Initial Engineering Design of a Post-Combustion ... - Energy

© 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m

Dr. Des DillonEPRI, Sr. Technical Leader

DOE Project Closeout MeetingMorgantown, March 25th 2020

Initial Engineering Design of a

Post-Combustion CO2 Capture

System for Duke Energy’s East

Bend Station Using Membrane

Based TechnologyDE-FE0031589

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© 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m2

Meeting Agenda

▪ Project Overview (EPRI)

▪ Background & Technical Approach– Project objectives and structure

▪ Analysis of Integration Options (Nexant)

▪ Final Membrane Capture system design for East Bend (MTR/Trimeric) – Membrane system and CPU description (Flow sheets)

– MTR Module arrangement and design

▪ Final BOP and Aux Power Design for East Bend (Nexant/Bechtel) – BOP and Aux Power Design

– Performance

– Layout

– Preliminary HAZOP & Constructability ?

▪ Comprehensive Cost Estimates (Nexant)– Capital and O&M Cost Estimate

▪ Summary of Economic Evaluation and Final Report (EPRI) COE, CO2 avoided cost and marginal operational cost estimated– Final Report

▪ Additional Questions and Discussions



Advantages of the Membrane Capture Process

▪ Simple, passive operation with no chemical handling, emissions, or disposal issues

▪ Membrane not effected by O2, SOx or NOx; co-capture possible

– O2, SOx or NOx permeate and therefore impact the overall process design

▪ Modular technology – high volume manufacturing to lower cost, pre-assembled, containerized skids

▪ No steam use → no modifications to existing boiler/turbines

▪ Near instantaneous response; high turndown possible

▪ Very efficient at partial capture (40-60% CO2 recovery)



Challenges of the Membrane Capture Process

▪ Develop a design that will minimize the impact on the power plant by disrupting as little of the existing facilities as possible.

• Also shorten the amount of downtime before the plant can resume normal operations

▪ Develop a design that will minimize the cost of each tonne of captured CO2 while also maintaining the net 600 MW output of the East Bend Station (EBS).

• This will be done by optimizing the percentage of CO2 captured (~60%) and by adding a natural-gas-fired combustion turbine (CT) or possibly a combined cycle to offset the new auxiliary loads



Project Structure - Team

TEAM MEMBER FUNDER ROLE

US DOE NETL √ Funder

EPRI √ Lead Organization, Project management Economic Evaluation, Dispatch Modelling

Duke Energy √ East Bend Station Owners, Site Hosts, Operators, Data Gathering

Nexant Engineering Designer, System integration and Costing

- Bechtel Auxiliary Power Source Specification, Engineering and Costing

Membrane Technology and Research (MTR) √ Membrane System technology provider, Design costing and optimization.

- Trimeric Design and costing of CO2 compression / condensation / fractionation Unit in the PCC



Technical Approach 1/2

▪ Following a data gathering task that will include several site visit to the EBS, a preliminary process design will be developed for one Post Combustion Capture (PCC) system which captures CO2 from the entire flue gas stream of the power plant.

▪ This preliminary design will then be subjected to a series of analyses to examine various options for minimizing the cost of CO2 capture on a $/tonne-captured basis.

▪ The analysis will also examine several options for providing the PCC system’s auxiliary power via a CT-based power plant.

▪ Once an optimized process design has been identified, that design will be detailed and documented in a complete Process Design Package (PDP).



Technical Approach 2/2

▪ As part of this effort a HAZOP and constructability review of the design will be conducted.

▪ The PDP data will be used to carry out a techno-economic analysis that will include a +/-30% accuracy capital cost estimate as well as an estimate of the first year cost of electricity and $/tonne cost of CO2

capture for the retrofitted power plant.

▪ The marginal operating cost of the retrofitted plant with also be calculated and used in a unit dispatch model to predict how the retrofit will impact how often the coal plant is called on to operate.



Supplying the Membrane System Power Requirements

▪ Unlike solvent PCC systems - No steam requirement, but power is required to drive the membrane systems fans, blowers, vacuum compressors pumps and CO2 compression

▪ 4 ways to supply power have been considered:

– Option 1: New natural gas-fired simple cycle,

– Option 2: New natural gas-fired combined cycle

– Option 3: New simple cycle with HRSG steam to the coal plant FWH

– Option 4: Auxiliary power supplied from the existing coal station

▪ Examine which option is best suited for MTR PCC integration implementation at EBS



Product

CO2

CW

Boiler

Ash

Primary & Secondary Air

AirPreheater

Stack

Ash

ESP

HP

Turbine Generator

IP LP ~

CW

Lime

CaSO3

SCR

HP FW Htr

LP FW Htr

DeaeratorBFW Pump

Cond Pump

88 F(31 C )

95 F(35 C )

100 F(38 C )

120 F(49 C )

>120 F(>49 C )

105 F(40.5 C )

Membrane-Based CO2 Capture and

Purification Section

Treated Flue Gas

ID + Booster

SurfaceCondenser

WFGD

Coal

MTR PCC Plant Battery Limit (MTR Design)

EBS Unit 2

CW

To FGD

Makeup

To CT

Makeup

~

MTR PCC BOP (Nexant Design)

Power to

PCC Plant

PCC

CW Supply PCC

CW Return

Gas Turbine Simple Cycle Cooling Tower

Natural Gas

from Pipeline

Exhaust to

Vent

(Actual 7F.04 GT SC Power Output available at 92 F is approximately 80% of Iso-rated values)

Aux Power Option 1: New natural gas-fired simple cycle



Aux Power impact on cost of CO2 Capture & COE

Note: Preliminary evaluation to help facilitate auxiliary power selection (NOT FINAL RESULTS))

$3.50/MSCF NG cost



Results From Auxiliary Power Assessment

▪ Similar cost of CO2 capture for all integration options (within margin of error)

▪ Selection of best option may be based on overall ease of integration instead of cost

▪ Recommend simple cycle (Option 1) using single GE7F04 turbine

– Lowest upfront cost of all the external power options considered

– Allow phased implementation of feedwater preheat (Option 3)

– Enough temperature & heat available for future EBS HP feedwater preheating if desired

– Potential for future addition of a full size HRSG, should the owner at a later date, consider additional power export of value

– GE 7F.04 was the old GE 7FA GT and its operation is well established commercially



Design Approach

▪ Assess Key Attributes of East Bend Station– Flue gas composition, temperature, pressure and flow

rate– Operability requirements– Desired capture rates and quantities– Cooling water availability and conditions– Cost of power assumptions

▪ Define project assumptions– Membrane cost and performance values– Set range of process pressure conditions– Consider process design – options for membrane

stages, steps, and recycles.

▪ Conduct process simulations

Plot for capture island



Flue Gas Composition at East Bend Station

10.1%

11.7%12.2%

12.8%

15.6%

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

11%

12%

13%

14%

15%

16%

17%

EBS - wet EBS - dry EBS - wet, low leak Typical - wet Typical - dry

CO2 Content in Flue Gas



Initial Process Design Parameters

▪ Membrane:– First-of-a-kind membrane performance

– Lower CO2 content benefits from a two-stage, two-step design

▪ Flue gas flow rate required two direct contact coolers

▪ Process equipment sized for summer design conditions

▪ Design basis cases include:– Annual average

– Summer design

– Turn down (50%)

Typical two-stage design

Two-stage, two-step design



Modular Membrane Container

▪ Capture process based on modular membrane containers

▪ Systems are scaled using multiple repeating units

▪ Flanged connections for flue gas in, flue gas out, and CO2

rich stream out.

▪ Inexpensive transportation, installation and changeout.



East Bend Station – Capture System Flowsheet



East Bend Station – Capture System Flowsheet – Island A

2 x 50%



East Bend Station – Capture System Flowsheet – Island B



East Bend Station – Capture System Flowsheet – Island C



East Bend Station – Capture System Flowsheet – Island D3 x 33%



Purchased Equipment Cost for the Capture Island

$124,175,000

$32,780,000

$70,494,000

$14,378,000

$17,150,000

$14,613,000

$0

$50,000,000

$100,000,000

$150,000,000

$200,000,000

$250,000,000

$300,000,000

Liquifaction andPurifcation

RefigerationPackage

Heat Exchangersand Knockouts

Vacuum andCompressionEquipment

MembraneStage 2

MembraneStage 1

($000)

Purchased Equipment $273,590

Labor and Materials $225,639

Bare Erected Cost $499,229

Engineering and Const. Management $49,923

Process and Project Contingencies $157,257

Total Plant Cost – Capture Island $706,409

Most of the PEC cost is attributable to the membrane and the rotating equipment

• 57% Membrane

• 26% Fans, Blowers and Compressors

• 17% Balance

$273,590,000



Plan view

General ArrangementFlue Gas Return

DCC

Flue Gas Feed

Membrane Stage 1

Vacuum Compressors

Stage 2, Step 1 Membrane

Stage 2, Step 2 Membrane

Compression and

Liquefaction

Capture plant is arranged in two

trains (2 x 50%) for: the DCC, flue

gas fan, and flue gas distribution

to the first stage membrane.



Key Findings and Takeaways from MTR

▪ This project significantly advanced MTR’s understanding of large-scale design

▪ Vendor product options were identified for all parts of the capture plant

▪ Host site and locational conditions are important:

– Reducing air inleak: potential to reduce membrane area/cost by ~27%

▪ Moving from FOAK to NOAK membrane manufacturing will be impactful

▪ Where possible, emphasize shop fabrication vs. field assembly to reduce

installation costs

▪ Carefully manage and optimize flue gas distribution in ductwork (CapEx vs. OpEx)

▪ The power output from the GT and the power demand of the capture island

divergent with increasing ambient temperatures



EBS PCC Retrofit BOP & Aux Power Systems

Flue Gas

Handling

Equipment includes:

• MTR membrane systems

• Auxiliaries (vacuum fans,

blowers, intercoolers, heat

exchangers, CO2 pumps,

refrigeration units, etc.…)

EBS Flue GasMTR PCC

Equipment includes:

• Gas turbine package

• Natural gas supply pipeline

CO2 Product

Power

Supply

Natural Gas

Power

Equipment includes:

• Flue gas ducting

• Flue gas blower

• DCC/caustic scrubber and

auxiliaries

Cooling

Water

System

Makeup Water

Cooling Water

Supply & Return

Equipment includes:

• Cooling tower package

• CW circulation system

• MU water treatment system

Balance of

Plant

Equipment includes:

• Plant/instrument air system

• Electrical system

• Instrumentation and control

• Fire protection system

• Flare and relief system

Buildings

Includes:

• Admin building

• Control system building

• Laboratory and warehouse

• Water treatment building

Equipment design provided by Nexant

Equipment design provided by MTR



Key Considerations For Retrofit Design

▪ Avoid triggering New Source Review▪ EBS Net power export remains the same as before PCC retrofit

▪ Add new gas-fired power generation to supply all PCC auxiliary power demand (Normally no net power export from new generation facility)

▪ Exception is Case 4, which does not add new generation capacity and the MTR PCC simply buys its power needs from EBS

▪ No (or minimum) modification to existing EBS power train

▪ Assume tie-in to existing EBS plant to allow ▪ Safe shutdown of PCC facilities in emergencies

▪ Planned black start-up of PCC facilities

▪ Minor PCC power in-balances during GT transient operations



Initial Final Design Findings

▪ FindingMTR Island Summer Design power consumptions for 60% CO2 recovery increased to 148 MW from the 130 MW estimated for the Integration Evaluation.

▪ Issue1 x 7F.04 GTSC can’t supply the total PCC Summer Design (92 °F ambient temperature) power demand when including the roughly 30 MW non-MTR BOP facilities demands.



Possible Solutions to Initial Final Design Issues

1. Bigger GT: 250 MW 7F.05 next size range machines

2. Evaporative Cooling: Cool 92 oF ambient air at 77 oF WBT down to about 82 oF saturation to increase 7F.04 output to roughly 170 MW

3. Optimize Compressor/Blower Efficiency: Work with OEM to reduce power demands

4. Reduce 92 oF CO2 Recovery: Design for 60% recovery at lower ambient temperature for when 7F.04 can generate higher output.

High Ambient Temperature Occurance Frequency

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

60 65 70 75 80 85 90 95

Ambient Temperature, deg F

% o

f Tim

e Te

mpe

ratu

re E

xcee

ds

Annual Occurance May thru Sept Occurance



Final Design Condition Selection

▪ Minimize capital investment on idling capacity and maximize equipment capacity utilization at continuous design operations:

– Don’t add evaporative cooling or change to larger 7F.05 GT since these will be used less than 10% of the time in a year and less than 20% during summer months.

– Work with compressor/blower OEM to optimize machine efficiencies.

– Design for 60% recovery at lower ambient temperature (average annual ambient temperature).

– Reduce flue gas flow through MTR island during 92 oF summer ambient conditions to keep total power demand within 7F.04 GT output capacity



Revised Final PCC Pre-FEED Design Basis

Summer AnnualBypass Average

Design Ambient Temperature

- Dry Bulb Temperature 92 oF 54 oF

- Wet Bulb Temperature 77 oF 48 oF

Cooling Water

– Maximum Supply Temperature 88 oF 70 oF

– Maximum Return Temperature 113 oF 90 oF

– Cooling Water Cycles of Concentration 3 3

CO2 Recovery

– % of CO2 in EBS Flue Gas As Calc 60%



EBS MTR PCC Retrofit Operating Scenarios

▪ Scenarios evaluated:– 100% annual average

– 75% summer bypass (25% flue gas bypass MTR)

– 50% minimum turndown at annual average ambient conditions

Plant EBS MTR PCC Retrofit

Scenario 100% annual average

75% summer w 25% bypass

50% minimum turndown

EBS Performance Rate Guaranteed Guaranteed Min. turndown EBS Gross Power Output, MWe 640 640 250Operating Ambient Conditions Annual average Summer design Annual averageFlue Gas Bypass MTR 0% 25% 0%CO2 Generated from EBS, stpd 16,090 16,090 6,838CO2 to MTR PCC Plant, stpd

Gas Turbine Exhaust CO2, stpd

16,090

2,444

12,068

2,409

6,838

1,622



Major BOP and Power Supply Systems

▪ Duct works to divert desulfurized Flue Gas (FG) from three existing EBS WFGD to the new MTR PCC, and to return CO2-depleted FG to existing EBS stack for release to atmosphere.

▪ Two 50% FG blowers to offset supply and return duct work pressure drops

▪ Two 50% FG feed conditioning systems

▪ One 198 MW GE7F.04 Gas Turbine Genset

▪ Twenty miles of 10” diameter natural gas supply pipeline

▪ A 10-cell cooling tower (CT) with circulation pumps, and underground cooling water (CW) distribution lines

▪ Electrical distribution system

▪ Makeup water and wastewater treating systems, plant and instrument air system, fire protection system, flare and relief system, and Buildings



Flue Gas Feed Blower and Conditioning Systems

▪ Two 50% FG blowers are included to offset pressure drops through the feed conditioning, supply and return duct works. Each blower is sized to handle 1,000,000 cubic feet per minute of FG at a head of 60” wc.

▪ Two 50% FG feed conditioning trains are included to reduce the flue gas feed sulfur and moisture before going to the MTR CO2 Capture Island. – Each train consists of a Direct Contact Column with circulation pumps and Plate &

Frame heat exchangers

– Each Contact Column has two packed bed sections:– Deep Flue Gas Desulfurization (DFGD) bottom bed to reduce the FG sulfur

content down below 5 ppm with caustic scrubbing

– Direct Contact Cooler (DCC) top bed to cool the FG to lowest temperature achievable with available cooling water (CW) to minimize MTR feed moisture content



DFGD/DCC Operation @ Annual Avg Temp w 70 °F CW:

70 °F

(21 °C )

95 °F

80 °F

(27 °C )

120 °F

(49 °C )

~148 °F

(~64 °C )

86 °F

(30 °C )

CW

To MTR PCC

Capture Island

Caustic

Makeup

Spent Caustic

DCC

Bed

DFGD

Bed

120 °F

(49 °C )

Direct Contactor

51’ ID x 127’ T/T

FG Blower10,150 MkW

2.2 PSI Head

One of Two

Identical Trains

Flue Gas

from WFGD

DCC Condensate to

FGD or CT Makeup

115 °F

(46 °C )

15,330 GPM

957 MkW

DCC Cooler

263 MM

11,000 GPM

576 MkW

125 °F



DFGD/DCC Operation @ Annual Avg Temp w 88 °F CW:

88 °F

(31 °C )

108 °F

99 °F

(37 °C )

120 °F

(49 °C )

~145 °F

(~63 °C )

105 °F

(40.5 °C )

CW

Feed To MTR PCC

Capture Island

Caustic

Makeup

Spent Caustic

DCC

Bed

DFGD

Bed

120 °F

(49 °C )

Direct Contactor

51’ ID x 127’ T/T

FG Blower9,370 MkW

2.0 PSI Head

One of Two

Identical Trains

Flue Gas

from WFGD

DCC Condensate to

FGD or CT Makeup

114 °F

(46 °C ) DCC Cooler

122 MM

15,570 GPM

974 MkW

8,240 GPM

432 MkW

125 °F

Treated Gas from MTR

PCC Capture Island

25%

Bypass



Electrical Distribution Systems

▪ Not true stand-alone islanded operation

▪ Assume tie-in to existing EBS plant to allow

▪ Safe startup and shutdown of PCC facilities in emergencies

▪ Planned black start-up of PCC facilities

▪ Minor PCC power in-balances during GT transient operations

▪ No net power export on annual operation basis



Retrofit Operating Scenarios & CO2 Capture Performances




Plant EBS MTR PCC RetrofitScenario 100% annual

average75% summer w 25% bypass


EBS Performance Rate Guaranteed Guaranteed Min. turndown EBS Gross Power Output, MWe 640 640 250Operating Ambient Conditions Annual average Summer design Annual averageFlue Gas Bypass MTR 0% 25% 0%CO2 Generated from EBS, stpd 16,090 16,090 6,838CO2 to MTR PCC Plant, stpdEBS Flue Gas CO2 Captured by MTR, stpdCO2 Capture Rate, % of EBS Flue Gas CO2 onlyGas Turbine Exhaust CO2, stpdNet CO2 Capture Rate (incl GT CO2 emissions)

16,0909,68860%

2,44452%

12,0688,39552%

2,40945%

6,8383,97358%

1,62247%



EBS MTR PCC Retrofit Overall Plant Performance


average75% summer w

25% bypass50% minimum

turndownEBS Flue Gas CO2 Captured, stpd 9,688 8,395 3,973CO2 Capture Rate, % of EBS Flue Gas CO2 only 60% 52% 58%Net CO2 Capture Rate (incl GT CO2 emissions) 52% 45% 47%POWER BALANCE, MWe

GenerationGas Turbine Output 165.3 162.8 89.1

Auxiliary LoadsGas Turbine Auxiliary Loads 2.5 2.5 2.3Makeup and Waste Water Pump 0.2 0.2 0.1CW Pump and CT Fans 8.8 7.7 5.0Flue Gas Feed Blower 25.3 22.7 13.5DCC Circulating Water Pump 3.1 2.9 1.7MTR PCC Loads 125.5 126.9 66.5

Total Auxiliary Loads 165.3 162.8 89.1NET POWER OUTPUT 0.0 0.0 0.0COOLING DUTY, MMBtu/hr

DCC 529 228 250MTR PCC 685 762 378

TOTAL COOLING LOAD 1,215 990 628



Overall Incremental Water Balances – 100% Annual

Average Operation



Overall Incremental Water Balances – 75% Summer

Design Operation



Plant Tie-in and Layout

▪ The MTR carbon capture unit is located to the south-east of the existing Unit 2 stack, with the power block located south-east of the MTR modules.

▪ Flue gas is routed east from the outlet of the 3 Absorbers via three 22 foot diameter round ducts to a common rectangular duct. This duct runs at a high elevation to clear existing structures and to allow clear access.

▪ The rectangular duct supplies the gas via vertical branch ducts to two, 2 stage at-grade axial flow fans that discharge into dedicated 22 foot square ducts to deliver the flue gas to the two Direct Contract Coolers (DCC’s).

▪ The supply ducts use carbon steel with a stainless cladding for corrosion protection.▪ The return gas from the MTR unit is routed in a common rectangular duct which is 36’ x

26’ in cross-section.▪ The return duct is split into 2 branches at the stack and will tie into the existing bypass

duct stack penetrations.▪ The return duct material of construction is coated carbon steel.▪ Overall pressure drop in the duct and DCC’s is approximately 2 psi.



Plant Tie-in and Layout

▪ Refer to the next two slides for the plot plan and location of the new cooling tower.

▪ A new 10 cell wet cooling tower will be constructed for the MTR unit.

▪ New cooling tower will be located to the east of the existing cooling tower, at a sufficient distance to preclude recirculation effects.

▪ Cooling water supply and return piping will be routed underground to the MTR unit and back to the cooling tower.

▪ New cooling water pumps will be installed at the cooling tower basin to supply the MTR unit.

▪ Makeup water will be pumped from the river water pumping station using new cooling tower makeup forwarding pumps.

▪ Makeup water piping will also be routed underground





Preliminary HAZOP (HAZID) Review

▪ PFD Based Review (No P&ID)

▪ More of a HAZID review than traditional HAZOP review

▪ Emphasize on identifying startup, shutdown, transient, and emergency operational needs

▪ Identify items need further attention during FEED phase



Preliminary Constructability Review

▪ Generalized review on:

▪ Construction sequences

▪ Critical path items

▪ Construction utility resources

▪ Potential lay down areas

▪ Large equipment transportations

▪ Identify items need further attention during FEED phase



Total Plant Cost Details (End 2018 Cost Basis)



Total Plant Cost Details

Overall EBS Retrofit

TPC = $1,044 MM

Overall MTR PCC System

TPC = $706 MM

▪ TPC is essentially evenly distributed among:

– MTR membrane cost [33%]

– MTR non-membrane cost (within MTR PCC capture block) [34%]

– Retrofit BOP cost (flue gas handling, power supply etc…) [32]



Retrofit Operating Scenarios & CO2 Capture Performances





average75% summer w 25% bypass


EBS Performance Rate Guaranteed Guaranteed Min. turndown EBS Gross Power Output, MWe 640 640 250Operating Ambient Conditions Annual average Summer design Annual averageFlue Gas Bypass MTR 0% 25% 0%CO2 Generated from EBS, stpd 16,090 16,090 6,838CO2 to MTR PCC Plant, stpdEBS Flue Gas CO2 Captured by MTR, stpdCO2 Capture Rate, % of EBS Flue Gas CO2 onlyGas Turbine Exhaust CO2, stpdNet CO2 Capture Rate (incl GT CO2 emissions)

16,0909,68860%

2,44452%

12,0688,39552%

2,40945%

6,8383,97358%

1,62247%



EBS MTR PCC Retrofit Overall Plant Performance Plant EBS MTR PCC RetrofitScenario 100% annual

average75% summer w

25% bypass50% minimum

turndownEBS Flue Gas CO2 Captured, stpd 9,688 8,395 3,973CO2 Capture Rate, % of EBS Flue Gas CO2 only 60% 52% 58%Net CO2 Capture Rate (incl GT CO2 emissions) 52% 45% 47%POWER BALANCE, MWe

GenerationGas Turbine Output 165.3 162.8 89.1

Auxiliary LoadsGas Turbine Auxiliary Loads 2.5 2.5 2.3Makeup and Waste Water Pump 0.2 0.2 0.1CW Pump and CT Fans 8.8 7.7 5.0Flue Gas Feed Blower 25.3 22.7 13.5DCC Circulating Water Pump 3.1 2.9 1.7MTR PCC Loads 125.5 126.9 66.5

Total Auxiliary Loads 165.3 162.8 89.1NET POWER OUTPUT 0.0 0.0 0.0COOLING DUTY, MMBtu/hr

DCC 529 228 250MTR PCC 685 762 378

TOTAL COOLING LOAD 1,215 990 628

MTR PCC plant operates at 75% flue gas load during summer conditions



Fixed Operating Cost

Plant EBS MTR PCC RetrofitCost Basis Year End 2018Average All-In Labor Rate $70,000 /yrOperating Labor Positions 9Overhead Labor Positions 10Fixed OPEX $MM/yr

Operating Labor 42 operating staff 2.9

Maintenance Labor (excl MTR Membrane TPC) 1% of TPC 7.0Maintenance Material (excl MTR Membrane TPC) 1% of TPC 7.0Labor Overhead 10 admin staff 0.7Insurance 1% of TPC 10.4Property Tax 1% of TPC 10.4Total Fixed Operating Cost 38.5

Maintenance labor and material for MTR membrane is estimated within membrane replacement costs



Variable Operating Cost

Plant EBS MTR PCC RetrofitOperating Scenario 100% Annual AverageCost Basis Year End 2018Operating hours 8,000/yrVariable OPEX

Unit CostProcess Consumables Consumption Units per year ($ per unit) $MM/yr

Natural Gas Feed 13,154,400 MSCF 3.5 46.0

River Water 15,537 1000 gallons 0.38 0.01

CO2 Product Export 3,229,200 ston -- --

Net Power Export 531 MWh -- --

Process Waste Water 9,864 1000 gallons 0.04 0.004

TOTAL PROCESS CONSUMABLES 46.1

Catalysts and Chemicals

MU Water, CW and WWT Chemicals 0.77

Caustic Scrubber NaOH 3,104 ston 408 1.3

Membrane Replacement 10.3% Membrane Eqpt162.6MM

16.7

Membrane Disposal 0.04% Cost 0.07

Refrigerant Makeup 2.5 ston 1,200 0.003

CO2 Dryer Desiccant 0.8 beds 78,000 0.06

TOTAL CATALYST AND CHEMICALS 18.8

Total Variable Operating Costs 64.9



Operating Costs for Various Operating Scenarios

Plant EBS MTR PCC RetrofitCost Basis Year End 2018Operating hours 8,000/yrScenario 100% annual

average 75% summer bypass 50% minimum

turndownEBS Flue Gas CO2 Captured, stpd 9,688 8,395 3,973EBS Flue Gas CO2 Emitted, stpd 6,402 7,695 2,865Gas Turbine Exhaust CO2, stpd (includes CO2 from air) 2,444 2,409 1,622CO2 Capture Rate, % of EBS Flue Gas CO2 only 60.2% 52.2% 58.1%Net CO2 Capture Rate (incl GT CO2 emissions) 52.3% 45.4% 47.0%

$MM/yr $MM/yr $MM/yr

Fixed OPEX 38.5 38.5 38.5

Variable OPEX

TOTAL PROCESS CONSUMABLES 46.1 45.4 30.6

TOTAL CATALYST AND CHEMICALS 18.8 18.4 18.0

Total OPEX 103.4 102.3 87.2

Total Operating Costs ($/ston CO2) 32.0 36.6 65.8



Interest rate on debt 5.0%

Nominal escalation rate 3.0%

Debt term 15 years

Years to construct 3 years

Natural gas price $3.50/MMscf

CO2 trans. & storage cost $10/metric ton

Internal rate of return on equity 10%

Operational life time 30 years

Discounted cash flow analysis suggests (additional) cost of electricity

between about $50 and $60 per megawatt-hour

• This is the additional revenue required from the sale of the original plant’s electric output to generate a return on investment in the capture process

• Based on operation at the “annual average” performance• 600 MWe net power to grid• No change in plant availability due to the presence of

the capture process• Key economic assumptions:

48

50

52

54

56

58

60

62

70

80

90

100

110

120

130

140

70.0% 72.5% 75.0% 77.5% 80.0% 82.5% 85.0% 87.5% 90.0%

Co

st o

f el

ectr

icit

y (U

SD/M

Wh

)

Co

st o

f C

O2

Cap

ture

d o

r A

void

ed (

USD

/met

ric

ton

)

Capacity Factor

45% debt financing

55% debt financing



Operating caseAnnual Average

Summer Bypass

Min. Turndown

Net Output (MWh/day) 14,402 14,402 14,418

EBS Emitted (t/net MWh) 0.403 0.485 0.180CT Emitted (t/net MWh) 0.154 0.152 0.102

Total 0.557 0.636 0.282

CO2 captured (t/MWh 0.610 0.529 0.250

EBS only capture rate 60.2% 52.2% 58.1%Overall capture rate 52.3% 45.4% 47.0%

No capture emissions (t/MWh) 1.014 1.014 0.431

Short run dispatch costs (USD/MWh)Natural gas 9.59 9.45 6.38

CO2 T&S 6.10 5.29 2.50Everything else 3.79 3.71 3.62

Total 19.49 18.45 12.50

Short-run costs are about equally fuel distributed between fuel and other VOM costs

Portion of capital that is debt financed 45% 55%

Capital 24.69 23.93

USD/MWh

VOM (excl. T&S) 13.38 13.38

T&S 6.10 6.10

FOM 9.84 9.84

COE 54.02 53.26

Cost captured 78.53 77.27USD/metric ton

Cost avoided 118.37 116.69

Capital costs contribute about 45% of the added cost of electricity

After accounting for the emissions from natural gas, about half of the

original emissions are avoided



Final Report

▪ A final report will be written that shall include:

– A description of the existing plant and the retrofit changes required to add CO2 capture.

– Process descriptions with process flow diagrams, and heat and material balances for the PCC plant including CO2 compression.

– A plot plan to establish the space required for the PCC plant.

– Equipment lists with sizing of major items for the PCC plant.

– Breakdown of costs by system for the PCC plant.

– Power, cooling water, and consumables used by the PCC plant.

– Description on preliminary PCC startup, shutdown, and bypass operating procedures with flow diagrams, and equipment requirements for integration with the existing power plant.

– All environmental emissions from the retrofitted PCC plant, including all disposal

requirements.



Acknowledgement and Disclaimer

AcknowledgementThis material is based upon work supported by the Department of Energy under Award Number DE-FE0031589. DisclaimerThis report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.



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