New Generation Strategy
Revenues: $14.5 billionAssets: $37 billionUS customers: 5 millionUS employees: 22,000
Source: AEP 2003 Annual ReportThe American Electric Power System100 years in operation
36,000 MW generation capacity more than 70% coalLargest generator of electricity in USLargest coal purchaser and consumer over 70 million short tons (64 million metric tons) per year
39,000 miles (62,000 km) transmission 7,900 miles (12,600 km) 230 765 kV
200,000 miles (320,000 km) distribution5 million customers in 11 states
$11.9 billion annual revenue$36.2 billion assets
Source: AEP 2005 Annual Report
The American Electric Power System
Revenues: $14.5 billionAssets: $37 billionUS customers: 5 millionUS employees: 22,000
Source: AEP 2003 Annual ReportAEP Today: The Need for New GenerationAEP is committed to providing reliable, affordable, and sustainable electricity to our 5 million customers.AEP has not added base load capacity since 1991 (Zimmer conversion)AEP will need approximately 1200 MW of additional generating capacity in our Eastern region by 2010AEP believes that Integrated Gasification Combined Cycle (IGCC) technology is the best choice for capacity additions in the East
Site Selection & Evaluation ProcessWhere is the best site to build a new IGCC Power Plant in AEP East?Site Study Team EstablishedRepresentatives from AEP Third Party Consultant retained for studyPotential Sites Identified AEP existing plants sitesAEP owned/controlled property Fatal Flaw Analysis to narrow list15 sites identified for evaluationDeveloped Ranking CriteriaEstablished Design Basis
Design Basis - Key Siting Parameters600 MW IGCC Unit (with option to expand to 1200 MW)2 x 2 x 2 x 1 Configuration 2 Operating Gasifiers / Gas Cleanup Systems 2 Combustion Turbines 2 Heat Recovery Steam Generators 1 Steam Turbine
600 MW1200 MWFuel Consumption2 million (1.8 million)4 million (3.6 million)short tons per year (metric tons per year)Heat Rate HHV8,500 (2,142)8,500 (2,142)Btu/kWh (kcal/kWh)Make-up water flow5,500 (347)11,000 (693)gallons per minute (liters per second)Land Requirements:power block30 (12)45 (18)acres (hectares)gasification island60 (24)105 (43)acres (hectares)rail loop150 (60)150 (60)acres (hectares)coal yard40 (16)40 (16)acres (hectares) inside rail loop solid waste disposal150 (60)300 (121)acres (hectares)Total (rail delivery)390 (158)600 (243)acres (hectares)Total (barge delivery)280 (113)490 (198)acres (hectares)Operating staff125200full time equivalent employees
Site Selection Ranking CriteriaSite TopographyTopography and SizeExpandabilityDistance from Waste DisposalFlood PotentialConstructabilityAir & Water EnvironmentalDistance from Class I AreasDispersion ConditionsExisting Air QualityAir Quality Non-Attainment Area CO2 Sequestration - Third Party Desktop StudyTransmissionDistance from TransmissionTransmission StabilityFeasibility of 2 Unit Transmission plan
Fuel DeliveryDistance from Rail or BargeAlternate TransportationDistance from Natural Gas PipelineDelivered Coal Cost DifferentialCooling WaterDistance from Adequate Water SourceAdequacy of Cooling Water SourceLand UseDesignated Parks & Recreation AreasExisting Land UseExisting ResidencesNearby Land UseHabitatWetlands Impact PotentialOther Natural Habitats Impact PotentialDocumented Presence of Threatened and Endangered Species
Site Selection Ranking CriteriaWeighting FactorsScale of 1 - 10Rating FactorsScale of 1 5Example below
Criteria DescriptionWeighting FactorEvaluation CriteriaRating FactorPlant Site Topography and Size80.5 to 1.0 percent slope and less than 100,000 c.y. (76,000 cubic meters) fill51.0 to 2.0 percent slope or 100,000 to 300,000 c.y. (76,000 to 228,000 cubic meters) fill42.0 to 3.0 percent slope or 300,000 to 600,000 c.y. (228,000 to 456,000 cubic meters) fill33.0 to 4.0 percent slope or 600,000 to 1,000,000 c.y. (456,000 to 760,000 cubic meters) fill24.0 to 5.0 percent slope or more than 1,000,000 c.y. (760,000 cubic meters) fill1Expandability for Future Units7Three or more units can fit on site5Only two units can fit on site3Only one unit can fit on site1
ResultsTop Sites by StateMountaineer West VirginiaGreat Bend OhioCarrs - Kentucky
Generating Technology Options: Integrated Gasification Combined Cycle (IGCC) Plants
Business Models of Various Technology SuppliersSyngas over the fenceTechnology owner provides capital investment and operating servicesCost of syngas may be tied to fuel cost, escalation, other factorsAlso oxygen over the fenceLicensingTechnology owner provides equipment design and performance guarantees for equipmentOwner assumes risk of integrated unit performanceTurn key EPC with performance guaranteesTechnology owner provides engineering and design of integrated unit and all componentsTechnology owner also assumes cost and schedule riskGuaranty of total unit performance: inputs vs. outputsGasification Technology Options
Commercial Technology ChoicesSlurry fed Conoco, GESlurry fed technologies suited to high rank fuelsDry fed ShellBetter heat rate, longer injector lifeTechnology suited for lower rank subituminous coals as well as high rank fuelsHeat Recovery/Integration Quench GEChemical production applicationsRadiant syngas cooler GE, Conoco, ShellHeat recovery for power generation in steam turbineConvective syngas cooler GEAvailability impact due to plugging not selected for reference plant
Gasification Technology Options
Current Configuration AEP East IGCCNet output 621 MW, Heat Rate 8,890 Btu/kWh (2,240 kcal/kWh) Target turndown to 40% of full load, and load following operationBroad fuel specification (eastern bituminous coal, petcoke)GE (formerly Texaco) GasifiersTwo radiant + quench gasifiers no spareOperating pressure 625 psi (43 bar)Turbine-GeneratorsTwo GE 7FB combustion turbines - 232 MW eachEvaporative inlet coolingSingle steam turbine 300 MWEmissions Control SystemsSelexol acid gas removal system for sulfur (H2S) removal w/COS reactorActivated carbon bed for mercury removalSyngas moisturization, nitrogen diluent for NOx controlSpace provisions for future polygeneration and CO2 capture
The gasifier operates at approximately 625 psi (43 bar) and 2550oF (1400oC)
Gasifier volume 1800 cubic ft (50.4 cubic meters)
The RSC generates high pressure steam by cooling the hot syngas from the gasifier from 2550oF to 1250oF (1400oC to 700oC).The RSC vessel is lined with waterwall panels along the inside perimeter of the vessel as well as some in the radial direction. The steam is generated in the RSC and circulated to the external steam drum.
The RSC concept has been demonstrated at plants in Germany as well as Coolwater and Polk Power in the USA. The vessel is about 6 m in diameter and 30-40 m long.The AEP RSC design is different than the Polk Power design because it has an internal water quench section at the vessel bottom which further cools the syngas at about 450oF (230oC).
Gasifier/Radiant Syngas Cooler (RSC)
When the gasifier load changes the oxygen to slurry ratio remains constant because the oxygen to carbon ratio is part of the control system.
The gasifier is connected to the RSC through a flange connection. The vessel heads and flanges are protected by the refractory lined transfer line.
The molten slag from the gasifier solidifies as it cools inside the RSC, and is collected in a water quench section at the bottom of the RSC. The slag and fines are removed through a lockhopper (LH) system which is automatically cycled to collect the slag at high pressure. The LH is then isolated and depressurized, and slag is dumped. The LH is re-pressurized and returned to collection mode. There will be 2 to 3 LH cycles per hour, depending on the fuel ash content.Gasifier/Radiant Syngas Cooler (RSC)
The velocity from the gasifier to the RSC decelerates from 15-20 feet per second (5-6 meters per second) to less than 3 feet per second (1 meter per second).The velocity profile of the syngas from the gasifier to the RSC is based upon jet flow calculations. The jet velocity when it hits the waterwall cannot be so high that it causes erosion and cannot be low enough to allow ash deposition.Gasifier/Radiant Syngas Cooler (RSC)
95% oxygen purity for oxygen to gasifier 98% other usesEconomy, ability to maintain design composition when changing loadsASU will consume ~110 MW depending on fuel and ambient conditionsAir integrationApproximately 25-30% of flow to main air compressor supplied by extraction air from CT at design point (ISO)Lessons learned from PolkUnit output curtailed due to lack of ASU capacityASU TurndownCompressor limited to approximately 85%Can adjust air extraction to extend rangeNo plans to produce other gases for saleStorage capacity 8 hours full load oxygen useNitrogen for purge, transfer CT to natural gas in case of ASU tripAir Separation Unit
Fuel FlexibilityThe gasification process can utilize any fuel containing hydrocarbonsCoalBiomassPetroleum ByproductsPetcokeThe AEP East IGCC design fuels include Northern Appalachian and Illinois Basin bituminous coals and the ability to blend petcoke with coalTechnology selection is dependant on fuelEastern Coal Low moisture content, high heating value Many eastern coals have high ash fusion temperatures, requiring the use of fluxant Some eastern coals have high chloride contentLignite & PRB coals High moisture content, high ash content, not currently suited for slurry fed gasifiers, due to ability to achieve desired slurry concentration.
Gasification Fuel Options
Impact of coal specificationsCoal ash fusion temperature - This is a slagging gasifier design which requires a less than 2500oF (1370oC) reducing ash fusion temperature. Coals with this low fusion temperatures are found in the Northern Appalachian and Illinois Basin. Coal in the Central and Southern Appalachian basin have high fusion temperatures and would require the addition of fluxant to suppress the ash fusion temperature. A fluxing system is currently not part of the AEP IGCC design.
Sulfur content range - The design sulfur content of the fuel effects the sizing of the Acid Gas Removal (AGR) and Sulfur Recovery Unit (SRU) systems. Coals from the Northern Appalachian and Illinois Basin have high sulfur content coals. The AEP coal specification allows for coals with sulfur content up to 7.5 lb SO2/mmBtu (5.26% wt. sulfur dry basis).
Impact of coal specifications (cont.)Chloride contentCoals from the Illinois Basin have high levels of chlorides. For IGCC technology, the chlorides are removed in the syngas cleaning systems. High chlorides may require the selection of higher alloys in certain systems, and may increase water usage. The AEP design provides for coal chlorides up to 3500 ppm (0.35% wt.).
Coal ash percentageNearly all of the ash is removed from the gasifier as slag. The ash content of the fuel determines the size of the slag handling systems. The AEP specification allows for ash content in the fuel up to 12%. This allows the use of many run-of-mine coals, with no coal washing needed.
Coal Prep SystemRod mills are used to mix and pulverize the coal. Dry coal and processes water is added to the rod mills. Coal slurry is then pumped into the gasifier at operating pressure.
There are two syngas/natural gas fired combustion turbines. The combustion turbine selected is the GE 7FB designed for syngas. Each turbine can generate 232 MW, utilizes air inlet cooling, and uses a hydrogen cooled generator. Nitrogen from the ASU and steam will be added to the syngas to increase mass flow and reduce the flame temperature. This feature enhances the output of the turbine, and allows for lower NOx operation.The HRSG is a two pressure design, which converts the heat from the exhaust of each combustion turbine into superheated steam. The HRSGs also receive steam from the gasification process. The steam turbine used is a GE D-111 with 40 inch (1 m) last stage blades. Steam in condensed by a water tube condenser. The steam turbine output is 310 MW, and uses a hydrogen cooled generator. The cooling tower provides circulating water for both the steam turbine condenser, and cooling loads from the ASU. The cooling tower is a mechanical draft type. Power Block
NOx15 ppm NOx in exhaust gas (15% O2 ref) on syngas25 ppm NOx in exhaust gas (15% O2 ref) on natural gasSO2>99.5% removal40 ppm total sulfur in syngas (H2S + COS)0.02 lb SO2/mmBtu~4 ppm total sulfur in exhaust gas (10% O2 ref)Particulates (PM10 and PM2.5)MercuryActivated carbon bed for mercury removalExpect 90% of mercury in syngasOther Hazardous Air PollutantsStartup considerationsEnvironmental performance without CO2 removal comparable to supercritical PC equipped with state of the art emissions controlsAir Emissions
- Acid gas technology choiceMDEA amine technology chemical solventSelexol allows for deeper sulfur removal physical solventRectisol methanol solventCost vs. effectivenessDepends on gas composition, sulfur removal desiredCapitalO&MEffect on output COS HydrolysisEffects on total emissionsCOS removal in AGR varies from
Diluent injectionNitrogen from ASU increase CT mass flow/outputCO2 maximize slip in AGR increase CT mass flow/output Steam impact on steam cycle outputSCRCostUncertainty of catalyst formulation for coal derived syngasInteraction with sulfurAmmonia salts produce particulate emissions, may deposit in HRSGOther Air EmissionsParticulate salts, H2SO4Ammonia 5 ppm slip (ref 15% O2)NOx Control
Flare OptionsFlare used to destroy raw or combustible gases during startup, shutdown, and transient eventsFlare emissions result in elevated ground level concentrations of SO2Operational and hardware modifications to reduce duration of flare eventsVisibility low during daylight hoursElevated Flare (AEP plant)Flare height 200 ft (60 m)
Flare OptionsGround Level Flare
Current plan to discharge wastewater to Ohio RiverThe discharge permits and their associated limits are set by the state where the plant is sitedThe Ohio River Valley Water Sanitation Commission (ORSANCO) is an organization that tries to address inconsistencies between states and proposes pollution control standards (www.orsanco.org).ORSANCO discharge targets are set to protect the users of the water and avoid water quality degradationThe target values for some elements are very low
ParameterRiver Max DissolvedRiver Max TotalGrey Water Cool Water IGCCDischarge Target Average/MaxMercury, ppt1.9313.163010/20Beryllium, ppb
Uncertainty of grey water compositionSamples not available for jar testsPotential interferences in treatmentUncertainty on levels achievable level of treatmentDetection LimitsHistoric dataToxicityChlorides in the effluentDaphnia survivabilityTemperatureWastewater Treatment Challenges
Wastewater Treatment ProcessAmmonia strippingGrey Water PretreatmentWastewater treatmentMetals RemovalBiological treatmentFilterFinal Effluent SumpRetenti...