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▪ Develop a design that will minimize the impact on the power plant by disrupting as little of the existing facilities as possible.
• Also shorten the amount of downtime before the plant can resume normal operations
▪ Develop a design that will minimize the cost of each tonne of captured CO2 while also maintaining the net 600 MW output of the East Bend Station (EBS).
• This will be done by optimizing the percentage of CO2 captured (~60%) and by adding a natural-gas-fired combustion turbine (CT) or possibly a combined cycle to offset the new auxiliary loads
▪ Following a data gathering task that will include several site visit to the EBS, a preliminary process design will be developed for one Post Combustion Capture (PCC) system which captures CO2 from the entire flue gas stream of the power plant.
▪ This preliminary design will then be subjected to a series of analyses to examine various options for minimizing the cost of CO2 capture on a $/tonne-captured basis.
▪ The analysis will also examine several options for providing the PCC system’s auxiliary power via a CT-based power plant.
▪ Once an optimized process design has been identified, that design will be detailed and documented in a complete Process Design Package (PDP).
▪ As part of this effort a HAZOP and constructability review of the design will be conducted.
▪ The PDP data will be used to carry out a techno-economic analysis that will include a +/-30% accuracy capital cost estimate as well as an estimate of the first year cost of electricity and $/tonne cost of CO2
capture for the retrofitted power plant.
▪ The marginal operating cost of the retrofitted plant with also be calculated and used in a unit dispatch model to predict how the retrofit will impact how often the coal plant is called on to operate.
▪ Unlike solvent PCC systems - No steam requirement, but power is required to drive the membrane systems fans, blowers, vacuum compressors pumps and CO2 compression
▪ 4 ways to supply power have been considered:
– Option 1: New natural gas-fired simple cycle,
– Option 2: New natural gas-fired combined cycle
– Option 3: New simple cycle with HRSG steam to the coal plant FWH
– Option 4: Auxiliary power supplied from the existing coal station
▪ Examine which option is best suited for MTR PCC integration implementation at EBS
▪ Assess Key Attributes of East Bend Station– Flue gas composition, temperature, pressure and flow
rate– Operability requirements– Desired capture rates and quantities– Cooling water availability and conditions– Cost of power assumptions
▪ Define project assumptions– Membrane cost and performance values– Set range of process pressure conditions– Consider process design – options for membrane
▪ FindingMTR Island Summer Design power consumptions for 60% CO2 recovery increased to 148 MW from the 130 MW estimated for the Integration Evaluation.
▪ Issue1 x 7F.04 GTSC can’t supply the total PCC Summer Design (92 °F ambient temperature) power demand when including the roughly 30 MW non-MTR BOP facilities demands.
▪ Minimize capital investment on idling capacity and maximize equipment capacity utilization at continuous design operations:
– Don’t add evaporative cooling or change to larger 7F.05 GT since these will be used less than 10% of the time in a year and less than 20% during summer months.
– Work with compressor/blower OEM to optimize machine efficiencies.
– Design for 60% recovery at lower ambient temperature (average annual ambient temperature).
– Reduce flue gas flow through MTR island during 92 oF summer ambient conditions to keep total power demand within 7F.04 GT output capacity
▪ Duct works to divert desulfurized Flue Gas (FG) from three existing EBS WFGD to the new MTR PCC, and to return CO2-depleted FG to existing EBS stack for release to atmosphere.
▪ Two 50% FG blowers to offset supply and return duct work pressure drops
▪ Two 50% FG feed conditioning systems
▪ One 198 MW GE7F.04 Gas Turbine Genset
▪ Twenty miles of 10” diameter natural gas supply pipeline
▪ A 10-cell cooling tower (CT) with circulation pumps, and underground cooling water (CW) distribution lines
▪ Electrical distribution system
▪ Makeup water and wastewater treating systems, plant and instrument air system, fire protection system, flare and relief system, and Buildings
▪ Two 50% FG blowers are included to offset pressure drops through the feed conditioning, supply and return duct works. Each blower is sized to handle 1,000,000 cubic feet per minute of FG at a head of 60” wc.
▪ Two 50% FG feed conditioning trains are included to reduce the flue gas feed sulfur and moisture before going to the MTR CO2 Capture Island. – Each train consists of a Direct Contact Column with circulation pumps and Plate &
Frame heat exchangers
– Each Contact Column has two packed bed sections:– Deep Flue Gas Desulfurization (DFGD) bottom bed to reduce the FG sulfur
content down below 5 ppm with caustic scrubbing
– Direct Contact Cooler (DCC) top bed to cool the FG to lowest temperature achievable with available cooling water (CW) to minimize MTR feed moisture content
Retrofit Operating Scenarios & CO2 Capture Performances
▪ Scenarios evaluated:– 100% annual average
– 75% summer bypass (25% flue gas bypass MTR)
– 50% minimum turndown at annual average ambient conditions
Plant EBS MTR PCC RetrofitScenario 100% annual
average75% summer w 25% bypass
50% minimum turndown
EBS Performance Rate Guaranteed Guaranteed Min. turndown EBS Gross Power Output, MWe 640 640 250Operating Ambient Conditions Annual average Summer design Annual averageFlue Gas Bypass MTR 0% 25% 0%CO2 Generated from EBS, stpd 16,090 16,090 6,838CO2 to MTR PCC Plant, stpdEBS Flue Gas CO2 Captured by MTR, stpdCO2 Capture Rate, % of EBS Flue Gas CO2 onlyGas Turbine Exhaust CO2, stpdNet CO2 Capture Rate (incl GT CO2 emissions)
turndownEBS Flue Gas CO2 Captured, stpd 9,688 8,395 3,973CO2 Capture Rate, % of EBS Flue Gas CO2 only 60% 52% 58%Net CO2 Capture Rate (incl GT CO2 emissions) 52% 45% 47%POWER BALANCE, MWe
GenerationGas Turbine Output 165.3 162.8 89.1
Auxiliary LoadsGas Turbine Auxiliary Loads 2.5 2.5 2.3Makeup and Waste Water Pump 0.2 0.2 0.1CW Pump and CT Fans 8.8 7.7 5.0Flue Gas Feed Blower 25.3 22.7 13.5DCC Circulating Water Pump 3.1 2.9 1.7MTR PCC Loads 125.5 126.9 66.5
Total Auxiliary Loads 165.3 162.8 89.1NET POWER OUTPUT 0.0 0.0 0.0COOLING DUTY, MMBtu/hr
▪ The MTR carbon capture unit is located to the south-east of the existing Unit 2 stack, with the power block located south-east of the MTR modules.
▪ Flue gas is routed east from the outlet of the 3 Absorbers via three 22 foot diameter round ducts to a common rectangular duct. This duct runs at a high elevation to clear existing structures and to allow clear access.
▪ The rectangular duct supplies the gas via vertical branch ducts to two, 2 stage at-grade axial flow fans that discharge into dedicated 22 foot square ducts to deliver the flue gas to the two Direct Contract Coolers (DCC’s).
▪ The supply ducts use carbon steel with a stainless cladding for corrosion protection.▪ The return gas from the MTR unit is routed in a common rectangular duct which is 36’ x
26’ in cross-section.▪ The return duct is split into 2 branches at the stack and will tie into the existing bypass
duct stack penetrations.▪ The return duct material of construction is coated carbon steel.▪ Overall pressure drop in the duct and DCC’s is approximately 2 psi.
Retrofit Operating Scenarios & CO2 Capture Performances
▪ Scenarios evaluated:– 100% annual average
– 75% summer bypass (25% flue gas bypass MTR)
– 50% minimum turndown at annual average ambient conditions
Plant EBS MTR PCC RetrofitScenario 100% annual
average75% summer w 25% bypass
50% minimum turndown
EBS Performance Rate Guaranteed Guaranteed Min. turndown EBS Gross Power Output, MWe 640 640 250Operating Ambient Conditions Annual average Summer design Annual averageFlue Gas Bypass MTR 0% 25% 0%CO2 Generated from EBS, stpd 16,090 16,090 6,838CO2 to MTR PCC Plant, stpdEBS Flue Gas CO2 Captured by MTR, stpdCO2 Capture Rate, % of EBS Flue Gas CO2 onlyGas Turbine Exhaust CO2, stpdNet CO2 Capture Rate (incl GT CO2 emissions)
turndownEBS Flue Gas CO2 Captured, stpd 9,688 8,395 3,973CO2 Capture Rate, % of EBS Flue Gas CO2 only 60% 52% 58%Net CO2 Capture Rate (incl GT CO2 emissions) 52% 45% 47%POWER BALANCE, MWe
GenerationGas Turbine Output 165.3 162.8 89.1
Auxiliary LoadsGas Turbine Auxiliary Loads 2.5 2.5 2.3Makeup and Waste Water Pump 0.2 0.2 0.1CW Pump and CT Fans 8.8 7.7 5.0Flue Gas Feed Blower 25.3 22.7 13.5DCC Circulating Water Pump 3.1 2.9 1.7MTR PCC Loads 125.5 126.9 66.5
Total Auxiliary Loads 165.3 162.8 89.1NET POWER OUTPUT 0.0 0.0 0.0COOLING DUTY, MMBtu/hr
DCC 529 228 250MTR PCC 685 762 378
TOTAL COOLING LOAD 1,215 990 628
MTR PCC plant operates at 75% flue gas load during summer conditions
Plant EBS MTR PCC RetrofitCost Basis Year End 2018Operating hours 8,000/yrScenario 100% annual
average 75% summer bypass 50% minimum
turndownEBS Flue Gas CO2 Captured, stpd 9,688 8,395 3,973EBS Flue Gas CO2 Emitted, stpd 6,402 7,695 2,865Gas Turbine Exhaust CO2, stpd (includes CO2 from air) 2,444 2,409 1,622CO2 Capture Rate, % of EBS Flue Gas CO2 only 60.2% 52.2% 58.1%Net CO2 Capture Rate (incl GT CO2 emissions) 52.3% 45.4% 47.0%
Discounted cash flow analysis suggests (additional) cost of electricity
between about $50 and $60 per megawatt-hour
• This is the additional revenue required from the sale of the original plant’s electric output to generate a return on investment in the capture process
• Based on operation at the “annual average” performance• 600 MWe net power to grid• No change in plant availability due to the presence of
▪ A final report will be written that shall include:
– A description of the existing plant and the retrofit changes required to add CO2 capture.
– Process descriptions with process flow diagrams, and heat and material balances for the PCC plant including CO2 compression.
– A plot plan to establish the space required for the PCC plant.
– Equipment lists with sizing of major items for the PCC plant.
– Breakdown of costs by system for the PCC plant.
– Power, cooling water, and consumables used by the PCC plant.
– Description on preliminary PCC startup, shutdown, and bypass operating procedures with flow diagrams, and equipment requirements for integration with the existing power plant.
– All environmental emissions from the retrofitted PCC plant, including all disposal
AcknowledgementThis material is based upon work supported by the Department of Energy under Award Number DE-FE0031589. DisclaimerThis report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.