Weidner_BiomassToMethanol_SeniorDesignProject_Fall2015

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Solar Thermal Conversion of
Biomass to Methanol
Instructor: A. W. Weimer
CHEN 4520
Bernard Britt
Robert McGugan
Sarah Stoeck
Andrew Weidner
Vanessa Witte

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Table of Contents
I. Executive Summary...................................................................................................................... 7
II. Introduction ................................................................................................................................ 8
Project Description and Scope .................................................................................................... 8
Mission Statement................................................................................................................... 8
Process Description ................................................................................................................. 8
III. Background Information.......................................................................................................... 11
Market for Renewable Methanol.............................................................................................. 11
Renewable Methanol from Biomass......................................................................................... 13
Solar-Thermal Processing.......................................................................................................... 14
IV. Environmental, Health & Safety .............................................................................................. 16
Chemical Hazards ...................................................................................................................... 16
Health and Safety Considerations............................................................................................. 20
Operator Safety ..................................................................................................................... 20
Licensure and Permits ........................................................................................................... 22
Environmental Considerations.................................................................................................. 24
Worst-Case Scenarios................................................................................................................ 29
Life Cycle Analysis...................................................................................................................... 32
Goal and Scope Definition ..................................................................................................... 32
Inventory Analysis.................................................................................................................. 34
Impact Assessment and Interpretation................................................................................. 37
V. Project Premises ....................................................................................................................... 38
Design........................................................................................................................................ 38
Biomass Pre-Processing......................................................................................................... 38
Biomass Gasification and Methanol Production ................................................................... 39
Amine Scrubbing.................................................................................................................... 39
Methanol Purification............................................................................................................ 39
Economics.................................................................................................................................. 40
VI. Approach.................................................................................................................................. 42
Hand Calculations...................................................................................................................... 42
Heat of Reactions: Cellulose and Steam................................................................................ 42

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Heat of Reaction: Lignin and Steam ...................................................................................... 43
Waste Biomass Feed Estimation ........................................................................................... 43
Theoretical Energy Requirement for Solar-Thermal Reactor................................................ 45
VII. Process Flow Diagrams with Material & Energy Balances ..................................................... 46
Biomass Pre-Processing............................................................................................................. 46
Process Description and PFD................................................................................................. 46
Material Balances .................................................................................................................. 48
Heat Duty............................................................................................................................... 49
Biomass Gasification ................................................................................................................. 49
Heat Duty............................................................................................................................... 61
Amine Scrubbing ....................................................................................................................... 62
Material Balance.................................................................................................................... 70
Heat Duty............................................................................................................................... 71
Product Separation & Post-Processing ..................................................................................... 71
Material Balances .................................................................................................................. 73
Heat Duty............................................................................................................................... 74
VIII. Process Description & Equipment Specifications.................................................................. 75
Generalized Equipment Design................................................................................................. 75
Pumps .................................................................................................................................... 75
Shell-and-Tube Heat Exchangers........................................................................................... 78
Vapor-Liquid Separators........................................................................................................ 82
Pressure Vessels and Towers................................................................................................. 90
Cyclones................................................................................................................................. 94
Biomass Pre-Processing............................................................................................................. 98
P-1 / SR-101 Shredding.......................................................................................................... 98
P-2 / RDR-101 Rotary Drying ............................................................................................... 100
P-3 / GR-101 Grinding.......................................................................................................... 103
P-4 / HP-101 Hopper............................................................................................................ 105

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Solar Field and Tower.............................................................................................................. 110
Biomass Gasification ............................................................................................................... 112
Solar Reactor........................................................................................................................ 112
Zinc-Oxide Reactor .............................................................................................................. 118
Methanol Reactor................................................................................................................ 119
Spray Quench Tank.............................................................................................................. 122
Heat Exchangers .................................................................................................................. 124
Compressor.......................................................................................................................... 126
Pumps .................................................................................................................................. 128
Vapor-Liquid Separators...................................................................................................... 130
ZN-SPLIT Cyclone ................................................................................................................. 134
Amine Scrubbing ..................................................................................................................... 134
Pressure Vessels, Separators, and Towers .......................................................................... 134
Heat Exchangers .................................................................................................................. 138
Pumps .................................................................................................................................. 143
Product Separation & Post-Processing ................................................................................... 144
Separator V-100................................................................................................................... 144
Distillation Column T-100 .................................................................................................... 145
IX. Utility Summary and Heat Integration................................................................................... 150
Utility Summary....................................................................................................................... 150
Heat Integration ...................................................................................................................... 152
X. Estimation of Capital Investment and Total Product Cost...................................................... 157
Capital Investment .................................................................................................................. 157
Equipment Cost Summary................................................................................................... 157
Operating Costs....................................................................................................................... 172
Metrics of Plant Operation.................................................................................................. 172
Variable Operating Costs..................................................................................................... 172
Fixed Operating Costs.......................................................................................................... 172
XI. Profitability Analysis............................................................................................................... 174
Profitability.............................................................................................................................. 174
Base Case............................................................................................................................. 174

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Modified Base Case: Life Cycle Analysis with Carbon Credit............................................... 179
Sensitivity Analysis .................................................................................................................. 181
XII. Conclusion............................................................................................................................. 188
XIII. References ........................................................................................................................... 189
XIII. Appendix .............................................................................................................................. 196
Appendix I: Engineering Calculations...................................................................................... 196
Appendix I-A: Approach Calculations .................................................................................. 196
Appendix I-B: Material and Energy Balances ...................................................................... 200
Appendix I-C: Split Fraction for AG-CLEAN.......................................................................... 205
Appendix I-D: Adiabatic Temperature Rise for Methanol Reactor ..................................... 206
Appendix II: Design and Costing Spreadsheets....................................................................... 207
Appendix II-A: Solar Field Design......................................................................................... 207
Appendix II-B: Cyclone Design............................................................................................. 208
Appendix II-C: Aspen PLUS Separator Design...................................................................... 209
Appendix II-D: Pump Design................................................................................................ 211
Appendix II-E: Compressor Design ...................................................................................... 213
Appendix II-F: Pre-Processing Design .................................................................................. 214
Appendix II-G: Amine Scrubbing Design.............................................................................. 216
Appendix II-H: Methanol Purification System Design ......................................................... 224
Appendix II-I: Quench Tank Design...................................................................................... 228
Appendix II-J: Heat Exchanger Design ................................................................................. 230
Appendix II-K: Reactor Heat Exchanger Design................................................................... 235
Appendix II-L: Reactor Design.............................................................................................. 236
Appendix II-M: Solar Field Costing....................................................................................... 241
Appendix II-N: Cyclone Costing ........................................................................................... 242
Appendix II-O: Aspen PLUS Separator Costing .................................................................... 243
Appendix II-P: Pump Costing ............................................................................................... 244
Appendix II-Q: Compressor Costing..................................................................................... 247
Appendix II-R: Pre-Processing Costing................................................................................. 248
Appendix II-S: Amine Scrubbing Costing ............................................................................. 250
Appendix II-T: Methanol Purification System Costing......................................................... 252

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Appendix II-U: Quench Tank Costing................................................................................... 253
Appendix II-V: Heat Exchanger Costing ............................................................................... 254
Appendix II-W: Reactor Heat Exchanger Costing ................................................................ 256
Appendix II-X: Reactor Costing............................................................................................ 257
Appendix III: Computer Process Modeling and Simulations................................................... 258
Appendix III-A: Biomass Pre-Processing Simulation............................................................ 258
Appendix III-B: Aspen PLUS Simulation ............................................................................... 259
Appendix III-C: Amine Scrubbing Simulation....................................................................... 260
Appendix III-D: Methanol Purification Simulation .............................................................. 261
Appendix III-E: Heat Integration.......................................................................................... 262
Appendix III-F: Reactor Computer Code.............................................................................. 263
Appendix IV: Economic Analysis Spreadsheets....................................................................... 266
Appendix IV-A: Base Case without Carbon Credit............................................................... 266
Appendix IV-B: Base Case with Carbon Credit..................................................................... 274
Appendix IV-C: Summary of Utilities ................................................................................... 282

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I. Executive Summary
As carbon emissions become a growing cause for global concern, greater pressure has been
placed on industry to develop innovative alternatives to traditional commodity chemical
production. In order to investigate such an alternative, a design report has been written
examining the construction and economic feasibility of a Solar-Thermal Biomass Gasification
facility. This facility will serve as an alternative means of high-purity, industrial scale methanol
production.
The facility modeled here utilizes 204 million pounds of corn stover biomass per year as feed
stock, employs 111 full-time operators, and produces 58,300,000 gal/year of methanol end
product. The plant operates in five distinct subunits. Waste corn stover enters the biomass pre-
processing portion of the facility where it is ground into usable cellulose and lignin. The usable
biomass is then sent to the biomass gasification subsystem, in which a series of three reactors
convert the biomass to methanol. In order to mitigate the environmental impact and utility
costs of the largest reactor, a solar field operating as part of the facility supplies thermal energy
to the solar reactor. An amine scrubbing system purifies the waste gas stream of environmental
toxins, while the final stage of product processing entails the purification of the end product
methanol, resulting in a final product stream with 99.97% purity by weight. The capital cost of
the facility was determined to be $300.5M.
An economic analysis was performed for plant operation in which 12.5% fixed IRR was
stipulated for facility investors. This economic analysis returned a 10.8% ROI, 9.2 year PBP and
$62.462M NPV based on a 30-year expected facility lifespan with a single year construction
period and single year of 50% capacity startup operation. In order to obtain the required 12.5%
IRR, the final product selling price was determined to be $1.69/gal methanol. This price is not
competitive with the current commodity market value of $1.05/gal (Methanex, 2015). Because
of the facility’s inability to ensure investors suitable returns while meeting end-product market
value, it is the recommendation of this design team that the Solar-Thermal Biomass Gasification
facility not be constructed. In the event that a carbon credit is granted to the facility to
incentivize eco-forward industry, a subsidy of $0.21/lb CO2 avoided would be required to
reduce the product selling price to market value and render the project economically viable.

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II. Introduction
Project Description and Scope
Mission Statement
United States methanol consumption is on the rise and is expected to increase 26% by 2020
(The American Oil and Gas Reporter, n.d.). This opens the market for increased demand in
chemicals, transportation, and power generation, as methanol is a key commodity in all three
sectors. The chemical industry uses this versatile compound in hundreds of chemicals including
solvents, plastics, paints, and adhesives. Combustion of fossil fuels, namely petroleum based
products, in the transportation sector is the second largest source of CO2 emissions in the US
and accounts for a third of all greenhouse gas (GHG) emissions to the atmosphere (EPA, n.d.).
Alternative fuel sources that result in significantly less GHG emissions than conventional fuel
has become a necessity as the world’s population and economy continues to increase.
Methanol provides an attractive alternative fuel option to replace petroleum due to a variety of
advantages. Implementing methanol into the transportation fuel industry could help to
significantly reach federal and state carbon reduction goals. In addition, companies are
exploring ways to use methanol as an additional fuel source for power generation to drive
turbines and create electricity.
This design project proposes to develop a renewable methanol production plant in Daggett, CA.
A techno-economic analysis will be performed to ascertain the viability of the plant in terms of
health and safety, equipment design, and return on investment. The plant will utilize waste
biomass as the feedstock and subsequently produce 58.3 million gallons of 99.97% pure
methanol annually. Slight excess of methanol was produced to account for unforeseen major
maintenance issues that could cut into production time. In this manner, the buyer’s supply
would have limited interruptions over the course of the plant’s lifetime, if any at all. The
gasification of the biomass will be operated using a hybrid reactor with energy sources from
concentrated solar power and natural gas, which will lower the plant’s overall GHG emissions.
Process Description
This process is utilizing waste biomass, corn stover, in a thermochemical gasification reaction to
produce methanol. The plant will be located in Daggett, CA and will operate 24 hours a day, for

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a total of 8000 hours per year. The plant can be divided into pre-processing, gasification, and
purification sections. Pre-processing involves drying the corn stover feedstock and grinding into
small particles applicable for gasification. Corn stover is delivered to the plant after harvest and
is initially shredded to reduce the bulk size to no larger than 6mm. The feedstock is sent to a
direct-contact air-dryer to convectively pull moisture from the particles. A hammer mill is then
employed to reduce the particles to micron size. Lastly, a hopper is used to pressurize the feed
to 35 bar to meet the specifications of the solar reactor.
At this point the feedstock is at the correct temperature and pressure for the gasification
reaction. Because biomass reactions are complicated and novel, software such as Aspen PLUS
requires multiple pieces of equipment to model them, though the reaction would take place in
a single vessel. The gasification reactor has concentrated solar power and natural gas as the
energy sources. Concentrated solar power (CSP) is produced by a field of heliostats targeted at
a solar tower with a compound parabolic concentrator. CSP is one of few renewable
technologies able to achieve the high temperatures required in the gasification process
(>1000°C) due to concentrating the thermal energy. Natural gas is fed as a supplement to CSP
to allow 24 hour operation.
In the gasification step, the pre-treated biomass must be reacted in high temperature, low-
oxygen conditions with water and a methane stream. A controlled level of oxygen limits the
combustion reaction formation of carbon dioxide, but provides enough heat for subsequent
gasification reactions. High temperatures yield fewer hydrocarbons such as char, tar, and ash
and increases conversion directly to carbon monoxide and hydrogen (syngas). The addition of
water and methane also serves to reach to the desired 2:1 ratio of H2:CO in the syngas and to
diminish the selectivity of carbon dioxide formation. The chief gasification reactions are shown
in the equations below:
𝐶𝐻 𝑥 𝑂𝑦(𝑏𝑖𝑜𝑚𝑎𝑠𝑠) + 𝐻2 𝑂 + 𝐶𝐻4
→ [𝐶𝑂 + 𝐻2 (𝑠𝑦𝑛𝑔𝑎𝑠)] + 𝐶𝑂2 + 𝐻2 𝑂 + 𝐶(𝑐ℎ𝑎𝑟)
(1)
𝐶𝐻4 + 𝐻2 𝑂 → 𝐶𝑂 + 3𝐻2 𝑂 (2)
2𝐶 + 𝑂2 → 2𝐶𝑂 (3)

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𝐶 + 𝑂2 → 𝐶𝑂2 (4)
𝐶 + 2𝐻2 → 𝐶𝐻4 (5)
𝐶𝑂 + 𝐻2 𝑂 → 𝐶𝑂2 + 𝐻2 (6)
𝐶 + 𝐻2 𝑂 → 𝐶𝑂 + 𝐻2 (7)
𝐶 + 𝐶𝑂2 → 2𝐶𝑂 (8)
The gasification process produces dirty, contaminated gas streams that undergo various
separation processes to clean the gas and remove particulates, such as ash solids, acid-gas,
sulfur, and chlorine. The resulting vapor stream is sent to the methanol processing reactor.
Maximum production of methanol follows from a high concentration of CO, a low
concentration of CO2, and an optimal ratio of H2:CO:H2O in the feed stream, values that are
dependent on specific reactor conditions. Equations (9), (10) and (11) below summarize the
simultaneous methanol synthesis reactions:
𝐶𝑂2 + 𝐻2 → 𝐶𝑂 + 𝐻2 𝑂 (9)
𝐶𝑂 + 2𝐻2 → 𝐶𝐻3 𝑂𝐻 (10)
𝐶𝑂2 + 3𝐻2 → 𝐶𝐻3 𝑂𝐻 + 𝐻2 𝑂 (11)
The output stream from the methanol reactor is split into a recycle stream back to the solar
reactor, a purge stream that is flared, and a product stream sent downstream for purification.
The downstream methanol purification process operates 24 hours a day as well. The dirty
methanol stream employs distillation to obtain a final methanol product stream with 99.97%
purity.

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III. Background Information
Market for Renewable Methanol
The $36 billion methanol industry has 90+ plants in operation worldwide and produces 49.8
million tons annually to be used in the chemical, transportation and power generation sectors
OH.3a chemical formula of CHwiths the simplest alcohol,Methanol i.(Methanol Institute, n.d.)
Its simplicity brings forth a variety of characteristics; methanol occurs naturally in the
environment, it is biodegradable, light and colorless, and it quickly breaks down in aerobic and
anaerobic conditions (Methanol Institute, n.d.). Methanol can be produced from a diverse array
of feedstocks which gives it the distinct advantage of polygeneration: the ability to be made
from any resource that can be converted into synthesis gas. As a result, methanol is classified as
“conventional” or “renewable.” Conventional methanol is produced from steam reformation
with the use of a fossil fuel, coal or natural gas, and steam. This produces a synthesis gas, as
shown below in Equation (12) for steam reformation (Methanol Institute, n.d.).
2 𝐶𝐻4 + 3𝐻2 𝑂 → 𝐶𝑂 + 𝐶𝑂2 + 7𝐻2 (𝑆𝑦𝑛𝑡ℎ𝑒𝑠𝑖𝑠 𝑔𝑎𝑠) (12)
The syngas is then processed over a catalyst to yield CH3OH, as shown in Equation (13).
𝐶𝑂 + 𝐶𝑂2 + 7𝐻2 → 2𝐶𝐻3 𝑂𝐻 + 2𝐻2 + 𝐻2 𝑂 (13)
Renewable methanol is produced from the synthesis of waste biomass such as switchgrass,
forest trimmings, corn stover, or other agricultural residue products in a very similar manner of
gasification and catalysis. Using biomass as the feedstock is considered carbon neutral due to
the sizeable carbon absorbance of the feedstock before processing. Additionally, renewable
biomass has an advantage in that it looks to include a CO2 stream as the feedstock,
consequently utilizing a GHG in its process (Karen Law, 2013).
Methanol is an exceptionally diverse chemical and thus has many advantages as a material for
chemical production or as a fuel source. With its unique ability for polygeneration,
manufacturers can tap into multiple resources to supply the increasing methanol demand.
Since methanol production is already well established in the global marketplace, the existing
infrastructure and logistics would allow for production conversion between conventional and

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renewable means, and possibly allow for a full transition to renewable methanol in the future.
As well, the US and other countries can leverage the economic benefit of the increased demand
of methanol. This is seen in two recent development projects: a 10 year Chesapeake Energy
Corp-Methanex contract and G2X Energy methanol-to-gasoline plant construction (The
American Oil and Gas Reporter, n.d.). Collaborations with natural gas energy companies and
new plant development projects represent a growing market that is seeking ways to utilize the
full potential.
At 40% of supply, the chemical sector has the largest demand for methanol, which is usually
provided through conventional means. The largest chemical use for methanol is in the plastic’s
industry to produce resins and polymers (The University of York, n.d.). Common methanol
derivatives include dimethyl ether, formaldehyde, acetic acid, methyl methacrylate, and
methylamines.
In the 1980’s and 1990’s, methanol received attention as an alternative fuel source, namely to
create a fuel blend with gasoline and possibly ethanol. It did not become a substantial
commodity though, primarily due to falling petroleum prices which negated any economic
incentive to its usage. In recent years, as petroleum prices and supply has been more volatile,
many countries including the United States are seeking ways to gain energy security and
mitigate uncertainties. As a result, the US has a seen a steady rise in alternative fuel demand
over the last decade. Federal Renewable Fuel Standards (RFS) calls for 18.11 billion gallons of
alternative fuel production in 2016; a 7% increase over the 2015 standards (EPA, n.d.).
Additionally, the Open Fuel Standard bill, if approved, would greatly promote the need for
methanol and demand could increase exponentially (Open Fuel Standard, n.d.) Methanol is
seen as one of the chief commodities able to fill the demand gap in alternative fuels due to a
variety of advantages specifically in the transportation sector: studies have shown a 65-95%
carbon reduction from well-to-tank and a 15-20% lower tailpipe emissions with fuel blends of
methanol, it cuts nitrogen oxide and volatile organic compound emissions, there are no toxic
additives necessary and has a half-life of 1-7 days versus gasoline and other constituents at over
a hundred days (Methanol Institute, n.d.). Another significant advantage is its ability to be used
in advanced efficiency technologies such as PEM fuel cells. While there are considerable

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advantages, methanol use in transportation fuels has disadvantages as well, such as it has half
the energy content as gasoline on a volume bases and it is corrosive in nature and miscible with
water which places different material requirements in vehicles (Methanol Institute, n.d.).
Lastly, methanol is being explored as an emerging fuel for electrical power generation. It can be
used as an energy carrier for hydrogen storage and delivery. Research has shown it can be
incorporated into existing dual-fueled gas turbines and can stand alone as a turbine fuel
(Methanol Institute, n.d.).
Renewable Methanol from Biomass
As opposed to bioethanol, methanol production from biomass has very few limitations in
feedstock choice. Agricultural resides, wastes, forest trimmings, and wood can be used – any
material able to undergo gasification to produce syngas. Since the feedstock can be a waste
material, there is little competition between materials usable as food sources. Furthermore, the
Energy Independence and Security Act mandates that non-food based bio-fuels ramp
production to meet the goal of 36 billion gallons by 2022, where methanol can obviously play a
major role.
A disadvantage to using biomass is that several additional production steps need to be taken
into consideration. The biomass must be pretreated by conditioning and drying to break down
cellulose and lignin and densify the material. Additionally, the use of biomass has a lower H:C
ratio compared to natural gas and thus produces char and ash to be taken into consideration in
the separations and waste disposal process. Also, conditions in the syngas formation reactions
need to be manipulated for maximum conversion. The syngas needs to be “upgraded” to
increase the H2 content and lower the methane content by utilizing the water-gas shift
reaction. Overall, biomass lowers the efficiency of the overall process due to these factors,
though methanol selectivity over 99% can still be achieved (Cheng, 2010).
Many feedstock options are available, though corn stover is the most plentiful non-food, non-
crop source of biomass in the US, due to corn crops producing the highest volume of residue in
comparison to all other major crops (Dupont, 2012). The current supply has been estimated at
75 million tons per year (Roth, 2014). As well, due to the increase in demand of corn and higher

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crop yields, the level of corn residue has increased as well, though the removal must be
sustainable.
Solar-Thermal Processing
Solar energy is one of the most accessible forms of renewable energy, and the amount available
is more than enough to power the entire world, provided it can be harnessed (Clean Technica,
n.d.). Currently, the capacity in the United States is 1.75 operating GW, with 2.2 GW in
development. Globally, there are 4.7 GW total current operating capacity with 22GW expected
by 2025 (Heba Hashem, 2015) . Among the solar energy possibilities, concentrated solar power
(CSP) has emerged as the major conversion technology due to many of its unique features and
relatively high efficiencies. CSP has the capability to achieve extremely high temperatures and
can be integrated with other conventional fossil fuel plants to create hybrid systems.
Consequently, a traditional fossil fuel plant’s overall GHG emissions are lowered by reducing
the fossil fuel input and relying partially on solar. CSP also has the ability for thermal energy
storage which allows for extended operation beyond when the sun is radiating energy.
A CSP process is constructed to collect the sunlight using heliostat mirrors that concentrate
solar energy using compound parabolic concentrators (CPC) to a centrally located tower. This
type of concentration allows for temperatures greater than 1000°C, which is beneficial to many
reaction systems. Figure 1 shows an aerial view of a solar power tower and heliostat field.
Figure 1: Aerial view of solar power tower and heliostat field

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In the biomass to methanol plant, a renewable energy source was sought to mitigate the use of
natural gas and GHG emissions. As well, biomass gasification requires high temperatures in
order to avoid tar formation and to increase the conversion to higher energy gases such as CO
and H2. CSP was the obvious choice to meet both the high temperature demands and the
lowered GHG emissions.

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IV. Environmental, Health & Safety
As in any chemical manufacturing system, it was paramount to consider the effects of the
proposed biomass gasification and methanol production plant on the environment and the
health and safety of the operators. This process involved a variety of chemical components
including reagents, catalysts, and waste products that are toxic, flammable, or highly reactive.
Waste treatment or management was considered for all streams exiting from the process. In
addition, the simulated process operated at temperatures over 1000°C and pressures up to 80
bar, conditions which can cause serious harm or disaster if not well-controlled and monitored.
Accordingly, worst-case scenarios were developed and evaluated. Finally, a life cycle analysis
(LCA) was performed to evaluate the environmental impacts of the proposed process across its
30-year lifetime on public health and land.
Chemical Hazards
A summary of all the chemical components present in the system is presented in Table 1 below.
Included in this table are the chemical formulas, lower explosion levels (LELs) of each
component, their auto-ignition temperatures, important safety hazards, general safety hazards,
and the permissible exposure limits (PELs) established by the Occupational Safety and Health
Administration (OSHA) (OSHA, 2011). In the following sections, methodologies to reduce these
chemical hazards will be discussed.
Table 1: Overview of chemical components in the biomass gasification and methanol production process. OSHA PELs are
obtained from (OSHA, 2011) or the indicated source (material safety data sheet, MSDS). GHG = greenhouse gas. *OSHA PELs not
considered because the limiting safety factor is the available oxygen in the atmosphere.
Component
(phase)
Chemical
formula
Lower
explosion
level
Auto-ignition
temperature
(°C)
Safety and
environmental
hazards
OSHA
PELs
(ppm)
Source
Biomass fly ash
(s)
N/A N/A Wide range
(232-2760)
Irritant; solid
hazardous waste
6 (Weyerhaeuser,
2014)
Hydrogen (g) H2 4 vol% 565.5 Flammable,
asphyxiant*; none
- (Air Products,
1994)
Nitrogen (g) N2 Not
flammable
Not
flammable
Asphyxiant*;
none
- (Air Products
and Chemicals,
Inc., 1997)
Water (g, l) H2O Not
flammable
Not
flammable
Slipping; none None (Sciencelab.com,
Inc., 2013)

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Corn stover
biomass (s)
Multi-
component
25 g/m3
Dust layer:
215
Dust cloud:
450
Explosive, irritant;
none
6 (IEA Bioenergy,
2013)
Hydrogen
sulfide (g)
H2S 4.3 vol% 270 Flammable, toxic;
toxic to aquatic
life
10 (Airgas, 2015)
Methane (g) CH4 1.8 vol% 287 Flammable,
asphyxiant*; GHG
- (Airgas, 2015)
Carbon
monoxide (g)
CO ≥12.5 vol% 700 Flammable, toxic;
lethal to fish,
pollutant
25 (Matheson Tri-
Gas, Inc., 2008)
Hydrochloric
acid (g, aq)
HCl Not
flammable
Not
flammable
Corrosive, toxic,
irritant; acidifies
water
0.3 (Sciencelab.com,
Inc., 2013)
Carbon dioxide
(g)
CO2 Not
flammable
Not
flammable
Asphyxiant; GHG 5000 (Air Products
and Chemicals,
Inc., 1994)
Ethane (g) C2H6 2.9 vol% N/A Flammable,
asphyxiant*; none
- (Sigma-Aldritch,
2015)
Ethylene (g) C2H4 2.7 vol% 450 Flammable,
asphyxiant*; none
- (Airgas, 2015)
Nitric oxide (g) NO Not
flammable
Not
flammable
Toxic, oxidizer,
irritant, reactive;
pollutant
25 (Matheson Tri-
Gas, Inc., 2008)
Nitrogen
dioxide (g)
NO2 Not
flammable
Not
flammable
Toxic, carcinogen;
pollutant
1 (Matheson Tri-
Gas, Inc., 2008)
Ammonia (g,
aq)
NH3 16 vol% 651 Flammable,
corrosive, irritant;
toxic to aquatic
life, pollutant
25 (Air Products
and Chemicals,
Inc., 1999)
Zinc oxide (s) ZnO Not
flammable
Not
flammable
Toxic, irritant;
hazardous solid
waste
5 (fume),
6
(particulat
e)
(Sciencelab.com,
Inc., 2013)
Zinc sulphide
(s)
ZnS Not
flammable
Not
flammable
Toxic, irritant,
reactive;
hazardous solid
waste
N/A (Sciencelab.com,
Inc., 2013)
Zinc chloride
(s)
ZnCl Not
flammable
Not
flammable
Toxic, corrosive,
irritant;
hazardous solid
waste
1 (fume),
6
(particulat
e)
(Sciencelab.com,
Inc., 2013)
Methyl
diethanolamin
e (MDEA) (l,
aq)
CH3N(C2H4O
H)2
1.4 vol% 280 Irritant;
biodegradable,
low toxicity to
aquatic life
N/A (Union Carbide
Corporation,
2015)
Mineral oil Varies N/A N/A Irritant, slightly
flammable;
hazardous waste
5 (mist) (Sciencelab.com,
Inc., 2013)

18
From this table and the accompanying MSDS documents, the most serious chemical hazards
were evaluated. Many of the chemical components in this process were present in the gas
phase, posing hazards regarding the availability of oxygen in the atmosphere on-site. In
particular, methane, ethane, ethylene, nitrogen, hydrogen, and carbon dioxide are classified by
OSHA as simple asphyxiants. A simple asyphxiant poses a hazard when the amount of available
oxygen in the air drops below 10%, which can cause unconsciousness and, in the absence of
further action, death by suffocation. If a large process gas leak occurred, this chemical hazard
would be a concern.
In addition, many of the components involved in the gasification of biomass are highly
flammable: hydrogen, carbon monoxide, hydrogen sulfide, methane, ethylene, ammonia, and
the biomass itself. Since the process gases are at pressures of at least 35 bar, it is unlikely that
ambient air would leak into the process. If the gas were exposed to ambient air at the
simulated temperatures up to 1450°C, the gas would likely auto-ignite, causing flaming jets of
high temperature, high pressure gas to be ejected from the equipment. These jets could start
fires in other equipment elsewhere in the plant, severely injure operators, and potentially cause
an explosion in other high pressure equipment. In addition, there is a risk of biomass fires
occurring. After the corn stover used in the process is unloaded, it is likely to be stored in a silo
before pre-processing. Since the biomass is not already dried (25% moisture by mass), there
exists a possibility of self-heating by microbial heat generation and exothermic side reactions in
ambient air. High temperatures can result at the core of a biomass silo as a result of thermal
runaway, ultimately resulting in spontaneous combustion of the biomass material (IEA
Bioenergy, 2013). The off-gassing of the moist biomass can also produce flammable compounds
such as CO, CH4, and aldehydes. The storage silo can then explode as a result of this volatile
mixture reaching high temperatures; an example of a silo explosion can be seen in Figure 2
below.

19
Figure 2: Silo explosion caused by the ignition of biomass off-gasses (IEA Bioenergy, 2013)
Many of the components in this process are also harmful to human health, particularly
ammonia, carbon monoxide, nitrogen oxide, nitrogen dioxide, and hydrogen sulfide. When
ammonia is inhaled, it is severely irritating to the lungs. The chemical is also corrosive to the
skin and eyes as a gas and an aqueous solution, where it contributes to an overall alkaline
solution. Upon inhalation, carbon monoxide can cause suffocation, blood damage, reproductive
complications, nerve damage, brain damage, and death. Inhalation of nitrogen oxide is fatal at
low concentrations, and eye contact with the chemical causes serious eye damage. Nitrogen
dioxide burns mucous membranes in the eyes, nose, and lungs and can be fatal if too much is
inhaled. Finally, hydrogen sulfide is very toxic to pulmonary tissue and is fatal if inhaled. The
biomass can also be harmful, as workers can become exposed to bacteria, spores, or other
pathogens living in the pre-dried biomass.
OSHA sets standards regarding workers’ exposure to harmful chemicals in the workplace. Table
1 outlines the permissible exposure limits (PELs) to various chemicals, expressed in parts of
compound per million parts of air (ppm). It is also required by OSHA that all chemical containers

20
are properly labelled with “the identity of the hazardous chemical and appropriate hazard
warnings” and that MSDSs are available with “detailed information about chemical hazards,
their effects, how to prevent exposure, and emergency treatment if an exposure occurs”
(OSHA, 2014). Finally, an inventory of chemicals present at the facility must be kept current and
available for reference. Personal protective equipment (PPE) is required for workers exposed to
these chemicals – these specifics will be addressed in the following section.
Health and Safety Considerations
Operator Safety
In order to legally employ operators, engineers, and other staff to run the plant, OSHA dictates
that certain minimum safety standards in plant operation and design be met. These regulations
are in place to protect employees from hazards in the workplace, as well as provide protections
to workers in reporting these hazards. It is the employer’s responsibility to provide certain
information to meet OSHA standards (OSHA, 2014). Injury and illness records must be available
to employees if these injuries or illnesses are a result of workplace conditions. Workers have
the right to exposure data; that is, employers must monitor levels of chemicals or substances
regulated by OSHA PELs and provide this data to employees. Finally, workers have the right to
their medical records, especially if a worker’s health “has been affected because of exposures
at work” (OSHA, 2014).
In case of an evacuation of the plant because of a disaster or other safety concern, exit routes
must be provided and meet certain OSHA requirements according to the Code of Federal
Regulations Title 29 (CFR 29), standard 1910.36 (OSHA, 2012). Exit routes must be permanent
and be built out of fire-resistant materials. The exit “must be protected by a self-closing fire
door that remains closed or automatically closes in an emergency upon the sounding of a fire
alarm or employee alarm system” (OSHA, 2012). The exit must also be unlocked and have
direct, unobstructed access to an open space. For example, the open space can be a street,
alley, or walkway. Outdoor exit routes are permitted under standard 1910.36.
Occupational noise exposure is an important workplace condition that must be met in industrial
settings; CFR 29, standard 1910. 95 outlines some requirements (OSHA, 2012). Table 2 presents

21
permissible noise exposures in duration per day versus sound level in decibels (dB). Proper
engineering and PPE should be provided if workers are exposed to sound exceeding these
values and durations. Examples of proper PPE include earplugs and noise-cancelling earmuffs.
Noise levels must also be monitored with calibrated audiometers and the data recorded.
Hearing protectors must also be provided free of charge to the workers.
Table 2: Permissible noise exposures (OSHA, 2012)
Duration per day, hours Sound level, dB
8 90
6 92
4 95
3 97
2 100
1 1/2 102
1 105
1/2 110
1/4 or less 115
OSHA also regulates the quality and condition of working-walking surfaces within industrial
plants, according to CFR 29, standard 1910.22 (OSHA, 2012). These surfaces must be kept clean
and dry in order to prevent slips and falls by workers. If the area surrounding process
equipment is wet, drainage systems must be installed and dry standing areas must be
maintained nearby. Aisles and passageways must be kept clear of debris and clutter. On
platforms and ladders, guard rails must be installed to prevent employees and operators from
falling from great heights.
For equipment operating at high pressures, OSHA requires the installation of pressure relief
valves according to CFR 29, standard 1910.101 (OSHA, 2012). These safety measures are
implemented to prevent the explosion of vessels in the case of overpressurization.
Overpressurization may result from blockage in a line or a larger temperature than expected in
a process unit. Pressure monitors equipped with alarms should also be installed in the process
to alert operators to rapidly rising pressures. Since this process also uses a variety of flammable

22
chemicals with a possibility for fires, a fire suppression system should be installed throughout
the plant and within the biomass silos to prevent flames.
Finally, personal protective equipment (PPE) must be worn by operators at all times to prevent
harm by chemicals, equipment, or operating conditions in the plant. Biomass or fly ash dust
clouds may form in the plant, so respirators should be worn at all times. Respirators also
prevent the inhalation of solid hazardous waste such as spent zinc oxide catalyst. If there is a
process gas leak, self-contained breathing apparatuses should be used to prevent the inhalation
of potentially fatal chemicals. Gloves and safety glasses should be worn at all times to prevent
injuries to the hands and eyes and block these bodily areas from discharges of chemicals.
Chemical goggles should be used upon if there is a process gas leak or if handling pure
chemicals or hazardous waste. Protective clothing such as overalls and long sleeves should be
worn at all times to prevent chemical exposure and skin injuries. A hard hat should be worn at
all times to prevent head injuries from falling equipment. Finally, to prevent the formation of
sparks from static charge, anti-static clothing and conductive boots should be worn at all times.
With these plant design and PPE enforcements in place, operator safety is enhanced.
Licensure and Permits
In order to operate a chemical processing facility in unincorporated San Bernardino County, CA,
a collection of licensures, permits, and information must be obtained from a variety of federal,
state, and county sources. These specifics are outlined in Table 3 below. A Certificate of
Disclosure of Hazardous Substances must be obtained from the Certified Unified Program
Agency (CUPA), Hazardous Materials Division within the San Bernardino County Fire
Department since hazardous materials are on site; this document is also known as a Business
Emergency/Contingency Plan. CUPA also provides hazardous materials and waste generation
information. Fire prevention information is supplied by the County of San Bernardino; this
authority will provide an inspection of the plant to ensure fire suppression and control systems
are being maintained effectively. The Air Quality Management District (AQMD) provides
Authority to Construct, Permit to Operate, and Building permits to industrial projects that emit
air emissions in the county. AQMD also provides Certificates of Occupancy. Since preliminary
hazardous waste treatment is done in the proposed plant, a Hazardous Waste Facility Permit

23
will be required from the Department of Toxic Substance Control. A State EPA ID Number is
required from the Department of Toxic Substances Control for businesses that “generate,
surrender to be transported, transport, treat, or dispose of hazardous waste” (California
Governor's Office of Business and Economic Development [GO-Biz], 2015). Since wastewater
will be discharged after treatment, an Industrial Activities Storm Water General Permit must be
obtained from the California Environmental Protection Agency (Cal/EPA). Cal/EPA also sets
Waste Discharge Requirements (WDRs). The Department of Industrial Relations provides
Occupational Safety and Health Information for businesses to use to develop an Injury and
Illness Prevention Plan. The Department of Industrial Relations also provides Workers’
Compensation Information. The Employment Development Department provides registration
forms for employers that pay over $100.00 in wages to one or more employees. The Franchise
Tax Board provides state income tax information and forms. An Employer Identification
Number (EIN) or Social Security Number (SSN) is required by the Internal Revenue Service (IRS)
in the U.S. Department of Treasury for all employers for income tax purposes. Employees are
required to submit Proof of Residency forms to demonstrate proof of eligibility to work in the
U.S. Finally, a Title V Air Permit is required for any facility that emits large quantities of nitrogen
oxides, or operates in a state subject to federal Acid Rain regulations. (Environmental
Protection Agency [EPA], 2015).
Table 3: Summary table of permits, licenses, and information needed for a “Chemical or Paint Formulation” business in
unincorporated San Bernardino county, California (California Governor's Office of Business and Economic Development [GO-Biz],
2015)
Licensure, permit, or information needed Distributing authority Level of government
Certificate of Disclosure of Hazardous
Substances
San Bernardino County Fire Department County
Hazardous Materials/Waste Generation San Bernardino County Fire Department County
Fire Prevention Information/Inspection County of San Bernardino County
Authority to Construct/Permit to Operate Air Quality Management District Regional
Certificate of Occupancy/Building Permit Air Quality Management District Regional
Hazardous Waste Facility Permit Department of Toxic Substances Control State
State EPA ID Number Department of Toxic Substances Control State
Industrial Activities Storm Water General
Permit
California Environmental Protection
Agency
State
Waste Discharge Requirements California Environmental Protection
Agency
State

24
Occupational Safety and Health
Information
Department of Industrial Relations State
Workers' Compensation Information Department of Industrial Relations State
Registration Forms for Employers Employment Development Department State
State Income Tax Information Franchise Tax Board State
Employer Identification Number (EIN or
SSN)
U.S. Department of Treasury Federal
Proof of Residency Requirement U.S. Immigration and Naturalization
Service
Federal
Title V Permit California Environmental Protection
Agency
Federal?
Environmental Considerations
One of the largest goals in the proposed biomass gasification for methanol production process
was to utilize a renewable energy source to provide the high temperatures needed in the
gasification reactor rather than burn fossil fuels. However, there were other environmental
considerations that were taken into account to evaluate the environmental impact of the plant,
including individual chemical considerations, possible chemical spills, greenhouse gases, and
waste disposal. Greenhouse gas emissions over the lifetime of the plant were considered in a
life cycle analysis (LCA).
Some of the chemicals given in Table 1 are listed as hazardous by the California Environmental
Protection Agency (Cal/EPA). These hazardous materials were classified as characteristic
hazardous wastes or used oils. The characteristic wastes are classified as such if they exhibit
“any of the four characteristics of a hazardous waste (ignitability, corrosivity, reactivity, and
toxicity)” and are given in Table 4 (California Department of Toxic Substances Control, 2014). An
ignitable substance is one that can cause a fire, spontaneously combust, or has a flash point less
than 60°C. Corrosive substances are materials that produce acidic or alkaline solutions (pH < 2
or pH > 12.5) or corrode metal storage containers. Reactive wastes are “unstable under certain
condition.” Toxic materials are “harmful or fatal [to fish or humans] when ingested or
absorbed.” Finally, used oil refers to “any oil that has been refined from crude oil, or any
synthetic oil that has been used and, as a result of use, is contaminated with physical or
chemical impurities” (California Department of Toxic Substances Control, 2014).

25
Table 4: Classification of hazardous waste components in the biomass gasification for methanol production process. Chemicals
from Table 1 are classified according to their characteristic waste codes or their status as a used oil.
Chemical (I) (R) (C) (T) Used
oil
Biomass fly ash X
Hydrogen X
Nitrogen
Water
Corn stover biomass X
Hydrogen sulfide X X
Methane X
Carbon monoxide X X
Hydrochloric acid X X
Carbon dioxide
Ethane X
Ethylene X
Nitric oxide X X X
Nitrogen dioxide X X
Ammonia X X X
Zinc oxide X
Zinc sulphide X X X
Zinc chloride X X
MDEA X
Mineral oil X
After classifying these streams as hazardous waste, the waste disposal of these streams was
considered. A table of all of the outlet streams from the process is given in Table 5 below. Two
of these streams were immediately flared: Waste Vap and PURGE. These streams are purged
because the products of their combustions are not hazardous. Two more streams require some
treatment before being flared: Light HC and Acid Gas. These streams will be passed over zinc
oxide (ZnO) to react all the hydrochloric acid (HCl) and hydrogen sulfide (H2S) according to
Equation (79) as presented in the Zinc-Oxide Reactor equipment design section, then the
streams are flared. In this way, harmful sulfur oxide (SOx) emissions can be avoided, and HCl will
not be emitted to the atmosphere. The amount of ammonia to be flared is small compared to
the outlet mass flow rate to be flared, and syngas burns with a lean flame and a combustion
speed “much quicker than natural gas” (U.S. Department of Energy, 2006). So, it was
determined to be acceptable to flare ammonia, despite the nitrogen oxide emissions.

26
Table 5: Summary of all outlet streams from the proposed process with compounds that are hazardous, sorted by simulation.
Components with mole fractions less than 1E-7 are not included.
Stream Simulation Mass flow rate
(lb/hr)
Composition (wt%) Phase Waste disposal
method
Bottoms HYSYS (MeOH) 6037 H2O: 0.9524
MeOH: 0.0476
Liquid Modified Luck-
Ettinger process,
then discharged as
wastewater
Waste Vap HYSYS (MeOH) 126.5 H2: 0.0193
CH4: 0.0363
C2H4: 0.0001
N2: 0.0483
H2O: 0.0125
CO: 0.3085
CO2: 0.0024
MeOH: 0.5725
Vapor Flared
Light HC HYSYS (Acid Gas) 1.316 H2O: 0.0117
CO2: 0.1359
H2S: 0.0015
CH4: 0.0087
CO: 0.7370
H2: 0.0984
N2: 0.0068
Vapor Passed over ZnO,
then flared
Acid Gas HYSYS (Acid Gas) 1317 H2O: 0.6201
CO2: 0.3729
H2S: 0.0046
CO: 0.0011
NH3: 0.0012
H2: 0.0001
Vapor Passed over ZnO,
then flared
Purge HYSYS (Acid Gas) 616.9 MDEA: 0.4500
H2O: 0.5262
HCl: 0.0238
Liquid Passed over ZnO,
then recycled into
amine scrubbing
system
QNCH-H2O Aspen PLUS 59227.1 All H2O Liquid Released as steam to
the atmosphere
SLDWASTE Aspen PLUS 226.878 All Ash Solid Sold
AQ-WASTE Aspen PLUS 2141.34 H2O: 0.99915
H2S: 1.3E-6
NH3: 0.00084
CO2: 4E-6
Liquid Modified Luck-
Ettinger process,
then discharged
ACIDS Aspen PLUS See HYSYS

27
ZN-SOLID Aspen PLUS 0.336905 ZnS: 1.0000, trace
ZnCl
Solid Solid hazardous
waste
PURGE Aspen PLUS 3141.47 N2: 0.05385
MeOH: 0.04060
C2H4: 0.00002
H2O: 0.00145
H2: 0.11288
CO: 0.77194
CO2: 0.00029
CH4: 0.01896
Vapor Flared
The final waste products zinc chloride (ZnCl) and zinc sulfide (ZnS) are disposed of as solid
hazardous waste. The solid waste stream ZN-SOLID is also disposed of as solid hazardous waste.
The amount of ZnO required to react with the HCl and H2S in each of solid waste streams was
determined by assuming 100% conversation of the gases and is given in Table 6. This analysis
yielded a total amount of 112,612 kg/yr needed of ZnO and 163,206 kg/yr of solid waste for
disposal. This solid waste will be placed into a satellite accumulation area on-site and routinely
taken to a waste disposal and treatment center (EPA, 2012). The waste solid ash from
SLDWASTE can be sold as fly ash to a concrete producer for $0.012/lb (The Aberdeen Group,
1985). The excess quench water from the QNCH-H2O stream will be emitted as steam to the
atmosphere.
Table 6: ZnO catalyst needed for waste treatment. ZnO costs $0.20/kg, and it costs $0.31/kg of solid waste for disposal. Assumes
8000 hr/yr of operation.
Stream Mass flow rate of ZnO needed
(kg/hr)
Mass flow rate of ZnS +
ZnCl2 (kg/hr)
Cost of disposal of ZnO
and waste disposal ($/hr)
Light HC 0.004 0.004 0.002
Acid Gas 6.51 7.80 3.72
Purge 7.43 12.45 5.35
ZN-SOLID 0.128 0.153 0.073
TOTAL 14.1 20.4 9.14
TOTAL (per yr) 112,612 163,206 73,120
To treat the remaining wastewater, a single-process wastewater treatment process called the
Modified Luck-Ettinger (MLE) process will be used (Exponent, 2012). MLE is a simple process
that utilizes two steps to remove nitrogen from wastewater – a simplified schematic is given in

28
Figure 3 below. The first step is the feeding of nitrogenated wastewater (AQ-WASTE) to an
alkaline anoxic tank, where bacteria take ammonia and oxidize it to nitrates; this process is
called denitrification. The bacteria needed reside in municipal waste, which is assumed to be
readily available from Daggett nearby. In MLE, an additional carbon source is needed; in this
process, the methanol waste stream Bottoms supplies this additional carbon. This decision
makes sense because the methanol is relatively dilute, reducing the toxicity of the methanol to
the bacteria. These nitrates and the added methanol are then consumed by heterotrophic
bacteria in nitrification, which emit the reduced nitrogen from the nitrates as nitrogen (N2) gas,
which is inert and not hazardous. A clarifier then removes the waste activated sledge (WAS)
from the effluent wastewater, which is disposed as municipal waste. Some of the WAS is
recycled to the process as recycled activated sledge (RAS). The large benefit of MLE in the scope
of the proposed process is that MLE consumes some of the methanol and ammonia hazardous
waste at the same time. The overall nitrification reaction is given in Equations (14) and (15)
below. The overall denitrification reaction is given in Equation (16) below.
2𝑁𝐻4
+
+ 3𝑂2 → 2𝑁𝑂2
−
+ 4𝐻+
+ 2𝐻2 𝑂 (14)
2𝑁𝑂2
−
+ 𝑂2 → 2𝑁𝑂3
−
(15)
𝑁𝑂3
−
+ 𝑂𝑟𝑔𝑎𝑛𝑖𝑐 𝐶𝑎𝑟𝑏𝑜𝑛 → 𝑁2 + 𝐶𝑂2 + 𝐻2 𝑂 + 𝑂𝐻−
(16)
Figure 3: Simplified schematic of the Modified Luck-Ettinger (MLE) process for the denitrogenation of wastewater (Exponent,
2012).

29
Worst-Case Scenarios
When designing any chemical processing plant, it is critical to evaluate the worst-case scenarios
that could occur in order to design ways to prevent disaster. In this section, a few possible
scenarios were considered. First, a leak of high-pressure process gases could occur, as discussed
earlier. Gas monitors and alarms should be installed throughout the plant in order to detect the
presence of H2 or CO gas in the atmosphere, as this would indicate a leak in the process
equipment. From there, the plant would be evacuated to ensure safety of the operators and
engineers. If the leak occurred in a unique piece of process equipment, the process would be
shut down by defocusing the heliostat mirrors off of the solar tower and shutting off the
regenerative natural gas burner in the solar reactor. To avoid shutdown of the whole process,
redundant lines could be installed throughout the process. In the event of a leak, valves at
either end of a redundant line could be opened to divert flow away from the leaky pipe. The
leaky pipe would then be shut off from the system by closing the valves and repaired.
The quench tank serves an integral role in quenching the gasification reaction by drastically
lowering the temperature of the solar reactor effluent from 1450°C to 120°C. If cooling water
flow to the quench tank were to suddenly stop, the very hot process gas would flow further
into the process, damaging many pieces of equipment not designed to withstand temperatures
over 1000°C. To avoid this occurrence, multiple pumps of the same specifications of the one
feeding cooling water to the quench tank could be purchased and installed in parallel. One of
these pumps could be used if another were to malfunction or break. Temperature sensors
should be installed in the piping downstream from the quench tank to detect its possible
malfunction.
As mentioned before, biomass fires could occur in storage silos. Self-heating of biomass can
cause the internal temperature of the biomass to reach upwards of 400°C, causing a fire to
ignite. Figure 4 shows the progress of a silo fire over 30 hours. At 30 hours, the fire begins to be
extinguished with inert gas. This figure demonstrates the importance of placing thermocouples
at the center of the biomass silo in order to detect the higher temperatures present in a silo
fire. A fire suppression system should be installed at the bottom of any storage silo to
extinguish the biomass with inert gas in case of a fire.

30
Figure 4: “Visualization of the measured temperatures inside a mock-up silo, 1 m diameter and 6 m height. The smoldering fire
was triggered in the middle of the silo and then allowed to develop freely which resulted in a slow fire spread downwards in the
silo. The combustion gases did not reach the top of the silo until about 20 hours. After about 30 hours, inert gas was applied
through the bottom of the silo which resulted in a fast reduction of the smoldering intensity” (IEA Bioenergy, 2013).
Finally, the exothermic reaction present in one of the three methanol synthesis reactors could
go out of control if the cooling water to the cooling coils within the vessel were to abate. The
temperature in the system would rise, eventually causing the system to overheat and perhaps
fail. To explore this idea further, an approximate adiabatic temperature rise was calculated for
one reactor. The methanol reactors are filled 25/26 of the way with a slurry of mineral oil
(Witco-40 oil) and catalyst. If the catalyst volume is assumed to be negligible, the volume of the
reactor filled with oil 𝑉𝑜𝑖𝑙 is calculated as follows with Equation (17):
𝑉𝑜𝑖𝑙 = (
25
26
)
𝑉𝑡𝑜𝑡𝑎𝑙
3
(17)
where 𝑉𝑡𝑜𝑡𝑎𝑙 is the volume of all three reactors combined. The 𝑚 𝑜𝑖𝑙 𝐶 𝑝,𝑜𝑖𝑙 of the oil can then be
found with using the heat capacity 𝐶 𝑝,𝑜𝑖𝑙 and density 𝜌 𝑜𝑖𝑙 of mineral oil (Engineering Toolbox,
n.d.) (Sciencelab.com, Inc., 2013). This calculation is shown in Equation (18) below:
𝑚 𝑜𝑖𝑙 𝐶 𝑝,𝑜𝑖𝑙 =
𝑉𝑜𝑖𝑙 𝐶 𝑝,𝑜𝑖𝑙
𝜌 𝑜𝑖𝑙
(18)
It was assumed that all of the heat duty 𝑄 of the reactor that would normally be removed by
the cooling coils goes into the mineral oil. The 𝑚𝐶 𝑝 value of the solid catalyst was assumed to
be negligible. The reactant gas 𝑚𝐶 𝑝 was calculated using values from Aspen PLUS and dividing

31
the mass flow rate by the reactor residence time τ, which was found using Excel and Polymath
during the reactor design (see Appendix III-F). This value was calculated along with 𝑚 𝑜𝑖𝑙 𝐶 𝑝,𝑜𝑖𝑙 in
Table 7 below and was found to be 69. Therefore, the 𝑚𝐶 𝑝 value for the oil is substantially
greater than that of the gas, so the 𝑚𝐶 𝑝 value of the gas can be neglected. Therefore, the
energy balance for this simplified system is given in Equation (19) as follows:
𝑄 = 𝑚 𝑜𝑖𝑙 𝐶 𝑝,𝑜𝑖𝑙
𝑑𝑇
𝑑𝑡
(19)
where 𝑇 is the temperature of the reactor and 𝑡 is the time after the cooling coils stop
functioning. Separating and integrating Equation (19) yields Equation (20):
𝑇(𝑡) = 𝑇𝑜 +
𝑄
𝑚 𝑜𝑖𝑙 𝐶 𝑝,𝑜𝑖𝑙
𝑡 (20)
where 𝑇𝑜 = 𝑇(𝑡 = 0 ℎ𝑟). A plot of Equation (20) with Excel can be seen in ___. From this plot, it
was determined that the mineral oil does a good job of diluting any temperature runaway that
may occur in the operation of this reactor. It was noted that this analysis did not take into
account the change in reaction rate with temperature. However, the small temperature
changes per minute that occur in this analysis show that there would exist a large amount of
time to detect problems with the cooling coils via thermocouples installed in the reactor. Flow
meters installed in the pipes leading to the cooling coils and temperature could also detect
shutdown of the coils. To avoid this occurrence, multiple pumps should be installed in parallel
to feed the cooling coils with water. The adiabatic temperature rise calculations can be found in
Appendix I-D.
Table 7: Calculation of parameters for the simplified adiabatic methanol reactor energy balance
Computation of temperature of reactor versus time
Total volume 1094.027 m3
Volume of one reactor 364.6757 m3
Volume of oil 350.6497 m3
Density of oil 0.838 g/mL
838 kg/m3
Total mass of oil 293844.4 kg
Heat capacity of oil 1.67 kJ/kg-K

32
mCp of oil 490720.2 kJ/K
Mass flow rate of gas 49033.97 kg/hr
Heat capacity of gas 7.226894 kJ/kg-K
Residence time of gas 0.02 hr
mCp of gas 7087.266 kJ/K
Heat duty of reactor 6.61E+07 kJ/hr
2.20E+07 kJ/hr/reactor
Initial reactor temperature 210 °C
483.15 K
Figure 5: Plot of reactor temperature (in °C) versus time (in min)
Life Cycle Analysis
A life cycle assessment (LCA) identifies, measures, and evaluates the environmental impact of
every stage of a product’s life according to the international standards set forth within ISO
14040. These standards dictate the four stages to be analyzed in an LCA are: Goal and Scope
Definition, Inventory Analysis, and LCIA (life cycle impact assessment) and Interpretation.
Goal and Scope Definition
The goal of this LCA is to identify the environmental impacts of building and operating a solar
thermal biomass to methanol plant over the entirety of its operation, and then quantifying this
impact in terms of greenhouse gas (GHG) emissions, namely carbon dioxide, and other
influential factors. The LCA should be an integral part of the decision making process when
200
220
240
260
280
300
0 20 40 60 80 100 120
T(°C)
t (min)
Simplified MeOH Reactor Temperature vs. Time

33
developing a new plant to ensure long term and short term public and land health and safety
issues are being addressed properly.
The plant operates with corn stover as the feedstock input, solar thermal, electricity, and
natural gas as the energy inputs, utilities as commodity inputs, and carbon dioxide, CO2,
emissions as the main output. An inventory analysis was performed on inputs and outputs for
pre-processing, gasification, and methanol purification, as well as a collective analysis over the
lifetime of the plant. Input data was generated from Aspen PLUS, the U.S Lifecycle Inventory
Database, and other resources. Figure 6 illustrates the system boundary used in this LCA.
The pre-processing unit inventory analysis involves analyzing the impact of the feedstock
agriculture, transportation, and CO2 absorption. By tracing the feedstock to its source, assuming
the corn is grown in Nevada, IA, the transportation emissions can be estimated. Land use,
fertilizer use and the resulting emissions were quantified as well and explained in detail in the
inventory analysis. Energy inputs to the plant include solar thermal energy, natural gas, and
electricity, with outputs being GHG emissions. Indirect effects, such as utility usage, are not
considered in this analysis.

34
Figure 6: System boundary for LCA for biomass to methanol plant
Inventory Analysis
The pre-processing unit uses corn stover as the biomass feedstock. The analysis of this product
assesses direct influences, such as CO2 emissions from transportation and CO2 absorption of
corn. As well, other factors were evaluated, such as the land use to grow the crop and fertilizer
needed for agriculture and the resulting emissions. A report from Iowa State University cites
the yield of corn stover to be 2.1 dry tons/acre (Zhang, Yanan, 2014). The biomass plant
requires an input of 82,000 tons/yr of feedstock, which equates to 39,048 acres of land/year to

35
provide enough corn stover to fuel the plant. When corn stover is used in biofuels production,
the entirety of the crop is depleted. Otherwise, the majority of the crop residue is left on the
fields to naturally replenish the soil with key elements such as nitrogen (N), phosphorous (P),
and potassium (K). Using all of the corn stover residue will require farmers to purposely
replenish the land with lost nutrients. Replacement rates for N, P, and K fertilizers were
calculated by Argonne Laboratory and are as follows: 7700 g N, 873 g P, and 9957 g K per 1 ton
of removed corn stover (Argonna National Laboratory, n.d.). The results of these calculations
are displayed in Table 8.
Table 8: Environmental factors from the waste feedstock
Factor Amount Unit
Land use 39,048 Acres land/year
Fertilizer added - Nitrogen 6.31x108
g N/year
Fertilizer added - Phosphorous 7.16x107
g P/year
Fertilizer added - Potassium 8.16x108
g K/year
N2O emission from added fertilizer 8.37x106
g N2O/year
NO emission from added fertilizer 4.10x108
g NO/year
Further, the CO2 emissions resulting in the transportation of the corn stover to the plant was
evaluated from Nevada, IA to Daggett, CA. Iowa is the largest producer of corn in the United
States, and thus feedstock originating in Iowa is a fair assumption. It was also assumed the
feedstock travels by a diesel powered train, as that is commonly used to transport freight
(Association of American Railroads, 2015). Train capacity varies substantially, anywhere from
1,000 to upwards of 20,000 tons. Frequency of travel would depend on the yield of corn stover
per crop per season, and how long corn stover can be stored after cultivation. BNSF reports 1
ton of freight is capable of travelling 423 miles on 1 gallon of diesel fuel (BNSF). After taking
into consideration an annual plant input of corn stover of 82,000 tons with a distance traveled
of ~1600 miles (from Nevada, IA to Daggett, CA), an approximate amount of CO2 emissions
from transportation fuel can be calculated. Michigan State University cites corn as having a
tremendous potential to remove carbon dioxide, upwards in the amount of 0.57 kg CO2/1 kg

36
corn stover (Michigan State University, 2007). The amount of CO2 absorbed by the required
amount of feedstock for the plant was assessed as well. The results of these calculations are
displayed in Table 9.
Table 9: CO2 emissions and absorbance due to transportation to plant and CO2 absorption
Feedstock lb CO2/year lb CO2/30 years (lifetime)
Transportation to plant 7.03x106
2.11x108
CO2 absorption from corn 9.33x107
2.8x109
The electrical energy and natural gas (if applicable) inputs for each section of the plant (pre-
processing, gasification, and purification) along with subsequent CO2 emissions were assessed.
Natural gas is an input only in the gasification section to supply additional power to the hybrid
solar reactors. Using the assumptions given of 1.8 lb CO2/1 kWh electricity, 15 lb CO2/100 ft3
natural gas delivered, and 117 lb CO2/1 million BTU released on combustion, the CO2 emitted
from each section was calculated and summed. The CO2 absorbance of corn stover was
subtracted from this to estimate the total plant CO2 emissions. A comparison of total emissions
of the proposed hybrid biomass plant (type I) to a typical methanol production plant was
assessed. The Methanol Institute cites typical methanol plant emissions from fossil fuels as
1000kg CO2 per 2000lb methanol produced (Methanol Institute, n.d.). For an annual production
of 58.3 million gallons of methanol, this equates to 1.18x1010 lb CO2 over the lifetime of the
plant. This was also compared to a biomass plant with only solar inputs (type II). The results of
these calculations are in Table 10.
Table 10: CO2 emissions yearly and annually for various plant types
Type of Plant /year2COlb /30 years (lifetime)2COlb
Typical plant (fossil fuels) 3.93x108
1.18x1010
Biomass type I 2.16x108
3.68x109
Natural Gas 1.26x108
3.79x109
Electricity 8.97x107
2.69x109
CO2 Absorption -9.33x107
-2.8x109

37
Biomass type II -3.57x106
-1.07x108
Difference: typical vs biomass type I 1.77x108
8.09x109
Difference: Biomass type I vs type II 2.2x108
3.79x109
Impact Assessment and Interpretation
The inventory analysis confirms many factors need to be taken into consideration before using
waste biomass in a conversion to methanol plant. Farmers will have to address the issue of
fertilizer replacement, especially with low crop-yield seasons. This adds cost to their business
that may or may not be well-received. Interestingly, ash from the biomass gasification process
can be used as a fertilizer. This could present a possible solution for farmers. As well, modern
farming practices allow for more sustainable methods to retain soil nutrients, which might be
necessary if this becomes an issue with farmers.
The CO2 absorbance from the biomass more than outweighs the CO2 emittance from the
transportation of the feedstock to the plant, though this CO2 absorbance would likely rather be
used as a carbon credit in the plant economics. Thus, the transportation CO2 emissions has an
environmental impact that would need to be addressed. Utilizing larger capacity trains to travel
less often could potentially lessen the transportation emissions. As well, as fuel cell and battery
technology advances, converting the shipment to advanced technology, carbon free vehicles
would mitigate this issue entirely.
On comparison of CO2 emissions for a typical methanol plant and the proposed biomass hybrid
plant (type I), the latter cuts emissions by more than half. This is a substantial difference in GHG
emissions, though even more so if the reactor were to operate completely on solar. Biomass
type II plant would, theoretically, operate completely on solar without the need of natural gas,
perhaps through the use of thermal energy storage. Negating the use of natural gas alone
allows the plant to have negative carbon emissions, when including the CO2 absorbance in the
overall emissions calculation. Type I was also compared to type II, and the difference in
emissions was still on the order of 108. This calculation confirms the use of natural gas still
contributes substantially to the GHG emissions, though natural gas cuts CO2 emissions ~50%
versus coal (US Energy Information Administration, n.d.).

38
V. Project Premises
Included in the scope of this project are four systems working in tandem to produce high
quality methanol from waste biomass. The first system is a biomass pre-processing section
modeled in SuperPro Designer which dries, grinds, and pressurizes corn stover biomass. The
second system is modeled in Aspen PLUS. The biomass is converted to syngas, which passes
through many clean-up steps and is converted into methanol. The third system is the modelling
of one of these clean-up steps in Aspen HYSYS: an amine scrubbing system which removes H2S
and CO2 from the syngas. The fourth system is a post-processing operation modeled in Aspen
HYSYS to purify the methanol product. These systems combined constitute the methanol
production plant.
The methanol production plant was designed to continuously produce 58,300,000 US gallons of
99.97 mol% of methanol per year. Slight excess of methanol was produced to account for
unforeseen major maintenance issues that could cut into production time. In this manner, the
buyer’s supply would have limited interruptions over the course of the plant’s lifetime, if any at
all. It was assumed that all raw materials are available at 100% purity. This plant was designed
to be a new “grass roots” plant, so the costs of land, site preparation, royalties, and other
related expenses were considered. The plant was planned to be constructed and operate in
Daggett, California, which is located in unincorporated San Bernardino County. It was assumed
that all utilities, such as cooling water, steam, electricity, wastewater systems, and compressed
air are readily available from nearby industrial sites. Other assumptions and specifications
unique to each system are outlined below.
Design
Biomass Pre-Processing
 Access to preheated dry air at 120°C and 1.013 bar assumed
 Access to nitrogen gas at 25°C and 35 bar assumed
 Dryer provides an evaporation rate of 20 (kg/hr)/m3
 Power Requirements:
o Shredder: 47 kW/(kg feed/s) with 0% power dissipation to heat

39
o Hammermill grinder: 130 kW/(kg feed/s)
o Lockhopper: 490 kW/m3, adiabatic operation, 5% nitrogen leaks to gasifier and
the remainder is vented by the hopper
o The required particle size distribution is met with the given power inputs
Biomass Gasification and Methanol Production
 Fluids package: RK-Soave with unconventional components
 Processed biomass enters the system at 90°C and 35 bar
 Gasification reactor modeled as decomposition of biomass into elemental forms fed into
an equilibrium (Gibbs) reactor
 1/3 of the duty of gasification provided by concentrated solar power, 2/3 provided by
natural gas burners
 Conversion of biomass in gasification reactor assumed to be 100%
o Kinetics modeled in Excel
 Conversion of H2S and HCl in ZnO reactor assumed to be 100%
o Kinetics modeled in Excel
 Conversion of CO and CO2 in methanol reactor assumed to be 45%
o Kinetics modeled in Polymath
 Catalyst in methanol reactor is Cu/ZnO/Al2O3 in slurry phase with Witco-40 mineral oil
 Efficiency of solid separations (cyclones) assumed to be 100%
 Pressure drops through piping and equipment assumed to be negligible
 All water and natural gas streams fed at 25°C
Amine Scrubbing
 Fluids package: Acid Gas Cleaning
 Specified to reduce the concentration of H2S in sweetened syngas to <1 ppm
Methanol Purification
 Fluids package: Peng-Robinson
 Final product volume calculated at a methanol density of 735 kg/m3 at 80°C (The
Engineering Toolbox, n.d.)

40
Economics
 Bare module cost method used to determine project capital cost
o When “installed” used in assumptions here, bare module factor is 1
 Base cost of heliostats is $126/m2, installed
 Base cost of secondary concentrator mirror area estimated at 10X heliostat cost per m2
($1260/m2), installed
 Base cost of solar tower (installed) in 2015 given by Equation (21) as follows, where ℎ is
the height in m:
𝐶 𝑃 = 1.41(600,000 + 17.72𝑚2.392) (21)
 Cost of natural gas: $2/1000 SCF (standard cubic feet)
 Cost of biomass: $60/metric ton delivered by railcar on a dry basis
 Cost of ZnO and methanol catalyst: $5/kg catalyst
 Value/cost of 450 psig (high pressure) steam: $17.29/1000 kg
 Value/cost of 150 psig (medium pressure) steam: $12.57/1000 kg
 Value/cost of 50 psig (low pressure) steam: $7.86/1000 kg
 Price of cooling water: $0.019/m3
 Refrigeration, -150°F: $15/GJ
 Refrigeration, -90°F: $12.21/GJ
 Refrigeration, -30°F: $9.43/GJ
 Refrigeration, 10°F: $6.57/GJ
 Chilled water, 40°F: $4.71/GJ
 Wastewater and solid hazardous waste treatment: $0.31/kg contaminant removed
 Landfill: $0.19/dry kg
 Cost of land: $1000/acre
 SiC tubes for the solar reactor are 6 inches in I.D., ¾ inch thick, and up to 20 m long
 SiC tubes costed as follows (email communication with Prof. Weimer):
o First reactor tube costs $1M, each other tube after first costs $300,000

41
 Cost of alumina insulation, metal containment shell, and secondary concentrator are all
installed
 5 yr MACR depreciation
 Cost of borrowed money (interest on capital) is 10%
 Operation is 24 hr/day for 333 days/yr (8000 hr/yr)
 Plant capacity is 50% in year 1, 75% in year 2, and 100% thereafter
 Lifetime of the plant is 30 years
 Construction period of the plant is 1 year
 Contingency is 15%
 Inflation is 1.9% throughout plant life for all considerations
 Effective tax rate is 38.9%
 Insurance and local taxes is 2%
 Total fixed cost used in cash flow calculations
 Cost of labor (annual wages per operator) is $104k/operator/shift (includes all
overhead)

42
VI. Approach
Hand Calculations
Heat of Reactions: Cellulose and Steam
Heat of Reaction at 25°C
The first hand calculation conducted in the approach calculations determines the heat of
reaction (∆𝐻𝑟), when cellulose is reacted with steam.
In order to obtain this value, the following reaction was provided:
𝐶6 𝐻10 𝑂5(𝑠) + 6𝑂2(𝑔) → 6𝐶𝑂2(𝑔) + 5𝐻2 𝑂(𝑙) (22)
This equation has a known heat of combustion (∆𝐻𝑐𝑜𝑚𝑏), which is −17.340 𝐽/𝑔 at 25°C.
Using this equation, the enthalpy of cellulose can be back calculated. The heat of combustion is
the difference between the enthalpies of the products and the enthalpies of the reactants
multiplied by their stoichiometric coefficients:
∆𝐻𝑐𝑜𝑚𝑏 = [5𝐻 𝐻2 𝑂(𝑙)
+ 6𝐻 𝐶𝑂2(𝑔)
] − [𝐻 𝐶6 𝐻10 𝑂5(𝑠)
+ 6𝐻 𝑂2(𝑔)
] (23)
Here, the enthalpies of carbon dioxide, water and oxygen gas at 25°C can be found in species
reference tables, such as those in Perry’s Chemical Engineering Handbook. With these values,
the only unknown is the enthalpy of cellulose, 𝐻 𝐶6 𝐻10 𝑂5(𝑠)
. By this method, the enthalpy of
cellulose was determined to be 2944.7 𝑘𝐽/𝑚𝑜𝑙.
In order to determine the heat of reaction of cellulose when reacted with steam, the chemical
formula for this desired reaction is given:
𝐶6 𝐻10 𝑂5(𝑠) + 𝐻2 𝑂(𝑔) → 6𝐶𝑂2(𝑔) + 5𝐻2(𝑔) (24)
Using the enthalpy of cellulose, the heat of reaction at 25°C can be found by once again taking
the difference between the products and reactants:
∆𝐻𝑟 = [5𝐻 𝐻2(𝑔)
+ 6𝐻 𝐶𝑂2(𝑔)
] − [𝐻 𝐶6 𝐻10 𝑂5(𝑠)
+ 𝐻 𝐻2 𝑂(𝑔)
] (25)
By this method, the heat of reaction at 25°C was determined to be −2910.9 𝑘𝐽/𝑚𝑜𝑙.

43
Heat of Reaction at 1450°C
In order to calculate the heat of reaction at high temperature, the enthalpies of the reactants
and products involved in the reaction must first be raised to their values at that temperature.
This is achieved by integrating the constant pressure heat capacities of each product and
reagent across the observed temperature increase:
𝐻 𝑇2
= ∫ 𝐶 𝑃 𝑑𝑡
𝑇2
𝑇1
(26)
After this integration has been performed on each product and reagent, Equation (25) is used
again, and the heat of reaction is obtained. At 1450°C, the heat of reaction for the
decomposition of cellulose in the presence of steam was found to be −3320.2 𝑘𝐽/𝑚𝑜𝑙.
Detailed analyses of these calculations can be found in Appendix I-A: Approach Calculations.
Heat of Reaction: Lignin and Steam
The determination of the heat of reaction of lignin in the presence of steam at 25°C and 1450°C
was accomplished by the same method used to find the heat of reaction of cellulose in the
presence of steam. By these calculations, it was determined that the decomposition of lignin in
the presence of steam at 25°C had a heat of reaction of −4221.9 𝑘𝐽/𝑚𝑜𝑙, while the same
reaction at 1450°C had a heat of reaction of −4236.0 𝑘𝐽/𝑚𝑜𝑙. A detailed description of the
calculations performed in order to achieve these values is available in Appendix I-A: Approach
Calculations.
Waste Biomass Feed Estimation
In order to estimate the amount of biomass required as system feed, the number of moles of
biomass produced on a per hour basis was divided by the 45% conversion of the methanol
reactor while ignoring the recycle streams. Knowing that one mole of CO was produced per
mole of biomass reacted, and that one mole of methanol was produced per mole of CO reacted
in the methanol reactor led to an initial guess of the moles of CO required in total. The project
description stated the optimal molar ratio of H2 to CO was 2, and that the steam methane
reforming reaction would lead to a 3:1 mole ratio of H2:CO per mole of methane reacted. The

44
final piece of given information was the weight percent of the three components fed to the
reactor, as shown in Table 11.
Table 11. Weight percent of cellulose, lignin, and ash in the feed gas.
wt% Cellulose 73.36%
wt% Lignin 23.34%
wt% Ash 1.18%
The first step in the calculation was to convert the percent mass composition to a mole percent
composition. This was done by taking a basis of 100g and using the molecular weights of each
component to determine the number of moles that would be present, then dividing each
component by the total number of moles. The results of this calculation are summarized in
Table 12.
Table 12. Mole percent results from hand calculation.
mol% Cellulose 75.21%
mol% Lignin 21.53%
mol% Ash 3.26%
Once the mole percent of the feed biomass was determined, stoichiometry was used to
determine the H2:CO ratio produced by biomass gasification. The results of this calculation were
that 1.067 moles of H2 were produced per mole of CO that was produced. Knowing that 2 moles
of Hydrogen per mole of carbon monoxide was the goal, an iteration was set up to determine
the fraction of CO produced by biomass, knowing that the fraction of CO produced by hydrogen
would be the difference between 1 and the fraction of CO produced by biomass. This iteration
was checked by ensuring that the overall moles of H2 produced was twice that of the overall
moles of CO produced.
Once the mole fraction of fed methane and fed biomass was determined, the total moles of CO
produced was used to calculate the feed rates of biomass and methane to the reactor using a
one-to-one ratio of moles CO produced to moles biomass or methane reacted.

45
Theoretical Energy Requirement for Solar-Thermal Reactor
The final step in the approach calculations is to determine the theoretical energy requirement
for the solar-thermal reactor. In order to do this, the power required to raise the temperatures
of the biomass, methane and steam to 1450°C is calculated.
These calculations are accomplished by integrating the constant pressure heat capacities of
each component across the desired temperature change, as shown in Equation (26). For lignin
and cellulose, the change in enthalpy for each component is added to ∆𝐻𝑟 for each reaction,
respectively. This value is then multiplied by the given molar flowrate of each component in
order to obtain the power required to heat, and recovered from reacting, a given biomass
substrate. This power can then be converted to kW.
This procedure is repeated independently for lignin, cellulose, steam and methane. The
individual power requirements for each component as well as the total estimated power
provided by the reactor are provided in the following table. Detailed calculations used to obtain
these values are present in Appendix I-A: Approach Calculations.
Table 13. Summary of power input/output for solar-thermal reactor.
Component Power Input / Output (+/-)
Cellulose -54046 kW
Lignin -23432.7 kW
Steam 17131.8 kW
Methane 25341.6 kW
Total: -35005.5 kW

46
VII. Process Flow Diagrams with Material & Energy Balances
Below are the process flow diagrams (PFD) with associated material and energy balances for
the pre-processing, gasification, amine scrubbing, and post-processing sections. Detailed
material and energy balance calculations can be found in Appendix I-B. Images for all of the
simulations may be found in Appendix III-A through Appendix III-D.
Biomass Pre-Processing
Process Description and PFD
Shown below in Figure 7 is the process flow diagram for the biomass pre-processing simulation.
This section is the first stage of the entire process, where the corn stover bales are made ready
for the gasification reactions that will occur further in the system.
Figure 7: Pre-processing section PFD

47
The feed enters at point S-101 at room temperature and pressure, where it is conveyed on a
rolling belt system to the first stage of pre-processing. The process begins with 2.55 x 104 𝑙𝑏𝑠
ℎ𝑟
of
corn stover with a composition shown below in Table 14.
Table 14: Composition of Biomass Mixture with Pure Components
Component Name Mass %
1 Ash 0.8700
2 Carbon 38.3920
3 Chlorine 0.0380
4 Hydrogen 4.5600
5 Nitrogen 0.1500
6 Oxygen 30.9750
7 Sulfur 0.0150
8 Water 25.0000
The stage 1 shredder will do the initial size reduction such that the corn stover is no larger than
1
4
𝑖𝑛. in diameter. This is necessary before entering the dryer as trying to dry an uncut bale is
too time- and energy-intensive.
The material is then moved via rolling conveyer to a direct-air rotary drum dryer system that
will reduce the moisture content from 25% to 6.25%. This operation is done to prevent excess
water from entering the solar reactor as well as to reduce complications in the later grinding
stage where the excess moisture can clump and block the grinder and lock-hopper. The 2.55 ×
104 𝑙𝑏
ℎ𝑟
of air enters at point S-102 at 120°C and exits at point S-104 at 90°C.
The remaining biomass enters the stage 2 grinder, P-3 / GR-101 Grinding, which was designed
as a hammer mill. This unit reduces the size of the particles to that necessary for the
gasification reaction as well as pressurization in the lock-hopper and the size distribution is
shown below in Table 15.

48
Table 15: Biomass Particle Size Distribution from Hammer Mill.
Size Interval Lower Limit (𝝁𝒎) Size Interval Upper Limit (𝝁𝒎) Weight Fraction Biomass Particles
100 120 0
120 140 .1
140 160 .2
160 180 .3
180 200 .4
The biomass then flows via pneumatic conveyance to the lock-hopper. Pneumatic conveyance
was used to prevent particles of this size to be lost from the system. The lock-hopper, P-4 / HP-
101, is capable of pressurizing the biomass to 35.0 bar, which is necessary to achieve the partial
pressures inside the solar reactor. This is achieved by adding 2.55 x 103 𝑙𝑏𝑠
ℎ𝑟
nitrogen at 35.0 bar
and 25°C in the bottom section of the lock-hopper. 95% of the nitrogen is bled from the system
and 5% of the nitrogen leaks into the biomass being fed to the solar reactor. This was modeled
in the PFD by P-5 / CSP-101 Component Splitting. After this step, the biomass is successfully
dried, sized, and pressurized as required by the system. The final feed to the solar reactor
leaves via S-110 at 85.59°C and 35.0 bar with a flowrate of 2.05 x 104 𝑙𝑏𝑠
ℎ𝑟
.
Material Balances
An atomic material balance was carried out on the biomass pre-processing section to ensure
closure of the system. Using Equation (27) below where A is some atomic species and there is
no generation, Table 16 was generated.
∑𝑛̇ 𝐴,𝑖𝑛 − ∑𝑛̇ 𝐴,𝑜𝑢𝑡 + 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 = 𝐴𝑐𝑐𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑜𝑛 (27)
Table 16: Atomic balance around the biomass pre-processing section
Atomic Species In
(lbmol/hr)
Out
(lbmol/hr)
Accumulation (lbmol/hr)
Ash 1.11111 1.11111 0
Carbon 816.4497 816.4497 0
Chlorine 0.13689 0.13689 0
Hydrogen 1286.683 1286.683 0

49
Nitrogen 1351.599 1351.599 -0.00042
Oxygen 936.3302 936.3298 .000426
Sulfur 0.11949 0.11949 0
From the energy balance, the system appears to be closed, and the only slight deviation is in
nitrogen and oxygen, which is most likely due to the number of significant digits used in the
mol% calculation in air. The error was insignificant, and the system is considered closed.
Heat Duty
Energy inputs and outputs were analyzed for the biomass pre-processing section. All the
required duties are supplied via electricity; a more in-depth analysis of the utility cost is
included in Section IX. Shown below in Table 17 is a summary of the heat duty per unit, where
positive duties represent the addition of energy to the unit operation.
Table 17: Heat duty summary for Biomass Pre-Processing Section
Unit Operation Heat Duty Required (Btu/hr) Provided by:
P-1 / SR-101 Shredding 5.16 𝑥 105
Electricity
P-2 / RDR-101 Rotary Drying 6.04 𝑥 105
Electricity
P-3 / GR-101 Grinding 1.14 𝑥 106
Electricity
P-4 / HP-101 Hopper 8.55 𝑥 104
Electricity
Biomass Gasification
Process Description and PFD
The following figure illustrates the primary section of the Solar-Thermal Biomass Gasification
facility, in which the biomass is converted to methanol. An explanation of the unit operations
and material flow within them, including flow rates, temperature, and pressure, is explained
below. A PFD for this section of the plant is shown in Figure 8.

50
Figure 8: Biomass gasification PFD

51
Biomass from the pre-processing section enters the solar reactor. In Aspen PLUS, the solar
reactor was modeled as two separate units. The first unit (DECOMP) was used to model the
breakdown calculations, while the second unit (SOLAR) models a Gibbs equilibrium reactor.
FORTRAN code was used with DECOMP in a breakdown calculator (BRKDOWN) to perform this
function; see Appendix III-F for this code. The biomass stream enters the DECOMP breakdown
unit at 90.0°C and 35.0 bar with a mass flowrate of 2.05×104 lb/hr. The heat duty of the
breakdown reactor is 7.75×107 Btu/hr. After undergoing breakdown and exiting the unit, the
stream temperature is raised to 1450°C with no change in pressure. In the SOLAR reactor, the
biomass process stream is contacted with 1.13×104 lb/hr of methane at 25.0°C and 35.0 bar. A
pressurized water stream (H2O-SLR) also enters the SOLAR reactor with a flowrate of 1.92×104
lb/hr at 26.0°C and 35.0 bar. The final stream that enters the solar reactor is a recycle stream
(R-SOLAR) from a later portion of the methanol synthesis process. This recycle stream has a
flowrate of 6.28×103 lb/hr and enters the solar reactor at a temperature of 50.0°C and 35.0 bar.
The heat duty of the solar reactor is 1.45×108 Btu/hr. Both this heat duty and the heat duty
supplied to the DECOMP breakdown unit are provided by the solar field and natural gas
burners. In the breakdown and solar reactor, the biomass is broken down into hydrocarbons
and other small molecules. A material balance associated with this reactor is given in Table 18.
Table 18: Material balance around the solar reactor (DECOMP + SOLAR)
IN OUT
Stream: BIOMASS R-SOLAR H2O-SLR METHANE PRODUCTS
Component Mass Flow Rates (lb/hr)
N2 0 338.352 0 0 514.3805
C2H6 0 0.005 0 0 0.009
CH3OH 0 255.106 0 0 0
C2H4 0 0.115 0 0 0.193
HCl 0 0 0 0 13.841
H2O 0 9.098 19200 0 1890.892
H2S 0 0 0 0 6.131
H2 0 709.237 0 0 6792.596
NO 0 6.92×106 0 0 1.05×10-5

52
NH3 0 1.99E-07 0 0 3.383
CO 0 4850.051 0 0 46935.05
CO2 0 1.825 0 0 665.592
CH4 0 119.140 0 11250 183.983
NO2 0 0 0 0 7.84×10-14
Ash 0 0 0 0 226.878
Biomass 20500 0 0 0 0
TOTAL 20500 6282.929 19200 11250 57232.93
TOTAL IN
(lb/hr)
TOTAL OUT
(lb/hr)
DIFFERENCE (lb/hr)
57232.93 57232.93 0.00
The product stream from the solar reactor exits at 1450°C and 35.0 bar. The flowrate of this
stream is 5.72×104 lb/hr. In order to cool this stream, water is fed into a quench tank (SPRAY-Q)
where it is contacted with pressurized cooling water (H2O-IN). The amount of cooling water
required to achieve the desired process stream temperature reduction is 5.95×104 lb/hr. The
cooling water enters at 25.5°C and 35.0 bar, and exits at 586°C. The cooling duty of the quench
tank is 9.49×107 Btu/hr, and the process stream is cooled to 120°C with no pressure change.
This process stream is then mixed with 2.98×102 lb/hr of the cooling water stream exiting the
quench tank. Contact with the 586°C cooling water stream raises the process stream
temperature to 122.0°C. A material balance for the quench tank system including the mixing
point between the exiting utility stream and process stream is given in Table 19.
Table 19: Material balance around the quench tank
IN OUT
Stream: PRODUCTS H2O-2 QNCH-H2O TO-CYCL
N2 514.3805 0 0 514.3805
C2H6 0.009 0 0 0.009
C2H4 0.193 0 0 0.193
HCl 13.842 0 0 13.842
H2O 1890.892 59524.74 59227.12 2188.516
H2S 6.131 0 0 6.131

53
H2 6792.596 0 0 6792.596
NO 1.05×10-5 0 0 1.05×10-5
NH3 3.383 0 0 3.383
CO 46935.05 0 0 46935.05
CO2 665.592 0 0 665.592
CH4 183.983 0 0 183.983
NO2 7.84×10-14 0 0 7.84×10-14
Ash 226.878 0 0 226.878
TOTAL 57232.93 59524.74 59227.12 57530.55
IN (lb/hr) OUT (lb/hr) DIFFERENCE (lb/hr)
116757.67 116757.67 0.00
The syngas stream exiting the quench tank system then enters a cyclone (CYCLONE), where
2.27×102 lb/hr of solid wastes are removed from the process. A material balance for the cyclone
separation unit is given in Table 20.
Table 20: Material balance around the cyclone (CYCLONE)
IN OUT
Stream: TO-CYCL VAPOR SLDWASTE
N2 514.381 514.381 0
C2H6 0.009 0.009 0
C2H4 0.193 0.193 0
HCl 13.842 13.842 0
H2O 2188.516 2188.516 0
H2S 6.131 6.131 0
H2 6792.596 6792.596 0
NO 1.05×10-5
1.05×10-5 0
NH3 3.383 3.383 0
CO 46935.05 46935.05 0
CO2 665.592 665.592 0
CH4 183.983 183.983 0
Ash 226.878 0 226.878
TOTAL 57530.55 57303.67 226.878

Weidner_BiomassToMethanol_SeniorDesignProject_Fall2015

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