Refinery Residue Based IGCC Power Plants and Market Potential

Transcription

1 10/17/2001 page 1 Gasification Technologies 2001 Refinery Residue Based IGCC Power Plants and Market Potential Joachim Wolff (Speaker), Karsten Radtke GmbH Jürgen Karg, Werner Günster Siemens AG Power Generation

2 10/17/2001 page 2 Content 1. Incentives 2. Design Conditions 3. Plant Concept 4. IGCC Overall Performance 5. Economic Evaluation 6. Project Execution 7. Outlook Syngas Cooler Gasification HP Steam Oxygen Raw Gas Scrubber/ Soot Removal Soot Water HP Steam, sat HP Steam for Gasification Desulphurization Sour Gas Clean Gas G Fuel Gas Flue Gas Soot Filtration Sulphur Recovery Waste Nitrogen Saturator G Steam Turboset Oxygen Air Separation Unit G Condenser Gas Turboset Boiler Feedwater Visbreaker Residue Waste Water Soot Filter Cake Sulphur Air Air Feedwater Makeup Gas Island Power Island

3 10/17/2001 page 3 Integrated Gasification Combined Cycle Advantages Clean Technology High Efficiency is not the Driver for Lowvalue Fuels Fuel Flexibility Repowering of Existing Plants Modularity + Phased Construction

4 10/17/2001 page 4 ± 25% ± 5% ± 10% ± 2% ± 20% ± 5% Gas Turbine/CC 30% Gasification/Gas Cleaning 25% Owners Cost 1020% ASU 15% Off Sites 1025% Project Development 515% Typical IGCC Project Costs GTC2000McConnel, Drnevich; Simbeck

5 10/17/2001 page 5 Incentives Optimised Overall IGCCPlant Concept Definition of an Overall Control Philosophy Minimisation of Plant Emissions Reducing Cost by Location Synergies/Greenfield Site Coordinate Interface and Integration Engineering Reducing Cost for Project Development Reducing Time for Project Implementation Evaluation of Realistic EPC Cost (+/ 10%)

6 10/17/2001 page 6 Market Potential for ResidueBased IGCC Liquid residues from existing refineries (302 Mio t/a) are corresponding to a general IGCC potential of 170 GW Existing Refineries: Non Accessible Share for IGCC Applications 80 GW IGCC Potential from Refinery New Capacity Additions until 2010: 30 GW Existing Refineries: Accessible Share for IGCC Applications 90 GW Restrictions Restrictions on on the the refinery refinery sites sites used used for for evaluation evaluation of of effective effective IGCC IGCC potential potential for for existing existing refineries: refineries: minimum minimum oil oil throughput/plant throughput/plant output output by by site site maximum maximum share share of of IGCC IGCC in in national national plant plant capacities capacities national national power power plant plant market market countryspecific countryspecific status status of of liberalization liberalization Total Potential for Residue Based IGCC up to 2010: 120 GW Africa/Middle East 16 GW Asia/Pacific 50 GW NAFTA 28 GW Eastern Europe 5 GW C/S Americas 9 GW Western Europe 12 GW

7 10/17/2001 page 7 Market Potential for ResidueBased IGCC up to 2010 subdivided into Net Frequency and Power Output Ranges (Total possible capacity 120 GW) 50 Hz Market: 61 GW 60 Hz Market: 59 GW Refinery new capacity additions are assumed to be mainly in the range of 7 Mio t/a crude oil capacity, resulting in a ResidueBased IGCC power output of about 500 The The Highest Potential for for ResidueBased IGCC IGCC is is in in the the Power Power Output Output Range Range of of to to

8 10/17/2001 page 8 Standard IGCC Scope of Work Definition of Basis of Design Concept Calculation and Optimisation Preparation of Cost Estimate Development of a Sound Project Implementation Program Definition of further Activities

9 10/17/2001 page 9 Lessons Learned IGCC Applications requires Coordinated Interface and Integration Engineering Yes: Close Cooperation of all participating parties No: Black Box Philosophy with limited direct communication Plant operation is heavily influenced by the overall control philosophy/system and its optimisation for the different plant section Well trained operators as well as optimised automation degree improves plant availability

10 10/17/2001 page 10 SGP Gasifier Liquide Fuel Visbreaker Residue 50 % Integration of Air Separation Unit (ASU) ASU Gas Cooling Gas Cleaning Sulphur Recovery Use of Sensible Raw Gas Heat to Produce High Pressure Steam Minimal Sulphur and Dust Emissions 100 % Waste Nitrogen from ASU to Gas Turbine (GT) Gas Saturation Fuel Oil Use of Low Level Heat for Clean Gas Saturation Low NO x Combustion Resulting in Low (< 25 ppm) NO x Emission Design for Secondary Fuel G Use of High Efficient Siemens V94.2 Gas Turbine (Syngas Proven) Triple Pressure Heat Recovery Steam Generator (HRSG) HRSG (SCR Optional) G Use of Siemens Reheat Steam Turbine (KN Series) Low HRSG Exhaust Temperature T = 126 C

11 10/17/2001 page 11 Gasification Steam Boiler Feedwater HP Steam Oxygen ASU Visbreaker Residue SGP Reactor Syngas Cooler Quench Raw Gas Scrubber Filtrate Dustfree Raw Gas Sour Gas Desulphurization Sulphur Recovery Unit Sulphur Expander G Waste Nitrogen Saturator System Air Gas Turbo Set Extracted Air Air Exhaust Gas Power HRSG Steam Turbo Set Power SGP Reactor Syngas Cooler Quench Quench Water Scrubber Soot Water Clean Gas Soot Filtration Waste Water Soot Filter Cake Saturator System Waste Nitrogen Gas Turbo Set Exhaust Gas Power Extracted Air Air HRSG Oxygen ASU Feedwater MakeUp Gasifier Pressure 66 bar 50100% Load Range Capability of the Plant Municipal Supply of Makeup Water Syngas Cooling Backup Fuel: Fuel Oil Base Load Operation

12 10/17/2001 page 12 No Feedstock Limitation for SGP Typical Data for Used Liquid Feedstocks Feedstock Type Standard Vacuum Liquid Liquid Feed Residue Coke Waste Feedstock Properties Specific Gravity, 15 C C/H Ratio, wt Sulphur, % wt Ash, %wt Feedstock [kg] Oxygen Feed 99.5 %, [kg] SGP Product Gas (150 C, 62 bar) Composition, % vol. (Dry) Hydrogen & Carbon Monoxide H 2 /CO Ratio ( mole/mole) Steam Export [kg] 2) Basis: Production of 1,000 m 3 (N) 1) of CO+H 2 1) m 3 (N) = m 3 at 0 C and bar 2) steam production corrected by gasification steam consumption

13 10/17/2001 page 13 Site Conditions Site elevation m above sea level 0 (*) Elevation of the plant (expected) m above sea level 8 Atmospheric pressure bar (*) Relative humidity (average) % 60 (*) Relative humidity (maximum) % 95 Ambient air temperature C 5 Ambient air temperature C 30 Ambient air temperature C 60 Ambient air temperature (average) C 15 (*) Wet bulb temperature C 12 Average rainfall mm/month 130 Average rainfall mm/year 1,000 Wind velocity (maximum) km/hr 150 Earthquake factor negligible (*) ISO Conditions used for Performance Calculation

14 10/17/2001 page 14 Performance Data Feedstock to Gasifiers kg/h 106,960 Fuel Heat Input (LHV) 1,131.9 Fuel Heat Input GTs (LHV) Output Gas Turbines 2 x Output Steam Turbine Output Expander 6.9 Total Gross Output Power Consumption Power Island 15.9 Power Consumption ASU 55.6 Power Consumption 3.2 Gasification/Gas Cleaning Net Power Output Net Efficiency Power Island (LHV) % 57.1 Net Efficiency IGCC (LHV) % 42.8 Waste Water m³/h 27.6 Sulphur t/h 5.3 Filtercake t/h 5.1

15 10/17/2001 page 15 Modular Design allows any Adaptation to Site Specifics

16 10/17/2001 page 16 Scope of Supply Complete IGCC, including Fuel Storage for Backup Fuel Liquid Sulphur Handling Waste Water PreTreatment Filter Cake Loading Cell Cooling Towers

17 10/17/2001 page 17 Exclusions Owners Cost Process Licence Fee and Royalties Land Sales Tax Transmission Lines Permitting Owner s Project Management Site Specifics Site Levelling and Demolition Piling, Rock Blasting or similar Measures Groundwater lowering Provision of Fuel, Utilities and Labour for Commissioning

18 10/17/2001 page 18 Economic Evaluation > Western European Greenfield Site > Comparison of 500 ( E Class GT, V94.2) with 700 Steam Power Plant and 780 Combined Cycle Power Plant ( F Class GT, V94.3A) for Natural Gas > Variation Investment Costs, Fuel Price, Plant Load Factor, Depreciation Period, Electricity Rate, etc. Overall Accuracy of Cost Estimate is +/10%. 91% Availability for Power/87% Availability for Syngas Visbreaker Residue, 5% Sulphur, HHV 40,139 kj/kg dry/17,257 Btu/lb dry

19 10/17/2001 page 19 Activity Month Description Key Dates Contract Award/Notice to proceed Taking Over of Site from Client Water and Pow er Supply available 6 kv/aux. Pow er available First Ignition of GT (Backup Fuel) First BFW to Gasification First Steam to Gasification First Air from GT to ASU First Oxygen to Gasification First Nitrogen from ASU to GT First Ignition of GT (Syngas) Mechanical Completion Plant Acceptance General Preliminary Activities Soil Investigation Site Preparation Detailed Engineering Pow er Island Gas Island Procurement & Manufacturing Gas Turbines Steam Turbines Gasifier ASU Others Civil & Construction Process Units Combined Cycle DCS Ele ctr ical Commissioning Startup

20 10/17/2001 page 20 Levelized Electricity Generation Costs [USct/kWh] IGCC SPP CCPP IGCC = Standard OilIGCC SPP = Steam Power Plant CCPP = Comb. Cycle Power Plant 1 0 Residues Coal Natural Gas $/t $/t Fuel Costs [US$/GJ]

21 Siemens Project Directorate 10/17/2001 page 21 S i e m e n s Power Flue Gas Power Demin. Water System Steam Turbine HRSG Gas Turbine Saturator Cooling Water System Steam Condensate System Power Island Gas Island Steam Steam Instrument.& Control System Balance of Plant Visbreaker Residue Shell Oil Gasification O 2 Air Separation Unit Syngas Effluent Cooler Waste Water Stripper Filtrate Soot Scrubbing Soot Water Filtration Unit Air O 2 Desulphurization Sulphur Recovery Sour Gas Flare System Firefighting System Air K r u p p U h d e Pretreated Waste Water Filter Cake Sulphur Instrument. Air System

22 10/17/2001 page 22 Customer LSTK Contract Siemens Project Directorate Single Point Responsibility wraparound liability Shell ASU Vendor Siemens Gasification BDP License Air Separation Unit Power Island Gas Generation Island

23 10/17/2001 page 23 Outlook (Next Steps) Minimisation and Optimisation of Low Level Heat Integration Cost Reduction versus Efficiency Plant Layout Overall Concept Cooling Tower Concept HRSG with Natural Circulation Determination of EPC Cost Basic Engineering for Accuracy +/ 10% Startup and Shutdown of the IGCC Minimisation of Time Minimisation of Flaring Plant Automation Concept Implementation of Standard Modules for Gasification Air Separation Plant Minimisation of Cooling Water Consumption and Internal Power Consumption Gas Turbine Application 60 Hz

24 10/17/2001 page 24 End of the Presentation

25 10/17/2001 page 25 Emissions Draft EC Directive Standard IGCC Standard IGCC Future EPA 9) Dust 5 mg/nm³ 1), 4), 5) < 5 mg/nm³ 1), 5) ) ) NOx 120 mg/nm³ 1), 2), 3) < 50 mg/nm³ 1), 2) ) ) SOx 35 mg/nm³ 1), 5), 6), 7) < 18 mg/nm³ 1), 5) ) ) 1) Nm³ refers to standard temperature ( K) and pressure ( kpa) conditions. 2) Related to dry exhaust gas at 15 vol. % O 2 3) For gas turbines with > 50 thermal input at ISO conditions and gaseous fuels other than natural gas 4) For gaseous fuels as a rule 5) Related to dry exhaust gas at 3 vol. % O 2 at Gas turbine Stack 6) For new plants and gaseous fuels in general 7) For new and existing plants and low calorific gases from gasification of refinery residues the emission limit would be 800 mg/nm³ 8) Total emissions in lb per MMBTU heat input (LHV) (3,862 MMBTU/hr) 9) Proposal GTC