (5.0) 16,000 (74) 347 0.50 4.5 (64) 2550
Using the economic framework shown in Fig. 4, both a minimum dispatch
cost (MDC) analysis (Fig. 5) and an internal rate of return on equity (IRRE)
analysis (Fig. 6) were carried out to compare these alternative options
that would provide CO2 for EOR.
-30
-20
-10
0
10
20
30
40
50
60
Crude oil
products
displaced
C input
to plant
C output
of plant
Ceq emissions
bycomponent
Net Ceq
emissions
Net GHGemissions for GBTL-CCS-3.2%
C extractedfrom atmospherevia photsynthesis
Ceqcredit for electricityemissions (NGCC-Vrate)
Ceqemissions upstream anddownstream of plant
C inchar (tolandfill)
C capturedas CO2 andstored
C as CO2in fluegases
C inFTL
C innaturalgas toplant
C inbiomass toplant
Net GHGemissions for crudeoilproducts displaced
FIG. 3: How a 50% reduction in GHG emissions for FTL is realized in a GBTL-CCS -3.2% plant.
The above are the C and GHG balances for the GBTL-CCS-3.2%, for which the net kgCeq/GJ of FTL (5th bar) = 0.50 x [kgCeq/GJ of crude
oil products displaced (1st bar)]. The plant was designed with enough biomass (3.2%) to reduce GHGI to 0.50. Assuming: (a) the latter
is new supercritical coal plant emitting 229 kgCeq/MWh & (b) equal percentage reductions in emissions for FTL & electricity, theemissions credit for the electricity coproduct (in 3rd bar) = (0.50)*(0.203 MWhe/GJ FTL)*(229 kg Ceq/MWhe) = 23.2 kg Ceq per GJ FTL.
0
10
20
30
40
50
0 10 20 30 40
Plant-gate selling price of CO 2, $ per tonne
NGCC-CCS
NGCC-V
GBTL-OT-CCS-3.2%,$90/B
PC-CCS retrofit
WOPC-V
FIG. 5: Minimum Dispatch Cost (MDC), No C-Mitigation Policy.
Systems with high MDCs cannot defend high design capacity factors
in economic dispatch competition. During 2003-2009 (when gas
prices were relatively high) the US average capacity factor (CF) for
NGCC-V plants was 39%--much lower than the 85% design CF. More
recently NGCC-V capacity factors have been higher because of lowergas prices. But if coproduction technologies become established in
the market, they will be able to defend their high design capacity
factors (90%) and force down capacity factors of competing power-
only technologies on the grid as their market penetration increases.
No curve is shown for CBTG-CCS-5.0% because its MDC is already$0/MWhe when the crude oil price is only $35/barrel.
0
3
6
9
12
15
18
0 10 20 30 40
Plant-gate CO2 sellingprice,$/t
NGCC-V(40% CF)
NGCC-CCS (40% CF)
PC-CCS retrofit
GBTL-CCS-3.2%,$90/B
CBTG-CCS-5.0%,$90/B
FIG. 6: profitability of Near-Term Options for Providing Captured
CO2 for EOR Applications, No C-Mitigation Policy. The PC-CCS retrofit
is the most profitable option for high CO2
selling prices highly
competitive for nearby EOR opportunities. Coproduction options are
more profitable for lower CO2 selling prices such systems could
compete in remote EOR markets if adequate CO2pipelineinfrastructure were in place. Coproduction systems are more
profitable than NGCC-V systems at all CO2
selling prices. NGCC-CCS
technology is not economically interesting.
Although the CO2 capture rate
for conventional GTL plant
designs is small, substantial
amounts of CO2 could be
provided for EOR by plant
designs for which electricity is a
major coproduct (see Tab. 1).
An analysis is presented for GBTL coproduction plants coprocessing 3.2%biomass (GBTL-CCS-3.2%) for which GHGI = 0.5 (Fig. 3) as rebuild option
for old coal power plant sites that compete with post-combustion PC-CCS
retrofit and coal/biomass coproduction coprocessing 5% biomass [CBTG-
CCS-5.0% (Larson et al. 2012)]all capturing CO2 for EOR (Tab. 1).
FIG. 4: Basis for Economic Calculations
All costs in $2007 including construction costs as of that year
(Owners cost)/[(total plant cost): 0.228 ( new construction); 0.202 (CCS retrofit)
45/55 debt/equity ratio
Real (inflation-corrected) cost of debt = 3.3%/year
For endogenous determination of IRRE it is assumed that:
Synfuels sold at refinery-gate price of equivalent crude oil-derived products
Electricity sold at price = levelized cost of electricity for NGCC-V @ 40% CF
These prices include value of GHG emissions based on GREET
38% combined federal/state corporate income tax rate
Property tax & insurance = 2% of TPC per year
20-year economic life & physical life for plants
Construction duration: 5 y (coproduction plants); 3 y (NGCC, PC-CCS retrofits)
Assumed CF: 90% (coproduction plants); 85% (PC-CCS retrofits); 40% (NGCC)
Assumed prices: $2.3/GJ (coal); $5/GJ (natural gas, biomass); $90/B (crude oil)
FIG. 7: There are shale plays throughout much of the Ohio River Valley, for which announcements
have been made that 14 GW of coal capacity will be retired by 2020. About the capacity
represents 25 relatively large plants---the brownfield sites of which are candidates for rebuilds.
FIG. 8: Denburys planned
Rockport to Tinsley CO2 pipelineTAB. 2: Implications of alternative uses of 2.7 Quads/y of shale gas (enough to provide 0.5 MMB/D of FTL via GBTL-CCS-3.2%) GHG emissionsavoided are those for the equivalent crude oil products and average US coal plants in 2010 (for which GHG emissions = 1044 kgCO2eq/MWh).
NGCC-V NGCC-CCS GBTL-CCS-3.2%
Assumed capacity factor 40% 40%. 90%
Generating Capacity supported, GWe 135 115 26
Electricity generation , 106 MWhe/y
(% of coal electricity in 2010)474 (26) 404 (22) 202 (11)
Liquid fuels provided, 103 stream B/D
FTL produced 0 0 500
Incremental crude oil enabled by CO 2 EOR 0 1420 860
GHG emissions avoided, 106 tonnes CO2eq
/y 270 350 170
Capital investment (TPC) required, $109 79 140 100
GHGemissionsintensity,
kgCeqperGJofFTL
MDC,
$perMWh
Internalrateofreturn
onequity,%peryear