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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