Paolo Chiesa. Politecnico di Milano. Tom Kreutz*, Bob Williams. Princeton University

Transcription

1 Analysis of Hydrogen and Co-Product Electricity Production from Coal with Near Zero Pollutant and CO 2 Emissions using an Inorganic Hydrogen Separation Membrane Reactor Paolo Chiesa Politecnico di Milano Tom Kreutz*, Bob Williams Princeton University Presented at the Second Annual Conference on Carbon Sequestration May 5-8, 2003, Alexandria, VA * presenter 1

2 Large Scale Production of H 2 from Fossil Fuels - Four Related Papers Presented Here - Natural Gas Coal & Residuals CO 2 Venting CO 2 Capture Almost all H 2 produced today 1) FTR vs. ATR with CC Refineries, chemicals, NH 3 production in China 2) Conventional technology 2) Conventional technology 3) Membrane reactors 4) Overview 2

3 H 2 from Coal: Motivation Distributed energy use (transportation and heating) responsible for ~2/3 of global CO 2 emissions CO 2 capture, compression, dehydration, and pipeline transport from distributed sources is very expensive. Low carbon energy carriers are needed: electricity...and hydrogen? If CO 2 sequestration is viable, fossil fuel decarbonization likely to be the cheapest route to electricity and hydrogen for many decades. Coal is of great interest because it is: Plentiful. Resource ~ 500 years (vs. gas/oil: ~100 years). Inexpensive $/GJ HHV (vs. gas at 2.5+ $/GJ). Ubiquitous. Wide geographic distribution (vs. middle east). Clean?! Gasification, esp. with sequestration, produces little gaseous emissions and a chemically stable, vitreous ash. Example: China: extensive coal resources; little oil and gas. Potential for huge emissions of both criteria pollutants and greenhouse gases. 3

4 Generic Process: Coal to H 2, Electricity, and CO 2 Quench + scrubber Water-gas shift (WGS) reactors CO + H 2 O <=> H 2 + CO 2 H 2 - and CO 2 -rich syngas Syngas cleanup, gas separation CO 2 CO-rich raw syngas H 2 -rich syngas CO2 drying and compression Coal slurry O 2 -blown coal gasifier Heat recovery, steam generation Supercritical CO 2 (150 bar) 95% O 2 separation unit Electricity production Electric power Hydrogen compression H 2 product (60 bar) N 2 GHGT-6 generic process figure ( ) All work presented here is based on O 2 -blown, entrained flow, coal gasification, primarily Texaco quench (some E-Gas). 4

5 Process Modeling Heat and mass balances (around each system component) calculated using: Aspen Plus (commercial software), and GS ( Gas-Steam, Politecnico di Milano) Membrane reactor performance calculated via custom Fortran codes Component capital cost estimates taken from the literature, esp. Holt, et al. and EPRI reports on IGCC Benchmarking/calibration: Economics of IGCC with carbon capture studied by numerous groups Used as a point of reference for performance and economics of our system Many capital-intensive components are common between IGCC electricity and H 2 production systems (both conventional and membrane-based) 5

6 Disaggregated Cost of H 2 Production Capital Charge Rate=15% 7 CO2 Sequestration (5 $/mt CO2) Hydrogen Cost ($/GJ, HHV) Net cost: 6.6 $/GJ CO2 drying & compression Raffinate turbine H2 compressor Membrane reactor H.T. WGS reactor Gasifier and quench O2 separation & compression Coal preparation & handling Construction Interest (4 yr) O&M (4% per year) Coal (1.18 $/GJ, HHV) Electricity credit (5.54 /kwh) Fig. D3 70 bar gasifier, 83.2% HRF, uncooled raffinate turbine, scale: 1 GW th H 2 (HHV) 6

7 Economic Assumptions Coal price (2000 average cost to electric generators) Capacity factor Capital charge rate Interest during construction O&M costs CO 2 storage cost * U.S. dollars valued in year Plant scale Coal Type 1.18 $/GJ (HHV) 80% 15% per yr 16.0% of overnight capital 4% of overnight capital per year 5 $/mt CO 2 (~0.7 $/GJ H 2 HHV) GW th H 2 Illinois #6 Best case cost estimate for: 16,000 tonne/day CO 2, 100 km pipeline, 2 km deep injection well (layer thickness > 50 m, permeability > 40 mda) 7

8 Benchmark: IGCC Electricity with CO 2 Capture CO-rich raw syngas High temp. WGS reactor Quench + scrubber CO 2 -lean exhaust gases Low temp. WGS reactor Saturated steam H 2 - and CO 2 -rich syngas Regeneration, Claus, SCOT Lean/rich solvent H 2 S physical absorption Solvent regeneration Lean/rich solvent CO 2 physical absorption H 2 -rich syngas CO 2 drying + compression Supercritical CO 2 to storage Coal slurry O 2 -blown coal gasifier Heat recovery steam generator Syngas expander 95% O 2 Steam turbine Turbine exhaust separation unit N 2 for (NO x control) Gas turbine GHGT-6 conv. electricity, CO2 seq. ( ) Cost: 6.4 /kwh, efficiency: 34.9% (HHV). (70 bar gasifier, scale: 362 MW e ) 8

9 H 2 Production: Add H 2 Purification/Separation CO-rich raw syngas High temp. WGS reactor Quench + scrubber CO 2 -lean exhaust gases Low temp. WGS reactor Saturated steam H 2 - and CO 2 -rich syngas Regeneration, Claus, SCOT Lean/rich solvent H 2 S physical absorption Solvent regeneration Lean/rich solvent CO 2 physical absorption H 2 -rich syngas CO 2 drying + compression Supercritical CO 2 to storage Coal slurry O 2 -blown coal gasifier Heat recovery steam generator Syngas expander 95% O 2 Steam turbine Turbine exhaust separation unit N 2 for (NO x control) Gas turbine GHGT-6 conv. electricity, CO2 seq. ( a) Replace syngas expander with PSA and purge gas compressor. 9

10 Conventional H 2 Production with CO 2 Capture CO-rich raw syngas Coal slurry High temp. WGS reactor Quench + scrubber O 2 -blown coal gasifier CO 2 -lean exhaust gases Low temp. WGS reactor Saturated steam Heat recovery steam generator H 2 - and CO 2 -rich syngas Regeneration, Claus, SCOT Lean/rich solvent H 2 S physical absorption Solvent regeneration Lean/rich solvent CO 2 physical absorption Pressure swing adsorption Purge gas CO 2 drying + compression High purity H 2 product Supercritical CO 2 to storage 95% O 2 Steam turbine Turbine exhaust separation unit N 2 for (NO x control) Gas turbine GHGT-6 conv. hydrogen, CO2 seq. ( ) H 2 cost: 7.3 $/GJ (HHV). (85% HRF, scale: 1 GW th H /kwh) 10

11 Change H 2 -CO 2 Gas Separation Scheme Solvent regeneration Quench + scrubber High temp. WGS reactor Low temp. WGS reactor H 2 - and CO 2 -rich syngas Lean/rich solvent CO 2 /H 2 S physical absorption CO 2 /H 2 S drying and compression CO 2 + H 2 S to storage CO-rich raw syngas Coal slurry O 2 -blown coal gasifier CO 2 -lean exhaust gases Saturated steam Heat recovery steam generator Pressure swing adsorption Purge gas High purity H 2 product 95% O 2 separation unit N 2 for (NO x control) Steam turbine Gas turbine GHGT-6 conv. hydrogen, co-seq. ( b) This work uses a membrane to separate H 2 from the syngas instead of CO 2. 11

12 H 2 Separation Membrane Reactor System Pure H 2 Quench + scrubber H 2 - and CO 2 -rich High temp. syngas WGS reactor Membrane WGS reactor Hydrogen compressor CO-rich raw syngas Raffinate High purity H 2 product Coal slurry O 2 -blown coal gasifier Catalytic combustor Uncooled turbine CO 2 /SO 2 drying and compression 95% O 2 CO 2 + SO 2 to storage separation unit O 2 (95% pure) Water N 2 GHGT-6 uncooled turbine, co-seq. ( ) Employ a H 2 permeable, thin film (10 µm), 60/40% Pd/Cu (sulfur tolerant) dense metallic membrane, configured as a WGS membrane reactor. 12

13 Membrane System with Cooled Raffinate Turbine Pure H 2 Quench + scrubber H 2 - and CO 2 -rich High temp. syngas WGS reactor Membrane WGS reactor Hydrogen compressor CO-rich raw syngas Coal slurry O 2 -blown coal gasifier Uncooled expander Raffinate Catalytic combustor Steam (for blade cooling) High purity H 2 product 95% O 2 Cooled turbine CO 2 /SO 2 drying and compression separation unit O 2 (95% pure) CO 2 + SO 2 to storage N 2 GHGT-6 cooled turbine, co-seq. ( ) Steam (for blade cooling) Water Blade cooling with steam enables higher TIT (1250 C vs. 850 C), and higher electrical conversion efficiency. Requires much lower HRF (~60%). 13

14 Hydrogen Separation Membrane Reactor (HSMR) Concept Shell-tube membrane module Exiting raffinate Entering high pressure syngas Catalyst pellets Thin film membrane Low pressure hydrogen permeate High pressure syngas Permeating hydrogen Low pressure hydrogen permeate Porous substrate Membrane Structure: Thin film membrane Optional oxide layer (needed for metallic membrane with SS substrate) Porous (optionally asymmetric) ceramic or stainless steel (SS) supporting substrate Membrane Reactor Alternative HSMR design: high pressure, WGS reaction, and membrane outside supporting tube, with H 2 permeating to the interior of the tube 14

15 Typical Membrane Reactor Performance 25 a) b) 70 H 2 Partial Pressure (bar) H2 Recovery Factor (%) Average H 2 Flux (kw/m 2 ) µm thick Pd-40Cu membrane 475 C; 1000 ppm H 2 S; 67 bar syngas Membrane Material Cost ($/kw) Membrane Area (10 3 m 2 ) Tube length H 2 Recovery Factor (%) H 2 Recovery Factor (HRF) = H 2 recovered / (H 2 +CO) in syngas HRF increases with membrane area diminishing returns Membrane costs rise sharply above HRF~80-90% (no sweep gas) 15

16 Cost of H 2 Compression and HSMR vs. H 2 Backpressure 2.0 Sum Cost ($/GJ H2, HHV) Number of compressor stages: Cost Minimum 4 3 Membrane capital Compressor power Compressor capital H 2 Backpressure (bar) Fig. G4b Broad cost minimum seen here (not always) at low H 2 backpressure 16

17 System Parameter Variations System Performance: - membrane reactor configuration - membrane reactor operating temperature - gasifier/system pressure - hydrogen backpressure - hydrogen recovery factor (HRF) - raffinate turbine technology (blade cooling vs. uncooled) System Economics: - membrane reactor cost (and type) - co-product electricity value - sulfur capture vs. sulfur + CO 2 co-sequestration 17

18 Effect of HSMR Configuration Avg. H2 Flux (kw/m 2, HHV) HT-WGS+HSMR HT-WGS+HSM HSMR Cost ($/kw HHV) HSMR H 2 Recovery Factor (%) In this system, with an upstream WGS reactor, a membrane reactor not obviously necessary for good system performance. 18

19 Modeling Results: Parametric Variations Description of system and/or change from one system to the next (in sequence). (Scale=1 GW th HHV coal input) Hydrogen Recovery Factor (%) Effective system efficiency (%, HHV)* CO 2 -free H 2 Cost ($/GJ /kwh Conventional technology A Uncooled turbine, 70 bar, FGD B A without FGD (co-storage) C B with 120 bar gasifier D C with sub-atmospheric (0.2 bar) turbine exhaust pressure E C with cooled raffinate turbine (TIT=1050 C) F E with TIT=1250 C * Effective system efficiency = HHV H 2 output / HHV (coal input coal saved**) ** Coal saved based on IGCC with CO2 capture, 34.9% HHV efficiency 19

20 Modeling Results: Parametric Variations /kwh 30 H2 Cost ($/GJ, HHV) /kwh Power / H 2 Ratio (%, HHV) "CT" 70 A bar Minus B 120 C Sub- D Cooled E F uncooled FGD bar Atm C Conven. Tech. Cooled 1250 C 0 H 2 costs via membranes comparable to costs via conventional technology Power / H 2 ratio and electricity price are key to H 2 costs 20

21 Oak Ridge Molecular Sieving Membrane -H 2 Permeance Relative to 60/40 Pd/Cu H2 Permeance Ratio Hydrogen backpressure (bar): Upstream Pressure (bar) Membrane permeance pressure dependence: - ceramic: (P high P low ) vs. metallic: ( P high P low ) Permeance increase up to factor of ~50 possible. Reduced purity. 21

22 Metallic vs. Ceramic Membrane reactors 8.0 Pd-Cu membrane H2 Cost ($/GJ, HHV) Ceramic molecular sieving membrane 3 /kwh 6.4 /kwh 3.0 Conven. "CT" 70 Abar Minus B 120 C Sub- D Cooled E Cooled F Tech. uncooled FGD bar Atm C 1250 C The increased permeance of ceramic membranes allows for potentially lower H 2 costs. (Same membrane unit price assumed, $3,021/m 2.) 22

23 Optimistic* Results Summary CO2 venting Pure CO2 sequestration Co-sequestration 8 7 H2 Cost ($/GJ HHV) est. est. est. est. 1 0 Conv. tech. Membrane Ceramic base case base case membrane Includes $5/t CO 2 = ~0.7 $/GJ HHV sequestration cost * Assumes electricity = 6.4 c/kwh Cooled raf. turbine Ceramic, cooled 23

24 Observations In quench gasifiers, equilibrium shifting does not appear to be very important (membrane reactor vs. membrane permeator). With efficient raffinate turbine and costly membrane reactor, high CO H 2 conversion efficiency may not be a design goal. High HRF yields high system efficiency and low H 2 costs that are relatively insensitive to the electricity prices; very high HRF typically is not required. Raising the gasifier pressure from 70 to 120 bar raises system efficiency and has the potential to lower the cost of H 2. Sub-atmospheric raffinate turbine exhaust pressure might improve efficiency; effect on costs is uncertain. Raffinate turbine blade cooling yields low HRF, i.e. increased power production, and more complex economic analyses. 24

25 Further Observations, Future Plans SO 2 -CO 2 co-sequestration raises the system efficiency, may lower the cost of H 2, and may provide environmental benefits (Hg, etc.). Good system design can yield H 2 costs that are relatively insensitive to HSMR cost and H 2 recovery. Relative to conventional technology membrane reactors might lower the cost of H 2 by ~10% (Pd-Cu) to ~20% (ceramic). Gas separation is not a large fraction of capital cost. Co-product electricity cost is very important to system design; entwined with H 2 recovery; co-product analysis is complex We plan to examine: 1) low steam-to-carbon ratio + syngas cooling, 2) alternative membrane types, configurations, and temperatures. 25