Carbon Management Research in UKy-CAER Supported by Carbon Management Research Group Kentucky EEC - DEDI ARPA-E US DOE International Collaboration US Department of Energy Rodney Andrews Center for Applied Energy Research University of Kentucky

Carbon Management Research Group Build on E-ON US investment in carbon management project Develop more energy and cost effective carbon management technologies Address specific materials, controls and waste management solutions Allow early adoption of technologies by Kentucky’s electric utilities Current Founding Members: Five Utilities, EPRI and KY DEDI

Three Research Topics Short-medium Term Projects –Post-Combustion CO 2 Capture 0.1MWth Pilot-scale study 0.5~1MWth Slipstream field testing at members’ sites –Technical-Economic Analysis Long-term Project –Chemical Looping Combustion/ Gasification for Solid Fuels

CAER Pilot-Plant Research Completed commissioning using K 2 CO 3 Solvent –Only reaches 3%-10% capture 100-hour Preliminary Study using K 2 CO 3 /Piperizane (PZ) –Could reach 90% capture –Precipitation of PZ Two-month MEA with 32 runs using ceramic packing –MEA degradation vs. stripping temperature –Mass transfer under utility flue gas conditions 1.5-year study using Aqueous Ammonia –Ammonia slip vs. rich-solution pH etc –Mass transfer/energy vs. packing and operating parameters –Troubleshooting and problem solving On-going new solution study –Catalyzed solvent –Formulated solvent

Kentucky Energy and Environment Cabinet Carbon Management Research Industrial Members ( AEP, Duke, Easy Ky Power, LG&E and KU, and EPRI) APRA-E (three years) for post-scrubbing solution dewatering DOE International Collaboration (five years) on catalyst development and CDI dewatering DOE (four years) on slipstream-scale study on solvent- based post-combustion CO 2 capture process Current Funding Mechanism

The History of Coal Fired Power Plant

CO 2 Emission vs. Net Plant Efficiency (coal)

Do We Have to Pay for Separation Targeted Process: –From a dilute state to over 90% purity dS total = dS system + dS surrounding ≥ 0 –the entropy of an isolated system which is not in equilibrium will tend to increase over time, approaching a maximum value at equilibrium; –the entropy change dS of a system undergoing any infinitesimal reversible process is given by δq / T, where δq is the heat supplied to the system and T is the absolute temperature of the system.

The Minimum Work for Separation Only The first law The Second law from 14% to 90% 175 kJ/kg CO 2 (166 Btu/kg CO 2 ) ~4% of coal HHV

CO 2 Management Approach

Post CO 2 Capture Process AbsReg Flue Gas (CO 2 ~14%) Clean gas (CO 2 <1%) Rich Sorbent Heat Lean Sorbent CO 2 Stream (>90%) Challenges –Low CO 2 concentration in flue gas High direct compression cost High transportation cost –CO 2 Enrichment Process High energy consumption (50- 80% increasing in COE) Finding appropriate technologies

CO 2 Scrubbing Process Options PC Flue Gas IGCC

What does CCS COE Incremental Include?

Capital Investment: The Priorities Source:Vattenfall The requirement of solvent is fast kinetic The requirement of solvent is to have higher net cyclic capacity

Conflicts (Impact will be discussed later on) ΔH abs kJ/gmol Rate Constant M -1 S -2 P amine, 40C atm x 10 3 MEA NH K 2 CO

Solvents Comparison

New Solvents Development VLE -- for determining the solvent capacity and heat of absorption; Wetted Wall Column – for determining the reaction rate, the catalytic effect

Mini-scrubber and Pilot-scale Mini-scrubber, scaleup from WWC, is used for solvent and catalyst development Pilot-plant for selected solvent and catalyst

The Need for CCS Heat Integration Heat Rejected to CW (400 Btu/lb CO 2 ) Heat rejected (100 Btu/lb CO 2 ) Heat needed (1300 Btu/lb CO 2 ) Heat Rejected (400 Btu/lb CO 2 ) Heat Rejected (600 Btu/lb CO 2 )

Can We Get fully Heat Integration? Stripper Condenser Rich Solution L/R EHX ΔT Has to reject by polish EHX Combustion Air FG Dew Point FG Temp Profile Yes, but little FW Heating Temp-limited Steam extraction Some, ALL?? Else??

What We Have Proposed for DOE Slipstream Project Engineering design, build and install an advanced CO 2 capture system into an existing PC power plant at a 0.7 MWe slipstream scale (~15 TPD CO 2 ) Three novel processes will be designed and integrated: 2-stage solvent striping, cooling tower desiccant, and Hitachi solvent 1. Two-stage Stripping: - Increase solvent working capacity by providing a secondary air-stripping column following the conventional steam stripping column. - Air stripping stream sent to boiler as combustion air to increase flue gas P CO 2 exiting boiler 2. Integrated Cooling Tower: - Use regenerated CO 2 stream waste heat to dry liquid desiccant - Liquid desiccant is used to dry cooling tower air  Improved power plant cooling tower and steam turbine efficiency 3. Advanced Hitachi Solvent: - Primary amine analogous to MEA

Team Structure

What will We Do? The design, start-up/commissioning of a 2MWth test facility (1400cfm); Two proprietary solvents are to be tested for parametric investigation and long-term verification; New corrosion resistance coatings for material used in CCS system (access ports needed in scrubber and stripper areas) Solvent degradation (liquid product and gaseous emissions from CCS) A series of transient tests to quantify the ability of the carbon capture system to follow load demand.

Preliminary 3-D View of Slipstream Unit 80 ft tall 1000 ft 2 footprint ( 15’x65’, but could be rearranged ) 5 to 6 modulus with 100,000lbs/ modulus Plus control/lab trailer and others

Testing Site: LG&E and KU’s Brown Generating Station