# CO 2 

# Capture at the Kemper County IGCC Project

2011 NETL CO 2 

# Capture Technology Meeting

# Kemper County IGCC Overview
Plant Site

Kemper Lignite Composition Average Min Max Heat Content btu/lb 5,290 4,765 5,870 Moisture % 45.5 42 50 Ash % 12.0 8.6 17 Sulfur % 1.0 0.35 1.7 

###  

## 2x1 Integrated Gasification Combined Cycle (IGCC)

– 

### 2 TR ansport I ntegrated G asifiers (TRIGTM)

– 

### 2 Siemens SGT6 - 5000F CTs

– 

### 1 Toshiba Steam Turbine (Tandem Compound Double Flow)

– 

### 582 MW peak and 524 MW on syngas

– 

### Heat Rate 11,708 Btu/kWh (29.5% HHV Efficiency w/ CO2 

### control and 40+% moisture coal)

– 

### Selexol for H 2 

### S and CO2 

### removal

– 

### 65+% CO2 

### capture (~800 lb/MWh emission rate)

– 

### Mine Mouth Lignite  

## Owner & Operator: Mississippi Power  

## Over $2 billion capital investment  

## Commercial Operating Date: May 2014  

## Use treated effluent from Meridian as makeup water  

## By-Products (TPY)

– 

### ~3,000,000 - Carbon dioxide used for EOR

– 

### ~135,000 - Sulfuric acid

– 

### ~20,000 - Ammonia

# Proposed Kemper County IGCC Project Map • ~70 miles transmission • ~ 60 miles CO2 

## pipeline (for EOR) • ~5 miles natural gas pipeline • ~31,000 acre mine site • ~2,900 acres plant site • ~ 30 miles treated effluent line Plant Site

New CO 2 Pipeline Meridian

# TRIG TM 

# Attributes/Advantages  

### Simple, well established design

– Based on technology in use for 70 years  

### Either Air - or Oxygen -blown

– Air for power

– Oxygen for liquid fuels and chemicals  

### High Reliability Design

– Non- slagging design:  Provides 10 -20 year refractory life,  Eliminates black water system  Provides non- fouling syngas cooler operation

– No burners to fail and be replaced

– Dry dust removal eliminates gray water system  

### Lower Fuel Costs

– Coarse, dry coal feed allows:  Fewer, lower power pulverizers, and  Less drying than other dry - feed gasifiers

– Cost - effective using high moisture, high- ash, low rank coals (PRB and lignite).  

### Excellent Environmental Performance

– Lower water use compared to pulverized coal (PC)

– Excellent emissions performance

– Easier to permit compared to PC

– Lower cost carbon capture compared to PC

### Gasifier Island Combined Cycle COAL

PROCESS AIR COMPRESSOR HIGH TEMPERATURE SYNGAS COOLING CO 2 AND SULFUR REMOVAL COAL MILLING & DRYING HIGH PRESSURE

COAL FEEDING
SOUR WATER TREATMENT AMMONIA RECOVERY RECYCLE

GAS COMPRESSION

GAS TURBINE
STEAM TURBINE CONDENSER SYNGASSWEET SYNGAS VENT GAS ANHYDROUS

AMMONIA ACID GAS RECYCLE GAS

COARSE G - ASHHP BFWHP STEAM
TO STACK HP, SUPERHEATED STEAMCONDENSATE MERCURY REMOVAL TRANSPORT

GASIFIER

AIR

POWER POWER FINE G - ASH WATER GAS SHIFT REACTION CO 2 

# Summary Flow Diagram

CO 2 COMPRESSION

AND DRYING CO 2 PARTICULATE COLLECTION LOW TEMPERATURE SYNGAS COOLING SWEET SYNGAS

SOUR WATER WSA PROCESS SULFURIC

ACID WATER FROM COAL DRYING

HEAT RECOVERY STEAM GENERATOR

# Evolution of Acid Gas Removal at Kemper County IGCC  

# Originally, no CO2 

# removal. H 2 

# S removed with amine.  

# With CO2 

# removal added to scope, design team explored three main options based on a physical solvent:

– 

## 25% CO2 

## removal (1,500 lb CO2 

## /MWh).  

## Case 1: No WGS, Selexol for sulfur removal, amine for CO2 

###  

## Case 1A: One stage of WGS, with Selexol for all acid gas removal.

– 

## 50% CO2 

## removal (1,000 lb CO2 

## /MWh).  

## Case 2: One Stage WGS with steam injection with Selexol for AGR.  

## Case 2A: Case 1A retrofitted to Case 2 in 2020  

## Case 2B: Case 1 retrofitted to Case 2 in 2020.

– 

## 65% CO2 

## removal (800 lb CO2 

## /MWh).  

## Case 3: Two stages WGS with steam injection and Selexol for AGR.

# Physical Solvent Selection The operating costs for an a mine were too expensive, due to high steam usage for regeneration. Therefore, a physical solvent was selected. Selexol Rectisol Volatility Low High Solvent Price High Low Emissions Concern No Yes 

# Both good options, but Selexol was chosen.

# Commercial Selexol Plant H 2 

## S Absorber CO 2 

## Absorber

Lean - Rich Exchanger Regenerator Flash Drums Concentrator ReboilerLean Solvent Sour Syngas
Rich Solvent H 2 S Absorber Lean / Rich Exchanger H 2 S Concentrator Recycle Gas H 2 S Regenerator

Flash Drum CondenserReflux Acid Gas Flash Drum

Steam - Heated Reboiler Steam Heat Lean Solvent Flash Gas Flash Gas CompressorLP Flash Gas To WSA Semi - Sweet Syngas CO 2 Captured CO 2 Absorber Sweet Syngas Semi - Lean Solvent Lean Chiller Semi - Lean Chiller

HP Flash MP Flash LP Flash CO 2 Recycle Compressor CO 2 Recycle Lean Solvent

Loaded Solvent 

## •Two Stages WGS • Selexol Physical Solvent • Refrigerated to 40 F

• Carbon Capture: >65% • CO 2 

## Emissions: 800 lb CO 2

## /MWh • Yield: >3 MM Tons/yr CO 2 

## • CO 2 

## compressed and used for EOR • Acid gas converted to sulfuric acid

via WSA process. 

# CO 2 

# Capture Scheme for 800 lb/MWhCooling Towers Sulfuric Acid

Production Sulfur/CO 2

Removal Coal Dome Flare Coal Loading Hoppers Process Air Compressors Water Treatment Coal Prep Gasifier Structure: Gasifiers, Syngas Cooling/Filtration

2 x 1 Combined Cycle Control/Admin Bldg. Warehouse Water Supply Pond

Electrical Switchyard

## Fluid Bed Dryer System Sulfuric Acid Production CO 2 

## and H 2 

## S Removal Gas Turbines HRSGs Steam Turbine Air Compressors HP Coal Feeders Gasifiers (2) Nitrogen Plant

Ammonia ProductionCO 2 Compressors
CO 2 Flash Drums (8)

Process Air Compressors (4) WGS Reactors Syngas Humidifiers COS Hydrolysis NH 3 Removal Mercury Adsorbers Sour Water/NH 3 Recovery System H 2 S Absorbers (2) AGR Regenerators (2) Crushed Coal Silos
Coal Mills (6) Back- pulse Surge Drums Particulate Collection Device (PCD) Dry Ash Filters (4) Gasifiers (2)
Main Syngas Coolers (4)

Warehouse Admin.

Bldg . Flare Derricks

Steam Turbine HP Coal Feeders (12) CO 2 Absorbers (6)

# Project Status  

## On June 3, 2010, the Mississippi Public Service Commission certified the project.  

## Mississippi Power has entered into CO2 offtake agreements with Denbury Onshore and Treetop Midstream Services, LLC  

## MDEQ issued the final PSD permit on March 9, 2010.  

## Procurement: All major equipment awarded. Equipment fabrication underway. First major pieces arriving on site.  

## Construction: Site cleared and graded. Foundation and pedestal work underway. Sumps, duct banks, underground piping being installed.

# Kemper Procurement Update 2 nd 

# Quarter - 2011
Base of CO 2 

# Absorber Top of CO 2 

# Absorber Base of Concentrator Lean/Rich Exchanger Plates

# Kemper County IGCC Construction Update 1 st 

# Quarter - 2011 Storm Drains 

# Fire Protection Piping Electrical Duct Banks

Began Installation of Underground Electrical and Mechanical Systems

## Deep Foundations/ Major Equipment Foundation Installation/U/G Utilities 

# Steam Turbine Columns 96” Circ. Water Pipe AGR Area Sumps 

# Kemper County IGCC Construction Update 2 nd 

# Quarter - 2011

# Kemper County IGCC Construction Update End of 2 nd 

# Quarter - 2011 Circulating Water Pipe
Gasifier Pile Caps/ Deep Foundation Installation Steam Turbine Operating Deck
Plant Site as of July 2011

# Summary  Physical solvents were selected for the Kemper design due to reduced steam usage.  The facility will use Selexol coupled with two stages of water gas - shift, resulting in a CO 2 

# emission rate of 800 lb/MWh (a nominal 65% reduction).  3 million tons/year of CO 2 

# captured at the Kemper site will be used for EOR, and will meet offtaker specifications.  Commercial operations are expected in May 2014.