© 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

© Jonathan Targett

2

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.

© Jonathan Targett

3

Acknowledgement

The author wishes to acknowledge the helpful comments of Dr. Pearson during the

review of the manuscript.

© Jonathan Targett

4

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

© Jonathan Targett

5

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

© Jonathan Targett

6

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

© Jonathan Targett

7

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.

© Jonathan Targett

8

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

© Jonathan Targett

9

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

Component

North

Sea (UK Zone)

NL (Groningen)

France

Algeria CIS Italy

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

© Jonathan Targett

10

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.

© Jonathan Targett

11

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

Feedstock

W. Europe

(% of Total)

USA

(% of Total)

World

(% 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.

© Jonathan Targett

12

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.

© Jonathan Targett

13

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.

© Jonathan Targett

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

© Jonathan Targett

15

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.

© Jonathan Targett

16

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

© Jonathan Targett

17

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 (Million

Tonnes/Year)

Cost* ($ Million)

Start-up

Date

Location

Construction Elements

0.90 $300 2001 Equatorial Guinea Engineering , Construction,

Procurement and Offsites

0.85 $227 2003 Al Jubail,

Saudi Arabia

Engineering & Construction

0.84 $240 2004 Point Lisas,

Trinidad

Engineering & Construction

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 (% of Total)

W. Europe (% 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

© Jonathan Targett

18

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.

© Jonathan Targett

19

Table 7 – Formaldehyde from Methanol Dehydrogenation – Direct Costs

Inputs Amount per Tonne of

Formaldehyde Produced

Typical Input Cost Direct Cost

Methanol 1.15 mt $137/mt $158/mt

Catalyst $55,000 per charge 3% of methanol ~ $5/mt

Utilities Electricity, Steam,

Cooling Water

Assume: steam credit ~ breakeven

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

© Jonathan Targett

20

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.

© Jonathan Targett

21

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.

© Jonathan Targett

Monsanto – Acetic Acid Process

Direct Costs

Methanol* $0.006/lb

Carbon Monoxide $0.022/lb

Catalyst & Additive(s) $0.007/lb

Utilities $0.005/lb

Total Direct Cost $0.040/lb

Methanol Market Pricing; 1990-2001

Typical range $0.30-0.60/gallon

High $1.00/gallon

Low $0.20/gallon

* Methanol consumed = 0.0122gallons per lb of acetic

acid produced; methanol density = 7.9lbs/gallon

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.

© Jonathan Targett

23

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.

© Jonathan Targett

24

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

© Jonathan Targett

25

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.

© Jonathan Targett

26

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

($/million BTU)

Output Synfuel Cost

($/Barrel*)

$0.5 $19.7

$2.0 $32.8

* Crude Oil Equivalent

© Jonathan Targett

27

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

Natural Gas 7.64mmBTU/bbl

Catalyst/Add(s) $2.19/bbl

Utilities $0.65/bbl

MtSynfuel® Direct Costs

Gas Price

($/million BTU)

Direct Cost

($/Barrel)

$0.5 $6.66

$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.

© Jonathan Targett

28

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.

© Jonathan Targett

29

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.

© Jonathan Targett

30

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

© Jonathan Targett

31

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

0

1

2

3

4

5

6

1997 1998 1999 2000 2001 2002

Year

Natu

ral G

as P

rice (

$/m

illio

n B

tu)

LNG - Japan

LNG - EU

NG - UK

NG - US (Henry Hub)

NG - Canada

Crude Oil - Heat Value

Source: B.P. Statistics

© Jonathan Targett

32

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

per Capacity Unit

($/mt per year)

Direct

Cost

($/mt)

Direct Cost

Input Price Assumption

Methanol from syngas 267-333 28 N.G. at $0.5/mmBtu

O2 or air – N/A

Formaldehyde CH3OH

de-H2

~300 163 Methanol at $137/mt

Acetic Acid CO +

CH3OH

308 88 Methanol at $137/mt

CO at $0.0034/scf

© Jonathan Targett

33

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

Capacity

(mt/year)

Investment

Cost

($ millions)

Sales Price

($/lb) ($/mt)

Payback

Year

NPV10%

($million)

IRR

(%)

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

0%

20%

40%

60%

80%

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14

Gross Margin (US$/lb)

Inte

rnal R

ate

of

Retu

rn

20% Utilization 40% Utilization 60% Utilization 80% Utilization 100% Utilization

*Constant gross margin, no deflator applied, five year S.L. depreciation, 30% corporation tax, all capital expenditure in year 1

© Jonathan Targett

34

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.

© Jonathan Targett

35

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 ($/barrel output)

3.19 4.79 6.38 7.98 9.58 11.17 12.77

Conversion Cost*

No Tax Payable ($/barrel output)

2.74 4.11 5.48 6.85 8.22 9.59 10.96

* 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

0%

20%

40%

60%

80%

100%

0 5 10 15 20 25 30 35 40 45 50

Project Year from Start

Pe

rce

nt

of

Ca

pit

al C

os

t

0% Tax

30% Tax

© Jonathan Targett

36

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

-$30,000

-$20,000

-$10,000

$0

$10,000

$20,000

0 5 10 15 20 25 30 35 40 45 50

Project Year from Start

Cu

mu

lati

ve

Dis

co

un

ted

Ca

sh

Flo

w

Conversion Charge

$10/barrel

$8/barrel

$6/barrel

$4/barrel

* No deflator applied, 10 year carried straight-line depreciation, 100% utilization, 0% tax, construction period prior to year zero

© Jonathan Targett

37

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

0

2

4

6

8

10

12

1994

1995

1996

1997

1998

1999

2000

2001

2002

Re

fin

ing

Ma

rgin

($

/ba

rre

l)

0

20

40

60

80

100

120

Ga

so

lin

e P

ric

e (

ce

nts

/ga

llo

n)

Refining Margin Gasoline Price (excl. tax)

Source: U.S. DOE, EIA

*Regular Unleaded, excludes taxes

© Jonathan Targett

38

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.

© Jonathan Targett

39

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.

© Jonathan Targett

40

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.

© Jonathan Targett

41

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

© Jonathan Targett

42

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

© Jonathan Targett

43

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