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, 15013 Denver West Parkway, Golden, Colorado, 80401

* To whom correspondence should be addressed, jesse.hensley@nrel.gov

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) 425 - 2000

Moisture (wt%) 3.95

Proximate Analysis (wt% dry)

Volatile matter 84.79

Fixed carbon 10.9

Ash 0.37

Ultimate Analysis (wt% dry)

Carbon 48.10

Hydrogen 6.25

Nitrogen 0.06

Oxygen (by difference) 45.69

Sulfur 0.05

HHV (MJ/kg) 18.68

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. CO2 flows into the

gasifier and downstream purges remained constant at 4 and 2.8 kg-h-1

, respectively.

Time (hours)

0 25 50 75 100 125 150

Am

ou

nt,

kg

/h

0

5

10

15

20

Steam

Wood

Carbon Dioxide

Carbon Dioxide Purge

Figure SI-1. Gasifier feed inputs as a function of time on stream.

Figure SI-2 presents the variation in primary gas components (H2, CO, CO2, and CH4) 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.

Time (hours)

0 25 50 75 100 125 150

Co

mp

on

en

t V

olu

me %

0

10

20

30

40

50

Hydrogen

Carbon Dioxide

Carbon Monoxide

Methane

Figure SI-2. Major gas components in reformer effluent as a function of time on stream.

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 Al2O3 (1

– 15 wt%) with a trace amount of graphite (< 5 wt%). Liquid methanol containing 2 wt% H2O (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 103 h

-1 with 5.5% H2 (vol/vol) in N2 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, CO2 was produced

in addition to H2 and CO:

��� � �� ↔��� ���

Figure SI-3. Schematic of methanol decomposition reactor.

The methanol feed described above produced 35-44 SLPM syngas consistently for more than 100 h. Steady

state compositions of CO and H2 from methanol decomposition are shown on the left in Figure SI-4. The average H2

and CO concentrations were 63.8% (vol/vol) and 24.5%. The H2:CO ratio was 2.6, which is higher than the

stoichiometric decomposition of methanol, and 6.2% CO2 was produced, confirming the activity of the water gas

shift reaction. Methane was also produced at 5.2%. Methane and CO2 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 107.8 h on

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 CH3OH 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.

If catalyst activation requires syngas of a higher purity than provided by the gasification process, and if the

purchase of large quantities of bottled H2 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 CO2 (especially at pressures > 700 kPa) and little to no affinity

for other syngas components (H2, CO, N2, CH4). During operation, one set of pressure vessels was online at an

operating pressure of 5 MPa, whereby CO2 from the fresh syngas was adsorbed onto the carbon extrudates and CO2-

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, CO2 desorbed from the carbon, regenerating the bed. Thus, CO2 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

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 CO2 removal from the syngas, and its performance varied with syngas composition.

For example, dry syngas at 6 mole% CO2 was reduced to 3.5% CO2 averaged across the adsorption cycle. At the

opposite extreme, moist syngas (1-2 mole% water) at 32 mole% CO2 was only reduced to 28% CO2. In general, the

PSA was less effective in removing CO2 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 CO2 concentration in

the PSA effluent, and illustrates the steady and cyclic nature of CO2 removal using this method.

Figure SI-7. CO2 concentrations in PSA effluent during steady-state operation. Syngas was derived from methanol and contained

an average of 6% (mole/mole) CO2.

PSA was an effective tool for CO2 removal, but only when the incoming gas was low in CO2 concentration

(below 10%). Alternately, the PSA was under-sized for the application; however, given the pressure required to

adsorb the CO2 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 CO2

content. Given the high H2: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 CO2 coupled with excess H2 will result in

reverse shift to CO, which theoretically provides for better carbon utilization in an integrated process.

0

1

2

3

4

5

6

0 50 100 150 200 250

CO

2in

PS

A E

fflu

ent

(%)

Time on Stream (min)