This document provides a summary of natural gas usage for chemical production. It discusses several key applications: [1] Production of hydrogen from natural gas, which is used to produce ammonia and methanol; [2] Generation of alkenes like ethylene and propylene from higher alkanes in natural gas; [3] Production of synthesis gas, a mixture of carbon monoxide and hydrogen, via steam reforming or partial oxidation of methane, which is used to produce a variety of chemicals. The document also examines typical investment patterns and economics for several chemical processes that utilize natural gas or its derivatives.

1. © Jonathan Targett
University of Aberdeen
Department of Geology and Petroleum Geology
2003/4
Usage of Natural Gas for Chemical Production
Submitted by: Jonathan Targett
Faculty Supervisors: Dr M.J. Pearson, Dr B.T. Cronin

2. © Jonathan Targett
Usage of Natural Gas for Chemical Production
By: Jonathan Targett
Abstract
Natural gas is an essential feedstock for the chemical process industries. Although the
natural gas proportion of hydrocarbons used for chemicals manufacture is lower in
Europe than in North America or the Middle East, natural gas nonetheless accounted
for 5-10% of total hydrocarbon feedstock consumed by the West German chemical
industry in the 1970s. The chemical industry is, in turn, an important customer for the
natural gas industry; about a quarter of Liquefied Petroleum Gas, is used for
chemicals production; most notably the production of alkenes from alkanes.
Applications of dry natural gas include reactions requiring pure methane; for example,
the production of chloromethanes. But the largest industrial chemical application is
the generation of hydrogen needed for production of ammonia and of synthesis gas, a
mixture of carbon oxide and hydrogen. Synthesis gas is the raw material for the bulk
of the world’s production of methanol, precursor for a wide range of industrial
chemicals and a possible component in transport fuel. There is potential for extension
of synthesis gas usage, not least in Gas-To-Liquids schemes involving the formation
of longer carbon chain molecules, suitable for use as liquid refinery feedstock or
transport fuel.
In addition to a summary of chemical applications of natural gas, analyses of available
process costings have been included. These demonstrate typical return patterns from
chemical process plant investments, and reveal that Gas-To-Liquids production of
transport fuel is an increasingly attractive alternative to crude oil refining. Talk of a
“hydrogen economy” can only serve to underscore the importance of chemical
production from natural gas, currently an indispensable source of hydrogen.
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3. © Jonathan Targett
Acknowledgement
The author wishes to acknowledge the helpful comments of Dr. Pearson during the
review of the manuscript.
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List of Contents
1. Introduction page 7
2. Natural Gas Composition page 9
3. Production of Hydrogen page 10
4. Alkenes page 11
5. C1 Methane Derivatives page 12
6. Synthesis Gas page 13
7. Synthesis Gas Hydroformylation page 15
8. C1 Oxygenates page 16
9. C2 Compounds page 20
10. Higher Carbon Chain Length Production page 22
11. Process Economic Assessment page 30
12. Conclusions page 39
13. References page 41
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List of Tables
1. Regional Natural Gas Analyses
2. Properties of the Five Reservoir Fluids
3. World Sources and Uses of Hydrogen in Percentage Terms, 1974
4. Ethylene Feedstocks by Region, mid 1970
5. Plant Investment Examples for Methanol from Synthesis Gas
6. Uses of Methanol in the U.S.A and Western Europe, mid 1970s
7. Formaldehyde from Methanol Dehydrogenation – Direct Costs
8. Typical Coal Bed Raw Gas Composition – Lurgi Gasification
9. Fischer-Tropsch Patents, 1997-2001
10. Typical Output Distribution for a Low Temperature FT Process
11. Process Direct Cost Examples
12. Plant Investment Return Examples
13. Breakeven Conversion Cost of Syncrude for Different Investment Costs
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List of Figures
1. Lurgi Autothermal Reformer for Partial Oxidation to Synthesis Gas
2. The Synetix Methanol Process from Synthesis Gas
3. The Shell Middle Distillate Synthesis Process
4. Benchmark Natural Gas Prices by Delivery Form and Region
5. Acetic Acid Plant Example - Investment Returns
6. Syncrude Unitized Capital Cost Repayment Period
7. Synfuel Plant Unitized Investment – Discounted Cash Flows
8. Implied U.S. Gasoline Refining Margin, 1994-2002
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1. Introduction
As a chemical feedstock natural gas has the limitation that it contains only low carbon
chain length alkanes. Nonetheless, natural gas usage for chemical production is large
and expanding; particularly in North America and the Middle East, where a high
proportion of ethylene is produced from ethane rather than oil-based naphtha. Natural
gas is also a major source of the hydrogen used for production of ammonia and
methanol, mainstays of the petrochemical economy.
Commercial synthesis processes to produce chemicals from dry natural gas deposits,
whose hydrocarbon content is mostly comprised of methane, were the focus of
intensive development efforts in the first half of the last century, and gave rise to the
synthesis gas processes that have grown rapidly in the last fifty years. Many of these
developments were of shared value for the processing of methane from coal
gasification, still a major chemical feedstock source in certain parts of the world.
The oil shocks of the 1970s and 1980s focused attention upon the objective of
developing alternative chemical feedstocks. In 1977, The Carter Administration
instituted the Department of Energy, successor to the Federal Energy Administration.
Among the first actions of D.O.E. was to draft legislation entitled the Fuel Use Act.
Passed in 1978, the act restricted end-uses of natural gas, terming it too valuable a
natural resource to burn; many provisions were, however, subsequently rescinded.
Among the earliest production processes developed using natural gas-derived methane
as feedstock was Fischer Tropsch synthesis to yield higher hydrocarbons, which can
substitute as refinery feedstock, or be used as transport fuel. Effectively
commercialized in Germany in the 1940s, Fischer Tropsch processes declined in
importance thereafter. Today they are the focus of renewed development interest as a
method to convert gas into more easily transportable liquids, a technique known as
Gas-to-Liquids processing. Several oil companies with refining operations have
announced plans to scale up FT processes, confirmation not only that the technology
is maturing, but also that the market is preparing for the incorporation of the resulting
output.
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The objectives of this overview are to:
 Acquaint the reader with industrial chemicals that are, or have the potential to
be, produced from natural gas.
 Highlight a few recent developments that are likely to result in further growth
of natural gas as a chemical feedstock.
 Examine typical investment patterns of a few chemical processes that use
natural gas or its derivatives.
The major uses of natural gas in existing industrial chemical processes are
summarized below:
I. Hydrogen production with carbon oxides as by-product
II. Alkene production from higher alkanes
III. C1 compounds produced from methane; e.g. chloromethanes
IV. Hydrogen/carbon monoxide mixtures, known as synthesis gas or syngas
V. Synthesis gas hydroformylation; e.g. for the production of alcohols
VI. C1 compounds containing oxygen; most notably methanol from synthesis gas
VII. Production of longer carbon chain length molecules; e.g. higher alcohols
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2. Natural Gas Composition c,e
In order to be suitable for chemical reaction, natural gas must, in most cases, be
fractionated to remove inorganic gases; typically these are removed for combustion
also. Separation of the individual hydrocarbon components in natural gas deposits is
usually practised only where sizeable levels of higher hydrocarbons are present. The
tables below show natural gas analyses for a number of producer regions and the
properties of the five reservoir fluids.
Table 1 – Regional Natural Gas Analyses
Producer Region North NL France Algeria CIS Italy
Sea (Groningen)
Component (UK Zone)
Methane 90 81 70-90 55-78 89-94 90-99
Ethane 3-4 3 3-4 8-22 4-5 0-5
Propane 1 <1 1 1-12 <2 0-2
Butane <1 <1 <1 1-2 <1 <2
Pentane <1 <1 <1 0-2 <1 <1
C6 & above <1 <1 <1 0-4 <1 <1
H2S N/A N/A <16 N/A N/A traces
Other Inorganics 3-4 15 2-10 <5 N/A 0-10
Source: The Natural Gas Industry, Medici
Table 2 – Properties of the Five Reservoir Fluids
Source: The Properties of Petroleum Fluids, McCain
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3. Production of Hydrogen a,m,o,q,r,v
A percentage breakdown of the sources and uses of hydrogen is shown in the
following table. Hydrogen derived from oil is formed as a co-product of other
processes; production from natural gas is usually considered a dedicated process.
Table 3 – World Sources and Uses of Hydrogen in Percentage Terms, 1974
Source Percentage of Total Production Volume
Oil 48
Natural Gas 30
Coal 16
Water Electrolysis 3
Other 3
Use Percentage of Total Consumption
Ammonia 59
Hydrotreating 15
Hydrocracking 9
Methanol* 7
Other 10
Source: Industrial Organic Chemistry, Weissermel & Arpe
* From synthesis gas
The use of methane as a source of hydrogen was first commercialized on a large scale
in the first half of the last century, alongside the development of ammonia processes
using direct extraction of nitrogen from air; e.g. the Haber Process. Current US
Department of Energy publications confirm that methane from natural gas is
envisaged as a primary source of hydrogen for carbon-free fuels, and focuses attention
on efforts to reduce the resulting hydrogen cost through improvements to existing
technology. Methods to disassociate hydrogen from water, avoiding the emission of
carbon oxide by-product, have continued to yield hydrogen at higher cost than that
derived from dedicated, steam reforming of natural gas or as a refinery co-product. An
advanced, full-scale hydrogen electrolysis unit requires 4KWh of electricity per cubic
meter of H2 produced, resulting in a hydrogen cost of about $1/Kg. Plasma and solar
furnace splitting of methane are among a variety of novel techniques being
investigated to achieve dedicated, lower production cost, alternatives. Membrane
separation is another.
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4. Alkenes a,l,n,q
Of the 50 million tonnes of liquefied petroleum gas, LPG, produced each year from
natural gas and oil-field associated gas, a quarter is estimated to be used for chemicals
manufacture. Where ethane and propane are separated from natural gas, the major
chemical use is conversion to the corresponding alkenes with hydrogen as co-product,
employing a variety of production techniques. Starting from ethane, ethylene is
typically produced by a thermal decomposition or “cracking” process; similar to
synthesis gas production discussed in section 6. Direct catalytic dehydrogenation is
more important as an emerging technique to convert propane into on-purpose
propylene; a technique that accounted for approximately 1½ million tonnes of
production from a worldwide total of 55 million tonnes in 2003. In the same period
approximately 80 million tonnes of ethylene were produced. The ethylene feedstock
breakdown shown below, reveals the large raw material divergence between regions.
Table 4 – Ethylene Feedstocks by Region, mid 1970s
Region W. Europe USA World
Feedstock (% of Total) (% of Total) (% of Total)
Refinery Gases 1 8 4
LPG 1 65 23
Naphtha (C5-C9) 88 1 56
Other 10 26 17
Source: Industrial Organic Chemistry, Weissermel & Arpe
Swings in gas prices can have a large impact on feedstock selection. In early 2003, the
U.S. chemical producer, Dow, is reported to have shutdown natural gas-based alkene
production at a Texas facility, following a spike that drove spot gas prices from $5 to
$18/millionBTU. Divergent natural gas pricing regimes also have an impact upon
alkene feedstock selection. In Alberta, several firms produce ethylene from ethane
obtained from nearby gas wells, and have maintained a feedstock price advantage that
has enabled them to export large volumes of ethylene derivatives such as polyethylene
to the U.S., despite higher Canadian benchmark gas prices – see section 11. A number
of ethylene production units, including a Dow plant on the U.S./Canadian border, are
designed to consume feedstock derived either from gas or oil.
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5. C1 Methane Derivatives a,q
5.1. Carbon Black
Most processes for the production of carbon black use natural gas, which may be
combusted over a deposition surface or thermally decomposed at high temperature
without combustion. The primary consumers of carbon black are the ink, coatings and
rubber industries.
5.2. Hydrogen Cyanide
Used for a range of industrial reactions, hydrogen cyanide is produced directly from
methane and ammonia, with or without the presence of oxygen:
CH4 + NH3 → HCN + 3H2 ΔH298 = +251 KJ/mol
CH4 + NH3 + 1½O2 → HCN + 3H2O ΔH298 = -113 KJ/mol
5.3. Carbon Disulphide
The primary end-use of carbon disulphide is for production of cellulosic polymers.
Carbon disulphide is produced as follows.
CH4 + S2 → CS2 + 2H2
Or CH4 + 2H2S → CS2 + 4H2
Or CH4 + 2S2 → CS2 + 2H2 S
5.4. Halogen Compounds
A full range of chloromethanes have been produced commercially by direct
chlorination of methane. Major end uses are non-flammable solvents, aerosol
propellants as well as precursors for silicon compounds. Chloromethane usage,
particularly in solvent and propellant applications, has been greatly curtailed owing to
fears about toxicological properties, effects on the atmosphere and persistence in the
environment.
CH4 + Cl2 → CH3Cl + HCl etc.
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6. Synthesis Gas a,d,f,k,q,r
Many commercial reactions using natural gas as feedstock commence by splitting the
hydrocarbon into synthesis gas, or syngas, a mixture of hydrogen, carbon monoxide
and, frequently, carbon dioxide as well. The most commonly used techniques to
produce syngas are Steam Reforming, SR, Partial Oxidation, POX, and hybrid
processes combining the two.
6.1. Steam Reforming, SR
In steam reforming, steam and gaseous alkane are pumped into a reaction chamber,
typically an adiabatic tube reactor or a shell&tube heat-exchanger reactor, heated
from the outside. The reaction is of the general form:
(-CH2-)n + nH2O → nCO +2nH2 ΔHStandard = +151 KJ/mol
For Methane
CH4 + H2O ↔ CO + 3H2
CH4+ 2H2O ↔ CO2 + 4H2
6.2. Partial Oxidation, POX
Partial oxidation involves the combustion of part of the hydrocarbon feed in a lined
pressure vessel using either pure oxygen or oxygen-enriched air. The reaction is of the
general form:
(-CH2-)n + ½nO2 → nCO +2nH2 ΔHStandard = -92 KJ/mol
For Methane
CH4 + ½O2 → CO + 2H2
CH4 + 1½O2 → CO + 2H2O
In the widely favoured autothermal configuration, the heat of combustion supplies
process warming. A commercial autothermal reformer oxidation reactor is shown in
the following figure.
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Figure 1 – Lurgi Autothermal
Reformer for Partial Oxidation to
Synthesis Gas
A common side reaction to both the
SR and POX processes is:
CO + H2O ↔ CO2 + H2
Courtesy: Lurgi AG, Frankfurt
6.3. Carbon Dioxide Reforming
Reforming of hydrocarbon with carbon dioxide is also a possible side reaction in
synthesis gas production processes:
CH4 + CO2 → 2CO + 2H2 ΔHStandard = >-200 KJ/mol
This reaction is highlighted as a possible stand-alone process in a 2002 compilation of
papers on CO2 conversion published by The American Chemical Society. The same
reactants are also examined as a potential route to ethane and ethylene.
6.4. Process Selection Considerations
Feedstock choice is an important factor in generating synthesis gas with the desired
carbon monoxide to hydrogen ratio. Various hydrocarbons can be used; one plant
constructor divides suitable feedstocks by synthesis reactor type as follows:
 Steam Reforming – Natural Gas, LPG or Naphtha (C5-C9 liquids)
 Autothermal Reforming – Natural Gas or Naphtha

15. © Jonathan Targett
Factors that influence and enable control of the CO/H2 ratio include:
 Removal vs. recycle of CO2; reduced CO2 increases H2 proportion
 SR steam to carbon ratio; higher S/C ratio increases H2 proportion
 SR and POX combination; SR favours higher H2 yield
 Proportion of methane feedstock; highest H/C ratio
7. Synthesis Gas Hydroformylation a,f,j,q,t,w
Among the routes to alcohols is the addition of synthesis gas to olefins. In the most
widely used process, the formation of “oxo” alcohols takes place in two steps, the first
being the reaction to normal and iso-aldehydes:
R-CH=CH2 + CO + H2 → R-CH2-CH2-CH=O
Or → R-CH-CH=O
CH3
Aldehyde intermediates are then hydrogenated to produce normal or branched
alcohols, and may also be used to produce carboxylic acids. In a process
commercialized by Shell, long chain alcohols can be produced in a single step. Shell
has also recently announced the development of a process to hydroformylate ethylene
oxide to propanediol, a monomer whose end uses include production of polyester
thermoplastics and thermoset resins. Depicted below, the ethylene oxide route is
heralded as an economic advance.
H2C-CH2 + CO + H2 → CH2OH-CH2-CH=O + H2 → CH2OH-CH2-CH2OH
O
The analogous route to butanediol via hydroformylation of propylene oxide, has
already been commercialized, and accounts for an increasing share of total available
capacity. Process advances in the production of on-purpose propylene oxide are likely
to boost the importance of the syngas/PO route to butanediol.
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8. C1 Oxygenates a,b,f,i,j,k,r,s,u,y
8.1. Methanol
8.1.1. Methanol from Syngas
Methanol is formed from synthesis gas as follows:
CO + 2H2 ↔ CH3OH ΔH298 = -91 KJ/mol
CO2 + 3H2 ↔ CH3OH + H2O ΔH298 = -50 KJ/mol
Factors increasing the yield of Methanol are decreased temperature and increased
pressure. Advances in catalysis and reactor design have led to the development of low
pressure processes; approximately 100 bar. Below is a diagram of the low-pressure
process developed by the former ICI catalysts group, now named Synetix, employing
a copper catalyst.
Figure 2 – The Synetix Methanol Process from Synthesis Gas
Source: Synetix
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Examples of investment levels for recent syngas methanol plants are shown in the
following table:
Table 5 – Plant Investment Examples for Methanol from Synthesis Gas
Capacity Cost* Start-up Location Construction Elements
(Million ($ Million) Date
Tonnes/Year)
0.90 $300 2001 Equatorial Guinea Engineering , Construction,
Procurement and Offsites
0.85 $227 2003 Al Jubail, Engineering & Construction
Saudi Arabia
0.84 $240 2004 Point Lisas, Engineering & Construction
Trinidad
0.84 €200 2005 Punta Arenas, Chile Licence, Engineering and
Procurement
Sources: Chemicals Technology, Lurgi
* Unadjusted
Lurgi has published the following direct cost assessment of its low-pressure, syngas
MegaMethanol® process for a super-size, 1.7 million tonnes per year capacity plant,
which would make it the world’s largest single production unit.
Annual Capacity: 1.7 million tonnes: Capital Cost: ~ $400 million
Direct Production Costs $16/mt (O2/NG split not provided)
Indirect Production Costs $12/mt (excl. depreciation)
Feedstock Assumption:
Natural Gas Cost $0.5/million BTU
Table 6 – Uses of Methanol in the U.S.A and Western Europe, mid 1970s
End Product USA W. Europe
(% of Total) (% of Total)
Formaldehyde 39 51
Dimethyl Terephthalate 11 16
Solvent 10 10
Methyl Methacrylate 3 5
Methylamines 3 4
Halogen Compounds 5 4
Other 29 10
Source: Industrial Organic Chemistry, Weissermel & Arpe
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The preceding table shows a breakdown of the major uses of methanol in the mid
1970s. The first commercial syngas methanol production plant was commissioned in
the mid 1960s. Worldwide capacity to produce methanol from synthesis gas reactors
is currently greater than 20 million tonnes annually.
8.1.2. Methanol by Direct Hydrogenation of Carbon Dioxide
Synthesis of methanol from direct hydrogenation of carbon dioxide has been
investigated most extensively in the context of hydrogen generation from coke; see
below. Known as the Carnol process, it is of interest for reprocessing of flue gases in
power plants, and has potential as a stand-alone route to methanol, relying on surplus
heat from neighbouring processes.
CH4 → C + 2H2
CO2 + 3H2 ↔ CH3OH + H2O
Japanese researchers have recently demonstrated carbon dioxide hydrogenation to
methanol in a 50 kg/day pilot plant. Higher space-time yield was reported than that
typically achieved in conventional syngas methanol reactors.
8.2. Formaldehyde
The main, on-purpose processes for formaldehyde production start from methanol.
CH3OH ↔ CH2O + H2 ΔH298 = +84 KJ/mol
Or CH3OH + ½O2 → CH2O + H2O ΔH298 = -38 KJ/mol
For the dehydrogenation route, the initial investment cost for a 25,000mt/annum
formaldehyde reactor is estimated, in one example, to be as low as $3-5 million.
Economies of scale are indicated to be small; 5-10% on capital investment and
indirect operating costs for a doubling of capacity. The process description calls for
the direct inputs shown in the following table.
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Table 7 – Formaldehyde from Methanol Dehydrogenation – Direct Costs
Inputs Amount per Tonne of Typical Input Cost Direct Cost
Formaldehyde Produced
Methanol 1.15 mt $137/mt $158/mt
Catalyst $55,000 per charge 3% of methanol ~ $5/mt
Utilities Electricity, Steam, Assume: steam credit ~ breakeven
Cooling Water
Source: IFP
In the U.S., formaldehyde suitable for certain end-uses has been produced directly
from hydrocarbon feedstock; 8% of total production in the mid 1970s. A 2000 patent
assigned to Georgia-Pacific Corporation describes the oxidation of methane directly
to formaldehyde in a procedure that can use sour natural gas feedstock. Biosynthesis
routes from methanol to formaldehyde have been scaled up by ICI and others.
8.3. Formic Acid
A sizeable proportion of formic acid has been obtained as a by-product of other
processes; for example the production of acetic acid from butane. Among the
theoretical on-purpose routes, the direct addition of water to carbon monoxide brings
with it a risk of degradation. An alternative is the reaction of carbon monoxide and
alcohol yielding a formate ester, which is then hydrolysed to formic acid. Below is the
general reaction pathway and the methanol case.
CO + ROH → ROCHO
ROCHO + H2O ↔ ROH + HOOCH
CO + HOCH3 → CHOCH3O
OCHOCH3 + H2O ↔ HOCH3 + HOOCH
Carbonylation reactions, those involving the addition of carbon monoxide, are an
important route to a number of carboxylic acids; see acetic acid – section 9.4
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9. C2 Compounds a,f,j,q,s,u
9.1. Acetylene
Alongside the calcium carbide route to acetylene, whose use has sharply declined in
the west, several processes have been developed to form acetylene via methane
combination at high temperature; a number are designed to use oil fractions also. The
techniques fall into three categories:
 Partial combustion of the feed in fire-proof ovens; e.g. Wulff process
 Electrically heated; e.g. Lichtbogen or H.E.A.P. process
 Indirect heating; e.g. using superheated steam
An early patent assigned to the Badische Anilin und Soda Fabrik describes one of the
first oxidation procedures to form acetylene in conditions similar to the syngas POX
reaction; the feed is partially combusted, and then quickly cooled to avoid soot
formation. Autothermal reactor designs recapture combustion heat to crack the
remainder of the feed. A number of variations have been commercialized; the Wulff
process includes a subsequent cracking step after partial oxidation.
First commercialized in Germany, the Hydrogen Electric Arc Pyrolysis, HEAP,
process is reportedly energy intensive, but remains in commercial operation.
Hydrogen is used as a heat transfer agent. Acetylene production via plasma pyrolysis
of coal-bed methane was the subject of renewed study in the U.S. during the first oil
crisis in the early 1970s. High temperature indirect heating processes employing
superheated steam have been demonstrated at various times. This technique was most
actively investigated in Japan, where a commercial plant was commissioned in 1970.
Chemical production starting from acetylene has typically competed unfavourably
with equivalent processes based on ethylene. In periods of ethylene shortage, the topic
of acetylene process alternatives has been revisited. A large-scale use of acetylene is
the Reppe process to produce 1,4-butanediol, an alternative to the propylene oxide-
hydroformylation route to 1,4-butanediol outlined in section 6.
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9.2. Ethanol
The predominant industrial synthesis processes for production of denatured ethanol
(i.e. H2O <5%) use ethylene. In several countries, fermentation processes from grain
or vegetable feedstocks represent a larger source than synthetic production. The U.S.
National Renewable Energy Laboratory gives details of an ethanol process in which
synthesis gas is fed to a fermentation bed. Fermentation processes yield an azeotropic
water/alcohol mixture from which the water cannot be completely removed without
distillation using an alternative solvent; azeotropic distillation. The production of
synthetic higher alcohol mixtures using synthesis gas is included in section 10.
9.3. Acetaldehyde
The prevalent route to acetaldehyde is oxidation of ethylene. A technique to produce
acetaldehyde from synthesis gas is outlined in a Texaco patent of 1985, but there is no
indication that it has been commercialized. In 1973 oxidation of C3&4 alkanes
directly to acetaldehyde is estimated to have accounted for 11% of total production,
however this route is regarded as uncompetitive owing to high levels of by-products.
9.4. Acetic Acid
Acetic acid has been produced via several routes, including; oxidation of
acetaldehyde, direct oxidation of hydrocarbon (primarily butene and butane), and
cabonylation of methyl acetate. Shown below is the on-purpose acetic acid production
route using carbon monoxide and methanol.
CO + 2H2 ↔ CH3OH ΔH298 = -91 KJ/mol
CH3OH + CO → CH3COOH ΔH298 = -138 KJ/mol
The following process cost estimate from SRI Consulting is based upon Monsanto’s
rhodium catalysis technique, purchased by B.P., and subsequently licensed under the
tradename Cativa®, using a modified, iridium catalyst. The plant investment cost is
$308/mt per year; small economies of scale are indicated for indirect operating costs.
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Monsanto – Acetic Acid Process Methanol Market Pricing; 1990-2001
Direct Costs Typical range $0.30-0.60/gallon
Methanol* $0.006/lb High $1.00/gallon
Carbon Monoxide $0.022/lb Low $0.20/gallon
Catalyst & Additive(s) $0.007/lb
* Methanol consumed = 0.0122gallons per lb of acetic
Utilities $0.005/lb acid produced; methanol density = 7.9lbs/gallon
Total Direct Cost $0.040/lb Sources: SRI, The Methanol Institute
10. Higher Carbon Series Production from Synthesis Gas a,d,f,g,h,k,p,x,z
10.1. Mixed Higher Alcohol Synthesis, H.A.S.
Mixed higher alcohols synthesis from syngas, H.A.S., has been investigated by a
number of firms primarily interested in the potential of using alcohols as oxygenate
blending components in transport fuel. When compared with methanol and ethanol,
higher alcohols have certain advantages as fuel additives, not least, their lower vapour
pressures, a factor in avoiding engine pre-ignition.
Until recently, low water solubility ethers such as methyl tertiary-butyl ether, MTBE,
have been preferred to alcohols as oxygenate fuel additives, however several U.S.
states have recently outlawed MTBE on toxicological grounds. The U.S. National
Renewable Energy Laboratory reports that a number of firms have gone ahead, and
scaled up H.A.S. pilot plants.
10.1.1. Snamprogetti, Enichem, Haldor Topsoe, SEHT
The SEHT process takes place in a fixed bed reactor at a higher temperature than
conventional methanol synthesis. Water is removed by azeotropic distillation. A plant
with capacity of 12,000mt/year was operated during the period 1982-87 in Pisticci,
Italy. The end product, designated Metanolo piu Alcoli Superiori®, was marketed in
premium gasoline.

23. © Jonathan Targett
10.1.2. Institut Français du Pétrole
The IFP process has been demonstrated at a small (20 bpd) pilot plant built in Japan.
The final product, referred to as Substifuel®, contains only 0.2% water.
10.1.3. Power Energy Fuels & Western Research Institute
Trade-named, Ecalene®, the end reaction mixture consists of roughly 80% ethanol and
methanol combined with 20% higher alcohols. Scale up in a 500 gallon per day pilot
plant is ongoing.
10.1.4. Dow
Developed in 1984, Dow’s process was not pursued. It gave a mixture of about 3:2:1
methanol, ethanol and propanol.
10.1.5. Lurgi
In Lurgi’s process, carbon dioxide is added directly to methanol to yield an unpurified
higher alcohol mixture with water content below 2%. The output, trade-named,
Octamix®, was piloted in Europe. Lurgi is also publicizing synthetic fuel production
via a process, known as MtSynfuels®, in which methanol is first reacted to dimethyl
ether. DME is then dehydrated to olefin, prior to oligomerization in a Conversion of
Olefins to Distillates® step, giving carbon chain lengths mainly in the gasoline and
diesel range with only low levels of non-fuel co-products. South Africa’s Mossgas has
operated a C.O.D. unit to produce transport fuels since 1992. DME, itself, has also
been used as a fuel blending component.
10.2. Isosynthesis
Although oligomerization reactions starting from synthesis gas typically result in a
spectrum of chain lengths, a process called simply, isosynthesis, is reported to yield
only isobutane and isobutene when carried out at high pressure and temperature; 150-
1000 atmospheres and 450°C. Periodic shortages of isobutene, a precursor for MTBE,
have stimulated fresh interest in the isosynthesis technique, which has not been
practised since the 1940s.
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10.3. Fischer Tropsch Synthesis
The general technique for producing higher hydrocarbons from mixtures of carbon
monoxide and hydrogen is named after Franz Fischer and Hans Tropsch, who
performed pioneering catalyst development in Germany in the 1920s for the
generation of synthesis gas. Disregarding side reactions, the oligomerization of
synthesis gas takes place in the following manner:
nCO + 2nH2 → (-CH2-)n + nH2O
2nCO + nH2 → (-CH2-)n + CO2
Fischer Tropsch production of transport fuels and lubricants from natural gas is
conducted in Malaysia and in South Africa, where coal feedstock is also employed;
the table below shows the typical composition of coal-bed gases.
Table 8 – Typical Coal Bed Raw Gas Composition – Lurgi Gasification
Coal Gas Component Concentration
(% of Total)
CH4 9-11
CO 15-18
CO2 30-32
H2 38-40
Source: Industrial Organic Chemistry, Weissermel & Arpe
Fischer Tropsch processes remain of active research interest, and The US Patent
Office maintains a separate category for FT patents; over seventy were filed in this
class from 1997 to 2001. The patent assignees are shown in table 9.
Table 9 – Fischer-Tropsch Patents, 1997-2001
Assignee No. of Patents
Exxon 34
Institut Français du Pétrole 10
Syntroleum 9
AGIP 6
Air Products 6
Others 6
Source: U.S. Patent Office, Class 518
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The most desirable reaction products are:
 normal alkanes
 primary and secondary, normal alcohols
 alpha olefins
In many instances, however, a range of branched molecules is also likely to form;
certain catalysts are even reported to yield aromatic hydrocarbons. Where a diverse
mix of functional terminal groups is undesirable, FT production processes may
include finishing steps; for example hydrogenation of olefins to alkanes, dehydration
of alcohols to olefins or hydroformylation of olefins to aldehydes, alcohols and acids.
Fischer Tropsch processes can be sub-divided into those designed primarily to yield:
 Synthetic crude oil (Syncrude)
 Transport fuels and/or blending components
 Lubricant basestocks and waxes
Output carbon chain lengths from Fischer Tropsch processes vary widely, depending
upon the oligomerization technique and catalysis. An example of the output
distribution from a low-temperature FT process is shown in the following table.
Table 10 – Typical Output Distribution for a Low Temperature FT Process
Carbon Chain Length Refinery Designation Output Proportion
(Weight %)
C1-C4 Gases 5-10
C5-C9 Naphtha 15-20
C10-C16 Kerosene 20-30
C17-C21 Diesel 10-15
C22+ Wax 30-45
Source: SRI Consulting
In a recent paper about Gas-to-Liquids conversion of Alaskan gas published by the
Society of Petroleum Engineers, the importance was stressed of avoiding long chain,
high melting point wax formation, and of checking that neither syncrude nor
syncrude/crude oil mixtures form gels that might obstruct pipeline restart after
shutdowns; either in slug flow or in blended flow pipeline operation modes.
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10.4. Fischer Tropsch Plant Considerations
Many Fischer Tropsch processes were conceived with coal-bed methane in mind as
hydrocarbon source. Coal processes include the following processing steps, several of
which are not required when utilizing natural gas feedstock:
 Drying and grinding
 Sulphur removal
 Sour water removal
 Acid gas removal
 Slag disposal
The U.S. Department of Energy commissioned a study, including ASPEN modeling,
of FT plants based on either coal or natural gas. The process modeled, yields C2-C5
alkanes that are subsequently used to form longer chain length molecules. The end
mixture contains no sulphur, nitrogen or oxygenates, and can be blended directly into
gasoline and diesel pools. Bechtel’s estimates of the cost of an integrated plant using
natural gas are as follows.
DOE/Bechtel Syncrude Example, 1998
Plant Input at Capacity 410 MMSCF/day
Plant Output Capacity approx. 45,000 bbl/day
Plant Investment $1.8 Billion
Syncrude Pricing Assumptions
Input Gas Price Output Synfuel Cost
($/million BTU) ($/Barrel*)
$0.5 $19.7
$2.0 $32.8
* Crude Oil Equivalent
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For purposes of comparison, Lurgi estimates the investment cost of its methanol-
based synfuel process at $20,000 per barrel per day of finished capacity, and gives the
following direct cost breakdown:
Lurgi – MtSynfuel® Direct Inputs MtSynfuel® Direct Costs
Gas Price Direct Cost
Natural Gas 7.64mmBTU/bbl ($/million BTU) ($/Barrel)
Catalyst/Add(s) $2.19/bbl $0.5 $6.66
Utilities $0.65/bbl $2.0 $18.12
10.5. Fischer Tropsch Plant Developments
A recent overview of emerging Gas-to-Liquids technologies published by Petroleum
Economist summarizes the firms most active in the scaling up of FT processes:
10.5.1. Sasol & Sasol/Chevron
Sasol’s Fischer Tropsch development efforts have historically been directed towards
the use of coal-bed methane. The primary outputs have been diesel fuel, FT waxes
and lubricant basestocks. Sasol’s own pioneering work on the Slurry Phase Distillate,
SPD® process forms the basis of a 50/50 joint-venture with ChevronTexaco, whose
input includes syncrude processing technology. Sasol’s SPD® process is to be utilized
in new plants in Ras Laffan, Qatar (Sasol) and Escravos, Nigeria (Sasol/Chevron);
each with capacity of 34,000 bpd.
10.5.2. ExxonMobil – AGC21 ®
The Advanced Gas Conversion for the 21st Century process, AGC21®, has been
designed to convert natural gas primarily into liquid refinery feedstock. It yields a
high quality syncrude, suitable for production of lubricants and premium transport
fuels, including aviation fuel. The process was demonstrated at a pilot plant in Baton
Rouge, Louisiana. A commercial plant is slated for construction in Qatar. Exxon
claims that over 2000 patents apply to the plant design.
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10.5.3. Shell Middle Distillate Synthesis, SMDS ®
Shell has been actively pursuing techniques to convert natural gas into liquids since
the early 1970s. The SMDS ® process yields syncrude, waxes and long chain alcohols.
Details of the individual process steps are shown in the figure below:
Figure 3 – The Shell Middle Distillate Synthesis Process ®
Shell has operated a pilot-scale SMDS ® plant in the Netherlands for over 20 years. In
1993 it started up a full-scale production unit in Bintulu, Malaysia, jointly constructed
with Petronas and Mitsubishi. As well as waxes and middle distillates (naphtha,
kerosene, diesel), plant output includes finished diesel fuel. Shell has selected eight
countries for the development of SMDS ® plant engineering studies; Egypt, Indonesia,
Iran, Trinidad, Malaysia, Argentina, Australia and Qatar.
10.5.4. BP/Kvaerner
BP has been scaling up an FT process since the mid 1980s. In 1994 B.P.
commissioned a pilot plant built by Davy Process Technology, a subsidiary of
Kvaerner. More recently, BP has constructed an $86 million test plant at Nikiski,
Alaska. This unit reportedly went into operation in July 2003, and is designed to
convert 3 million ft3 of natural gas into 300 barrels of syncrude per day.
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10.5.5. Rentech
Colorado-based Rentech was formed with the objective of developing GTL plants to
convert landfill methane into liquid fuels. A 253 bpd pilot plant was operated
successfully, but owing to inadequate methane volumes, the unit was mothballed. A
feedstock switch is being investigated.
10.5.6. Syntroleum
A developer of FT plant technology, Syntroleum currently operates only
demonstration reactors, whose outputs include both transport fuels and refinery
feedstocks. Syntroleum has licensed elements of its technology to a range of energy
concerns, including Arco, Texaco, Repsol, Kerr McGee, Marathon, Ivanhoe as well as
the Australian Government. The Syntroleum FT process is employed at a 70,000 bpd
unit within an Arco refinery in Washington State, and has been proposed for a GTL
facility to be operated in Qatar by Ivanhoe. Syntroleum has announced plans to build,
and operate, a commercial plant of its own in Peru.
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11. Process Economic Assessment b,z
The major groups of costs that are typically considered in market pricing decisions,
and that form the basis for plant investment decisions, include:
 Direct costs per unit of production
 Raw material input costs
 Utilities consumed and credits for useful heat recovered
 Direct labour inputs
 Analytical costs
 Credits for usable by-products
 Debits for disposal of unusable by-products
 Packaging and shipping
 Distribution costs
 Recurring costs associated with production
 Maintenance
 Catalyst renewal and/or replacement costs
 Process licence fees
 Product line research & development
 Product design and specification
 Production process
 Packaging
 Capital costs
 Initial plant investment; including engineering and construction
 Equipment upgrades and process improvements; e.g. debottlenecking
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Complexity arises from processes that generate two or more desired end-products, to
which a share of direct and indirect costs must be allocated. These cost allocations
may have an important bearing on decisions about the attractiveness of investments to
separate, and purify co-product streams; use or dispose decisions. Similarly, plants in
which multiple products are manufactured in batches or campaigns of a limited time
period, require the development of an allocation system for indirect costs. All of the
processes described in earlier sections are conceived as continuous dedicated
production units that are likely to find alternative uses only in rare instances.
11.1. Natural Gas Input Pricing
Natural gas tariffs are reported in the following types of measurement unit:
 Thermal; e.g. British Thermal Units
 Volume; e.g. Standard Cubic Feet at standard temperature and pressure
 Weight; e.g. Tonnes
Figure 4 – Benchmark Natural Gas Prices by Delivery Form and Region
Natural Gas Pricing by Form & Region
6
5
Natural Gas Price ($/million Btu)
LNG - Japan
4
LNG - EU
NG - UK
3
NG - US (Henry Hub)
NG - Canada
2
Crude Oil - Heat Value
1
0
1997 1998 1999 2000 2001 2002
Year
Source: B.P. Statistics
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The divergence of composition between different natural gas producer regions makes
exact comparisons complex, obscuring, for example, the raw material value of ethane
and propane for alkene production. In the methanol plant example from section 8, a
low thermal unit price has been applied, but in the gas-to-liquid plant examples, gas
pricing is omitted; instead, a conversion cost per unit of liquid output has been
calculated.
11.2. Measures of Investment Return
The measures used for comparisons of plant investments are listed below:
 Internal rate of return – assumes plant investment occurs in one initial lump.
 Project net present value – assumes a constant cost of project capital of 10%,
giving an NPV10% value; terminal value assumption – plant operation is
assumed to continue at least 50 years in all cases; see example - Figure 6.
 Payback year – assumes process plant investment is to take one full year.
11.3. Plant Economics - Examples
11.3.1. Commodity Chemical Plants
The following table compares the capital costs of the plant examples from preceding
sections for production of methanol, formaldehyde and acetic acid:
Table 11 – Process Direct Cost Examples
Product Route Investment Cost Direct Direct Cost
per Capacity Unit Cost Input Price Assumption
($/mt per year) ($/mt)
Methanol from syngas 267-333 28 N.G. at $0.5/mmBtu
O2 or air – N/A
Formaldehyde CH3OH ~300 163 Methanol at $137/mt
de-H2
Acetic Acid CO + 308 88 Methanol at $137/mt
CH3OH CO at $0.0034/scf
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Assuming the direct costs and selling prices shown in the preceding table were to
remain constant, the subsequent plant investment returns would be as follows:
Table 12 – Plant Investment Return Examples*
Product Annual Investment Sales Price Payback NPV10% IRR
Capacity Cost Year
(mt/year) ($ millions) ($/lb) ($/mt) ($million) (%)
Methanol 800,000 227 0.063 139 4 428 30
Formaldehyde 25,000 4 0.104 229 4 10 36
Acetic Acid 800,000 227 0.136 299 3 922 52
*No deflator applied, 5 year straight-line depreciation, 100% utilization, 30% corporation tax, all capital expenditure in year 1
For the acetic acid example, investment returns have been calculated for various
levels of capacity utilization across a range of gross margins; the difference between
revenues and direct costs.
Figure 5 – Acetic Acid Plant Example - Investment Returns*
Acetic Acid Plant Investment Return vs. Gross Margin
at Various Capacity Utilization Rates
20% Utilization 40% Utilization 60% Utilization 80% Utilization 100% Utilization
80%
Internal Rate of Return
60%
40%
20%
0%
0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14
Gross Margin (US$/lb)
*Constant gross margin, no deflator applied, five year S.L. depreciation, 30% corporation tax, all capital expenditure in year 1
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Factors not considered at this stage of analysis include:
 realistic utilization assumptions; 80-90% of nameplate capacity is often the
highest that can be attained, after taking maintenance shutdowns into account
 the arrival of new plant capacity in lumps; these can sharply reduce utilization
rates of all producers; detailed return calculations require ramp-up forecasts
 the volatility of commodity chemical markets; see, for example, methanol
pricing shown in Section 9.4
 cost-based pricing to in-house derivatives production; e.g. polymerization
 competition from by-product processes with little supplementary investment
requirement and direct costs restricted mainly to utilities
 site costs associated with environmental compliance and decommissioning
These effects have the largest impact on those plants using processes with
comparatively high direct costs per unit of output. Recent investment decisions
suggest that producing acetic acid by direct methanol carbonylation has a strong direct
cost position, (i.e. low direct cost) when compared to other on-purpose routes, but
acetic acid is an example of a commodity obtained from both on-purpose and by-
product production.
11.3.2. Synthetic Crude Oil
In a syncrude plant that is operated as a cost centre, revenue for repayment of plant
capital cost is derived from a flat conversion charge per unit of output. Natural gas is
supplied to the plant in return for delivery of a specified quantity of syncrude.
For different plant investment costs, the conversion charge that results in an IRR of
10% (NPV10% of zero) has been calculated, and is shown for a range of plant
investment costs in the table overleaf.
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Table 13 – Breakeven Conversion Cost of Syncrude for Different Investment Costs
Plant Investment Cost
($/bpd of capacity) 10,000 15,000 20,000 25,000 30,000 35,000 40,000
Conversion Cost*
30% Tax Payable 3.19 4.79 6.38 7.98 9.58 11.17 12.77
($/barrel output)
Conversion Cost*
No Tax Payable 2.74 4.11 5.48 6.85 8.22 9.59 10.96
($/barrel output)
* NPV10= zero, no deflator applied, ten year straight-line depreciation, 100% utilization, all capital expenditure in first year
For the purpose of assessing the size of the necessary conversion charge required to
meet plant investment costs, neither indirect plant costs, nor direct costs such as
utilities required per barrel of output are considered. Using the breakeven gas
conversion costs calculated above, the following figure shows the repayment period
for a unitized investment in syncrude production; i.e. one barrel per day of output
capacity.
Figure 6 – Syncrude Unitized Capital Cost Repayment Period
Repayment Period of Initial Plant Capital Cost
NPV(10%) = zero, 10 year depreciation
100%
Percent of Capital Cost
80%
60%
0% Tax
30% Tax
40%
20%
0%
0 5 10 15 20 25 30 35 40 45 50
Project Year from Start
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11.3.3. Synthetic Fuel
For the example given in section 10.4 of a plant to manufacture synthetic fuel
according to Lurgi’s MTSynfuels® process, the capital cost amounts to $20,000 per
barrel per day of capacity. The cumulative discounted cash flows at various fixed
natural gas conversion costs have been calculated on a unitized basis, and are plotted
in Figure 7. Excluding raw materials, Lurgi estimates direct and indirect plant costs
for the MTSynfuels ® process, to be in the range of $3-4/barrel.
Figure 7 – Synfuel Plant Unitized Investment - Discounted Cash Flows
Proforma Cumulative Discounted Cash Flow of Synfuel Plant Investment
Repayment by Fixed Natural Gas Conversion Tariff
Plant Capacity Cost - $20,000/Barrel per Day
$20,000 Conversion Charge
$10/barrel
Cumulative Discounted Cash Flow
$10,000
$8/barrel
$6/barrel
$0
$4/barrel
-$10,000
-$20,000
-$30,000
0 5 10 15 20 25 30 35 40 45 50
Project Year from Start
* No deflator applied, 10 year carried straight-line depreciation, 100% utilization, 0% tax, construction period prior to year zero
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11.3.4. Gas to Liquids, GTL, Production
Fischer Tropsch syncrude production represents a supplementary processing step to
an end-product which is, for many applications, no more valuable than low-sulphur
crude oil. Parallels can be drawn with gas liquefaction direct costs and capital costs;
taking into account supplementary “offsites” investments in pipelines, terminals, tanks
and specialized shipping vessels. Many comparisons are, however, inexact and highly
dependent upon individual field circumstances, such as the value of ethane and
propane components, as well as the presence of existing infrastructure.
A more revealing comparison can be made between natural gas synfuel costs and
transport fuel costs from crude oil refining. Excluding taxes, the U.S. Department of
Energy estimates that raw material accounts for about half the ex works cost of
gasoline; refining margin for almost a quarter. The following figure shows the implied
refining margin of gasoline from crude oil in recent years.
Figure 8 – Implied U.S. Gasoline Refining Margin, 1994-2002
U.S. Gasoline Price* & Implied Refining Margin, 1994-2002
12 120
Refining Margin Gasoline Price (excl. tax)
10 100
Gasoline Price (cents/gallon)
Refining Margin ($/barrel)
8 80
6 60
4 40
2 20
0 0
94
95
96
97
98
99
00
01
02
19
19
19
19
19
19
20
20
20
Source: U.S. DOE, EIA
*Regular Unleaded, excludes taxes
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Making the simplifying assumption that refining margins are comprised only of
capital cost repayment plus plant direct* and indirect operating costs, allows the
following comparison between gas-to-synfuel and oil-to-gasoline production costs:
Example – Lurgi MTSynfuels® Gas-to-Synfuel
Processing Charge
($/barrel)
Breakeven Capital Charge $5.50 11.3.2
Direct & Indirect Plant Costs* $3.00-4.00 11.3.3
Total $8.50-9.50
*Excludes raw material cost
At current gasoline price levels, the cost of production of synthetic fuel from natural
gas appears to be broadly comparable with the cost of producing gasoline from crude
oil. This result gives grounds for optimism that the GTL era is truly dawning.
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12. Conclusions
The chemical process industry is a large scale consumer of natural gas, which is used
for; power generation, steam heating or chemical reaction. When compared to other
sources of hydrocarbon, natural gas has the principal benefit that it yields fewer by-
products.
For use as chemical feedstock, the composition of natural gas is a particularly
important consideration; for example, higher alkanes make gas suitable for alkene
production. Some pre-reaction purification is usually necessary, regardless whether
the feedstock source is wet or dry natural gas, coal gas, oil-field associated gas,
refinery gas, or biogenically-derived gas. Advantage can be gained from processes
that are able to dispense with one or more purification step.
The commercial natural gas reactions examined earlier, have each been assigned to
one of the following four usage categories:
 Alkene production from higher alkanes.
Alkene production using alkanes separated from natural gas requires long-term,
stably-priced supplies at a particular geographic location; handling capacity for
LPG is one method to ensure adequate supply volumes. Gas reservoir volumes of
C2&3 alkanes should be a consideration in assessing the attractiveness of field
development. Direct catalytic dehydrogenation is an important technique to help
balance on-purpose and by-product alkene supplies.
 Processes requiring hydrogen and/or carbon oxides.
Having the highest hydrogen to carbon ratio, methane is particularly valuable for
the formation of hydrogen. For high volume syngas derivatives, natural gas input
is almost certain to be required, either as sole raw material, or in supplement to
other hydrocarbon feedstocks. Synthesis gas chemical processes appear to have
economic advantages for the production of a number C1&2 compounds.
Prospects for new uses of syngas appear promising.
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 Processes requiring pure or near pure methane; e.g. chloromethanes.
Natural gas contains primarily methane, and has the advantage that it can be used
as a sole feedstock in the exact quantities required.
 Conversion into higher carbon chain length molecules.
Processes to make higher carbon chain length molecules from natural gas have
tended to be regarded as a higher cost route to strategic transport fuel supplies,
within the framework of contingency planning for oil price shocks. At present oil
prices, production of higher carbon chain length molecules from natural gas
seems to represent a viable alternative. The greatest potential exists in regions
with:
i. large deposits of stranded gas; e.g. Alaska’s North Slope
ii. large surpluses of dry natural gas; e.g. The Arabian Gulf
iii. gas deposits, but little or no oil, which are located far from resupply
points for liquid transport fuels
In an environment of diminishing discovery rates of new crude oil reserves, interest in
the chemical production uses of natural gas can be expected to grow, irrespective of
carbon cost comparisons. It is to be anticipated that oil and gas pricing structures will
align themselves so that feedstocks may be readily interchanged in a broader range of
shared applications.
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13. References
a) K. Weissermel & H.J. Arpe, Industrial Organic Chemistry, 2nd edition,
translated by A. Mullen, Verlag Chemie, Weinheim, 1978
b) Institut Français du Pétrole, A. Chauvel, P. Leprince, Y. Barthel, C.
Raimbault, J.-P. Arlie, Manual of Economic Analysis of Chemical Processes,
Feasibility Studies in Refinery and Petrochemical Processes, Translated by R.
Miller & E. Miller, McGraw Hill, New York, 1981
c) W.D. McCain, The Properties of Petroleum Fluids, 2nd edition, Pennwell,
Tulsa, Oklahoma, 1990
d) Fundamentals of Gas to Liquids, Petroleum Economist, London, 2003, edited
by D. Bamber, T. Nicholls, J. Deaville:
i) S. Idrus, Bintulu: commercializing Shell’s first GTL plant
ii) M. Waddacor, GTL era is dawning, after 80 years of R&D
iii) I. Dybkjær, Synthesis gas technology
e) M. Medici, The Natural Gas Industry, A Review of World Resources and
Industrial Applications, Newnes-Butterworths, London, 1974
f) P.L. Spath, D.C. Dayton, Preliminary Screening – Technical and Economic
Assessment of Synthesis Gas to Fuels and Chemicals with Emphasis on the
Potential for Biomass-Derived Syngas, National Renewable Energy
Laboratory, Contract NREL-TP-510-34929, Golden, Colorado, 2003
g) Bechtel Corporation, Baseline Design/Economics for Advanced Fischer-
Tropsch Technology, U.S. Department of Energy, Federal Energy Technology
Center, Contract DE-AC22-91PC90027, Pittsburgh, 1998
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h) S. Khataniar, G.A. Chukwu, S.L. Patil, A.Y. Dandekar, The University of
Alaska, Fairbanks, Technical and Economic Issues in Transportation of GTL
Products from Alaskan North Slope to the Markets, Society of Petroleum
Engineers, Paper No. 86931, 2004
i) Synetix Low Pressure Methanol Process, Synetix Corporation, Billingham,
www.synetix.com
j) Process Economics Program, Stanford Research Institute, Menlo Park,
California, http://pep.sric.sri.com
k) Technologies of Lurgi Oel & Gas Chemie, MG Engineering, Company
Brochure, Lurgi Oel Gas Chemie GmbH, Frankfurt
l) World Liquefied Petroleum Gas Association, Paris, www.worldlpgas.com
m) R.E. Uhrig, Engineering Challenges of The Hydrogen Economy, The Bent,
Spring 2004 edition, Tau Beta Pi, Knoxville, Tennessee
n) Chemical & Engineering News, The American Chemical Society, Columbus,
Ohio:
i) M.S. Reisch, Running Low on Gas, Vol. 81, No. 28, 14.7.2003
ii) A. Tullo, Petrochemicals, Vol. 82, No.11, 15.3.2004
o) AirLiquide, HYOS Hydrogen Technologies, www.airliquide.com
p) R.M. Smith, New Developments in Gas to Liquids Technologies, SRI
Consulting, Menlo Park, California, 2004
q) A.L. Waddams, Chemicals from Petroleum, 2nd edition, John Murray, London,
1968
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r) Carbon Dioxide Conversion and Utilization, American Chemical Society,
edited by C. Song, A.F. Gaffney, Oxford University Press, Oxford, 2002:
i. C. Song, CO2 Conversion & Utilization: An Overview, Clean Fuels and
Catalysis Program, Pennsylvania State University, University Park,
Pennsylvania
ii. T. Inui, Effective Conversion of CO2 to Valuable Compounds by Using
Multifunctional Catalysts, Air Water Incorporated, Sakai, Japan
iii. M. Steinberg, Carbon Dioxide and Fuel Production, Department of
Applied Science, Brookhaven National Laboratory, Upton, New York
iv. Y. Wang, Y.Ohtsuka, Utilization of Carbon Dioxide for Direct
Selective Conversion of Methane to Ethane and Ethylene with
Calcium-based Binary Catalysts, Hiroshima University, Hiroshima,
Japan
s) U.S. Patent Office, patent numbers; 4525481, 3686344, 6,028,228
t) Shell Chemicals, www.shellchemicals.com
u) The Methanol Institute, www.methanol.org
v) United States Department of Energy, www.fe.doe.gov
w) Oxeno, www.oxeno.com
x) Exxon Newsroom, www.exxonmobil.com/Corporate/Newsroom
y) Chemicals Technology, www.chemicals-technology.com/projects
z) B.P., www.bp.com/subsection.do?categoryId=95&contentId=2006480
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