Pilot Scale Production of Mixed Alcohols from Wood. Supplementary Information

Transcription

1 Pilot Scale Production of Mixed Alcohols from Wood Supplementary Information Richard L. Bain, Kimberly A. Magrini-Bair, Jesse E. Hensley *, Whitney S. Jablonski, Kristin M. Smith, Katherine R. Gaston, Matthew M. Yung National Bioenergy Center, National Renewable Energy Laboratory, Denver West Parkway, Golden, Colorado, * To whom correspondence should be addressed, jesse.hensley@nrel.gov

2 This section provides details and data as called by the main text. Composition of Biomass Feed Table SI-1. Proximate and ultimate analyses of biomass feedstock. Feed particle size (µm) Moisture (wt%) 3.95 Proximate Analysis (wt% dry) Volatile matter Fixed carbon 10.9 Ash 0.37 Ultimate Analysis (wt% dry) Carbon Hydrogen 6.25 Nitrogen 0.06 Oxygen (by difference) Sulfur 0.05 HHV (MJ/kg) 18.68

3 Gasifier/Reformer Net Inputs and Outputs Figure SI-1 shows rates of solids and gases delivered to the fluidized bed gasifier. Steam and oak feeds were constant at 13.4 and 7.5 kg-h -1, respectively, leading to a consistent steam to biomass ratio of 1.79:1. The oak feed rate did fluctuate slightly when reloading the feed hopper but returned to steady values quickly. CO 2 flows into the gasifier and downstream purges remained constant at 4 and 2.8 kg-h -1, respectively Steam Amount, kg/h 10 Wood 5 Carbon Dioxide Carbon Dioxide Purge Time (hours) Figure SI-1. Gasifier feed inputs as a function of time on stream. Figure SI-2 presents the variation in primary gas components (H 2, CO, CO 2, and CH 4 ) during the test. Methane, carbon monoxide, and carbon dioxide concentrations (inclusive of nitrogen) averaged 39, 13, 33, and 0.8 mole %, respectively, over the 150 h duration. Component Volume % Hydrogen Carbon Dioxide Carbon Monoxide Methane Time (hours) Figure SI-2. Major gas components in reformer effluent as a function of time on stream.

4 Methanol Decomposition to Generate Syngas A schematic of the methanol decomposition reactor system is shown in Figure SI-3. A 10.2 cm ID Inconel reactor (C) was loaded with 5 kg of Sud-Chemie MegaMax 700 tablets (6 mm x 4 mm). MegaMax 700 is used industrially to synthesize methanol from syngas, and contains CuO (55 70 wt%), ZnO (20 35 wt%), and Al 2 O 3 (1 15 wt%) with a trace amount of graphite (< 5 wt%). Liquid methanol containing 2 wt% H 2 O (to slow the rate of coke deposition) was introduced through a superheater coil at a flow rate of 30 g-min -1 (B) and vaporized at 320 C. Argon (0.6 SLPM) was added as an internal standard for gas analysis. Syngas was produced over the reduced MegaMax catalyst at 280 C (reduced at a space velocity of 1.2 x 10 3 h -1 with 5.5% H 2 (vol/vol) in N 2 for 40 h at 290 C). Gas and vapor products exited the reactor through the heated outlet section (D), unreacted methanol and water were condensed and collected in the scrubber system (E), and product gas was cooled to room temperature (F) and sent to the blower described above. Non-dispersive infrared (NDIR) and gas chromatography (GC) were used to quantify gas concentrations. The water-gas shift reaction is active on this catalyst and therefore, CO 2 was produced in addition to H 2 and CO: Figure SI-3. Schematic of methanol decomposition reactor. The methanol feed described above produced SLPM syngas consistently for more than 100 h. Steady state compositions of CO and H 2 from methanol decomposition are shown on the left in Figure SI-4. The average H 2 and CO concentrations were 63.8% (vol/vol) and 24.5%. The H 2 :CO ratio was 2.6, which is higher than the stoichiometric decomposition of methanol, and 6.2% CO 2 was produced, confirming the activity of the water gas shift reaction. Methane was also produced at 5.2%. Methane and CO 2 concentrations varied with pressure and temperature as did methanol conversion. Due to thermodynamic limitations, some methanol vapor persisted into the product. Methanol conversion decreased from 96% after approximately 41 min on stream to 68% after h on

5 stream despite steady increases in operating temperature (shown below), which suggests that the MegaMax catalyst deactivates non-negligibly under these operating conditions. Figure SI-4. Products of CH 3 OH decomposition as a function of time on stream. The catalyst temperature, product gas flow rate, and pressure drop across the catalyst bed are shown in Figure SI-5. Changes in pressure drop across the bed reflect increased coking of the catalyst, which inhibits catalyst activity and decreases carbon efficiency. In the first 20 hours of operation, the pressure drop in the catalyst bed increased from 0 kpa to 12 kpa after which a steady state was achieved. The temperature in the bed was strongly affected by the endothermic decomposition reaction, and increased as the catalyst lost activity over time. Figure SI-5. Process conditions during methanol decomposition. Methanol decomposition does not appear to be an ideal reaction to produce syngas for long periods because it produces significant amounts of coke thereby reducing catalyst life and carbon efficiency. Operated in the forward direction, to produce methanol from syngas, the reaction across the catalyst is highly pressure dependent. As a result, when run in the reverse direction, the reaction was significantly hindered by coke build-up over time because of a steady increase in pressure across the bed. Additionally, the reactor used to perform this work is not ideal for a packed bed, because heat was transferred exclusively from the wall to the catalyst, because reactor diameter was large relative to catalyst particle size (10.2 cm reactor and 0.5 cm catalyst pellets), and because the reaction was highly endothermic, leading to large radial temperature gradients. Axial temperature gradients were also observed.

6 If catalyst activation requires syngas of a higher purity than provided by the gasification process, and if the purchase of large quantities of bottled H 2 and CO is untenable due to safety concerns or institutional policies, and/or if the temporary production of syngas via steam methane reforming is economically unfeasible, the production of syngas via reverse methanol synthesis can offer a short-term alternative for clean syngas generation. Acid Gas Removal Gas compression and acid gas removal systems are shown schematically in Figure SI-6. Syngas was compressed for acid gas treatment with a two-stage diaphragm compressor (PDC Machines, Inc., Model 4-300/1750). Because the syngas flow to the compressor was typically less than the minimum suction flow for the unit, a forward pressure regulator was added between the compressor discharge and inlet to allow recycle of compressed gas to maintain the compressor inlet at positive pressure. Figure SI-6. Gas compression and acid gas removal systems. Compressed syngas was fed to a small pressure swing adsorption (PSA) unit for acid gas removal. Two sets of pressure vessels with internal volumes of 16 L per set were filled with activated carbon extrudates (Norit RB 30M, lot # SKC/08/44). This carbon has a high affinity for CO 2 (especially at pressures > 700 kpa) and little to no affinity for other syngas components (H 2, CO, N 2, CH 4 ). During operation, one set of pressure vessels was online at an operating pressure of 5 MPa, whereby CO 2 from the fresh syngas was adsorbed onto the carbon extrudates and CO 2 - depleted syngas exited the vessels to downstream second-stage compression. Concurrently, the other set of pressure vessels was depressurized to 83 kpa (local atmospheric pressure) into the waste gas header. As the pressure was lowered, CO 2 desorbed from the carbon, regenerating the bed. Thus, CO 2 removal was achieved by differences in the carbon adsorption capacities at high and low pressures. No heating or vacuum systems were employed. Following acid gas removal, syngas was compressed to 20 MPa with pneumatic gas boosters (Haskel model AGD-30) and stored in carbon steel gas accumulators (internal volume 125 L) to ensure smooth and uninterrupted

7 operation of the mixed alcohol reactor. Prior to entering the reactor system, syngas was routed through a 1 L activated carbon bed (Norit RB 30M, lot # SKC/08/44) to remove iron carbonyls. A slipstream of PSA effluent was reduced in pressure to 2 MPa and fed to a separate two-stage compression system. Gas flow was controlled at 3.5 SLPM into a series of pneumatic gas boosters (Haskel models AG30 and AGD30) to increase the pressure to 14 MPa. Back pressure was controlled using a manual backpressure regulator (Tescom). Gases were metered into a bench scale reactor system (described in manuscript) and excess gas flowed through the backpressure regulator to a waste gas header. The PSA system provided CO 2 removal from the syngas, and its performance varied with syngas composition. For example, dry syngas at 6 mole% CO 2 was reduced to 3.5% CO 2 averaged across the adsorption cycle. At the opposite extreme, moist syngas (1-2 mole% water) at 32 mole% CO 2 was only reduced to 28% CO 2. In general, the PSA was less effective in removing CO 2 at high concentrations and when moisture was carried into the unit, due in both cases to rapid saturation of the carbon sorbent. Figure SI-7 shows representative data for CO 2 concentration in the PSA effluent, and illustrates the steady and cyclic nature of CO 2 removal using this method. 6 5 CO 2 in PSA Effluent (%) Time on Stream (min) Figure SI-7. CO 2 concentrations in PSA effluent during steady-state operation. Syngas was derived from methanol and contained an average of 6% (mole/mole) CO 2. PSA was an effective tool for CO 2 removal, but only when the incoming gas was low in CO 2 concentration (below 10%). Alternately, the PSA was under-sized for the application; however, given the pressure required to adsorb the CO 2 on carbon, it is unlikely that a high pressure PSA of this design would be efficient (significant quantities of gas would be exhausted to the waste header regardless of bed volume). At higher concentrations, the time required to regenerate (depressurize) a sorbent bed approached the time to saturation of the online bed, significantly reducing the amount of gas available for conversion and necessitating the use of syngas with high CO 2 content. Given the high H 2 :CO ratio of the incoming gas, however, this was not necessarily problematic. Metal sulfide catalysts have a high water gas shift activity, and therefore, excess CO 2 coupled with excess H 2 will result in reverse shift to CO, which theoretically provides for better carbon utilization in an integrated process.