Coal based IGCC technology

Transcription

1 Coal based IGCC technology Ola Maurstad, post doc Based on work during stay at Massachusetts Institute of Technology

2 Gasification Gasification is the conversion of a solid fuel to a combustible syngas (CO+H 2 ) Gasification enables Coal to run gas turbines Fuel gas clean up Pre-combustion CO 2 capture Gasification is not a new technology 2

3 Main features of the 3 gasifier types Gasifier type Moving bed Fluidized bed Entrained flow Outlet temperature Low ( C) Moderate ( C) High ( C) Oxidant demand Low Moderate High Ash conditions Dry ash or slagging Dry ash or Slagging agglomerating Size of coal feed 6-50 mm 6-10 mm < 100 µm Acceptability of fines Limited Good Unlimited Other characteristics Methane, tars and oils present in syngas Low carbon conversion Pure syngas, high carbon conversion 3

4 Moving bed gasifier Fluidized bed gasifier Focus of commercial gasifier technology providers: Entrained flow slagging gasifier 4

5 Entrained flow slagging gasifiers Outlet syngas temperature: C Slagging: Ash is a low viscosity liquid Pure gas High carbon conversion Can handle any coal type (technical perspective) Coal is ground to < 100 microns particles Particle residence time: a few seconds 5

6 Maturity of gasifiers 3 major classes Moving bed Fluidized bed Entrained flow Key modern gasifiers are of the entrained flow type: GE (formerly Texaco) Shell ConocoPhilips: E-gas process (formerly Destec) The moving bed type The Lurgi dry ash gasifier (Sasol-Lurgi) Fluidized bed type gasifiers less developed Not fully commercialized 6

7 GE Shell ConocoPhillips 70 bar 39 bar Flow direction is really upwards?! ~35 bar Source: 7

8 Integrated Gasification Combined Cycle (IGCC) What is an IGCC? A combined cycle (CC) power plant with a gasifier in front of it to provide the gaseous fuel Gasification Converts coal to syngas (CO+H 2 ) Combined cycle Converts the syngas to electricity Consists of Gas turbine Steam cycle (HRSG & steam turbine) 8

9 Integrated gasification combined cycle (IGCC) without CO 2 capture Gasification Quench water Heat Hot raw syngas Coal feed Water quench or heat recov. Gasifier ~1500 C ~300 C Particulate removal ~40 C Sulfur removal H 2 S Depending on process configuration Steam turbine Combined cycle O 2 Clean syngas Hot steam Feed water N 2 ASU Air (15 atm) Gas turbine Exhaust ~600 C HRSG Flue gas ~120 C Air Air 9

10 Experience with coal based IGCCs Demonstration plants with government support Project participant/ Plant name Southern California Edison/ Cool Water Dow (Destec)/LGTI Nuon/ Nuon Power Buggenum Destec and PSI Energy/ Wabash River Tampa Electric Company/ Polk Power Station Elcogas/ Puertollano Sierra Pacific Power Company/Pinon Pine Location Barstow, CA Plaquemine, LA Buggenum, The Netherlands West Terre Haute, IN Mulberry, FL Puertollano, Spain Reno, NV Electric output (net) 100 MW 160 MW Gasifier type (current owner) GE with heat recovery ConocoPhillips E-gas 253 MW Shell 262 MW 250 MW ConocoPhillips E-gas GE with heat recovery 298 MW Prenflo 99 MW KRW air blown fluidized bed Gas turbine Dates of operation GE 7E Siemens SGT6-3000E Siemens SGT5-2000E GE 7FA GE 7 FA Siemens SGT5-4000F GE 6FA present present present present (18 start-up attempts, failed to achieve steady state operation) 10

11 Availability of IGCC demos 90.0% 80.0% 70.0% 60.0% 50.0% 40.0% 30.0% Nuon Availability Wabash Availability TECO Availability Elcogas Availability Cool Water Availability LGTI Syngas Availability 20.0% 10.0% 0.0% 1st year 2nd year 3rd year 4th year 5th year 6th year 7th year 8th year 9th year 10th year 11th year 11

12 Increasing commercial interest in IGCC Several alliances formed in 2004 aiming to provide IGCC customers one stop shopping (buy the package instead of the pieces..) GE & Bechtel. GE purchased the Texaco gasifier from ChevronTexaco ConocoPhillips & Fluor Shell, Uhde and Black & Veatch Main challenges are to demonstrate competitiveness towards pulverized coal (PC) plants in the market Capital cost Availability 12

13 IGCC with CO 2 capture Quench water Heat Particulate removal ~300 C Water quench or heat recov. Shift CO+H 2 O =CO 2 +H 2 ~40 C Sulfur removal Steam H 2 S New blocks added for CO 2 capture Depending on process configuration Hot raw syngas ~1500 C ~40 C Coal feed Gasifier CO 2 capture CO 2 Steam turbine O 2 H 2 rich fuel Hot steam Feed water N 2 ASU Air Air (15 atm) Gas turbine Air Exhaust ~600 C HRSG Steam extraction to shift reaction Flue gas ~120 C 13

14 Sequence of gas clean up, shift and capture: Syngas from gasifier Candle filters ( C) Water scrubber Shift (if capture, 500 C & 200 C) Water gas shift reaction: CO + H 2 O => H 2 + CO 2 Simultaneous hydrolysis Exothermic, heat is released => chemical energy lost Demands steam from steam cycle => electricity lost Hydrolysis (if no capture, 180 C) COS + H 2 O => H 2 S + CO 2 Needed because sulfur removal is more effective for H 2 S Negligible impact on energy balance (due to ppm level) Sulfur removal Acid gas removal (AGR), 40 C: MDEA, Selexol Sulfur recovery unit (SRU): Claus plant, production of solid sulfur Tail gas treatment (TGT): E.g. SCOT, treatment of exit stream from SRU CO 2 capture, 40 C: MDEA, Selexol Shift (sour) Candle filter Scrubber Sulfur removal CO 2 capture Syngas to gas turbine Hydrolysis 14

15 Sulfur removal configurations NETL/MIT simulation: Air blown SRU Absorption process in TGT Recycle of concentrated H 2 S to SRU Higman, 2003 (Gasification text book), also IEA, 2003: Oxygen blown SRU No absorption process in TGT, only conversion of sulfur compounds to H 2 S Recycle of dilute H 2 S to AGR Elimination of emission stream from TGT Raw syngas AGR Clean syngas Raw syngas AGR Clean syngas H 2 S H 2 S Air SRU Solid sulfur Oxygen/Air SRU (Single stage Claus ) Solid sulfur Tail gas Tail gas Recycle of H 2 S TGT To incinerator Recycle of tail gas with H 2 S Hydrogenation/ Quench AGR Acid gas removal, SRU Sulfur recovery unit, TGT Tail gas treatment 15

16 Gas turbines & syngas/h 2 The new 9H turbine (50Hz) ready for testing in Baglan bay, UK. CC output: 480 MW Eff. 60 % LHV Source: GE Major large gas turbines in the 60 Hz market General Electric: 7FA*, 7FB, (7H) Siemens**: SGT6-5000F (W501F), SGT6-6000G (W501G) Mitsubishi: 501F, 501G Electric output per gas turbine 200 MW (+/-) Letters E,F,G,H in the order of higher efficiency * Used in Tampa and Wabash IGCC demonstrations, ** Siemens has in 2004 implemented a unified nomenclature 16

17 Increased turbine mass flow Fuel Gas turbine = compressor + combustor + turbine Compressor air Hot exhaust Because the heating value of syngas is lower, a higher mass flow rate of fuel is added to the turbine Potential increase in power (GE 7FA: From 172 to 192 MW, +12 %) Two ways to get more mass flow through the turbine: Decreased firing temperature (reduces CC efficiency) Higher pressure ratio (preferred) Higher pressure ratio requires sufficient compressor surge margin Alternatively (if no margin), bleed air from compressor outlet to ASU Gas turbine torque limit can be limiting 17

18 Integration of ASU and GT Fuel Nitrogen from ASU Air bleed to ASU Hot exhaust Compressor air Degree of integration Percentage of air needed in ASU which is bled from the GT compressor outlet A range from 0 % to 100 % is possible No integration (0 %): availability (+), efficiency (-) Full integration (100 %): availability (-), efficiency (+) Optimal trade-off*: 25 % - 35 % * Neville Holt, Turbomachinery International, May/June

19 IGCC turbines Modern gas turbines use combustors where fuel and air is premixed to reduce flame temperatures and therefore NO x formation (dry low NO x burners) Turbines in IGCC plants: Diffusion burners instead of DLN (avoiding the danger of flashback) Dilution with nitrogen and/or steam necessary, nitrogen preferred 19

20 Reduced GT firing temperature Increased % of H 2 O in the exhaust Leads to higher heat transfer Reduction of firing temperature (TIT) necessary to maintain material lifetime In order of increasing trouble: Natural gas Syngas from IGCC H 2 rich syngas from IGCC with CO 2 capture For same reason, N 2 dilution preferred over steam injection Compressor air ~15 C ~400 C Fuel ~1300 C Hot exhaust ~600 C What determines the gas turbine firing temperature / turbine inlet temperature (TIT)? Ans: The fuel supply in MW or btu/hour Graphics source: GE 20

21 Steam cycles Purpose: Utilize gas turbine exhaust and other heat sources to produce electricity Consists of HRSG (next slide) + steam turbine State-of-the-art cycle for CC 3 pressure level steam generation with reheat Steam parameters The three subcritical pressure levels (optimized in each case?) Superheat: Typical 540 C (Maximum 565 C) Reheat: Typical 540 C 21

22 HRSG = A big heat exchanger Cold stack gas, C Heat recovery steam generator Produces steam from the hot gas turbine exhaust Hot exhaust from gas turbine, 600 C 22

23 HRSG Construction of 100 MW CC plant by Kinder Morgan, Midland, Texas, 2004 (My photo). Left: HRSG Right: Inlet air filter above GE LM6000 gas turbine Evaporators (boilers): production of steam Economizers: Increasing the temperature of liquid water Superheaters: Increasing the temperature of steam (water vapor) May be integrated with IGCC syngas coolers. Steam is superheated in HRSG. Suppliers: Vogt-NEM, Nooter-Eriksen, Foster Wheeler, Aalborg Industries, and Deltak Source: GE 23

24 Air separation units (ASUs) Cryogenic air separation: A process in which air is separated into component gases by distillation at low temperatures Lowest cost alternative for large scale applications Single train production capacity (O 2 ): 3200 t/d Recognized for high reliability For IGCC, probably O 2 storage only for a few hours operation Major suppliers Air Products Air Liquide BOC Gases Praxair Linde Source: Air Products t/d 24

25 IGCC efficiency While natural gas based CCs have efficiencies (LHV) close to 60 %, coal based IGCCs have lower efficiencies (below 45 % for the same technology level) Main reason is the gasification step where part of the chemical energy in the coal (about 20-30%) is converted to heat This heat is less efficiently converted to electricity than the chemical energy in the produced syngas Another factor is the work required for air separation IGCCs have no clear efficiency benefit compared to supercritical pulverized coal plants 25

26 IGCC improvement potential Advances in several areas can potentially improve the performance of future IGCC plants Gasifiers Dry feed gasifier with two stages Refractory and feed injector lifetime Coal feed and slag removal systems Air separation Oxygen separating membranes (ionic transport membranes) Gas turbines Higher firing temperatures Novel cycles including high temperature fuel cells 26

27 According to a study*, a year 2020 IGCC plant could be 49 % (LHV) efficient without capture and 43 % efficient with capture Without CO 2 capture With CO 2 capture GE Shell 2020 plant GE Shell 2020 plant Efficiency (%,LHV) Capital cost ($/kw) For the year 2020 plant, the study* assumed Bituminous coal A two-stage dry feed gasifier A gas turbine more advanced than H-class Supercritical steam cycle Membrane air separation * IEA GHG report PH4/19, 2003 (by Foster Wheeler) 27

28 IGCC issues Effect of coal quality Most studies on bituminous coal (high rank) Degree of integration (% of ASU air from GT) US demos: 0 % European demos 100 % Future plants: % (probably) Gas clean up (sulfur and CO 2 ) 2-stage Selexol, physical absorption seems to be preferred Co-capture of sulfur and CO 2 acceptable? Gas turbines on hydrogen rich fuels 28

29 IGCC Concluding remarks Several IGCC plants have been demonstrated, all with government support, private companies are now working to commercialize the technology IGCC challenges Demonstrate competitive capital cost and availability IGCC benefits (over pulverized coal plants) Lower environmental impact, probably easier permitting Lower cost option if CO 2 capture (greenfield & retrofit) Capture of CO 2 introduces some minor technical challenges related to gas turbines on hydrogen rich fuels For low rank coals such as lignite, less information on IGCC performance is available 29

30 Thank you! 30