coal to methanol senior design project final report

May 8, 2015

Ed Andjeski and Professor Speidel

Chemical Engineering Department

Drexel University

Philadelphia, PA 19104

Subject: Final Submission for Coal to Methanol Senior Design Project

Dear Mr. Andjeski,

Attached is the final design report on the production of methanol from coal. The pilot plant will

be located in Pittsburg, PA and will produce 835.4 lb/hr of 99.9% pure methanol. Waste

products include sulfur compounds, hydrogen, and unreacted syngas consisting of nitrogen,

methane, and trace amounts of hydrogen. The annual cost of manufacturing is $10.8 million and

the estimate for yearly production revenue is $1.8 million. Economic analysis demonstrates the

project is not feasible on the pilot plant scale.

Sincerely,

Group 3 - Coal to Methanol

Danielle Boccelli, Jacklyn Briguglio, Laura Ferguson, Kyle Mattson, Olivia Mustaro

Coal to Methanol

Danielle Boccelli, Jacklyn Briguglio, Laura Ferguson, Kyle Mattson, Olivia Mustaro

Team 3

Edward Andjeski

May 8, 2015

By signing this document, I acknowledge that work represented here is solely our Team’s efforts

and no plagiarism has occurred in its preparation.

In partial fulfillment of the requirements for CHE 483: Process Design III, Department of

Chemical and Biological Engineering Drexel University, Philadelphia, PA 19104

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Drexel University, CHE 483

Completed By: Reviewed By:

Abstract

This coal-to-methanol project creates 99.9% pure methanol using coal as the raw material. Methanol is

a commodity chemical most commonly used as a precursor for the production of formaldehyde, which is

widely used in the construction industry. Energy production from coal has been viewed negatively in

recent years due to its negative impact on the environment compared to most other fuel sources.

Methanol is a cleaner product that has a variety of other uses such as, biodiesel, gasoline blending, and

dimethyl ether (DME) production. The goal of this study is to determine the feasibility of producing

methanol from coal.

Methanol has previously been synthesized using natural gas as the raw material, and this process is laid

out in a similar fashion. Raw coal is pulverized and fed into a gasification reactor, which breaks the coal

down into a gaseous mixture of compounds, called syngas. The syngas leaving the gasification unit

contains sulfur compounds found naturally in coal, which can harm some of the equipment

downstream. These naturally occurring sulfur compounds are stripped from the mixture using an amine

solution and absorption column. The sulfur compounds are then treated off-site. Finally, the clean

syngas mixture, made up of mostly CO and hydrogen, is sent into a synthesis reactor, which uses a

catalyst to produce the methanol. The methanol is then separated from the unreacted gases and stored,

while the waste gases are separated further into a pure hydrogen stream, which is put into a pipeline

and can be sold, and a waste gas stream that is sent to an air treatment plant off-site.

The plant is located in Pittsburgh, Pennsylvania. This was chosen because the grade of coal specified for

this process is a Pittsburgh-based bituminous coal with a high carbon content and fairly low sulfur

content. Having the plant close to the mine will cut down on transportation costs, and all coal will be

brought in by barge. All stream and equipment sizing calculations were done on a basis of 1,000 lb/hr of

coal fed to the process. This scale is small for commodity chemicals, which are usually produced in large

quantities to increase economic margins. The scale studied here is on the order of a pilot plant. This

scale was chosen due to limitations while using Aspen software to simulate the process.

From the 1,000 lb/hr of raw coal being fed to the process, 835.4 lb/hr of methanol is produced. As a

result, the annual revenue from sales after subtracting raw material costs is $1.45 million, and the

annual operating cost is $10.8 million. At this scale, the process is not profitable. One way to create

more revenue would be to increase production rate by at least a factor of ten; this would generate ten

times the amount of revenue if the price of methanol stays constant since it is a linear relationship. This

will also increase operating costs slightly, but they do not increase linearly with production rate since it

will not require ten times the equipment, energy, or labor to run a scaled up process.

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Executive Summary

The project is designed to convert bituminous coal into methanol. Burning coal for energy is on the

decline because it emits more pollutants than other forms of energy. Because of this, coal is a relatively

inexpensive feed (estimated at $0.031/lb). The cost of coal for one year of production at full rates of

1,000 lb/hour of coal into the system is $0.248 MM. Along with coal, steam ($0.015/lb) and oxygen

($0.03/lb) are also fed to the process at about 100 lb/hr each - this costs just over $34,000 per year. The

cost of the catalyst, which has a 5 year lifespan, was also added in to the material costs at $11.26/hr, or

$89,000/year.

Methanol is a cleaner and higher-value product than coal, and can be utilized in many industries. The

price of methanol is estimated at $0.20/lb, which would result in $1.33 MM/year in earnings. In

addition to methanol, the process also produces hydrogen ($0.03/lb), and slag ($0.53/lb), which could

both be sold for a combined total of $0.43 MM/year. The total annual revenue from sales after

subtracting raw material costs is $1.45 MM.

The foundation for the process (input material costs v. output material costs) shows that it is possible to

generate a profit using this process. However, the profit is not feasibly seen using such small scale

operations. This is because the annual cost of operating ($10.8MM/year) is much larger than the

production revenue. Annual revenue would increase linearly as long as the price of the materials are

stable - as production rates increase, earnings will continue to increase at the same rate until the market

is saturated. Manufacturing costs, on the other hand, are likely to increase at a diminishing rate as the

size of the plant increases; a plant running at ten times the scale would not require ten times the labor,

nor would the equipment require ten times the energy to run. Also, capital costs for equipment would

not increase linearly, although it is likely that more pieces of equipment would be needed.

Since the base case for the process was found to be unfeasible, building this plant would result in a net

loss that would increase over time. The capital cost, which was calculated to be $6.30MM, would never

be recovered. The main way this could be remedied, as mentioned previously, is to increase production

rates. Another way to increase process profitability would be to do a waste management study for the

process. Currently, waste treatment accounts for about one half of all manufacturing costs; this is

mainly due to the 1,000 lb/hr of hazardous, sulfur-containing waste coming from the amine

regeneration tower, SR-201. Of this waste stream, 94.4% is water. Clean water is required as makeup to

account for the loss from the tower. If this stream was reduced to 70 lb/hr, waste treatment would be

reduced to $0.44MM per year, resulting in a total yearly cost of manufacturing of $5.93MM; this would

also reduce the amount of pure water needed for the process. Reducing waste, in addition to increasing

production rates, would likely result in a profitable process.

.

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Table of Contents Abstract .......................................................................................................................................................... i

Executive Summary ....................................................................................................................................... ii

Report ........................................................................................................................................................... 3

Introduction .............................................................................................................................................. 3

Process Synthesis Discussion .................................................................................................................... 4

Process Description ................................................................................................................................... 5

Process and Equipment Design Discussion ............................................................................................... 9

Table 1: Equipment Sizing Summary ................................................................................................... 13

Operating Requirements......................................................................................................................... 16

Table 2: Utility Cost Basis ($/BTU) ...................................................................................................... 16

Table 3: Catalyst Requirements .......................................................................................................... 16

Environmental Concerns/Waste Minimization/Sustainability ............................................................... 17

Table 4: Sustainability Metrics ............................................................................................................ 19

Safety Considerations ............................................................................................................................. 21

Economic Feasibility for Base Case ......................................................................................................... 23

Figure 1: Cumulative Cash Flow ($MM) .............................................................................................. 23

Table 5: Economics Summary ............................................................................................................. 24

Table 6: Capital Cost............................................................................................................................ 25

Table 7: Cost of Labor Calculations ..................................................................................................... 26

Table 8: Utility Cost Basis ($/BTU) ...................................................................................................... 27

Table 9: Energy Balance and Utilities .................................................................................................. 28

Table 10: Waste Treatment Cost ........................................................................................................ 29

Table 11: Production Profits ............................................................................................................... 29

Economic Uncertainty and Sensitivity .................................................................................................... 30

Figure 2: Cost of Manufacturing v. Product Sale Price ....................................................................... 30

Process Optimization .............................................................................................................................. 31

Table 12: Gasification Optimization Study .......................................................................................... 31

Table 13: Sulfur Removal Optimization Study .................................................................................... 32

Table 14: Sustainability Metrics Comparison ...................................................................................... 33

Conclusions and Recommendations ....................................................................................................... 34

References .............................................................................................................................................. 35

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Appendix A: Process Design Details ............................................................................................................ 38

A. Process Flow Diagram ......................................................................................................................... 38

Appendix B: Material Balances ................................................................................................................... 39

Table B.1: Process Stream Table ......................................................................................................... 39

Table B.2: Material Balance ................................................................................................................ 40

Appendix C: Figures and Tables .................................................................................................................. 41

Table C.1: Chemical Component Properties Table ............................................................................. 41

Table C.2: Coal Properties ................................................................................................................... 41

Table C.3: Annual Cash Flow Summary ............................................................................................... 42

Table C.4: Material Costs in 2015 ....................................................................................................... 43

Table C.5 Sensitivity Analysis .............................................................................................................. 43

Appendix D: Plot Plan.................................................................................................................................. 44

Figure D.1: Plot Plan ............................................................................................................................ 44

Appendix E: Supporting Documentation .................................................................................................... 44

Report

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Introduction

The purpose of this project is to study the feasibility of operating a coal-to-methanol plant. Methanol is

a commodity chemical, commonly used in the production of formaldehyde, a chemical that is used in

the construction industry to produce adhesives for various construction board products. Demand for

formaldehyde production is heavily dependent on the construction industry, so a slowdown in

construction can reduce formaldehyde demand. The global demand for formaldehyde production from

methanol is expected to increase at a rate of 5% per year through 2018. It is also expected that other

end-uses of methanol will increase, such as demand in the fuel industry for products like biodiesel,

gasoline blending and dimethyl ether (DME) [1].

Methanol is typically produced from natural gas. The natural gas is first separated into a synthetic gas

(syngas) stream consisting of CO, CO2, water, and hydrogen. The second step is the catalytic synthesis of

methanol from the gas stream, which is a highly exothermic reaction. The energy created from the

synthesis is used to generate electricity for other sections of the process as needed [2].

This project will use a similar process, with the exception of using coal as the raw material as opposed to

natural gas. The coal will be gasified and separated into a syngas stream as described previously. The

syngas will then be treated with an amine solution to remove the sulfur compounds created as a result

of the naturally occurring sulfur in coal. Finally, the syngas will be reacted in the presence of a catalyst to

form methanol, then separated from the unreacted gas to obtain a high purity product. The reason for

choosing coal as the raw material is because coal is a dirty fuel source and the goal of the project is to

create a product that is useful and not as harmful to humans and the environment as coal.

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Process Synthesis Discussion

Gasification is the first major step in the process, where coal is broken down from a solid into a mixture

of gaseous compounds, called syngas. The syngas from the gasifier contains sulfur compounds, which

can damage equipment downstream, and therefore, must be removed. There were several alternatives

to using an amine stripper for the H2S treatment. However methyldiethanolamine (MDEA) is the most

effective at removing sulfur compounds for the type of coal used in this process, because it selectively

removes sulfur compounds in the presence of CO and CO2. A plug flow catalyst reactor was found to be

the most effective way of converting the syngas into methanol. This reactor was chosen because it is

most effective in terms of catalyst loading and conversion of syngas to methanol. The plant capacity is

1,000 lb/hr of raw coal entering the process.

For the Shell gasifier used as a basis for this project, the downtime (planned and unplanned) is usually

five weeks out of the year [3]. Based on this, the stream factor will be 0.904. Five weeks should be

ample time for cleaning and maintenance on all other pieces of equipment.

The raw materials required for this process are coal, oxygen, steam, and MDEA. The coal for this process

is a Pittsburgh-based bituminous coal, which has an elemental composition described in the component

property table in Appendix C Table 2. The oxygen needed for the gasification must be as pure as

possible, and this will be purchased from an outside company. An air processing unit was considered as

an alternate, but the capital cost outweighed the cost of buying pure oxygen from a supplier. Steam will

be generated on site. The MDEA required is a 30 mole% solution, which can be purchased in bulk [4].

The methanol product will have a purity of 99.9% by weight. The following assumptions were made in

designing this process:

● All stream and sizing calculations were done on the basis of 1,000 lb/hr of coal coming into the

process, with an additional 100 lb/hr each of oxygen and steam.

● The oxygen feed is pure oxygen.

● The MDEA is in a 30 mole% solution in water and has a total flow rate of 10,000 lb/hr.

● The coal is pulverized to 12 microns before it enters the gasification reactor.

● All initial economic calculations were done in terms of 2015 dollars, and then adjusted using an

inflation rate of 2.0% when analyzing the life of the project.

● The water flows for the utilities are approximated on a basis of 1,000 lb of steam or cooling

water per process piece for the water intensity portion of the sustainability metrics.

● The catalyst activity and lifespan of 3-5 years are approximated based on data found in

literature.

● The only reaction taking place inside the methanol reactor is the synthesis of methanol from

carbon monoxide.

● An air treatment plant is adjacent to the facility.

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Process Description

Please refer to drawing D-004 in Appendix A, the block flow diagram for the coal to methanol process

for an overall process description. Please refer to drawing D-001 for the gasification section, drawing D-

002 for the sulfur removal section, and drawing D-003 for the methanol reaction and separation

sections. A detailed stream table can be found in Appendix B Table 1.

The main feed into the process is pulverized coal; coal is received from a local Pittsburgh coal mine by

barge, where it is taken off the barge by conveyor CV-101 and sent into a pulverizer, CR-101. The

pulverizer crushes the coal to a 12 micron particle size. The coal then is fed through a filter, FT-101, to

sort out any large pieces that may disrupt the process, and in line 1003 is transported into the

pulverized coal holding tank, T-101. The coal in the tank is at ground level; using screw conveyer CV-103

and elevator, EV-102, the coal is elevated to the correct height, where it flows through another screw

conveyor, CV-106, in line 1006 which feeds the pulverized coal into the gasification reactor, R-101A/B.

The total feed rate of coal into the process is 1,000 lb/hr. Oxygen and steam are also fed into the

reactor. Oxygen, coming in in line 1009, is fed at a rate of 100 lb/hr at 500 °F and 350 psi. Steam, line

1007, is fed at 101 lb/hr at 350 psi and 1,000 °F. The total feed rate into the reactor is 1,200 lb/hr.

The gasification reaction between coal, steam, and oxygen occurs in the gasification R-101A/B. The

equations below show the chemistry of the reaction.

3𝐶 + 𝑂2 + 𝐻2𝑂 → 𝐻2 + 3𝐶𝑂

The carbon in the coal reacts with steam and oxygen in R-101A/B to produce syngas; syngas is a mixture

of carbon monoxide, carbon dioxide, hydrogen, water, and other organic compounds. Due to the

kinetics of the reaction, the syngas mixture is mostly carbon monoxide and hydrogen, and lower

concentrations of other components. This syngas mixture leaves R-101A/B at 1,200 lb/hr, 2900 °F and

350 psi in line 1015. Since this reaction takes place at high temperatures and pressures, the gasification

vessel is constructed of stainless steel with thick refractory lining. The reactor also has water-filled

membranes lining the walls; these membranes get coated with slag as the reaction takes place and

allow the slag to flow downwards, along the walls to the bottom of the reactor to be recovered. [5] The

slag leaves through line 1014, is slag. Slag is a glass-like product that results from the burning of metals

and coal at high temperatures.

From the gasification reactor, the syngas needs to be cooled with heat exchangers, and decompressed

with a turbine, then the sulfur impurities must be removed. First, the effluent syngas from R-101A/B is

put through a series of heat exchangers, HX-101A-C, to remove excess heat. The first heat exchanger in

the train, HX-101A reduces the temperature of the syngas from 2900 °F to 1,000 °F using high pressure

steam; the syngas leaves the exchanger in line 1018 at 1,000 °F. The next exchanger, HX-101B, uses low

pressure steam to cool the syngas further, to 330 °F on the outlet in line 1021. The final heat exchanger,

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HX-101C, cools the syngas to 120 °F using cooling water. The syngas leaves H-101A-C in line 1101 at 120

°F, 350 psi, and at the same flow rate as the feed to the exchanger, 1,200 lb/hr.

The Pittsburgh coal used in the process contains 3.86% sulfur, 2.23 % pyritic and 1.63% organic; sulfur

reacts in the gasification reactor to form hydrogen sulfide (H2S) carbon disulfide (CS2) and carbonyl

sulfide (COS). These sulfur compounds need to be removed for both safety and environmental reasons.

Hydrogen sulfide is toxic to humans at low concentrations and is harmful to the environment and

corrosive to steel, so it needs to be removed from the process as early as possible.

The sulfur removal tower, AB-201, removes the sulfur compounds through absorption with the amine

compound methyldiethanolamine, or MDEA. MDEA removes sulfur compounds, specifically hydrogen

sulfide, in the presence of carbon dioxide. A 30 mole% solution of MDEA in water is sufficient for the

level of sulfur removal required. First, P-201 pressurizes the ambient pressure MDEA to 350 psi, and is

fed at 10,000 lb/hr via line 1102 into heat exchanger HX-201 to heat it to the absorption temperature

from 70 °F to 80 °F in line 1105 using steam. The steam in line 1103 is 1,000 lb/hr at 307 °F and 75 psi

and leaves the exchanger in line 1104 at 224 °F at the absorption column feed pressure and flow rate.

In the tower, 10,000 lb/hr of the liquid MDEA solution, in line 1105, is fed above the top tray, tray

number 1, at 350 psi and 80 °F, and 1,201 lb/hr of the sour syngas, in line 1101 is fed above the bottom

tray, tray number 20, at 350 psi and 120 °F. The absorption of sulfur compounds into the amine solution

is a pseudo reaction, and the chemistry is shown below:

Two streams exit the sulfur removal tower, AB-201: a rich amine stream, line 1108, that contains the

MDEA along with the sulfur impurities, and a sweet gas stream, line 1106, that contains only syngas. The

rich amine stream flows at 10,057 lb/hr, at 89 °F and 350 psi. The sweet gas stream is 1,049 lb/hr, and is

at 80 °F and 350 psi.

The rich amine in line 1108 is then sent to a steam stripper, SR-201, to remove the sulfur compounds

present in the amine; steam will be used, via a reboiler, to strip the sulfur compounds, forcing the H2S

and other compounds out of the amine solution. First, the pressure of the rich amine stream is let down

using a pressure changing valve, V-201, from 350 psi to 22.7 psi in line 1109. Line 1109 then enters a

feed-effluent exchanger to heat the amine to the temperature needed to strip out the sulfur

compounds. The rich amine leaves the exchanger, HX-202, in line 1110 at 175 °F, 22.7 psi, and at 10,000

lb/hr. The stripper operates at 22.7 psi and 215 °F. The amine boils in the tower and the sulfur

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compounds separate and leave the stripper in the overhead gas stream 1119; line 1119 is 210 °F, 14.7

psi, and 1,000 lb/hr. The gaseous sulfur compound stream, in line 1119, will be separated and sent to a

sulfur treatment plant to recover elemental sulfur. The other stream leaving SR-201 is the lean MDEA

stream in line 1114; this stream consists of only MDEA and water. First, it is cooled in the feed-effluent

heat exchanger and then pumped and recycled back to the absorber tower AB-201 in line 1113; line

1113 is 123 °F, 350 psi, and 10,000 lb/hr. Regenerating and recycling the amine will reduce cost, as less

fresh amine will need to be fed into the process once the recycle occurs.

After the sweet syngas leaves the sulfur absorber section through line 1106, it passes to a knock-out

drum, KO-201, to remove any water that is present in the gas. Water containing some impurities will

leave the process in line 1121 at 80 °F and 350 psi, at 5 lb/hr. This water does potentially contain

impurities, so it will be sent to a water treatment facility to be treated and then returned to a local

water source.

Line 1201 leaving KO-201, contains dry syngas at 1,044 lb/hr, 80 °F and 350 psi. First, the gas is

compressed to 750 psi, then heated to 482 °F, which are the conditions under which the reaction takes

place. The syngas leaving the knockout drum goes into CP-301, the syngas compressor, which is driven

by turbine TB-301 using waste steam from HX-101A. The syngas leaving the compressor leaves in line

1202 at 261 °F, 725 psi, and at 1,044 lb/hr. Next, the syngas is heated to reaction temperature in heat

exchanger HX-301; this heat exchanger uses steam to heat the syngas. The syngas leaves the heat

exchanger in line 1210 at 330 °F and 725 psi, at 1,044 lb/hr. This resulting syngas is fed directly into the

methanol reactor, R-301A/B.

The syngas to methanol reaction takes place in reactor R-301A/B. In the reactor, carbon monoxide

reacts with hydrogen to form methanol in the presence of a copper/zinc/alumina catalyst. The reaction

takes place at 482 °F and 725 psi in and reaction chemistry is shown below.

𝐶𝑂 + 2𝐻2 → 𝐶𝐻3𝑂𝐻

A copper/zinc/alumina catalyst is used to drive the reaction. The reactor is a plug flow reactor, with the

flow occurring vertically through the reactor with tubes between the beds to provide cooling on the

tube side. The catalyst used in the reaction becomes inactive above temperatures of 570 °F, so it is

important to have proper heat removal to avoid catalyst deactivation.

The syngas mixture in line 1210 enters reactor R-301A/B, where it is converted to methanol. Then,

methanol and unreacted gas leave the reactor in line 1211, which is 1,113 lb/hr of total flow, at a

pressure of 725 psi and 482 °F. The methanol contains a lot of impurities, so the final product has to be

purified before sale.

In order to do this, the reactor effluent must be cooled below the boiling point of methanol (148 °F).

Line 1211 enters the methanol heat exchanger, HX-302, which is cooled using cooling water, from the

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reaction temperature, and leaves in line 1205 at 102 °F and 725 psi. Line 1215 thus contains liquid

methanol and impurities; it flows into the methanol flash drum, FD-301, where the liquid methanol and

unreacted gas separate.

Two streams exit the methanol flash drum, FD-301: line 1216, and line 1217, which is 825 lb/hr of pure

methanol product. Line 1216 contains some methanol and unreacted gases; 137 lb/hr of this gas is

hydrogen and 9.5 lb/hr of methanol in the stream, both of which can be sold. To separate the methanol

and unreacted gases first, line 1217 is sent to a membrane filter, F-301, that selectively separates out

the hydrogen from the rest of the components of the stream. Leaving F-301 are two streams. Line 1221

contains 137 lb/hr of pure hydrogen at 80 °F and 725 psi, which is sold to a customer. Line 1218 contains

a mixture of methanol and unreacted gas. Line 1218 is fed to a flash drum, FD-302, that will further

separate the unreacted gas from the methanol. Line 1219 leaving FD-302 is a pure methanol steam at 80

°F, 725 psi, and 9.5 lb/hr; this stream combines with line 1217 to form line 1220. The other line leaving

FD-302 is line 1222, which is waste gas. This 71 lb/hr of waste gas can either be sent to a flare, or sent to

reactor R-301A/B to remove heat and control reaction temperature.

Line 1220 is the combined methanol product; 835.9 lb/hr of 99.98% pure methanol at 80 °F and 725 psi.

This methanol is sent to storage tanks, where it is held until final sale.

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Process and Equipment Design Discussion

R-101 Gasification Reactor

Pulverized coal with a 12 micron particle size is gasified using Shell Gasification technology, chosen for

its low maintenance costs, which are due to the robustness of the membrane wall gasifier and long

lifetime of coal burners [6]. The dried, pulverized coal is fed to the gasifier at a rate of 1,000 lb/hr. The

gasification reactor is 3.63 feet in diameter and 8 feet in length. Pre-heated oxygen (100 lb/hr at 500 °F

and 350 psi) and steam (101 lb/hr at 1,000 °F and 350 psi) are mixed and fed to the injector. Coal reacts

with oxygen and water to produce syngas at an operating temperature of 2,900 °F and pressure 350 psi.

The gasifier is lined with refractory material and equipped with an inner membrane wall consisting of

circulating water/steam-filled tubes. During operation, ash is converted into molten slag which flows

down the reactor where it solidifies and is removed [7].

HX-101 A/B/C Syngas Heat Exchangers

The hot syngas must be cooled from 2,900 °F before entering the sulfur removal unit that operates at

120 °F. This is done using three heat exchangers in series at 350 psi. The first exchanger has an area of

69.3 ft2 and uses high-pressure steam to reduce the temperature to 1,000 °F, the second has an area of

40.75 ft2 and uses low-pressure steam to reduce the temperature to 330 °F, and the third has an area of

34.5 ft2 and uses cooling water to reduce the temperature to 120 °F.

AB-201 Sulfur Absorption Column

Sulfur compounds must be removed from the syngas before methanol synthesis is attempted to avoid

poisoning the Cu/ZnO/Al2O3 catalyst in the methanol reactor. A sulfur removal unit operating at 350 psi

removes sulfur by absorbing it into a 30% methyldiethanolamine (MDEA) solution. MDEA selectively

absorbs H2S in the presence of CO2 at temperatures below 135 °F.

Lean MDEA solution is heated to 80 °F and fed at 10,000 lb/hr to the top tray of the column while the

sour syngas at 120 °F is fed at 1,107 lb/hr to the bottom tray. Sulfur is absorbed into the MDEA solution

as it passes over the sour syngas in the 0.93 foot diameter and 21 foot tall column. The rich MDEA

solution exits the bottom of the column at 10,057 lb/hr to a steam stripper that removes sulfur

compounds so the MDEA can be recycled. Sweet syngas exits the top of the column at 1,049 lb/hr.

SR-201 Steam Stripper

A stripper is required to remove the sulfur compounds present in the rich amine stream. Steam is used

to strip the sulfur compounds, forcing the H2S and other compounds out of the amine solution. The

stripper is 0.93 feet in diameter and 12 feet tall. The gaseous sulfur compound stream is sent to a sulfur

treatment plant to recover elemental sulfur and the lean MDEA is recycled back to the absorption

column.

KO-201 Water Knock Out Drum

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Excess water must be removed from the syngas to avoid catalyst deactivation in the methanol reactor. A

water knockout drum 1.84 feet in diameter and 5.53 feet in height is used to remove approximately

5lb/hr of water from the sulfur-free syngas. Dry syngas exits the drum at 1,044 lb/hr.

TB-301 Syngas Turbine

A 75 HP turbine is driven by the superheated steam produced in HX-101A at a flow rate of 9,041,724

lb/hr. The turbine drives the compressor, CP-301.

CP-301 Syngas Compressor

A 75 HP compressor is required to raise the pressure of the syngas leaving the sulfur absorption unit

from 350 psi to 725 psi before the syngas enters the methanol reactor. The temperature of the stream

leaving the compressor increases to 261 °F with compression.

HX-301 Methanol Reactor Heat Exchanger

A 3.34 ft2 steam heat exchanger is required to preheat the feed to the methanol reactor. Syngas enters

the heat exchanger at 261 °F and leaves at 330 °F.

R-301 Methanol Reactor

An Imperial Chemical Industries (ICI) low pressure reactor that operates at 482 °F and 725 psi is used to

react hydrogen and carbon monoxide to form methanol. It is modeled in Aspen as an adiabatic, shell

and tube, plug flow reactor using kinetic data deduced from the Langmuir-Hinshelwood rate equation

[7]:

To accommodate a feed of 1,000 lb/hr of pulverized coal, the reactor must be 10.23 feet in diameter

and 18 feet in length for a total reactor volume of 1,480 cubic feet.

The ICI reactor consists of 2,094 vertical tubes packed with catalyst that are surrounded by boiling

water. Catalyst is charged through manholes at the top of the reactor and gravity discharge of spent

catalyst permits rapid preparations for maintenance and recharging [8]. The total tube volume of 822 ft3

requires 33,876 lb of catalyst. Catalyst addition and withdrawal occurs during manufacturing downtime

[9].

A low-pressure Cu/ZnO/Al2O3 pellet catalyst, chosen for its high selectivity, stability and activity, is used

to drive the reaction of carbon monoxide and hydrogen to methanol [10]. The catalyst forms methanol

from carbon monoxide only at low levels of carbon dioxide, making it a good choice for the process since

the feed to the reactor is has trace levels of carbon dioxide. The proportions of the copper, zinc, and

alumina elements are >55% by weight, 21-25% by weight, and 8-10 % by weight, respectively, with a

standard size of 6 x 4 mm and optimal operating temperature and pressure ranges of 390-590 F and

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570-1175 psi. The most active catalysts have a high copper content while the Al2O3 interacts with the

supporting ZnO to improve methanol selectivity by reducing the potential for dimethyl ether formation

[11]. Catalyst poisoning can result from exposure to sulfur, halogens, and phosphorus containing

compounds from biomass and nickel carbonyls from reactor equipment. Poisoning by these compounds

results in site blocking or sintering, which yields decreased activity [12]. Commercial methanol synthesis

catalysts have lifetimes on the order of 3-5 years under normal operating conditions [11].

HX-302 Methanol Heat Exchanger

A 41.4 ft2 heat exchanger is required to cool the 1,044 lb/hr of methanol reactor effluent from 482 °F to

102 °F. The heat exchanger uses cooling water at 1,000 lb/hr. The effluent must be cooled to below the

boiling point of methanol (148 °F) to allow separation of the methanol and unreacted syngas in FD-301.

FD-301 Methanol Flash Drum

A flash drum 2.34 feet in diameter and 7 feet tall is required to separate the product methanol from the

unreacted gas. The drum operates at 725 psi and 80 °F allowing unreacted syngas to leave the top of the

drum at 218 lb/hr and 99.9% pure methanol to leave the bottom at 825.9 lb/hr.

The unreacted gas leaving the top of the drum passes through a hydrogen membrane filter, F-301. Pure

hydrogen leaves the filter at 137 lb/hr and is transported to the neighboring air plant through a

hydrogen pipeline.

FD-302 Waste Gas Recycle Flash Drum

A flash drum 0.75 feet in diameter and 2.2 feet tall is required to further separate and purify the

methanol from the filtered unreacted gas stream leaving F-301. 9.5 lb/hr of methanol leaves the bottom

of the drum and is combined with the product methanol stream, while the remaining unreacted gas at

71.3 lb/hr is returned the air plant for further processing.

Overall, 1,000 lb/hr of pulverized coal, 101 lb/hr of steam, and 100 lb/hr of oxygen results in a yield of

835.9 lb/hr of 99.9% pure methanol. Process byproducts include slag from the gasifier, sulfur

compounds stripped from the MDEA solution, water removed via knock-out drum, and unreacted waste

syngas from the flash drums. Once cooled, slag is can be marketed as a by-product for multiple

advantageous uses, which negates the need for long-term disposal plans. The profit costs and avoidance

of disposal costs combine to improve the economics of the disposition of slag [13]. Sulfur compounds

removed from the amine solution are hazardous to human health and the environment. Hydrogen

sulfide (H2S), carbon disulfide (CS2), and carbonyl sulfide (COS) will be reacted to form elemental sulfur

in an off-site sulfur treatment plant. The water removed from the knock out drum following the sulfur

removal unit contains traces of potentially harmful chemicals so it will be sent off-site to be treated by a

wastewater company before being released to the municipality.

In addition to the manufacturing area, a maintenance shop, central control room, and office space with

personnel facilities, such as a locker room and break room, are included in the plant. The maintenance

CTM 12



shop will host the mechanics, welders, pipe fitters, etc. necessary for the process. A plot plan showing

the arrangement of the processing units and buildings within the plant is displayed in Appendix D.

Process equipment was sized using the simulation results in Aspen. Sample calculations can be found in

the calculations section and tabulated equipment sizes and specifications are summarized in Table 1 on

the next page.

CTM 13



Table 1: Equipment Sizing Summary

Compressors MOC Compressor Type Power (HP) #Spares

CP-301 SS/SS Rotary 90 1

Drums MOC Height (ft) Diameter (ft) Pressure (psi)

FD-301 SS/SS 7 2.3 725

FD-302 SS/SS 2.3 0.8 725

KO-201 SS/SS 6 2 350

Exchangers MOC Type Pressure (psi) Area (ft2)

HX-101A T/T Double Pipe 350 20

HX-101B SS/SS Double Pipe 350 6

HX-101C SS/SS Double Pipe 350 19

HX-201 SS/SS Double Pipe 350 50

HX-202 SS/SS Multiple Pipe 350 170



Filters MOC Type Pressure (psi)

F-301 SS/SS Membrane 725

Miscellaneous MOC Type Length Power (HP)

CR-101 SS/SS 100 Mesh 60

CV-101 SS/SS Screw Conveyor 16 5




BV-101 SS/SS Belt Conveyor 70 15

EV-101 SS/SS Elevator 50 15

EV-102 SS/SS Elevator 50 15

Pumps MOC Type Power (HP) Pressure Out (psi)

P-201 SS/SS Centrifugal 17 407

P-202 SS/SS Centrifugal 2 407

P-203 SS/SS Centrifugal 0.5 61

Reactors MOC Type Volume (ft3) # Spares

R-101 A/B SS/SS Combustion 100 1

R-301 A/B SS/SS Shell and Tube 1480 1

Storage Tanks MOC Type Volume (ft3)

T-101 SS/SS Fixed Roof 3900




Towers MOC Height (ft) Diameter (ft) # Trays

AB-201 SS/SS 21 1 21

SR-201 SS/SS 12 1 12

Turbines MOC Type Power (HP) # Spares

TB-301 SS/SS Axial 90 1

CTM 14



Process Control Systems

A programmable logic controller (PLC) is used to control the flow rates of the four inlet streams entering

the gasification reactor (R-101). The PLC is connected to two flow controllers placed on the valves of the

inlet steam and oxygen streams. It is also connected to a speed controller attached to the motor of CV-

106, the screw conveyer entering the R-101. Additionally, the PLC is connected to a flow controller for

the inert nitrogen stream, which pressurizes the conveyer entering the reactor. The PLC adjusts the flow

rates of each stream to ensure that the correct ratio of pulverized coal, oxygen, and steam enters the

reactor at the required pressure.

A temperature controller is placed on the valve controlling the flow of an additional steam inlet stream

that is at a lower temperature than the steam reacting with the coal. The additional steam is used to

cool the reactor, since the reactions are exothermic, and the amount of steam required is based on the

temperature of the reactor. If the temperature in the reactor is too high, the additional steam will cool it

down. This temperature controller is vital for the safety of the process, since the gasification reactor is

already subject to high temperatures.

A level controller is placed on the valve controlling the flow of recycle amine from the stripper (SR-201)

to the absorber (AB-201). This will measure the liquid level inside the stripper column. If there is too

much liquid inside the stripper, then the valve will open further and allow more amine to be recycled to

the absorber. This control scheme will help prevent flooding inside the stripper.

A pressure controller is used on the knockout drum (KO-201) directly after the sulfur absorber. This

controller determines how far to open the valve that controls the flow of sulfur-free syngas to the

methanol synthesis section of the process. Higher pressure will result in more syngas flowing from the

knockout drum to the methanol synthesis section.

A flow controller is placed on the valve which controls the amount of sulfur going to the sulfur

treatment plant from the condenser (CD-201) attached to the stripper column. The controller will adjust

the valve depending on how much amine is being recycled into the stripper and how much sulfur is

being stripped from the amine. This will help prevent buildup of both sulfur and amine in the stripper.

A pressure controller is used on the compressor at the beginning of the methanol synthesis section of

the process (CP-301). The controller is also connected to the valve controlling the superheated steam

that drives the adjacent turbine (TB-301), which is being supplied by HX-101A. Additional steam will be

supplied to the turbine, which will provide more energy to the compressor in order to increase the

pressure of the syngas going into the methanol reactor (R-301). The compressor will pressurize the

syngas to 725 psi, which is the operating pressure of the methanol reactor.

A temperature controller is placed on HX-301, which is directly before the methanol reactor. The

exchanger will provide any additional heat that is needed using steam, since the methanol reaction must

CTM 15



take place at 482℉. The compressor will heat up the syngas while pressurizing it, so the amount of

additional heat needed will vary. The amount of steam needed will be determined using the

temperature controller.

A temperature and pressure controller is placed on the valve controlling the amount of steam going into

HX-302, which cools the stream leaving the methanol reactor. The steam flow rate will be adjusted

depending on how much cooling is required going from the methanol reactor to the first flash drum

separator (FD-301). The flash drum operates below the boiling point of methanol, so the waste gases

will go out the top and the methanol product will come out the bottom stream.

An additional temperature and pressure controller is placed on the valve that controls the amount of

boiler water going into R-301. The optimal temperature range for the catalyst is 390℉-590℉, and the

reaction occurring in R-301 is exothermic. Therefore, the cooling water will ensure that the temperature

of the reactor stays within the range where the catalyst is most effective. The amount of water needed

will depend on the temperature and pressure of the reactor, which will both increase as the reaction

goes to completion.

A pressure controller is placed on the valve controlling the flow of waste gas to the offsite air treatment

plant. If the pressure becomes too high leaving the second flash drum (FD-302) then a portion of the gas

will be redirected to the emergency flare. This will prevent buildup of pressure inside the flash drum and

will only be used in emergency situations.

CTM 16



Operating Requirements

The plant will operate 47 weeks out of the year, 24 hours per day, with 5 weeks of down time. Planned

downtime was based off of Shell Coal Gasification Process (SCGP) plants in China, which typically

operate more than 300 days per year [3].

Utilities

Utilities consist of high pressure steam, low pressure steam, cooling water, and electricity. The cost per

BTU basis for each utility is summarized in the table below. The cost of utilities was calculated to be

$74.98 per hour.

Table 2: Utility Cost Basis ($/BTU)

Cooling Water 4.04E-07

fired heater 90% efficient 1.41E-05

HP Steam 2.02E-05

LP Steam 1.52E-05

Electric 1.92E-05

Labor Requirements

A total of 28 operating personnel will be employed at the plant and 6 employees are required per shift,

two for the gasification unit, two for the sulfur removal unit, and two for the methanol production unit.

Waste Streams

Waste treatment costs include disposal of sulfur-containing compounds from the sulfur removal unit

(hazardous), unreacted syngas from the flash drum (non-hazardous), and waste water from the knock-

out drum.

Catalyst Requirements

The catalyst requirements for the process are the Cu/ZnO/Al2O3 catalyst used in the methanol synthesis

reactor. The catalyst was assumed to have a lifetime of 3-5 years.

Table 3: Catalyst Requirements

# Tubes 2,094

Tube length 16 ft

Tube diameter 0.41 ft

Tube volume 822 ft3

Amount of cat 33,876.74 lb

CTM 17



Environmental Concerns/Waste Minimization/Sustainability

This process creates several waste streams that contain hazardous products. The primary product,

methanol, is also a hazardous material.

Slag is a glass-like byproduct that is created when coal is heated at high temperatures. In this process,

Pittsburgh coal is heated to 2,900 °F in order to gasify it, and the metal compounds in the coal are

burned, creating slag. The molten slag flows out of the reactor, wand is pumped into a quenching tank

where it will solidify. These solid masses of slag will be pulverized to a standard particle size and sold.

Gasification slag is especially useful in industry due to its leachability characteristics, and can be sold to

various markets for use in asphalt, Portland cement, construction structural backfill, and many other

applications [13] [14]. The amount of slag produced cannot be minimized, so safety precautions are put

in place to ensure it is safely contained. Since the main concern with the slag is the high temperature, it

will be contained in insulated lines that keep the temperature under control and reduce the risk for

fires.

Hydrogen sulfide (H2S), carbon disulfide (CS2), and carbonyl sulfide (COS) are all created in the

gasification process. These compounds are dangerous and harmful to the environment. All of these

sulfur compounds leave the process directly in the waste stream coming from the amine regenerator.

This stream will be reclaimed and sent to a sulfur plant, which will react these compounds to form

elemental sulfur.

H2S is a combustible sulfur compound that is extremely hazardous to human health. It is characterized

by its rotten-egg odor at very low concentrations, however, it is not detectable by odor at toxic

concentrations (which are relatively moderate). Exposure to low concentrations of H2S has been linked

to human health effects, such as eye, skin, and respiratory irritation. Hydrogen sulfide is also corrosive

to metals. There need to be several lines of defense against H2S releases. First, all pieces of equipment

that are in H2S service need to be made of stainless steel to avoid corrosion; there also needs to be signs

in the area warning of H2S presence. Additionally, all personnel who work in areas where H2S can be

present must wear personal H2S monitors to ensure they are not exposed without their knowledge [15]

[16].

COS is a colorless, flammable gas identifiable by its unpleasant odor. When COS is in the presence of

humidity (as would be likely if a release occurred), it decomposes to carbon dioxide and hydrogen

sulfide. It is important to avoid the release of COS because if it does not decompose, it can cause serious

health effects to humans, such as convulsions and respiratory paralysis. Releases of COS will not cause

significant environmental effects [17].

CS2 is a colorless, volatile liquid. In humans and animals, CS2 is absorbed by the lungs and can result in

local irritation and pharyngitis and central nervous system effects; long term exposure results in

CTM 18



neurological and cardiovascular effects. CS2 will evaporate from water and soil into the atmosphere,

and does not cause significant environmental effects [18].

There is no way, unfortunately, to reduce the production of sulfur compounds in the syngas; the sulfur

compounds are formed by the sulfur present in the coal, so the only possible way to reduce the

production of sulfur compounds would be to choose a different coal for feed stock that contained less

sulfur. The coal chosen is the best for the application, so it will not be changed to reduce the sulfur

compounds. Instead, there will be extra safety precautions taken to ensure proper handling of these

materials.

The sulfur gases will be sent to a sulfur plant, which will be purchased as a “stock” unit, which will be

purchased as a fully functional unit on which no extra design is required, and placed on the plant

grounds close to the sulfur removal unit. The sulfur plant will process the sulfur gas in clause units and

produce an end product of elemental sulfur; this elemental sulfur will be sold as an additive to concrete

or sulfur enhanced fertilizers [19].

Syngas is reacted in the methanol reactor to form methanol, but there is some unreacted gas in the

product stream. This gas is recovered from the methanol and recycled into the reactor feed, to increase

total conversion and to decrease the waste stream amount. However, there are some components that

do not react in this gas stream, so there is a purge to avoid buildup of inert gases in the system. The

purge stream contains some greenhouse gases, such as carbon dioxide, and other dangerous gases like,

nitrogen. It is imperative that this gas stream is not released directly to the atmosphere, as it will give off

toxic emissions. The purge gas will first be sent through a carbon dioxide sequestering system to recover

carbon dioxide left in the stream. These units are produced and created by other companies, so it will be

purchased as a functioning unit and fit into the process; no design is needed in this section, as it is a

"stock" unit and will be purchased as a fully functional unit. Next, the purge gases will be sent to a flare

before releasing to the atmosphere to reduce toxic emissions [20].

Water is removed from this process after the sulfur removal step; this water must be treated as waste

water because it can contain traces of other harmful chemicals, and has the potential to be hazardous.

The waste water stream will be sent off-site to be treated by a local industrial waste water treatment

facility, such as a close-by refinery or chemical plant; the waste will not be able to be treated in a

municipal water treatment facility due to its contamination with amine and other compounds. This

water has the potential to contaminate groundwater under unusual circumstances, such as a line leak,

so there will be secondary containment around the waste water streams and holding tanks to avoid this

hazard. The amount of water created in the gasification step is minimized by carefully maintaining a

ratio coal:steam:oxygen ratio of 10:1:1. This reduces the amount of water formed while ensuring a

syngas composition high in hydrogen and carbon monoxide.

CTM 19



There are many potential pollutants and hazardous chemicals present in this process, but the hazards

can be avoided by extra equipment and containment measures that reduce the chance of

environmental releases.

Table 4: Sustainability Metrics

Metric

Material Intensity 43.7 % (kg/kg)

Energy Intensity 43.37 MJ/kg

Water Intensity 12,105.88 kg/kg

Toxic Emissions 1.32 kg/kg

Greenhouse Gases 1.42 kg/kg

The first metric calculated was the Material Intensity, which investigates the amount of raw materials

the process uses and how it relates to the amount of product produced, in this case, methanol. Overall,

43.7% of our inputs are not manufactured into the final product. Of this 43.7% is either excess gas that is

being used elsewhere or is a waste product that must be removed from the process.

𝑀𝑎𝑡𝑒𝑟𝑖𝑎𝑙 𝐼𝑛𝑡𝑒𝑛𝑠𝑖𝑡𝑦 =𝑀𝑎𝑠𝑠 𝑜𝑓 𝑅𝑎𝑤 𝑀𝑎𝑡𝑒𝑟𝑖𝑎𝑙𝑠 − 𝑀𝑎𝑠𝑠 𝑜𝑓 𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑠

𝑂𝑢𝑡𝑝𝑢𝑡𝑠

The second metric studied was the energy intensity. This metric examines amount of energy the process

needs to create a kilogram of methanol produced. Hot streams within the plant were used in heat

exchangers to recycle energy and help reduce the overall energy consumption.

𝐸𝑛𝑒𝑟𝑔𝑦 𝐼𝑛𝑡𝑒𝑛𝑠𝑖𝑡𝑦 = 𝑁𝑒𝑡 𝐹𝑙𝑢𝑒 𝐸𝑛𝑒𝑟𝑔𝑦 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑 (𝑀𝐽)


Water Intensity addresses the amount of fresh water used in the process. The fresh water accounts for

steam, cooling water, and general utilities water along with the water that goes into the process for the

gasification reaction. This number is very large due to the large amount of cooling that takes place after

the gasification reaction. There is also a constant loss of sulfur-containing water in the amine stripper

requiring constant renewal of that water.

𝑊𝑎𝑡𝑒𝑟 𝐼𝑛𝑡𝑒𝑛𝑠𝑖𝑡𝑦 = 𝑀𝑎𝑠𝑠 𝑜𝑓 𝐹𝑟𝑒𝑠ℎ 𝑊𝑎𝑡𝑒𝑟 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑 (𝑘𝑔)


The metric for Toxic Releases measures the amount of toxic chemicals according to Environmental

Protection Agency's Toxic Release Inventory Chemical List for 2014. In this specific process, the

chemicals that are accounted for under the list are water (because it contains trace other chemicals and

has to be treated like toxic waste), carbonyl sulfide, hydrogen sulfide, carbon disulfide, ammonia, and

slag. The releases are combated by water treatment and the sulfur removal process.

CTM 20



𝑇𝑜𝑥𝑖𝑐 𝑅𝑒𝑙𝑒𝑎𝑠𝑒 = 𝑀𝑎𝑠𝑠 𝑜𝑓 𝑇𝑜𝑥𝑖𝑐 𝑃𝑜𝑙𝑙𝑢𝑡𝑎𝑛𝑡𝑠 𝑖𝑛 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠 𝑎𝑛𝑑 𝑊𝑎𝑠𝑡𝑒 (𝑘𝑔)


The final metric reviewed is Greenhouse Gas emissions which takes any emissions that are considered to

be greenhouse gases and relates them to carbon dioxide. The chemicals considered were carbon

dioxide, carbon monoxide, methane, and nitrogen dioxide. This section also takes into account the

carbon emissions from powering the plant.

𝐺𝑟𝑒𝑒𝑛ℎ𝑜𝑢𝑠𝑒 𝐺𝑎𝑠𝑒𝑠 =𝐶𝑂2 𝐸𝑞𝑢𝑖𝑣𝑎𝑙𝑒𝑛𝑡 𝑓𝑟𝑜𝑚 𝐹𝑢𝑒𝑙, 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠, 𝑎𝑛𝑑 𝑊𝑎𝑠𝑡𝑒 (𝑘𝑔)


CTM 21



Safety Considerations

Within the gasification process, the temperature and pressure reach conditions that cause the coal to

partially combust. The coal increases the risk of explosion so it is crucial to ensure the oxygen level does

not exceed the flammable limit. The particle size of coal also creates an inhalation hazard. Workers in

this area should have inhalation PPE, such as respirators, to prevent exposure to coal dust [21].

Since reactor the gasification reactor receives a pure oxygen feed, it is important to ensure the oxygen

does not combust before entering the vessel. To combat this risk, oxygen will not be stored on site and

instead will be made at a separate plant then transported via pipeline on site. Oxygen is fed at the exact

rate it needs to be consumed, so that there is no accumulation of unreacted oxygen in the system. The

pipeline that feeds the oxygen will be fitted with explosion arrestors to prevent an explosion from

flowing back to the production plant; explosion arrestors are pieces of equipment that are composed of

smaller pipes, similar to the design of a heat exchanger, filled with mesh to help dissipate the flame

front and stop the explosion from propagating. Oxygen level sensors around the reactor ensure the air

around the reactor does not become oxygen rich.

The waste stream exiting leaving the gasifier contains molten slag, which contains many heavy metal

materials that need to be treated. A water bath below the gasifier collects the molten slag where it cools

it to a solid. Once the slag solidifies, it can be transported without releasing these dangerous materials.

The gasifier outlet stream contains carbon monoxide, carbon dioxide, water, hydrogen gas, and sulfur

compounds. Hydrogen gas makes up most of the syngas, creating a safety risk since hydrogen is highly

combustible in the presence of oxygen [22]. To prevent hydrogen leaks in this pipeline, there will be

limited welds in the pipeline, as well as sensors to monitor the hydrogen gas and carbon monoxide

concentration in the space surrounding the pipeline. To prevent fires, the surrounding pipeline will be

monitored for hydrogen leaks using hydrogen sensors. Carbon monoxide is an odorless and colorless

toxic gas, so sensors are needed to ensure the safety of the operators in the area around the process.

Carbon dioxide also has associated health risks at low concentrations so monitors will also need to be

installed. Since carbon dioxide is also an environmental risk, its treatment is also talked about in the

environmental section of this report.

The sulfur components that exit the gasifier are removed through an amine absorption column. In order

to avoid release of the sulfur compounds, limited welds between the gasifier and the sulfur removal

system. Sulfur is extremely corrosive and needs to be removed as soon as possible from the system to

reduce risk. Besides being corrosive, the biggest risk of the sulfur compounds is the toxicity of H2S. The

sulfur present in the coal forms H2S in the gasification reactor; H2S is extremely toxic at low

concentrations that are not detectable by odor. This area will need to be monitored with H2S sensors,

have posted signs warning of the possibility of H2S presence in the air, and the required PPE in this area

will include personal H2S sensors. The sulfur compounds are absorbed into the amine when the two

come into contact. The rich amine, containing the sulfur compounds, is then stripped with steam,

CTM 22



leaving a stream of purely sulfur compounds. This stream will be sent to a sulfur plant to treat the gas

and produce elemental sulfur. Leaving the sulfur removal process, all that remains in the syngas is

carbon monoxide, carbon dioxide, water, which is removed immediately using a knock-out drum, and

hydrogen gas.

Methanol is created from the syngas in the methanol reactor unit. Methanol is a relatively harmless

chemical but it poses an explosion hazard, and it must be stored at away from potential spark sources

and at ambient temperatures. Methanol can easily flash if near an open flame. Methanol is a problem

when a large spill occurs overwhelming the surrounding area. Methanol easily breaks down in the

environment making it relatively benign environmentally, but is still a safety hazard.

Water and steam are used throughout the process as reactants and as a form of temperature control.

The water that is removed from the process will need to be treated in a wastewater treatment area to

remove any trace sulfur compounds, amines, or heavy metals. Waste water monitoring sensors will

allow for excess sulfur or heavy metal concentrations to be detected before they reach wastewater

treatment and allow for the plant to avoid fines associated with water treatment and impurities.

All the pieces of equipment that are needed to ensure the safety of the process will need to be put on a

maintenance schedule; a maintenance calendar prevents the plant from using emergency equipment to

continue production. When installed, the equipment will be evaluated for its criticality and proper

maintenance procedures will be attached to the appropriate equipment pieces.

CTM 23



Economic Feasibility for Base Case

To determine if the plant would be profitable to build, the payout period, which is the number of years it

takes to turn a profit, is calculated by finding the time it takes for the plant to have a positive cumulative

cash flow. Cumulative cash flow is the total revenue generated by the products (methanol, hydrogen,

and slag), minus all of the costs of production, which include: capital costs (land, equipment, and startup

MDEA cost); manufacturing costs such as labor, utilities, waste treatment, and raw materials; taxes; and

depreciation. The tax rate and inflation rate were assumed to be 39.0% and 2.0% respectively, and

depreciation was assumed to be linear over an 11-year period, with a salvage rate of 10% of the initial

investment. The economic analysis covers a span of 17 years, from 2015-2031.

The grassroots capital cost of the project is $6.30 MM, and the yearly cost of manufacturing is $10.82

MM (2015); the breakdown for which can be seen in Table 5. The plant profits $1.76 MM per year

(2015) from sales. This means that at the current rates, the project would never be able to turn a profit.

The economic calculations include two years for construction, during which there is no revenue. A

cumulative cash flow diagram over the span of the project is shown below (Figure 1), and an exhaustive

account of the cash flow over time can be seen in Table C.3 of Appendix C.

Figure 1: Cumulative Cash Flow ($MM)

CTM 24



Table 5: Economics Summary

Cost $/year

Capital Cost* $6,304,280

Cost of Labor $1,481,200

Cost of Utilities $581,271

Cost of Waste Treatment $4,423,270

Cost of Raw Materials $371,996

Cost of Manufacturing $10,833,336

Revenue ($/yr) $1,758,647

Payout Period (yr) N/A

*Total Capital Cost, not on yearly basis

Capital Cost All prices for equipment were based on the sizing information listed in Table 6 and were calculated using

CapCost, with the exception of the equipment listed in the Miscellaneous section of the table. The

equipment in the Miscellaneous section were not available in CapCost, and are based off of supplier

estimates found on J&M Industrial’s website. The total bare module cost for the equipment is $3.36

MM, and the total grassroots cost is $5.35 MM. Grassroots cost can be estimated as 1.6 times the bare

module cost [25].

In addition to equipment cost, the cost of land, and the cost of MDEA needed at start-up were also

added to the total capital cost. Land cost was estimated at $600,000, and the cost of MDEA was at

$9,000. Additional MDEA needed during production to make up for loss is accounted for in the raw

material costs.

CTM 25



Table 6: Capital Cost

Compressors MOC Compressor Type Power (HP) #Spares Purchase Cost Bare Module Cost Grass Roots Cost

CP-301 SS/SS Rotary 90 1 $79,900 $402,000 $571,000

Drums MOC Height (ft) Diameter (ft) Pressure (psi) Purchase Cost Bare Module Cost Grass Roots Cost

FD-301 SS/SS 7 2.3 725 $3,630 $89,700 $108,000

FD-302 SS/SS 2.3 0.8 725 $2,470 $29,400 $36,000

KO-201 SS/SS 6 2 350 $4,540 $42,000 $606,000

Exchangers MOC Type Pressure (psi) Area (ft2) Purchase Cost Bare Module Cost Grass Roots Cost

HX-101A T/T Double Pipe 350 20 $3,270 $63,400 $80,000

HX-101B SS/SS Double Pipe 350 6 $2,780 $16,600 $24,200

HX-101C SS/SS Double Pipe 350 19 $3,230 $19,300 $28,100

HX-201 SS/SS Double Pipe 350 50 $4,040 $24,100 $35,100

HX-202 SS/SS Multiple Pipe 350 170 $7,090 $42,300 $61,600



Filters MOC Type Pressure (psi) Purchase Cost Bare Module Cost Grass Roots Cost

F-301 SS/SS Membrane 725 $190,000 $284,000 $430,000

Miscellaneous MOC Type Length Power (HP) Purchase Cost Bare Module Cost Grass Roots Cost

CR-101 SS/SS 100 60 $9,500 $9,500 $16,000

CV-101 SS/SS Screw Conveyor 16 5 $10,000 $10,000 $16,800




BV-101 SS/SS Belt Conveyor 70 15 $8,200 $8,200 $13,800

EV-101 SS/SS Elevator 50 15 $5,800 $5,800 $9,740

EV-102 SS/SS Elevator 50 15 $5,800 $5,800 $9,740

Pumps MOC Type Power (HP) Press,out (psi) Purchase Cost Bare Module Cost Grass Roots Cost

P-201 SS/SS Centrifugal 17 407 $10,900 $70,700 $101,000

P-202 SS/SS Centrifugal 2 407 $6,370 $41,400 $59,200

P-203 SS/SS Centrifugal 0.5 61 $6,170 $30,700 $46,200

Reactors MOC Type Volume (ft3) #Spares Purchase Cost Bare Module Cost Grass Roots Cost

R-101 A/B SS/SS Combustion 100 1 $186,900 $280,200 $424,000

R-301 A/B SS/SS Shell and Tube 1480 1 $85,400 $128,000 $194,000

Storage Tanks MOC Type Volume (ft3) Purchase Cost Bare Module Cost Grass Roots Cost

T-101 SS/SS Fixed Roof 3900 $55,300 $60,800 $102,000

TS-401 SS/SS Fixed Roof 6684 $62,500 $68,700 $115,000



Towers MOC Height (ft) Diameter (ft) # Trays Purchase Cost Bare Module Cost Grass Roots Cost

AB-201 SS/SS 21 1 21 $31,000 $414,000 $511,000

SR-201 SS/SS 12 1 12 $17,500 $46,400 $67,100

Turbines MOC Type Power (HP) #Spares Purchase Cost Bare Module Cost Grass Roots Cost

TB-301 SS/SS Axial 90 1 $189,000 $1,160,000 $1,690,000

Total $1,152,940 $3,561,300 $5,695,280

CTM 26



Cost of Manufacturing The total cost of manufacturing (COM) was calculated using the equation below [25]:

𝐶𝑂𝑀 = 0.028 ∗ 𝐶𝑐𝑎𝑝 + 2.73 ∗ 𝐶𝑂𝐿 + 1.23 ∗ (𝐶𝑈 + 𝐶𝑊𝑇 + 𝐶𝑅𝑀)

In this equation, Ccap is the total capital cost, and COL, CU, CWT, and CRM are the costs of operating labor,

utilities, waste treatment, and raw materials, respectively. All of these costs were calculated for 2015,

and were adjusted by the inflation rate when looking at the profitability of the plant over its lifetime.

Cost of Operating Labor To calculate the cost of labor, the number of operators per shift (Nop/shift in Table 7) had to be

calculated using the equation below [25]:

𝑁𝑜𝑝/𝑠ℎ𝑖𝑓𝑡 = √6.29 + 31.7 ∗ 𝑃2 + 0.23 ∗ 𝑁𝑛𝑝

P, which the number of processing steps involving particulate solids, is 1 (for the handling of pulverized

coal). Nnp, the number of nonparticulate processing steps, is fifteen (two columns, two flash drum, two

reactors, one compressor, one turbine, and seven heat exchangers). Assuming the plant needs 6

operators per shift, and 4.5 operators for every one operator per shift, the total number of operators

came out to 28. Multiplying this by an average salary of $52,900 resulted in the total operating cost of

$1.48 MM per year (2015).

Table 7: Cost of Labor Calculations

Nnp 15

N_op/shift 6

N_op 28

Salary $52,900

Cost of Labor $1,481,200

CTM 27



Cost of Utilities

The cost of utilities was estimated for most pieces of equipment using the heat duties for the equipment

from the Aspen models. This does not include pumps, and the items in the Miscellaneous section of the

capital cost table, which were calculated by converting the horsepower of the motor to BTU/hour, and

using this number to estimate electricity cost. Using these energies, utility costs for each piece of

equipment were calculated by multiplying the amount of energy needed by the cost of the basis utility

(electric, cooling water, etc.). Both heat duties and utility costs per hour of operation are listed in Table

9, and the price per BTU of energy for each basis utility (which come from Analysis, Synthesis, and

Design of Chemical Processes [25], and are adjusted to 2015 prices for inflation) are listed in Table 8.

Total cost per year for utilities $0.58 MM. This estimate only accounts for the utilities needed to run the

process, and does not account for auxiliary on-site buildings.

Table 8: Utility Cost Basis ($/BTU)

Cooling Water 4.04E-07

HP Steam 2.02E-05

LP Steam 1.52E-05

Electric 1.92E-05

CTM 28



Table 9: Energy Balance and Utilities

Equipment Energy

In Energy

Out

HP Steam Cost

LP Steam Cost

Cooling Water Cost Electric

BTU/h BTU/h $/h $/h $/h $/h

AB-201 - - - - - -

BV-101 38,167 - - - - $0.73

CP-301 228,999 - $4.64 - - -

CR-101 152,666 - - - - $2.93

CV-101 12,722 - - - - $0.24

CV-102 12,722 - - - - $0.24

CV-103 12,722 - - - - $0.24

CV-106 12,722 - - - - $0.24

EV-101 38,167 - - - - $0.73

EV-102 38,167 - - - - $0.73

F-301 - 5,169 - - $0.10

FD-301 - 32,349 - - $0.01 -

FD-302 964 - - $0.02 - -

HX-101A - 2,998,346 $60.70 - - -

HX-101B - 212,383 - $5.31 - -

HX-101C - 262,355 - - $0.11 -

HX-201 84,819 - - - - -

HX-202 - - - - - -

HX-301 - - - - - -

HX-302 - 750,602 - - - -

KO-201 - - - - - -

P-201 43,510 - - - - $0.84

P-202 8,899 - - - - $0.17

P-203 1,272 - - - - $0.02

R-101A/B - - - - - -

R-301A/B - - - - - -

SR-201 - - - - - -

T-101 - - - - - -

T-401 - 228,999 - - - -

T-402 686,517 4,490,204 - - - -

T-403 - - - -

TB-301 - 228,999 -$4.64 - - -

Total $60.70 $5.33 $0.12 $7.24 $73.39

CTM 29



Cost of Waste Treatment The cost of waste treatment was estimated by analyzing the streams exiting the process that do not

contain sellable product, which include: the sulfur waste stream (hazardous, 1115), the water stream

from the knock-out drum (waste water, 1121), and the waste gas stream after the separations (non-

hazardous, 1222). The cost of treating of these streams was based on information from Analysis,

Synthesis, and Design of Chemical Processes [25], and adjusted to account for inflation. The total waste

treatment cost per year is $4.42 MM, a breakdown for which can be seen in Table 10.

Table 10: Waste Treatment Cost

lb/h $/lb $/h

Disposal, hazardous 1,000.00 0.54 $540.90

Disposal, nonhazardous 71.73 0.02 $17.59

Water Treatment 4.00 0.000020 $0.0001

Total $558.49

Cost of Raw Materials The cost of raw materials was estimated by finding the price per pound of the raw material, and

multiplying by the total number of hours in operation. A few different sources were needed in order to

find prices for all of the materials. Table C.4 of Appendix C lists the price of the material as found in the

sources, a conversion of the found value to a per pound basis, and a final price in 2015 dollars. These

prices are then multiplied by the total amount of material required to get a total raw material cost of

$0.37 MM per year. (Table 11) Total revenue from the product streams is $1.76 MM per year.

The cost of catalyst is also included in these calculations. Since the catalyst has to be changed out every

five years or so, the cost of the total amount of catalyst needed in the methanol reactor is divided over

this time period to come up with a per hour cost.

Table 11: Production Profits

Unit Price Amount In Amount Out Total Profit

Material $/lb lb/h lb/h $/h

Coal $0.031 1,000 - (31.38)

Oxygen $0.03 100 - (2.80)

Steam* $0.015 101 - (1.54)

MDEA $0.897 0.00025 - (0.00)

Methanol $0.20 - 835.13 168.09

Slag $0.53 - 94.40 50.33

Hydrogen $0.03 - 137.20 3.63

Catalyst $11.65 0.967 - (11.26)

Total Hourly Production Profit $183

Total Yearly Production Profit $1,447,078

CTM 30



Economic Uncertainty and Sensitivity

The project is not feasible because of the high operating costs, and pilot plant size of the process. Since

the base case for the project is not feasible, a sensitivity study was done to see how the price paid for

the products would have to change in order for the process to turn a profit over the life of the project.

This was done by varying sale price of the products (the initial cost of products, $0.21/lb, was found by

taking a weighted average of the prices of the three sellable products), and calculating the cost of

manufacturing that would result in a DCFROR of 0. This would mean, that although no profits were

earned, the project would at least break even.

Figure 2 shows a graph of cost of manufacturing v. sale price of the products, and Table C.5 of Appendix

C shows the data points that were plotted in this graph. In order for the process to break even at its

current operating costs, the price of the products would have to rise 750%, to $1.79/lb.

Figure 2: Cost of Manufacturing v. Product Sale Price

One of the major issues for the process is the cost of waste treatment. The sulfur removal section of the

plant produces about 1000 lb/hour of hazardous waste. That stream alone costs $4.28MM per year to

treat. The majority of this steam (94.4%) is water lost from the amine; clean water is later added back to

the process to account for this loss. If water loss was reduced, waste treatment costs for the year could

be reduced to $0.44MM per year, resulting in a total yearly cost of manufacturing of $5.93MM. This

would still be more than the plant makes in material revenue for the year, however, it would reduce the

break-even price of products to just over $1/lb ($1.004). This is still a 377% increase from where the

current prices are, but that is far less than the 750% increases needed for the base case cost of

manufacturing. Moreover, this decrease, coupled with an increase in production rates, would likely

make the process profitable overall.

The process produces materials that are of a higher value than the raw materials that go into it. Since

annual revenue would likely increase linearly, while manufacturing costs are likely to increase at a

decreasing rate as the size of the plant increases, it is probably that higher production rates would make

this process feasible.

CTM 31



Process Optimization

The original process model had room for improvement. The process was on a small, pilot-plant scale;

commodity chemicals such as methanol are usually produced in large quantities to maximize profits. The

process also had multiple, large pressure changes throughout the different sections of the process;

these pressure changes necessitated extra equipment that increased capital and utility cost for the

process. There was also an undesirable mixture of syngas; the syngas contained carbon dioxide as well

as carbon monoxide, where it is most desirable in this process to only have carbon monoxide. These

shortcomings of the process decrease profitability and were analyzed to see if improvements and

process optimizations could be made.

Two process optimizations were done to improve the process performance and to save money on utility

and operation costs. The first was an optimization of the gasification reactor to increase the amount of

carbon monoxide produced and decrease the amounts of carbon dioxide produced. Carbon monoxide is

the desired reactant in the methanol reactor since it reacts with hydrogen in the presence of the catalyst

to form methanol. This reaction is efficient and produces the desired product with no by-products.

Carbon dioxide reacts undesirably to form methanol and water which are very difficult to separate, as

they have an azeotrope. The minimization of carbon dioxide, and consequently water, in the process

helps to simplify the separation of the methanol product and ensure a high product quality. Pinch point

analysis was done on the gasification Aspen file in order to find the correct ratio of feed components

and the correct temperature and pressure to create the desired syngas stream. The feed rate of steam

and water, the reaction temperature, and the reaction pressure were varied to find what resulted in the

most desirable syngas mixture. The table below shows the results.

Table 12: Gasification Optimization Study

Water Flow Oxygen Flow Temperature Pressure CO2 CH4 CO H2 O2 H2S

lb/hr lb/hr F psi lb/h lb/h lb/h lb/h lb/h lb/h

101 100 2,600 725 3.48 35.25 759.65 257.94 trace 61.67

51 100 2,600 725 1.53 67.97 703.76 245.52 trace 61.94

201 100 2,600 725 13.89 9.49 798.01 268.13 trace 61.99

101 50 2,600 725 1.40 73.02 695.04 249.91 trace 61.96

101 200 2,600 725 16.17 7.96 799.21 256.21 trace 61.96

101 100 2,500 725 5.00 42.91 745.32 255.11 trace 61.98

101 100 2,700 725 2.44 29.62 770.13 260.02 trace 61.94

101 100 2,600 350 1.39 22.24 783.66 262.79 trace 61.90

101 100 2,600 600 2.79 30.92 767.65 259.55 trace 61.95

101 100 2,900 350 0.39 16.52 794.18 264.91 trace 61.65

CTM 32



It was found that feeding steam and water at 100 lb/hr into the reactor at 2,900 °F and 350 psi produces

a syngas stream with minimal carbon dioxide and maximum carbon monoxide; the carbon monoxide

content in the stream is 794 lb/hr while carbon dioxide is only 0.39 lb/hr. This ratio allows for full

conversion of the carbon monoxide into methanol with almost no production of water. The resultant

methanol stream can be purified to 99.98% methanol.

The second process optimization done was to increase the pressure of the sulfur removal section to

reduce the pressure changes throughout the process. Initially, the absorber column (AB-201) in the

sulfur removal section operated at atmospheric pressure. This meant that the system pressure, which

was 350 psi in the gasification section, would go from 350 psi to 14.7 psi, then back up to 725 psi in the

methanol section. To facilitate these pressure changes, there was a turbine to reduce the pressure from

350 psi to 14.7 psi before the sulfur removal section, and a compressor to increase the pressure after

the sulfur removal section from 14.7 psi to 725 psi. Compressors and turbines are both expensive pieces

of equipment that require a lot of utilities to operate; increasing the pressure would reduce the need for

this equipment. Pinch point analysis was used to understand how the increase in pressure would affect

the removal of sulfur. The pressure of the absorber column was incrementally stepped up to find the

optimum pressure for sulfur removal. The table below shows the results.

Table 13: Sulfur Removal Optimization Study

AB-201 Pressure Turbine Size H2S in Sweet Gas

psi HP lb/hr

14.7 102.8 7.51E-05

20 96.5 5.50E-05

50 74 3.03E-05

100 52.3 2.48E-05

200 25.8 2.27E-05

300 7.54 2.86E-05

350 0 2.25E-05

The removal of sulfur increased with increasing pressure, so it was decided to operate the sulfur

removal section at 350 psi. This removed the need for pressure reduction before the unit, and

minimized the size of the compressor needed to increase the system pressure before the methanol

reactor.

Unfortunately, the process could not be scaled up to a large-scale, commodity chemical sized operation

due to limitations of the Aspen software. Upon attempts to scale the process up by five and ten times,

the Aspen files would not converge to a solution; the software was unable to adequately scale up the

process. It is understood that this process is currently modeled as a pilot-sized plant and it is difficult to

CTM 33



calculate how profitable the process would be if it were scaled up without a properly functioning model

in Aspen, as scaling is not linear, so there is no accurate way to predict the profits of the plant.

Table 14: Sustainability Metrics Comparison

Metric Previous Metrics Current Metrics

Material Intensity 58.80 % (kg/kg) 43.70 % (kg/kg)

Energy Intensity 116.51 MJ/kg 43.37 MJ/kg

Water Intensity 49.06 kg/kg 12,105.88 kg/kg

Toxic Emissions 0.33 kg/kg 1.32 kg/kg

Greenhouse Gases 2.15 kg/kg 1.42 kg/kg

Overall, the material, energy, and greenhouse gas sustainability metrics have improved due to the

optimization. The metric that changed the most drastically is the water intensity due to the changes in

the sulfur removal section. The amount of water needed to ensure proper removal of sulfur was not

correctly accounted for in the Interim report, and fixing this problems has caused it to increase greatly.

The problem with this large amount of water is that it contains sulfur and must be treated as toxic

waste. The sulfur impurities in the water can also explain why the toxic emissions metric has also

increased, as the sulfur compounds are toxic. With the optimization, all of the sulfur, along with other

toxic chemicals, are being removed and are accounted for in the toxic emissions metric.

CTM 34



Conclusions and Recommendations

This feasibility study describes a process that uses bituminous coal as a raw material to create methanol.

On the basis of 1,000 lb/hr of coal processed, methanol is produced at a rate of 835 lb/hr with a purity

of 99.9% by weight. The grassroots capital cost is estimated to be $8.6 million. The yearly cost of

operation is estimated at $10.8 million, and the plant creates an annual revenue of $1.45 million. It can

be seen here that the plant is not profitable at the current capacity.

While not profitable, the methanol production process operates successfully and the technology could

be applied as a cleaner coal-to-fuel process.

There are a few ways to improve upon the profitability of the plant, the first being increasing the

production rate. If the plant were to be scaled up by at least a factor of ten, then the amount of revenue

generated would be ten-fold of what is currently being made, if methanol prices stay stable. However,

the cost of manufacturing would not increase ten-fold since it is not a linear relationship. A plant that is

ten times the size of the current capacity will not need ten times the labor required to run. Additionally,

the equipment would not need to be ten times as large if the process were scaled up, and would not

need ten times the amount of energy to run. Capital costs would also not increase linearly with scale up,

however it will still increase due to larger and more pieces of equipment. Finally, reducing waste is

another way to lower the cost of manufacturing. Currently, waste treatment of the sulfur compounds

accounts for about half of the total manufacturing costs. If the waste streams were decreased then the

cost of manufacturing would decrease, resulting in a higher possibility of the process becoming

profitable.

The result of this feasibility study is that this process as designed is not profitable and would result in a

net loss that increases over time. Increasing the plant production rate would increase product revenue

linearly while the equipment, energy, and labor costs would increase at a lower rate. Reducing waste

streams would also cut back the manufacturing costs significantly. It is for these reasons that most

commodity chemicals are produced on a much larger scale, because the economic margins increase as

the production rate increases, therefore is advantageous to manufacture as much product as possible.

CTM 35



References

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[5] 2015. [Online]. Available: http://denr.sd.gov/Hyperion/Air/Ref/10%20Year%20Operating%20Experience%20Presentation.pdf. [Accessed: 08- Mar- 2015].

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CTM 36



redir=1&referer=http%3A%2F%2Fwww.google.com%2Furl%3Fq%3Dhttp%253A%252F%252Fscholarworks.sjsu.edu%252Fcgi%252Fviewcontent.cgi%253Farticle%253D7695%2526context%253Detd_theses%26sa%3DD%26sntz%3D1%26usg%3DAFQjCNHZa9YidL7cJJZgUBnnkoSnAyCHVA#search=%22http%3A%2F%2Fscholarworks.sjsu.edu%2Fcgi%2Fviewcontent.cgi%3Farticle%3D7695%26context%3Detd_theses%22. [Accessed: 08- Mar- 2015].

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CTM 37



[22] 'Hydrogen Safety', 2015. [Online]. Available: http://www.arhab.org/pdfs/h2_safety_fsheet.pdf. [Accessed: 08- Mar- 2015]. [23] Eia.gov, 'Coal News and Markets - Energy Information Administration', 2015. [Online]. Available: http://www.eia.gov/coal/news_markets/index.cfm. [Accessed: 08- Mar- 2015].

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[26] Zauba.com, 'Export Data and Price of methyldiethanolamine bulk | Zauba', 2015. [Online]. Available: https://www.zauba.com/export-METHYLDIETHANOLAMINE+BULK-hs-code.html. [Accessed: 08- Mar- 2015].

[27] Methanex.com, ‘Business Pricing’, 2015. [Online]. Available: https://www.methanex.com/our-business/pricing/. [Accessed: 08- April- 2015].

[28] Grainger.com, 'GRAINGER APPROVED Blast Media,Coal Slag,20/40 Grit - Pneumatic Blasting Media - 6YY28|6YY28 - Grainger Industrial Supply', 2015. [Online]. Available: http://www.grainger.com/product/GRAINGER-APPROVED-Blast-Media-6YY28. [Accessed: 08- Mar- 2015]. [29] Icis.com, 'Chemicals A-Z', 2015. [Online]. Available: http://www.icis.com/resources/news/2005/12/08/190713/chemical-profile-hydrogen/ [Accessed: 08- Mar- 2015]. [30] April 2015 Quote from Haldor Topsoe Inc.

CTM 38



Appendix A: Process Design Details

A. Process Flow Diagram

CTM 39



Appendix B: Material Balances Table B.1: Process Stream Table

Str

ea

mD

esc

rip

tio

nT

em

pe

ratu

reP

ress

ure

Ma

ss F

low

Str

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Ma

ss F

low

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psi

lb/h

1001

Raw

Coal from

Barg

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15

1,0

00

1114

Lean M

DE

A fro

m S

R-2

01

215

14.7

9,0

57

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Pulv

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CR

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15

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00

1115

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Ric

h G

as fro

m S

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01

210

14.7

3,0

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1003

Pulv

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T-1

01

70

15

1,0

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1116

Cool G

as t

o C

D-2

01

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3,0

00

1004

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EV

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15

1,0

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Coolin

g W

ate

r75

14.7

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1005

Pulv

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eed t

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Coolin

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ate

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1006

350 p

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1119

Condensed R

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1007

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350

100

1120

Coole

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00

1008

Oxygen

500

350

100

1121

H2S

Ric

h G

as t

o S

ulfu

r P

lant

210

14.7

1,0

00

1009

Oxygen F

eed t

o R

-101A

/B500

350

100

1122

Reflu

x t

o S

R-2

01

--

2,0

00

1010

Nitro

gen

70

350

50

1123

SR

-201 C

ool R

eboil

Str

eam

180

37.7

-

1011

Nitro

gen t

o D

rive

CV

-106

70

350

50

1124

SR

-201 H

ot

Reboil

Str

eam

220

37.7

-

1012

Ste

am

435

350

-1125

Low

Pre

ssure

Ste

am

250

16.0

-

1013

Ste

am

to Q

uench R

-101A

/B435

350

-1226

Low

Pre

ssure

Ste

am

Retu

rn230

16.0

-

1014

Sla

g2,9

00

350

94

1127

SR

-101 R

eboil

Retu

rn220

37.7

-

1015

R-1

01A

/B E

ffluent

Syngas

2,9

00

350

1,1

07

1128

Wate

r from

KO

-201

80

350

5

1016

Hig

h P

ressure

Ste

am

490

400

9,0

41,7

24

1201

H2S

-Fre

e,

Wate

r-F

ree S

yngas t

o C

P-3

01

80

350

1,0

44

1017

Superh

eate

d S

team

Retu

rn600

1,5

00

9,0

41,7

24

1202

Com

pre

ssed S

yngas

261

725

1,0

44

1018

HX-1

01A

Effl

uent

Syngas

1,0

00

350

1,1

07

1203

Superh

eate

d S

team

600

1,5

00

9,0

41,7

24

1019

Low

Pre

ssure

Ste

am

250

16

791,1

51

1204

Superh

eate

d S

team

to D

rive

TB

-301

600

1,5

00

9,0

41,7

24

1020

Low

Pre

ssure

Ste

am

Retu

rn300

55

791,1

51

1205

Ste

am

Retu

rn600

--

1021

HX-1

01B

Effl

uent

Syngas

330

350

1,1

07

1206

CP

-301 D

rive

600

--

1022

Coolin

g W

ate

r75

15

15,8

02

1207

Ste

am

505

715

1,0

00

1023

Coolin

g W

ate

r R

etu

rn100

15

15,8

02

1208

Ste

am

to H

X-3

01

505

715

1,0

00

1101

AB

-101 F

eed S

yngas (

H2S

)120

350

1,1

07

1209

Ste

am

Retu

rn370

715

1,0

00

1102

Lean M

DE

A S

upply

70

350

10,0

00

1210

Syngas F

eed t

o R

-301A

/B330

725

1,0

44

1103

Low

Pre

ssure

Ste

am

307

75

1,0

00

1211

R-2

02A

/B E

ffluent

482

725

1,0

44

1104

Low

Pre

ssure

Ste

am

Retu

rn224

75

1,0

00

1212

Coolin

g W

ate

r70

15

1,0

00

1105

Lean M

DE

A F

eed t

o A

B-2

01

80

350

10,0

00

1213

Coolin

g W

ate

r to

HX-3

02

70

15

1,0

00

1106

H2S

-Fre

e S

yngas

80

350

1,0

49

1214

Coolin

g W

ate

r R

etu

rn129

15

1,0

00

1107

H2S

-Fre

e,

Wate

r-F

ree S

yngas

80

350

1,0

44

1215

Cool R

-202A

/B E

ffluent

to F

D-3

01

102

725

1,0

44

1108

Ric

h M

DE

A fro

m A

B-2

01

89

350

10,0

57

1216

Unre

acte

d G

ases fro

m F

D-3

01

80

725

218

1109

Low

Pre

ssure

Ric

h M

DE

A t

o H

X-2

02

89

22.7

10,0

57

1217

Meth

anol P

roduct

from

FD

-301

80

725

825.9

1110

Hot

Ric

h M

DE

A t

o S

R-2

01

175

22.7

10,0

57

1218

Bott

om

s fro

m F

-301

80

725

81

1111

Low

Pre

ssure

Lean M

DE

A215

14.7

10,0

57

1219

Meth

anol P

roduct

from

FD

-302

80

725

9.5

1112

Makeup W

ate

r to

MD

EA

215

14.7

943

1220

Pure

Meth

anol P

roduct

80

725

835.4

1113

Hig

h P

ressure

Recycle

MD

EA

123

350

10,0

00

1221

Pure

Hydro

gen t

o P

ipelin

e80

725

137

1222

Waste

Gas t

o A

ir P

lant

80

725

71

Ta

ble

1:

Pro

ce

ss S

tre

am

Ta

ble

CTM 40



Table B.2: Material Balance

CTM 41



Appendix C: Figures and Tables

Table C.1: Chemical Component Properties Table

Component MW NBP,°F Freeze Point,

°F

Water

solubility

(g/L)

Flash Point,

°F Flammability

Safety

Hazards

Ammonia (NH3) 17 -28 -108 31% (w/w) N/A Flammable Toxic by

Inhalation

Carbon Dioxide (CO2) 44 -71 -108 1.45 N/A Non-flammable Greenhouse

Gas

Carbon Disulfide (CS2) 76 115 -169 2.17 -45 Highly Flammable

Skin, Eye,

and

Inhalation

Irritant

Carbon Monoxide (CO) 28 -313 -337 0.028 -312 Highly Flammable Carbon

Monoxide

Poisoning

Carbonyl Sulfide (COS) 60 -58 -218 1.25 N/A Flammable Acute

Toxicity

Elemental C 12 ~8700 ~6300 Insoluble N/A Flammable

Black

Carbon

Irritates

Respiratory

System

Elemental H 1 -423 -435 Insoluble N/A Highly Flammable Asphyxiant

When Pure Elemental O 16 -297 -362 0.015 N/A Non-flammable None

Elemental S 32.1 832 239 Insoluble 168-188 Highly Flammable Irritates

Respiratory

System Hydrogen Disulfide

(H2S) 34.1 -76 -116 4 -116 Highly Flammable

Major Injury

or Death Methane (CH4) 16 -259 -296 0.023 -306 Highly Flammable Asphyxiant

Methanol (MeOH) 32 149 -144 53 Flammable Highly Toxic

Methyl Diethanol Amine

(MDEA) 119 477 -6 Miscible 261

Flammable (with

Aluminum) Skin and Eye

Irritation

Sulfuric Acid (H2SO4) 98.1 639 50 Miscible N/A Non-flammable Highly

Corrosive Water (H20) 18 212 32 - N/A Non-flammable None

Table C.2: Coal Properties

Coal Name Coal Type Moisture and Mineral-Matter Free Basis Moisture-Free Basis

% Carbon % Hydrogen % Nitrogen % Oxygen % Pyritic S % Sulfate S

Pittsburgh (DECS-23) High Volatile A

Bituminous 84.64 5.82 1.54 8.00 2.23 0.01

Coal Name Coal Type

Percentage Moisture Moisture-Free Basis

Received Equilibrium % Ash % Volatile

Matter % Fixed Carbon

Pittsburgh (DECS-23) High Volatile A

Bituminous 2.00 2.50 9.44 39.42 51.14

CTM 42



Ta

ble C.3: Annual Cash Flow Summary

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

12

34

56

78

910

11

12

13

14

15

16

17

Sa

les,

lb

s (M

M)

6.6

16.6

16.6

16.6

16.6

16.6

16.6

16.6

16.6

16.6

16.6

16.6

16.6

16.6

16.6

1

Pri

ce

, n

et

$/l

b0.2

10.2

10.2

10.2

10.2

10.2

20.2

20.2

30.2

30.2

40.2

40.2

50.2

50.2

60.2

60.2

70.2

7

Re

ve

nu

e (

$M

M)

1.3

91.3

91.4

21.4

51.4

71.5

01.5

31.5

61.6

01.6

31.6

61.6

91.7

31.7

61.8

0

Fix

ed

Co

st (

$M

M)

11.2

611.4

811.7

111.9

512.1

912.4

312.6

812.9

313.1

913.4

513.7

214.0

014.2

814.5

614.8

5

Fix

ed

In

ve

stm

en

t ($

MM

)1.1

34.5

46.3

06.3

06.3

06.3

06.3

06.3

06.3

06.3

06.3

06.3

06.3

06.3

06.3

06.3

06.3

0

De

pre

cia

tio

n0.5

70.5

70.5

70.5

70.5

70.5

70.5

70.5

70.5

70.5

70.5

70.6

3

Gro

ss P

rofi

t-1

0.4

4-1

0.6

7-1

0.8

7-1

1.0

7-1

1.2

8-1

1.5

0-1

1.7

2-1

1.9

4-1

2.1

7-1

2.4

0-1

2.6

4-1

2.3

0-1

2.5

5-1

2.8

0-1

3.6

9

Ta

xe

s (3

9%

)-4

.07

-4.1

6-4

.24

-4.3

2-4

.40

-4.4

8-4

.57

-4.6

6-4

.75

-4.8

4-4

.93

-4.8

0-4

.89

-4.9

9-5

.34

Aft

er

Ta

x P

rofi

t-6

.37

-6.5

1-6

.63

-6.7

6-6

.88

-7.0

1-7

.15

-7.2

8-7

.42

-7.5

6-7

.71

-7.5

1-7

.66

-7.8

1-8

.35

AT

Ca

sh F

low

($M

M)

-1.1

3-3

.40

-7.5

6-5

.93

-6.0

6-6

.18

-6.3

1-6

.44

-6.5

7-6

.71

-6.8

5-6

.99

-7.1

3-7

.51

-7.6

6-7

.81

-7.7

2

Cu

m.

Ca

sh F

low

($M

M)

-1.1

3-4

.54

-12.1

0-1

8.0

3-2

4.0

9-3

0.2

7-3

6.5

8-4

3.0

2-4

9.6

0-5

6.3

1-6

3.1

5-7

0.1

5-7

7.2

8-8

4.7

8-9

2.4

4-1

00.2

5-1

07.9

7

PW

Fa

cto

r0.8

90.8

00.7

10.6

40.5

70.5

10.4

50.4

00.3

60.3

20.2

90.2

60.2

30.2

00.1

80.1

60.1

5

An

nu

al

PW

($M

M)

-1.0

1-2

.71

-5.3

8-3

.77

-3.4

4-3

.13

-2.8

5-2

.60

-2.3

7-2

.16

-1.9

7-1

.79

-1.6

4-1

.54

-1.4

0-1

.27

-1.1

2

Cu

mu

lati

ve

PW

($M

M)

-7.0

0-1

0.0

0-1

5.0

0-1

9.0

0-2

3.0

0-2

6.0

0-2

9.0

0-3

1.0

0-3

4.0

0-3

6.0

0-3

8.0

0-3

9.0

0-4

1.0

0-4

3.0

0-4

4.0

0-4

5.0

0-4

6.0

0

Ta

ble

C.3

: A

nn

ua

l C

ash

Flo

w S

um

ma

ry

CTM 43



Table C.4: Material Costs in 2015

Material Price Basis Price per lb Year of Data Average Inflation 2015 Price

Coal [23] $62.75 per short ton $0.031 2015 0 $0.031

Oxygen [24] $55.90 per short ton $0.028 2015 0 $0.028

Steam [25] $29.97 per 1,000 kg $0.01359 2008 1.61% $0.015

MDEA [26] $38,823.36 per 19,800 kg $0.89 2014 0.80% $0.90

Methanol [27] $1.33 per gallon $0.20 2015 0.00% $0.20

Slag [28] $42.65 per 80 lb $0.53 2015 0 $0.53

Hydrogen [29] $2.15 per scf $0.02 2005 1.91% $0.03

Catalyst [30] $800.00 per ft3 $11.65 2015 0 $11.65

Table C.5 Sensitivity Analysis

COM Sale Price % Increase, Sale Price

0.983 0.21 0

1.048 0.221 5

1.31 0.263 25

1.638 0.315 50

2.293 0.42 100

3.603 0.63 200

6.224 1.05 400

10.81 1.79 750

14.09 2.31 1000

CTM 44



Appendix D: Plot Plan

Figure D.1: Plot Plan

coal to methanol senior design project final report

Documents