AEP Mountaineer CCS II
Integration of a Commercial Scale CO2 Capture Facility into a Host Plant
Global CCS Institute / CSLF Meeting on Project Integration, 2011
Presented By: Matt Usher, P.E. CCS Engineering Manager, AEP November 3, 2011
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Mountaineer Plant Overview Project Overview Phase 1 Technical Objectives Technical Approach Operations Integration Chilled Ammonia Process Overview
Key Integration Areas Steam Supply and Condensate Return Flue Gas Exhaust Process Water / Wastewater Byproduct Bleed Stream Study
CO 2 Compression Study CAP Power Supply CCS Control Systems Conclusions
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5.2 million customers in 11 states
Industry leading size and scale of assets:
#2 Domestic generation with 38,000 MW #1 Transmission with 39,000 miles #1 Distribution with 216,000 miles Coal & transportation assets Over 7,500 railcars involved in operations Own/lease and operate over 2,850 barges & 75 towboats AEP Generation Capacity Portfolio Coal handling terminal with 20 million tons of capacity Coal/ Gas/ Nuclear Other – Lignite Oil (hydro, wind, Consume 76 million tons of coal per year etc.) 18,712 employees 66% 22% 6% 6%
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Operated by Appalachian Power Company, a subsidiary of AEP. Located on State Route 62 near New Haven, West Virginia A single 1300 MW net pulverized coal plant Emission Controls ESP – Original Equipment SCR – Installed 2001
FGD and SO3 Mitigation installed 2007 Primary fuel is bituminous coal
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 5of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Mountaineer Carbon Capture Product Validation Facility Summary
Location New Haven, WV
Capacity 100,000 tonnes CO2/yr
Size ≈ 54 MWt 79,798 Nm3/hr
CO2 Storage Deep geological formations
Upstream APC ESP, SCR, WFGD, SO3 Equipment Sorbent injection Start-Up 3rd Qtr 2009 Fuel Bituminous Coal American Electric Power Reagent Ammonium carbonate Mountaineer Power Plant Regeneration Steam – turbine CCS Product Validation Facility Energy extraction (HP Turbine New Haven, WV Exhaust Chiller R410A Refrigerant Byproduct Ammonium sulfate (dilute water solution)
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 6of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. MT CCS II Project Overview
Purpose: Advance the development of the Alstom Chilled Ammonia
Process (CAP) CO2 Capture technology and demonstrate CO2 storage and monitoring technology at commercial scale Project Participants AEP, USDOE, Alstom, Battelle, WorleyParsons, Potomac Hudson, Geologic Experts Advisory Team
Location: Mountaineer Power Plant and other AEP owned properties near New Haven, WV
Preliminary cost estimate: $668 million 50/50 DOE cost share up to $334M
Project Technical Objectives
90% CO2 removal from the stack gas
Store 1.5 million metric tons of CO2/year
Demonstrate commercial scale technology
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Conceptual Design Basis Complete Design Documents to support cost estimating
Mass & Energy Balances
Process Flow Diagrams (PFDs)
Process & Instrumentation Diagrams (P&IDs)
General Arrangements (GAs)
Plot Plan
Electrical One Line Diagrams
Electrical Load Lists
Equipment Lists
Valve & Instrument Lists
3D Model
Engineering in position to freeze design early in Phase II
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Chemical Plants Power Plants Uniform product from a Production based on
uniform feedstock demand
Stable production rate w/ Cyclical based on consistent production weather, time of day, etc.
schedules Frequent load adjustments Process variables Base load one day, load- minimized to reduce following the next. impacts. Variable feedstock (coal)
Chemical composition, heating value, moisture content, etc.
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 9of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. MT CCS II Phase I Technical Approach Operations (cont.) AEP and Alstom collaborated to practically address process variability in the commercial scale design PVF Lessons Learned Integrated design workshops
Effective communication to develop . Detailed flue gas specifications with expected ranges for significant characteristics . Expected quantities and quality of makeup water to properly identify equipment sizing, treatment needs, HXR capacities, etc. . Expected quantity and quality of available steam and how the steam supply is affected by load changes, ambient conditions, etc. . A suite of material and energy balances . Depicting main generating unit variability AND CAP modeled process variability with respect to changes in load, ambient conditions, etc.
Goal: Maximize efficiency and minimize complexity of operations.
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Integration areas considered:
Flue gas heat recovery to reduce the flue gas temperature
entering the CAP (omitted early from consideration).
Heat of compression recovery from CO2 compression.
Steam extraction from the Mountaineer steam turbine and condensate return from the CAP to Mountaineer’s feed water heating system for heat recovery.
Rich/Lean heat exchanger network design by Alstom to maximize the CAP efficiency (details are confidential).
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 11 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. MT CCS II Phase I Technical Approach Evaluating integration opportunities
Qualitative complexity (equipment, piping, controls, etc.)
Qualitative impacts (BOP, critical systems) Quantitative assessment of maximum energy recovery
potential (seasonal vs. year-round)
Quantitative assessment of associated capital and operating costs
Risk element to integration
First-of-a-kind technology Complexity of scale and demonstration
Innovation spawns integration
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. Weather Data (temps, rainfall, wind rose)
. Site Characteristics (location, elevation, seismic criteria, etc.)
. Available Water & Utilities Info
. AEP Design Criteria (by discipline)
. Applicable codes & standards
Periodic site walk-downs w/ Plant Operations
. Equipment locations
. Steam and other BOP tie-ins
Integrated engineering & design workshops (CAP and BOP)
. Wiesbaden, Germany
. Knoxville, TN
. Reading, PA
. Columbus, OH
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 13 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Chilled Ammonia Process Overview
Gas to CO2 Chilled Stack Water Reagent
CO2 CO2 Flue Gas Gas Cooled CO CO CO from FGD Cooling 2 2 2 and Flue Gas Absorber Regenerator Cleaning Clean
CO2 to Storage
Reagent Heat and Pressure
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 14 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Key Integration Areas
Steam Supply and Condensate Return
Steam source analysis included: Extraction from the cold reheat (CRH)
Extraction from the intermediate pressure (IP) turbine
Extraction from cross-over between IP turbine and the low pressure (LP) turbine.
Results indicated the advantage of choosing an extraction point with a pressure that is as close as possible to the required operating pressure. Due to the variance in available pressure at each extraction point during normal unit operation, a single extraction point could likely not provide the required steam conditions to the CAP.
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 15 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Key Integration Areas
Turbine Arrangement w/ CAP Integration
LP Turbine New Throttling Valve LP Turbine New Throttling Valve HP Turbine To Generator
LP Turbine New Throttling ValveLP Turbine New Throttling Valve IP Turbine
To Generator
Boiler To CAP To CAP
To Feedwater Heaters American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 16 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Key Integration Areas
Steam Supply to CAP Based on steam cycle evaluation and process
optimization, the Phase I design basis would be to extract steam at two different pressure levels: higher pressure steam for regeneration from the IP/LP crossover utilizing throttling valves (butterfly type)
Lower pressure to supply steam for process stripping. Condensate Return from CAP
returned to the Mountaineer feed water heating system to
reclaim the condensate as well as offset a portion of the overall energy demand. To minimize contamination concerns, a condensate storage “buffer” tank is included in the design, which is continuously monitored for contamination.
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 17 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Key Integration Areas CAP Flue Gas Exhaust Options considered:
CAP exhaust to existing stack
CAP exhaust to new stack close coupled to process island
CAP exhaust to existing MT hyperbolic cooling tower
Evaluation Results: Hyperbolic cooling tower option eliminated from consideration . Technical and environmental risk factors Existing stack option and new stack options were both technically acceptable. Team initially recommended a new dedicated stack. . Uncertainties associated with modeling and permitting a new stack in the timeframe of the project restricted AEP from considering this option for the Phase I conceptual design. . For treating higher percentages of flue gas, a dedicated stack would be required as the technical difficulties surrounding mixing of flue gas streams becomes a concern.
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 18 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Key Integration Areas Process Makeup / Wastewater
Process Makeup Water Demand Flow Rate (% of CAP Total Makeup) Evaporative condenser evaporation 51% Evaporative condenser blowdown 26% Pump seal cooling water (25 4% pumps, 4 gpm each, avg.) Washdown hose stations 4% Process water makeup (clarified 3% water) DCC makeup (RO product) 7% Filter backwash and RO concentrate 3% 2% Makeup water clarifier sludge blowdown Total makeup requirement 100%
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Process Makeup / Wastewater (cont.) Process Makeup Water
The entire makeup water stream for the capture plant is treated by chlorination for biological control and by chemical precipitation and clarification
The portion of the makeup water used for DCC makeup requires additional treatment (two-pass RO unit) to produce relatively high
purity water.
Process Wastewater CAP is designed to minimize wastewater production Non-usable liquid streams . Condensed moisture from the flue gas entering the CAP . CAP supply duct drain effluent will be collected and sent back to the main stack drain system . Evaporative condenser blowdown from the CAP refrigeration system discharged to MT wastewater ponds. Return duct drain effluent collected and sent to holding tank for re-use in the process.
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 20 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Key Integration Areas Chilled Ammonia Process Byproduct Stream Options considered:
. Ammonium sulfate recovery for commercial end-use
. Reaction of ammonium sulfate to a secondary byproduct that can be either sold commercially or disposed of in a landfill . Reuse of the ammonium sulfate solution within the Mountaineer flue gas path.
Focus on commercial use and disposal options Recovery of Crystallized Ammonium Sulfate for Resale
Recovery of 40 wt% Ammonium Sulfate for Resale
Alternate process referred to as “Lime Boil” to react ammonium sulfate with lime to recover ammonia and produce gypsum that could be combined with Mountaineer’s gypsum waste product from the FGD.
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Chilled Ammonia Process Byproduct Stream (cont.) 40 wt% solution selected as design basis Lower energy demand Optimal product for end-user Lime Boil process option eliminated High OPEX Increased waste
The CAP byproduct stream expected to be a 25 wt% (typical) aqueous solution of dissolved ammonium sulfate. System designed to accommodate a stream as low as 15 wt% total dissolved solids (TDS).
Based on the desire for operational flexibility, a total of four (4) 50,000 gallon tanks were provided to handle dilute CAP by-
product that may be less than 15 wt%.
Space allocated in equipment layout for additional crystallization equipment (future) Increased marketing flexibility
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CO2 Compression Injection pressures in the 1200 psi – 1500 psi range are expected early in the life of the target injection wells (from PVF experience). Maximum injection pressure into the geological formations targeted for the project is expected to be
approximately 3000 psi. Compression to an intermediate pressure, followed by variable speed pumping to the final injection pressure offers greater flexibility and efficiency over the life of the system as compared to full compression to the maximum expected injection pressure.
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 23 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Key Integration Areas
CO2 Compression (cont.) integrally-geared centrifugal compression to a super- critical condition
integrally-geared centrifugal compression to a sub- critical condition followed by cooling (liquefaction) and
pumping to the final CO2 pipeline pressure Integrally geared technology is proven, cost effective, and offers, with the use of a variable-speed drive on the
CO2 pump, a wide range of outlet pressures. Phase I cost estimate reflects the cost for sub-critical compression and liquefaction
Conservative approach in that supercritical compression is less mechanically complicated (though higher operating risk), lower CAPEX, and presumably lower total installed cost.
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 24 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Key Integration Areas
CAP Power Supply
Analysis performed that considered: Estimated electrical loads
Steady state load flow requirements
Large motor starting scenarios
Resultant bus voltage and short circuit duty to size and determine equipment ratings.
Mountaineer sub-station upgrades Two (2) new 138kV lines to a step-down station to serve
CAP island and associated BOP systems.
Installation of a fiber multiplexer and other necessary electronics to provide bandwidth as needed to support the telecommunications needs of the capture plant.
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 25 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information. Key Integration Areas
CCS Control Systems
All control and monitoring associated with process systems and equipment will generally be from the Distributed Control System (DCS) terminal located in a dedicated CCS control room located near the CAP. CCS Control Room Features Designed as a continuously occupied control center
designed to accommodate two (2) operators and a shift supervisor. Included all the necessary displays for safe operation of both the capture and storage systems.
Normal control and monitoring will be from the DCS Operator Interface Terminal (OIT)
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CCS Control Room Features DCS also monitors data returned from the CO2 storage Well Maintenance & Monitoring System (WMMS) PLC at each well site as well as data from instrumentation monitoring pipeline leakage.
CO2 leakage is alarmed in the CCS control room for operator action. A dedicated monitor in the CCS control used to display status of selected Mountaineer power block systems (unit load, etc.). . No capability of controlling any of the main power block systems. . Similarly, the CCS systems’ status is displayed in the main Mountaineer control room. A dedicated data historian workstation is used to collect and store a history of process values, alarms, and status changes.
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Overall the conceptual design and integration of the CAP and its associated BOP systems into the Mountaineer power generating station was a success.
Engineering team confident that a prudent balance was struck between operation and integration philosophies
Collaborative process was instrumental in identifying many of the technical risk factors up front, and in designing a capture and storage facility that could be practically integrated and successfully operated at Mountaineer.
Key Integration Accomplishments Selection of process steam source that minimized extraction ties, eliminated significant turbine modifications, and kept the operation of the steam supply as simple as practical. Incorporation of a condensate return storage “buffer” tank to alleviate contamination concerns with respect to the main unit steam cycle.
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Key Integration Accomplishments (cont.)
The ability to re-introduce CO2 into the CAP return duct in the event that the product does not meet specifications for injection, or if the injection wells are out of service.
Separate flue gas condensate (inlet/outlet) drainage and collection systems provided as a precaution in the event that a CAP upset increased the ammonia concentration in the return flue gas condensate, which could potentially impact the plant’s ammonia discharge limits.
Additional byproduct storage tanks to handle dilute byproduct and increase operational flexibility.
Robust power supply to insure CCS system reliability
Dedicated integrated controls system to provide CCS monitoring capabilities and maximize efficiency of operations.
American Electric Power: This report is provided “as-is” and with no warranties, express or implied, whatsoever for the use or the accuracy of the information contained therein. Use of the report and the information found therein is at the sole risk of the recipient. American Electric Power Company, its affiliates and subsidiaries, shall not be liable in any way for the accuracy of any information contained in the report, including but not limited to, any 29 of 30 errors or omissions in any information content; or for any loss or damage of any kind incurred as the result of the use of any of the information.