1 Flue Gas Aerosol Pretreatment Technologies to Minimize Post-Combustion CO 2 Capture (PCC) Solvent Losses DOE funding award DE-FE0031592 2018 NETL CO 2 Capture Technology Meeting Devin Bostick, Linde LLC August 16, 2018 Pittsburgh, PA
Transcript
1
Flue Gas Aerosol Pretreatment Technologies to Minimize Post-Combustion CO2 Capture (PCC) Solvent Losses
DOE funding award DE-FE0031592
2018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
2
Acknowledgement and Disclaimer
Acknowledgement This presentation is based on work supported by the Department of Energy under Award Number DE-FE0031592
Disclaimer ldquoThis presentation 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 thereofrdquo
Linde EngineeringTechnology-focused Air Separation
Global 1
Air Separation
Global 1
Hydrogen Syn Gas
Global 2
Hydrogen Syn Gas
Global 2
Olefins
Global 2
Olefins
Global 2
Natural Gas
Global 3
Natural Gas
Global 3
HyCO Tonnage Plants
gt70 plants
HyCO Tonnage Plants
gt70 plants
HyCO Tonnage Plants
gt70 plants
ASU Tonnage Plants
gt300 plants
ASU Tonnage Plants
gt300 plants
ECOVAR Std Plants
gt1000 plants
ECOVAR Std Plants
gt1000 plants
Linde Gas - TonnageWorld-class operations
CO2 Plants
gt100 plants
Founded
Sales (2017)
Employees
Countries
US Linde Gas HQ
US Linde Engineering Facilities
Leveraging
Synergies
1879
$20 billion
64000
gt100
Bridgewater NJ
Tulsa OK
Holly Springs GA
Houston TX
Linde has extensive experience in CO2 capture amp handling
5
Experience in design amp erection of different wash processes for CO2
removalbull Linde-Rectisol reg
bull BASF Oase technreg
bull Benfield
Long experience in operation of CO2 plants transport amp distribution
bull OCAP pipeline (Netherlands)
bull Onsite business
bull Bulk supply
CO2 Capture and Injection
LNG plant for Statoil in SnoslashhvitNorway with CO2
capture from natural gas and CO2 re-injection off-shore
CO2 Wash Units
Removal of impurities like Hydrocarbons Heavy metals O2 amp H2O for food grade CO2
CO2 Food Grade Plants CO2 Transport and Distribution
6
Overall ObjectiveDemonstrate and evaluate two innovative flue gas aerosol pretreatment technologies identified to significantly reduce high aerosol particle concentrations (gt107 particlescm3) in the 70-200 nm particle size range
(1) A high velocity water spray-based system with unique design features(2) A novel electrostatic precipitator (ESP) device with an optimized design and operating conditions
Specific Objectivesmdash Complete an aerosol mechanism literature review and develop a mechanistic model
characterizing aerosol formation and interaction with amine solvent in the absorber of a PCC plantmdash Design build install commission and operate the two technologies for flue gas aerosol
pretreatment at a coal-fired power plant host site providing the flue gas as a slipstream at a flow rate of 500-1000 scfm
mdash Complete parametric testing and analysis of each technology to demonstrate achievement of target performance
mdash Complete a benchmarking study to identify the optimal aerosol pretreatment system for commercial deployment and integration with solvent-based PCC technology
Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Budget Period 1 612018 11302018
10 Project management 612018 11302018
21 Mechanism review 612018 6292018
22 Mechanism modeling 722018 11282018
31 Design basis dev 612018 6292018
32 Basic engineering 722018 1052018
33 Detailed engineering 1082018 11282018
34 Test planning 10292018 11282018
Budget Period 2 1232018 11292019
10 Project management 1232018 11292019
41 ESP system fabrication 1232018 8302019
42 Spray system fabrication 1232018 8302019
43 Procurement for install 1232018 8302019
51 Site installation 922019 10182019
52 Commission amp start-up 10212019 11292019
Budget Period 3 1222019 11302020
10 Project management 1222019 11302020
61 ESP system tests 1222019 2242020
62 Spray system tests 2172020 4302020
63 Test analysis 542020 8282020
70 Benchmarking analysis 8312020 11272020
80 Removal of equipment 8312020 11272020
Project Scope Timeline amp Milestones
7
BP1 Design amp Engineering
A
B
C
D
E
F
G
HIJ
BP2 Fabrication amp Installation
BP3 Testing amp Analysis
Task ID Milestone Completion Date1 A Updated PMP 629181 B Kick-Off Meeting 727182 C Mechanisms review amp modeling complete 1130183 D Design amp engineering complete 1130183 E Test plan complete 1130184 F Fabrication amp procurement complete 830195 G Installation amp commissioning complete 1129196 H Parametric testing complete 51207 I Benchmarking analysis complete 1130208 J Removal of equipment complete 113020
8
Project Participants
Partner
Organization
Lead contact(s) Key Role(s)
DOE-NETL Andy Aurelio Project Manager
-Funding amp sponsorship
Linde LLC Devin BostickPrincipal InvestigatorKrish Krishnamurthy Technology Director
-Prime contract-Overall program management-High velocity water spray-based aerosol pretreatment technology owner
University of Illinois Urbana-Champaign (UIUC)
Kevin OrsquoBrien Project Lead
-Aerosol mechanisms review-Host site liaison-Flue gas and liquid effluent composition measurement amp analysis
Washington University in St Louis (WUSTL)
Pratim BiswasProject Lead
-Aerosol mechanisms modeling lead-ESP-based aerosol pretreatment technology owner-Characterization of aerosols in flue gas
Affiliated Construction Services (ACS)
Greg LarsonProject Lead
-Procurement management for high velocity water spray-based system-Construction management for site modifications amp module installation
9
Project Budget DOE Funding and Cost Share
SourceBudget Period 1
Jun 2018 ndash Nov 2018
Budget Period 2
Dec 2018 ndash Nov 2019
Budget Period 3
Dec 2019 ndash Nov 2020Total
DOE Funding $457822 $1290725 $1078826 $2827834
Cost Share $176612 $260949 $269860 $707421
Total Project $634435 $1551674 $1348686 $3534795
Cost share commitments
Linde $234869
University of Illinois (UIUC) $231339
Washington University in St Louis (WUSTL) $191213
Affiliated Construction Services (ACS) $50000
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
2
Acknowledgement and Disclaimer
Acknowledgement This presentation is based on work supported by the Department of Energy under Award Number DE-FE0031592
Disclaimer ldquoThis presentation 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 thereofrdquo
Linde EngineeringTechnology-focused Air Separation
Global 1
Air Separation
Global 1
Hydrogen Syn Gas
Global 2
Hydrogen Syn Gas
Global 2
Olefins
Global 2
Olefins
Global 2
Natural Gas
Global 3
Natural Gas
Global 3
HyCO Tonnage Plants
gt70 plants
HyCO Tonnage Plants
gt70 plants
HyCO Tonnage Plants
gt70 plants
ASU Tonnage Plants
gt300 plants
ASU Tonnage Plants
gt300 plants
ECOVAR Std Plants
gt1000 plants
ECOVAR Std Plants
gt1000 plants
Linde Gas - TonnageWorld-class operations
CO2 Plants
gt100 plants
Founded
Sales (2017)
Employees
Countries
US Linde Gas HQ
US Linde Engineering Facilities
Leveraging
Synergies
1879
$20 billion
64000
gt100
Bridgewater NJ
Tulsa OK
Holly Springs GA
Houston TX
Linde has extensive experience in CO2 capture amp handling
5
Experience in design amp erection of different wash processes for CO2
removalbull Linde-Rectisol reg
bull BASF Oase technreg
bull Benfield
Long experience in operation of CO2 plants transport amp distribution
bull OCAP pipeline (Netherlands)
bull Onsite business
bull Bulk supply
CO2 Capture and Injection
LNG plant for Statoil in SnoslashhvitNorway with CO2
capture from natural gas and CO2 re-injection off-shore
CO2 Wash Units
Removal of impurities like Hydrocarbons Heavy metals O2 amp H2O for food grade CO2
CO2 Food Grade Plants CO2 Transport and Distribution
6
Overall ObjectiveDemonstrate and evaluate two innovative flue gas aerosol pretreatment technologies identified to significantly reduce high aerosol particle concentrations (gt107 particlescm3) in the 70-200 nm particle size range
(1) A high velocity water spray-based system with unique design features(2) A novel electrostatic precipitator (ESP) device with an optimized design and operating conditions
Specific Objectivesmdash Complete an aerosol mechanism literature review and develop a mechanistic model
characterizing aerosol formation and interaction with amine solvent in the absorber of a PCC plantmdash Design build install commission and operate the two technologies for flue gas aerosol
pretreatment at a coal-fired power plant host site providing the flue gas as a slipstream at a flow rate of 500-1000 scfm
mdash Complete parametric testing and analysis of each technology to demonstrate achievement of target performance
mdash Complete a benchmarking study to identify the optimal aerosol pretreatment system for commercial deployment and integration with solvent-based PCC technology
Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Budget Period 1 612018 11302018
10 Project management 612018 11302018
21 Mechanism review 612018 6292018
22 Mechanism modeling 722018 11282018
31 Design basis dev 612018 6292018
32 Basic engineering 722018 1052018
33 Detailed engineering 1082018 11282018
34 Test planning 10292018 11282018
Budget Period 2 1232018 11292019
10 Project management 1232018 11292019
41 ESP system fabrication 1232018 8302019
42 Spray system fabrication 1232018 8302019
43 Procurement for install 1232018 8302019
51 Site installation 922019 10182019
52 Commission amp start-up 10212019 11292019
Budget Period 3 1222019 11302020
10 Project management 1222019 11302020
61 ESP system tests 1222019 2242020
62 Spray system tests 2172020 4302020
63 Test analysis 542020 8282020
70 Benchmarking analysis 8312020 11272020
80 Removal of equipment 8312020 11272020
Project Scope Timeline amp Milestones
7
BP1 Design amp Engineering
A
B
C
D
E
F
G
HIJ
BP2 Fabrication amp Installation
BP3 Testing amp Analysis
Task ID Milestone Completion Date1 A Updated PMP 629181 B Kick-Off Meeting 727182 C Mechanisms review amp modeling complete 1130183 D Design amp engineering complete 1130183 E Test plan complete 1130184 F Fabrication amp procurement complete 830195 G Installation amp commissioning complete 1129196 H Parametric testing complete 51207 I Benchmarking analysis complete 1130208 J Removal of equipment complete 113020
8
Project Participants
Partner
Organization
Lead contact(s) Key Role(s)
DOE-NETL Andy Aurelio Project Manager
-Funding amp sponsorship
Linde LLC Devin BostickPrincipal InvestigatorKrish Krishnamurthy Technology Director
-Prime contract-Overall program management-High velocity water spray-based aerosol pretreatment technology owner
University of Illinois Urbana-Champaign (UIUC)
Kevin OrsquoBrien Project Lead
-Aerosol mechanisms review-Host site liaison-Flue gas and liquid effluent composition measurement amp analysis
Washington University in St Louis (WUSTL)
Pratim BiswasProject Lead
-Aerosol mechanisms modeling lead-ESP-based aerosol pretreatment technology owner-Characterization of aerosols in flue gas
Affiliated Construction Services (ACS)
Greg LarsonProject Lead
-Procurement management for high velocity water spray-based system-Construction management for site modifications amp module installation
9
Project Budget DOE Funding and Cost Share
SourceBudget Period 1
Jun 2018 ndash Nov 2018
Budget Period 2
Dec 2018 ndash Nov 2019
Budget Period 3
Dec 2019 ndash Nov 2020Total
DOE Funding $457822 $1290725 $1078826 $2827834
Cost Share $176612 $260949 $269860 $707421
Total Project $634435 $1551674 $1348686 $3534795
Cost share commitments
Linde $234869
University of Illinois (UIUC) $231339
Washington University in St Louis (WUSTL) $191213
Affiliated Construction Services (ACS) $50000
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Linde EngineeringTechnology-focused Air Separation
Global 1
Air Separation
Global 1
Hydrogen Syn Gas
Global 2
Hydrogen Syn Gas
Global 2
Olefins
Global 2
Olefins
Global 2
Natural Gas
Global 3
Natural Gas
Global 3
HyCO Tonnage Plants
gt70 plants
HyCO Tonnage Plants
gt70 plants
HyCO Tonnage Plants
gt70 plants
ASU Tonnage Plants
gt300 plants
ASU Tonnage Plants
gt300 plants
ECOVAR Std Plants
gt1000 plants
ECOVAR Std Plants
gt1000 plants
Linde Gas - TonnageWorld-class operations
CO2 Plants
gt100 plants
Founded
Sales (2017)
Employees
Countries
US Linde Gas HQ
US Linde Engineering Facilities
Leveraging
Synergies
1879
$20 billion
64000
gt100
Bridgewater NJ
Tulsa OK
Holly Springs GA
Houston TX
Linde has extensive experience in CO2 capture amp handling
5
Experience in design amp erection of different wash processes for CO2
removalbull Linde-Rectisol reg
bull BASF Oase technreg
bull Benfield
Long experience in operation of CO2 plants transport amp distribution
bull OCAP pipeline (Netherlands)
bull Onsite business
bull Bulk supply
CO2 Capture and Injection
LNG plant for Statoil in SnoslashhvitNorway with CO2
capture from natural gas and CO2 re-injection off-shore
CO2 Wash Units
Removal of impurities like Hydrocarbons Heavy metals O2 amp H2O for food grade CO2
CO2 Food Grade Plants CO2 Transport and Distribution
6
Overall ObjectiveDemonstrate and evaluate two innovative flue gas aerosol pretreatment technologies identified to significantly reduce high aerosol particle concentrations (gt107 particlescm3) in the 70-200 nm particle size range
(1) A high velocity water spray-based system with unique design features(2) A novel electrostatic precipitator (ESP) device with an optimized design and operating conditions
Specific Objectivesmdash Complete an aerosol mechanism literature review and develop a mechanistic model
characterizing aerosol formation and interaction with amine solvent in the absorber of a PCC plantmdash Design build install commission and operate the two technologies for flue gas aerosol
pretreatment at a coal-fired power plant host site providing the flue gas as a slipstream at a flow rate of 500-1000 scfm
mdash Complete parametric testing and analysis of each technology to demonstrate achievement of target performance
mdash Complete a benchmarking study to identify the optimal aerosol pretreatment system for commercial deployment and integration with solvent-based PCC technology
Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Budget Period 1 612018 11302018
10 Project management 612018 11302018
21 Mechanism review 612018 6292018
22 Mechanism modeling 722018 11282018
31 Design basis dev 612018 6292018
32 Basic engineering 722018 1052018
33 Detailed engineering 1082018 11282018
34 Test planning 10292018 11282018
Budget Period 2 1232018 11292019
10 Project management 1232018 11292019
41 ESP system fabrication 1232018 8302019
42 Spray system fabrication 1232018 8302019
43 Procurement for install 1232018 8302019
51 Site installation 922019 10182019
52 Commission amp start-up 10212019 11292019
Budget Period 3 1222019 11302020
10 Project management 1222019 11302020
61 ESP system tests 1222019 2242020
62 Spray system tests 2172020 4302020
63 Test analysis 542020 8282020
70 Benchmarking analysis 8312020 11272020
80 Removal of equipment 8312020 11272020
Project Scope Timeline amp Milestones
7
BP1 Design amp Engineering
A
B
C
D
E
F
G
HIJ
BP2 Fabrication amp Installation
BP3 Testing amp Analysis
Task ID Milestone Completion Date1 A Updated PMP 629181 B Kick-Off Meeting 727182 C Mechanisms review amp modeling complete 1130183 D Design amp engineering complete 1130183 E Test plan complete 1130184 F Fabrication amp procurement complete 830195 G Installation amp commissioning complete 1129196 H Parametric testing complete 51207 I Benchmarking analysis complete 1130208 J Removal of equipment complete 113020
8
Project Participants
Partner
Organization
Lead contact(s) Key Role(s)
DOE-NETL Andy Aurelio Project Manager
-Funding amp sponsorship
Linde LLC Devin BostickPrincipal InvestigatorKrish Krishnamurthy Technology Director
-Prime contract-Overall program management-High velocity water spray-based aerosol pretreatment technology owner
University of Illinois Urbana-Champaign (UIUC)
Kevin OrsquoBrien Project Lead
-Aerosol mechanisms review-Host site liaison-Flue gas and liquid effluent composition measurement amp analysis
Washington University in St Louis (WUSTL)
Pratim BiswasProject Lead
-Aerosol mechanisms modeling lead-ESP-based aerosol pretreatment technology owner-Characterization of aerosols in flue gas
Affiliated Construction Services (ACS)
Greg LarsonProject Lead
-Procurement management for high velocity water spray-based system-Construction management for site modifications amp module installation
9
Project Budget DOE Funding and Cost Share
SourceBudget Period 1
Jun 2018 ndash Nov 2018
Budget Period 2
Dec 2018 ndash Nov 2019
Budget Period 3
Dec 2019 ndash Nov 2020Total
DOE Funding $457822 $1290725 $1078826 $2827834
Cost Share $176612 $260949 $269860 $707421
Total Project $634435 $1551674 $1348686 $3534795
Cost share commitments
Linde $234869
University of Illinois (UIUC) $231339
Washington University in St Louis (WUSTL) $191213
Affiliated Construction Services (ACS) $50000
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
4
Overview of The Linde Group
1
Linde EngineeringTechnology-focused Air Separation
Global 1
Air Separation
Global 1
Hydrogen Syn Gas
Global 2
Hydrogen Syn Gas
Global 2
Olefins
Global 2
Olefins
Global 2
Natural Gas
Global 3
Natural Gas
Global 3
HyCO Tonnage Plants
gt70 plants
HyCO Tonnage Plants
gt70 plants
HyCO Tonnage Plants
gt70 plants
ASU Tonnage Plants
gt300 plants
ASU Tonnage Plants
gt300 plants
ECOVAR Std Plants
gt1000 plants
ECOVAR Std Plants
gt1000 plants
Linde Gas - TonnageWorld-class operations
CO2 Plants
gt100 plants
Founded
Sales (2017)
Employees
Countries
US Linde Gas HQ
US Linde Engineering Facilities
Leveraging
Synergies
1879
$20 billion
64000
gt100
Bridgewater NJ
Tulsa OK
Holly Springs GA
Houston TX
Linde has extensive experience in CO2 capture amp handling
5
Experience in design amp erection of different wash processes for CO2
removalbull Linde-Rectisol reg
bull BASF Oase technreg
bull Benfield
Long experience in operation of CO2 plants transport amp distribution
bull OCAP pipeline (Netherlands)
bull Onsite business
bull Bulk supply
CO2 Capture and Injection
LNG plant for Statoil in SnoslashhvitNorway with CO2
capture from natural gas and CO2 re-injection off-shore
CO2 Wash Units
Removal of impurities like Hydrocarbons Heavy metals O2 amp H2O for food grade CO2
CO2 Food Grade Plants CO2 Transport and Distribution
6
Overall ObjectiveDemonstrate and evaluate two innovative flue gas aerosol pretreatment technologies identified to significantly reduce high aerosol particle concentrations (gt107 particlescm3) in the 70-200 nm particle size range
(1) A high velocity water spray-based system with unique design features(2) A novel electrostatic precipitator (ESP) device with an optimized design and operating conditions
Specific Objectivesmdash Complete an aerosol mechanism literature review and develop a mechanistic model
characterizing aerosol formation and interaction with amine solvent in the absorber of a PCC plantmdash Design build install commission and operate the two technologies for flue gas aerosol
pretreatment at a coal-fired power plant host site providing the flue gas as a slipstream at a flow rate of 500-1000 scfm
mdash Complete parametric testing and analysis of each technology to demonstrate achievement of target performance
mdash Complete a benchmarking study to identify the optimal aerosol pretreatment system for commercial deployment and integration with solvent-based PCC technology
Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Budget Period 1 612018 11302018
10 Project management 612018 11302018
21 Mechanism review 612018 6292018
22 Mechanism modeling 722018 11282018
31 Design basis dev 612018 6292018
32 Basic engineering 722018 1052018
33 Detailed engineering 1082018 11282018
34 Test planning 10292018 11282018
Budget Period 2 1232018 11292019
10 Project management 1232018 11292019
41 ESP system fabrication 1232018 8302019
42 Spray system fabrication 1232018 8302019
43 Procurement for install 1232018 8302019
51 Site installation 922019 10182019
52 Commission amp start-up 10212019 11292019
Budget Period 3 1222019 11302020
10 Project management 1222019 11302020
61 ESP system tests 1222019 2242020
62 Spray system tests 2172020 4302020
63 Test analysis 542020 8282020
70 Benchmarking analysis 8312020 11272020
80 Removal of equipment 8312020 11272020
Project Scope Timeline amp Milestones
7
BP1 Design amp Engineering
A
B
C
D
E
F
G
HIJ
BP2 Fabrication amp Installation
BP3 Testing amp Analysis
Task ID Milestone Completion Date1 A Updated PMP 629181 B Kick-Off Meeting 727182 C Mechanisms review amp modeling complete 1130183 D Design amp engineering complete 1130183 E Test plan complete 1130184 F Fabrication amp procurement complete 830195 G Installation amp commissioning complete 1129196 H Parametric testing complete 51207 I Benchmarking analysis complete 1130208 J Removal of equipment complete 113020
8
Project Participants
Partner
Organization
Lead contact(s) Key Role(s)
DOE-NETL Andy Aurelio Project Manager
-Funding amp sponsorship
Linde LLC Devin BostickPrincipal InvestigatorKrish Krishnamurthy Technology Director
-Prime contract-Overall program management-High velocity water spray-based aerosol pretreatment technology owner
University of Illinois Urbana-Champaign (UIUC)
Kevin OrsquoBrien Project Lead
-Aerosol mechanisms review-Host site liaison-Flue gas and liquid effluent composition measurement amp analysis
Washington University in St Louis (WUSTL)
Pratim BiswasProject Lead
-Aerosol mechanisms modeling lead-ESP-based aerosol pretreatment technology owner-Characterization of aerosols in flue gas
Affiliated Construction Services (ACS)
Greg LarsonProject Lead
-Procurement management for high velocity water spray-based system-Construction management for site modifications amp module installation
9
Project Budget DOE Funding and Cost Share
SourceBudget Period 1
Jun 2018 ndash Nov 2018
Budget Period 2
Dec 2018 ndash Nov 2019
Budget Period 3
Dec 2019 ndash Nov 2020Total
DOE Funding $457822 $1290725 $1078826 $2827834
Cost Share $176612 $260949 $269860 $707421
Total Project $634435 $1551674 $1348686 $3534795
Cost share commitments
Linde $234869
University of Illinois (UIUC) $231339
Washington University in St Louis (WUSTL) $191213
Affiliated Construction Services (ACS) $50000
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
Linde has extensive experience in CO2 capture amp handling
5
Experience in design amp erection of different wash processes for CO2
removalbull Linde-Rectisol reg
bull BASF Oase technreg
bull Benfield
Long experience in operation of CO2 plants transport amp distribution
bull OCAP pipeline (Netherlands)
bull Onsite business
bull Bulk supply
CO2 Capture and Injection
LNG plant for Statoil in SnoslashhvitNorway with CO2
capture from natural gas and CO2 re-injection off-shore
CO2 Wash Units
Removal of impurities like Hydrocarbons Heavy metals O2 amp H2O for food grade CO2
CO2 Food Grade Plants CO2 Transport and Distribution
6
Overall ObjectiveDemonstrate and evaluate two innovative flue gas aerosol pretreatment technologies identified to significantly reduce high aerosol particle concentrations (gt107 particlescm3) in the 70-200 nm particle size range
(1) A high velocity water spray-based system with unique design features(2) A novel electrostatic precipitator (ESP) device with an optimized design and operating conditions
Specific Objectivesmdash Complete an aerosol mechanism literature review and develop a mechanistic model
characterizing aerosol formation and interaction with amine solvent in the absorber of a PCC plantmdash Design build install commission and operate the two technologies for flue gas aerosol
pretreatment at a coal-fired power plant host site providing the flue gas as a slipstream at a flow rate of 500-1000 scfm
mdash Complete parametric testing and analysis of each technology to demonstrate achievement of target performance
mdash Complete a benchmarking study to identify the optimal aerosol pretreatment system for commercial deployment and integration with solvent-based PCC technology
Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Budget Period 1 612018 11302018
10 Project management 612018 11302018
21 Mechanism review 612018 6292018
22 Mechanism modeling 722018 11282018
31 Design basis dev 612018 6292018
32 Basic engineering 722018 1052018
33 Detailed engineering 1082018 11282018
34 Test planning 10292018 11282018
Budget Period 2 1232018 11292019
10 Project management 1232018 11292019
41 ESP system fabrication 1232018 8302019
42 Spray system fabrication 1232018 8302019
43 Procurement for install 1232018 8302019
51 Site installation 922019 10182019
52 Commission amp start-up 10212019 11292019
Budget Period 3 1222019 11302020
10 Project management 1222019 11302020
61 ESP system tests 1222019 2242020
62 Spray system tests 2172020 4302020
63 Test analysis 542020 8282020
70 Benchmarking analysis 8312020 11272020
80 Removal of equipment 8312020 11272020
Project Scope Timeline amp Milestones
7
BP1 Design amp Engineering
A
B
C
D
E
F
G
HIJ
BP2 Fabrication amp Installation
BP3 Testing amp Analysis
Task ID Milestone Completion Date1 A Updated PMP 629181 B Kick-Off Meeting 727182 C Mechanisms review amp modeling complete 1130183 D Design amp engineering complete 1130183 E Test plan complete 1130184 F Fabrication amp procurement complete 830195 G Installation amp commissioning complete 1129196 H Parametric testing complete 51207 I Benchmarking analysis complete 1130208 J Removal of equipment complete 113020
8
Project Participants
Partner
Organization
Lead contact(s) Key Role(s)
DOE-NETL Andy Aurelio Project Manager
-Funding amp sponsorship
Linde LLC Devin BostickPrincipal InvestigatorKrish Krishnamurthy Technology Director
-Prime contract-Overall program management-High velocity water spray-based aerosol pretreatment technology owner
University of Illinois Urbana-Champaign (UIUC)
Kevin OrsquoBrien Project Lead
-Aerosol mechanisms review-Host site liaison-Flue gas and liquid effluent composition measurement amp analysis
Washington University in St Louis (WUSTL)
Pratim BiswasProject Lead
-Aerosol mechanisms modeling lead-ESP-based aerosol pretreatment technology owner-Characterization of aerosols in flue gas
Affiliated Construction Services (ACS)
Greg LarsonProject Lead
-Procurement management for high velocity water spray-based system-Construction management for site modifications amp module installation
9
Project Budget DOE Funding and Cost Share
SourceBudget Period 1
Jun 2018 ndash Nov 2018
Budget Period 2
Dec 2018 ndash Nov 2019
Budget Period 3
Dec 2019 ndash Nov 2020Total
DOE Funding $457822 $1290725 $1078826 $2827834
Cost Share $176612 $260949 $269860 $707421
Total Project $634435 $1551674 $1348686 $3534795
Cost share commitments
Linde $234869
University of Illinois (UIUC) $231339
Washington University in St Louis (WUSTL) $191213
Affiliated Construction Services (ACS) $50000
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
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1
800
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736663748743719
136
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1
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APS
791600921273033
141
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141
300000
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5120
APS
776599182579565
146
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43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
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299061666666667
188
130470221105528
195
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311
380613666666667
195
140578994974874
202
706025000000001
322
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202
158666502512563
209
794851923076924
334
64940
209
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217
860896153846155
346
883372
217
146305745393635
225
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359
130709333333333
225
175050465661642
233
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372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
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429
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279
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830633
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334
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573
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594
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1018
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615
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1055
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685
114283076923077
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685
766995862646567
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533704666666667
71
625145611390285
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558684615384616
1219
398905
737
531419574539364
764
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1263
272716
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791
320039230769231
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791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
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1459
1185743
882
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914
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1512
901657
914
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947
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1568
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588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
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626
1
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10021
583
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673
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626
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723
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673
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777
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835
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777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
6
Overall ObjectiveDemonstrate and evaluate two innovative flue gas aerosol pretreatment technologies identified to significantly reduce high aerosol particle concentrations (gt107 particlescm3) in the 70-200 nm particle size range
(1) A high velocity water spray-based system with unique design features(2) A novel electrostatic precipitator (ESP) device with an optimized design and operating conditions
Specific Objectivesmdash Complete an aerosol mechanism literature review and develop a mechanistic model
characterizing aerosol formation and interaction with amine solvent in the absorber of a PCC plantmdash Design build install commission and operate the two technologies for flue gas aerosol
pretreatment at a coal-fired power plant host site providing the flue gas as a slipstream at a flow rate of 500-1000 scfm
mdash Complete parametric testing and analysis of each technology to demonstrate achievement of target performance
mdash Complete a benchmarking study to identify the optimal aerosol pretreatment system for commercial deployment and integration with solvent-based PCC technology
Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Budget Period 1 612018 11302018
10 Project management 612018 11302018
21 Mechanism review 612018 6292018
22 Mechanism modeling 722018 11282018
31 Design basis dev 612018 6292018
32 Basic engineering 722018 1052018
33 Detailed engineering 1082018 11282018
34 Test planning 10292018 11282018
Budget Period 2 1232018 11292019
10 Project management 1232018 11292019
41 ESP system fabrication 1232018 8302019
42 Spray system fabrication 1232018 8302019
43 Procurement for install 1232018 8302019
51 Site installation 922019 10182019
52 Commission amp start-up 10212019 11292019
Budget Period 3 1222019 11302020
10 Project management 1222019 11302020
61 ESP system tests 1222019 2242020
62 Spray system tests 2172020 4302020
63 Test analysis 542020 8282020
70 Benchmarking analysis 8312020 11272020
80 Removal of equipment 8312020 11272020
Project Scope Timeline amp Milestones
7
BP1 Design amp Engineering
A
B
C
D
E
F
G
HIJ
BP2 Fabrication amp Installation
BP3 Testing amp Analysis
Task ID Milestone Completion Date1 A Updated PMP 629181 B Kick-Off Meeting 727182 C Mechanisms review amp modeling complete 1130183 D Design amp engineering complete 1130183 E Test plan complete 1130184 F Fabrication amp procurement complete 830195 G Installation amp commissioning complete 1129196 H Parametric testing complete 51207 I Benchmarking analysis complete 1130208 J Removal of equipment complete 113020
8
Project Participants
Partner
Organization
Lead contact(s) Key Role(s)
DOE-NETL Andy Aurelio Project Manager
-Funding amp sponsorship
Linde LLC Devin BostickPrincipal InvestigatorKrish Krishnamurthy Technology Director
-Prime contract-Overall program management-High velocity water spray-based aerosol pretreatment technology owner
University of Illinois Urbana-Champaign (UIUC)
Kevin OrsquoBrien Project Lead
-Aerosol mechanisms review-Host site liaison-Flue gas and liquid effluent composition measurement amp analysis
Washington University in St Louis (WUSTL)
Pratim BiswasProject Lead
-Aerosol mechanisms modeling lead-ESP-based aerosol pretreatment technology owner-Characterization of aerosols in flue gas
Affiliated Construction Services (ACS)
Greg LarsonProject Lead
-Procurement management for high velocity water spray-based system-Construction management for site modifications amp module installation
9
Project Budget DOE Funding and Cost Share
SourceBudget Period 1
Jun 2018 ndash Nov 2018
Budget Period 2
Dec 2018 ndash Nov 2019
Budget Period 3
Dec 2019 ndash Nov 2020Total
DOE Funding $457822 $1290725 $1078826 $2827834
Cost Share $176612 $260949 $269860 $707421
Total Project $634435 $1551674 $1348686 $3534795
Cost share commitments
Linde $234869
University of Illinois (UIUC) $231339
Washington University in St Louis (WUSTL) $191213
Affiliated Construction Services (ACS) $50000
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Budget Period 1 612018 11302018
10 Project management 612018 11302018
21 Mechanism review 612018 6292018
22 Mechanism modeling 722018 11282018
31 Design basis dev 612018 6292018
32 Basic engineering 722018 1052018
33 Detailed engineering 1082018 11282018
34 Test planning 10292018 11282018
Budget Period 2 1232018 11292019
10 Project management 1232018 11292019
41 ESP system fabrication 1232018 8302019
42 Spray system fabrication 1232018 8302019
43 Procurement for install 1232018 8302019
51 Site installation 922019 10182019
52 Commission amp start-up 10212019 11292019
Budget Period 3 1222019 11302020
10 Project management 1222019 11302020
61 ESP system tests 1222019 2242020
62 Spray system tests 2172020 4302020
63 Test analysis 542020 8282020
70 Benchmarking analysis 8312020 11272020
80 Removal of equipment 8312020 11272020
Project Scope Timeline amp Milestones
7
BP1 Design amp Engineering
A
B
C
D
E
F
G
HIJ
BP2 Fabrication amp Installation
BP3 Testing amp Analysis
Task ID Milestone Completion Date1 A Updated PMP 629181 B Kick-Off Meeting 727182 C Mechanisms review amp modeling complete 1130183 D Design amp engineering complete 1130183 E Test plan complete 1130184 F Fabrication amp procurement complete 830195 G Installation amp commissioning complete 1129196 H Parametric testing complete 51207 I Benchmarking analysis complete 1130208 J Removal of equipment complete 113020
8
Project Participants
Partner
Organization
Lead contact(s) Key Role(s)
DOE-NETL Andy Aurelio Project Manager
-Funding amp sponsorship
Linde LLC Devin BostickPrincipal InvestigatorKrish Krishnamurthy Technology Director
-Prime contract-Overall program management-High velocity water spray-based aerosol pretreatment technology owner
University of Illinois Urbana-Champaign (UIUC)
Kevin OrsquoBrien Project Lead
-Aerosol mechanisms review-Host site liaison-Flue gas and liquid effluent composition measurement amp analysis
Washington University in St Louis (WUSTL)
Pratim BiswasProject Lead
-Aerosol mechanisms modeling lead-ESP-based aerosol pretreatment technology owner-Characterization of aerosols in flue gas
Affiliated Construction Services (ACS)
Greg LarsonProject Lead
-Procurement management for high velocity water spray-based system-Construction management for site modifications amp module installation
9
Project Budget DOE Funding and Cost Share
SourceBudget Period 1
Jun 2018 ndash Nov 2018
Budget Period 2
Dec 2018 ndash Nov 2019
Budget Period 3
Dec 2019 ndash Nov 2020Total
DOE Funding $457822 $1290725 $1078826 $2827834
Cost Share $176612 $260949 $269860 $707421
Total Project $634435 $1551674 $1348686 $3534795
Cost share commitments
Linde $234869
University of Illinois (UIUC) $231339
Washington University in St Louis (WUSTL) $191213
Affiliated Construction Services (ACS) $50000
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
8
Project Participants
Partner
Organization
Lead contact(s) Key Role(s)
DOE-NETL Andy Aurelio Project Manager
-Funding amp sponsorship
Linde LLC Devin BostickPrincipal InvestigatorKrish Krishnamurthy Technology Director
-Prime contract-Overall program management-High velocity water spray-based aerosol pretreatment technology owner
University of Illinois Urbana-Champaign (UIUC)
Kevin OrsquoBrien Project Lead
-Aerosol mechanisms review-Host site liaison-Flue gas and liquid effluent composition measurement amp analysis
Washington University in St Louis (WUSTL)
Pratim BiswasProject Lead
-Aerosol mechanisms modeling lead-ESP-based aerosol pretreatment technology owner-Characterization of aerosols in flue gas
Affiliated Construction Services (ACS)
Greg LarsonProject Lead
-Procurement management for high velocity water spray-based system-Construction management for site modifications amp module installation
9
Project Budget DOE Funding and Cost Share
SourceBudget Period 1
Jun 2018 ndash Nov 2018
Budget Period 2
Dec 2018 ndash Nov 2019
Budget Period 3
Dec 2019 ndash Nov 2020Total
DOE Funding $457822 $1290725 $1078826 $2827834
Cost Share $176612 $260949 $269860 $707421
Total Project $634435 $1551674 $1348686 $3534795
Cost share commitments
Linde $234869
University of Illinois (UIUC) $231339
Washington University in St Louis (WUSTL) $191213
Affiliated Construction Services (ACS) $50000
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
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163
80000
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168
442790384615385
269
137845333333333
168
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175
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183715
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188
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195
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195
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202
706025000000001
322
419054666666667
202
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209
794851923076924
334
64940
209
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217
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346
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217
146305745393635
225
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359
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221599480737019
259
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279
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279502308207705
334
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552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
9
Project Budget DOE Funding and Cost Share
SourceBudget Period 1
Jun 2018 ndash Nov 2018
Budget Period 2
Dec 2018 ndash Nov 2019
Budget Period 3
Dec 2019 ndash Nov 2020Total
DOE Funding $457822 $1290725 $1078826 $2827834
Cost Share $176612 $260949 $269860 $707421
Total Project $634435 $1551674 $1348686 $3534795
Cost share commitments
Linde $234869
University of Illinois (UIUC) $231339
Washington University in St Louis (WUSTL) $191213
Affiliated Construction Services (ACS) $50000
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
Technology Development
Rationale Background amp Previous Research
10
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
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359
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372
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372
335709822445561
385
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40
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414
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685
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414
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429
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71
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429
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445
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737
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445
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461
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764
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478
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791
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552
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914
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573
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573
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982
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594
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615
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1018
216415
615
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638
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1055
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638
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661
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1094
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661
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685
114283076923077
1134
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685
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71
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1176
533704666666667
71
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737
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1219
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737
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764
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764
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791
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131
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791
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82
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1358
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82
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1407
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851
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882
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1459
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882
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914
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1512
901657
914
860247541038527
947
1114950
1568
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947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
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1877
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1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
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1263
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2091
75311933333333
1263
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131
427556153846154
2167
71270066666667
131
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1358
528136538461539
2247
670295
1358
816854716917924
1407
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2329
612828
1407
682292696817421
1459
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2414
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1459
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1512
523173076923077
2503
64353
1512
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1568
532400
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575052
1568
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1625
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269
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1685
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1747
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289
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301689807692308
3106
390656
1877
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1946
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322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
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3587
451665266
1114
73515500837521
3718
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1197
491714613065327
3854
750723816
1286
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3995
3692090772
1382
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542
08614861802
1486
23149945
583
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1596
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542
2547951466667
626
1
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10021
583
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673
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1843
11057
626
2478060433333
723
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1981
12158
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777
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2129
12433
723
1953912566667
835
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2288
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777
1421029306667
898
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2458
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835
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965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
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1114
1
3051
3452
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1197
01230695642
3278
23495
1114
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1286
1
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1597
1197
34943302333
1382
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3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
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2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
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2458
1
6732
194
2288
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2642
1
7234
1705
2458
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2839
1
7774
1395
2642
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3051
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8354
124
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08735821033
3278
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8977
97
3051
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3523
1
9647
92
3278
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3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
11
Amine losses
Flue gas cooler
Flue gas blower
Flue gas inlet
Condensate
Major factor aerosol particles in flue gas from coal-fired power plants
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
1 Wang Xinlei amp Williams Brent amp Tang Y amp Huang Yuhsuan amp Kong L amp Yang Xin amp Biswas Pratim (2013) Characterization of organic aerosol produced during pulverized coal combustion in a drop tube furnace Atmospheric Chemistry and Physics 13 105194acp-13-10919-2013
12
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
13
Phase IAerosol growth and nucleation from water in absorber
Phase IIAerosol growth from amine in absorber
Phase IIIBuildup of captured CO2and amine bound to CO2in aerosols
Phase IVSalt accumulation inside particles causing further amine and CO2 diffusion into aerosols
02 microm particle
1 G Lombardo B Fostas M Shah A Morken O Hvidsten J Mertens E Hamborg Results from Aerosol Measurement in Amine Plant Treating Gas Turbine and Residue Fluidized Catalytic Cracker Flue Gases at the CO2 Technology Centre Mongstad GHGT-13 Energy Procedia 2017 114 Pages 1210-1230
Water condensation
Nucleation from water supersaturation
1 microm particle
Amine absorption until complete saturation
2 microm particle
CO2 and CO2+amine absorption
2-5 microm particleSalt accumulationCO2 and amine diffusion
Amine contained in aerosol particles are then emitted from PCC absorber in treated gas stream
The Kelvin equation gives the minimum particle diameter d of a liquid1 supersaturation leads to nucleation of smaller particles
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
14
Benefits of aerosol particle reduction
Benefits
Manageable solvent supply and transport logistics
Optimum power plant efficiency
when integrated with PCC
Reduction of particulate that can unfavorably react with amine
solvent
Improved PCC plant specific
energy performance
Environmental sustainability and
performance
Improved PCC plant business
caselower cost
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
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445
830633
279
238293788944724
289
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461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
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311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
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334
273149989949749
346
969944230769232
573
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346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
For power plants integrated with solvent-based PCC without an existing baghouse optimized flue gas aerosol pretreatment is the only viable option to reduce aerosol concentrations from gt109 particlescm3 to manageable levels near 104-106
particlescm3 for particles with diameters in the range of 70-200 nm
Pretreatment has traditionally been performed using simple ESPs and Brownian filters
Few systematic studies have been conducted to evaluate performance of different technologies over a full range of conditions
15
BH = baghouse
1 Based on single point experience some options eg dry bed conf may handle higher particle concentrations than others
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
Chart1
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
10000000
1000000
10000000
1000000000
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
126325376884422
188
591696153846154
30
299061666666667
188
130470221105528
195
660759615384616
311
380613666666667
195
140578994974874
202
706025000000001
322
419054666666667
202
158666502512563
209
794851923076924
334
64940
209
15709983919598
217
860896153846155
346
883372
217
146305745393635
225
847675000000001
359
130709333333333
225
175050465661642
233
943019230769232
372
182267
233
20586516917923
241
949319230769232
385
263912666666667
241
21836616080402
25
96023076923077
40
355521333333333
25
221599480737019
259
956119230769232
414
484109
259
231432663316583
269
1025750000
429
647791
269
228343541038526
279
964151923076924
445
830633
279
238293788944724
289
982432692307693
461
1054740
289
24027170519263
30
103288461538462
478
125545333333333
30
254431427135679
311
981471153846155
514
1435950
311
281640274706868
322
100416538461539
533
161942333333333
322
279502308207705
334
995501923076924
552
169811666666667
334
273149989949749
346
969944230769232
573
182475666666667
346
301086837520938
359
89473076923077
594
187437333333333
359
337571587939699
372
791292307692308
615
1885320
372
335709822445561
385
719676923076924
638
184891666666667
385
303290958123953
40
67950576923077
661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
267825041876047
461
294517500
764
1276340
461
268898750418761
478
235586538461539
791
111617666666667
478
246584087102178
496
219594615384616
82
956378666666667
496
22753597319933
514
183537307692308
851
786719333333333
514
20805557118928
533
132950384615385
882
654658
533
193145899497488
552
991526923076924
914
524162333333333
552
180397058626466
573
723884615384616
947
398477
573
159287497487437
594
49395000
982
294095333333333
594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
0009
lt03
lt03
lt03
Literature data
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Abbott Power Plant (42 reheat burner w dryer)
Abbott Power Plant (0 reheat burner wo dryer)
Wilsonville (after baghouse) (WashU)
Wilsonville (before baghouse) (SR)
UT Austin (NCCC) (before baghouse)
TCM (no BH no BF)
Wilsonville (after baghouse) (SR)
Wilsonville Parametric Tests (Linde)
Wilsonville Long-term Tests (Linde)
Anal Ins
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
Particle number (cm3)
Particle diameter (nm)
kg amineMT CO2
04080107622
00095091096
SMPS
682819795644892
982
427900576923077
157
14468166666667
982
1000000
10
4000000
2400
100000
35
650000
10
SMPS
735415966499163
102
532616923076924
163
160013
102
200000
20
3000000
2800
1150000
60
600000
20
SMPS
667026341708543
106
642390384615385
168
14813666666667
106
200000
40
2000000
2800
10000000
100
530000
40
SMPS
566092556113903
109
764663461538462
175
91535
109
1000000
70
1000000
3000
10000000
160
400000
70
SMPS
60451071356784
113
993782692307693
181
21280833333333
113
6300000
110
900000
3200
1400000
280
350000
120
SMPS
640447634840872
118
103840961538462
188
277361
118
8000000
200
800000
3200
120000
480
50000
200
SMPS
63931935678392
122
119893653846154
195
30501933333333
122
5000000
400
600000
3800
1400
640
20000
400
SMPS
67781860636516
126
155467692307692
202
35493966666667
126
800000
700
500000
3800
1000
960
10000
600
SMPS
678467648241207
131
173807500
209
25912033333333
131
1
800
400000
3800
1000
1920
5000
800
SMPS
736663748743719
136
198103846153846
217
20493533333333
136
1
1000
318900
3800
900
2560
100
1000
APS
791600921273033
141
245189807692308
225
34751733333333
141
300000
3800
750
5120
APS
776599182579565
146
27240826923077
233
43427866666667
146
200000
3800
APS
748095604690118
151
301905384615385
241
592247
151
100000
4000
APS
852265149078728
157
348734615384616
25
614018
157
90000
4100
APS
99985068676717
163
375607115384616
259
87004466666667
163
80000
4200
11043162479062
168
442790384615385
269
137845333333333
168
70000
4200
119948670016751
175
523365384615385
279
183715
175
112247051926298
181
445000384615385
289
241348
181
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188
591696153846154
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188
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195
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202
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322
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209
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372
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385
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25
221599480737019
259
956119230769232
414
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259
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269
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429
647791
269
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279
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445
830633
279
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461
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289
24027170519263
30
103288461538462
478
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311
981471153846155
514
1435950
311
281640274706868
322
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533
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322
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334
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552
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334
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346
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301086837520938
359
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594
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372
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372
335709822445561
385
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638
184891666666667
385
303290958123953
40
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661
177122333333333
40
296100891122278
414
554032692307693
685
167757333333333
414
305137175879397
429
441263461538462
71
1563790
429
298671450586265
445
39593576923077
737
143831333333333
445
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461
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764
1276340
461
268898750418761
478
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791
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496
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496
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514
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851
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882
654658
533
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552
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914
524162333333333
552
180397058626466
573
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947
398477
573
159287497487437
594
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982
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594
140093966499163
615
329623653846154
1018
216415
615
125712003350084
638
232231346153846
1055
155941333333333
638
11582181239531
661
170568076923077
1094
109822
661
933554824120604
685
114283076923077
1134
811729333333333
685
766995862646567
71
851232692307693
1176
533704666666667
71
625145611390285
737
558684615384616
1219
398905
737
531419574539364
764
425857115384616
1263
272716
764
401304512562814
791
320039230769231
131
224988666666667
791
302290415410386
82
224643461538462
1358
175139333333333
82
234256559463987
851
204812115384616
1407
137377666666667
851
174277956448911
882
133968461538462
1459
1185743
882
119620948073702
914
120355384615385
1512
901657
914
860247541038527
947
1114950
1568
95869666666667
947
588795608040202
982
892715384615385
1625
866524
982
453500100502513
1018
75693076923077
1685
79995933333333
1018
306104184254607
1055
734100000000001
1747
855652
1055
214392951423786
1094
732648076923078
1811
82140833333333
1094
171584234505863
1134
530092307692308
1877
81683533333333
1134
129452606365159
1176
609534615384616
1946
71270166666667
1176
109800234170854
1219
491257692307693
2017
67286033333333
1219
875061487437187
1263
391936346153846
2091
75311933333333
1263
755701192629817
131
427556153846154
2167
71270066666667
131
76907041876047
1358
528136538461539
2247
670295
1358
816854716917924
1407
538875
2329
612828
1407
682292696817421
1459
484882692307693
2414
60685066666667
1459
484327912897823
1512
523173076923077
2503
64353
1512
601245688442212
1568
532400
2595
575052
1568
608947306532664
1625
391983653846154
269
53995533333333
1625
57423530318258
1685
39818576923077
2788
56581733333333
1685
665198110552765
1747
390621538461539
289
50526966666667
1747
641284469011726
1811
282454038461539
2996
52087233333333
1811
551386834170855
1877
301689807692308
3106
390656
1877
515487715242882
1946
392116538461539
322
40069366666667
1946
557056576214406
2017
262214807692308
3338
42029366666667
2017
585014763819096
2091
300040192307693
346
563217748743719
2167
327144807692308
3587
516019996649917
2247
291944038461539
3718
635039155778895
2329
410772307692308
3854
678386860971525
2414
438539038461539
3995
540607373534339
2503
810536808
542
534717524288108
2595
882899298
583
624962696817421
269
884130018
626
507626351758795
2788
848442984
673
482487487437186
289
79158372
723
462233661641542
2996
628394094
777
614290241206031
3106
484154992
835
549685423785595
322
3250266138
898
485615936348409
3338
1930962502
965
446652388609716
346
97717245
1037
733651755443887
3587
451665266
1114
73515500837521
3718
1710666186
1197
491714613065327
3854
750723816
1286
453128479061977
3995
3692090772
1382
22625785
542
08614861802
1486
23149945
583
11076250522
1596
89545
542
2547951466667
626
1
1715
10021
583
26411294
673
1
1843
11057
626
2478060433333
723
1
1981
12158
673
2428556433333
777
1
2129
12433
723
1953912566667
835
1
2288
113975
777
1421029306667
898
01230695642
2458
9234
835
797872833333
965
1
2642
70035
898
430967506667
1037
1
2839
49195
965
21839545
1114
1
3051
3452
1037
84446483333
1197
01230695642
3278
23495
1114
320313357
1286
1
3523
1597
1197
34943302333
1382
1
3786
1089
1286
17471639033
1486
1
4068
781
1382
116477634
1596
1
4371
5965
1486
08735821033
1715
1
4698
4325
1596
05823884733
1843
1
5048
3995
1715
05823884733
1981
1
5425
3185
1843
02911942367
2129
1
5829
2325
1981
1
2288
1
6264
2185
2129
02911942367
2458
1
6732
194
2288
02911942367
2642
1
7234
1705
2458
08735821033
2839
1
7774
1395
2642
02911942367
3051
1
8354
124
2839
08735821033
3278
1
8977
97
3051
05823884733
3523
1
9647
92
3278
08735818
3786
1
10370
71
3523
23295514667
4068
1
11140
56
3786
05823884733
4371
1
11970
51
4068
05823884733
4698
1
12860
35
4371
1
5048
1
13820
31
4698
1
5425
1
14860
21
5048
1
5829
1
15960
16
5425
1
6264
1
17150
1
5829
1
6732
1
18430
055
6264
1
7234
1
19810
05
6732
1
7774
055
7234
1
8354
02
7774
1
8977
005
8354
1
9647
0
8977
1
10370
01
9647
1
11140
005
10370
1
11970
005
11140
1
12860
01
11970
1
13820
0
12860
1
14860
0
13820
1
15960
0
14860
1
17150
0
15960
1
18430
0
17150
1
19810
0
18430
0
19810
Literature data
Abbott (no RH no dryer)
Abbott (RH w dryer)
SR (Wilsonville before BH)
SR (Wilsonville after BH)
Linde (Wilsonville after BH)
UT Austin (Wilsonville before BH)
TCM (no BH no BF)
Particle Diameter (nm)
Particle Number Concentration (cm3)
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Methods
10E7 particlescm3 reported literature maximum
Abbott aerosol data showing gt10E7 particlescm3 compared to other flue gases
Abbott (reheater off no dryer)
Abbott (42 reheater w dryer)
NCCC after baghouse (WUSL measurements)
NCCC before baghouse (Southern Research measurements)
NCCC after baghouse (Southern Research measurements)
NCCC before baghouse (University of Texas at Austin measurements)
Residual fluidized catalytic cracker (Technology Centre Mongstad measurements)
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Method
Amine emissions (kg aminetonne CO2
Aerosol particle concentration range where adequate (particlescm3)
Baghouse
0009
0 to 1E+7
0
10000000
Dry bed operation (no BH)
lt03
0 to 1E+6
0
1000000
Absorber operating conditions (no BH)
lt03
0 to 1E+7
0
10000000
Pre-treatment solutions (no BH)
lt03
0 to 1E+9
0
1000000000
Methods
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) at which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pre-treatment
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
TEA
Technology proposed in this work
Baghouse Dry bed operation (no BH) Absorber operating conditions (no BH) Pre-treatment solutions (no BH)
Amine Losses (kg aminetonne CO2)
Inlet flue gas aerosol particle concentration range (particlescm3) for which technology can adequately remove particles
Baghouse
Dry bed operation (no BH)
Absorber operating conditions (no BH)
Flue gas pretreatment
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Base case
Case 1
Case 2
Case 3
Case 4
Case 5
DOE Case B12B Reference w baghouse
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
wo baghouse (breakeven)
Cost Basis Year
2011$
2011$
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4416576
4530755
4497804
4432245
4516307
45154043379888
Thermal input (kWt) (HHV)
1694366
1694366
1736605
1723975
1698847
1732627
Coal flowrate (kghr)
224791
224791
230395
228719
225385
229867
11478458479996
Total steam turbine power (kWe)
642000
642000
643332
654224
644359
656869
Gross Power (MWe)
6420
6420
6433
6542
6444
6569
96690
9669
3
Auxiliary Power (MWe)
913
913
934
1038
941
1072
9969
Net Power (MWe)
551
551
550
550
550
550
PCC Reboiler Duty (MW)
3311
3311
4106
3372
3323
3386
Specific Duty (MJkg CO2)
248
248
300
248
248
248
4405686
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
450395408921933
982680892193308
445482004460967
Fuel Unit Cost ($ton)
6854
6854
6854
6854
6854
6854
440778425101536
440864946116186
Power Plant Efficiency () (HHV)
32500
32500
31668
31930
32387
31725
Boiler Efficiency () (HHV)
89100
89100
89100
89100
89100
89100
CO2 Produced (MThr)
480
480
492
489
482
491
CO2 Produced (lbhr)
1058945
1058945
1085344
1077450
1061745
1082857
4415000
CO2 Produced (MTyear)
4207729
4207729
4312625
4281259
4218856
4302745
443224546416968
CO2 Captured ()
90
90
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
085
085
Variable Cost
$60366961
$82839499
$61871865
$61421865
$60526594
$60429346
Fixed Cost
$63094548
$62118858
$62746820
$62624815
$62372778
$62753124
Fuel Cost
$126458921
$126458921
$12961144817
$12866877277
$12679332619
$12931450746
Total Overnight Cost
$2384351816
$2331909536
$2364444218
$2356810371
$2341063213
$2364453241
$2364444218
Total Plant Cost
$1939142000
$1890358000
$1921756120
$1915655869
$1903054023
$1922071279
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$38782850
$37807160
$38435122
$38313117
$38061080
$38441426
Maintenance Material Cost
$18097725
$18097725
$1854888787
$1841398019
$1814558223
$18145582
Consumables Cost
$36775427
$59247965
$3769221114
$3741807239
$3687267513
$36775427
Waste Disposal Cost
$5493809
$5493809
$563076559
$558981254
$550833671
$5508337
By-Products Cost
$0
$0
$0
$0
$0
$0
Preproduction Costs (x1000)
$59957
$60854
$59820
$59635
$59257
$59691
Inventory Capital (x1000)
$41125
452270951087832
418250410605904
$4155922
410280350765301
$4159189
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
$0
$0
Land (x1000)
$900
$877
$892
$889
$883
$892
Other Owners Costs (x1000)
$290871
$283554
$288263
$287348
$285458
$288311
Financing Costs (x1000)
$52357
$51040
$51887
$51723
$51382
$51896
Total Overnight Costs (TOC)
$2384351816
$2331909536
$2364444218
$235681037146
$2341063213
$236445324106
Coal and sorbent handling ($x1000)
$52286
$52286
$53154
$52896
$52378
$53073
Coal and sorbent prep amp feed ($x1000)
$24983
$24983
$25398
$25274
$25027
$25359
Feedwater amp misc BOP systems ($x1000)
$112150
$112150
$114013
$113457
$112348
$113838
PC boiler ($x1000)
$400793
$400793
$407450
$405465
$401502
$406825
Flue gas cleanup ($x1000)
$197475
$148691
$151161
$150424
$148954
$150929
CO2 removal ($x1000)
$533757
$533757
$542622
$543241
$544054
$545052
935327377984728
CO2 compression amp drying ($x1000)
$98381
$98381
$100015
$99528
$98555
$99862
Heat and power integration ($x1000)
$0
$0
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45027
$45775
$45552
$45107
$45705
Steam turbine generaor ($x1000)
$178176
$178176
$181135
$180253
$178491
$180858
Cooling water system ($x1000)
$62254
$62254
$63288
$62980
$62364
$63191
Ashspent sorbent handling system ($x1000)
$19028
$19028
$19344
$19250
$19062
$19314
Accessory electric plant ($x1000)
$93584
$93584
$95138
$94675
$93749
$94993
Instrumentation amp control ($x1000)
$31654
$31654
$32180
$32023
$31710
$32130
Improvements to site ($x1000)
$18063
$18063
$18363
$18274
$18095
$18335
Buildings amp structures ($x1000)
$71531
$71531
$72719
$72365
$71657
$72608
TPC without PCC ($x1000)
$1307004
$1258220
$1279119
$1272887
$1260445
$1277157
PCC cost ($x1000)
$632138
$632138
$642638
$642769
$642609
$644914
COE ($MWh wo TampS)
$13320
$13686
$13368
$13305
$13185
$13279
COE ($MWh w TampS)
$14280
$14646
$14353
$14282
$14149
$14262
Fuel Costs ($MWh)
$3090
$3084
$3165
$3139
$3095
$3139
Variable Costs ($MWh)
$1470
$2023
$1511
$1500
$1478
$1474
Fixed Costs ($MWh)
$1540
$1517
$1532
$1529
$1523
$1529
Capital Costs ($MWh)
$7220
$7062
$7160
$7137
$7089
$7136
Cost of CO2 Captured ($ton wo TampS)
$5262
$7069
$6497
$6472
$6414
$6440
Cost of CO2 Captured ($MT wo TampS)
$5800
$6413
$5894
$5872
$5818
$5842
Cost of CO2 Captured ($MT w TampS)
$6901
$7514
$6995
$6972
$6919
$6943
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$46312929
$47467476
$47122241
$46435398
$47358727
CO2 TSM Cost ($MWh)
$960
$960
$985
$977
$963
$984
Coal handling amp conveying (kWe)
480
480
492
488
481
491
Pulverizers
3370
3370
3454
3429
3379
3446
Sorbent handling amp reagent preparation (kWe)
1070
1070
1097
1089
1073
1094
Ash handling (kWe)
780
780
799
794
782
798
Primary air fans (kWe)
1670
1670
1712
1699
1674
1708
Forced draft fans (kWe)
2130
2130
2183
2167
2136
2178
Induced draft fans (kWe)
8350
8350
8558
8496
8372
8539
SCR (kWe)
60
60
61
61
60
61
Activated carbon injection (kWe)
27
27
28
27
27
28
Dry sorbent injection (kWe)
108
108
111
110
108
110
Baghouse (kWe)
110
110
113
112
110
112
Wet FGD (kWe)
3550
3550
3638
3612
3559
3630
PCC plant auxiliaries (kWe)
16000
16000
16399
27280
18682
30361
14000
2640
CO2 compression (kWe)
35690
35690
36580
36314
35784
36496
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
400
400
Condensate pumps (kWe)
640
640
656
651
642
654
Circulating water pumps (kWe)
7750
7750
7943
7885
7770
7925
Ground water pumps (kWe)
710
710
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
4010
4010
Transformer losses (kWe)
2380
2380
2439
2422
2386
2434
Total auxiliaries (kWe)
91285
91285
93383
103756
94148
107186
Net plant heat rate (BTUkWh)
10498
10498
10775
10686
10535
10755
Condenser cooling duty (GJhr)
1867
1867
1914
1900
1872
1909
Limestone sorbent flowrate (kghr)
22213
22213
22767
22601
22272
22715
Raw water withdrawal (m3min)
30
30
30
30
30
30
Raw water consumption (m3min)
23
23
24
24
23
24
NOx (MTyear)
1517
1517
1555
1544
1521
1551
Particulates (MTyear)
195
195
200
198
196
199
Hg (kgyear)
6
6
6
6
6
6
SO2 (MTyear)
0
0
0
0
0
0
COE Reduction (w TampS)
256
051
002
-092
-012
COE Reduction (wo TampS)
275
036
-011
-101
-031
Cost of CO2 Reduction (wo TampS)
1057
162
123
032
073
Cost of CO2 Reduction (w TampS)
888
136
104
027
061
PCC Plant Cost Reduction
000
-166
-168
-166
-202
Targets
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Concentration (cm3)
Particle Size (nm)
Before
After
Removal eff ()
Average removal eff ()
71
441263461538462
533704666666667
999879050791
997335936184
737
39593576923077
398905
999899250073
764
294517500
272716000
999907402446
791
235586538461539
224988666666667
999904498505
82
219594615384616
175139333333333
99992024425
851
183537307692308
137377666666667
999925150004
882
132950384615385
1185743
99991081312
914
991526923076924
90165700
999909063791
947
723884615384616
95869666666667
999867562227
982
49395000
866524
999824572528
1018
329623653846154
79995933333333
999757311308
1055
232231346153846
855652
999631551892
1094
170568076923077
82140833
999518427863
1134
114283076923077
81683533333333
999285252589
1176
851232692307693
71270166666667
999162741665
1219
558684615384616
67286033333333
998795634756
1263
425857115384616
75311933333333
998231521076
131
320039230769231
71270066666667
997773083428
1358
224643461538462
670295
997016182909
1407
204812115384616
612828
997007852788
1459
133968461538462
60685066666667
99547019754
1512
120355384615385
64353
994653085094
1568
1114950
575052
994842351675
1625
892715384615385
53995533333333
993951539957
1685
75693076923077
56581733333333
99252484697
1747
734100000000001
50526966666667
993117154793
1811
732648076923078
52087233333333
992890552098
1877
530092307692308
390656
992630415603
1946
609534615384616
40069366666667
993426236073
2017
491257692307693
42029366666667
991444537699
2091
391936346153846
2167
427556153846154
2247
528136538461539
2329
538875
2414
484882692307693
2503
523173076923077
2595
532400
269
391983653846154
2788
39818576923077
289
390621538461539
2996
282454038461539
3106
301689807692308
322
392116538461539
3338
262214807692308
346
300040192307693
3587
327144807692308
3718
291944038461539
3854
410772307692308
3995
438539038461539
542
810536808
89545
-104761672958
583
882899298
10021
-135010529819
626
884130018
11057
-25060791681
673
848442984
12158
-432977846394
723
79158372
12433
-570648774838
Test Matrix
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
8 weeks of testing for each system 1 day testing per week at each condition 2nd part of 5th day includes data analysis and recap May vary cooling temperature depending on test results Flue gas flow and recirculation flow may vary depending on initial test results
ACM 1 High-velocity water spray injection (1 or more different nozzle designs and 1 or more perforated tray designs will be tested depending on early results)
ACM 2 Novel ESP (voltage and current ranges chosen may vary depending on early test results)
Test Week
Test Day Each Week
Test Parameters
Test Week
Test Day Each Week
Test Parameters
Flue gas flow (scfm)
Recirculation flow (gpm)
LG ratio
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Cooling onoff
Water spray temperature (deg F)
Flue gas flow (scfm)
ESP Voltage (kV)
ESP Current (mA)
Flue gas impurities filter (SOx NOx etc) onoff (optional)
Week 1nozzle 1 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 2nozzle 2 perforated tray 1Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 1No ESP dryerEffect of ESP voltage at max flue gas flow w filterWeek 2No ESP dryerEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
100
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
100
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Week 3nozzle 1 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filterWeek 4nozzle 2 perforated tray 1Effect of LG ratio at min gas flow w and wo cooling and filter
1
500
100
214
off
off
Determined by process
Week 3No ESP dryerEffect of ESP voltage at 75 flue gas flow w filterWeek 4No ESP dryerEffect of ESP voltage at 75 flue gas flow w filter (different voltage and current range)
1
750
7
14
off
1
500
300
641
off
off
Determined by process
1
750
8
13
off
2
500
100
214
on
off
Determined by process
2
750
9
11
on
2
500
300
641
on
off
Determined by process
2
750
10
10
on
3
500
100
214
off
on
95
3
750
11
9
off
3
500
300
641
off
on
95
3
750
12
8
off
4
500
100
214
on
on
95
4
750
13
8
on
4
500
300
641
on
on
95
4
750
15
7
on
5 (repeat 1st)
500
100
214
off
off
Determined by process
5 (repeat 1st)
750
7
14
off
Week 5nozzle 1 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filterWeek 6nozzle 2 perforated tray 1Effect of LG ratio at min and 50 max circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 5No ESP dryerEffect of ESP voltage at 50 flue gas flow w filterWeek 6No ESP dryerEffect of ESP voltage at 50 flue gas flow w filter (different voltage and current range)
1
500
7
14
off
1
1000
200
214
off
off
Determined by process
1
500
8
13
off
2
1000
100
107
on
off
Determined by process
2
500
9
11
on
2
1000
200
214
on
off
Determined by process
2
500
10
10
on
3
1000
100
107
off
on
95
3
500
11
9
off
3
1000
200
214
off
on
95
3
500
12
8
off
4
1000
100
107
on
on
95
4
500
13
8
on
4
1000
200
214
on
on
95
4
500
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
500
7
14
off
Week 7nozzle 1 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filterWeek 8nozzle 2 perforated tray 2Effect of LG ratio at max and min circulation flow w and wo cooling and filter
1
1000
100
107
off
off
Determined by process
Week 7ESP dryer usedEffect of ESP voltage at max flue gas flow w filterWeek 8ESP dryer usedEffect of ESP voltage at max flue gas flow w filter (different voltage and current range)
1
1000
7
14
off
1
1000
300
321
off
off
Determined by process
1
1000
8
13
off
2
1000
100
107
on
off
Determined by process
2
1000
9
11
on
2
1000
300
321
on
off
Determined by process
2
1000
10
10
on
3
1000
100
107
off
on
95
3
1000
11
9
off
3
1000
300
321
off
on
95
3
1000
12
8
off
4
1000
100
107
on
on
95
4
1000
13
8
on
4
1000
300
321
on
on
95
4
1000
15
7
on
5 (repeat 1st)
1000
100
107
off
off
Determined by process
5 (repeat 1st)
1000
7
14
off
Sheet3
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
Case 1
Case 2
Case 3
Case 4
wo baghouse and high solvent makeup (4x)
Varying absorber conditions and same solvent makeup
wo baghouse using water spray pretreatment system
wo baghouse using ESP pretreatment system
Cost Basis Year
2011$
2011$
2011$
2011$
PC Boiler Steam Flow (lbhr)
4416576
4530755
4497804
4416576
Thermal input (kWt) (HHV)
1694366
1736605
1723975
1692236
Coal flowrate (kghr)
224791
230395
228719
224508
Total steam turbine power (kWe)
642000
643332
654224
642000
Gross Power (MWe)
6420
6433
6542
6420
Auxiliary Power (MWe)
913
934
1038
913
Net Power (MWe)
551
550
550
551
PCC Reboiler Duty (MW)
3311
4106
3372
3310
Specific Duty (MJkg CO2)
248
300
248
248
Fuel Type
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Illinois No 6 Coal
Fuel Unit Cost ($ton)
6854
6854
6854
6854
Power Plant Efficiency () (HHV)
32500
31668
31930
32387
Boiler Efficiency () (HHV)
89100
89100
89100
89100
CO2 Produced (MThr)
480
492
489
480
CO2 Produced (lbhr)
1058945
1085344
1077450
1057614
CO2 Produced (MTyear)
4207729
4312625
4281259
4202441
CO2 Captured ()
90
90
90
90
Capacity Factor (Fraction)
085
085
085
085
Variable Cost
$82839499
$61871865
$61421865
$60526594
Fixed Cost
$62118858
$62746820
$62624815
$62372778
Fuel Cost
$126458921
$12961144817
$12866877277
$12679332619
Total Overnight Cost
$2331909536
$2364444218
$2356810371
$2341063213
Total Plant Cost
$1890358000
$1921756120
$1915655869
$1903054023
Annual Operating Labor Cost
$7384208
$7384208
$7384208
$7384208
Maintenance Labor Cost
$12065150
$12065150
$12065150
$12065150
Administrative amp Labor Support
$4862340
$4862340
$4862340
$4862340
Property Taxes and Insurance
$37807160
$38435122
$38313117
$37822131
Maintenance Material Cost
$18097725
$1854888787
$1841398019
$1807497942
Consumables Cost
$59247965
$3769221114
$3741807239
$3672920691
Waste Disposal Cost
$5493809
$563076559
$558981254
$548690427
By-Products Cost
$0
$0
$0
$0
Preproduction Costs (x1000)
$60854
$59820
$59635
$58985
Inventory Capital (x1000)
452270951087832
418250410605904
$4155922
408451435817063
Initial Cost for Catalyst and Chemicals (x1000)
$0
$0
$0
$0
Land (x1000)
$877
$892
$889
$878
Other Owners Costs (x1000)
$283554
$288263
$287348
$283666
Financing Costs (x1000)
$51040
$51887
$51723
$51060
Total Overnight Costs (TOC)
$2331909536
$2364444218
$235681037146
$2326540582
Coal and sorbent handling ($x1000)
$52286
$53154
$52896
$52242
Coal and sorbent prep amp feed ($x1000)
$24983
$25398
$25274
$24962
Feedwater amp misc BOP systems ($x1000)
$112150
$114013
$113457
$112056
PC boiler ($x1000)
$400793
$407450
$405465
$400456
Flue gas cleanup ($x1000)
$148691
$151161
$150424
$148566
CO2 removal ($x1000)
$533757
$542622
$543241
$535646
CO2 compression amp drying ($x1000)
$98381
$100015
$99528
$98298
Heat and power integration ($x1000)
$0
$0
$0
$0
Combustion turbineaccessories ($x1000)
$0
$0
$0
$0
HRSG ducting amp stack ($x1000)
$45027
$45775
$45552
$44989
Steam turbine generaor ($x1000)
$178176
$181135
$180253
$178026
Cooling water system ($x1000)
$62254
$63288
$62980
$62202
Ashspent sorbent handling system ($x1000)
$19028
$19344
$19250
$19012
Accessory electric plant ($x1000)
$93584
$95138
$94675
$93505
Instrumentation amp control ($x1000)
$31654
$32180
$32023
$31627
Improvements to site ($x1000)
$18063
$18363
$18274
$18048
Buildings amp structures ($x1000)
$71531
$72719
$72365
$71471
TPC without PCC ($x1000)
$1258220
$1279119
$1272887
$1257162
PCC cost ($x1000)
$632138
$642638
$642769
$633945
COE ($MWh wo TampS)
$13686
$13330
$13279
$11848
COE ($MWh w TampS)
$14646
$14316
$14256
$12807
Fuel Costs ($MWh)
$3084
$3165
$3139
$3048
Variable Costs ($MWh)
$2023
$1474
$1474
$1461
Fixed Costs ($MWh)
$1517
$1532
$1529
$1372
Capital Costs ($MWh)
$7062
$7159
$7136
$5967
Cost of CO2 Captured ($ton wo TampS)
$7069
$6450
$6440
$4804
Cost of CO2 Captured ($MT wo TampS)
$6413
$5851
$5842
$4358
Cost of CO2 Captured ($MT w TampS)
$7514
$6952
$6943
$5458
CO2 TSM Cost ($MT)
$1101
$1101
$1101
$1101
CO2 TSM Cost ($)
$46312929
$47467476
$47122241
$46254722
CO2 TSM Cost ($MWh)
$960
$985
$977
$959
Coal handling amp conveying (kWe)
480
492
488
479
Pulverizers
3370
3454
3429
3366
Sorbent handling amp reagent preparation (kWe)
1070
1097
1089
1069
Ash handling (kWe)
780
799
794
779
Primary air fans (kWe)
1670
1712
1699
1668
Forced draft fans (kWe)
2130
2183
2167
2127
Induced draft fans (kWe)
8350
8558
8496
8340
SCR (kWe)
60
61
61
60
Activated carbon injection (kWe)
27
28
27
27
Dry sorbent injection (kWe)
108
111
110
108
Baghouse (kWe)
110
113
112
110
Wet FGD (kWe)
3550
3638
3612
3546
PCC plant auxiliaries (kWe)
16000
16399
27280
16090
CO2 compression (kWe)
35690
36580
36314
35645
Miscellaneous balance of plant (kWe)
2000
2000
2000
2000
Steam turbine auxiliaries (kWe)
400
400
400
400
Condensate pumps (kWe)
640
656
651
639
Circulating water pumps (kWe)
7750
7943
7885
7740
Ground water pumps (kWe)
710
710
710
710
Cooling tower fans (kWe)
4010
4010
4010
4010
Transformer losses (kWe)
2380
2439
2422
2377
Total auxiliaries (kWe)
91285
93383
103756
91289
Net plant heat rate (BTUkWh)
10498
10775
10686
10485
Condenser cooling duty (GJhr)
1867
1914
1900
1865
Limestone sorbent flowrate (kghr)
22213
22767
22601
22185
Raw water withdrawal (m3min)
30
30
30
30
Raw water consumption (m3min)
23
24
24
23
NOx (MTyear)
1517
1555
1544
1515
Particulates (MTyear)
195
200
198
195
Hg (kgyear)
6
6
6
6
SO2 (MTyear)
0
0
0
0
COE Reduction (w TampS)
256
025
-017
-1031
COE Reduction (wo TampS)
275
008
-031
-1105
Cost of CO2 Reduction (wo TampS)
1057
088
073
-2487
Cost of CO2 Reduction (w TampS)
888
074
061
-2090
PCC Plant Cost Reduction
000
-166
-168
-029
Figure 11
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Item
Unit
Value
Results for 2 boilers at Abbott
Temperature
deg F
200
Pressure (gauge)
psig
075
Gas composition
Moisture
vol
192
CO2
vol (dry)
92
O2
vol (dry)
735
SO2
ppmv (wet)
177
NOx
ppmv (wet)
211
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Mechanism of actionWater circulates in loop at high velocity and contacts aerosol particles using a spray nozzle comprised of very small holes Contacting spray causes condensation and growth of particles that are then captured in loop and removed from vapor phase
PerformanceHigh velocity spray-based pretreatment reduced amine losses ~15-18 times during testing at 045 MWe PCC pilot in Niederaussum that began in 20091
16
1) P Moser G Vorberg T Stoffregen et A The wet electrostatic precipitator as a cause of mist formation ndash Results from the amine-based post-combustion capture pilot plant at Niederaussem International Journal of Greenhouse Gas Control 41 (2015) 229ndash238
Typical inlet flue gas conditions ~160 degF ~1 bara~12 mol CO2 (wet)
TestsPlanned tests will evaluate new nozzle amp perforated tray designs and the impact of several operating conditions (flows temperatures etc) on performance
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
17
Mechanism of actionESP applies high voltage between plate and wire that ionizes flue gas aerosols Ionized particles are diverted towards collecting plates for removal WUSTLrsquos system will incorporate a patented photo-ionizer technology that enhances particle capture efficiency
PerformanceBased on flue gas testing at the Linde-BASF 15 MWe pilot at NCCC in 2016 WUSTLrsquos ESP is expected to provide 98-99 removal efficiency for 1000 scfm gas flow and a specific collection area (SCA) of 95 m2(m3s) which can be increased to remove more particles in the size range of 10-500 nm1
TestsPlanned tests will evaluate voltage amp current effects and the impact of the photo-ionizer on ESP performance
1) Y Wang Z Li P Biswas Aerosol Measurements in Coal Combustor Exhaust Gas on 15 MWe Advanced Aqueous Amine-Based PCC Pilot Plant in Wilsonville AL Washington University in St Louis August 8 2016
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Economic amp technical advantages and potential challenges of each technology
18
Scenario DOE-NETL Case B12B PP w 90 CO2
capture
Case 1 PP w 90 CO2 capture high-velocity spray aerosol
pretreatment
Case 2 PP w90 CO2 capture novel ESP aerosol pretreatment
Baghouse Yes No No
Added CAPEX w aerosol pretreatment ($)
NA $3261720 $2338318
Added energy consumption w aerosol pretreatment (MW)
NA 11 132
Total Overnight Cost ($) $2384351816 $2356810371 $2328373523
PCC plant specific energy consumption (MJkg CO2)
248 248 248
Cost of electricity wo TampS (COE $MWh)
$13320 $13305 $13131
Key advantages NA Manageable footprint amp high performance low CAPEX can easily be integrated into direct
contact cooler of PCC plant
Very small footprint amp high performance
low CAPEX amp OPEX
Potential challenges NA Higher energy consumption could lead to decreased power plant
efficiency
High voltage equipment can pose a safety concern scale-up of novel components may present issues
PP 550 MWe supercritical power plant with high flue gas aerosol concentrations leading to very high amine losses for an integrated PCC plant with no aerosol mitigation usedBaghouses require significant footprint area and power plant retrofit costs including shutdown periods baghouses also produce a pressure drop so flue gas fan power must be increased the costs associated with these factors are not included
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Technical ApproachHost Site Setup Innovation Targets Success Criteria amp Project Risks and Mitigation Strategies
19
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Pilot host site Abbott Power Plant at UIUC in Champaign IL
20
Abbott plant schematic and tie-in points to pilot skid
Abbott chosen as optimal host site for testing since aerosol concentrations were measured to be among the highest in scientific literature
Abbott plant aerial view
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Preliminary Pilot Skid Layout at Abbott Host Site
21
Inlet to Abbott Power Plant Stack
WUSTL ESP pretreatment
8 flue gas slipstream inlet piping
Flue gas supply conditions for
slipstreamP 075 psig
T 200degFF 500-1000 scfm
Flue gas flowmeter temperature meter pressure meter gas
composition analysis
Blower filter
Process Isolation
Valve
Linde high-velocity water
spray pretreatment
Upstream aerosol
measurement
Downstream blower pulls flue
gas due to pressure drop
Blower speed is varied to control flue gas flowrate
Optional sorbent-based SOx and NOx removal
8 flue gas slipstream
outlet piping
Process Isolation
Valve
Process Isolation
Valve
Flue gas outlet
isolation valve
Process Isolation
Valve
Downstream aerosol
measurement
Control system and gas
composition analysis
WUSL ESP control
computer
Electric Conduit Supply
Cooling Water
Supply and Return
Service Water Supply
Process condensate discharge to storage
tank
Batch condensate sampling for
analysis at UIUC
Flue gas inlet
isolation valve
Linde
WUSTL
OSBL
ISBL
COLOR KEY
Linde + WUSTL
Condensate treatment
and disposal
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Pilot Testing Innovation Targets
22
Parameter Rationale Expected target
Particle removal efficiency for 500-1000 scfm flue gas slipstream ()
Flue gas aerosol particles in size range 70-200 nm lead to amine losses in the treated gas of amine-based PCC plants
gt98
Cost competitiveness (COE = cost of electricity)
Reduced capital and operating costs are required for commercial application of enabling technologies for PCC
COE lt $13320MWh and cost of CO2 captured lt $58tonne when compared to DOE-NETL reference case B12B
Energy efficiency Low electricity consumption reduces parasitic load for enabling technologies
Energy consumption lt 14 MWe (threshold above which energy consumption greatly impacts COE and cost of CO2captured)
Environmental sustainability when integrated with PCC technology for supercritical coal-fired power plants without a baghouse
Minimal environmental impact is required to meet process safety amp regulatory requirements for customers
Process condensate adequately removed amp treated as needed ESP solids removed and treated as needed
Particle removal efficiency = (Particle concentration before aerosol pretreatment (cm3) - Particle concentration after aerosol pretreatment (cm3) )(Particle concentration before aerosol pretreatment (cm3) ) 100
when integrated with PCC technology for a 550 MWe supercritical coal-fired power plant without a baghouse
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Decision Points and Success Criteria
23
Decision Point Date Success Criteria
Equipment procurement and fabrication of both aerosol pretreatment systems and components for installation
11302018 bull Successful completion of designs HAZOPsafety reviews and engineering documents that have been accepted by host site and reviewed by NETL
bull Update of costs based on vendor quotes and cost proposal within budget
bull Preliminary parametric test matrix in accordance with FOA guidelines and agreement with NETL
Installation of aerosol pretreatment systems on site
08302019 bull Host site is prepared and ready to receive aerosol pretreatment systems for installation
Handover to testing team 11292019 bull Successful completion of commissioning activities
bull Close-out of action items related to construction and installation from HAZOPS and safety reviews
Start of testing phase 12022019 bull Finalization of a test matrix for the parametric testing campaign with minimal changes from preliminary test plan and agreement with NETL
bull Coal flue gas availability from host site Project closeout 11302020 bull Successful demonstration of test objectives
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Technical Project Risks and Mitigation Strategies
24
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Technical Risks
Material Compatibility Low Medium
bull Flue gas composition and analysis will be used as part of the design basis Material compatibility with corrosive contaminants in the flue gas can be addressed by host site and Linde Engineering experience with flue gas handling
Waste Handling Low Medium
bull Batch analysis of flue gas condensate and other liquid waste streams for regulatory compliance before disposal
bull Treated flue gas will be sent back to the Abbott power plant stack for monitoring before exhaust
bull Solid waste (flue gas particles) is expected to be low
Flue gas aerosol variability Medium Mediumbull The aerosol control methods being tested are expected to
work over wide ranges of aerosol particle concentrations and size distributions
Plugging process equipment Low Medium
bull The aerosol particle concentration in the Abbott flue gas has been measured The design and operation of all equipment components for each aerosol control module will be sufficient to prevent plugging based on these measurements and Linde Engineering experience with similar systems
Flue gas condition variability affecting aerosol measurements Low Medium
bull Online flue gas analysis (temperature composition pressure humidity etc) during testing team experience handling various flue gas qualities
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Resource amp Project Management Risks and Mitigation Strategies
25
Description of Risk Probability Impact Risk Management Mitigation and Response Strategies
Resource Risks
Flue gas and utility non-availability from power plant Medium High
bull Availability of required utilities will be confirmed with the host site and will be included as part of the design basis Power plant schedule will be confirmed prior to installation decision
Unavailability of operators and key individuals with experience and know-how Low Medium
bull Commitment from all participants to make project successful
bull Management of all team membersrsquo availability and schedule through resource planning
bull Team members have overlapping skills and knowledge and substitutions are possible
Project cost overruns Low Highbull Clear scope definition and specifications sent to vendors
and subcontractors for pricing suitable scope management and limit change orders
Equipmentmodule fabrication delay Low Medium
bull Project schedule includes contingency for delays in procurement or fabrication
bull Team will select reputable suppliers and obtain firm commitments during purchase order process
Project Management RisksPoor communication among team members Low Medium bull Maintain communication on a regular basis to align team
on decision making
Conflicts among team members Low Mediumbull Team members have existing relationships from
participation in prior projects and have worked well together in the past
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Progress and Current Project Status
Budget Period 1
26
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
27
Project Progress Status of Key Project Milestones (Budget Period 1)
Budget Period 1 (June 1 2018 ndash November 30 2018)
Completed
mdash Submit updated project management plan (06292018) radic
mdash Conduct kick-off meeting with DOE-NETL (07272018) radic
In Progress (planned completion by 11302018)
mdash Review and modeling effort of aerosol-driven amine loss mechanisms
mdash Design engineering and cost analysis for pilot skid
mdash Preliminary test plan drafted
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
Budget Period 2 (December 2018 ndash November 2019)
mdash Complete fabrication and procurement of aerosol pretreatment systems and components for installation (08302019)
mdash Complete site installation and commissioning of aerosol pretreatment systems ensure both systems are ready for testing (11292019)
Budget Period 3 (December 2019 ndash November 2020)
mdash Complete parametric testing of both aerosol pretreatment systems (05012020)
mdash Complete technology benchmarking and analysis close-out report based on test results (11302020) complete comparison against innovation targets and other state-of-the-art aerosol mitigation technologies found in literature (11302020)
mdash Dismantling and removal of test equipment and platform (11302020)
28
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Future plans
Further scale-up of optimized aerosol pretreatment systems to be integrated with large-scale or demonstration PCC plants amp economic analysis to accurately understand cost implications when incorporated with PCC technology
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
Slide Number 29
29
Thank you for your attention
Project DE-FE00315922018 NETL CO2 Capture Technology MeetingDevin Bostick Linde LLCAugust 16 2018Pittsburgh PA
Slide Number 1
Acknowledgement and Disclaimer
ProjectOverview
Overview of The Linde Group
Linde has extensive experience in CO2 capture amp handling
Project Objectives
Project Scope Timeline amp Milestones
Project Participants
Project Budget DOE Funding and Cost Share
Technology Development
Rationale reducing aerosol-driven amine losses from solvent-based PCC technology enables its broader commercial deployment
Aerosol particle formation during coal combustion
Theory and mechanisms for aerosol-driven amine losses from PCC plant absorbers1
Benefits of aerosol particle reduction
Methods to reduce aerosol-driven solvent losses Flue gas aerosol pretreatment provides optimum solution1
High velocity water spray-based aerosol pretreatment technologyDeveloped by RWE amp tested in Niederaussem Germany at lignite-fired coal power plant
Advanced ESP-based aerosol pretreatment technologyDeveloped by Washington University in St Louis (WUSTL) and tested at NCCC in Wilsonville AL on 65 slpm flue gas sample
Economic amp technical advantages and potential challenges of each technology
Technical Approach
Pilot host site Abbott Power Plant at UIUC in Champaign IL
Preliminary Pilot Skid Layout at Abbott Host Site
Pilot Testing Innovation Targets
Decision Points and Success Criteria
Technical Project Risks and Mitigation Strategies
Resource amp Project Management Risks and Mitigation Strategies
Progress and Current Project Status
Project Progress Status of Key Project Milestones (Budget Period 1)
Key Project Milestones (Budget Periods 2 and 3) amp Future Plans
