Carbon Management Research in UKy-CAER

Supported byCarbon Management Research Group

Kentucky EEC - DEDIARPA-E

US DOE International CollaborationUS Department of Energy

Rodney AndrewsCenter 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 CO2 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 K2CO3 Solvent

– Only reaches 3%-10% capture

•100-hour Preliminary Study using K2CO3/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 CO2 capture process

Current Funding Mechanism

The History of Coal Fired Power Plant

CO2 Emission vs. Net Plant Efficiency (coal)

Do We Have to Pay for Separation

• Targeted Process: – From a dilute state to over 90% purity

• dStotal = dSsystem + dSsurrounding ≥ 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 CO2

(166 Btu/kg CO2)~4% of coal HHV

CO2 Management Approach

Post CO2 Capture Process

Abs RegFlue Gas(CO2 ~14%)

Clean gas (CO2<1%)

Rich Sorbent

Heat

Lean Sorbent

CO2 Stream(>90%)

Challenges– Low CO2 concentration in flue gas

• High direct compression cost• High transportation cost•

– CO2 Enrichment Process• High energy consumption (50-

80% increasing in COE) • Finding appropriate technologies

CO2 Scrubbing Process Options

PC Flue Gas

IGCC

What does CCS COE Incremental Include?

Direct• CAPX • OPEX relating to

CCS only

Indirect

• Steam Extraction

• Makeup Power

Others• T.S.M• D.F.O

Heat Integration

• Stripper• Compressor

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)

ΔHabs

kJ/gmolRate Constant

M-1S-2

Pamine, 40C atm x 103

MEA 84 6000 0.1

NH3 27-60 799 200

K2CO3 27 50 0

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

Absorb40°C1 atm

Steam 3 atm

CO2150 Bar

Strip117°C2 atm

12% CO230% MEA (7 m)

Lean0.2

Rich0.5

MonoEthanolAmine Absorption/Stripping

C

1.2% CO2

The Need for CCS Heat Integration

Heat Rejected

to CW (400 Btu/lb

CO2)

Heat rejected

(100 Btu/lb CO2)

Heat needed (1300 Btu/lb CO2)

Heat Rejected

(400 Btu/lb CO2)

Heat Rejected

(600 Btu/lb CO2)

Can We Get fully Heat Integration?

StripperCondenser

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??

CAER's CCS Technology

Two-stage stripping

Integrated Cooling Tower

Advanced Solvent

What We Have Proposed for DOE Slipstream Project

1. 2.

3. Engineering design, build and install an advanced CO2 capture system into an existing PC power plant at a 0.7 MWe slipstream scale (~15 TPD CO2)

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 PCO2

exiting boiler

2. Integrated Cooling Tower: - Use regenerated CO2 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 ft2 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