AEP Mountaineer CCS II

Transcription

1 AEP Mountaineer CCS II Integration of a Commercial Scale CO 2 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 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 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.

2 Agenda 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 2of 30

3 AEP Overview 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 Coal handling terminal with 20 million tons of capacity Consume 76 million tons of coal per year 18,712 employees AEP Generation Capacity Portfolio Coal/ Lignite Gas/ Oil Nuclear Other (hydro, wind, etc.) 66% 22% 6% 6% 3of 30

4 Mountaineer Plant 4of 30

5 Mountaineer Plant 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 SO 3 Mitigation installed 2007 Primary fuel is bituminous coal 5of 30

6 Mountaineer Carbon Capture Product Validation Facility Summary Location Capacity New Haven, WV 100,000 tonnes CO 2 /yr Size 54 MWt 79,798 Nm3/hr CO 2 Storage Deep geological formations Upstream APC Equipment ESP, SCR, WFGD, SO 3 Sorbent injection Start-Up 3 rd Qtr 2009 Fuel Bituminous Coal Reagent Ammonium carbonate Regeneration Energy Chiller Refrigerant Byproduct Steam turbine extraction (HP Turbine Exhaust R410A Ammonium sulfate (dilute water solution) American Electric Power Mountaineer Power Plant CCS Product Validation Facility New Haven, WV 6of 30

7 MT CCS II Project Overview Purpose: Advance the development of the Alstom Chilled Ammonia Process (CAP) CO 2 Capture technology and demonstrate CO 2 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% CO 2 removal from the stack gas Store 1.5 million metric tons of CO 2 /year Demonstrate commercial scale technology 7of 30

8 MT CCS II Phase I Technical Objectives 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 8of 30

9 Chemical Plants Uniform product from a uniform feedstock Stable production rate w/ consistent production schedules Process variables minimized to reduce impacts. MT CCS II Phase I Technical Approach Operations Can a chemical plant operate like a power plant and vice versa? Power Plants Production based on demand Cyclical based on weather, time of day, etc. Frequent load adjustments Base load one day, loadfollowing the next. Variable feedstock (coal) Chemical composition, heating value, moisture content, etc. 9of 30

10 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. 10 of 30

11 Integration MT CCS II Phase I Technical Approach AEP approached integration conservatively on MT CCS II 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 CO 2 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). 11 of 30

12 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 12 of 30

13 MT CCS II Integration Execution Strategy Process Design w/ Alstom & WorleyParsons Site Design Conditions and Criteria (AEP) 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 13 of 30

14 Chilled Ammonia Process Overview Chilled Water Gas to Stack CO 2 Reagent CO 2 CO 2 Flue Gas from FGD Gas Cooling and Cleaning Cooled Flue Gas CO 2 Absorber CO 2 Regenerator CO 2 Clean CO 2 to Storage Reagent Heat and Pressure 14 of 30

15 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. 15 of 30

16 Key Integration Areas Turbine Arrangement w/ CAP Integration LP Turbine New Throttling Valve LP Turbine New Throttling Valve HP Turbine To Generator IP Turbine LP Turbine New Throttling Valve LP Turbine New Throttling Valve To Generator Boiler To CAP To CAP To Feedwater Heaters 16 of 30

17 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. 17 of 30

18 CAP Flue Gas Exhaust Key Integration Areas 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. 18 of 30

19 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% 19 of 30

20 Key Integration Areas 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. 20 of 30

21 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. 21 of 30

22 Key Integration Areas 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 byproduct that may be less than 15 wt%. Space allocated in equipment layout for additional crystallization equipment (future) Increased marketing flexibility 22 of 30

23 Key Integration Areas CO 2 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. 23 of 30

24 CO 2 Compression (cont.) Key Integration Areas integrally-geared centrifugal compression to a supercritical condition integrally-geared centrifugal compression to a subcritical condition followed by cooling (liquefaction) and pumping to the final CO 2 pipeline pressure Integrally geared technology is proven, cost effective, and offers, with the use of a variable-speed drive on the CO 2 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. 24 of 30

25 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. 25 of 30

26 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) 26 of 30

27 Key Integration Areas 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. CO 2 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. 27 of 30

28 Conclusions 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. 28 of 30

29 Conclusions Key Integration Accomplishments (cont.) The ability to re-introduce CO 2 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. 29 of 30