ccs projects integration workshop - london 3nov11 - aep - integration of a commercial scale co2...

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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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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

CO2 Compression Study

CAP Power Supply

CCS Control Systems

Conclusions


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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 assetsOver 7,500 railcars involved in operationsOwn/lease and operate over 2,850 barges & 75 towboatsCoal handling terminal with 20 million tons of capacityConsume 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%


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Mountaineer Plant


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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 SO3 Mitigation installed 2007

Primary fuel is bituminous coal


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Mountaineer Carbon Capture Product Validation Facility Summary

American Electric PowerMountaineer Power PlantCCS Product Validation FacilityNew Haven, WV

Location New Haven, WV Capacity 100,000 tonnes CO2/yr

Size ≈ 54 MWt

79,798 Nm3/hr CO2 Storage Deep geological

formations Upstream APC Equipment

ESP, SCR, WFGD, SO3Sorbent injection

Start-Up 3rd Qtr 2009 Fuel Bituminous Coal Reagent Ammonium carbonate Regeneration Energy

Steam – turbine extraction (HP Turbine Exhaust

Chiller Refrigerant

R410A

Byproduct Ammonium sulfate (dilute water solution)


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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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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


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MT CCS II Phase I Technical Approach

Chemical Plants

Uniform product from a uniform feedstock

Stable production rate w/ consistent production schedules

Process variables minimized to reduce impacts.

Power Plants

Production based on demand

Cyclical based on weather, time of day, etc.

Frequent load adjustments

Base load one day, load- following the next.

Variable feedstock (coal)

Chemical composition, heating value, moisture content, etc.

Operations

Can a chemical plant operate like a power plant and vice versa?


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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

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 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).


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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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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


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Gas to StackChilled

Water

Chilled Ammonia Process Overview

Gas Cooling

and Cleaning

Flue Gas from FGD

CO2

Cooled Flue Gas

CO2

CO2 Regenerator

CO2 Absorber

CO2

Clean CO2 to Storage

Reagent Heat and Pressure

Reagent

CO2


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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.


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Turbine Arrangement w/ CAP Integration

To Generator

To Generator

Boiler

HP Turbine

IP Turbine

LP Turbine

LP Turbine

LP Turbine

LP Turbine

To CAP

New Throttling Valve New Throttling Valve

New Throttling Valve New Throttling Valve

To Feedwater Heaters

To CAP


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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.


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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.


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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 pumps, 4 gpm each, avg.)

4%

Washdown hose stations 4% Process water makeup (clarified water)

3%

DCC makeup (RO product) 7% Filter backwash and RO concentrate 3%

Makeup water clarifier sludge blowdown

2%

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.


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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 byproduct 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.


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CO2 Compression (cont.)

integrally-geared centrifugal compression to a supercritical 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.


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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.


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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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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.


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Conclusions

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.

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