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Economics of Steam Methane Reformation and Coal Gasification for Hydrogen Production

Permanent Link: http://ufdc.ufl.edu/UFE0021134/00001

Material Information

Title: Economics of Steam Methane Reformation and Coal Gasification for Hydrogen Production
Physical Description: 1 online resource (50 p.)
Language: english
Creator: Vergis, Midhun T
Publisher: University of Florida
Place of Publication: Gainesville, Fla.
Publication Date: 2007

Subjects

Subjects / Keywords: carlo, coal, dcfror, dpbp, economics, gasification, hydrogen, methane, monte, npv, reformation, simulation, smr, stem
Mechanical and Aerospace Engineering -- Dissertations, Academic -- UF
Genre: Mechanical Engineering thesis, M.S.
bibliography   ( marcgt )
theses   ( marcgt )
government publication (state, provincial, terriorial, dependent)   ( marcgt )
born-digital   ( sobekcm )
Electronic Thesis or Dissertation

Notes

Abstract: Fossil fuels (especially petroleum) drive today's leading economies. However, soon that age will decline, and we will need alternatives less detrimental to our environment. Hydrogen continues to be one of the most promising, talked about energy carriers of the future. Cost-effective, more environmental friendly methods of producing hydrogen need to be commercially established. In addition storage and transportation continue to remain dominant hurdles that need to be improved. We performed an economic comparison of two methods for producing hydrogen commercially (steam methane reformation and coal gasification)to reach a solution that will most benefit future generations.
General Note: In the series University of Florida Digital Collections.
General Note: Includes vita.
Bibliography: Includes bibliographical references.
Source of Description: Description based on online resource; title from PDF title page.
Source of Description: This bibliographic record is available under the Creative Commons CC0 public domain dedication. The University of Florida Libraries, as creator of this bibliographic record, has waived all rights to it worldwide under copyright law, including all related and neighboring rights, to the extent allowed by law.
Statement of Responsibility: by Midhun T Vergis.
Thesis: Thesis (M.S.)--University of Florida, 2007.
Local: Adviser: Sherif, Sherif A.

Record Information

Source Institution: UFRGP
Rights Management: Applicable rights reserved.
Classification: lcc - LD1780 2007
System ID: UFE0021134:00001

Permanent Link: http://ufdc.ufl.edu/UFE0021134/00001

Material Information

Title: Economics of Steam Methane Reformation and Coal Gasification for Hydrogen Production
Physical Description: 1 online resource (50 p.)
Language: english
Creator: Vergis, Midhun T
Publisher: University of Florida
Place of Publication: Gainesville, Fla.
Publication Date: 2007

Subjects

Subjects / Keywords: carlo, coal, dcfror, dpbp, economics, gasification, hydrogen, methane, monte, npv, reformation, simulation, smr, stem
Mechanical and Aerospace Engineering -- Dissertations, Academic -- UF
Genre: Mechanical Engineering thesis, M.S.
bibliography   ( marcgt )
theses   ( marcgt )
government publication (state, provincial, terriorial, dependent)   ( marcgt )
born-digital   ( sobekcm )
Electronic Thesis or Dissertation

Notes

Abstract: Fossil fuels (especially petroleum) drive today's leading economies. However, soon that age will decline, and we will need alternatives less detrimental to our environment. Hydrogen continues to be one of the most promising, talked about energy carriers of the future. Cost-effective, more environmental friendly methods of producing hydrogen need to be commercially established. In addition storage and transportation continue to remain dominant hurdles that need to be improved. We performed an economic comparison of two methods for producing hydrogen commercially (steam methane reformation and coal gasification)to reach a solution that will most benefit future generations.
General Note: In the series University of Florida Digital Collections.
General Note: Includes vita.
Bibliography: Includes bibliographical references.
Source of Description: Description based on online resource; title from PDF title page.
Source of Description: This bibliographic record is available under the Creative Commons CC0 public domain dedication. The University of Florida Libraries, as creator of this bibliographic record, has waived all rights to it worldwide under copyright law, including all related and neighboring rights, to the extent allowed by law.
Statement of Responsibility: by Midhun T Vergis.
Thesis: Thesis (M.S.)--University of Florida, 2007.
Local: Adviser: Sherif, Sherif A.

Record Information

Source Institution: UFRGP
Rights Management: Applicable rights reserved.
Classification: lcc - LD1780 2007
System ID: UFE0021134:00001


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ECONOMICS OF STEAM METHANE REFORMATION AND COAL GASIFICATION FOR
HYDROGEN PRODUCTION



















By

MIDHIUN THOMAS VERGIS


A THESIS PRESENTED TO THE GRADUATE SCHOOL
OF THE UNIVERSITY OF FLORIDA IN PARTIAL FULFILLMENT
OF THE REQUIREMENTS FOR THE DEGREE OF
MASTER OF SCIENCE

UNIVERSITY OF FLORIDA

2007

































O 2007 Midhun Thomas Vergis



































To my family for their continuous love, support, and encouragement.









ACKNOWLEDGMENTS

I wish to express my gratitude to my supervisory committee (Dr. S. A. Sherif, Dr. William

E. Lear, and Dr. Herbert A. Ingley) for their expertise, encouragement, and support. I would also

like to thank Mr. Gaurav Malhotra for his continued support.












TABLE OF CONTENTS


page

ACKNOWLEDGMENTS .............. ...............4.....


LIST OF TABLES .........__.. ..... .__. ...............6....


LIST OF FIGURES .............. ...............7.....


AB S TRAC T ......_ ................. ............_........8


CHAPTER


1 BACKGROUND INFORMATION ................. ...............9.................


1 .1 Introducti on ................. ...............9............ ...
1.2 Why Hydrogen? ................ ...............11.......... .....
1.3 The Hydrogen Economy ................. ...............12.......... ....


2 HYDROGEN PRODUCTION METHOD S ................ ...............16........... ...


2. 1 Steam Methane Reformation (SMR) ........._..__......_ .. ...............16.
2.1.1 Introduction .............. ...............16....
2. 1.2 Process Description .............. .....................17
2.2 Gasification............... ..............1
2.2.1 Introduction .............. ...............19....
2.2.2 Process Description .............. ...............20....


3 ECONOMIC ANALYSIS .............. ...............26....


3.1 Methodology ................. ...............26................
3.2 Capital Cost Estim ate .............. .. ... ... ............... ...............2
3.3 Operating Cost or Cost of Manufacturing Estimate (COM) ................. .....................27
3.4 Steps to Compare Economic Merit............... ...............30.


4 RE SULT S AND DI SCU SSION ............... ...............3


5 CONCLUSIONS .............. ...............44....


APPENDIX DATA FOR ECONOMIC ANALYSIS ...._ ......_____ .......___ ...........4


LIST OF REFERENCES ............_ ..... ..__ ...............48...


BIOGRAPHICAL SKETCH .............. ...............50....










LIST OF TABLES


Table page

1-1. Properties of Selected Fuels .............. ...............15....

3-1. Basis for the Chemical Engineering Plant Cost Index .............. ...............34....

3 -2. Probable Variation of Key Parameters ..........._._ ... ...............35....__...

3 -3. Probable Variation of Cost of Raw Material: CRM ................. ...............35...........

4-1. Discounted Cash Flow Diagram for Steam Methane Reformation (SMR).............._._........39

4-2. Discounted Cash Flow Diagram for Gasifieation .............. ...............40....

4-3. Discounted Profitability Criteria for Steam Methane Reformation (SMR) and
Gasification ........... __..... ._ ...............41....

A-1. Calculation of Fixed Capital Investment without Cost of Land (FCIL) for Steam
Methane Reformation (SMR) and Gasifieation............... ..............4

A-2. Calculation of CRM for Steam Methane Reformation (SMR) and Gasifieation...................46

A-3. Calculation of CUT for Steam Methane Reformation (SMR) and Gasification ................. ..46

A-4. Calculation of COL for Steam Methane Reformation (SMR) and Gasification ...................46

A-5. Calculation of Economic Analysis Parameters for Steam Methane Reformation
(SMR) and Gasification ................. ...............47........_.....










LIST OF FIGURES


Figure page

2-1 Simplified Block Diagram of SMR .............. ...............25....

2-2 Detailed Process Flow Diagram of Gasification ................. ...............25......_... ..

3-1 Hydrogen Price Analysis with Net Present Value (NPV) .............. .....................3

3-2 Fluctuation in Price of Natural Gas and Coal (1985-2005) ................... ...............3

4-1 Discounted Cash Flow Diagram for SMR and Gasification............... .... ..........4

4-2 Probability Distribution: Net Present Value (NPV)............... ...............42.

4-3 Probability Distribution: Discounted Cash Flow Rate of Return (DCFROR) ................... 42

4-4 Probability Distribution: Discounted Payback Period (DPBP) .............. ....................43









Abstract of Thesis Presented to the Graduate School
of the University of Florida in Partial Fulfillment of the
Requirements for the Degree of Master of Science

ECONOMICS OF STEAM METHANE REFORMATION AND COAL GASIFICATION FOR
HYDROGEN PRODUCTION



Midhun Thomas Vergis

August 2007

Chair: S. A. Sherif
Major: Mechanical Engineering

Fossil fuels (especially petroleum) drive today's leading economies. However, soon that

age will decline, and we will need alternatives less detrimental to our environment. Hydrogen

continues to be one of the most promising, talked about energy carriers of the future. Cost-

effective, more environmental friendly methods of producing hydrogen need to be commercially

established. In addition storage and transportation continue to remain dominant hurdles that need

to be improved. We performed an economic comparison of two methods for producing hydrogen

commercially steam methane reformation and coal gasifieation; to reach a solution that will

most benefit future generations.









CHAPTER 1
BACKGROUND INFORMATION

1.1 Introduction

The world is approaching the first stages of an energy crisis that could have a serious

impact on the security, economics, politics, and lifestyle of every human being. This crisis is

being caused primarily because the world's economy has been dependent on oil for so long and

we will soon reach a stage when the growth in demand for oil exceeds our ability to supply it and

we do not have commercially viable alternatives. There are no immediate solutions to this

problem but the repercussions in the near future will be severe, which is why we need to act

soon.

We have faced similar situations before (most notably the oil crises in 1973, 1979 and

more recently in 1990, 2001 and 2003 onwards) that arose due to political reasons. In the United

States, the price of oil rose from $3/bbl to almost $40/bbl in the 1970s alone. For the handful of

industrialized nations like the Soviet Union that were net energy exporters the effects of the oil

crisis resulted in a sudden and massive influx of money. Experts attribute the recent spike to

$78/bbl in 2006 to a variety of factors: North Korea's missile launches, the crisis between Israel

and Lebanon, Iranian nuclear brinkmanship, and most importantly because of reports from the

U. S Department of Energy confirming a decline in petroleum reserves.

Evidence of this is the fact that oil companies spent $8 billion on exploration in 2003, but

discovered only $4 billion of commercially useful oil [1]. More proof is Chevron Texaco' s

recent decision to acquire an oil company and its reserves last year which reveals that bigger oil

companies consider it cheaper to just buy oil than invest in exploration [2].

In recent years, even oil producing nations have been unable to keep pace with fast

growing global demand. The fact that oil has increased from below $25/bbl since 2003 to









$63/bbl today, while oil producers have consistently produced at maximum capacity, is

compelling evidence that oil is becoming scarce relative to demand and that there are no more oil

reserves available.

Peak oil is the inevitable movement when world oil production hits its peak and, from that

moment on, reserves are on an ever dwindling downward spiral. By the end of 2005, British

Petroleum estimated the world oil reserves at 1.2 trillion barrels and at our current consumption

rate of about 83 million barrels per day; we barely have enough to last another 40 years.

According to the U.S. Energy Information Agency, the United States is the single largest

consumer of oil worldwide at about 25% followed by China and Japan at 8% and 6% each.

A policy of conservation of energy should be enforced. Conservation measures and steps

to improve existing efficiencies can lower the rate of increased demand imposed by worldwide

economic development and increase in population. And while it may be a step in the right

direction there is no single solution to avoid the long period of energy shortages we will soon

enter. By acknowledging that these shortages are real and permanent, there are many things we

can do both individually and as a global economy to make the most from the world energy crisis

which has already begun. It is the steady rise in oil prices that will force alternative energy

sources that are already environmentally sound and commercially attractive for future use even

though they may appear more capital intensive. We need to act now to develop the infrastructure

this transition requires since there is none to provide fuels in the volumes required if we hope to

one day replace our current use of oil. Installing this kind of infrastructure will take years.

Finally the greenhouse effect and pollution are just a few of the environmental problems

caused by the utilization of fossil fuels. One of the main pollutants is carbon dioxide. The U. S.

Energy Information Agency reports that carbon dioxide accounts for about 83% of the










greenhouse gases released into the atmosphere. The continuing carbon dioxide pollution to the

environment is causing global warming (in turn, affecting forests, agriculture yields, ecosystems,

as well as human health and well-being). The information provided in this section should prove

without any doubt that the world energy crisis is very real and we need to adopt alternative

sources of energy that are less polluting.

1.2 Why Hydrogen?

One fuel that is expected to play a maj or role in the mid to long-term future of the energy

sector is hydrogen. Hydrogen is a desirable fuel for various reasons as discussed below.

Hydrogen, the lightest element, has three isotopes: hydrogen, H, deuterium, D and tritium,

T [3]. Hydrogen is abundant and available in plenty as water occupying about 70% of the earth' s

surface.

Whereas hydrogen atoms exist under certain conditions, the normal state of pure hydrogen

is the hydrogen molecule, H2, which is the lightest of all gases. Molecular hydrogen is a product

of many reactions, but is present at only low levels (0. 1 ppm) in the Earth' s atmosphere. The

hydrogen molecule exists in two forms, designated ortho-hydrogen and para-hydrogen,

depending on the nuclear spins of the atoms. Many physical and thermodynamic properties of H2

depend on the nuclear spin orientation, but the chemical properties of the two forms are the

same .

Compared to other possible alternatives hydrogen has the highest energy content per unit

weight of 120 MJ/kg as opposed to 48 MJ/kg for natural gas and 44 MJ/kg for gasoline [4]. It is

a very stable molecule and is not particularly reactive under normal conditions. However, at

elevated temperatures and with the aid of catalysts, H2 undergoes many reactions and forms

compounds with almost every other element.










Hydrogen energy has long been established scientifically as an environmentally cleaner

source of energy to end-users, particularly in transportation applications without significant

release of pollutants. Upon combustion, hydrogen returns to water, accompanied by virtually no

pollution and no greenhouse gas production, in contrast to hydrocarbon-based fuels. Since U.S.

transportation is 97% dependent on petroleum, (much of it imported from parts of the world that

are considered politically unstable), a strategy of shifting to domestically-produced hydrogen

fuel is very appealing.

However, there are several key issues that need to be addressed. Safety, storage and

transportation of hydrogen continue to remain maj or areas that need further improvement if we

are to support the large capital investments needed to develop the vast infrastructure that will

propel hydrogen as the energy source of the future. However significant scientific progress has

been made in these fields over the last decade that has generated growing interest worldwide.

Hydrogen is a product that is fully capable of sustaining the world's energy needs now and

in the future. If renewably produced, hydrogen would be a fuel used that does not contribute to

environmental damage and supports the human well being.

1.3 The Hydrogen Economy

In virtually all advanced economies, there is considerable interest and enthusiasm over the

concept of a hydrogen economy and the prospect of hydrogen-fuelled vehicles. Not since the mid

1970s, when the term "hydrogen economy" was first coined, has there been anything like the

current level of research activity and discussion even in the popular press.

Several examples of large-scale hydrogen based energy systems can be cited. Among them

are the World Energy Network (WE-NET) in Japan [5], the Solar Hydrogen Demonstration Plant

in Neunburg vorm Wald [6] and the HYSOLAR: A German-Saudi Arabian Program on Solar

Hydrogen [7]. The best example that can be cited is the FutureGen Alliance, a non-profit









consortium of some of the world' s largest coal producers and users formed to partner with the

U. S. Department of Energy's FutureGen proj ect. Member companies span Australia, Canada and

China. These proj ects are aimed at establishing a worldwide energy system based on harnessing

sources such as solar and coal, producing hydrogen via water electrolysis, and liquefying the

hydrogen to the end points of use. Current efforts are to design efficient water electrolyzers,

large-scale hydrogen liquefaction plants and high efficiency hydrogen gas turbines.

There are still many technical hurdles yet to be fully overcome involved with the safe

transportation and storage of hydrogen. The challenge may be summarized thus: manufacturers

are unwilling to produce vehicles without an in-place fuelling infrastructure and fuel producers

are unwilling to build that infrastructure without some certainty that vehicles requiring those

fuels will be in operation.

From a transportation perspective, generally what is envisioned is fuel cell powered cars

that use hydrogen as fuel and produce only water vapor as emissions. A fuel cell is an energy

conversion device that combines hydrogen and oxygen in an electrochemical process to produce

electric power, some low temperature heat and water vapor as the only emissions. The use of

liquid hydrogen as a rocket fuel for use in space flights is well established and is now being

seriously considered for use as fuel for aircraft.

Unfortunately, 96% of all hydrogen produced in the U.S. today uses natural gas as a

feedstock in spite of having the world's largest reserves of coal. The trends in natural gas prices

follow trends in the price of oil. Therefore the cost of producing hydrogen becomes dependent on

the highly volatile price of natural gas.

For most rapidly developing and developed nations, the best alternative to natural gas is

coal which is cheaper and more readily available. Today coal is priced as a dirty solid fuel and









for this reason it is often available at a small fraction of the cost of cleaner oil and natural gas

containing the same amount of energy. The process of commercial production of hydrogen along

with electricity, industrial grade process steam and pre-cursors to produce usable transportation

fuels from coal, coke and other carbonaceous matter is called IGCC or Integrated Gasification

Combined Cycle.

For more than 40 years the South African government, fearing an oil embargo in retaliation

to their policy of apartheid, has commercially produced a range of liquid fuels from coal

including gasoline, diesel and j et fuel.

Countries such as the U.S., China and India that are oil-poor but coal rich could stand to

benefit greatly and could potentially convert its principal asset for energy independence! Today,

no single technology seems to offer a clear solution, although it appears that coal gasification

offers a potential solution with respect to sustainability issues and energy independence, many

technical hurdles remain which suggest it is decades away from large scale, cost effective

implementation.

Given these many uncertainties, one might argue that it is premature to analyze alternative

forms of infrastructure. However, if one accepts the premise of a not-so distant hydrogen

transition and the need to begin making the necessary investments now, strategic planning need

not wait for resolution of these many issues. Rather, energy, economic and environmental

analyses must be undertaken in concert with research on improved production, storage, and

distribution technologies.









Table 1-1. Properties of Selected Fuels
Hydrogen Methane Methanol Gasoline
PropertyH2 CH4 CH30H C6- 12
Boiling point, oC -253 -162 65 Wide range
Physical state at 250C Gas Gas Liquid Liquid
Heating value: weight basis
Lower heating value, MJ/kg 120 48 20 42-44
Higher heating value, MJ/kg 142 53 23 44-46
Heating value: volume basis*
Lower heating value, MJ/Nm3 11 35 15,700 -32,000
Higher heating value, MJ/Nm3 13 39 18, 100 -33,000
Flammability limits, vol. % in air 4.1 to 74.0 5.3 to 15.0 6.0 to 36.5 1.4 to 7.6
Explosive limits, vol. % in air 18.2 to 58.9 5.7 to 14.0 6.7 to 36.0 1.4 to 3.0
Molecular diffusion coefficient, cm2/S 0.61 0.16 0.13 0.05
Auto-ignition temperature in air, OC 571 632 470 220
* Nm3 Of gas at atmospheric pressure or m3 Of liquid









CHAPTER 2
HYDROGEN PRODUCTION METHODS

There are several methods of producing hydrogen today. Those that will be discussed and

compared in this study are steam methane reformation (SMR) and gasification. A brief

discussion of both technologies will be made followed by an economical analysis in the

subsequent chapters in an attempt to reach a solution that will prove most advantageous for near-

term effect and promote energy independence.

Hydrogen production methods from renewable sources have not been considered in this

analysis for several reasons. They tend to be an intermittent source of energy that is not yet

completely reliable without the use of advanced storage methods. Consequently this results in

huge initial investments and cannot be deemed a practical solution when compared to more

commercially methods already in existence today. The initial hurdle lies in establishing these

existing technologies on a larger global scale following which enough industrial experience of

related supporting technologies can be better understood to equip us for future implementation of

production methods from renewable sources.

Today, hydrogen is produced primarily from fossil fuels (natural gas, petroleum, and coal)

using well-known commercial processes. Worldwide, the predominant feed is natural gas (48%),

followed by oil-petroleum (30%), coal (18%), and electricity (4%) [8]. The process description

that follows is not meant to provide a detailed understanding but a brief overview comparing

both technologies that lead to the process economics.

2.1 Steam Methane Reformation (SMR)

2.1.1 Introduction

Large-scale catalytic steam reformation of natural gas is the most common, least expensive

method of producing hydrogen commercially available today and almost 48% of the world' s










hydrogen is produced from SMR. Natural gas is, on average, ~ 95% methane, with the balance

being higher hydrocarbons (ethane, propane) and trace contaminants, such as H2S and CO2. SMR

is widely used, especially in the United States, to provide high purity hydrogen to the chemical,

petrochemical, and refining industries.

2.1.2 Process Description

This method is a multi-step process that comprises of gas pre-treatment; catalytic

reforming; high temperature water-gas shift; low temperature water-gas shift; purification; and

compression/liquefaction. Descriptions of each maj or component technology are based on Figure

2-1.

* Feedstock: Natural gas to be used must be compressed before it undergoes reformation.
Feed pre-treatment is generally required, since untreated natural gas nearly always contains
sulfur compounds. Pre-treatment and handling of compressed natural gas is easier and
cheaper than that required for coal or any other solid carbonaceous matter used in
gasification.

* Purification (Desulfurization): After the feed is compressed, natural gas undergoes
desulfurization to remove traces of sulfur from the gas. Desulfurization of the feed gas,
which is usually carried out using a zinc oxide bed, is needed since sulfur can poison the
reformer catalyst.

* Selective Catalytic Reduction (SCR): Low NOx burner technology is sometimes not able
to meet strict regulations alone and therefore, new SMRs also require the addition of an
SCR unit to the stack. Here liquid ammonia is vaporized and inj ected into the flue gas,
which passes over a honeycomb-shaped (V20s TiO2) catalyst. The ammonia reacts with
NOx in the presence of oxygen to form nitrogen and water vapor. By varying the ammonia
inj section rate, NOx is controlled to the desired level.

* Reformation: After pre-treatment, the feed gas is mixed with process steam at an
appropriate steam-to-carbon mole ratio of 3 (typically) to prevent the production of solid
carbon or coke, which can build up on the catalyst and plug the reactor tubes. The catalytic
steam reforming reaction takes place at pressures of approximately 3-25 bar and high
temperatures (650-9000C) [8]. The reformation is favored by high temperature and steam
and reduced by higher pressure. Recent advancements (e.g., high pressure catalyst tubes) in
reformer technology allow reliable hydrogen production even at higher operating
pressures.

CH4 + H20 (g) t* CO + 3H12 (A~H = +206 kJ/mol CH4) (2-1)









The catalyst, typically nickel based, is packed into tubes and the heat needed for reaction
shown above is provided externally by combustion of additional natural or purge gas.
Concerns regarding emissions can be addressed by using the latest environmental controls
for NOx control and sulfur removal while designing an SMR facility. Environmental
controls significantly add to the capital and operating costs of a hydrogen production
facility. The SMR process is a more environmentally acceptable process of producing
hydrogen than gasification. Low NOx burners utilize staged fuel combustion and flue gas
recirculation to minimize NOx production. (Staged fuel combustion involves introducing
the fuels at different locations to create two combustion zones). Tail gas from the Pressure
Swing Adsorption (PSA) unit provides bulk of the heat input to the furnace, with natural
gas for start up and control. Once the reformer is heated, the unit can operate with 100%
PSA fuel if needed. The basic layout has the convection section and the stack mount on
top, with a process gas waste heat boiler located underneath. A steam drum is mounted on
top of the reformer.

* Shift: The synthesis gas mixture ("syngas" is a mixture of hydrogen and CO) is sent to the
high and low temperature shift reactors, where additional hydrogen is produced via the
water-gas shift reaction:

CO + H120 (g) ** CO2 + H12 (A~H = -41 kJ/mol CO) (2-2)

The above reaction is favored at lower temperatures as opposed to the reformer reaction.
To compensate for slower reaction kinetics at lower temperatures a solid Co-Mo catalyst is
used. To take advantage of the high temperatures generated, a two-stage water-gas shift
reaction is generally used, with the high temperature stage operating at ~ 4000C and the
low temperature stage at ~ 2500C. The exit gas contains primarily H12, and also CO2, H120
and small amounts of CO, methane and higher hydrocarbons. Since residual CO leaving
the shift converter is recovered in the PSA unit as reformer fuel, the gain in plant
efficiency if a second stage of shift is added is less when compared to the increase in
equipment cost. The costs involved for the shift reactions are high, but lower when
compared to the same process taking place in gasifieation. This can be attributed to the
higher amounts of steam required to shift the larger amounts of CO generated for an
equivalent amount of hydrogen.

* Pressure swing adsorption (PSA): After cooling of the raw gas and separation of process
condensate, a PSA unit is used to purify the raw H2. They operate at about 20 bar and reach
H2 Separation efficiencies in the range 85-90%. It is the most common process used in
large systems, where very high purity hydrogen (99.999%) at ~ 30 bar is the desired
product. These PSA-based hydrogen plants have higher efficiencies than conventional low-
purity plants because of additional export steam credits. The adsorbent used is a mixture of
activated carbon and zeolites and removes all of the contaminants from the hydrogen
product in a single step. With adjustments to the PSA operation, one can also produce a
high purity CO2 Stream for sequestration or for sale, in addition to the hydrogen stream but
at the cost of hydrogen purity [9]. Tail gas from the PSA unit is used as reformer fuel.
Again the costs involved with the PSA units are high but lower than a similar arrangement
in gasifieation which will be described further on.










* Compression: Following the PSA purification step, hydrogen gas is compressed to ~ 60
bar and sent to steam generators as shown in the Figure 2-1.

* Heat recovery: Heat recovery coils include feed gas preheat, mixed feed (gas and steam)
preheat, steam generation, and steam superheating. The reformer furnace process outlet is
cooled in a waste heat boiler by heat exchange with circulating feed-water to produce
steam. This steam can be exported to a nearby refinery or petrochemical facility for
process needs and/or converted into electricity. Downstream of the shift converter, the gas
is cooled against boiler feed-water.

2.2 Gasification

2.2.1 Introduction

Coal has been used for centuries with the earliest recorded use in China in 220 A.D. Later

on in the 1600s when coal was heated and the release of gas was first noted, the process was

described as "the coal did belch forth a wild spirit or breath .. not susceptible of being confined

in vessels, nor capable of being reduced to a visible body."

Coal gasification is the process of reacting coal with oxygen, steam, and carbon dioxide to

form a product gas containing hydrogen and carbon monoxide. Gasification is essentially

incomplete combustion. From a processing point of view the main operating difference is that

gasification consumes heat evolved during combustion. Depending on the type of gasifier and

the operating conditions, gasification can be used to produce a fuel gas suitable for any number

of applications. For instance, a low heating value fuel gas may be produced from an air blown

gasifier for use as an industrial fuel and for power production. A medium heating value fuel gas

may be produced from enriched oxygen blown gasification for use as a synthesis gas in the

production of chemicals such as ammonia, methanol, and transportation fuels. A high heating

value gas can be produced from shifting the medium heating value product gas over catalysts to

produce a substitute or synthetic natural gas (SNG). The technical information described here is

very similar to commercially available systems in IGCCs.









2.2.2 Process Description


The flexibility of gasification technology allows it to be integrated into a variety of system

configurations to produce electrical power, thermal energy, fuels, or chemicals as shown in

Figure 2-2. This section provides a brief description of each maj or component technology.

* Raw materials: The raw material used in the gasifier is fed as slurry. Gasifier feed (coal),
is ground in mills and treated with pre-heated water to the required mixture. As indicated
in the diagram, a vast array of carbonaceous matter can be used as feedstock for
gasification. The advantages of flexible feedstock are outweighed however by the fact that
storage, pre-treatment and handling is much more cumbersome and thus capital-intensive
than using natural gas for SMR. This is one of several factors that make gasification more
expensive than SMR, the others associated with the air separator, removal of ash and other
particulate matter, sulfur, CO2 TemOVal and sequestration, additional steam requirements
for the shift reaction as compared to SMR, and finally the larger PSA system requirements
which are discussed below.

* Air separator: The air separator is essentially a unit that generates ~ 95% pure Oz at
atmospheric pressure along with trace amounts of N2 and Ar. The Oz is then compressed to
slightly higher than the gasifier operating pressure and fed to the gasifier. The purge N2 is
also compressed and fed to the combustion gas turbine for NOx control. The air separator is
one of the components that make gasification more expensive owing to its additional
power requirements and costs associated with 02 COmpression.

* Gasifier: Current gasification technology takes place in 02-blown, entrained flow gasifiers
operating at 70 bar. Entrained Flow Gasifiers have been developed to improve the gas
production rate and can operate with a wider range of feedstock and allows complete
conversion to hydrogen, carbon monoxide, and carbon dioxide, producing no tars, oils, or
phenols. Coal slurry and oxygen are fed at the top of the pressurized vessel at operating
temperatures of the order of 13 500C. Liquid slag flows down the walls and is drained from
the lockhopper. In gasifiers partial combustion occurs in an oxygen-deficient or reducing
atmosphere using about 30-50% of the oxygen theoretically required for complete
combustion to carbon dioxide and water. Carbon monoxide and hydrogen are the principal
products, and only a fraction of the carbon in the coal is oxidized completely to carbon
dioxide. The combustion reaction is written in a general form as:

(1 + h) C + 02 -2 h CO + (1 h) CO2 (AH = 172.5 h 393.5 kJ/mol) (2-3)

where A varies from 0 (pure CO2 prOduct) to 1 (pure CO product).

The value of h depends upon the gasification conditions and is usually close to 1. The heat
released by the partial combustion provides the bulk of the energy necessary to drive the
endothermic gasification reactions. Further conversion occurs through the much slower,
reversible gasification reactions with CO2 and H20 produced by gasification with heavier
carbonaceous material such as waste oils.









C + CO2 t, 2 CO (A~H = 172.5 kJ/mol)


(2-4)


C + H20 t, CO + H2 (AH = 131 kJ/mol) (2-5)

Hydrogen and carbon monoxide production increases with decreasing oxygen in the feed,
with decreasing pressure, and with increasing temperature. The composition of hydrogen
and carbon monoxide produced in the newer generation of gasifiers are sufficient for all
applications liquid production, chemical synthesis or power generation. As can be
observed from the figure, excess steam from the heat recovery steam generator (HRSG) is
drawn off and can be sold as industrial-grade process steam. The remaining steam is sent to
the gasifier for further syngas production as described above and also for quench cooling to
~ 2500C. Although this process results in a slight drop in efficiency, (due to the thermal
energy drop in the syngas that could have been used to create valuable high pressure steam)
this process is vital for two reasons to lower the concentration of unwanted trace elements
and to increase saturation that will promote the shift reactions that follow. The quenching
process is quite inexpensive and reliable but nonetheless adds to the capital costs involved
in this process.

* Particulate removal: Minerals (ash) in the feedstock separate and leave the bottom of the
gasifier either as an inert glass-like slag or other marketable solid product. A small fraction
of the ash becomes entrained in the syngas and requires downstream particulate removal.
The raw syngas after quenching is sent to a scrubber giving a saturated flow largely free of
particulate matter and water-soluble contaminants such as NH3, HCN and chlorides.
Particulate removal is effected either through a series of dry solid filters, so that the gas fed
to the combustion turbine is essentially free of suspended particulates. In this system first,
a hot cyclone removes over 90% of the particulates, and the remainder is removed by an
advanced dry char filtration system. Slag, the maj or solid by-product of the gasification
process, is vitrified black sand like material that can be marketed as construction material.
There are no solid wastes from the coal gasification process [similar to those produced by a
pulverized coal process] no scrubber sludge, fly ash or bottom ash. Gasifier slag can be
used as a principal component in concrete mixtures (Slagcrete) to make roads, pads, and
storage bins. Other applications of gasifier slag and fly slag are in asphalt aggregate,
Portland cement kiln feed, and lightweight aggregate. In a gasification facility, heavy
metals are very low because they are encapsulated in the slag. Other metals, such as
mercury and selenium, are volatile and are detected in the syngas. Compared to a
conventional combustion plant, metals removal should be easier because the cleanup can
be done on the syngas at a higher pressure in a reducing environment rather than in the
lower pressure, oxidizing environment of the effluent. Thus near-complete removal from
syngas exists by selective adsorbents.

* Gas clean-up: This stage essentially frees the syngas stream of sulfur and CO2. Sulfur is
converted to H2S and COS under the reducing conditions of the gasifier and the COS
produced is converted to H2S at the shift reactors. The H2S is sent to a sulfur recovery unit
typically found in such processes that comprises an air-blown Claus plant for oxidizing
H2S to elemental sulfur, and a Shell Claus off-gas treating (SCOT) plant for tail gas
cleanup. Claus plant tail gas contains sufficiently high levels of sulfur compounds (H2S,
SO2, COS, CS2 and S vapor) that require further cleanup. In the SCOT process, these










compounds are catalytically converted to H2S, which is removed with an amine absorption
unit and recycled back to the Claus plant. A Rectisol system can be used for acid gas
removal from the syngas because it provides better sulfur removal than an amine system.
However, a Rectisol system is more expensive and auxiliary power intensive than the
amine systems. Therefore prior to CO2 capture, H2S is removed from the syngas
(containing ~0.6% H2S by volume) by physical absorption in dimethyl ether of
polyethylene glycol (Selexol) to elemental sulfur that can be sold at ~ $100/ton. Sulfur
removal efficiency exceeding 99% are commonly achieved in IGCCs [10, and
1 1].Combustion of coal gas in high firing-temperature gas turbines converts virtually the
entire CO to CO2. CO2 TemOVal is required since it substantially increases the heating value
of the pressure swing adsorption (PSA) purge gas so as to make feasible its use in a gas
turbine following compression and since it reduces the size (and thus the cost) of the PSA
system. CO2 is removed from the sulfur-free syngas (containing 30-32% CO2 by volume)
by physical absorption in Selexol at 350C. Unlike H2S removal, where stripping is carried
out by heating the rich solvent, the CO2 is released without heating in a series of flash
drums at decreasing pressures. Since CO2 emiSsions is a maj or concern with gasification a
mention will be made at this point about sequestration. After CO2 is separated from the
process stream, it is sequestered so it is not released to the atmosphere. The two most
commonly proposed methods for sequestration are ocean disposal and underground
inj section [9]. In ocean disposal, several options are available Liquid CO2 may be released
from pipelines at depths of 2,000 m or more; solid CO2 can be disposed of by ships; or
CO2 can be converted into hydrates for disposal. With underground sequestration, the CO2
is inj ected into depleted natural gas reservoirs or other geologic formations such as
aquifers. Okken [9] estimates that there is a total of 5 years worth of capacity in old natural
gas wells and an additional 15 years capacity in sedimentary basins. Although the ocean
has a CO2 uptake capacity that is almost 7,000 times greater than current carbon emissions
it cannot be considered feasible since the CO2 Will HOt remain in the ocean for long and
requires further investigation into the impacts on marine ecosystems. Ocean disposal can
be considered for future implementation but not while the costs involved are
approximately twice those of underground inj section. Costs for removal, stripping and
compression of CO2 are included from previous estimates and included in the economic
analysis in the next chapter. This and the sulfur removal systems substantially increase the
cost of gasification. During gasification the nitrogen content of coal is converted to
molecular nitrogen, N2, ammonia, NH3, and a small amount of hydrogen cyanide, HCN.
Other techniques are being investigated in hot-gas cleanup technologies. The lower NOx
from the combustion turbines are the result of improved turbine design and the use of a
diluent (steam or N2 purge gas) for NOx control. Since a maj or portion of the power
generated comes from the gas turbine, the water requirement is substantially reduced from
that required for a conventional coal-fired power plant, where all of the power is generated
from steam turbines. The problem of water required for water-treatment systems to address
tars, phenols, and metals is eliminated for entrained-flow gasifiers. The waste water from
the gasification plants is cleaned up to meet the requirements for water discharges.
However, if desired and at additional expense, a reverse osmosis system can be added to
treat the waste water from the gasification system to obtain a zero discharge system. The
water required by a gasification facility is a variable that is often neglected. Hence a rough









estimate of the water requirements of both SMR and gasification will be made to produce
realistic results.

* Shift reactor: The mixture of H20 and CO (water-gas) shift reaction is used to "shift" the
bulk of the stream' s chemical energy into H2. The reaction taking place is:

CO + H20 (g) t* CO2 + H2 (A~H = -41 kJ/mol) (2-6)

This reaction is favored at low temperatures where the reaction rates are slow thus
requiring the use of a sulfur-tolerant solid Co-Mo catalyst. To make the best use of the heat
generated by the reaction and to adequately promote the formation of H2 two shift reactors
are employed in series with cooling in between either by pressurized steam generation or
heating of boiler feed-water. The initial reactor converts 85-90% of the CO and allows the
syngas to reach ~ 4000C by generating high pressure steam. Syngas then enters the second
reactor where CO conversion proceeds adiabatically up to 98% and the temperature reaches
2250C. The syngas is again cooled as described earlier. A third low temperature reactor
may be included for maximum conversion efficiencies of over 99% but is not always
considered cost effective. Syngas is cooled at each stage in preparation for downstream
processes.

* Syngas conversion: Pressure swing adsorption (PSA) units purify the hydrogen. High
purity (~99.999%) H2 is assumed to be extracted from the clean syngas at 350C using PSA.
As reviewed earlier, PSA units used in SMR operate at about 20 bar and reaches H2
separation efficiencies in the range 85-90%. To maintain the same H2 Separation efficiency
at pressures of 70 bar considered here would require a more complex (and more expensive)
system arrangement and is consistent with current information. Pure hydrogen exits the
PSA, while the purge gas (the remaining 15% H2 alOng with the other species) is
discharged at 1.5 bar and can be used to generate steam for power production in the steam
turbine. At a pressure exceeding 60 bar, the H2 prOduct is suited for long-range pipeline
transport and there is no need for further compression as with SMR. The larger and more
complex PSA system required of gasification again is another parameter that results in it
being more capital intensive over SMR.

* Fuels and chemicals: It was South Africa' s policy of apartheid and consequently
economic sanctions being imposed that forced them to produce liquid fuels from
hydrocarbon synthesis processes such as the Fisher-Tropsch method. This technology
developed by German scientists during Hitler's regime has been employed by Sasol
successfully for the past 50 years. Gasification is the only advanced power generation
technology capable of co-producing a wide variety of commodity and premium products
(e.g., methanol, higher alcohols, diesel fuel, jet fuel and gasoline) in addition to hydrogen,
electricity and industrial-grade process steam to meet future market requirements. It is this
ability to produce value-added products from impure H2-rich syngas left after CO2 TemOVal
that has made gasification economical in selected situations and will be a key driver in a
deregulated power market. China maintains that shipping crude oil long distances from the
coast to remote Inner Mongolia for conventional fuels refining would be expensive,
whereas producing coal-derived fuels via liquefaction would be relatively competitive.
Recently the Chinese government approved large-scale efforts to produce liquid









transportation fuels using coal gasification [12]. China's largest coal firm, Shenhua Group,
plans to start up the country's first coal-to-fuels plant in 2007 or early 2008, in the world's
most ambitious application of coal liquefaction since World War II. Shenhua plans to
operate eight liquefaction plants by 2020, producing, in total, more than 30 million tons of
synthetic oil annually enough to displace more than 10 percent of her proj ected oil
imports. China's progress in constructing coal-conversion plants puts it far ahead of the
U.S., where coal gasification is still recovering from a damaged reputation. The finished
fuels would be hauled from the plants in tank-cars via Shenhua's existing railroads adj acent
to the mines. These trains already haul coal for later trans-shipment via waterways to city
markets. To quantify the costs involved in producing such fuel pre-cursors is extremely
case-specific and has not been considered in this analysis.

* Fuel cells: The most attractive energy conversion technology that uses hydrogen is fuel
cells. A fuel cell is an energy conversion device that combines hydrogen and oxygen in an
electrochemical process to produce a non fluctuating DC power output, some low-
temperature heat, and water vapor as the only emissions. Different types of fuel cells are
distinguished by their different electrolytes and the different temperatures reached during
operation. Today, fuel cells are used in manned space flight to provide power for the
spacecraft and drinking water for the astronauts; as backup power for critical services in
hospitals and banks; and in an increasing number of cars and buses. Substantial
development efforts are underway by automobile manufacturers in Germany, Japan and the
U.S. to bring fuel cell vehicle technology to the market. Fuel cells such as POFC, SOFC
and PEM cells are used today and will continue to increase in the future. Hydrogen fuel
cell vehicles have several potential advantages over conventional gasoline engine vehicles
including higher fuel efficiency, lower greenhouse gas and conventional pollutant
emissions, longer lifetimes, and lower drive train maintenance costs. In addition, hydrogen
fuel vehicles are proj ected to have excellent fuel economy at 66 mpg, gasoline equivalent
[13]. If hydrogen produced with sequestration of the separated CO2 WeTO USed in fuel cell
cars, lifecycle CO2 emiSsions per km would be less than 1/5 of those for gasoline internal
combustion engine cars. Costs involved with the manufacture of fuel cells or the resulting
drop in CO2 emiSsions is beyond the scope of this analysis and has not been included.

* Combustion/combustion turbine: The cleaned synthesis gas is then combusted in a high
efficiency gas turbine/generator to produce both electrical power and supply compressed
air to the air separation unit that generates oxygen for the gasifier. The chemical energy of
the low pressure PSA purge gas can be used to produce electric power. Due to the removal
of CO2 ahead of PSA the purge gas consists mainly of H2 and its heating value is
sufficiently high to justify its compression and its use as fuel in a combined cycle. The
power generated can be increased by either by-passing more syngas over the PSA unit or
by limiting the water-gas shift reaction. The separation of CO2 however necessitates a
higher steam requirement for dilution prior to shift conversion because of the higher
heating values involved. The generation of gas turbine used for these systems are typically
the steam cooled GE 107H or the Siemens V64.3a that offer significant efficiency gains
and cost reduction. As mentioned previously, in order to limit NOx emissions, N2 frOm the
air separator is compressed and inj ected into the combustor [14].The costs for the selected
gas turbine are included in the capital costs developed.











*Heat recovery steam generator (HRSG) and steam turbine: The hot combustion gas
from the turbine is sent to a HRSG, which in turn, drives a steam turbine/generator to
produce additional electrical power. In this mode of operation, a maj or portion of the
electricity required is produced in the combustion gas turbine/generator. The steam cycle
that bottoms the gas turbine is highly integrated with the gasifieation process, which,
depending on the plant scheme, provides heat for evaporation, high pressure superheat (in
the syngas cooler) and feed-water heating. Re-heat and low pressure superheat are
generated at the HRSG.


I Compressor


Figure 2-1. Simplified Block Diagram of SMR


Particulate Gas
removral clean up



G~asifier
Particulates



Ai separator Gmnp
Coail pelrolneon coke.
tnamass waSle Biet


~,n,,,Electric power


Heat recovery
steamr geneatorr
Stack
Generator
Electric power


Figure 2-2. Detailed Process Flow Diagram of Gasifieation









CHAPTER 3
ECONOMIC ANALYSIS

3.1 Methodology

This analysis is kept simple and transparent to facilitate revision by readers wishing to use

different economic assumptions. To decide if a given process is a good investment as opposed to

another:

* Capital Cost must be determined.

* Operating Cost or Cost of Manufacturing must be determined.

* A comparison must be made of certain parameters which will be defined in this chapter.

These parameters are determined by combining the capital and operating costs.

The Chemical Engineering Plant Cost Index (CEPCI) has been employed to calculate all costs as

per 2006 $ value. Using the more common consumer price index (CPI) issued by the U.S.

government is not accurate. This index represents a composite cost index that reflects changing

costs due to inflation for the average consumer of a number of goods (e.g. housing, cost of basic

foods, transportation etc.); these are weighted appropriately to reach a value reflecting the

average cost of these goods and hence cannot be used. The basis for this cost index is shown in

Table 3-1.

3.2 Capital Cost Estimate

Capital cost pertains to the costs associated with the construction of a new plant. These

capital costs are based on equipment module costing techniques developed by Guthrie [15] in the

early 1970s and forms the basis of many of the equipment module techniques in use today. This

costing technique relates all costs back to the purchased cost of equipment evaluated for some

base conditions. Deviations from these base conditions are handled by using multiplying factors

that depend on the specific equipment, pressure and materials of construction.









To determine the capital cost for both technologies would require a detailed analysis of

each component and is beyond the scope of this work. For both SMR and gasification, the capital

cost developed by Basye et al. [16] are updated to 2006 $ and used as a base value to which

further costs are added. The costs of each included component will be mentioned as and when

they are included.

The final capital cost estimates developed for both SMR and gasification will henceforth

be referred to as Fixed Capital Investment without including the cost of land (FCIL). The cost of

land is not included as part of FCI since it is considered an investment that cannot be depreciated

since it is recoverable at the end of the proj ect life. Since the primary aim of this economic

analysis is a comparison of SMR and gasification the cost of land is assumed to be of the same

order and is therefore neglected.

3.3 Operating Cost or Cost of Manufacturing Estimate (COM)

The more important factors that influence the cost of manufacturing are provided along

with a brief explanation of each. The approach provided to calculate COM is similar to that

expressed in most engineering practices that have been well established for several decades and

is explained in detail below [17]. They can be broadly classified into three categories:

1. Direct manufacturing costs: These costs represent operating expenses that vary with
production rate. The formulae represented here are in keeping with the model developed, but
have been modified in certain cases for a more realistic approach.

* Raw materials (CRM): The raw materials used for SMR and gasification are natural gas
and coal. The industrial price of natural gas in 2006 as per the EIA was $7.5/GJ. The price
of coal used, $1.45/GJ (based on the higher heating value) was the average cost to U. S.
electric generators in 2006 as per the U.S. Energy Information Agency. Hydrogen
production capacities are obtained from Bayse et al [16]. Process efficiencies have been
updated according to recently published data [18]. Final CRM ValUeS are presented in the
appendix.

* Waste treatment (CwT): The cost of waste treatment is assumed to be zero and not
factored into the Cost of Manufacturing, but the equipment used (e.g. desulfurizer, Selexol
system used for CO2 TemOVal etc.) are accounted for while calculating FCIL.










* Utilities (CUT): COsts of utility streams are determined according to the requirements of
equipment used. CUT is difficult to estimate because of fluctuations that arise owing to
geographic and political variations. CUT for both SMR and gasification has been updated
from previously published work [19]. Cost of process water has been included for both
methods and is presented in the appendix. The huge difference between the two is a result
of the maintenance and process water requirements.

* Operating labor (COL): COst of personnel required for plant operations. The technique
used to estimate operating labor requirements is based on a correlation developed by
Alkhayat and Gerrard [20]. According to this method the operating labor requirement is
given by the equation:

NOL = (6.29 + 31.7P2 + 0.23 Nnp) 0.5 (3-1)

where NOL is the number of operators per shift, P is the number of processing steps that
involve handling, transportation and distribution, particle size control and removal. Nnp is
the number of non-particulate processing steps and includes compression, heating and
cooling, mixing and reaction. A single operator works on the average 49 weeks a year, at 5,
8-hour shifts per week. This amounts to 245 shifts/operator per year and assuming 3, 8-
hour shifts per day we have 1,095 operating shifts per year. Hence the number of operators
needed to provide for 1,095 shifts per year would be 4.5. Since NOL giVCS the number of
operators per shift per year, this number should be multiplied by 4.5 and rounded off to the
nearest whole number to determine the number of operators that need to be hired. From the
U. S. Bureau of Labor and Statistics the annual wages for a chemical manufacturing facility
is $19/hour which can be rounded off to $40,000 per year for 2,000 hours per year. Hence
multiplying the above number by $40,000 results in COL. The results of the final COL are
presented in the appendix.

* Direct supervisory and clerical labor: Cost of admini strative/engineering and support
personnel. This cost can be expressed in terms of COL aS (0. 18) COL.

* Maintenance and repairs: Cost of labor and materials associated with maintenance. This
cost can be expressed as (0.06) FCIL.

* Operating Supplies: Cost of miscellaneous supplies that support daily operation are not
considered to be raw materials. Examples include lubricants, filters, respirators and
protective equipment for operators etc. The cost of operating supplies is (0.009) FCIL.

* Laboratory charges: Costs of routine and special laboratory tests required for product
quality control and testing. These charges are represented as (0.15) FCIL-

* Patents: Cost of using patented or licensed technology. Patents are accounted for as (0.03)
COM.

Therefore the Total Direct Manufacturing Costs can be written as CRM + WT + UT + 1.33 COL









0.03 COM + 0.069 FCIL



2. Fixed manufacturing costs: Factors not affected by the level of production. These costs
occur even when the plant is not in operation.

* Depreciation: Costs associated with the physical plant (buildings, equipment etc.).
According to published data a 10% depreciation is adopted. Therefore depreciation is (0.1)
FCIL. As will be seen towards the end of this section this is just a crude approximation to
eliminate depreciation and is discussed separately owing to its significance in calculating
cash flows.

* Local taxes and insurance: Costs associated with property taxes and liability insurance.
Based on plant location and risks associated with the process and is expressed as (0.032)
FCIL.

* Plant overhead costs: Includes all costs associated with operations of auxiliary facilities
supporting the manufacturing process. Costs involve payroll and accounting services, fire
protection and safety, medical services, cafeteria and recreation facilities, payroll overhead
and employee benefits. These can be expressed as (0.708) COL + (0.036) FCIL.

Therefore the Total Fixed Manufacturing Costs can be written as (0.708) COL + (0.068) FCIL

depreciation.



3. General expenses: These costs represent an overhead burden that is necessary to carry out
business functions. They include management, sales, financing, and research expenses. These
seldom vary with production however in some cases research expenses do increase with an
increase in production.

* Administration costs: Costs for administration; includes salaries, other administration,
buildings and other related activities. Administration costs are (0. 177) COL + (0.009) FCIL.

* Distribution and selling costs: Costs of sales and marketing required to sell chemical
products. Includes salaries and other miscellaneous costs. Distribution and selling costs
amount to (0.011) COM.

* Research and development: Costs of research activities related to the product. Includes
salaries and funds for research related equipment and supplies. R&D costs are represented
as (0.05) COM.

Therefore the Total General Manufacturing Costs can be written as (0. 177) COL









(0.009) FCIL + (0. 16) COM.



Finally Total Cost of Manufacturing,

COM = (0.28) FCIL + (2.73) COL + (1.23) (CUT + WT + RM)

At this point a mention should be made that COMd = COM depreciation = (0.18) FCIL

(2.73) COL + (1.23) (CUT + WT + RM). This will be useful when describing the policy adopted

to calculate the cash flows generated for both processes in the following section.

3.4 Steps to Compare Economic Merit

To be able to judge the economic merit of SMR and gasification, FCIL and COMd mUSt be

combined and compared. This is explained further.

1. Cash flow: Cumulative cash flow diagrams that incorporate time value of money are an
effective way to analyze inflow and outflow of money. Different methods of comparisons of
SMR and gasification that are outlined here can only be derived based on creating cash flow
diagrams. Each component required to generate a cash flow diagram will now be discussed
briefly with only required information presented to simplify the analysis. Calculated results
are presented in the appendix.

* Fixed Capital Investment without the cost of land, FCIL: Capital Cost is considered as
fixed capital i.e. capital which cannot be recovered at the end of the plant life. Hence in
order to calculate depreciation (which is an integral part of any cash flow), we first
determine FCIL which is the fixed capital excluding the cost of land. The cost of land is not
included since it is the only part of the fixed capital investment that cannot be depreciated
or is recoverable at the end of the plant' s life. In all analyses the fixed capital which is
incurred at the beginning of the life of a plant will be expressed spread over a period of
time. A construction life of three years is assumed for both SMR and gasification and the
FCIL is spread at 10%, 3 5% and 55% respectively at the end of each year.

* Taxation, (t): Taxation has a direct impact on the profits realized from building and
operating a plant. When comparing proj ects, the effect of taxes must always be accounted
for. Taxation rates for companies and the laws governing taxation change frequently. For
most large corporations, the basic federal taxation rate is 35%. In addition corporations
must also pay state, city and other local taxes. The overall taxation rate is often in the range
of 40% to 50% as per the Federal Tax Rate Schedule for Corporations in 2001 [21]. A tax
rate of 42% is assumed for this study.









* Interest rate, (i): An annual interest rate of 10% has been assumed. Denoted as (i), the
interest is factored while computed discounted cash flows. This "internal" interest rate is
usually determined by corporate management and represents the minimum acceptable rate
of return that any company will accept for any new investment.

* Working Capital: Working capital comprises of variables defined earlier CRhi, FCIL and
COL. A factor of 10% for each component adds up to the working capital as shown:

Working Capital = (0. 10) CRhi + (0. 10) FCIL + (0. 10) COL

* Salvage, (S): Salvage is the scrap value of the plant equipment at the end of its useful life.
Salvage value for equipment is typically zero; however a salvage of 10% of FCIL is
estimated conservatively for both methods since a plant life of 20 years has been set (see
below), which is lower than the typical life for a proj ect of this magnitude.

* Revenue, (R): Revenue generated from both plants are computed and presented in the
appendix. Revenue is generated only after construction period of the plant in this case,
after 3 years and is assumed to be constant over the plant life. For both plants a hydrogen
production capacity of 11,870,000 GJ has been assumed as described earlier. Literature
regarding the costs of hydrogen produced by SMR and gasification were obtained from
two detailed estimates [22, and 23]. All sources reached a price of approximately $5 -
$8/GJ for a 1994 $ value for SMR and the price of hydrogen produced by gasification was
calculated to be in the range of about $10 $ 12/GJ, 1994 $ value.

For this analysis the cost of hydrogen generated as revenue was varied to determine the
least positive NPV for either proj ect to break even. As shown in Figure 3-1 the lowest cost
of hydrogen produced by SMR ($15.5/GJ) was much lower than that of gasification (~
$20/GJ). These values agree with the detailed studies mentioned where costs of hydrogen
produced from SMR and gasification can be scaled to a 2006 $ value of $11/GJ and
$16/GJ respectively. More recent studies show that the hydrogen selling price by
gasification can be reduced further by the added benefits of revenue generated from other
valuable by-products such as fuel pre-cursors, industrial grade steam and electricity which
have not been accounted for here.

Hence for a more thorough comparison the price of hydrogen generated will be assumed as
$21/GJ for both SMR and gasification.

* Cost of Manufacturing with depreciation, (COMd): COMd is the cost of manufacturing
excluding depreciation and is calculated based on relevant information provided earlier.

* Plant life, (n): The plant life indicates the life of the plant equipment to be used in
calculations. Since both SMR and gasification plants are capital intensive processes, the
plant life will henceforth be assumed as 20 years according to the guidelines set by the
U. S. Department of Treasury [24].

* Depreciation: Depreciation is defined as the difference between the original cost and the
salvage value. Only fixed capital can depreciate. Working capital (salaries, raw material,









contingencies) is recoverable at the end of the plant' s life and is not depreciated.
Depreciation is normally dependent on location of the plant. Contrary to most similar
analyses performed where either the Straight Line method (SL) or Double Declining
Balance (DDB) (both approved by the U.S. Internal Revenue Service (IRS)) is adopted for
simplicity, the Modified Accelerated Cost Recovery System (MACRS) has been adopted
for this purpose. The current federal tax law is based on MACRS and uses a half-year
convention. Since the plant and equipment life for this analysis has been set at 20 years the
MACRS here will be used over a shorter period of time, which is 10 years for this class
life. This method ensures greater accuracy since it is better to depreciate an investment as
early as possible to allow less tax paid in a given year. The MACRS method uses the DDB
method and switches to the SL method when the latter yields a greater depreciation
allowance for that year. The half-year convention assumes that the equipment is bought
midway through the first year for which depreciation is allowed and so the first year
depreciation is only half of that for a full year. Likewise in the eleventh (and last) year after
the 3-year construction period, the depreciation is again for one-half year. The MACRS
generally follows this pattern since DDB method has the largest depreciation in the early
years and SL method represents the largest depreciation towards the end of the proj ect life.
Both SL and DDB methods are described briefly:

i. Straight Line depreciation method In this method an equal amount of
depreciation is charged each year over the depreciation period allowed. The
annual depreciation in a certain year, k is denoted as dk. The total capital for
depreciation, D = FCIL S.

dk= D /n (3-2)

ii. Double Declining Balance method of depreciation In this method the amount of
depreciation each year is a constant fraction (here 2) of the book value, BVk-1.

2 ]=k-1
dkDD _,, FCE= d (3-3)


* After tax cash flow: The cash flow after taxes is finally calculated as the sum of the net
profit after taxes and depreciation.

After tax cash flow = Net profit + Depreciation = (R-COMd-dk) (1-t) + dk (3 -4)

* Cumulative discounted cash flow: Finally the cumulative discounted cash flows are
computed based on the discounted cash flows for each year. An annual interest rate of 10%
is used.

After tax cash flow
Discounted cash flow = (3-5)
[(1+i)"]i


Results are presented in Chapter 4.









2. Comparison parameters: Certain parameters that will be useful in comparing the economic
merit of both proj ects will now be discussed. All parameters are discounted back to the initial
start-up time of the proj ect to account for the time value of money. Using non-discounted
techniques to evaluate the profitability of proj ects of this magnitude and level of investment
is not recommended. The discounted parameters used in this analysis can be broadly
classified into three criteria: cash, time, and interest, and are explained further in this section:

* Net Present Value (NPV): Cumulative discounted cash position at the end of the proj ect
life. Values greater than unity indicate profitable processes while those less than unity
represent unprofitable proj ects. A higher NPV is always more desirable. The NPV of a
proj ect is the final cumulative discounted cash value at the end of the proj ect life.

* Discounted Payback period (DPBP): Time required after start-up to recover the FCIL
required for the proj ect with all cash flows discounted back to the initial time. To
determine the DPBP, the working capital is discounted back in time and the number of
years required after the project construction period to recover this amount equals the
DPBP. The proj ect with a shorter payback period is considered more desirable.

* Discounted Cash Flow Rate of Return (DCFROR): Interest rate at which all the cash
flows must be discounted in order for the NPV of the proj ect to equal zero. In other words,
DCFROR represents the highest, after-tax interest or discount rate at which the proj ect can
just break even. If the DCFROR calculated for a proj ect is greater than the internal
discount rate (here assumed 10%) then it is considered profitable. There are two methods
of calculating the DCFROR, either iteratively determine the value of "i" for which NPV
equals zero or solve the equation for NPV expressed in terms of "i" as the sum of the
cumulative discounted cash value at the end of each year.

* Monte-Carlo Simulation: The Monte-Carlo method is a concept of assigning probability
distributions to parameters, repeatedly choosing variables from these distributions and
using these values to calculate a function dependent on the variables. As a result a
sensitivity analysis arising due to risk and demand can be quantified graphically for PBP,
NPV and ROR and are presented in Chapter 4. According to Humphrey [25], parameters
that are normally varied and their probability distributions have been presented in Table 3-


However since the goal of this study is a comparison of SMR and gasification the approach
as shown above will have to be modified to produce satisfactory results. The only real
parameter that can be varied in this situation is the Cost of Raw Material, CRhi. To produce
realistic results a real-time analysis was performed of the variation of the costs of both
imported natural gas and domestically available coal from 1985 to 2005, as reported by the
EIA. A twenty-year period was chosen in keeping with the assumed 20 year construction
period for both proj ects and the year 1995 was selected as the baseline for price variation.
Forecasts of prices were not used to preserve the accuracy. As is evident from Figure 3-2,
the percentage variation of the price of natural gas is far greater than that of coal. Hence
the variations in CRhi that have been used for the Monte Carlo simulation are in keeping
with the results presented above and are presented in Table 3-3.









As explained above each parameter is chosen and a random variable is selected from
within the probability distribution range. Corresponding values of NPV, DCFROR and
DPBP are determined using the calculated values at a hydrogen selling price of $21/GJ as
the base value. These steps are then repeated; (the more values obtained the smoother the
curve). Cumulative probability data are then determined and then plotted. The results of
the Monte Carlo simulation are presented in Chapter 4.



Table 3-1. Basis for the Chemical Engineering. Plant Cost Index
Components of index Weighing. of component (%)
Equipment, machinery, and support
(a) Fabricated equipment 37
(b) Process machinery 14
(c) Pipe, valves and fittings 20
(d) Process instruments and controls 7
(e) Pumps and compressors 7
(f) Electrical equipment and materials 5
(g) Structural supports, insulation, and paint 10
100 61% of total
Erection and installation labor 22
Buildings, materials and labor 7
Engineering and supervision 10
Total 100
The CEPCI for 2006 is 478.7 and will be used for all calculations henceforth.











Table 3-2. Probable Variation of Key Parameters
Parameter Lower limit Upper limit
FCIL 20% 30%
Prce of hydrogen 10% 10%
Working capital 50% 10%
Income tax rate, t 20% 20%
Interest rate, i 10% 20%
Cost of raw material, CRM 20% 20%
Salvage value, S 80% 20%



Table 3-3. Probable Variation of Cost of Raw Material: CRM
Steam Methane Reformation
Gasification
Parameter (SMR)
Lower limit Upe limit Lower limit Uprlimit
Cost of raw material, CRM 0 % 445 % 17.9 % 76.9 %


$500 0

$400 0

$300 0

$200 0

$100 0

50.0

-5100 0

-5200.0

-5300 0

-5400.0

-5500 0


-*- SMR
'~~ m-asinic allon
21 22 23 24 25


Cost of Hydrogen ($1GJ)


Figure 3-1. Hydrogen Price Analysis with Net Present Value (NPV)


















500.0%6




400.0%




300.0%




200.0%




100.0%




0.0%6




-100.0%6


-*--Natural Gas
-=-Coal


,~~: ,5~- ,~" ,5~*" ,~ ,;~` ,~" ,~' ,~"


Year


Figure 3-2. Fluctuation in Price of Natural Gas and Coal (1985-2005)









CHAPTER 4
RESULTS AND DISCUSSION

This paper serves to examine the economic ramifications of two methods of hydrogen

production: one that is commercially already in existence worldwide, SMR; and the other

which has begun to gain a lot of interest among governments worldwide-Gasifieati on.

Although gasifieation is a well-established technology, it can only be competitive with

SMR when coal is available in plenty (e.g. U.S., China, and India). Increase in prices can be

attributed to various reasons-increased costs due to handling and pre-treatment of coal,

increased water requirements, more capital intensive equipment required for heavier cleanup

operations and labor requirements among others.

However in spite of being much more expensive, it still enj oys widespread popularity

because Integrated Gasifieation Combined Cycle power generation systems have shown

considerable potential for producing chemicals apart from hydrogen products include

ammonia, methanol and synthetic natural gas, and conventional transportation fuels [35].

This substantially reduces the overall cost, improves system efficiency and reduces

emissions. Because there are significant coal reserves in many areas of the world, coal could

replace natural gas and oil as the primary feedstock for hydrogen production in those areas

and one day promote energy independence for those nations.

The results of the economic analysis will now be presented as explained in Chapter 3.

As is evident from Figure 4-1 and Table 4-3 (and in agreement with published data) SMR is

the commercially preferred option, with a higher NPV, higher DCFROR and lower payback

period. Next, the results of the Monte-Carlo risk simulation are presented for NPV, DCFROR

and DPBP (Figures 4-2, 4-3 and 4-4).

The results show that for a cumulative probability of 500 (the median probability value

situation) the NPV of gasification is higher than SMR. Although both SMR and gasification

show high probability to reach their respective values of NPV as calculated, there is still a









high enough probability that indicates that the risks associated with SMR are high. Figure 4-3

proves that the probability of SMR having a decent DCFROR is low. In comparison

gasification shows a much stronger probability of attaining a higher DCFROR than SMR.

The results from Figure 4-4 are similar to Figure 4-3. While SMR shows a low probability of

a decent payback period, the probability of a payback period of nearly 20 years is much

higher in the case of gasification.

The above results are a strong indicator that despite the fact that current results show

that SMR may be a cheaper option, the risks associated are high and warrant massive

investment in gasification the technology of the future.










Table 4-1. Discounted Cash Flow Diagram for Steam Methane Reformation (SMR)
Cash flow
Depreciation Revenue Cash flow Cumulative cash flow
Investment FCIL-Sdk COMd (R-COMd-dk)(1-t)+dk (110H-.
Year ..dk ..R .....(di counted) (discounted)
(million $) .. (million $) .. (million $) (million $) discounted) ....
(million $) (million $) ..(million $) (million $)
(million $)
0 0.00 136.10 0.00 0.00 0.00
0 0.00 136.10 0.00 0.00 0.00
1 13.61 136.10 (13.61) (12.37) (12.37)
2 47.64 136.10 (47.64) (39.37) (51.74)
3 74.86 136.10 (74.86) (56.24) (107.98)
3 24.20 136.10 (24.20) (18.18) (126.16)
4 13.61 122.49 249.27 159.10 58.02 58.02 39.63 (86.54)
5 24.50 97.99 249.27 159.10 62.59 62.59 38.86 (47.67)
6 19.60 78.39 249.27 159.10 60.53 60.53 34.17 (13.50)
7 15.65 62.74 249.27 159.10 58.87 58.87 30.21 16.71
8 12.52 50.22 249.27 159.10 57.56 57.56 26.85 43.56
9 10.07 40.15 249.27 159.10 56.53 56.53 23.97 67.53
10 8.98 31.17 249.27 159.10 56.07 56.07 21.62 89.15
11 8.98 22.18 249.27 159.10 56.07 56.07 19.65 108.81
12 8.85 13.34 249.27 159.10 56.02 56.02 17.85 126.65
13 8.85 4.49 249.27 159.10 56.02 56.02 16.23 142.88
14 4.49 249.27 159.10 54.19 54.19 14.27 157.15
15 249.27 159.10 52.30 52.30 12.52 169.67
16 249.27 159.10 52.30 52.30 11.38 181.05
17 249.27 159.10 52.30 52.30 10.35 191.40
18 249.27 159.10 52.30 52.30 9.41 200.81
19 249.27 159.10 52.30 52.30 8.55 209.36
20 -249.27 159.10 52.30 52.30 7.77 217.13
21 249.27 159.10 52.30 52.30 7.07 224.20
22 -249.27 159.10 52.30 52.30 6.42 230.62
23 -249.27 159.10 60.19 60.19 6.72 237.35
23 24.20 2.70 240.05









Table 4-2. Discounted Cash Flow Diagram for Gasification
Cash flow
Revenue Cash flow Cumulative cash flow
Investment dk FCIL-Sdk COMd (R-COMd-dk)(1-t)+dk (110H- ..
Year .... ..R .....(discounted) (di counted)
(million $) (million $) (million $) .. (million $) (million $) discounted) ....
(million $) ..(million $) (million $)
(million $)
0 0.00 535.90 0.00 0.00 0.00
0 0.00 535.90 0.00 0.00 0.00
1 53.59 535.90 (53.59) (48.72) (48.72)
2 187.57 535.90 (187.57) (155.01) (203.73)
3 294.75 535.90 (294.75) (221.45) (425.18)
3 56.73 535.90 (56.73) (42.62) (467.80)
4 53.59 482.31 249.27 145.97 82.42 82.42 56.29 (411.50)
5 96.46 385.85 249.27 145.97 100.43 100.43 62.36 (349.14)
6 77.17 308.68 249.27 145.97 92.32 92.32 52.11 (297.03)
7 61.63 247.05 249.27 145.97 85.80 85.80 44.03 (253.00)
8 49.30 197.75 249.27 145.97 80.62 80.62 37.61 (215.39)
9 39.66 158.09 249.27 145.97 76.57 76.57 32.47 (182.92)
10 35.37 122.72 249.27 145.97 74.77 74.77 28.83 (154.10)
11 35.37 87.35 249.27 145.97 74.77 74.77 26.21 (127.89)
12 34.83 52.52 249.27 145.97 74.54 74.54 23.75 (104.14)
13 34.83 17.68 249.27 145.97 74.54 74.54 21.59 (82.55)
14 17.68 249.27 145.97 67.34 67.34 17.73 (64.81)
15 249.27 145.97 59.91 59.91 14.34 (50.47)
16 249.27 145.97 59.91 59.91 13.04 (37.43)
17 249.27 145.97 59.91 59.91 11.85 (25.58)
18 249.27 145.97 59.91 59.91 10.78 (14.80)
19 249.27 145.97 59.91 59.91 9.80 (5.01)
20 -249.27 145.97 59.91 59.91 8.91 3.90
21 249.27 145.97 59.91 59.91 8.10 12.00
22 -249.27 145.97 59.91 59.91 7.36 19.36
23 -249.27 145.97 90.99 90.99 10.16 29.52
23 56.73 6.34 35.85











Table 4-3. Discounted Profitability Criteria for Steam Methane Reformation (SMR) and
Gasification
Net present Discounted cash flow rate Discounted payback
value of return period
Proj ect
(NPV) (DCFROR) (DPBP)
(million $) (%) (years)
SMR 240.1 31.5 2.9
Gasification 35.9 11.1 12.6


19 20 21 22 23 23


-*- SMR
-m- Gasificallon


-400


Year


Figure 4-1. Discounted Cash Flow Diagram for SMR and Gasification














1000


750 -



50 -









-2500


-*--SMR
-=- Gasification


-2000 -1500 -1000 -500 0 500 1000

NPV (million $)


1500


Figure 4-2. Probability Distribution: Net Present Value (NPV)


-4- SM R
-u-- Gasilcation


005 01 015 02 025
DCFROR (%~)


Figure 4-3. Probability Distribution: Discounted Cash Flow Rate of Return (DCFROR)














1000


750









2500


-*- SMR
I Gasificallon


010 20 30 40 93 60
DPBP (years)





Figure 4-4. Probability Distribution: Discounted Payback Period (DPBP)









CHAPTER 5
CONCLUSIONS

Our study showed that in the future gasification could prove to be the more attractive

alternative when compared to SMR for hydrogen production. This is evident from the following:

* The NPV of gasification is $36 million while that of SMR is $240 million. This indicates
that the net value of the proj ect is significantly higher for SMR.

* The DCFROR for gasification 11% while that of SMR is 32%. Since we have assumed an
internal rate of return as 10% it is evident that while both proj ects are viable, SMR is a
superior alternative.

* Gasification has a DPBP of 12.6 years whereas that of SMR is 2.9 years.

* The Monte-Carlo simulation shows that the risks associated with gasification are much
lower according to the parameter variations presented in Tables 3-2 and 3-3. Therefore it is
proven that gasification is a more mature technology and must be adopted for the future.

The economic analysis performed is both comprehensive and transparent allowing revision by

readers wishing to use different economic assumptions. The results presented are conclusive and

have a great deal of accuracy for the following reasons:

* Previous economic analyses performed on hydrogen production systems have always been
focused on estimating the capital costs based on production capacities, operating pressure
requirements and material of construction to determine a price of hydrogen in ($/GJ). This
study adopts a unique approach to confirm that SMR is in fact cheaper than gasification
and is in agreement with published results. The uniqueness lies in the fact that a future
selling hydrogen price was identified and cash flows were generated for both proj ects. This
is a more economically sound method since it gives a clearer, more realistic idea of the
investments with revenues generated at the end of each year.

* As opposed to the traditional method of using CPI to account for inflation, CEPCI was
used. CEPCI was developed specifically to estimate costs of chemical engineering
facilities. Since it is not influenced by other weighted factors, it results in greater accuracy.

* Most estimates developed used either the DDB or SL method of depreciation. This is not
realistic and can create error in results. The MACRS approach used here represents the
policy adopted by the I.R. S. to depreciate chemical facilities of this nature in a real-life
situation.

* The cash flows developed are all discounted. While smaller proj ects can be evaluated by
non-discounted cash flows they should not be used for such analyses. This ensures greater
accuracy of results and follows a more realistic approach.










* A correlation was used to develop COL. While most estimates just assume the number of
workers required and their hourly wages, a relation that differentiates between hours of
operation of equipment and their operators, that accounts for shift-work for each process
stage was used.

* And finally the Monte-Carlo simulation of probability distribution to quantify the
associated risks was used to further strengthen results.

* The variation in CRM has been modified to impart a more realistic approach based on
previous cost data. This ensures greater accuracy of results from the Monte-Carlo
simulation.












Table A-1. Calculation of Fixed Capital Investment without Cost of Land (FCIL) for Steam
Methane Reformation (SMR) and Gasification
FCIL
MethodL
(million $)
SMR
(includes natural gas preparation and handling, reformer' 3.
desulfurizer, heat recovery, shift converter, PSA and other related
equipment, building, and facility)
Gaification
(includes coal storage, preparation and handling, air separation
unit, gasifier, heat recovery/syngas cooling, shift converter, Sulfur53.
removal and recovery systems, CO2 absorption, removal and
compression, PSA and other related equipment, building and
facility)


Table A-2. Calculation of CRhi for Steam Methane Reformation (SMR) and Gasification
Hydrogen Consumption
Process
production of Price CRhi
Method efficiency..
capacity natural gas ($/GJ) (million $)
(GJ) (GJ)
SMR 11,870,000 85 13,964,706 7.50 105
Gasification 11,870,000 58 20,465,517 1.45 30


Table A-3. Calculation of CLIT for Steam Methane Reformation (SMR) and Gasification
Estimated.
Price CLIT
Method consumption..
16 nlo ($/1000 gallons) (million $)
SMR
(water requirements for cooling and 4,000 0.5 2.0
process steps)
Gasification
(water requirements for cooling and 12,000 0.5 7.2
pocess steps)


Table A-4. Calculation of COL for Steam Methane Reformation (SMR) and Gasification
Hydrogen COL
3 P N, NOL *
production proceSS n (mill10H $)
SMR4 14 23 0.91
Gasification 6 16 34 1.36


APPENDIX DATA FOR ECONOMIC ANALYSIS









Table A-5. Calculation of Economic Analysis Parameters for Steam Methane Reformation
(SMR) and Gasification
Economic parameters SMR Gasification
Taxation rate 42 % 42 %
Annual interest rate 10 % 10 %
Salvage value $13,610,000 $53,590,000
Working capital $24,201,000 $56,726,000
FCIL $136, 100,000 $535,900,000
Revenue from sales $249,270,000 $249,270,000
Cost of raw materials, CRhi $105,000,000 $30,000,000
Cost of utilities, CUT $2,410,000 $7,234,000
Cost of operating labor, COL $910,000 $1,360,000
Cost of manufacturing without depreciation, COMd $159,096,600 $149,972,620
Proj ect life (years after startup) 20 20
Construction period 3 3
Distribution of FCIL
End of year one 10 % 10 %
End of year two 35 % 35 %
End of year three 55 % 55 %










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BIOGRAPHICAL SKETCH

The author obtained his bachelor' s degree in mechanical engineering from the National

Institute of Technology (formerly known as the Regional Engineering College), Tiruchirappalli,

India, in 2005. He then started his master' s degree in mechanical engineering at the University of

Florida in fall, 2005. After graduation, the author will commence his professional career in the

Steam Turbines Proj ect Management group at Siemens, Power Generation in Orlando, U. S.A.





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1 ECONOMICS OF STEAM METHANE REFO RMATION AND COAL GASIFICATION FOR HYDROGEN PRODUCTION By MIDHUN THOMAS VERGIS A THESIS PRESENTED TO THE GRADUATE SCHOOL OF THE UNIVERSITY OF FLOR IDA IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF SCIENCE UNIVERSITY OF FLORIDA 2007

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2 2007 Midhun Thomas Vergis

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3 To my family for their continuous love, support, and encouragement.

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4 ACKNOWLEDGMENTS I wish to express my gratitude to my supervisory committee (Dr. S. A. Sherif, Dr. William E. Lear, and Dr. Herbert A. Ingley) for their expe rtise, encouragement, and support. I would also like to thank Mr. Gaurav Malhot ra for his continued support.

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5 TABLE OF CONTENTS page ACKNOWLEDGMENTS...............................................................................................................4 LIST OF TABLES................................................................................................................. ..........6 LIST OF FIGURES................................................................................................................ .........7 ABSTRACT....................................................................................................................... ..............8 CHAPTER 1 BACKGROUND INFORMATION.........................................................................................9 1.1 Introduction............................................................................................................... ..........9 1.2 Why Hydrogen?.............................................................................................................. ..11 1.3 The Hydrogen Economy...................................................................................................12 2 HYDROGEN PRODUC TION METHODS...........................................................................16 2.1 Steam Methane Reformation (SMR)................................................................................16 2.1.1 Introduction............................................................................................................16 2.1.2 Process Description................................................................................................17 2.2 Gasification............................................................................................................... ........19 2.2.1 Introduction............................................................................................................19 2.2.2 Process Description................................................................................................20 3 ECONOMIC ANALYSIS......................................................................................................26 3.1 Methodology................................................................................................................ .....26 3.2 Capital Cost Estimate...................................................................................................... .26 3.3 Operating Cost or Cost of Manufacturing Estimate (COM)............................................27 3.4 Steps to Compar e Economic Merit...................................................................................30 4 RESULTS AND DISCUSSION.............................................................................................37 5 CONCLUSIONS....................................................................................................................44 APPENDIX DATA FOR ECONOMIC ANALYSIS....................................................................46 LIST OF REFERENCES............................................................................................................. ..48 BIOGRAPHICAL SKETCH.........................................................................................................50

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6 LIST OF TABLES Table page 1-1. Properties of Selected Fuels................................................................................................ .15 3-1. Basis for the Chemical Engineering Plant Cost Index......................................................... 34 3-2. Probable Variation of Key Parameters................................................................................. 35 3-3. Probable Variation of Cost of Raw Material: CRM...............................................................35 4-1. Discounted Cash Flow Diagram for Steam Methane Reformation (SMR).......................... 39 4-2. Discounted Cash Flow Diagram for Gasification................................................................ 40 4-3. Discounted Profitability Criteria for Steam Methane Reformation (SMR) and Gasification................................................................................................................... .....41 A-1. Calculation of Fixed Capital Investment without Cost of Land (FCIL) for Steam Methane Reformation (SMR) and Gasification.................................................................46 A-2. Calculation of CRM for Steam Methane Reformation (SMR) and Gasification................... 46 A-3. Calculation of CUT for Steam Methane Reformation (SMR) and Gasification................... 46 A-4. Calculation of COL for Steam Methane Reformation (SMR) and Gasification................... 46 A-5. Calculation of Econo mic Analysis Parameters for Steam Methane Reformation (SMR) and Gasification.....................................................................................................47

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7 LIST OF FIGURES Figure page 2-1 Simplified Block Diagram of SMR...................................................................................25 2-2 Detailed Process Flow Diagram of Gasification................................................................25 3-1 Hydrogen Price Analysis with Net Present Value (NPV).................................................35 3-2 Fluctuation in Price of Na tural Gas and Coal (1985-2005)...............................................36 4-1 Discounted Cash Flow Diag ram for SMR and Gasification..............................................41 4-2 Probability Distribution: Net Present Value (NPV)...........................................................42 4-3 Probability Distribution: Discounted Cash Flow Rate of Return (DCFROR)...................42 4-4 Probability Distribution: Di scounted Payback Period (DPBP).........................................43

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8 Abstract of Thesis Presen ted to the Graduate School of the University of Florida in Partial Fulfillment of the Requirements for the Degree of Master of Science ECONOMICS OF STEAM METHANE REFO RMATION AND COAL GASIFICATION FOR HYDROGEN PRODUCTION by Midhun Thomas Vergis August 2007 Chair: S. A. Sherif Major: Mechanical Engineering Fossil fuels (especially petroleum) drive t odays leading economies. However, soon that age will decline, and we will need alternatives less detrimenta l to our environment. Hydrogen continues to be one of the most promising, talk ed about energy carriers of the future. Costeffective, more environmental friendly methods of producing hydrogen need to be commercially established. In addition storage a nd transportation continue to rema in dominant hurdles that need to be improved. We performed an economic co mparison of two methods for producing hydrogen commercially steam methane reformation and coal gasification; to reac h a solution that will most benefit future generations.

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9 CHAPTER 1 BACKGROUND INFORMATION 1.1 Introduction The world is approaching the fi rst stages of an energy crisis that could have a serious impact on the security, economics, politics, and li festyle of every human being. This crisis is being caused primarily because the worlds econo my has been dependent on oil for so long and we will soon reach a stage when the growth in demand for oil exceeds our ability to supply it and we do not have commercially viable alternatives There are no immediate solutions to this problem but the repercussions in the near future will be severe, which is why we need to act soon. We have faced similar situations before (most notably the oil crises in 1973, 1979 and more recently in 1990, 2001 and 2003 onwards) that ar ose due to political reasons. In the United States, the price of oil rose from $3/bbl to almo st $40/bbl in the 1970s alon e. For the handful of industrialized nations like the Sovi et Union that were net energy e xporters the effects of the oil crisis resulted in a sudden and massive influx of money. Experts attribute the recent spike to $78/bbl in 2006 to a variety of factors: North Kor ea's missile launches, the crisis between Israel and Lebanon, Iranian nuclear bri nkmanship, and most importantly because of reports from the U.S Department of Energy confirming a decline in petroleum reserves. Evidence of this is the fact that oil comp anies spent $8 billion on exploration in 2003, but discovered only $4 billion of commercially usef ul oil [1]. More proof is Chevron Texacos recent decision to acquire an oil company and its reserves last y ear which reveals that bigger oil companies consider it cheaper to just buy oil than invest in exploration [2]. In recent years, even oil producing nations have been unable to keep pace with fast growing global demand. The fact that oil ha s increased from below $25/bbl since 2003 to

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10 $63/bbl today, while oil producers have consis tently produced at maximum capacity, is compelling evidence that oil is becoming scarce re lative to demand and that there are no more oil reserves available. Peak oil is the inevitable movement when worl d oil production hits its peak and, from that moment on, reserves are on an ever dwindling downward spiral. By the end of 2005, British Petroleum estimated the world oil reserves at 1.2 trillion barrels and at our current consumption rate of about 83 million barrels per day; we ba rely have enough to last another 40 years. According to the U.S. Energy Information Agenc y, the United States is the single largest consumer of oil worldwide at about 25% follo wed by China and Japan at 8% and 6% each. A policy of conservation of energy should be enforced. Conservation measures and steps to improve existing efficiencies can lower the rate of increased demand imposed by worldwide economic development and increase in population. And while it may be a step in the right direction there is no single so lution to avoid the long period of energy shortages we will soon enter. By acknowledging that thes e shortages are real and perman ent, there are many things we can do both individually and as a global economy to make the most from the world energy crisis which has already begun. It is the steady rise in oil prices that will force alternative energy sources that are already envir onmentally sound and commercially at tractive for future use even though they may appear more capital intensive. We need to act now to develop the infrastructure this transition requires since there is none to pr ovide fuels in the volumes required if we hope to one day replace our current use of oil. Installing this kind of infrastructure will take years. Finally the greenhouse effect a nd pollution are just a few of the environmental problems caused by the utilization of fossil fuels. One of the main pollutants is carbon dioxide. The U.S. Energy Information Agency reports that carbon dioxide accounts for about 83% of the

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11 greenhouse gases released into the atmosphere The continuing carbon dioxide pollution to the environment is causing global warming (in turn, aff ecting forests, agriculture yields, ecosystems, as well as human health and well-being). The info rmation provided in this section should prove without any doubt that the world en ergy crisis is very real and we need to adopt alternative sources of energy that are less polluting. 1.2 Why Hydrogen? One fuel that is expected to play a major role in the mid to long-term future of the energy sector is hydrogen. Hydrogen is a desirable fuel for various reasons as discussed below. Hydrogen, the lightest element, has three isotope s: hydrogen, H, deuterium, D and tritium, T [3]. Hydrogen is abundant and available in plen ty as water occupying about 70% of the earths surface. Whereas hydrogen atoms exist under certain conditions, the normal state of pure hydrogen is the hydrogen molecule, H2, which is the lightest of all ga ses. Molecular hydrogen is a product of many reactions, but is present at only low levels (0.1 ppm) in the Earths atmosphere. The hydrogen molecule exists in two forms, de signated ortho-hydroge n and para-hydrogen, depending on the nuclear spins of the atoms. Many physical and thermodynamic properties of H2 depend on the nuclear spin orientation, but the chemical properties of the two forms are the same. Compared to other possible alternatives hydr ogen has the highest energy content per unit weight of 120 MJ/kg as opposed to 48 MJ/kg for natu ral gas and 44 MJ/kg for gasoline [4]. It is a very stable molecule and is not particularly reactive under normal conditions. However, at elevated temperatures and with the aid of catalysts, H2 undergoes many reactions and forms compounds with almost every other element.

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12 Hydrogen energy has long been established scie ntifically as an environmentally cleaner source of energy to end-users, pa rticularly in transportation a pplications wit hout significant release of pollutants. Upon combustion, hydrogen re turns to water, accompanied by virtually no pollution and no greenhouse gas pro duction, in contrast to hydrocar bon-based fuels. Since U.S. transportation is 97% dependent on petroleum, (much of it imported from parts of the world that are considered politically unsta ble), a strategy of shifting to domestically-produced hydrogen fuel is very appealing. However, there are several key issues that need to be addressed. Safety, storage and transportation of hydrogen continue to remain majo r areas that need further improvement if we are to support the large capital investments needed to develo p the vast infrastructure that will propel hydrogen as the energy source of the future However significant scientific progress has been made in these fields over the last decade th at has generated growing interest worldwide. Hydrogen is a product that is fu lly capable of sustaining the worlds energy needs now and in the future. If renewably produced, hydrogen would be a fuel used that does not contribute to environmental damage and supports the human well being. 1.3 The Hydrogen Economy In virtually all advanced economies, there is considerable interest and enthusiasm over the concept of a hydrogen economy and the prospect of hydrogen-fuelled vehicles. Not since the mid 1970s, when the term hydrogen economy was firs t coined, has there be en anything like the current level of research activity and di scussion even in the popular press. Several examples of large-scale hydrogen ba sed energy systems can be cited. Among them are the World Energy Network (WE-NET) in Japan [5], the Solar Hydrogen Demonstration Plant in Neunburg vorm Wald [6] and the HYSOLAR: A German-Saudi Arabian Program on Solar Hydrogen [7]. The best example that can be cited is the FutureGen Alliance, a non-profit

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13 consortium of some of the worl ds largest coal producers and user s formed to partner with the U.S. Department of Energys Futu reGen project. Member companie s span Australia, Canada and China. These projects are aimed at establishi ng a worldwide energy system based on harnessing sources such as solar and coal, producing hydrog en via water electrolysis, and liquefying the hydrogen to the end points of use. Current efforts are to design efficient water electrolyzers, large-scale hydrogen liquefaction plants and high efficiency hydrogen gas turbines. There are still many technical hurdles yet to be fully overcome involved with the safe transportation and storage of hydrogen. The chal lenge may be summarized thus: manufacturers are unwilling to produce vehicles without an in-p lace fuelling infrastructure and fuel producers are unwilling to build that infrastructure withou t some certainty that vehicles requiring those fuels will be in operation. From a transportation perspective, generally wh at is envisioned is fuel cell powered cars that use hydrogen as fuel and produce only water vapor as emissions. A fuel cell is an energy conversion device that combines hydrogen and oxygen in an electr ochemical process to produce electric power, some low temperature heat and water vapor as the only emissions. The use of liquid hydrogen as a rocket fuel for use in space flights is we ll established and is now being seriously considered for use as fuel for aircraft. Unfortunately, 96% of all hydrogen produced in the U.S. today uses natural gas as a feedstock in spite of having the wo rlds largest reserves of coal. Th e trends in natural gas prices follow trends in the price of oil. Therefore the cost of producing hydrogen becomes dependent on the highly volatile price of natural gas. For most rapidly developing and developed nation s, the best alternative to natural gas is coal which is cheaper and more readily available. Today coal is priced as a dirty solid fuel and

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14 for this reason it is often available at a small fr action of the cost of cl eaner oil and natural gas containing the same amount of energy. The proce ss of commercial production of hydrogen along with electricity, industr ial grade process steam and pre-curs ors to produce usable transportation fuels from coal, coke and other carbonaceous ma tter is called IGCC or Integrated Gasification Combined Cycle. For more than 40 years the South African governm ent, fearing an oil embargo in retaliation to their policy of apartheid, has commercially produced a range of liquid fuels from coal including gasoline, diesel and jet fuel. Countries such as the U.S., Ch ina and India that are oil-poor but coal rich could stand to benefit greatly and could potenti ally convert its principal asse t for energy independence! Today, no single technology seems to offer a clear soluti on, although it appears that coal gasification offers a potential solution with respect to sustai nability issues and energy independence, many technical hurdles remain which suggest it is d ecades away from large scale, cost effective implementation. Given these many uncertainties, one might argue that it is premature to analyze alternative forms of infrastructure. However, if one accep ts the premise of a not-so distant hydrogen transition and the need to begin making the nece ssary investments now, st rategic planning need not wait for resolution of these many issues Rather, energy, economic and environmental analyses must be undertaken in concert with research on improved production, storage, and distribution technologies.

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15 Table 1-1. Properties of Selected Fuels Property Hydrogen H2 Methane CH4 Methanol CH3OH Gasoline C6C12 Boiling point, C -253 -162 65 Wide range Physical state at 25C Gas Gas Liquid Liquid Heating value: weight basis Lower heating value, MJ/kg 120 48 20 42 Higher heating value, MJ/kg 142 53 23 44 Heating value: volume basis* Lower heating value, MJ/Nm3 11 35 15,700 -32,000 Higher heating value, MJ/Nm3 13 39 18,100 -33,000 Flammability limits, vol. % in air 4.1 to 74.0 5.3 to 15.06.0 to 36.5 1.4 to 7.6 Explosive limits, vol. % in air 18.2 to 58.9 5.7 to 14.06.7 to 36.0 1.4 to 3.0 Molecular diffusion coefficient, cm2/s 0.61 0.16 0.13 0.05 Auto-ignition temperature in air, C 571 632 470 220 Nm3 of gas at atmospheric pressure or m3 of liquid

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16 CHAPTER 2 HYDROGEN PRODUCTION METHODS There are several methods of producing hydroge n today. Those that will be discussed and compared in this study are steam methane reformation (SMR) and gasification. A brief discussion of both technologies will be made followed by an economical analysis in the subsequent chapters in an attempt to reach a so lution that will prove most advantageous for nearterm effect and promote energy independence. Hydrogen production methods from renewable sour ces have not been considered in this analysis for several reasons. They tend to be an intermittent source of energy that is not yet completely reliable without the use of advanced storage methods. Consequently this results in huge initial investments and cannot be deemed a practical solution when compared to more commercially methods already in existence today. The initial hurdle lies in establishing these existing technologies on a larger global scale following which enough industrial experience of related supporting technologies can be better understood to equip us for future implementation of production methods from renewable sources. Today, hydrogen is produced primarily from foss il fuels (natural gas, petroleum, and coal) using well-known commercial proces ses. Worldwide, the predominant feed is natural gas (48%), followed by oilpetroleum (30%), coal (18%), an d electricity (4%) [8]. The process description that follows is not meant to provide a detail ed understanding but a brief overview comparing both technologies that lead to the process economics. 2.1 Steam Methane Reformation (SMR) 2.1.1 Introduction Large-scale catalytic steam reformation of na tural gas is the most common, least expensive method of producing hydrogen commercially ava ilable today and almost 48% of the worlds

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17 hydrogen is produced from SMR. Na tural gas is, on average, ~ 95% methane, with the balance being higher hydrocarbons (ethane, propane ) and trace contaminants, such as H2S and CO2. SMR is widely used, especially in the United States, to provide high purity hyd rogen to the chemical, petrochemical, and refining industries. 2.1.2 Process Description This method is a multi-step process that comprises of gas pre-treatment; catalytic reforming; high temperature watergas shift; low temperature watergas shift; purification; and compression/liquefaction. Descriptions of each major component technology are based on Figure 2-1. Feedstock: Natural gas to be used must be compressed before it undergoes reformation. Feed pre-treatment is generally required, since untreated natural gas ne arly always contains sulfur compounds. Pre-treatment and handling of compressed natura l gas is easier and cheaper than that required fo r coal or any other solid carbonaceous matter used in gasification. Purification (Desulfurization): After the feed is compre ssed, natural gas undergoes desulfurization to remove traces of sulfur fr om the gas. Desulfuriza tion of the feed gas, which is usually carried out us ing a zinc oxide bed, is needed since sulfur can poison the reformer catalyst. Selective Catalytic Reduction (SCR): Low NOx burner technology is sometimes not able to meet strict regulations al one and therefore, new SMRs al so require the addition of an SCR unit to the stack. Here liquid ammonia is vaporized and injected into the flue gas, which passes over a honeycomb-shaped (V2O5 TiO2) catalyst. The ammonia reacts with NOx in the presence of oxygen to form nitroge n and water vapor. By varying the ammonia injection rate, NOx is controlled to the desired level. Reformation: After pre-treatment, the feed gas is mixed with process steam at an appropriate steam-to-carbon mole ratio of 3 (t ypically) to prevent the production of solid carbon or coke, which can build up on the cataly st and plug the reactor tubes. The catalytic steam reforming reaction takes place at pre ssures of approximately 3-25 bar and high temperatures (650-900C) [8]. The reformati on is favored by high temperature and steam and reduced by higher pressure. Recent advancem ents (e.g., high pressure catalyst tubes) in reformer technology allow reliable hydroge n production even at higher operating pressures. CH4 + H2O (g) CO + 3H2 ( H = +206 kJ/mol CH4) (2-1)

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18 The catalyst, typically nickel based, is packed into tubes and the h eat needed for reaction shown above is provided externally by combustion of additional natural or purge gas. Concerns regarding emissions can be addresse d by using the latest environmental controls for NOx control and sulfur removal while desi gning an SMR facility. Environmental controls significantly add to the capita l and operating costs of a hydrogen production facility. The SMR process is a more envi ronmentally acceptable process of producing hydrogen than gasification. Low NOx burners utilize staged fu el combustion and flue gas recirculation to minimize NOx production. (Staged fuel combustion involves introducing the fuels at different locations to create two combustion zones). Tail gas from the Pressure Swing Adsorption (PSA) unit provides bulk of the heat input to the furnace, with natural gas for start up and control. Once the reformer is heated, the unit can operate with 100% PSA fuel if needed. The basic layout has th e convection section and the stack mount on top, with a process gas waste heat boiler locat ed underneath. A steam drum is mounted on top of the reformer. Shift: The synthesis gas mixture (syngas is a mixture of hydrogen and CO) is sent to the high and low temperature shift reactors, wh ere additional hydrogen is produced via the watergas shift reaction: CO + H2O (g) CO2 + H2 ( H = -41 kJ/mol CO) (2-2) The above reaction is favored at lower temper atures as opposed to the reformer reaction. To compensate for slower reaction kinetics at lower temperatures a solid Co-Mo catalyst is used. To take advantage of the high temperat ures generated, a two-stage water-gas shift reaction is generally used, with the high te mperature stage operat ing at ~ 400C and the low temperature stage at ~ 250C. The exit ga s contains primarily H2, and also CO2, H2O and small amounts of CO, methane and higher hydrocarbons. Since residual CO leaving the shift converter is recovered in the PSA unit as reformer fuel, the gain in plant efficiency if a second stage of shift is added is less when compared to the increase in equipment cost. The costs involved for the shift reactions are high, but lower when compared to the same process taking place in gasification. This can be attributed to the higher amounts of steam required to shift the larger amounts of CO generated for an equivalent amount of hydrogen. Pressure swing adsorption (PSA): After cooling of the raw gas and separation of process condensate, a PSA unit is used to purify the raw H2. They operate at about 20 bar and reach H2 separation efficiencies in the range 85%. It is the most common process used in large systems, where very high purity hydr ogen (99.999%) at ~ 30 bar is the desired product. These PSA-based hydrogen plants have higher efficiencies than conventional lowpurity plants because of additi onal export steam credits. The ad sorbent used is a mixture of activated carbon and zeolites and removes al l of the contaminants from the hydrogen product in a single step. With adjustments to the PSA operation, one can also produce a high purity CO2 stream for sequestration or for sale, in addition to the hydrogen stream but at the cost of hydrogen purity [9]. Tail gas fr om the PSA unit is used as reformer fuel. Again the costs involved with the PSA units are high but lower than a similar arrangement in gasification which will be described further on.

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19 Compression: Following the PSA purification ste p, hydrogen gas is compressed to ~ 60 bar and sent to steam generators as shown in the Figure 2-1. Heat recovery: Heat recovery coils include feed gas preheat, mixed feed (gas and steam) preheat, steam generation, and steam superheatin g. The reformer furnace process outlet is cooled in a waste heat boiler by heat excha nge with circulating feed-water to produce steam. This steam can be exported to a near by refinery or petrochemical facility for process needs and/or converted into electricity. Downstream of the shift converter, the gas is cooled against boiler feed-water. 2.2 Gasification 2.2.1 Introduction Coal has been used for centuries with the earl iest recorded use in China in 220 A.D. Later on in the 1600s when coal was heated and the release of gas was first noted, the process was described as the coal did belch forth a wild spirit or breath not susceptible of being confined in vessels, nor capable of bei ng reduced to a visible body. Coal gasification is the process of reacting coal with oxygen, steam, and carbon dioxide to form a product gas containing hydrogen and car bon monoxide. Gasification is essentially incomplete combustion. From a processing point of view the main operating difference is that gasification consumes heat ev olved during combustion. Depending on the type of gasifier and the operating conditions, gasification can be used to produce a fuel gas suitable for any number of applications. For instance, a low heating valu e fuel gas may be produced from an air blown gasifier for use as an industrial fuel and for power production. A medium heating value fuel gas may be produced from enriched oxygen blown ga sification for use as a synthesis gas in the production of chemicals such as ammonia, meth anol, and transportation fuels. A high heating value gas can be produced from shifting the medium heating valu e product gas over catalysts to produce a substitute or synthetic natural gas (SNG) The technical information described here is very similar to commercially available systems in IGCCs.

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20 2.2.2 Process Description The flexibility of gasification t echnology allows it to be integrat ed into a variety of system configurations to produce electr ical power, thermal energy, fuels, or chemicals as shown in Figure 2-2. This section provides a brief desc ription of each major component technology. Raw materials: The raw material used in the gasifier is fed as slurry. Gasifier feed (coal), is ground in mills and treated with pre-heated water to the required mixture. As indicated in the diagram, a vast array of carbonace ous matter can be used as feedstock for gasification. The advantages of flexible feed stock are outweighed however by the fact that storage, pre-treatment and handling is much more cumbersome and thus capital-intensive than using natural gas for SMR. This is one of several factors that make gasification more expensive than SMR, the others associated with the air separator, removal of ash and other particulate matter, sulfur, CO2 removal and sequestration, additional steam requirements for the shift reaction as compar ed to SMR, and finally the la rger PSA system requirements which are discussed below. Air separator: The air separator is essentially a unit that generates ~ 95% pure O2 at atmospheric pressure along with trace amounts of N2 and Ar. The O2 is then compressed to slightly higher than the gasi fier operating pressure and fe d to the gasifier. The purge N2 is also compressed and fed to the combustion gas turbine for NOx control. The air separator is one of the components that make gasificati on more expensive owing to its additional power requirements and costs associated with O2 compression. Gasifier: Current gasification technology takes place in O2-blown, entrained flow gasifiers operating at 70 bar. Entrained Flow Gasifiers have been de veloped to improve the gas production rate and can operate with a wider range of feedstock and allows complete conversion to hydrogen, carbon mon oxide, and carbon dioxide, producing no tars, oils, or phenols. Coal slurry and oxygen are fed at the top of the pressurized vessel at operating temperatures of the order of 1350C. Liquid sl ag flows down the walls and is drained from the lockhopper. In gasifiers partial combusti on occurs in an oxygen-deficient or reducing atmosphere using about 30-50% of the oxyge n theoretically required for complete combustion to carbon dioxide and water. Car bon monoxide and hydrogen are the principal products, and only a fraction of the carbon in th e coal is oxidized completely to carbon dioxide. The combustion reaction is written in a general form as: (1 + ) C + O2 2 CO + (1 ) CO2 ( H = 172.5 393.5 kJ/mol) (2-3) where varies from 0 (pure CO2 product) to 1 (pure CO product). The value of depends upon the gasification conditions and is usually close to 1. The heat released by the partial combus tion provides the bulk of the energy necessary to drive the endothermic gasification reactions. Further conversion occurs thr ough the much slower, reversible gasification reactions with CO2 and H2O produced by gasification with heavier carbonaceous material such as waste oils.

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21 C + CO2 2 CO ( H = 172.5 kJ/mol) (2-4) C + H2O CO + H2 ( H = 131 kJ/mol) (2-5) Hydrogen and carbon monoxide production increas es with decreasing oxygen in the feed, with decreasing pressure, a nd with increasing temperatur e. The composition of hydrogen and carbon monoxide produced in the newer gene ration of gasifiers are sufficient for all applications liquid production, chemical synthesis or power generation. As can be observed from the figure, excess steam from th e heat recovery steam generator (HRSG) is drawn off and can be sold as industrial-grade process steam. The remaining steam is sent to the gasifier for further syngas production as desc ribed above and also for quench cooling to ~ 250C. Although this process results in a slig ht drop in efficiency, (due to the thermal energy drop in the syngas that could have been used to create valuable high pressure steam) this process is vital for two reasons to lo wer the concentration of unwanted trace elements and to increase saturation that will promote the shift reactions that follow. The quenching process is quite inexpensive and reliable but nonetheless adds to the capital costs involved in this process. Particulate removal: Minerals (ash) in the feedstock separate and leave the bottom of the gasifier either as an inert glass-like slag or other marketable solid product. A small fraction of the ash becomes entrained in the syngas and requires dow nstream particulate removal. The raw syngas after quenching is sent to a scru bber giving a saturated flow largely free of particulate matter and water-soluble contaminants such as NH3, HCN and chlorides. Particulate removal is effected either through a se ries of dry solid filter s, so that the gas fed to the combustion turbine is essentially free of suspended particulates. In this system first, a hot cyclone removes over 90% of the partic ulates, and the remainder is removed by an advanced dry char filtration system. Slag, the major solid by-product of the gasification process, is vitrified black sand like material th at can be marketed as construction material. There are no solid wastes from the coal gasi fication process [similar to those produced by a pulverized coal process] no scrubber sludge, fl y ash or bottom ash. Ga sifier slag can be used as a principal component in concrete mi xtures (Slagcrete) to make roads, pads, and storage bins. Other applications of gasifier slag and fly sl ag are in asphalt aggregate, Portland cement kiln feed, and lightweight a ggregate. In a gasifi cation facility, heavy metals are very low because they are encapsulated in the slag. Other metals, such as mercury and selenium, are volatile and are detected in the syngas. Compared to a conventional combustion plant, metals remova l should be easier be cause the cleanup can be done on the syngas at a higher pressure in a reducing environment rather than in the lower pressure, oxidizing environment of the effluent. Thus near-complete removal from syngas exists by sele ctive adsorbents. Gas clean-up: This stage essentially frees the syngas stream of sulfur and CO2. Sulfur is converted to H2S and COS under the reducing conditions of the gasifier and the COS produced is converted to H2S at the shift reactors. The H2S is sent to a sulfur recovery unit typically found in such processes that comp rises an air-blown Claus plant for oxidizing H2S to elemental sulfur, and a Shell Claus off-gas treating (SCOT) plant for tail gas cleanup. Claus plant tail gas contains sufficiently high le vels of sulfur compounds (H2S, SO2, COS, CS2 and S vapor) that require further cleanup. In the SCOT process, these

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22 compounds are catalytica lly converted to H2S, which is removed with an amine absorption unit and recycled back to the Claus plant. A Rectisol system can be used for acid gas removal from the syngas because it provides bett er sulfur removal than an amine system. However, a Rectisol system is more expens ive and auxiliary power intensive than the amine systems. Therefore prior to CO2 capture, H2S is removed from the syngas (containing ~0.6% H2S by volume) by physical absorp tion in dimethyl ether of polyethylene glycol (Selexol) to elemental sulf ur that can be sold at ~ $100/ton. Sulfur removal efficiency exceeding 99% are commonly achieved in IGCCs [10, and 11].Combustion of coal gas in high firing-temperature gas turbines converts virtually the entire CO to CO2. CO2 removal is required since it substa ntially increases the heating value of the pressure swing adsorption (PSA) purge ga s so as to make feasible its use in a gas turbine following compression and since it reduces the size (and thus the cost) of the PSA system. CO2 is removed from the sulfur-free syngas (containing 30-32% CO2 by volume) by physical absorption in Se lexol at 35C. Unlike H2S removal, where stripping is carried out by heating the rich solvent, the CO2 is released without hea ting in a series of flash drums at decreasing pressures. Since CO2 emissions is a major concern with gasification a mention will be made at this point about sequestration. After CO2 is separated from the process stream, it is sequestered so it is not released to the atmosphere. The two most commonly proposed methods for sequestra tion are ocean disposal and underground injection [9]. In ocean disposal, se veral options are available Liquid CO2 may be released from pipelines at depths of 2,000 m or more; solid CO2 can be disposed of by ships; or CO2 can be converted into hydrates for di sposal. With underground sequestration, the CO2 is injected into depleted natural gas reser voirs or other geologic formations such as aquifers. Okken [9] estimates that there is a to tal of 5 years worth of capacity in old natural gas wells and an additional 15 years capacity in sedimentary basins. Although the ocean has a CO2 uptake capacity that is almost 7,000 times greater than current carbon emissions it cannot be considered feasible since the CO2 will not remain in the ocean for long and requires further investigation into the impact s on marine ecosystems. Ocean disposal can be considered for future implementati on but not while the costs involved are approximately twice those of underground in jection. Costs for removal, stripping and compression of CO2 are included from previous estimat es and included in the economic analysis in the next chapter. This and the su lfur removal systems substantially increase the cost of gasification. During gasification the ni trogen content of coal is converted to molecular nitrogen, N2, ammonia, NH3, and a small amount of hydrogen cyanide, HCN. Other techniques are being investigated in hot-gas cleanup technologies. The lower NOx from the combustion turbines are the result of improved turbine design and the use of a diluent (steam or N2 purge gas) for NOx control. Since a major portion of the power generated comes from the gas turbine, the wate r requirement is substantially reduced from that required for a conventional coal-fired power plant, where all of the power is generated from steam turbines. The problem of water re quired for water-treatment systems to address tars, phenols, and metals is eliminated for en trained-flow gasifiers. The waste water from the gasification plants is cleaned up to m eet the requirements for water discharges. However, if desired and at a dditional expense, a reverse osmo sis system can be added to treat the waste water from the gasification sy stem to obtain a zero discharge system. The water required by a gasification facility is a va riable that is often neglected. Hence a rough

PAGE 23

23 estimate of the water requirements of both SMR and gasification will be made to produce realistic results. Shift reactor: The mixture of H2O and CO (water-gas) shift reaction is used to shift the bulk of the streams chemical energy into H2. The reaction taking place is: CO + H2O (g) CO2 + H2 ( H = -41 kJ/mol) (2-6) This reaction is favored at low temperatur es where the reaction rates are slow thus requiring the use of a sulfur-toler ant solid Co-Mo catalyst. To ma ke the best use of the heat generated by the reaction and to ade quately promote the formation of H2 two shift reactors are employed in series with cooling in betw een either by pressurized steam generation or heating of boiler feed-water. Th e initial reactor conve rts 85-90% of the CO and allows the syngas to reach ~ 400C by generating high pres sure steam. Syngas then enters the second reactor where CO conversion proceeds adiabatic ally up to 98% and th e temperature reaches 225C. The syngas is again cooled as descri bed earlier. A third low temperature reactor may be included for maximum conversion effici encies of over 99% but is not always considered cost effective. Syngas is cooled at each stage in prep aration for downstream processes. Syngas conversion: Pressure swing adsorption (PSA) units purify the hydrogen. High purity (~99.999%) H2 is assumed to be extracted from the clean syngas at 35C using PSA. As reviewed earlier, PSA units used in SMR operate at about 20 bar and reaches H2 separation efficiencies in the ra nge 85%. To maintain the same H2 separation efficiency at pressures of 70 bar considered here would require a more complex (and more expensive) system arrangement and is consistent with current information. Pure hydrogen exits the PSA, while the purge gas (the remaining 15% H2 along with the other species) is discharged at 1.5 bar and can be used to ge nerate steam for power production in the steam turbine. At a pressure exceeding 60 bar, the H2 product is suited for long-range pipeline transport and there is no need for further co mpression as with SMR. The larger and more complex PSA system required of gasification ag ain is another paramete r that results in it being more capital intensive over SMR. Fuels and chemicals: It was South Africas policy of apartheid and consequently economic sanctions being imposed that forced them to produce liquid fuels from hydrocarbon synthesis processe s such as the Fisher-Tr opsch method. This technology developed by German scientists during Hitlers regime has been employed by Sasol successfully for the past 50 years. Gasificat ion is the only advanced power generation technology capable of co-producing a wide va riety of commodity and premium products (e.g., methanol, higher alcohols, diesel fuel, je t fuel and gasoline) in addition to hydrogen, electricity and industrial-grade process steam to meet future market requirements. It is this ability to produce value-added products from impure H2-rich syngas left after CO2 removal that has made gasification economical in select ed situations and will be a key driver in a deregulated power market. China maintains that shipping crude oil long distances from the coast to remote Inner Mongolia for conventional fuels refining would be expensive, whereas producing coal-derived fuels via li quefaction would be relatively competitive. Recently the Chinese government approve d large-scale efforts to produce liquid

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24 transportation fuels using coal gasification [ 12]. China's largest coal firm, Shenhua Group, plans to start up the country's first coal-to-fu els plant in 2007 or early 2008, in the world's most ambitious application of coal liquef action since World War II. Shenhua plans to operate eight liquefaction plants by 2020, produci ng, in total, more th an 30 million tons of synthetic oil annually enough to displace more than 10 percent of her projected oil imports. China's progress in constructing coal -conversion plants put s it far ahead of the U.S., where coal gasification is still recove ring from a damaged reputation. The finished fuels would be hauled from the plants in tank -cars via Shenhua's existing railroads adjacent to the mines. These trains already haul coal for later trans-shipment via waterways to city markets. To quantify the costs involved in producing such fuel pre-cursors is extremely case-specific and has not been considered in this analysis. Fuel cells: The most attractive energy conversion t echnology that uses hydrogen is fuel cells. A fuel cell is an energy conversion de vice that combines hydrogen and oxygen in an electrochemical process to produce a non fl uctuating DC power output, some lowtemperature heat, and water vapor as the only emissions. Different type s of fuel cells are distinguished by their different electrolytes and the different temperatures reached during operation. Today, fuel cells are used in ma nned space flight to provide power for the spacecraft and drinking water for the astronauts; as backup power for critical services in hospitals and banks; and in an increasi ng number of cars and buses. Substantial development efforts are underway by automobile manufacturers in Germany, Japan and the U.S. to bring fuel cell vehicle technology to the market. Fuel cells such as POFC, SOFC and PEM cells are used today and will continue to increase in the future. Hydrogen fuel cell vehicles have several poten tial advantages over conventi onal gasoline engine vehicles including higher fuel efficiency, lower greenhouse gas and conventional pollutant emissions, longer lifetimes, and lower drive tr ain maintenance costs. In addition, hydrogen fuel vehicles are projected to have excelle nt fuel economy at 66 mpg, gasoline equivalent [13]. If hydrogen produced with se questration of the separated CO2 were used in fuel cell cars, lifecycle CO2 emissions per km would be less than 1/5 of those for gasoline internal combustion engine cars. Costs involved with th e manufacture of fuel cells or the resulting drop in CO2 emissions is beyond the scope of this analysis and has not been included. Combustion/combustion turbine: The cleaned synthesis gas is then combusted in a high efficiency gas turbine/generator to produce both electrical power and supply compressed air to the air separation unit th at generates oxygen for the gasi fier. The chemical energy of the low pressure PSA purge gas can be used to produce electric power. Due to the removal of CO2 ahead of PSA the purge gas consists mainly of H2 and its heating value is sufficiently high to justify its compression and its use as fuel in a combined cycle. The power generated can be increased by either by-passing more syngas over the PSA unit or by limiting the water-gas shift reaction. The separation of CO2 however necessitates a higher steam requirement for dilution prior to shift conversion because of the higher heating values involved. The generation of gas turbine used for these systems are typically the steam cooled GE 107H or the Siemens V 64.3a that offer significant efficiency gains and cost reduction. As mentioned previously, in order to limit NOx emissions, N2 from the air separator is compressed and injected into the combustor [14].The costs for the selected gas turbine are included in the capital costs developed.

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25 Heat recovery steam generato r (HRSG) and steam turbine: The hot combustion gas from the turbine is sent to a HRSG, which in turn, drives a steam turbine/generator to produce additional electrical power. In this mode of operation, a major portion of the electricity required is produced in the combustion gas turbin e/generator. The steam cycle that bottoms the gas turbine is highly integr ated with the gasification process, which, depending on the plant scheme, provides heat fo r evaporation, high pr essure superheat (in the syngas cooler) and feed-water heating. Re-heat and low pressure superheat are generated at the HRSG. Figure 2-1. Simplified Block Diagram of SMR Figure 2-2. Detailed Process Fl ow Diagram of Gasification

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26 CHAPTER 3 ECONOMIC ANALYSIS 3.1 Methodology This analysis is kept simple and transparent to facilitate revision by readers wishing to use different economic assumptions. To decide if a given process is a good investment as opposed to another: Capital Cost must be determined. Operating Cost or Cost of Manufacturing must be determined. A comparison must be made of certain paramete rs which will be defined in this chapter. These parameters are determined by comb ining the capital and operating costs. The Chemical Engineering Plant Cost Index (CEPC I) has been employed to calculate all costs as per 2006 $ value. Using the more common consum er price index (CPI) issued by the U.S. government is not accurate. This index represents a composite cost index that reflects changing costs due to inflation for the average consumer of a number of goods (e.g. housing, cost of basic foods, transportation etc.); thes e are weighted appropriately to reach a value reflecting the average cost of these goods and he nce cannot be used. The basis for this cost index is shown in Table 3-1. 3.2 Capital Cost Estimate Capital cost pertains to the costs associated with the construction of a new plant. These capital costs are based on equipment modul e costing techniques developed by Guthrie [15] in the early 1970s and forms the basis of many of the equipment module technique s in use today. This costing technique relates all cost s back to the purchased cost of equipment evaluated for some base conditions. Deviations from these base c onditions are handled by using multiplying factors that depend on the specific equipment, pr essure and materials of construction.

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27 To determine the capital cost for both technolog ies would require a de tailed analysis of each component and is beyond the scope of this work. For both SMR and gasification, the capital cost developed by Basye et al. [16] are updated to 2006 $ and used as a base value to which further costs are added. The costs of each includ ed component will be mentioned as and when they are included. The final capital cost estimates developed for both SMR and gasification will henceforth be referred to as Fixed Capital Investme nt without including the cost of land (FCIL). The cost of land is not included as part of FCI since it is cons idered an investment th at cannot be depreciated since it is recoverable at the e nd of the project life. Since th e primary aim of this economic analysis is a comparison of SMR and gasification th e cost of land is assumed to be of the same order and is therefore neglected. 3.3 Operating Cost or Cost of Manufacturing Estimate (COM) The more important factors that influence the cost of manufactu ring are provided along with a brief explanation of each. The approach provided to calculate COM is similar to that expressed in most engineering pr actices that have been well esta blished for several decades and is explained in detail below [17]. They can be broadly classified into three categories: 1. Direct manufacturing costs: These costs represent operating expenses that vary with production rate. The formulae represented here ar e in keeping with th e model developed, but have been modified in certain cases for a more realistic approach. Raw materials (CRM): The raw materials used for SMR and gasification are natural gas and coal. The industrial price of natural gas in 2006 as pe r the EIA was $7.5/GJ. The price of coal used, $1.45/GJ (based on the higher heat ing value) was the average cost to U.S. electric generators in 2006 as per the U.S. Energy Information Agency. Hydrogen production capacities are obtained from Bayse et al [16]. Pro cess efficiencies have been updated according to recently published data [18]. Final CRM values are presented in the appendix. Waste treatment (CWT): The cost of waste treatment is assumed to be zero and not factored into the Cost of Ma nufacturing, but the equipment us ed (e.g. desulfurizer, Selexol system used for CO2 removal etc.) are accounted for while calculating FCIL.

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28 Utilities (CUT): Costs of utility streams are determined according to the requirements of equipment used. CUT is difficult to estimate because of fluctuations that arise owing to geographic and political variations. CUT for both SMR and gasification has been updated from previously published work [19]. Cost of process water has been included for both methods and is presented in the appendix. The huge difference between the two is a result of the maintenance and process water requirements. Operating labor (COL): Cost of personnel required fo r plant operations. The technique used to estimate operating labor requirem ents is based on a correlation developed by Alkhayat and Gerrard [20]. According to this method the operating labor requirement is given by the equation: NOL = (6.29 + 31.7P2 + 0.23 Nnp) 0.5 (3-1) where NOL is the number of operators per shift, P is the number of processing steps that involve handling, transportati on and distribution, particle size control and removal. Nnp is the number of non-particulate processing st eps and includes comp ression, heating and cooling, mixing and reaction. A single operator works on the average 49 weeks a year, at 5, 8-hour shifts per week. This amounts to 245 shifts/operator per y ear and assuming 3, 8hour shifts per day we have 1,095 operating shifts per year. Hence the number of operators needed to provide for 1,095 shifts per year would be 4.5. Since NOL gives the number of operators per shift per year, this number s hould be multiplied by 4.5 and rounded off to the nearest whole number to determin e the number of operato rs that need to be hired. From the U.S. Bureau of Labor and Statistics the annua l wages for a chemical manufacturing facility is $19/hour which can be rounded off to $40,000 per year for 2,000 hours per year. Hence multiplying the above number by $40,000 results in COL. The results of the final COL are presented in the appendix. Direct supervisory and clerical labor: Cost of administrative/engineering and support personnel. This cost can be expressed in terms of COL as (0.18) COL. Maintenance and repairs: Cost of labor and materials asso ciated with maintenance. This cost can be expressed as (0.06) FCIL. Operating Supplies: Cost of miscellaneous supplies th at support daily op eration are not considered to be raw materials. Examples include lubricants, filters, respirators and protective equipment for opera tors etc. The cost of ope rating supplies is (0.009) FCIL. Laboratory charges: Costs of routine and special labo ratory tests requ ired for product quality control and testing. These ch arges are represented as (0.15) FCIL. Patents: Cost of using patented or licensed t echnology. Patents are accounted for as (0.03) COM. Therefore the Total Direct Manufact uring Costs can be written as CRM + CWT + CUT + 1.33 COL +

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29 0.03 COM + 0.069 FCIL 2. Fixed manufacturing costs: Factors not affected by the level of production. These costs occur even when the plant is not in operation. Depreciation: Costs associated with the physical plant (buildings, equipment etc.). According to published data a 10 % depreciation is adopted. Th erefore depreciation is (0.1) FCIL. As will be seen towards the end of this se ction this is just a crude approximation to eliminate depreciation and is discussed separate ly owing to its significance in calculating cash flows. Local taxes and insurance: Costs associated with property taxes and liability insurance. Based on plant location and risks associated w ith the process and is expressed as (0.032) FCIL. Plant overhead costs: Includes all costs associated with operations of au xiliary facilities supporting the manufacturing proc ess. Costs involve payroll and accounting services, fire protection and safety, medical se rvices, cafeteria and recreati on facilities, payroll overhead and employee benefits. These can be expressed as (0.708) COL + (0.036) FCIL. Therefore the Total Fixed Manufacturi ng Costs can be written as (0.708) COL + (0.068) FCIL + depreciation. 3. General expenses: These costs represent an overhead bur den that is necessary to carry out business functions. They include management, sa les, financing, and research expenses. These seldom vary with production however in some cas es research expenses do increase with an increase in production. Administration costs: Costs for administration; include s salaries, other administration, buildings and other related activitie s. Administration costs are (0.177) COL + (0.009) FCIL. Distribution and selling costs: Costs of sales and marketin g required to sell chemical products. Includes salaries and other miscellaneous costs. Di stribution and selling costs amount to (0.011) COM. Research and development: Costs of research activities re lated to the product. Includes salaries and funds for research related equi pment and supplies. R&D costs are represented as (0.05) COM. Therefore the Total General Manufacturi ng Costs can be written as (0.177) COL +

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30 (0.009) FCIL + (0.16) COM. Finally Total Cost of Manufacturing, COM = (0.28) FCIL + (2.73) COL + (1.23) (CUT + CWT + CRM) At this point a mention should be made that COMd = COM depreciation = (0.18) FCIL + (2.73) COL + (1.23) (CUT + CWT + CRM). This will be useful when describing the policy adopted to calculate the cash flows generated fo r both processes in the following section. 3.4 Steps to Compare Economic Merit To be able to judge the economic merit of SMR and gasification, FCIL and COMd must be combined and compared. This is explained further. 1. Cash flow: Cumulative cash flow diagrams that in corporate time value of money are an effective way to analyze inflow and outflow of money. Different methods of comparisons of SMR and gasification that are outlined here can only be derived based on creating cash flow diagrams. Each component required to genera te a cash flow diagram will now be discussed briefly with only required information presente d to simplify the analysis. Calculated results are presented in the appendix. Fixed Capital Investment with out the cost of land, FCIL: Capital Cost is considered as fixed capital i.e. capital which cannot be recovered at the end of the plant life. Hence in order to calculate depreciation (which is an integral part of any cash flow), we first determine FCIL which is the fixed capital excluding the cost of land. The cost of land is not included since it is the only pa rt of the fixed capital investme nt that cannot be depreciated or is recoverable at the end of the plants li fe. In all analyses the fixed capital which is incurred at the beginning of the life of a plant will be expr essed spread over a period of time. A construction life of three years is assumed for both SMR and gasification and the FCIL is spread at 10%, 35% and 55% resp ectively at the end of each year. Taxation, (t): Taxation has a direct impact on the profits realized from building and operating a plant. When comparing projects, th e effect of taxes must always be accounted for. Taxation rates for companies and the laws governing taxation ch ange frequently. For most large corporations, the basic federal ta xation rate is 35%. In addition corporations must also pay state, city and other local taxes. The overall taxa tion rate is often in the range of 40% to 50% as per the Fe deral Tax Rate Schedule for Co rporations in 2001 [21]. A tax rate of 42% is assumed for this study.

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31 Interest rate, (i): An annual interest rate of 10% has been assumed. Denoted as (i), the interest is factored while computed discounted ca sh flows. This interna l interest rate is usually determined by corporate management and represents the minimum acceptable rate of return that any company will accept for any new investment. Working Capital: Working capital comprises of variables defined earlier CRM, FCIL and COL. A factor of 10% for each component adds up to the working capital as shown: Working Capital = (0.10) CRM + (0.10) FCIL + (0.10) COL Salvage, (S): Salvage is the scrap value of the plant e quipment at the end of its useful life. Salvage value for equipment is typically zero; however a salvage of 10% of FCIL is estimated conservatively for both methods sinc e a plant life of 20 y ears has been set (see below), which is lower than the typical life for a project of this magnitude. Revenue, (R): Revenue generated from both plants are computed and presented in the appendix. Revenue is generated only after constr uction period of the plant in this case, after 3 years and is assumed to be constant over the plant life. Fo r both plants a hydrogen production capacity of 11,870,000 GJ has been assu med as described earlier. Literature regarding the costs of hydr ogen produced by SMR and gasi fication were obtained from two detailed estimates [22, and 23]. All sour ces reached a price of approximately $5 $8/GJ for a 1994 $ value for SMR and the pri ce of hydrogen produced by gasification was calculated to be in th e range of about $10 $12/GJ, 1994 $ value. For this analysis the cost of hydrogen generated as revenue was varied to determine the least positive NPV for either project to break even. As shown in Figure 3-1 the lowest cost of hydrogen produced by SMR ($15.5/GJ) was much lower than that of gasification (~ $20/GJ). These values agree w ith the detailed studies men tioned where costs of hydrogen produced from SMR and gasification can be scaled to a 2006 $ value of $11/GJ and $16/GJ respectively. More recent studies s how that the hydroge n selling price by gasification can be reduced further by the adde d benefits of revenue generated from other valuable by-products such as fuel pre-cursors, industrial grade steam and electricity which have not been accounted for here. Hence for a more thorough comparison the pri ce of hydrogen generated will be assumed as $21/GJ for both SMR and gasification. Cost of Manufacturing with depreciation, (COMd): COMd is the cost of manufacturing excluding depreciation and is calc ulated based on relevant in formation provided earlier. Plant life, (n): The plant life indicates the life of the plant equipment to be used in calculations. Since both SMR and gasification plants are capital intensive processes, the plant life will henceforth be assumed as 20 years according to the guidelines set by the U.S. Department of Treasury [24]. Depreciation: Depreciation is defined as the difference between the original cost and the salvage value. Only fixed capital can depreciate. Working capital (salaries, raw material,

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32 contingencies) is recoverabl e at the end of the plants life and is not depreciated. Depreciation is normally dependent on location of the plant. Contrary to most similar analyses performed where either the Straig ht Line method (SL) or Double Declining Balance (DDB) (both approved by the U.S. Inte rnal Revenue Service (IRS)) is adopted for simplicity, the Modified Accelerated Cost Recovery System (MACRS) has been adopted for this purpose. The current federal tax law is based on MACRS and uses a half-year convention. Since the plant and equipment life for this analysis has been set at 20 years the MACRS here will be used over a shorter period of time, which is 10 years for this class life. This method ensures greater accuracy since it is better to depreciate an investment as early as possible to allow less tax paid in a given year. The MACRS method uses the DDB method and switches to the SL method when the latter yields a greater depreciation allowance for that year. The half-year conve ntion assumes that the equipment is bought midway through the first year for which depr eciation is allowed and so the first year depreciation is only half of that for a full year. Likewise in th e eleventh (and last) year after the 3-year construction period, the depreciation is again fo r one-half year. The MACRS generally follows this pattern since DDB met hod has the largest depreciation in the early years and SL method represents the largest depr eciation towards the end of the project life. Both SL and DDB methods are described briefly: i. Straight Line depreciation method In this method an equal amount of depreciation is charged each year ov er the depreciation period allowed. The annual depreciation in a certain year, k is denoted as dk. The total capital for depreciation, D = FCIL S. dk = D / n (3-2) ii. Double Declining Balance method of depreciation In this method the amount of depreciation each year is a constant fraction (here 2) of the book value, BVk-1. dk DDB = 1 L j 02 FCIdjk jn (3-3) After tax cash flow: The cash flow after taxes is finally calculated as the sum of the net profit after taxes and depreciation. After tax cash flow = Net profit + Depreciation = (RCOMddk) (1-t) + dk (3-4) Cumulative discounted cash flow: Finally the cumulative discounted cash flows are computed based on the discounted cash flows fo r each year. An annual interest rate of 10% is used. Discounted cash flow = nAfter tax cash flow [(1+i)] (3-5) Results are presented in Chapter 4.

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33 2. Comparison parameters: Certain parameters that will be useful in comparing the economic merit of both projects will now be discussed. All parameters are discounted back to the initial start-up time of the project to account for the time value of money. Using non-discounted techniques to evaluate the prof itability of projects of this ma gnitude and level of investment is not recommended. The discounted parameters used in this analysis can be broadly classified into three criteria: cash, time, and inte rest, and are explained fu rther in this section: Net Present Value (NPV): Cumulative discounted cash positi on at the end of the project life. Values greater than unity indicate profitable processe s while those less than unity represent unprofitable pr ojects. A higher NPV is always more desirable. The NPV of a project is the final cumulative discounted cash value at the end of the project life. Discounted Payback period (DPBP): Time required after star t-up to recover the FCIL required for the project with all cash flows discounted back to the initial time. To determine the DPBP, the working capital is discounted back in time and the number of years required after the projec t construction period to reco ver this amount equals the DPBP. The project with a shor ter payback period is considered more desirable. Discounted Cash Flow Ra te of Return (DCFROR): Interest rate at which all the cash flows must be discounted in orde r for the NPV of the project to equal zero. In other words, DCFROR represents the highest, after-tax intere st or discount rate at which the project can just break even. If the DCFROR calculated fo r a project is greater than the internal discount rate (here assumed 10%) then it is co nsidered profitable. There are two methods of calculating the DCFROR, either iteratively determine the value of i for which NPV equals zero or solve the equation for NPV e xpressed in terms of i as the sum of the cumulative discounted cash value at the end of each year. Monte-Carlo Simulation: The Monte-Carlo method is a concept of assigning probability distributions to parameters, repeatedly choosing variables from these distributions and using these values to calculate a function dependent on the variables. As a result a sensitivity analysis arising due to risk and demand can be quantifie d graphically for PBP, NPV and ROR and are presented in Chapter 4. According to Humphrey [25], parameters that are normally varied and th eir probability distributions ha ve been presented in Table 32. However since the goal of this study is a comp arison of SMR and gasification the approach as shown above will have to be modified to produce satisfactory results. The only real parameter that can be varied in this si tuation is the Cost of Raw Material, CRM. To produce realistic results a real-time analysis was perf ormed of the variation of the costs of both imported natural gas and domestically availa ble coal from 1985 to 2005, as reported by the EIA. A twenty-year period was chosen in k eeping with the assume d 20 year construction period for both projects and the year 1995 was se lected as the baseline for price variation. Forecasts of prices were not used to preser ve the accuracy. As is evident from Figure 3-2, the percentage variation of the price of natural gas is far grea ter than that of coal. Hence the variations in CRM that have been used for the M onte Carlo simulation are in keeping with the results presented above and are presented in Table 3-3.

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34 As explained above each parameter is chosen and a random variable is selected from within the probability distri bution range. Corresponding va lues of NPV, DCFROR and DPBP are determined using the calculated valu es at a hydrogen selling price of $21/GJ as the base value. These steps are then repeated ; (the more values obtained the smoother the curve). Cumulative probability data are then determined and then plotted. The results of the Monte Carlo simulation are presented in Chapter 4. Table 3-1. Basis for the Chemical Engineering Plant Cost Index Components of index Weighing of component (%) Equipment, machinery, and support (a) Fabricated equipment 37 (b) Process machinery 14 (c) Pipe, valves and fittings 20 (d) Process instruments and controls 7 (e) Pumps and compressors 7 (f) Electrical equipment and materials 5 (g) Structural supports, insulation, and paint 10 100 61% of total Erection and installation labor 22 Buildings, materials and labor 7 Engineering and supervision 10 Total 100 The CEPCI for 2006 is 478.7 and will be used for all calculations henceforth.

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35 Table 3-2. Probable Variation of Key Parameters Parameter Lower limit U pper limit FCIL 20% 30% Price of hydrogen 10% 10% Working capital 50% 10% Income tax rate, t 20% 20% Interest rate, i 10% 20% Cost of raw material, CRM 20% 20% Salvage value, S 80% 20% Table 3-3. Probable Variation of Cost of Raw Material: CRM Steam Methane Reformation (SMR) Gasification Parameter Lower limit Upper limit Lower limit Upper limit Cost of raw material, CRM 0 % 445 % 17.9 % 76.9 % Figure 3-1. Hydrogen Price Analysis with Net Present Value (NPV)

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36 Figure 3-2. Fluctuation in Price of Natural Gas and Coal (1985-2005)

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37 CHAPTER 4 RESULTS AND DISCUSSION This paper serves to examine the economi c ramifications of two methods of hydrogen production: one that is commercially already in existen ce worldwide, SMR; and the other which has begun to gain a lot of interest among governments worldwide-Gasification. Although gasification is a well-established t echnology, it can only be competitive with SMR when coal is available in plenty (e.g. U.S ., China, and India). Increase in prices can be attributed to various reasons-i ncreased costs due to handli ng and pre-treatment of coal, increased water requirements, more capital in tensive equipment required for heavier cleanup operations and labor requirements among others. However in spite of being much more expe nsive, it still enjoys widespread popularity because Integrated Gasification Combined Cycle power generation systems have shown considerable potential for producing chemical s apart from hydrogen products include ammonia, methanol and synthetic natural gas, and conventional transportation fuels [35]. This substantially reduces the overall cost, improves system efficiency and reduces emissions. Because there are significant coal re serves in many areas of the world, coal could replace natural gas and oil as the primary feedstock for hydr ogen production in those areas and one day promote energy inde pendence for those nations. The results of the economic analysis will now be presented as explained in Chapter 3. As is evident from Figure 4-1 and Table 4-3 (and in agreement with published data) SMR is the commercially preferred opt ion, with a higher NPV, higher DCFROR and lower payback period. Next, the results of the Monte-Carlo risk simulation ar e presented for NPV, DCFROR and DPBP (Figures 4-2, 4-3 and 4-4). The results show that for a cumulative probabi lity of 500 (the median probability value situation) the NPV of gasification is highe r than SMR. Although bot h SMR and gasification show high probability to reach th eir respective values of NPV as calculated, there is still a

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38 high enough probability that indica tes that the risks associated with SMR are high. Figure 4-3 proves that the probability of SMR having a decent DCFROR is low. In comparison gasification shows a much str onger probability of attaining a higher DCFROR than SMR. The results from Figure 4-4 are similar to Figure 4-3. While SMR shows a low probability of a decent payback period, the probability of a payback period of nearly 20 years is much higher in the case of gasification. The above results are a strong in dicator that despite the fact that current results show that SMR may be a cheaper option, the risk s associated are high and warrant massive investment in gasification th e technology of the future.

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39Table 4-1. Discounted Cash Flow Diagram for Steam Methane Reformation (SMR) Year Investment (million $) Depreciation dk (million $) FCIL-Sdk (million $) Revenue R (million $) COMd (million $) (R-COMd-dk)(1-t)+dk(million $) Cash flow (nondiscounted) (million $) Cash flow (discounted) (million $) Cumulative cash flow (discounted) (million $) 0 0.00 136.10 0.00 0.00 0.00 0 0.00 136.10 0.00 0.00 0.00 1 13.61 136.10 (13.61) (12.37) (12.37) 2 47.64 136.10 (47.64) (39.37) (51.74) 3 74.86 136.10 (74.86) (56.24) (107.98) 3 24.20 136.10 (24.20) (18.18) (126.16) 4 13.61 122.49 249.27 159.10 58.02 58.02 39.63 (86.54) 5 24.50 97.99 249.27 159.10 62.59 62.59 38.86 (47.67) 6 19.60 78.39 249.27 159.10 60.53 60.53 34.17 (13.50) 7 15.65 62.74 249.27 159.10 58.87 58.87 30.21 16.71 8 12.52 50.22 249.27 159.10 57.56 57.56 26.85 43.56 9 10.07 40.15 249.27 159.10 56.53 56.53 23.97 67.53 10 8.98 31.17 249.27 159.10 56.07 56.07 21.62 89.15 11 8.98 22.18 249.27 159.10 56.07 56.07 19.65 108.81 12 8.85 13.34 249.27 159.10 56.02 56.02 17.85 126.65 13 8.85 4.49 249.27 159.10 56.02 56.02 16.23 142.88 14 4.49 249.27 159.10 54.19 54.19 14.27 157.15 15 249.27 159.10 52.30 52.30 12.52 169.67 16 249.27 159.10 52.30 52.30 11.38 181.05 17 249.27 159.10 52.30 52.30 10.35 191.40 18 249.27 159.10 52.30 52.30 9.41 200.81 19 249.27 159.10 52.30 52.30 8.55 209.36 20 249.27 159.10 52.30 52.30 7.77 217.13 21 249.27 159.10 52.30 52.30 7.07 224.20 22 249.27 159.10 52.30 52.30 6.42 230.62 23 249.27 159.10 60.19 60.19 6.72 237.35 23 24.20 2.70 240.05

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40Table 4-2. Discounted Cash Flow Diagram for Gasification Year Investment (million $) dk (million $) FCIL-Sdk (million $) Revenue R (million $) COMd (million $) (R-COMd-dk)(1-t)+dk(million $) Cash flow (nondiscounted) (million $) Cash flow (discounted) (million $) Cumulative cash flow (discounted) (million $) 0 0.00 535.90 0.00 0.00 0.00 0 0.00 535.90 0.00 0.00 0.00 1 53.59 535.90 (53.59) (48.72) (48.72) 2 187.57 535.90 (187.57) (155.01) (203.73) 3 294.75 535.90 (294.75) (221.45) (425.18) 3 56.73 535.90 (56.73) (42.62) (467.80) 4 53.59 482.31 249.27 145.97 82.42 82.42 56.29 (411.50) 5 96.46 385.85 249.27 145.97 100.43 100.43 62.36 (349.14) 6 77.17 308.68 249.27 145.97 92.32 92.32 52.11 (297.03) 7 61.63 247.05 249.27 145.97 85.80 85.80 44.03 (253.00) 8 49.30 197.75 249.27 145.97 80.62 80.62 37.61 (215.39) 9 39.66 158.09 249.27 145.97 76.57 76.57 32.47 (182.92) 10 35.37 122.72 249.27 145.97 74.77 74.77 28.83 (154.10) 11 35.37 87.35 249.27 145.97 74.77 74.77 26.21 (127.89) 12 34.83 52.52 249.27 145.97 74.54 74.54 23.75 (104.14) 13 34.83 17.68 249.27 145.97 74.54 74.54 21.59 (82.55) 14 17.68 249.27 145.97 67.34 67.34 17.73 (64.81) 15 249.27 145.97 59.91 59.91 14.34 (50.47) 16 249.27 145.97 59.91 59.91 13.04 (37.43) 17 249.27 145.97 59.91 59.91 11.85 (25.58) 18 249.27 145.97 59.91 59.91 10.78 (14.80) 19 249.27 145.97 59.91 59.91 9.80 (5.01) 20 249.27 145.97 59.91 59.91 8.91 3.90 21 249.27 145.97 59.91 59.91 8.10 12.00 22 249.27 145.97 59.91 59.91 7.36 19.36 23 249.27 145.97 90.99 90.99 10.16 29.52 23 56.73 6.34 35.85

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41 Table 4-3. Discounted Profitability Criteria for Steam Methane Reformation (SMR) and Gasification Project Net present value (NPV) (million $) Discounted cash flow rate of return (DCFROR) (%) Discounted payback period (DPBP) (years) SMR 240.1 31.5 2.9 Gasification 35.9 11.1 12.6 Figure 4-1. Discounted Cash Flow Diagram for SMR and Gasification

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42 Figure 4-2. Probability Distribu tion: Net Present Value (NPV) Figure 4-3. Probability Distribu tion: Discounted Cash Flow Rate of Return (DCFROR)

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43 Figure 4-4. Probability Di stribution: Discounted Payback Period (DPBP)

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44 CHAPTER 5 CONCLUSIONS Our study showed that in the future gasifica tion could prove to be the more attractive alternative when compared to SMR for hydrogen pr oduction. This is evident from the following: The NPV of gasification is $36 million while that of SMR is $240 million. This indicates that the net value of the project is significantly higher for SMR. The DCFROR for gasification 11% while that of SMR is 32%. Since we have assumed an internal rate of return as 10% it is evident that while both projects are viable, SMR is a superior alternative. Gasification has a DPBP of 12.6 years whereas that of SMR is 2.9 years. The Monte-Carlo simulation shows that the ri sks associated with gasification are much lower according to the parameter variations presented in Tables 3-2 and 3-3. Therefore it is proven that gasification is a mo re mature technology and must be adopted for the future. The economic analysis performed is both comp rehensive and transparent allowing revision by readers wishing to use different economic assump tions. The results presented are conclusive and have a great deal of accuracy for the following reasons: Previous economic analyses performed on hydr ogen production systems have always been focused on estimating the capital costs based on production capacities, operating pressure requirements and material of construction to determine a price of hydr ogen in ($/GJ). This study adopts a unique approach to confirm that SMR is in fact cheaper than gasification and is in agreement with published results. The uniqueness lies in the fact that a future selling hydrogen price was identi fied and cash flows were gene rated for both projects. This is a more economically sound method since it gi ves a clearer, more realistic idea of the investments with revenues genera ted at the end of each year. As opposed to the traditional method of using CPI to account for inflation, CEPCI was used. CEPCI was developed specifically to estimate costs of chemical engineering facilities. Since it is not influenced by other we ighted factors, it result s in greater accuracy. Most estimates developed used either the DDB or SL method of depreciation. This is not realistic and can create error in results. Th e MACRS approach used here represents the policy adopted by the I.R.S. to depreciate chemi cal facilities of this nature in a real-life situation. The cash flows developed are all discounted. While smaller projects can be evaluated by non-discounted cash flows they should not be us ed for such analyses. This ensures greater accuracy of results and follows a more realistic approach.

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45 A correlation was used to develop COL. While most estimates just assume the number of workers required and their hourly wages, a relation that different iates between hours of operation of equipment and their operators, th at accounts for shift-work for each process stage was used. And finally the Monte-Carlo simulation of probability distribution to quantify the associated risks was used to further strengthen results. The variation in CRM has been modified to impart a more realistic approach based on previous cost data. This ensures greater accuracy of results from the Monte-Carlo simulation.

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46 APPENDIX DATA FOR ECONOMIC ANALYSIS Table A-1. Calculation of Fixed Capital Investment without Cost of Land (FCIL) for Steam Methane Reformation (SMR) and Gasification M etho d FCIL (million $) SM R (includes natural gas preparat ion and handling, reformer, desulfurizer, heat recovery, shift converter, PSA and other related equipment, building, and facility) 136.1 G asificatio n (includes coal storage, preparati on and handling, air separation unit, gasifier, heat recovery/synga s cooling, shift c onverter, Sulfur removal and recovery systems, CO2 absorption, removal and compression, PSA and other related equipment, building and facility) 535.9 Table A-2. Calculation of CRM for Steam Methane Reformation (SMR) and Gasification M etho d Hydrogen production capacity (GJ) Process efficiency (%) Consumption of natural gas (GJ) Price ($/GJ) CRM (million $) SM R 11,870,000 85 13,964,706 7.50 105 G asificatio n 11,870,000 58 20,465,517 1.45 30 Table A-3. Calculation of CUT for Steam Methane Reformation (SMR) and Gasification M etho d Estimated consumption (106 gallons) Price ($/1000 gallons) CUT (million $) SM R (water requirements for cooling and process steps) 4,000 0.5 2.0 G asificatio n (water requirements for cooling and process steps) 12,000 0.5 7.2 Table A-4. Calculation of COL for Steam Methane Reformation (SMR) and Gasification H ydrogen production process P Nnp NOL COL (million $) SM R 4 14 23 0.91 G asificatio n 6 16 34 1.36

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47 Table A-5. Calculation of Econo mic Analysis Parameters for Steam Methane Reformation (SMR) and Gasification Economic parameters SMR Gasification Taxation rate 42 % 42 % Annual interest rate 10 % 10 % Salvage value $13,610,000 $53,590,000 Working capital $24,201,000 $56,726,000 FCIL $136,100,000 $535,900,000 Revenue from sales $249,270,000 $249,270,000 Cost of raw materials, CRM $105,000,000 $30,000,000 Cost of utilities, CUT $2,410,000 $7,234,000 Cost of operating labor, COL $910,000 $1,360,000 Cost of manufacturing without depreciation, COMd$159,096,600 $149,972,620 Project life (years after startup) 20 20 Construction period 3 3 Distribution of FCIL End of year one 10 % 10 % End of year two 35 % 35 % End of year three 55 % 55 %

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48 LIST OF REFERENCES 1. Homer-Dixon T, Friedmann S. Coal in a Ni ce Shade of Green. The New York Times, Opinions, Op-Ed Contributors, March 25, 2005. p. 1. 2. Horton R. The World Energy Crisis. Notes from a presentation made by Chairman, Alchemix Corporation to The Southwest Ch iefs, Scottsdale, Arizona, 2005. p. 2. Website http://www.alchemix.net (accessed 3-11-2007). 3. Sharpe AG. Inorganic Chemistry, Longman Scientific and Technical, Burnt Hill, Essex, U.K., co-published in U.S. by John Wiley & Sons, Inc., New York, 1992. 3:211. 4. Bockris. Hydrogen Energy, Texas A&M University in ECT, 2005; 4:13. 5. Fukuda K. Japans WE-NET Program. Proceed ings of the 7th Canadian Hydrogen Workshop, Quebec City, Quebec, 1995. p. 83-100. 6. Blank H, Szyszka A. Solar Hydrogen Dem onstration Plant in Neunburg vorm Wald. In Veziroglu TN, Derive C, and Pottier J (eds.) Hydrogen Energy Progress IX, M.C.I. Paris, 1992. (2):677-686. 7. Grasse W, Oster F, Aba-Oud H. HYSOLAR: The German-Saudi Arabian Program on Solar Hydrogen 5 Years of Experience. Inte rnational Journal of Hydrogen Energy, 1992. 17(1):1-8. 8. Othmer K. Hydrogen. Encyclopedia of Chemical Technology, 1998. 13:759-807. 9. Okken, PA. Costs of Reducing CO2 Emissions by Means of Hydrogen Energy. International Journal of H ydrogen Energy, 1992. 18(4): 319-323. 10. Othmer K. Coal Gasification. Encyclope dia of Chemical Technology, 1998. 6:771-832. 11. Gasification Plant Cost and Performance Optimization. Report prepared by Bechtel Corporation, Global Energy Inc, Nexant In c for U.S. DOE National Energy Technology Laboratory, September, 2003. p. 20. 12. Peckam J. Ultra-clean fuels from coal lique faction: China about to launch big projects Brief Article. Diesel Fuel News, July 2002. p. 1. 13. Ekdunge P, Raberg M. The Fuel Cell Vehicle An alysis of Energy Use, Emissions and Cost. International Journal of H ydrogen Energy, 1998. 23(5):381-385. 14. Chiesa P, Lozza G. Using hydrogen as a gas turbine fuel. Proceedings of the ASME Turbo Expo, Atlanta, 2003. Article GT 2003-38205. 15. Guthrie KM. Capital Cost Estimating, Evalua tion and Control. Chemical Engineering, 1969. 76(3):114.

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49 16. Bayse L, Swaminathan S. Hydrogen Production Costs A Survey. A report prepared by Sentech, Inc, of the review of production co sts of hydrogen via commercially available processes by The Executive Committee of th e Hydrogen Implementing Agreement in June 1997. Table 6.1, December, 1997. p. 19. 17. Turton R, Bailie RC, Whiting WB, Shaeiwitz JA. Analysis, Synthesis, and Design of Chemical Processes. Prentice Hall Internati onal Series in the Physical and Chemical Engineering Series, 2003. 6:187-217. 18. Chiesa P, Consonni S, Kreutz T, Williams R. Co-production of hydrogen, electricity and CO2 from coal with commercially ready tec hnology. Part A: Performance and emissions. International Journal of Hydrogen Energy, 2005. 30:747-767. 19. Mirabal T. An Economic Analysis of Hydr ogen Production Technologies. Masters thesis, University of Florida, Ga inesville, Florida, 2003. 20. Alkhayat WA, Gerrard AM. Estimating Mann ing Levels for Process Plants. AACE Transactions, 1984. 1:2.1-2.4. 21. Corporations, Property. U.S. Department of Treasury Internal Revenue Service. Washington, D.C., December 2000. Publication 542. Website http://www.irs.gov/publications/p542/ (accessed 3-29-2007). 22. Gaudernack B. Hydrogen Production from Fossil Fuels. Hydrogen Power: Theoretical and Engineering Solutions, Kluwer Academic Publishers, the Netherlands, 1998. p. 75-89. 23. Leiby S. Options for Refinery Hydrogen. A private report by the Process Economics Program, Menlo Park, CA, 1994. Report No. 212, SRI International. 24. Healy Clean Coal Project. Prepared by Alaska Industrial Department and Export Authority for the U.S. DOE Cooperative agreement No. DE-FC22-91PC90544. Quarterly technical progress report for the period of Januar y 1 to December 31 1999. October 2000. Report 3336, p. 2-105. 25. How to Depreciate Property. U.S. Department of Treasury Internal Revenue Service. Washington, D.C., December 2000. Publication 946. Website http://www.irs.gov/publications/p946/ (accessed 3-29-2007). 26. Humphrey KK. Cost and Optimization Engineering. 3rd edition, McGraw-Hill Companies, Inc., 1991. p.289-295.

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50 BIOGRAPHICAL SKETCH The author obtained his bachelors degree in mechanical engineering from the National Institute of Technology (formerly known as the Regional Engineeri ng College), Tiruchirappalli, India, in 2005. He then started his masters degree in mechanical engineering at the University of Florida in fall, 2005. After graduation, the author will commence his professional career in the Steam Turbines Project Management group at Si emens, Power Generation in Orlando, U.S.A.