DEVELOPMENT AND DEPLOYMENT OF FUTURE FUELS FROM COAL

DEVELOPMENT AND DEPLOYMENT OF FUTURE FUELS FROM COAL

DR ANDREW MINCHENER OBE

Report prepared for the IEA Working Party on Fossil Fuels

JUNE 2019

DEVE LO PMENT AND

DE PLOYMENT O F FUTU RE

FUE LS FROM COAL

DR ANDREW MINCHENER OBE

Report prepared for the IEA Working Party on Fossil Fuels

I E A C L E A N C OA L C E N T R E A P S L E Y H OU S E , 1 7 6 U P P E R R I C H M ON D R OA D

L ON D ON , S W 1 5 2 S H U N I T E D K I N G D OM

+4 4 [ 0 ] 2 0 3 9 0 5 3 8 7 0

W W W . I E A - C OA L . ORG

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I E A C L E A N C O A L C E N T R E – D E V E L O P M E N T A N D D E P L O Y M E N T O F F U T U R E F U E L S F R O M C O A L

P R E F A C E

This report has been produced by the IEA Clean Coal Centre and is based on a survey and analysis of

published literature, and on information gathered in discussions with interested organisations and

individuals. Their assistance is gratefully acknowledged. It should be understood that the views expressed

in this report are our own, and are not necessarily shared by those who supplied the information, nor by

our member organisations.

The IEA Clean Coal Centre was established in 1975 and has contracting parties and sponsors from:

Australia, China, the European Commission, Germany, India, Italy, Japan, Poland, Russia, South Africa,

Thailand, the UAE, the UK and the USA.

The overall objective of the IEA Clean Coal Centre is to continue to provide our members, the IEA Working

Party on Fossil Fuels and other interested parties with independent information and analysis on all

coal-related trends compatible with the UN Sustainable Development Goals. We consider all aspects of

coal production, transport, processing and utilisation, within the rationale for balancing security of supply,

affordability and environmental issues. These include efficiency improvements, lowering greenhouse and

non-greenhouse gas emissions, reducing water stress, financial resourcing, market issues, technology

development and deployment, ensuring poverty alleviation through universal access to electricity,

sustainability, and social licence to operate. Our operating framework is designed to identify and publicise

the best practice in every aspect of the coal production and utilisation chain, so helping to significantly

reduce any unwanted impacts on health, the environment and climate, to ensure the wellbeing of societies

worldwide.

The IEA Clean Coal Centre is organised under the auspices of the International Energy Agency (IEA) but

is functionally and legally autonomous. Views, findings and publications of the IEA Clean Coal Centre do

not necessarily represent the views or policies of the IEA Secretariat or its individual member countries.

Neither IEA Clean Coal Centre nor any of its employees nor any supporting country or organisation, nor

any employee or contractor of IEA Clean Coal Centre, makes any warranty, expressed or implied, or

assumes any legal liability or responsibility for the accuracy, completeness or usefulness of any

information, apparatus, product or process disclosed, or represents that its use would not infringe

privately-owned rights.

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K E Y M E S S A G E

Coal gasification for gaseous and liquid fuels production (future fuels) can fulfil an important strategic

need, particularly in various developing and industrialising countries where coal is the primary fuel source

and oil and gas energy security of supply is an issue.

However, the commercial deployment of these technologies in such countries can be problematical for

various technical and economic reasons, although it is encouraging that some projects appear to be

moving forward. China is leading the way to establish a commercial scale industrial sector with a focus on

converting low-grade, low-value, coals to high-value chemicals including liquid- and gas-based future

fuels. It offers a template for all stages of this industrial development cycle, including the means to

financially underpin such coal conversion projects, and the associated infrastructure needs.

Water availability and the need to limit CO2 emissions will need to be taken into account if the global coal

chemicals sector is to continue to grow on a sustainable basis. For the former, China is seeking to establish

the means both to limit water use and to introduce improved waste water treatment techniques. In order

to lower the carbon intensity of these gasification-based coal conversion systems, there is scope to take

advantage of the gasification process arrangement that results in the CO2 being concentrated as a waste

gas stream prior to currently being emitted from the stack. This means that the marginal cost to capture

the CO2 would be very low, and offers the prospect of early opportunity, low cost, CCUS projects, with

the CO2 being used for EOR applications, thereby helping CCS/CCUS to become established on a global

basis at significant scale.

China has publicly declared that it intends to establish some CCUS demonstration projects on gasification

coal conversion systems, in close proximity to existing oil wells. Potentially this represents a major

opportunity to move CCS/CCUS forward, which should position the nation as a global leader for ensuring

that high efficiency low emissions clean coal technology will form a key part of a global low carbon future.

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A C R O N Y M S A N D A B B R E V I A T I O N S

ADB Asian Development Bank

BRICC Beijing Research Institute of Coal Chemistry, China

CBM coal bed methane

CCS carbon capture and storage

CCUS carbon capture utilisation and storage

CH4 methane

CO carbon monoxide

CO2 carbon dioxide

CTC coal-to-chemicals

CTL coal-to-liquids

CTMEG coal-to-mono-ethylene glycol

CTO coal-to olefins

CTSNG coal-to-synthetic natural gas

DCL direct coal liquefaction

DME dimethyl ether

EOR enhanced oil recovery

FT Fischer-Tropsch

FYP Five-Year Plan

ICL indirect coal liquefaction

IEA International Energy Agency

IEACCC IEA Clean Coal Centre

IEAWPFF IEA Working Party on Fossil Fuels

LNG liquefied natural gas

LPG liquefied petroleum gas

MTG methanol-to-gasoline

MTO methanol-to-olefins

MTP methanol-to-polypropylene

NDRC National Development and Reform Commission, China

SAS Sasol Advanced Synthol™

SSPD Sasol Slurry Phase Distillate™

US DOE Department of Energy, USA

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U N I T S

A$ Australian dollar

bbl barrel

°C degree Celsius

H2 hydrogen

kt kilotonne

kWh kilowatt hour

m3/h cubic metres per hour

MPa megapascal

Mt million tonnes

t/d tonnes per day

US$ US dollar

A C K N O W L E D G E M E N T S

This project was initiated by Mr Hubert Howener, former Vice-Chairman of the IEA Working Party of

Fossil Fuels, who established the rationale for the study and the broad scope of work. It has since been

developed further then implemented by Dr Andrew Minchener OBE, General Manager of the IEA Clean

Coal Centre Technology Collaboration Programme. There has been strong support from the Technical

University of Freiberg through Dr Robert Pardemann (now with Outotec), the East China University of

Science and Technology, as well as expert representatives from government, industry and academia in

Australia, Germany, and the United States of America.

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C O N T E N T S

PREFACE 3

KEY MESSAGE 4

ACRONYMS AND ABBREVIAT IONS 5

ACKNOW LEDGEMENTS 6

CONTENT S 7

LIST OF FIGU RES 9

LIST OF T ABLES 1 0

EXECUTIVE SU MMARY 11

1 INTRODUCT ION 1 5

1.1 Rationale for use of coal as a resource to provide low carbon end products 15

2 COAL GASIFICAT ION -BASED CONVERSION DEVEL OPMENT AND

COMMERCIAL DEPLOYMEN T 17

2.1 Early technology champions 17

2.1.1 South Africa 17

2.1.2 USA 19

2.2 Opportunities for Australia 20

3 T HE IMPORTANCE OF T H E DEVELOPMENT AND DE PLOYMENT

PROGRAMME IN CHINA 22

3.1 Strategic considerations 22 3.2 Steps in establishing the Chinese coal-to-fuels and chemicals sector 23

3.3 Development status of coal to future fuels 26

3.3.1 Hydrogen 26

3.3.2 Methanol 26

3.3.3 Dimethyl ether 27

3.3.4 Synthetic liquid fuels 28

3.3.5 Synthetic natural gas 33

3.4 Sectoral policy and regulatory challenges 40

3.4.1 Maximising utilisation efficiency with improved environmental impact 40

3.4.2 Technology improvement options 41

3.4.3 Government financial interactions 42

3.5 China coal conversion market considerations to 2020 42 3.6 R&D prospects for the Chinese coal to synthetic fuels industry 44

3.6.1 Coal (syngas)-to-ethanol 44

3.6.2 Coal-based polygeneration 45

3.7 Emissions intensity issues 47

3.7.1 Conventional emissions 47

3.7.2 Carbon emissions 47

3.8 Export opportunities 50

4 T HE W AY FORWARD 51

5 MAIN T EXT REFERENCES 52

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6 APPENDIX – FU NDAMENT ALS OF COAL CONVERSI ON TECHNOLOGIES 58

6.1 Major routes for the production of fuels from coal 58 6.1.1 Indirect coal liquefaction 58

6.1.2 Suitable feedstock range 59

6.1.3 Description of underlying process principles 59

6.1.4 Efficiency and environmental performance 84

6.2 Direct Coal Liquefaction 86

6.2.1 Suitable feedstock range 86 6.3 Coal to Synthetic Natural Gas 91

6.3.1 Description of underlying process principle 91

6.3.2 Suitable feedstock range 92

6.3.3 Efficiency and environmental performance 93

6.3.4 Technical maturity and industrial applications 93

6.4 Coal conversion by-products (tars) 93 6.4.1 Origin of coal conversion by-products 93

6.4.2 Tar upgrading technologies 95

6.4.3 Technical maturity and industrial applications 98

7 APPENDIX REFERENCES 9 9

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L I S T O F F I G U R E S

Figure 1 Schematic of the end-product flexibility of the gasification process 15

Figure 2 Schematic of the Sasol coal-to-liquids commercial scale plant 18

Figure 3 Simplified plant process of the Great Plains Synfuels Plant 20

Figure 4 Map of China indicating the geographical distribution of coal resources 23

Figure 5 Coal-to-methanol block diagram 27

Figure 6 Schematic of direct coal liquefaction processes 28

Figure 7 Schematic of indirect coal liquefaction processes 29

Figure 8 The Shenhua Direct Coal Liquefaction Project 30

Figure 9 Shenhua Ningxia coal-to-liquids plant 32

Figure 10 China’s current and planned gas transport infrastructure 35

Figure 11 Schematic of the CTSNG natural gas process 36

Figure 12 The Huineng CTSNG plant 36

Figure 13 Coal-to-ethanol conversion process schemes 44

Figure 14 Schematic for a coal-based polygeneration system 46

Figure 15 Framework for a multi-energy system based around coal polygeneration 46

Figure 16 Possible route for conversion of CO2 to methanol 50

Figure 17 Schematic of an indirect liquefaction process 59

Figure 18 Gas purification sequence for sour and sweet CO-shift 65

Figure 19 Anderson-Schulz-Flory carbon number distribution 68

Figure 20 HTFT: Product separation and gas loop design 69

Figure 21 LTFT: Product separation and gas loop design 70

Figure 22 One-stage quasi-isothermal methanol synthesis 72

Figure 23 Illustration of the two-stage Lurgi MegaMethanol™ concept 73

Figure 24 PMEOH process 74

Figure 25 Schematic of indirect DME synthesis 79

Figure 26 Schematic of direct DME synthesis 82

Figure 27 Temperature dependence of MTG product distribution 83

Figure 28 Schematic of ExxonMobil MTG synthesis 84

Figure 29 Common process schematic of a direct coal liquefaction plant according to the

‘Deutsche Technologie’ approach 88

Figure 30 Example flow scheme of a direct coal liquefaction product treatment section 90

Figure 31 Comparison of Lurgi and Haldor Topsøe SNG synthesis 92

Figure 32 Schematic of the VCC heterogeneous slurry-bed hydrogenation process 97

Figure 33 Schematics of the BRICC process for treatment of low and high-temperature tars 98

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L I S T O F T A B L E S

Table 1 Summary of national coal-to-oil projects established in China during the 11th FYP period 29

Table 2 Provisional CTL demonstration programme in China 31

Table 3 Coal-to-SNG projects in operation or for construction in China through 2016 38

Table 4 Environmental characteristics of coal-based synthetic fuels 47

Table 5 Major differences between fixed bed, fluidised bed and entrained-flow gasification 61

Table 6 Overview of commercial coal gasification technologies 63

Table 7 Overview of commercial FT technologies 67

Table 8 Overview of methanol plants (based on solid feedstock) for methanol, propylene or

olefins production 75

Table 9 Overview of coal-based projects for methanol, propylene and olefins production in

planning, development and construction in China 78

Table 10 Indirect DME synthesis processes 80

Table 11 Overview of indirect synthesis DME projects on stream in China 80

Table 12 Comparison of processes of direct DME synthesis 82

Table 13 Summary of performance parameters for different types of coal gasifiers 84

Table 14 Specific product yields of different liquid syntheses 85

Table 15 Environmental parameters of coal liquefaction routes 85

Table 16 Second generation coal liquefaction developments based on the IG process according

to the Bergius-Pier principle 89

Table 17 Tar treatment processes 96

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E X E C U T I V E S U M M A R Y

RATIONALE AND PRE-REQUISITES FOR COAL TO FUTURE FUELS DEPLOYMENT

Gasification is a process by which low-value, low-grade coal can be converted into syngas (CO + H2), which

can then be used to produce higher value, more amenable products. Based around modern gasifier

systems, there is scope to produce a wide range of chemicals, together with future fuels, including

methanol, dimethyl ether, hydrogen, synthetic natural gas and liquid transport fuels.

In principle, this can fulfil an important strategic need, particularly in various developing and industrialising

countries where coal is the primary fuel source while oil and gas availability can be limited. It offers the

means to balance the energy trilemma of energy security, economic attractiveness and, with the

appropriate control systems, acceptable environmental impact.

There are several pre-requisites for establishing this technology, which are the need to:

• have available large reserves of low-cost gasifiable coal, typically as stranded assets due to either

low quality or location;

• have a host government with the ability and will to provide enabling support for the very large

capital investments that are required;

• be able to cover the costs for infrastructure needs both for the supply of feedstocks and for

transporting the end-products; and

• have the means to ensure adequate institutional capacity requirements can be met.

TECHNOLOGY CHAMPIONS

The original extensive commercial deployment was in South Africa, arising from the period when imports

of oil by that country were politically problematical. Since then, their coal-to-liquids synfuels production

has been maintained while their major coal-to-chemicals production has been converted to use natural

gas as the feedstock instead of coal. A large-scale demonstration of coal-to-synthetic natural gas (CTSNG)

production was subsequently established in the USA but not taken further due to lower-cost alternative

gas sources being available.

The focus of this report is on the new technology champion, namely China, which is leading the way to

establish and financially underpin a major commercial-scale coal conversion sector, based on low-grade

coals. It offers a template for large-scale coal-to-chemicals, gaseous and liquid fuels deployment, for all

stages of the industrial development cycle. Within the synthetic fuel subsector, the leading options include

coal-to-liquids and coal-to-synthetic natural gas. Such large-scale projects represent a massive up-front

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capital investment to cover the coal conversion plant itself and the associated infrastructure needs. The

production cost of the coal can be reasonably well-estimated and normally is relatively stable. In contrast,

the costs of oil and gas, from which the end-products can also be made, have always been more volatile.

Consequently, the overall profitability is very difficult to estimate, for the nominal 50-year’s lifetime of

the process, since there will be times when oil- and gas-based end-products are more competitive than

the coal-based versions.

COMMERCIAL CHALLENGES

Both within and outside China, concerns remain about high supply costs and uncertainty of forward oil

and gas prices. The major slump of international oil prices in 2014 from over 100 US$ per barrel (bbl) to

as low as 30 US$/bbl had a major impact on the overall coal conversion sectoral programme in China. The

breakeven oil price at which these future fuel processes will be nominally financially attractive is when

crude oil international prices are above 60 US$/bbl, although there is a range of breakeven values

depending on the process, the cost of coal and the local circumstances.

ENERGY AND ENVIRONMENTAL CHALLENGES

There are several interconnected and significant energy and environmental technical challenges to be

addressed. These include a need to optimise both high-efficiency operation and the consistent production

of top-quality products. The National Development and Reform Commission (NDRC), as part of its plans

to limit possible future vulnerability to lower-cost imports for some products, has demanded centralised

approval for new coal conversion projects. As well as introducing various constraints regarding water use,

energy efficiency and environmental protection, it has also included the need for project developers to

show that they have the capability to be able to subsequently address CO2 emissions intensity.

Based on current information, coal-to-methanol, dimethyl ether and hydrogen are all mature technologies.

Coal-to-liquid fuels processes, after considerable challenges, now operate adequately, with scale-up to

commercial prototype plants underway. In contrast, for coal-to-synthetic natural gas, due in part to the

type of gasifier selected for the first demonstration units, operational performance has been

problematical with the required environmental standards not always being met. The government

recognises the need to consider carefully the experiences of both successful and failed projects, especially

as the growth in both the size of the sector and the individual projects has been rapid. While problems are

to be expected on all large-scale projects, it appears for the synthetic natural gas options that these are

due to ineffective decision-making, inappropriate technology selection, and the lack of comprehensive

high standard project management. The Government has now included the efficiency requirement in the

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approval process for new units in line with the national policy. It will also close the lower-end (least

efficient) existing coal-to-chemicals processes and will continue to upgrade the more complex processes

that provide high added value.

From an environmental perspective, water availability in the more arid northern parts of China where most

of the suitable coal is located is a concern. For all conversion processes, full attention needs to be given

to both limiting water usage through process optimisation and to recycling water wherever it is practicable

to do so. Again, the Government has set tough standards for ensuring maximum water recycling, and these

needs must be included in the process design and operational plan, which represents a key part of the

approval procedure. This has led to a range of innovative techniques being established. However, this issue

could ultimately lead to a limit as to how large this coal conversion sector can become.

CARBON EMISSIONS INTENSITY ISSUES

The other issue is the release of CO2 into the atmosphere, which represents both a challenge and an

opportunity. While the end-products have high amenity value and are clean, compared to low-grade coal,

their production results in higher releases of CO2 than would be the case if that coal had been combusted.

Should the sector continue to grow, this level of greenhouse gas release might impact adversely on China’s

declared intention to peak its national CO2 emissions by 2030, if not earlier. However, the coal conversion

process results in the CO2 being concentrated prior to its release, which then offers a potentially low

marginal cost route for it to be captured and used to enhance oil recovery. In China, many of the coal

gasification sites are significant large-scale emitters of concentrated streams of CO2, but equally

importantly, there are clusters of such sites in various industrial locations reasonably close to oil wells.

These represent cumulative large point sources for CO2 release and so offer the prospect for major

demonstrations of integrated CCUS by utilising that CO2 to enhance oil recovery from nearby oil wells

while also resulting in a significant level of CO2 storage. The marginal cost of adopting this approach is low

compared to establishing CO2 capture on a coal-fired power plant.

The NDRC of China and the Asian Development Bank (ADB) have worked closely together on several

CCS/CCUS institutional capacity projects, which led to the development of a coal-based CCUS

development and deployment roadmap for China. This has included the identification of several early

opportunity demonstration projects based around large coal-to-chemicals plants that would allow Chinese

industry to gain familiarity in establishing major, multi-stakeholder projects. Such demonstrations can aid

China in building up expertise on all aspects of the CCS/CCUS chain. These activities led to a declaration

of intent at COP21 by the Ministry of Finance of China that the Chinese Government will work with the

ADB to establish several CCUS demonstration projects using this approach. This should also kick-start

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China’s intended overall CCUS demonstration and deployment programme, which should position the

nation as a global leader for ensuring that high-efficiency low-emissions clean coal technology will form a

key part of a global low carbon future.

With regard to other low carbon coal-based gasification technology prospects, China is also considering

establishing integrated energy systems that can ensure an efficient, clean poly-production system with

near-zero emissions. This includes the research, development, and demonstration of modern coal

conversion technologies, where coal is both a fuel and a feedstock and can be used in conjunction with

other energy sources. The first stage might comprise a gasification-based system, primarily for power and

heat production. This can be designed such that when market demands for electricity and heat are met,

various clean energies and industrial raw materials, including natural gas, liquid fuels with ultra-low

emissions, aviation and specialty fuels, and chemicals can be produced via the gasification-based coal

conversion system. The second phase could incorporate coal with both unconventional energy and

renewable energy systems.

INTERNATIONAL OPPORTUNITIES

Beyond its domestic market, China is seeking export opportunities for its own gasification technologies

and to establish a major engineering, procurement and construction role on overseas projects, where it

has in some cases licensed technology from international suppliers. Indeed, the role of China is likely to

be critical in establishing coal conversion projects in certain developing countries as it can provide both

the technical expertise and financially underpin such projects, including the associated infrastructure

needs, making it a competitive option. There is an increasing emphasis on the use of domestic designed

coal gasification and some downstream plant, in line with State Government Directives. At the same time,

there continues to be a significant input from foreign technology suppliers for equipment such as large-

scale high-efficiency air separation units together with downstream syngas processing stages and the

associated catalysts.

I N T R O D U C T I O N

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1 I N T R O D U C T I O N

As part of a global initiative that followed on from various dissemination activities arising from the

Gleneagles Accord, the IEA Working Party on Fossil Fuels (IEAWPFF) has taken forward the

preparation of a technology status review of gasification-based coal conversion to synthetic fuels and

chemicals (future fuels).

1.1 RATIONALE FOR USE OF COAL AS A RESOURCE TO PROVIDE

LOW CARBON END PRODUCTS

Gasification is a process by which carbon containing materials can be converted into syngas (CO + H2),

that can then be used to produce a range of synthetic fuels and chemicals. These feedstocks can include

coal, natural gas, petroleum refining residues, carbonaceous wastes and biomass. For coal, besides

traditional products such as ammonia or chemicals derived either during coke production or from

acetylene based on calcium carbide, there is a significant new chemical industry being established,

based around modern gasifier systems for the production of fertilisers, hydrogen, petrochemical

substitutes such as aromatics, ethylene glycol, olefins and synthetic natural gas together with liquid

transport fuels (Figure 1).

Figure 1 Schematic of the end-product flexibility of the gasification process (Seeking Alpha, 2012)

This approach provides the means to monetise low-value, low-grade coal assets into high value, more

amenable products. That said, the modern gasification-based coal conversion systems require

significant upfront capital investment. While the costs of the end products should be reasonably

I N T R O D U C T I O N

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predictable, their economic viability is less certain since the prices of the alternative competing

sources of the end products, such as petroleum refining residues and natural gas, can be very volatile.

Over the lifetime of the coal-based conversion process, this can make for a difficult investment

decision. Consequently, many such projects are undertaken for strategic reasons such as the need to

limit imports of natural gas and oil, while providing some level of national energy security, with the

end products offering a significant amenity value and potentially a more positive environmental

impact than the original coal source.

Scope of the study

This study provides a global review of the technological development of coal-to-chemicals, with an

emphasis on future fuels systems, their potential attractiveness for countries with limited oil and

natural gas supplies, and the inherent economic risks due to the international price volatility of

processes that use alternative oil and natural gas as the primary feedstocks. The focus is on China

where the national government is pursuing the establishment of a modern coal-to-chemicals (CTC)

industry, based on using low-grade coals. This has included testing a wide range of process options at

the large industrial pilot scale, followed by the upgrade of those demonstration projects, which have

shown higher energy conversion efficiency and adequate environmental performance, to initiate the

introduction of commercial prototype plants. This has included the identification of suitable

geographical locations, with both adequate coal supplies and water availability, as well as offering

prospects for extending the industrial chain to promote local economic and social development.

The major impact of falling oil prices on the profitability of the sector and the steps being taken by the

Chinese government to counter these problems are also considered. At the same time, using such

processes to demonstrate lower cost CCUS operation through CO2 enhanced oil recovery has been

considered as an early opportunity route for lowering process carbon intensity in this large industrial

sector.

C O A L G A S I F I C A T I O N - B A S E D C O N V E R S I O N D E V E L O P M E N T A N D C O M M E R C I A L D E P L O Y M E N T

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2 C O A L G A S I F I C A T I O N - B A S E D C O N V E R S I O N

D E V E L O P M E N T A N D C O M M E R C I A L

D E P L O Y M E N T

The financial uncertainties inherent in establishing capital-intensive coal-to-chemicals plants, the

products of which can be vulnerable to those from competing processes based on the oil and/or natural

gas feedstocks, has meant that the take-up has been limited. This provides a strong example of the

conflict between strategic longer-term planning and short-term expediency. The early technology

champions were South Africa and the USA and their two commercial-scale gasification-based coal

conversion projects are described below. Subsequently, China has taken a major initiative to establish

a massive coal-to-chemicals industrial programme. The description and assessment of this initiative is

provided separately in Section 3, in recognition of its unique approach.

2.1 EARLY TECHNOLOGY CHAMPIONS

2.1.1 South Africa

The original extensive commercial deployment was in South Africa, arising from the period when

imports of oil by that country were politically problematical. Currently, South Africa, through Sasol,

operates the world’s only gasification-based commercial coal-to-liquid (CTL) facility at Secunda with

an output capacity of 160,000 bbl/d of oil equivalent (see Figure 2). All the synthetic fuels are used to

meet growing domestic demand for petroleum products, with about 30% of South Africa’s petrol and

diesel needs being met through coal conversion (Sasol, 2010).


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Figure 2 Schematic of the Sasol coal-to-liquids commercial scale plant (NETL, 2011a)

At the two units in Secunda, which began operation in the early 1980s, pressurised Sasol/Lurgi fixed

bed dry bottom gasifiers are used to produce syngas from high ash content, high ash melting point coal

in the presence of steam and oxygen (Van Nierop and others, 2000). The average syngas production

rate is 1.5 million m3/h, with a typical composition of 58% H2, 29% CO, 11% CH4, 1% CO2. After cooling,

the various condensates that are removed from the syngas provide co-products such as tars, oils and

pitches, together with ammonia, sulphur, cresols and phenols, with the pitch being converted into coke

in an anode coke plant.

Once purified, the syngas is sent to a suite of nine Sasol Fischer-Tropsch (FT) Advanced Synthol (SAS)

reactors where it is reacted in the presence of a fluidised iron-based catalyst at elevated pressure

(~2.5 MPa) and a temperature of about 350°C (Dry, 2002). This produces further by-products, namely

reaction water and oxygenated hydrocarbons, together with a wide range of hydrocarbons in the C1-C20

range (Gibson, 2007). These hydrocarbons are cooled in the plant until most components become

liquefied. Differences in boiling points are utilised to yield separate hydrocarbon-rich fractions and

methane-rich gas. Some of the methane-rich gas (C1) is sold as pipeline fuel gas, while the rest is sent

to a reforming unit, where it is converted back to syngas and re-routed to the reactors. The C2-rich

stream is split into ethylene and ethane. The ethane is cracked in a high-temperature furnace yielding


1 9


ethylene, which is then purified. Propylene from the light hydrocarbon gases is purified and used in

the production of polypropylene. Within this stream there are also large quantities of olefins in the C5

to C11 range. Most of this oil stream is routed to a refinery where liquefied petroleum gas, propane,

butane, fuel oil, paraffin, petrol and diesel are produced. The oxygenates in the aqueous stream from

the synthesis process are separated and purified in the chemical work-up plant to produce alcohols,

acetic acid and ketones including acetone, methyl ethyl ketone and methyl iso-butyl ketone. These

oxygenate chemicals are either recovered for chemical value or are processed to become fuel

components. Of the olefins, ethylene, propylene, pentene-1 and hexene-1 are recovered and sold into

the polymer industry. Surplus olefins are converted into diesel to maintain a gasoline-diesel ratio to

match market demand. The annual synfuels output from these High Temperature FT plants in 2002

was about 8 Mt.

At Sasolburg, from 1955 when it began operation until 2004, the coal-based synthesis feed gas was

reacted in the Sasol slurry phase distillate (SSPD) reactors at a lower temperature than is the case in

the SAS reactors, primarily producing linear-chained hydrocarbon waxes and various liquid products

(Dry, 2002). Residual gas was sold as pipeline gas, while lighter hydrocarbons were hydro-treated to

produce either pure kerosene or paraffin fractions. Ammonia was also produced and either sold

directly or utilised downstream to produce explosives and fertilisers. Around 40 Mt/y of low-grade

coal were converted into liquid fuels, gas, and other products.

The SSPD technology is also the technology favoured by Sasol for the commercial conversion of

natural gas to synfuels. It produces a less complex product stream than the SAS technology and

products can readily be converted to high quality diesel. In 2004, Sasol switched feedstock at Sasolburg

to natural gas imported from Mozambique (Sasol, 2010).

2.1.2 USA

The second commercial-scale operation, the Great Plains Synfuels Plant, was established in Beulah,

North Dakota and has been in operation producing synthetic natural gas (SNG) from lignite for

35 years. It remains the only coal-to-SNG (CTSNG) facility in the USA (NETL, 2011b). The plant also

produces high purity CO2, which is distributed through a pipeline to end users in Canada for enhanced

oil recovery (EOR) operations. Other products include anhydrous ammonia, ammonium sulphate,

krypton, xenon, de-phenolised cresylic acid, liquid nitrogen, phenol, and naphtha, the latter being

burned as fuel in plant boilers.

The plant began operation in 1984. However, after the facility was built, natural gas prices continued

to drop impacting on the profitability of the plant, which led the US DOE to purchase the plant for

US$1 billion in 1986. The US DOE sold the plant in 1988 to Basin Electric Power Cooperative, which

owned the adjacent power plant and has since operated the facility through its Dakota Gasification

Company subsidiary. Over the years, various studies to consider an expansion of this technological

base were undertaken but none were ever implemented. The recent and rapid development of the


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shale oil fracking approach from which shale gas is a plentiful low cost by-product, suggests that there

is little likelihood of expanding the Grand Plains SNG project.

Figure 3 Simplified plant process of the Great Plains Synfuels Plant (NETL, 2011b)

Figure 3 provides a schematic of the overall process. Some14,500 tonnes per day (t/d) of lignite are

gasified with oxygen and steam in 14 Lurgi Mark IV gasifiers to produce a wide range of gaseous raw

products. These exit the gasifiers and are then cooled, removing tar, oils, phenols, ammonia and water

via condensation from the gas stream. These products are then purified, transported, or stored for later

use as a fuel for steam generation. After cooling, the gas is further treated to remove impurities, then

sent to a methanation unit where CO and most of the remaining CO2 is reacted over a nickel catalyst

with free H2 to form CH4, which is then further cooled, dried, compressed and transported by pipeline

to the eastern United States.

2.2 OPPORTUNITIES FOR AUSTRALIA

Australia is a leading international coal exporter, supplying high quality steam and metallurgical coal,

particularly to Asia. At the same time, there should be great potential for upgrading their low-quality

brown coal, which represents an enormous energy resource but in its current form is almost unsaleable.

There have been ongoing discussions with companies from both Japan and China to use

gasification-based conversion technologies to produce high-grade high-value products, to be shipped

back to these two target customers, although no commercial deals are yet in place. The latest possible

venture is the Kawasaki Hydrogen Road, for which the plan is to produce hydrogen from mined brown

coal and send it in liquefied form to Japan in custom-made ships. It would then be used for a variety of

purposes via conversion into electricity and thermal energy. The CO2 emitted in the brown coal


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conversion process would be captured and stored in geological formations in Australia. Kawasaki,

Iwatani, J-Power and Shell Japan are backing the project, with the Victorian and Commonwealth

governments committing A$1 million and A$2 million respectively to the front-end engineering

design (FEED) study (The Australian, 2016).

T H E I M P O R T A N C E O F T H E D E V E L O P M E N T A N D D E P L O Y M E N T PR O G R AM M E I N C H I N A

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3 T H E I M P O R T A N C E O F T H E D E V E L O P M E N T

A N D D E P L O Y M E N T P R O G R A M M E I N C H I N A

3.1 STRATEGIC CONSIDERATIONS

There are several pre-requisites for establishing coal-to-chemicals technologies (IEA, 2006), which are

the need to:

• have available large reserves of low-cost gasifiable coal, with stranded assets, due to either too

low-quality or location, likely to be particularly attractive;

• have a host government with the ability and will to provide enabling support for the very large

capital investments that are required;

• be able to cover the costs for infrastructure needs both for the supply of feedstocks and for

transporting the end products; and

• have the means to ensure adequate institutional capacity requirements.

Within this context, China’s fossil energy resources are coal-rich, oil-and natural gas-lean, coupled

with a major and growing demand for fuels and chemical products, which raises significant security of

energy supply issues. For example, in 2010, China’s annual crude oil demand was about 450 Mt, of

which some 200 Mt were provided from domestic sources and the remainder via imports. For 2030,

the expectation is that total demand may be some 800 Mt, with domestic demand at best managing

200–220 Mt. The imports will be as crude oil rather than refined products, as China has expanded its

refining sector and will continue to do so for the foreseeable future (Wu, 2012). There is a similar

situation for natural gas, with likely annual demand for 2030 being over 550 billion m3, of which

domestic supplies can provide some 200 billion m3, excluding unconventional sources.

The establishment of coal-to-chemicals, liquid fuels and synthetic natural gas is seen as a potentially

attractive means to counter this situation, while also providing a way for the major cash-rich

state-owned enterprises from the coal and power sectors to continue to diversify their energy product

portfolios, in line with national strategic initiatives to establish large-scale integrated energy

companies. Consequently, in order to promote domestic innovation and improved resource use, since

2004 the Chinese State Government has sought to determine the technical and economic viability of

using gasification-based coal conversion to produce both synthetic oil and gas, and to manufacture

various chemical products (Minchener, 2011a). This first comprised the introduction of various

policies and regulations to initiate an expansive development plan that was designed to test various

gasification-based coal conversion techniques and take forward the more promising options towards

commercial deployment. The focus is on using low-grade coals, in the north and west of the country

(Figure 4). However, with concerns about water use, and the recognition that in a global market the

outputs from coal conversion technologies are commercially vulnerable to imported


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petrochemical-based alternatives, the implementation plan has been a cautious one, at least by Chinese

standards.

Figure 4 Map of China indicating the geographical distribution of coal resources (Wikimedia, 2013)

3.2 STEPS IN ESTABLISHING THE CHINESE COAL-TO-FUELS AND

CHEMICALS SECTOR

China operates a top-down command economy, which is structured around a five-year planning cycle,

as defined by the Five-Year Plan for National Economic and Social Development (FYP). This sets out

the intended way forward for the nation and provides guidelines, policy frameworks, and targets for

policy-makers at all levels of government. Each plan provides top down overall objectives and goals

related to economic growth and industrial planning in key sectors and regions, while more recently

also covering social issues. Although the timescale is nominally five years, many policies and directives

flow through from one plan to the next. The process begins with State Government guidelines and

supporting policies together with targeted policy initiatives, which are prepared by various national

commissions and ministries. These then form the framework against which provincial and local

organisations provide detailed work plans for achieving the designated targets.

The State Government’s initial approach during the 11th FYP (2006-2010) was to encourage various

coal-to-chemical projects to be established to produce syngas as a building block for ammonia, fertiliser,

hydrogen and methanol (Minchener, 2011a). This led to the construction of many units of varying


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sizes with the coal gasification stage and many of the downstream components comprising a mix of

imported and domestic technologies (see Chapter 6 Appendix on page 58). Subsequently, through the

11th and the 12th FYP (2011-2015), there was a cautious development of more complex

coal-to-chemicals and coal-to-synfuels, with the State Government tightly controlling possible projects.

This was due in part to high capital investment requirements and the uncertainty of forward oil prices

suggesting potentially unattractive economic returns. It also ensured that the provincial governments

didn’t initiate small inefficient projects with poor environmental performance, arising from a lack of

national awareness. Alongside these initiatives, a major development was the push to establish a

national CTL programme covering both the direct process and, at smaller scale, the indirect process.

During the 12th FYP period, there was a review of individual process streams established on

operational plants, to determine those with acceptable efficiency and environmental performance

characteristics. Those plants that did not meet those requirements were closed. In addition, the

intention was to upgrade those demonstration projects that offered the higher energy conversion

efficiency, a suitable geographical location with both adequate suitable coal supplies and sufficient

water availability, as well as offering prospects for extending the industrial chain to promote local

economic and social development. This included a focus on the construction of projects for clean

production, utilisation, processing and conversion of low-calorific-value coal (Inside China, 2012).

Large-scale operations were taken forward for coal-to-olefins (CTO), coal-to-mono-ethylene glycol

(CTMEG), and coal-to-synthetic natural gas (CTSNG). At the same time, plans were developed to

expand the CTL programme to achieve commercial scale capacity. There was also the initiation of

small-scale activities to investigate the potential of further coal conversion processes

(Minchener, 2013).

In February 2012, the Ministry of Industry & Information Technology published the Petrochemical &

Chemical Industry overall 12th Five-Year Plan, together with specific plans for the olefin and fertiliser

industries (Asiachem, 2013). This set out the need to actively promote advanced coal gasification and

coal-based polygeneration processes; to further establish Chinese intellectual property rights; and to

further improve the utilisation ratio of lower rank coal and other poor quality mineral species. In terms

of targets, the plan suggested that coal/methanol to olefins should achieve at least 20% market

penetration, displacing traditional naphtha-based conversion processes, while the proportion of

nitro-fertiliser capacity using advanced gasification processes should reach 30% together, with the

development of 450,000 t/y ammonia and 800,000 t/y urea (or higher capacity) process units.

The NDRC also published the Coal Industry 12-5 Developing Programme. This specifies that new

coal-to-chemicals projects will be based in those areas of Inner Mongolia, Xinjiang, Shaanxi, Shanxi,

Yunnan, and Guizhou Provinces that have both adequate quantities of suitable coal (see Figure 4) and

water supplies necessary to support process upgrading future fuels projects for CTL, CTSNG, and

various coal chemicals processes.


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These trends continue with the 13th Five-Year Plan. The drivers include strengthening technological

innovation to further develop deep coal processing to produce liquid and gaseous fuels with high

amenity value. However, at the same time, there remains a focus on an increasing emphasis for

rationally controlling the pace of development, a strict implementation of environmental access

conditions and limiting associated market risk. There is also a need to ensure operational stability with

high availability, including the assessment and, where possible, application of innovative approaches

for organic integration of coal deep-processing, oil refining, petrochemical, and power production

(Asiachem, 2017a).

This includes the steady advancement of demonstration projects while ensuring standards are met for

energy efficiency, environmental protection, water saving, and the use of domestic produced

equipment with Chinese intellectual property rights. Thus, new projects will only be permitted in

regions with adequate water resources; they must be consistent with China's overall plans to control

coal consumption, and with a need to prioritise the use of low-quality coals with high sulphur and ash

content in order to reduce their use elsewhere. Efficiency targets for CTL plants include the use of a

maximum of 3.7 tonnes of coal for each tonne of oil produced, while CTSNG projects must use no

more than 2.3 tonnes coal for every 1000 m3 of gas produced.

Operational production capacity during the 13th Five-Year Plan for CTL has been set at 13 Mt/y while

for CTSNG it is 17 billion m3/y (China Oil & Gas 2017).

Key future CTL projects have been identified as Shenhua Ningxia Coal Phase II, Ningxia; Shenhua

Erdos 2nd & 3rd Lines, Inner Mongolia; Yankuang Yulin Phase II, Shaanxi; Ganquanpu, Xinjiang; Yili,

Xinjiang; Yitai, Inner Mongolia; Bijie, Guizhou; Eastern Inner Mongolia. For coal-to-SNG, the key

projects include Zhundong, Xinjiang; Yili, Xinjiang; Erdos, Inner Mongolia; Datong, Shanxi; Xing'an

League, Inner Mongolia (Asiachem, 2017c). Only a few of these have proceeded so far beyond the

concept and early design stage, as indicated in Section 3.3. There are also some coal polygeneration

demonstration projects listed, which are at an early stage of development, including: Yanchang-Yulin-

Shenhua Coal-Oil-Power Poly-generation, Shaanxi; Shaanxi-Yulin Coal-Oil-Gas-Chemical

Poly-generation; Longcheng Yulin Coal-Oil-Gas Poly-generation; Jiangneng Shenwu Pingxiang

Coal-Power-Oil Poly-generation, Jiangxi.

These plans were robust but were affected significantly by external events such as the global financial

crisis starting in 2008 and then, in 2014, there was a global collapse in the oil price, which led to a

retrenchment of activities, both in terms of the operational programme and the progressing of new

projects. The impact that this had on future fuel products, that is, hydrogen, methanol, dimethyl ether,

synthetic gasoline/diesel and synthetic natural gas, is considered in Sections 3.3 to 3.7 below.


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3.3 DEVELOPMENT STATUS OF COAL TO FUTURE FUELS

3.3.1 Hydrogen

Coal-to-hydrogen production is a mature technology, and a 600 t/d unit was built in 2007 to provide

hydrogen for the Shenhua Group direct coal liquefaction plant. More typically, it is used in numerous

coal conversion plants where the hydrogen produced from the syngas is combined with nitrogen from

the air separation unit to produce ammonia.

3.3.2 Methanol

Methanol is a prime chemical output that can be produced from coal, petroleum and natural gas using

the mature conversion process shown in Figure 5. It has several direct applications while also being

used as a building block in the manufacture of many of the coal-based petrochemical substitutes that

are described below.

During the 11th FYP period, the drive was to rapidly and significantly increase coal-to-methanol

production to avoid using higher cost petroleum and natural gas as the primary feedstocks. In overall

terms, the expectation was that methanol use would rise rapidly, with likely products including:

• formaldehyde, agricultural and pharmaceutical chemicals;

• a blend component with gasoline/petrol;

• dimethyl ether (DME) as a substitute for diesel and liquefied petroleum gas (LPG); and

• a means to produce substitutes for petro-chemical industrial products.

The NDRC projections were that total methanol use would increase from some 7 Mt in 2005 to 25 Mt

by 2010 and 65 Mt by 2020, and that domestic producers would be able to supply all of China’s needs.

Overall demand increased broadly in line with projections; however, despite the NDRC stipulating in

2011 that there would be a cap on coal-to-methanol production capacity of 50 Mt by 2015 (Yang and

Jackson, 2012), that limit was breached, with the result that average operational rates were 59% in

2014, with the less economically competitive units standing idle. The forward projection was that

operational rates would rise through the introduction of new markets for methanol, especially for

methanol-to-olefins (MTO) and methanol-to-propylene (MTP). While these opportunities have begun

to materialise, the sharp fall in crude oil prices has distorted these plans.


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Figure 5 Coal-to-methanol block diagram (Davy, 2013)

3.3.3 Dimethyl ether

Dimethyl ether (DME) is a non-toxic, colourless, odourless gas that has many similarities to LPG. Its

primary use is as a blending chemical with LPG since it can be easily liquefied and transported using

existing LPG supply and storage techniques. This is its largest application in the global DME market,

which is dominated by its use in the Asia Pacific region, especially China. DME blended with LPG can

be used for domestic cooking and heating, with blends containing up to 20% volume DME generally

being usable without modifications to either equipment or distribution networks. Growth in DME’s

use for such domestic applications is increasing sharply, especially in developing countries where

portable (bottled) fuel is providing a safer, cleaner, and more environmentally benign option for

cooking and heating when natural gas is not a major option (International DME Association, 2016). It

is also a promising alternative automotive fuel. DME can be used as fuel in diesel engines, gasoline

engines (30% DME / 70% LPG) and gas turbines, with diesel showing the most distinct advantages. It

is seen as a viable alternative to other energy sources for medium-sized power plants, especially in

isolated or remote locations where it can be difficult to transport natural gas and where the

construction of liquefied natural gas (LNG) regasification terminals would not be appropriate

(International DME Association, 2016).

Among the Asia Pacific countries, China accounts for over 80% of DME demand, for use in LPG

blending purposes and to a minor extent as an aerosol propellant. Increased domestic production has

led to a significant fall in the amount of LPG imported. As noted, this market will increase further as

DME is used for blending in transportation processes. The major Chinese supplier is the Jiutai Energy

Group. It is projected that China’s share of this global market will increase to over US$7.8 billion by

2020, with firm annualised growth of close to 20% between 2015 and 2020 (Markets and Markets,

2016). In China, DME is produced from coal-to-methanol plants through the addition of a methanol

dehydration stage, which can be considered as a mature production route. The price of DME is a

function of the price of methanol and LPG. The energy value of DME is approximately 62% that of

LPG; however, the listed sale price is typically 75–90% that of LPG, representing a premium to energy

value.


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3.3.4 Synthetic liquid fuels

Transport fuels (gasoline/petrol, diesel and jet fuel) are currently derived from crude oil, which has

about twice the hydrogen content of coal. For coal to replace crude oil, it must be converted to liquids

with similar hydrogen contents to oil and with similar properties. This can be achieved either by

removing carbon or by adding hydrogen, while also largely removing elements such as sulphur,

nitrogen and oxygen (Williams and Larson, 2003). There are two approaches to providing liquid fuels

from coal (Couch, 2008).

Figure 6 Schematic of direct coal liquefaction processes (Deutsche Bank, 2007)

In direct coal liquefaction (DCL), pulverised coal is treated at high temperature and pressure with a

solvent that comprises a process-derived recyclable oil (see Figure 6). The hydrogen/carbon ratio is

increased by adding gaseous H2 to the slurry of coal and coal-derived liquids, together with catalysts

to speed up the required reactions. The liquids produced have molecular structures similar to those

found in aromatic compounds and need further upgrading to produce specification fuels such as

gasoline/petrol and fuel oil. Liquid yields are generally in the range 60–70%.

The indirect coal liquefaction route (ICL) is a high temperature, high pressure process that first

requires the gasification of coal to produce a syngas, which can be converted to liquid fuels via either

the Fischer-Tropsch (FT) process or the Mobil process (Radtke and others, 2006). In the FT process,

Figure 7, which is the more common, the syngas is cleaned of impurities and then catalytically

combined/rebuilt to make the distillable liquids. These can include hydrocarbon fuels such as

synthetic gasoline/petrol and diesel, and/or oxygenated fuels, together with a wide range of other

possible products. For the FT synthesis stage, the choice of making either gasoline/petrol or diesel is

determined by the selection of operating temperature and catalyst. In the Mobil process, the syngas

can be converted to methanol, or the latter can be provided separately as the starting material, which

is then converted to petroleum products via a dehydration sequence (AAAS, 2009).


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Figure 7 Schematic of indirect coal liquefaction processes (Spath and Dayton, 2003)

Although more complex, ICL has several advantages over DCL. Thus:

• the principal product from the first stage is a gas which leaves behind most of the mineral matter

of the coal in the gasifier, apart from any volatile components;

• undesirable components, such as sulphur compounds, are more readily removed from the gas;

• it is easier to control the build-up of the required products;

• there is good operational flexibility in that syngas made from any source (coal, petroleum

residues, natural gas, or biomass) can be used;

• in principle, the CO2 produced can readily be captured for subsequent utilisation or storage;

• the end products have near-zero aromatics and no sulphur. With minimal further refining it is

possible to produce ultraclean diesel or jet fuel.

The four demonstration projects in China that were constructed and began operation during the

11th FYP period (2006-2010) are included in Table 1 (Yue, 2010; Market Avenue, 2010). These

covered both process options.

TABLE 1 SUMMARY OF NATIONAL COAL-TO-OIL PROJECTS ESTABLISHED IN CHINA DURING THE 11TH FYP

PERIOD (YUE, 2010; MARKET AVENUE, 2010)

Company Location Technology Licensor Annual

output, Mt

Start-up

date

Shenhua Inner Mongolia DCL Shenhua 1.0 2008

Yitai Inner Mongolia ICL Synfuels China 0.16 2009

Lu’an Shanxi Province ICL polygeneration Synfuels China 0.16 2009

Shenhua Inner Mongolia ICL Synfuels China 0.16 2009


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Figure 8 The Shenhua Direct Coal Liquefaction Project (Shu, 2016)

The Shenhua Group demonstration project (Figure 8) is at Erdos in the Inner Mongolia Autonomous

Region. There is one complete production train together with the ancillaries and supporting facilities

(power, water, coal), which are sufficient for all three production lines that are ultimately intended.

This line comprises coal processing, a coal-based hydrogen production plant, liquid production and

upgrading facilities, solvent recovery plant and catalyst preparation plant together with storage vessels

for the various end products. This line produces 1.06 Mt of oil products. Annual coal throughput is

about 3.4 Mt and is supplied from a Shenhua mine that is adjacent to the DCL site. The technology

incorporates components from USA, Japan and Germany, which have been integrated in to an overall

design by Shenhua. The facility operates using a Shell coal gasification/hydrogen unit, with the basic

design for the coal liquefaction and H-Oil units licensed from Axens. In 2012, the performance data

that were released suggested that, after numerous periods of below specification operation and

subsequent equipment modifications, the Shenhua DCL process had achieved long-term stable

operation and commercial grade products, although this required some departure from the original

process specification. It had also resulted in considerable benefits from ‘learning by doing’, which

should promote the improvement of equipment manufacturing for the modern coal-to-liquids and

coal-to-chemicals industries in China, as well as the advancement of design, integration, and

construction capabilities in related fields.

The three ICL projects also made good progress over the same period. Of these, the Yitai CTL Company

produced over 160 kt of various oil and chemical products in 2012, reached design capacity for the

first time since its initial start-up, and achieved a unit consumption of 3.64 tonnes of coal and 820 kWh

of electricity per tonne of oil. Overall energy efficiency was greater than 42%. All the other

performance indices were better than the design specification (Asiachem, 2013). Gross profits were

stated as 140 million RMB (~US$24 million), which increased to 192 million RMB (US$32 million) in

2014 due to increased output (Li, 2015).


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While recognising the enormous difference in scale of operation between these DCL and ICL process

units, an outline economic assessment was made in 2011 (Research in China, 2011). This considered

the impact of the input coal price on the production cost of the crude oil from both processes. At that

time, this suggested that the breakeven price compared to crude oil was about 60 US$/bbl.

As an alternative, there is the methanol-to-gasoline (MTG) process. However, the economics are

understood to be less attractive, although the Jincheng Anthracite Mining Group has taken out two

licenses with a 2500 bbl/d unit being established in Shanxi Province (Helton and Hindman, 2014).

Consequently, in the 12th FYP period, with continuing high oil prices, plans were formulated at

Shenhua to establish additional DCL production trains, while scale-up towards 1 Mt capacity was

initiated for several ICL processes although progress has varied considerably. Table 2 provides

information on the better-defined CTL demonstration projects, which are led by the four major coal

companies, namely Shenhua Group, Yitai Group, Lu'An Group and Yankuang Group, all of which have

established technology demonstrations and are now taking forward significant scale-up opportunities.

TABLE 2 PROVISIONAL CTL DEMONSTRATION PROGRAMME IN CHINA (LI, 2013)

Company Location Annual product capacity, Mt

Shenhua Ningxia Ningxia 4

Shenhua Inner Mongolia 1

Yankuang Yulin Shaanxi 1

Yitai Xinjiang 1.8

Lu’an Changzhi Shanxi 3 x 0.5

The most advanced is the Shenhua Ningxia 4 Mt/y commercial demonstration unit (see Figure 9),

which is a joint venture between the Shenhua Group and the Ningxia Coal Corporation within the Coal

Chemical Industry Zone of the Ningdong Energy and Chemical Industry Base in the Ningxia Hui

Autonomous Region (Ningdong Government, 2016). This comprises 2 Synfuels China’s medium

temperature slurry bed Fischer-Tropsch oil production trains, each of 2 Mt capacity, together with

auxiliary facilities including 12 sets of 101,500 m3/h air separation units, 28 Siemens dry pulverised

coal gasifiers, 4 trains of Rectisol® gas clean-up systems, 3 trains of SRU methanol units, a coal-fired

power generation plant, and a waste water treatment plant. The overall plant has an annual

consumption of 24.5 Mt of coal and 25 Mt of water, and can produce 4 Mt of oil products annually,

including 2.7 Mt of diesel, 980,000 t of naphtha petroleum and 340,000 t of liquefied gas. The

by-products include 200,000 t of sulphur, 75,000 t of mixed alcohol and 145,000 t of ammonium

sulphate. The estimated total investment is RMB 55 billion.(~US$9 billion), while the projected

average annual sales income is RMB 26.6 billion (~US$4 billion), to give an average annual profit of

RMB 15 billion (US$2.6 billion) (Zhang, 2017).


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Figure 9 Shenhua Ningxia coal-to-liquids plant (World CTX, 2017)

In September 2017, the Lu’an Group via its subsidiary Lu’an Clean Energy formed a US$1.3 billion

joint venture with Air Products to own and operate the ASUs and gasification and syngas clean-up

systems for a 1.8 Mt/y CTL plant in Changzhi, Shanxi Province to demonstrate integrated

oil-chemical-electricity-heat production, using high-sulphur and high-ash coal (Air Products, 2017a).

This includes a 1 Mt/y oil production line using an iron-based catalyst, and an 800 kt/y oil/wax

production line with a cobalt-based catalyst. There will also be integration with nearby methanol

production plants to provide an alternative source of syngas feedstock (Asiachem, 2017c). The joint

venture will receive coal, steam and power from Lu’An and will supply syngas in return under a long-

term, onsite contract. The plant came fully onstream during November 2018 to supply syngas and

other industrial gases to Lu’an Clean Energy (Air Products, 2018).

In Yulin, Shaanxi Province, the Yankuang Coal Group, together with the Yanzhou Coal Company and

the Yanchang Petroleum Group proceeded slowly with the development of its coal-to-liquids

demonstration project (Xinhua, 2015). The early information suggested that 5 Mt of coal would be

converted into 1.15 Mt of oil and chemical products annually, including 790,000 t of diesel and

250,000 t of naphtha (Air Products, 2016). The intended start-up of the complete plant was scheduled

by end 2017 (Asiachem, 2017d). Major component testing of the Air Products’ air separation trains

was completed successfully, with all four units being brought fully on-stream. Subsequently, Air

Products and the Yankuang Group via its subsidiary the Shaanxi Future Energy Group Co, Ltd. (SFEC)

signed an agreement to form an Air Products majority-controlled joint venture company which would

build, own and operate the air separation, gasification and syngas clean-up system to supply about

2.5 million m3/hour of syngas to the SFEC site. SFEC would supply coal, steam and power and receive

syngas under a long-term, onsite contract. The overall project is now expected to come onstream

during 2021 (Air Products, 2017b).


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The other major prospect, Yitai’s 28 billion RMB (US$4.2 billion) CTL project, gained State approval

in 2016 (Reuters, 2016). Based in Inner Mongolia, it is expected to produce 2.15 Mt of diesel, naphtha,

liquefied petroleum gas and liquefied natural gas, as well as 157,700 t of other chemical products (Asia

Miner, 2017).

Looking to the mid-2020s, Shenhua Ningxia Group has commissioned a feasibility study for a further

4 Mt/y CTL project, including site selection and process optimisation. It has formerly announced that

in 2018 it will seek State Government approval to build this second plant. The National Energy

Administration has listed the project in the National Coal Deep Processing Plan 2016-2020. Part of the

rationale for this move is that it will allow Shenhua Ningxia to optimise the Ningdong base’s resource

allocation, improve the industrial chain, and so improve overall operational efficiency, in line with the

standards outlined above.

There are further projects being considered. For example, Yankuang Group is drawing up plans to

build another coal liquefaction unit in Shaanxi Province provisionally during the 13th Five-Year Plan

period (2016-2020), which will be designed with an annual capacity of 4 Mt. They have signed a

provisional agreement for a joint venture with American Air Products and Chemicals to develop this

project (Newsbase, 2017). The Yitai Group has set a target to produce 20 Mt/y of future fuels and

associated chemicals, and has started work on four potential projects, although only one is at the formal

approval stage, as listed above.

If all these key prospects are taken forward successfully (Asiachem, 2017c), there is expected to be

nine CTL projects in China, with an annual capacity of over 38 Mt at a total investment of some

RMB 380 billion (US$55 billion).

3.3.5 Synthetic natural gas

The Chinese government has set an ambitious goal of increasing the share of natural gas in the national

energy mix to 10% by 2020. This is part of a national initiative to reduce air pollution and CO2

emissions by replacing some of the country's coal and oil use with natural gas. Only a limited amount

is to be used for CHP and/or power production. Rather, it is used for non-power sector applications

such as local heating, cooking, and small industrial applications to counter the haze and smog that

envelops the city regions of much of China. Government projections suggest that the annual gas

demand will reach some 400 billion m3 by 2020 and ~550 billion m3 by 2030 (Forbes, 2016; US EIA,

2016a). A more recent projection by the International Energy Agency (IEA) suggested Chinese

demand for natural gas will rise by almost 60% between 2017 and 2023 to 376 billion m3 (South China

Morning Post, 2018). These levels will have to be met by a combination of domestic natural gas

production, import by pipelines and as LNG together with the introduction of alternative

unconventional domestic sources such as coal bed methane (CBM), shale gas, and CTSNG.


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China has made significant increases in natural gas production since 2003 and reached about

135 billion m3 per year by the end of 2015, with the expectation that 190 billion m3 could eventually

be achieved (US EIA, 2014). The future production growth is expected to come from large onshore

fields in the western and north central regions of China as well as from the offshore deep-water regions

in the South China Sea. Even so, China's natural gas consumption has outstripped domestic supply

since 2007, which has led to rising imports of both LNG and pipeline gas, equivalent to 32% of total

gas used in 2015.

Figure 10 provides an overview of the current and planned gas pipeline infrastructure and LNG

terminals. The main pipelines continue to be established by major oil companies, such as PetroChina

and Sinopec, to transport LNG and domestic gas from Xinjiang and imported supplies from Central

Asia to China’s eastern provinces (Platts, 2014b). As well as moving supplies of natural gas and LNG,

these can also be used to transport unconventional domestic sources such as CBM, shale gas and

CTSNG. There are also gas pipelines to supply local users, for which several of the early leader project

developers are also establishing units to convert SNG into LNG substitute to improve transport

availability of the end product.

However, neither shale gas nor CBM production is progressing at the rate suggested a few years

previously (World Coal, 2014). Although China probably has the world’s largest shale gas potential

with 31,000 billion m3 of technically recoverable resources, the economically attractive portion

appears to be severely limited due to geological complexity, shortages of water, land access, as well as

the lack of a comprehensive infrastructure and service industry (US EIA, 2016b). The 2020 annual

production target is 30 billion m3. Currently, there are more than 20,000 wells producing just

10 million m3/d from the Ordos and Qinshui Basins of Shanxi Province. Although these two basins are

considered to have China's best geologic conditions, they still face significant challenges of low

permeability and under-saturation that reduce well productivity (World Coal, 2014).


3 5


Figure 10 China’s current and planned gas transport infrastructure (Platts, 2014b)

Consequently, the introduction of commercial-scale CTSNG production has attracted considerable

interest. The process scheme for CTSNG production is set out in Figure 11. Although it is competitive

compared with domestic shale gas and imported natural gas, SNG is more expensive than the domestic

produced conventional natural gas. However, in principle, it can provide a significant contribution of

the gas supply that will be needed to achieve China’s 2020 target and beyond.

Originally, the intention was to establish four demonstration plants to allow the developers to gain

technology awareness and market experience. However, this approach was then overtaken when a

major deployment programme was initiated prior to the first four projects becoming operational. This

included proposed plants with significantly greater capacities than those included in the original plan.

Some 14 coal gasification projects in China were either under construction or at the

design/planning/development stage through to 2016, with a total potential annual SNG output of just

over 21 billion m3 pipeline quality gas. The longer-term targets were some 80–95 billion m3/y,

although the timelines for these subsequent expansions were not firmly defined.


3 6


Figure 11 Schematic of the CTSNG natural gas process (modified by author)

However, the original schedule was not maintained. Government approval procedures took much

longer to complete than had been expected, due to the need to manage the environmental and water

use impacts, which has meant that projects have been put on hold and/or failed to reach completion

by their initially projected dates. Consequently, at the end of 2016, the number of plants operational

was four, with an annual gas production capacity of around 4 billion m3, way below the original

declaration. The first plant in operation was the Qinghua Phase 1 unit in Xinjiang, with an annual

capacity of 1.4 billion m3, which commenced production in late 2013 (Interfax, 2016). By early 2014,

commissioning of the 1.4 billion m3 capacity Datang Keqi Project in Inner Mongolia was completed

and operations were underway. This was followed later that year by Phase 1 of the Huineng Project in

Inner Mongolia with an annual capacity of 0.4 billion m3 (Figure 12). Lastly, the Guanghui Energy

Project in Xinjiang, with an annual capacity of 0.5 billion m3 began operation in late 2016 (Table 3).

Figure 12 The Huineng CTSNG plant (Haldor Topsøe, 2014)

Table 3 provides a listing of these four operational projects together with others that are understood

to be being actively taken forward. This information has been gathered from various Chinese and

international sources and while it has been cross checked as far as is practicable, it is stressed that it

may not be completely accurate and so should be used with caution.


3 7


As with any major energy-based capital investment, there are various stages to address prior to final

approval to construct and operate. Consequently, any developer needs to prepare an initial proposal,

followed by a pre-feasibility design study and outline costing, then a full front-end engineering design

(FEED) study and detailed costing. Besides those being declared operational, projects in the table have

been designated as either approved, under development or under construction’. The Chinese system

does not necessarily differentiate publicly between levels of approval while being under development

generally refers to a project that has received provisional approval to move towards FEED studies. Any

project said to be under construction has achieved all of the approval hurdles. On this basis, it can be

seen that few projects are currently under construction, reflecting the limited progress that has been

made in recent years and the limited prospects for additional capacity to come on line by 2020

(Asiachem, 2016a).

Table 3 also shows that the project owners include major state-owned coal companies and power

companies, together with the three major oil and gas entities, namely CNPC, Sinopec and CNOOC.

The latter group have not just entered this sector through direct investments but have also

established themselves as end-product buyers while controlling the transport pipelines. For example:

• The Sinopec Xinjiang SNG Out-Pumping Pipeline Project is over 8000 km in length with a capital

investment of more than RMB 100 billion (US$17 billion) with a 30 billion m3 annual pumping

capacity.

• The CNOOC Mengxi SNG shipping pipeline project is some 1279 km in length and passes

through Inner Mongolia, Shanxi, Hebei and Tianjin respectively.


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TABLE 3 COAL-TO-SNG PROJECTS IN OPERATION OR FOR CONSTRUCTION IN CHINA THROUGH 2016 (BASED ON

(REUTERS, 2016; ECEC, 2015; PLATTS, 2014; CAIXIN ONLINE, 2014; ICIS NEWS, 2013; AND SELECTED PROJECT

OWNERS’ WEBSITES)

Owner Location Annual output capacity,

billion m3

Target

for first

phase

operation

Status in late 2016

1st phase Complete

plant

Qinghua

Phases 1 and 2

Yili, Xinjiang 1.4 5.5 2012 Phase 1 operational from late

2013. Phase 2 under development

Guanghui Energy Xinjiang 0.5 4.0 2012 Phase 1 operational from late

2016. Phase 2 approved

Datang Intl Keqi

Phases 1 and 2

Chifeng Inner

Mongolia

1.4 4.0 2013 Phase 1 operational from early

2014. Phase 2 under development

Huineng Phases 1

and 2

Erdos, Inner

Mongolia

0.4 2.0 2013 Phase 1 operational late 2014

Phase 2 under development

Xinwen Xintian Yili, Xinjiang – 2.0 2013 Under construction

Datang Intl Fuxin

Phases 1, 2 and 3

Fuxin, Liaoning 1.0 4.0 2013 Phase 1 under construction

Other phases under development

Huaneng Changii

Xinjiang

– 4.0 2013 Approved

Guodian Xinganmeng

Inner Mongolia

2.0 4.0 2014 Approved

Shenhua Inner Mongolia – 2.0 2015 Under development

CPI Yili Xinjiang 0.9 3.4 2015 Under development

CPI Huocheng

Xinjiang

2.0 6.0 2015 Under development

CNOOC Erdos, Inner

Mongolia

– 4.0 2015 Under development

Hongsheng

Energy

Gansu – 4.0 2015 Under development

Sinopec Zhundong

Xinjiang

– 8.0 2017 Under development

Xintian Coal Yili Xinjiang – 2 – Construction underway

Xing’an Chemical

Group

Xing’an Inner

Mongolia

4 – Construction underway

CNOOC/Datong

Coal

Datong Shanxi – 4.0 – Under development

Hebei Energy Changii

Xinjiang

– 4.0 – Approved

Henan Energy Changii

Xinjiang



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TABLE 3 – CONTINUED

Suxin Energy Tacheng

Xinjiang

– 4.0 – Under development

Huadian Hunlunbuir

Inner Mongolia


Xinmeng Energy Erdos, Inner

Mongolia


Beijing Enterprises Erdos, Inner

Mongolia


China Coal Changii

Xinjiang


CPI Yinan Yili Xinjiang 2 6 – Phase 1 under development

Beikong Jingtai Erdos, Inner

Mongolia

– 4 – Under development

Zhejiang Energy

Phases 1 and 2

Zhundong

Xinjiang

2 4 – Phase 1 under development

Zhejiang Energy Yini Xinjiang – 6 – Under development

Huaxing Energy Inner Mongolia – 4 – Approved

Anhui Energy Huainan Anhui – 2.2 – Approved

The expectation was that annual operational capacity by end 2016 would be approaching 10 billion m3

and by 2020 close to 90 billion m3. However, as already noted, due to the delays in projects being

approved, the maximum capacity for the plants currently operational is less than 4 billion m3 and in

practice these plants are running at low utilisation rates due to technical problems and design issues.

The technological requirements to ensure adequate standards can be met for efficiency, minimisation

of water usage and acceptable environmental performance are challenging, with a consequent need

for a high standard of integrated management.

These operational issues led to a suspension of the approvals procedure for other planned plants

through 2015, which was only reversed in the early part of 2016 (Reuters, 2016). Consequently, the

progress of the projects is relatively slow. Apart from the four operational units, almost all the others

listed in Table 3, although now approved and in many cases described as under development, are still

at an early preparation stage, or at best at the general design and basic engineering design stage. The

few listed with construction underway are proceeding slowly. Consequently, the CTSNG industry in

China has still to achieve the performance goals necessary for ensuring scale-up to the commercial

prototype demonstration stage before such technology deployment can proceed with confidence

(Li, 2019).

Datang International Power Generation Co Ltd, is one company that had extensive plans to enter the

CTSNG market but has now reversed that intention (Caixin Online, 2014). Some six months after its

project in Keshiketeng Prefecture became one of the first two CTSNG demonstration plants to begin


4 0


operations, this major state-owned enterprise signed an agreement with the State-owned Assets

Supervision and Administration Commission's China Reform Holdings Corp. Ltd. This agreement

allowed Datang to transfer five companies from its non-core businesses to the regulator's subsidiary.

These comprised five coal-to-gas projects in Keshiketeng, Inner Mongolia, and in Fuxin, Liaoning

Province, together with related facilities such as dedicated pipelines for the gas, which was intended

to be sold directly to local gas distribution companies for residential use. This allowed Datang to

restructure its businesses and reduce the burden of investment. Datang took this step due to massive

losses sustained on its first CTSNG project, with the risk that the other projects would also be

unsuccessful. There were technology problems centred on gasification technology issues; in particular,

the need for rigorous treatment of the waste water was a major problem. Equally importantly, there

were inappropriate plant management choices, which had been based on their core power sector

experience rather than selecting those with a sound knowledge of the chemical sector.

3.4 SECTORAL POLICY AND REGULATORY CHALLENGES

Within the coal to synthetic fuels (future fuels) sector, there have been various initiatives to establish

a viable coal conversion approach. At the same time, various design and operational limitations have

become evident that have caused the overall programme to be delayed. This has been compounded by

major falls in the global oil price, which have resulted in further disincentives to proceed with the

technology deployment programme. That said, China has approached all these issues with a strong

strategic consideration and an avoidance of short-term reactions.

3.4.1 Maximising utilisation efficiency with improved environmental impact

The Government has identified the strategic importance of introducing CTSNG to increase the

availability of methane, especially to limit local air pollution from domestic and non-power industrial

applications. CTL can fulfil a similar role, through the production of gasoline/petrol with near-zero

aromatics and no sulphur, so helping to limit the formation of haze and smog in key parts of the eastern

side of the country.

As noted above, the Government targets for gas availability would only be met through the

combination of various sources, several of which are well behind their deployment schedule.

Consequently, since there is also the need for further major transport infrastructures to be established

from remote locations, it is questionable if their respective contributions to the overall natural gas

supply will be adequate to meet the 2020 target.

The NDRC aligned the development targets for the coal-to-chemicals sector with the energy and

carbon intensity issues to be addressed during the 12th FYP (ICIS, 2011). As part of its energy

conversion efficiency drive, it recognised the importance of economies of scale and introduced

minimum plant size requirements for manufacturing chemicals and fuels from coal, below which

approval would not be given. For the synthetic fuels considered in this report, the minimum annual


4 1


product capacity requirement for coal-to-methanol and CTL are both set at 1 Mt, while for CTSNG the

annual minimum must be 2 billion m3 (SZW Group, 2011). It has also stated that any new project is

required to be consistent with China's overall plans to control coal consumption and is encouraged to

prioritise the use of low-quality coals with high sulphur and ash contents to reduce their use elsewhere

(Reuters, 2015). CTL plants would be permitted to use a maximum of 3.7 tonnes of coal for each tonne

of oil produced, while CTSNG projects would have to use no more than 2.3 tonnes coal for every

1000 m3 of gas produced.

Water availability for industrial processes is becoming a significant problem. The national policies

prohibit using residential and agricultural water for coal conversion projects, restrict SNG and CTL

projects in regions with water scarcity, and prohibit coal conversion in regions where water

consumption has reached quotas. Policies also prohibit coal conversion in regions where industrial

impact exceeds environmental tolerance. Policies prevent coal conversion in regions that import coal,

while promoting coal conversion in regions with adequate water and indigenous coal resources (China

Greentech Initiative, 2014).

Just as standards for coal use have provided a driver to improve coal gasification efficiency, so the

need to conserve water has led to the development of water saving and water purification schemes.

An example is the need to address the adverse environmental impact arising from the waste water of

the fixed bed coal gasifiers. Such plants produce a difficult effluent, which contains large amounts of

phenol and salt in the waste water that is difficult to treat. The Beijing Research Institute of Coal

Chemistry (BRICC) has utilised an advanced oxidation method to realise the open cycle of

macromolecular organics in waste water and enhance the biochemical ability of effluent. This has led

to the development of various techniques, which provide options for:

• an efficient extraction technology for the removal of phenol and ammonia from coal gasification

effluent, with an extraction rate higher than 93%; and minimal loss rate of the extraction agent;

and

• COD (chemical oxygen demand) removal from high concentration brine water, with associated

crystallisation of the salts.

Such techniques have shown promising results and large-scale trials on industrial-scale coal

gasification are planned (Du, 2016).

The NDRC has also advised that, for all new units, approval to proceed will require the owners to show

how CO2 capture technology could be applied in due course, in effect a form of CO2 capture-ready

requirement.

3.4.2 Technology improvement options

For CTL and CTSNG technologies, there is scope to improve the current options and to establish

alternative possibilities. Thus, for CTSNG, there are R&D plans to further develop the key aspects of


4 2


the methanation technology, such as improvements in fixed bed gasification pressure, efficient waste

water treatment and reuse, while also improving energy efficiency and overall financial return

(Yao, 2016). From a process perspective, there is a need in both cases to ensure operational stability,

optimise the individual system components such as gasifiers, as well as better integrate the overall

engineering design, including air-cooling and other water management technologies. The expectation

is that the NDRC wants to put together a complete process package, with intellectual property rights,

that improve the stability and economics of large plants.

Many of the initial projects were based heavily on imported equipment, which led the government to

pursue localisation for manufacture of such items together with a plan for the ‘Introduction, digestion

and absorption of imported advanced technologies’. There is an increasing emphasis on the use of

domestic designed coal gasification and some downstream plant, in line with State government

directives. At the same time, there continues to be a significant input from foreign technology

suppliers for equipment such as large-scale high efficiency air separation units together with

downstream syngas processing stages and the associated catalysts. This push to establish Chinese

equipment industry development depressed the price of imports and hence has reduced overall

project investment requirements.

3.4.3 Government financial interactions

Consumption tax is imposed on all the organisations that either manufacture or import taxable

products, process taxable products under consignment, or sell taxable products. It is levied on five

categories of products that include high-energy consumption and high-end products, such as passenger

cars and motorcycles, and non-renewable and non-replaceable petroleum products, such as

gasoline/petrol and diesel oil. Until recently, this included CTL products (China Briefing, 2016).

The State has various means to incentivise CTL activities, and recently it has chosen to exempt the

CTL companies from payment of consumption tax, as a positive policy shift to support this part of the

coal conversion sector. To put this in context, CTL projects break even when the coal price is about

400 yuan (US$58) per tonne with crude oil at about 60 US$/bbl. At current coal and oil prices, the

industry has been operating below this breakeven position, with the consumption tax being a

significant contributor to that deficit. However, since February 2017, the State Government agreed to

give preferential policies for CTL demonstration projects, with a consumption tax exemption for five

years. For Lu'an Group, for example, their annual tax commitment on their operational 1.8 Mt CTL

plant will be reduced by nearly RMB 2.5 billion (US$363 million).

3.5 CHINA COAL CONVERSION MARKET CONSIDERATIONS TO

2020

Following the global financial crisis, China introduced a stimulus programme in the fourth quarter of

2008, which was implemented through 2009 and 2010, with a value of RMB 4 trillion


4 3


(~US$586.9 billion). This massive injection of capital played a major role in the rapid growth of

infrastructure projects, to the extent that the programme subsequently had to be shut down to avoid

inflationary pressures. Nevertheless, it had a significant positive impact on building up the

coal-to-chemicals sector.

In contrast, the 2014 global slump in oil prices from 100–110 US$/bbl to below 40 US$/bbl caused

considerable difficulties. The crude oil price at which CTL and CTSNG are broadly in the breakeven

range is 60–70 US$/bbl, the exact value being project specific depending on whether the company

developing the project has access to its own coal supplies, and how it prices that coal for conversion

purposes, the proportion of equipment made in China, the exact product slate and its value, and the

end product transport costs. In all cases, there is minimal margin with the oil price below 40 US$/bbl.

With the flow-through of project proposals not translating into actual new operational plants, the

Chinese government is expected to lower its 2020 development target for all coal conversion projects.

There is also an indirect driver that could have an impact on the sustainable coal-to-chemicals sector

(Institute of Energy Economics and Financial Analysis, 2016). Thus, China is starting to rebalance

domestic coal production by reducing production capacity to bring it in to line with projected demand.

In addition to closing a considerable quantity of production, the intention is to achieve economies of

scale such that the minimum production quota for an ongoing coal mining company will be at least

3 Mt/y. The expectation is that the coal located in North and Northwest China will be relatively

unaffected since government policies have already identified that future coal production will be

focused on Xinjiang and Inner Mongolia. It remains to be seen whether such moves will result in coal

prices in China rising from their current distressed levels, which will impact on coal conversion project

profitability.

For CTL, the initial demonstration projects generally performed adequately after extensive

commissioning and some design modifications. Anecdotal evidence from various trade bodies suggests

that there are at least 16 CTL plants, with a cumulative annual production capacity of over 22 Mt either

under construction or in advanced planning stages. However, as noted in Table 2, the number of

projects that appear to have construction approval is far smaller. Thus, with the exceptions discussed

in Section 3.3.3, it is questionable that preparations are significantly under way for other such projects,

given the fall in oil prices and the consequent impact on the financial viability of such coal conversion

products. That said, CTL products pricing is regulated by the NDRC, while the product distribution

channels are also restricted, which suggests that the government has strong control over any policies

to offset the profitability problems.

For CTSNG, while there is a long list of projects, the reality is that most of these are at a very early

stage due to the problems that have occurred with the frontrunners. Much of the problem seems to be

with the early choice of the fixed bed gasifier, which appears to have been selected because the syngas

produced will contain some methane unlike rival designs. However, it is also problematical to deal


4 4


with the waste water contamination, at least within the Chinese context, although waste water

treatment techniques are being established. There is a wide range of alternative coal gasifiers available

to Chinese companies, either from domestic or international sources (Minchener, 2013). As such, the

core technology should not be a showstopper to sectoral deployment.

Initially, with a seemingly stable and high oil price making petroleum-based alternative manufacturing

routes unattractive, together with cost reduction due to the technology localisation policies, as well as

the strong government financial support, sector profitability was encouraging. However, the

subsequent cut back in government support due to the ending of its stimulus programme and the

plunge in global oil prices created major financial difficulties in this sector. Consequently, the

economic basis for establishing the coal to future fuels technology is challenging.

For functioning units, the attitude seems to be that it is worthwhile to get some return on investment

by continuing operation, as the alternative of closing down units would crystalise the potential losses,

with associated unemployment consequences. For units at the design, FEED and construction phases,

the preferred option is to slow down all preparatory work so that the plant is held back until the market

recovers. Since oil prices traditionally rise and fall, the rationale for this approach is understandable.

3.6 R&D PROSPECTS FOR THE CHINESE COAL TO SYNTHETIC

FUELS INDUSTRY

Beyond the optimisation of the commercial prototype technologies outlined above, the next prospects

are at an early stage and the market prospects are not yet clearly determined.

3.6.1 Coal (syngas)-to-ethanol

There is a potentially significant industrial demand for ethanol, for which several production methods

are available, including the conversion of coal-based syngas (Figure 13).

Figure 13 Coal-to-ethanol conversion process schemes (Asiachem, 2012)


4 5


The options include the conversion of acetic acid either by direct hydrogenation or via esterification

then hydrogenation, using coal-based syngas as the raw material source. The SOPO Group has carried

out pilot-scale trials of a syngas-to-ethanol technique that was developed jointly with the CAS Dalian

Institute of Chemical Physics and the Wuhan Engineering Company. This uses a silica-base catalyst to

convert coal-based syngas and, through the process flow of hydrogenation and separation, to a product

conforming to both the specifications of premium industrial ethanol and fuel grade ethanol

(Asiachem, 2013). From a market perspective, the volume for industrial ethanol is limited and so this

industry will only become significant if ethanol can be used as a blend with petrol in the transportation

sector. This is dependent on the establishment of positive Chinese policy and regulations and it

remains to be seen whether a coal-based production process will win any market share available

compared to a bio-process. Even then, the end product is likely to face competition from the use of

batteries and natural gas as alternative approaches.

3.6.2 Coal-based polygeneration

On the assumption that the technical improvements outlined above can be achieved, there is an

expectation that China will establish the use of a portfolio of coal gasification technologies, to

demonstrate integrated gas, electricity, and chemical polygeneration, with ‘near-zero’ emissions. This

includes the research, development, and demonstration of modern coal conversion technologies,

where coal is both a fuel and a feedstock, and can be used in conjunction with other energy sources.

The first stage might comprise a gasification-based system, primarily for power and heat production.

This can be designed so that when market demands for electricity and heat are met, various clean

energies and industrial raw materials, including natural gas, liquid fuels with ultra-low emissions,

aviation and specialty fuels, and chemicals can be produced via the gasification-based coal conversion

system (Figure 14).


4 6


Figure 14 Schematic for a coal-based polygeneration system (Power, 2014)

The second phase could incorporate coal with both unconventional energy and renewable energy

systems. An indicative example is shown in Figure 15. Such an approach seems attractive in principle

and would certainly meet the State Government’s wish to encourage innovation in industrial energy

production and use. However, it is as yet at the concept stage and will need careful consideration of

the challenges as well as perceived advantages to determine that it is a reasonable financial investment

within the coal-to-chemicals sector.

Figure 15 Framework for a multi-energy system based around coal polygeneration (Ni and others,

2014)


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3.7 EMISSIONS INTENSITY ISSUES

While it is recognised that gasification-based coal conversion produces an end product that has a

higher asset value than coal, is more flexible in its mode of utilisation and is generally seen as a cleaner

product, there is a need to consider the emissions arising from the production process.

3.7.1 Conventional emissions

The nature of the gasification system and its various clean-up units provides inherent advantages in

removing syngas contaminants prior to utilisation of the syngas (NETL, 2016), due in part to the

high-pressure gasifier operation, which significantly reduces the gas volume requiring treatment.

3.7.2 Carbon emissions

Besides the issue of high coal and water usage to produce synthetic fuels (Table 4), the other issue is

the release of CO2 into the atmosphere, which represents both a challenge and an opportunity. While

the synthetic fuel end products have high amenity values, their production results in higher levels of

CO2 release than would be the case if that coal had been directly combusted. Should the sector continue

to grow, this level of greenhouse gas release might impact adversely on China’s declared intention to

peak its national CO2 emissions by 2030, if not earlier.

However, the coal conversion processes lead to the CO2 being concentrated prior to being emitted

from the plant. This offers a potentially low marginal cost route for CCUS where the CO2 is captured,

transported and then used for EOR, providing a suitable oil well is located reasonably close to the plant.

This can provide a revenue stream to the CO2 provider from the oil producer as a result of the

incremental oil that is produced. At the same time, a significant portion of that CO2 then remains stored

within the oil deposit.

TABLE 4 ENVIRONMENTAL CHARACTERISTICS OF COAL-BASED SYNTHETIC

FUELS (DEUTSCHE BANK, 2007)

Chinese applications Standard coal

consumption

Water

consumption

CO2

emissions

tonnes/tonnes

CTL 4.4 13.0 5.0

CTSNG tonnes/1000 m3

2.8 6.6 2.5

China has a large number of coal–chemical plants in which CO2 capture offers a low-cost (less than

20 US$/t) possibility, while many of these coal-chemical plants are also in the vicinity of oil fields

amenable to CO2-EOR (Minchener, 2011b). China has the unique opportunity to demonstrate CCUS

at low cost. Since China has established significant capacity across the CCUS chain through research,

development, the construction of nine pilot projects, and extensive international cooperation


4 8


(ADB, 2015), it has reached an adequate level of readiness to construct large-scale CCUS

demonstration projects.

The NDRC of China and the Asian Development Bank (ADB) have worked closely together on a

number of CCS/CCUS institutional capacity projects, which led to the development of a coal-based

CCUS development and deployment roadmap for China. This included the identification of a number

of early opportunity demonstration projects based around large coal-to-chemicals plants that would

allow Chinese industry to gain familiarity in establishing major, multi-stakeholder projects. These

opportunities for such demonstrations can aid China in building up expertise on all aspects of the

CCS/CCUS chain. At COP21 in 2015, the Ministry of Finance of China publicly stated that the Chinese

government will work with the ADB to establish several CCUS demonstration projects using this

approach. This should also kick-start China’s intended overall CCUS demonstration and deployment

programme, which should position the nation as a global leader for ensuring that high efficiency low

emissions clean coal technology will form a key part of a global low carbon future.

In terms of a timescale for such for CO2-EOR demonstration projects, the current low oil price may

have temporarily reduced the financial incentives to proceed, since they may have a direct impact on

the CO2 off-take price that any oil producer is willing to pay. Typically, oil producers pay about a

quarter of the price of the crude oil recovered for the injected CO2. However, the fundamental drivers

remain strong.

As noted previously, China imports more than half of its crude oil. At the same time, some 70% of its

domestic oil production comes from nine large oil fields, which are all mature and are either facing or

will soon face a decline in production. In some of these oil fields, water flooding is no longer effective

in maintaining oil production levels. Introducing CO2-EOR is thus inevitable to maintain the economic

viability of such oil fields. Thus, it is essential to undertake early stage pilot testing and demonstration

to show that this technique will also successfully lead to effective CO2 storage. In order to overcome

the lack of interest at current oil prices, the Chinese government will need to provide alternative

incentives to industries both to capture and transport CO2 and to conduct CO2-EOR.

To put this in context, the NDRC-ADB CCUS roadmap suggests that a phased approach to CCUS

demonstration and deployment is needed. It recommends first targeting low-cost CCUS applications

in coal–chemical plants with CO2-EOR, to prove the feasibility of the CO2 off-take arrangement and

provide much-needed confidence in large-scale CCUS application. In parallel, intensive R&D activities,

including limited activities in coal-based power plants, could bring down the capture costs while

providing new insights and experiences. This dual-track approach of accelerated demonstration and

more intensified R&D until the year 2025 can pave the way for wider deployment of cost-competitive

CCUS from 2030 onward (ADB, 2015).

The coal chemical industry (including future fuels) expects to have to play a major role in reducing

the nation’s unit GDP carbon emission and unit GDP energy consumption by 18% and 15%


4 9


respectively during the 13th Five-Year Plan period (2016-2020). While CCS is seen as a potential

mainstream route to permanently removing CO2 from the atmosphere, there is no direct financial

benefit to industry in doing so, unless it is linked to a CO2-EOR process (that is CCUS). In recognition

of this problem, there continue to be numerous R&D programmes to turn the CO2 into a stable and

saleable product. However, the prospects remain limited, either due to market opportunities or

because the energy needed to break down the CO2 and turn it into other chemical compounds is high.

If that second energy source is carbon based, it results in additional CO2 being released, thereby partly

or wholly negating any benefit arising.

However, there are some possibilities to use renewable energy sources, which will change the carbon

balance significantly although if the end product is a fuel then the CO2 will not be removed from the

atmosphere for long. The polygeneration option outlined in Figure 16 is one such option and there are

several others. Thus R&D studies and industrial trials on the conversion of CO2 to methanol have been

carried out by numerous research agencies, both in China and abroad.

In Iceland, the aptly named Carbon Recycling International built a pilot plant that uses

renewable-derived electricity to make hydrogen for conversion into methanol in a catalytic reaction

with CO2, which had been captured from flue gas released by a geothermal power plant located nearby.

The annual recycling capacity is 5.5 thousand tonnes of CO2 a year into methanol. The energy for the

process comes from the Icelandic Grid (Carbon Recycling International, 2016).

The development focus is on the synthesis catalyst necessary to achieve high conversion and high

selectivity, as well as affordable hydrogen generation based on renewable energy sources (Asiachem,

2016c). The Chinese R&D is at an early stage, including work by the CAS Shanxi Institute of Coal

Chemistry, the CAS Shanghai Advanced Research Institute and the Shanghai Huayi Group.


5 0


Figure 16 Possible route for conversion of CO2 to methanol (Asiachem, 2016c)

3.8 EXPORT OPPORTUNITIES

Beyond its domestic market, China has begun to seek export opportunities for its own gasification

technologies and coal conversion systems, as well as looking to establish a major engineering,

procurement and construction role. Indeed, the role of China is likely to be critical in establishing coal

conversion projects in, say, certain developing countries as it can not only provide the technical

expertise but also financially underpin such activities, including the associated infrastructure needs,

which makes it a very competitive option (Minchener, 2013).

The potential to export technology and expertise is reasonable. For example, in Mongolia, which has

adequate low-grade coal and water supplies, negotiations are underway for a major CTSNG project,

with the end-product being transported to China. A feasibility study and general environmental

assessment for the project has been completed by the Wuhan Engineering Company on behalf of the

Ministry of Mining and Heavy Industry of Mongolia. This forms part of the overall economic

assessment prior to project investment. The planned industrial plant and gas transmission pipelines

will have an annual production capacity of 725 million m3 of SNG and 300,000 t of high quality

gasoline/petrol. The complex will be built next to the Baganuur coal mine, close to the capital city of

Ulaanbaatar (Montsame, 2017). The driver for the project is to limit air pollution caused by the direct

combustion of the low-grade coal through its replacement with SNG. The assessment project is being

funded by the World Bank as one of the subcomponents of the Mining Infrastructure Investment

Support Project, financed by a World Bank soft loan.

T H E W AY F O R W A R D

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4 T H E W A Y F O R W A R D

The strategic drivers for China’s coal to future fuels development and deployment programme

continue to be to support national energy security while promoting regional economic opportunities

through enhanced employment. To this is linked the need to establish intellectual property by

developing Chinese technology, which can result in increased competitiveness through cost reduction

from localised equipment manufacture.

Within these broad objectives, there continues to be a strong push to establish future fuels from coal,

primarily coal to liquids and coal to synthetic natural gas, together with the production of hydrogen,

dimethyl ether and methanol. While the latter three fuel options are mature technologies, China does

not yet have a commercial scale sector established for the two prospects with the greatest market

potential. It is close with coal to liquid processes but has some way to go for coal to synthetic natural

gas. However, it does have much of the necessary framework in place at large scale for providing the

coal and more especially for transporting the end products. At the same time, the overall development

plan continues to evolve with focused R&D in place to both improve existing options and to develop

new prospects.

That said, China is struggling to reconcile national strategic requirements with international market

forces, as reflected in the volatility of oil prices, which determines whether the coal-based future fuel

options can remain financially competitive.

In response to these challenges, China has established long term plans, since the energy optimisation

challenges can be solved, while the government can to some extent address the economic uncertainties,

thereby underpinning the sector as necessary.

The biggest issue may yet be environmental sustainability, namely ensuring the availability of water

and addressing the high carbon intensities for the various processes. There are some very innovative

developments that seek to address the former, through minimisation of direct water use and the

effective cleaning plus recycling of waste water to limit overall demand. As for the carbon issue, it is

technically feasible to capture the CO2 emitted from the processes, at low marginal cost, thereby

enabling it to be used for enhanced oil recovery, which improves its economic attractiveness. Although

this remains to be demonstrated at large scale, it is a positive sign that China has agreed that it will take

such requirements forward in cooperation with the Asian Development Bank.

Other carbon removal options are being considered, based on the use of renewable energy as a means

to break down the CO2 and form alternative products including future fuels. However, such end

products will release CO2 when used and it remains questionable whether such an approach will

ultimately result in a significant net reduction in greenhouse gas emissions.

M A I N T E X T R E F E R E N C E S

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5 M A I N T E X T R E F E R E N C E S

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http://www.hcs.harvard.edu/~hejc/papers/FT-Week4.pdf

http://www.szwgroup.com/cleancoal/2011/newshow6.asp

http://www.theaustralian.com.au/business/mining-energy/japanese-to-use-latrobe-brown-coal-to-produce-green-hydrogen/news-story/22115a61770d6f25a798e0a629839ca2

http://www.theaustralian.com.au/business/mining-energy/japanese-to-use-latrobe-brown-coal-to-produce-green-hydrogen/news-story/22115a61770d6f25a798e0a629839ca2

http://www.eia.gov/todayinenergy/detail.cfm?id=17591

http://www.eia.gov/todayinenergy/detail.cfm?id=23152

http://commons.wikimedia.org/wiki/File:Map_of_China_coal_resources.svg


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Williams R, Larson E (2003) A comparison of direct and indirect liquefaction technologies for making fluid fuels from coal. Energy for Sustainable Development. V11, (4) 103-129 (December 2003)

Wong C (2011) The fiscal stimulus program and problems of macroeconomic management in China. Available from: www.oecd.org/gov/budgeting/48143862.pdf Presented at the 32nd annual meeting of OECD senior budget officials, Luxembourg (6-7 June 2011)

World Coal (2014) Coalbed methane in China: challenges and obstacles. Available from: www.worldcoal.com/cbm/22082014/CBM-in-China-special-report-CBM100/ (22 August 2014)

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Wu K (2012) China’s oil supply security: imports, strategic stockpiling and overseas investment. Available from: www.esi.nus.edu.sg/docs/event/wu-kang.pdf Presented at China energy issues in the 12th Five Year Plan and beyond conference. Organised by the Energy Studies Institute at the National University of Singapore (NUS) Singapore (23-24 February 2012)

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Xinhua (2015) Yankuang, Yanchang Petroleum commissions 1-mln-t/yr CLT project. Available from: http://en.xfafinance.com/html/Industries/Energy/2015/144432.shtml (21 September 2015)

Yang C-J, Jackson R (2012) China’s growing methanol economy and its implications for energy and the environment. Available from: http://biology.duke.edu/jackson/ep2012.pdf Energy Policy 41 878–884 (2012)

Yao Q (2016) Personal communication, Tsinghua University (26 April 2016)

Yue G (2010) Clean coal roadmap and the development of modern coal chemical industry. Shenhua Coal to Liquid and Chemical Co Ltd. Presented at the 2nd China Clean Coal Summit, Beijing, China (April 2010)

Zhang X (2017) Visiting the world's biggest single coal-to-liquid project in Yinchuan. Available from: www.iea-coal.org/visiting-the-worlds-biggest-single-coal-to-liquid-project-in-yinchuan-china/ (27 June 2017)

S O U R C E S F O R I M A G E S

Figure

Number

Caption Attribution Source

8 The Shenhua Direct Coal

Liquefaction Project

Shu, 2016 http://cornerstonemag.net/shenhuas-dcl-project-

technical-innovation-and-latest-developments/

9 Shenhua Ningxia coal-to-

liquids plant

World CTX, 2017 http://worldctx.com/wp-content/uploads/Shenhua-

Ningxia-CTL.jpg

12 The Huineng CTSNG

plant

Haldor Topsøe,

2014

www.topsoe.com/news/2014/11/huineng-sng-plant-goes-

stream-transforming-coal-clean-energy-china

http://www.oecd.org/gov/budgeting/48143862.pdf

http://www.worldcoal.com/cbm/22082014/CBM-in-China-special-report-CBM100/

http://worldctx.com/wp-content/uploads/Shenhua-Ningxia-CTL.jpg

http://www.esi.nus.edu.sg/docs/event/wu-kang.pdf

http://chemweekly.com/release/Coal-Chemical-Industry-Outlook-2015.pdf

http://en.xfafinance.com/html/Industries/Energy/2015/144432.shtml

http://biology.duke.edu/jackson/ep2012.pdf







A P P E N D I X – F U N D A M E N T AL S O F C O A L C O N V E R S I O N T E C H N O L O G I E S

5 8


6 A P P E N D I X – F U N D A M E N T A L S O F C O A L

C O N V E R S I O N T E C H N O L O G I E S

Coal can be used as a feedstock both for the chemical industry and the production of future fuels.

Technology development began early in the 1920s and has advanced significantly since

(Higman, 2014). Besides the production of gaseous and liquid products, coal conversion by-products

such as tars from pyrolysis are used increasingly either as chemical feedstock or introduced into

refinery processes.

6.1 MAJOR ROUTES FOR THE PRODUCTION OF FUELS FROM

COAL

6.1.1 Indirect coal liquefaction

With indirect coal liquefaction, the coal is gasified to produce a raw gas, which after treatment and

purification can be used as feed gas for a wide range of syntheses. A general schematic indicating major

process units of a typical indirect coal liquefaction process chain is given in Figure 17. Gasification is

the thermo-chemical conversion of carbonaceous feedstock in a reductive gas atmosphere by adding

an agent, which can be oxygen, air, CO2 or steam. This produces a combustible gas normally containing

larger amounts of CO, H2 and smaller amounts of CO2, steam, CH4 and trace component gases.

High-purity oxygen (sometimes mixed with steam) is commonly used as the gasification agent and is

typically provided by cryogenic air separation. The feed coal, which in some cases needs to be dried

and crushed to the grain size required by the gasification process, is conveyed into the gasifier where

it reacts with the gasification agent.

The raw product gas from the gasifier is subsequently cooled and cleaned to remove dust and/or tar

prior to the removal of corrosive, catalyst poisoning gas components, such as sulphur compounds, and

the composition of the cleaned syngas is adjusted to meet the requirements of the downstream

synthesis. Besides the major process units, there are typically several auxiliary processes, such as

balance of plant, steam, sulphur recovery, CO2 and or off-gas treatment, waste water treatment, as well

as synthesis product upgrading and refining.


5 9


Figure 17 Schematic of an indirect liquefaction process (modified by author)

6.1.2 Suitable feedstock range

In principle, there is no restriction with respect to coal quality regarding its applicability to an indirect

coal liquefaction process. That said, for specific coal gasification technologies, there are constraints as

to acceptable ash and moisture content, and grain size. Since coal quality can vary significantly

depending on coal rank, ash content and ash properties, not every coal is applicable to every gasifier

design either for technological or economic reasons. Nevertheless, there is a wide range of commercial

gasification technologies to cover the whole range of coal qualities.

As well as coal gasification, there are various technologies available or under development, which are

designed to use biomass or other carbonaceous fuels as feedstock. There is also the option to co-gasify

biomass with coal. This approach has been industrially tested, with the amount of co-fed biomass that

can be accommodated strongly depending on the impact on the ash/slag behaviour, the availability of

biomass and the level of pre-treatment needed since biomass has a lower energy density than coal.

Once the raw gas is provided, there are various mature and well commercialised gas treatment

technologies to upgrade the syngas to the quality required by the synthesis process.

6.1.3 Description of underlying process principles

Coal gasification technologies

The main process of an indirect coal liquefaction route is the gasification process that converts the coal

into a raw gas, which can be used as syngas after cleaning. The most important gasification reactions

are given below. Besides the indicated heterogeneous and homogeneous gasification reactions,

pyrolysis reactions also occur during heating of the coal particles, yielding mainly char, higher

hydrocarbons (in particular aromatic compounds), water (from drying and decomposition of oxygen


6 0


containing functional groups in the coal structure), carbon dioxide and methane. Because of the

complex mechanism of pyrolysis reactions, they are not included in the list of reactions below. Most

of the pyrolysis products will be reactants converted into syngas compounds during later gasification

reactions. Hence, they are normally not found (or only to a very little extent) in the raw gas except

for fixed bed gasification systems where higher hydrocarbons are commonly found in the raw gas

because of the operating conditions created by the counter-current flow scheme inside the gasifier.

In situ combustion reactions partially taking place and covering the energy demand of endothermic

gasification reactions are (Krzack and Smalfeld, 2008):

C + O2 → CO2 -406.3 kJ/kmol (1)

2 C + O2 ↔ 2 CO -246.7 kJ/kmol (2)

2 CO + O2 ↔ 2 CO2 -556.9 kJ/kmol (3)

2 H2 + O2 ↔ 2 H2O -483.7 kJ/kmol (4)

CH4 + 2 O2 ↔ CO2 + 2 H2O -802.3 kJ/kmol (5)

Endothermic and exothermic gasification reactions:

C + CO2 ↔ 2 CO +159.6 kJ/kmol (6)

C + H2O ↔ CO + H2 +118.5 kJ/kmol (7)

C + 2 H2O ↔ CO2 + 2 H2 +77.3 kJ/kmol (8)

C + 2 H2 ↔ CH4 -87.7 kJ/kmol (9)

CO + H2O ↔ CO2 + H2 -41.1 kJ/kmol (10)

CO + 3 H2 ↔ CH4 + H2O -206.2 kJ/kmol (11)

2 CO + 2 H2 ↔ CH4 + CO2 -247.3 kJ/kmol (12)

According to equations 1–12, the reactions comprise exothermic and endothermic reactions. A high

share of the yielded syngas components can be attributed to heterogeneous gasification reactions, most

of which are endothermic and therefore require provision of heat. For the gasification of solid fuels,

the typical process principle is autothermic gasification where a fraction of the fuel is internally

combusted to provide the heat required to carry out the endothermic reactions. For the conversion of

gaseous or light liquid hydrocarbons, for example, naphtha or natural gas, the process schemes include

an external heat supply and are called allothermic processes. In contrast, for autothermic processes,

high-purity oxygen sometimes mixed with steam is used as the gasification agent. Although air was

used in older plants, today’s gasification plants apply high-purity oxygen (≥98 vol%) to avoid dilution

of the raw gas by the nitrogen contained in the air which would be disadvantageous for downstream

gas processing and the synthesis unit.

Autothermic solid fuels gasification processes can be distinguished by three principles for solid gas

contacting, namely fixed or moving bed, fluidised bed or entrained-flow gasification. The major

differences regarding grain size, residence time and other parameters are summarised in Table 5.


6 1


TABLE 5 MAJOR DIFFERENCES BETWEEN FIXED BED, FLUIDISED BED AND ENTRAINED-FLOW GASIFICATION

(PARDEMANN AND MEYER, 2015)

Fixed bed gasification Fluidised bed gasification Entrained-flow gasification

Feedstock particle size Coarse

(>5 mm up to several cm)

Fine-grained

(mm range)

Powdered

(<0.2 mm range)

Feedstock feeding Quasi-continuous feeding

using lock hoppers

Gravimetric through

angular pipe or screw

conveying

Pneumatically or by dense

flow feeding using lock

hoppers or slurry feeding

Oxygen consumption Low/medium Medium High

Operating temperature Below or above ash

melting

Below ash melting Above ash melting

Raw gas exit

temperature

650–1070 K 870–1270 K 1270–1770 K (without raw

gas cooling)

Carbon conversion 80–90% (remaining

carbon in tar condensate)

85–95% (remaining

carbon mostly in ash)

95–99% (remaining carbon

in fly ash and slag)

Hydrocarbon

decomposition

Marginal Almost complete Complete

Syngas characteristics

(dependent on coal

quality)

High CH4 yield

Higher H2 content

compared to CO

High CO2 content

Tar condensate in raw gas

Medium CH4 yield

Almost equal ratio of H2

versus CO

Reduced tar condensate

content

Lower CO2 content

compared to fixed bed

High CO content at lower

H2 content

Lowest CH4 concentration

Minimal CO2 content

No tar condensate in raw

gas

One of the most important parameters distinguishing the three process principles is the operating

temperature. Whereas entrained-flow processes are operated above the ash melting temperature,

fluidised and moving-bed processes require lower temperatures below the ash melting temperature

(with some exceptions). Gas cooling is required because subsequent gas cleaning processes are

operated at about room temperature or lower. The level of gas cooling needed is determined by the

operating temperature, with very high gasifier exit temperatures above 1250°C from entrained flow

systems and about 600°C for moving bed systems. The fluidised bed exit temperature ranges between

800°C and 1000°C, depending on the coal type used.

There are multiple concepts including direct cooling by injection of cold water into the hot gas (water

quench), direct cooling by recirculation and injection of dedusted cooled raw gas into the hot gas (gas

quench), direct cooling by secondary injection of carbonaceous fuel and taking advantage of

subsequently occurring endothermic reactions or indirect cooling by radiant or convective cooling

with recovery of heat for steam generation. Besides, there are hybrid systems combining some of the

described options. A major issue for gasification processes operated above the ash melting temperature

is the avoidance of deposition or fouling in heat exchangers caused by solidifying sticky ash particles.

Another issue is the need to prevent corrosion caused by condensation of alkali vapour compounds


6 2


like Na or K. For chemical applications, the widest applied option for gas cooling is water quenching

because of lower equipment costs and advantageous conditions for the downstream gas treatment. In

contrast, applications requiring the highest overall system efficiencies like IGCC power plants benefit

from heat recovery cooling systems.

Besides differences in cooling of the raw gas exiting the gasification reactor, there are requirements to

control coal grain size and moisture content, with the latter strongly dependent on coal rank and

quality. There are different milling technologies applicable for different coal types. Whereas mills for

hard coal often feature an integrated milling and drying approach, for lower rank coals typically there

are separate processes.

The energy requirement for milling depends on the type of the applied mill, for example rod mill,

hammer mill or roller mill, and coal hardness, typically with decreasing hardness for lower rank coals.

The average energy consumption of widely applied roller mills is about 7 to 7.5 kWh/kg of coal.

For separate coal drying there are tubular dryers and fluidised bed dryers, which are particularly

applicable for low rank coals like lignite. The thermal energy requirement is at least as high as the

evaporation enthalpy of the water at the given process pressure, and normally is about 2500 to

3000 kJ/kg of evaporated moist water. As there are different binding forms of water in coal, the energy

demand for drying can exceed the evaporation enthalpy with decreasing moisture content of the coal.

In addition to integrated drying and milling being mainly applied to bituminous and higher-rank

subbituminous coals, there are also fluidised bed dryers for low-rank subbituminous coals with high

moisture content. Fluidised bed drying is used for fine-grained coal under atmospheric or elevated

pressure. There is a high efficiency potential by fluidised bed drying as the drying heat demand can be

satisfied by compression and utilisation of the latent heat of the vapour obtained from coal drying. If

installed upstream of an entrained-flow gasification process, the dried coal will be milled to the

required particle size after drying. As yet, there is not a commercial drying technology for lump coal.

Whereas moving-bed and fluidised bed gasification are characterised by gravimetric dry feeding, coal

injection into an entrained-flow gasification reactor can be realised by dry or slurry feeding of

dust-grained coal (less than 0.2 mm). Gasification processes applying slurry feeding can achieve higher

operating pressures than dry-fed gasifiers ranging between 6 and 6.5 MPa as the slurry consisting of

approximately 60–65 wt% coal and 35–40 wt% water is simply pumped to the required pressure and

injected into the reactor. Today’s dry feeding systems for entrained-flow gasification mostly rely on

pneumatic or dense phase feeding using a transport gas that is often N2 limiting the maximum pressure

to about 4 MPa for prevention of raw gas dilution with inert gas components. Dry-fed systems

generally feature higher efficiencies because there is no need for evaporation of the slurry water

consuming an additional fuel for heat provision in the autothermal processes. New developments aim

for high-pressure dry-feeding systems by so-called solid feed pumps allowing for higher feeding

pressures without a need for increasing carrier gas flow. Developments include the pumps by GE and


6 3


by Rocketdyne-Aerojet (Gräbner, 2015). However, none of the new developments have achieved

commercial application so far.

An overview of commercial coal gasification technologies is given in Table 6. Whereas moving-bed

gasification was the dominating technology in the past, the majority of newly installed plants today rely

on entrained-flow gasification (Higman, 2014; GTC, 2015). Although there are a number of Western

equipment providers with technologies developed mainly during the 1970s and 1980s, the more recent

developments took place in China, resulting in a number of new processes. Current drivers are to reduce

Capex, increase efficiency and optimise gas composition to specific applications. There is also focus on

the development of new gasifiers to utilise lower feedstock quality.

TABLE 6 OVERVIEW OF COMMERCIAL COAL GASIFICATION TECHNOLOGIES (PARDEMANN AND MEYER, 2015)

Fixed bed gasification Fluidised bed gasification Entrained-flow gasification

Below ash melting:

Lurgi fixed bed dry bottom

Sasol fixed bed dry bottom

Sedin fixed bed dry bottom

Above ash melting:

Envirotherm or ZEMAG

British Gas Lurgi (BGL)

High-temperature Winkler

U-Gas (Gas Technology Institute)

Envirotherm circulating fluidised

bed

KBR Transport-Integrated Gasifier

(TRIG)

Dry feeding:

Prenflo Direct Quench

Prenflo (conventional)

SIEMENS fuel gasification process

(GSP)

Shell coal gasification process

CHOREN Clean coal gasifier

Mitsubishi (MHI) air and

oxygen-blown gasifier

Huang HT-L gasifier

Pratt Whitney Rocketdyne (PWR)

Slurry feeding:

GE gasification

Phillips66 (E-Gas) gasification

MCSG (North-West research

Institute) gasifier

Opposite Multiple Burner gasifier

(East China University of Science

and Technology)

Two-stage oxygen gasifier

(Tsinghua University)

As the most important component of a coal-to-liquids route is the gasification block, significant effort

is put on reduction of capital expenditures in particular as it has the highest share of equipment costs

ranging between 40% and 65%. Besides the development of more compact gasifiers, for example, by

Aerojet Rocketdyne, reduction of specific capital costs shall be achieved by increasing the single-unit

capacities (such as, GE, SIEMENS, ECUST, Air Liquide Global E&C Solutions), introducing dry-feed

pumps (see above), replacing heat recovery systems for syngas cooling by less expensive quench

systems or by increasing the gasification pressure to build smaller reactors with higher specific

throughput (including CB&I, Air Liquide Global E&C Solutions).


6 4


Examples for increase of efficiency are illustrated by efforts to maximise carbon conversion or by

developments for dry-feeding systems or by the introduction of heat recovery systems instead of

quench cooling. Optimisation of the raw gas composition for a specific application is to some extent

contradictory to efficiency increase by heat recovery steam generators as syngas composition

adjustment is mainly addressed by introduction of quench systems reducing the need for downstream

CO-shift conversion.

Adaptation to a lower quality feedstock, that is low-grade and low-rank coals, is addressed particularly

by low or medium-temperature gasification, typically based on fluidised bed systems. Examples for

new gasification concepts include the ICC-CAS fluidised bed gasifier, the E-Str concept of CB&I and

INCI proposed by TU Bergakademie Freiberg. In addition, fixed bed dry bottom gasification

technologies can cope with high ash content coal, albeit with adaptation of operating procedures and

conditions (Gräbner, 2015).

Provision of high-purity oxygen

While some gasification processes operate with air (for example, to provide producer gas), modern

autothermic gasification processes use high-purity oxygen as the gaseous reactant, especially for

syngas or hydrogen provision. Typically, this is provided by cryogenic air separation, which comprises

a low-temperature distillation of air according to the Linde principle. The air is first dried then

subjected to stage-wise compression with intercooling to very high pressure (about 7 MPa) before it

is expanded to take advantage of the Joule-Thomson effect leading to a very low temperature close to

80 K. Separation of oxygen and nitrogen takes place in two separate distillation columns, these being

insulated (so-called cold box) and operated at different pressure levels, in the range 0.5–0.6 MPa for

oxygen and 1–1.2 MPa for nitrogen. Thus high-purity nitrogen is recovered from the high-pressure

column (because of its lower boiling temperature) while oxygen and lower-purity nitrogen are

obtained from the low-pressure column. The purity required for the oxygen ranges between 98 and

99.5 vol%. If high-purity nitrogen is also a desired product, it can be obtained at up to 99.9 vol% purity.

Today’s largest cryogenic air separation units are capable of providing up to 5000 t/d oxygen in a single

train with new developments targeting 7000 t/d oxygen capacity. Auxiliary power consumption of

state-of-the-art air separation produces high-purity oxygen is about 0.245 kWh/kg of oxygen. Future

potential indicates 0.175 kWh/kg of oxygen for highly heat integrated, thermo- and fluid-dynamically

optimised air separation units (Pardemann and Meyer, 2015).

Gas treatment and conditioning

Gas purification for liquid syntheses comprise mature technologies. The typical sequence starts with

the preferentially separate removal of tars and dust followed by the removal of NH3 and HCl.

Dependent on the concentration of sulphur species in the gas and the requirement for the final syngas

H2 content, the next step is either removal of sulphuric acid compounds or gas conditioning by


6 5


CO-shift conversion. If the sulphur removal unit is not capable of handling organic sulphur compounds,

a COS and CS2 conversion reactor is required before scrubbing of H2S and subsequently of CO2.

For raw gas containing sufficient sulphur concentration and for syntheses or applications not requiring

100% H2 in the syngas, the typical CO-shift conversion process would be the sour shift process. For

ammonia synthesis or H2 production, the CO-shift process would be a sweet CO-shift.

Figure 18 Gas purification sequence for sour and sweet CO-shift (modified by author)

Figure 18 provides a schematic that indicates the typical sequence of gas purification steps. If the gas

contains tar, as is the case for fixed bed coal gasification, tar oil compounds need to be removed, for

example, benzene, toluene or xylene, either together with the dust or separately by removing the dust at

elevated temperature and the tar compounds at lower temperatures being the optimal case. The most

commonly applied process is a venturi-type wash cooler removing tar and dust and cooling down the

raw gas for downstream gas conditioning steps. There is a requirement for extensive treatment of the

tar-dust-water mixture due to the dissolution of organic compounds, especially phenol, in the scrubber

water.

The next step after removal of the bulk content of solids from the raw gas is additional water scrubbing.

Besides removal of the finest particles and droplets, water scrubbing aims for recovery of ammonia

and halide species from the raw gas. Having passed the water scrubbing, the downstream gas

conditioning differs dependent on the syngas quality required. The downstream gas purification does

not only aim for removal of pollutants and catalyst poisoning components but also for adjustment of

the gas composition, in particular the (H2-CO2)/(CO+CO2) ratio. The hydrogen content normally

needs to be increased at the expense of the CO content by applying the homogenous water-gas-shift

reaction (see equation 10) using steam as reactant and increasing the content of CO2 that needs to be

removed after passing the CO-shift stage. The extent of hydrogen content adjustment depends on the

H2/CO ratio of the raw gas provided by the gasifier and the syngas requirement. The H2/CO ratio

differs with coal rank and gasification process, with lower ratios for entrained-flow gasifiers and higher


6 6


hydrogen content for fluidised bed and moving-bed gasification. As CO-shift conversion is performed

in fixed bed reactors filled with a catalyst bed, the sulphur content of gas entering the CO-shift unit is

an important parameter. There are two process variants: the sulphur resistant catalyst is applied to the

raw gas, known as sour CO-shift; and a sulphur sensitive catalyst is used for the sweet gas CO-shift.

Whereas the sour shift catalyst requires a minimum H2S/steam ratio in the raw gas and a minimally

achievable CO concentration in the exit gas in the range of 3 to 4 vol%, sweet CO-shift can yield as low

as 0.2 to 0.4 vol% residual CO concentration if applied as a multi-stage process. The maximum H2S

concentration should not exceed between 6-7 ppmv for the high-temperature stage and needs to be

less than 0.1 ppm for the low-temperature stage. Most coals will yield a raw gas of sufficiently high

sulphur content to apply a sour shift system. A minimum steam to dry gas ratio of 1.5 to 2 is required

for both CO-shift types for optimal reaction conditions to approach thermodynamic equilibrium.

If the synthesis requires maximum hydrogen concentrations, for example, ammonia synthesis or

hydrogen for refinery applications, sweet CO-shift conversion will always be required to reduce the

CO content to a minimum, thereby maximising the H2 yield. Hence, the next step after water scrubbing

includes the removal of sulphur components before the gas is saturated with steam and then

completely passed through the CO-shift unit. This is a combination of multi-stage high-temperature

conversion (280–490°C) and a one-stage low-temperature reactor (180–250°C). The significantly

increased content of CO2 is reduced by low-temperature CO2 removal, see below. Residual

concentrations of CO2 or CO are further reduced, either by conversion of both species into methane

if increased inert gas content is acceptable, or by cryogenic scrubbing or application of special CO

removing solvents.

All other syntheses for transportation fuels including synthetic natural gas feature lower requirements

for the H2/CO ratio. One or two-stage reactor setups are applied to sour CO-shift conversion with the

reactors operated at high temperature between 280°C and 490°C and bypassing a fraction of the raw

gas around the CO-shift unit. The bypass ratio is determined by the exit CO and H2 contents of the

converted gas, the raw gas H2/CO ratio, and the syngas requirement. Sulphur compounds as well as

CO2 are removed following CO-shift conversion, see below. As CO2 often acts as a reactant, there are

less stringent requirements for the CO2 capture rate, allowing for a slightly higher operating

temperature of the CO2 removal section. Complete removal of CO2 is advantageous only for

cobalt-based low-temperature Fischer-Tropsch synthesis where too high a CO2 content in the purified

syngas leads to a need for larger equipment size.

As noted above, the final step to obtain a syngas meeting the synthesis requirements includes the

removal of acid gas components including sulphur (organic and inorganic) and CO2. Currently, the

widest applied acid gas removal process for coal gasification-based syngas is based on physical

absorption applying methanol as the scrubbing agent. All such processes rely on the strongly

temperature-dependent solubility of sulphuric acid gases and CO2 in methanol. Applying methanol as

solvent results in residual sulphur concentrations of less than 0.1 ppmv, with the capability to


6 7


simultaneously reduce the CO2 content down to 10 ppmv. Most of the sulphuric acid gases are

removed at about 273 K whereas trace concentrations and the CO2 are removed at between 200 K and

240 K. Although this type of washing is energy intensive, due to the low-temperature cooling, it is the

preferred technology solution because of its capability to also remove most other pollutants to

minimum levels, for example, higher hydrocarbons such as tar compounds as well as carbonyls. Both

types of compounds are collected from the raw gas before the sulphur removal stage. Moreover, it is

possible to remove organic sulphur species without requirement for prior conversion to H2S.

For common synthesis applications, especially fuel syntheses, this process is the last step before

providing the purified and conditioned syngas to the reactor.

Fischer-Tropsch (FT) synthesis

This synthesis technique was developed and commercialised in Germany in the 1930s

(de Klerk, 2011a,b) for processing a wide range of feedstocks (Table 7). It is characterised as a High-,

Medium- and Low-temperature FT process, according to the synthesis temperature.

TABLE 7 OVERVIEW OF COMMERCIAL FT TECHNOLOGIES (GTC, 2015)

Co-LTFT Fe-LTFT Fe-MTFT Fe-HTFT

Reactor types Fixed bed

microchannel

slurry

Fixed bed slurry Slurry Circulating or

stationary fluidised

bed

Feedstock Biomass, coal,

natural gas

Biomass, coal,

natural gas

Coal Coal, natural gas

Commercial process

examples

Sasol Slurry Phase

Distillate

Shell Middle

Distillate

Sasol Slurry Phase

Distillate

Synfuels China High

Temperature Slurry

FT

Sasol Advanced

Synthol

Syncrude composition

(major components,

wt%)

CH4: 6

LPG: 5

C5-C10: 20

C11-C22: 22

C22+: 46

CH4: 6

LPG: 6

C5-C10: 20

C11-C22: 22

C22+: 47

CH4: 4

LPG: 4

C5-C10: 13

C11-C32:43

C33+:31

CH4: 13

Ethylene: 6

LPG: 22

C5-C10: 34

C11-C22: 7

C22+: 3

Operating

temperature, °C

≈240 ≈240 ≈280 ≈340

Operating pressure, MPa ≈2.5 ≈2.5 ≈2.5 ≈2.5

Sources (de Klerk, 2011a,b) (de Klerk, 2011a,b) (Li, 2014; Xu and

others, 2015)

(de Klerk, 2011a,b)

The product of FT synthesis (syncrude) comprises a broad range of hydrocarbons, the main products

are alkenes, alkanes, aromatics and oxygenates. For simplification, hydrogenation of CO is shown in

equation 13, which shows that water is a major by-product.


6 8


nCO + 2nH2 → -(CH2)- + H2O -165 kJ/kmol (500 K) (13)

Hydrogenation is a highly exothermic process and heat removal is critical for FT reactor design. As a

result, all FT processes produce medium pressure steam in cooling coils (slurry reactors, fluidised bed

reactor) or at the shell side of a multi-tubular reactor (fixed bed).

For all processes, the molar fraction xn of each carbon number n in the product depends on the chain

growth probability 𝛼. This relationship is described by the Anderson-Schulz-Flory (ASF) distribution:

𝑥𝑛 = (1−) ∙ 𝛼(𝑛−1) (14)

In practice, for all commercial FT processes, the methane selectivity is larger than predicted by the

ASF relationship, Figure 19. In contrast, the concentration of C2-components is usually lower. Catalysts

for LTFT processes can be characterised by two 𝛼 -values due to the large fraction of heavy

hydrocarbons.

Figure 19 Anderson-Schulz-Flory carbon number distribution (de Klerk, 2000)

Cobalt catalysts have a lifetime of several years, which makes them more suitable for operation in fixed

bed reactors. The water-gas-shift reaction is not catalysed and only low amounts of CO2 are produced.

The desired H2/CO ratio in the syngas feed stream should be in the range of 2.06–2.10.

For FT processes using iron catalysts, the water-gas-shift activity needs to be considered. Thus:

CO2 + H2 ↔ CO + H2O -40 kJ/kmol (500 K) (15)

Iron catalysts have a high-water-gas-shift activity which should be taken into account when the syngas

modulus is calculated. The so-called Ribblett ratio needs to be considered in this case:

(H2)/(2 CO+3 CO2) ≈ 1 (Steynberg 2004). Iron catalysts are well-suited for feedstocks with a low


6 9


hydrogen content such as coal. Usually, iron catalysts are replaced after several weeks and not

rejuvenated. For HTFT a typical cycle time is 40–45 days, while for LTFT it is 70–100 days

(de Klerk, 2000).

HTFT is undertaken in either circulating or stationary fluidised bed reactors at 330–360°C

(de Klerk, 2011). All products are gaseous and can be separated after cooling outside the reactor. Only

iron catalysts are used. Fluidised bed reactors have advantageous mass and heat transfer properties in

comparison to fixed bed reactors. Gas-catalyst separation is achieved using cyclones. As shown in

Table 7 a large fraction of the syncrude consists of short- and medium-length chain products, such as

LPG and naphtha. This makes HTFT suitable for the production of gasoline and diesel products.

A flowsheet of the HTFT process is shown in Figure 20. Stepwise cooling of products is used to

separate recycled components and heavy hydrocarbons. Liquid-liquid separation steps are required to

remove liquid oil from aqueous products.

Figure 20 HTFT: Product separation and gas loop design (de Klerk, 2011a,b)

HTFT (also known as High Temperature Slurry Fischer-Tropsch) is conducted using an iron catalyst

in the slurry phase. Operating conditions are around 270–290°C (Xu and others, 2015). The elevated

reactor temperature can be used to generate high temperature steam. In addition, the developers state

that the catalyst has a superior activity, low methane selectivity and a low oxygenate content in the

syncrude. Slurry reactors have superior mass and heat transfer characteristics and can be used for

online catalyst replacement. As can be seen from Table 7, MF-FT syncrude composition is similar to

other Fe-LTFT processes.

For LTFT reactors both iron and cobalt have been applied in industrial multi-tubular fixed bed reactors

and slurry reactors. The temperature regime of LTFT is usually in the range of 200–240°C


7 0


(de Klerk, 2011). Liquid product-catalyst separation is complicated and catalyst entrainment to

downstream process units can cause severe damages (de Klerk, 2011a,b).

Syncrude from LTFT synthesis consists predominantly of long-chain hydrocarbons and the most

desirable final products are Diesel, Kerosene and Wax. An illustrative Fischer-Tropsch case is shown

in Figure 21. It shows that less intermediate cooling steps are required as the first gas-liquid separation

steps takes place within the reactor.

Figure 21 LTFT: Product separation and gas loop design (de Klerk, 2000)

For this ‘open gas loop’ process, the tail gas is sent to a gas turbine to generate power. All commercial

large-scale systems are operated by recycling at least a part of the unconverted syngas. An additional

purge stream is needed to avoid build-up of inert components. The ‘closed gas loop’ design is chosen

if the syncrude yield should be maximised. In this case the purge gas stream is kept at a minimum.

Autothermal or steam reforming is applied to convert light hydrocarbons back to syngas and to

increase the output of syncrude (Steynberg, 2004).

Product upgrading and refinery design depends strongly on the desired product yield, as does the

chosen FT route. Product upgrading at FT facilities can involve production of intermediate products

or fuel blending components, which are then shipped for final refining at conventional refineries. This

minimum refining approach has been realised in the Oryx GTL-FT facility, where a single

hydrocracker is used to produce intermediate products and LPG. On the other hand, the large Sasol

Synfuels refinery complex produces motor-gasoline and diesel products, as well as numerous

chemicals (de Klerk, 2011a,b).

All of the mentioned FT processes have been applied commercially by Sasol. As noted in the main

report, other projects, primarily in China, are at the planning and construction phase, with a major unit

recently starting operation.


7 1


Methanol synthesis

Methanol is an important chemical, especially as an intermediate in the production of future fuels such

as DME, gasoline/petrol via the MTG process, and as a blend with gasoline/petrol. The first low

pressure methanol process was introduced in 1966. Typical process conditions are in the range of 5-10

MPa and 200–300℃. Unconverted syngas is usually recycled with mass-related ratios of 3 to 7

(BTG, 2015). This is due to low conversion which is typically in the range of 4–14% for each pass.

Currently, all commercially established methanol processes are low pressure using Cu/ZnO/Al

composite catalysts (Ott and others, 2012). Syngas-based methanol formation can be described by the

following reactions:

CO + H2 ↔ CH3OH -90.77 kJ/kmol (300 K) (16)

CO2 + 3 H2 ↔ CH3OH + H2O -49.16 kJ/kmol (300 K) (17)

CO2 + H2 ↔ CO + H2O +41.21 kJ/kmol (300 K) (18)

As can be seen from the equations above, the theoretical (H2-CO2)/(CO+CO2) ratio (syngas modulus)

at the reactor inlet should equal 2. For most industrial processes, a slightly larger value up to 2.1 is

chosen. By-products that can be formed during commercial processes include hydrocarbons through

FT reactions, methane, alcohols, DME, esters and ketones. Syngas-based methanol formation is highly

exothermic and a key issue in methanol reactor design is heat removal. Sintering of Cu particles on the

catalyst surface reduces catalyst activity and lifetime and makes temperature control important

(Ott and others, 2012).

Commercial methanol synthesis is conducted mainly in quasi-isothermal fixed bed reactors.

Quench-type and multibed intercooled reactor configurations are utilised as well. In 2011, Lurgi was

the major technology licensor, followed by Johnson Matthey/Davy Process Technologies and Haldor

Topsøe. The original ICI process uses an adiabatic reactor with several fixed beds, which are directly

quenched with cold syngas. This process is now owned by Johnson Matthey and offered in

collaboration with Davy Process Technologies. Since modern methanol plants are mainly based on

quasi-isothermal reactors, these technology providers now offer an axial or radial flow steam raising

reactor (Bertau and others, 2014; Ott and others, 2012).


7 2


Figure 22 One-stage quasi-isothermal methanol synthesis (Wurzel, 2006)

Lurgi offers a quasi-isothermal one-stage process for medium-scale applications and large-scale,

multi-stage concepts). The conventional one-stage reactor (shown in Figure 22) is suitable for

methanol production capacities around 3000 t/d while large-scale methanol plants have capacities of

5000 t/d and more.

Medium-scale reactor inlet temperatures are 220–250°C and can reach temperatures up to 280°C

within the reactor. By cooling the reactor outlet gas stream to about 40°C, liquid methanol and water

can be retrieved before recycling of the unconverted syngas. A purge stream is needed to avoid

accumulation of inert gases (Bertau and others, 2014; Wurzel, 2006; Chen, 2011).

The MegaMethanol™ technology consists of an integrated two stage reactor concept, as shown in

Figure 23. The first reactor is a conventional steam raising reactor. The methanol-containing outlet

stream enters a second reactor which is cooled by the syngas feed steam for the first reactor. As a

result of the countercurrent flow of the cold syngas, reactor temperature is reduced and a high

equilibrium driving force can be realised. The GigaMethanol concept has been developed for

production capacities of up to 10,000 t/d but it can so far only be applied to high pressure (up to

10 MPa) autothermal reforming. In comparison to one-stage synthesis higher per-pass conversion

rates can be achieved (Wurzel, 2006; Air Liquide Global E&C Solutions, 2015).


7 3


Figure 23 Illustration of the two-stage Lurgi MegaMethanol™ concept (Pardemann, 2013)

Adiabatic methanol reactors are commercially available from Haldor Topsøe and comprise three

reactors with inter-stage cooling (Aasberg-Petersen, 2013).

Liquid phase methanol synthesis (LPMEOH™) is a process developed by Air Products and Chemicals

Inc, specifically for syngas with a low H2/CO ratio and for IGCC operations. As shown in Figure 23,

the process comprises a slurry bubble column reactor, in which the catalyst is suspended in a mineral

oil. Syngas enters the bottom of the reactor and conversion occurs at the surface of the suspended

catalysts. Due to the hydrodynamic conditions, a homogeneous temperature distribution can be

achieved within the reactor vessel. Steam is generated in tubes immersed within the slurry.

These conditions result in higher conversion for each pass than for conventional methanol synthesis

routes. Another distinct feature is the possibility to operate the synthesis with gas with a low hydrogen

content. As can be seen from Figure 24, additional steam can be added to the synthesis gas to generate

more hydrogen through the homogeneous water-gas-shift reaction. Operation with a syngas modulus

of 0.34 has been demonstrated successfully (Air Products, 2003). However, this process has not been

commercialised due to the engineering complexity.


7 4


Figure 24 PMEOH process (Pardemann, 2013; Air Products, 1998)

Product upgrade of raw methanol can be realised through either two-column or three-column

distillation, which offer low investment costs and energy savings respectively. The methanol purity

standards A (99 wt% methanol; 0.1 wt% water; 0.05 wt% alcohols) and AA (99.85 wt% methanol;

0.1 wt% water; 10 ppm alcohols) can be achieved with either product upgrading route

(Pardemann, 2013).

The importance of methanol is illustrated by the large number of commercial coal-based methanol

plants, as shown in Table 8, and numerous units at the planning phase (Table 9). These data are all for

plants in China where the market has been moving swiftly. Consequently, while it has been cross

checked as far as is practicable, it is stressed that it may not be completely accurate and so should be

used with caution.


7 5


TABLE 8 OVERVIEW OF METHANOL PLANTS (BASED ON SOLID FEEDSTOCK) FOR METHANOL, PROPYLENE OR

OLEFINS PRODUCTION (GTC, 2015)

Plant in China Gasification technology and coal feed

capacity

Output

capacity,

MWth

Year

operation

begun

Anhui Haoyuan Chemical Plant 2 HT-L (max 1200 t/d coal) 280 2013

Anhui Huayi 2 (+1) OMB (max 3000 t/d coal) 689 2012

Anhui Linquan Chemical 1 HT-L (max 800 t/d coal) 187 2008

China Coal Yulin CTO Phase 1 (China) Not specified 5 (+2) (max 7200 t/d coal) 1,680 2014

Dalian Dahua 1 Shell Gasifier (max. 1100 t/d coal) 232 2007

Datang Duolun MTP 3 Shell Gasifiers (max 20,000 t/d coal) 3373 2011

Datong 1 Shell Gasifier (coal) 546 2014

Donghua Energy Methanol Not specified 2 (+1) (max 2400 t/d coal) 560 2012

East China Energy Inner Mongolia

Methanol

2 (+1) Multi Component Slurry

Gasification (max 3000 t/d coal)

700 2013

Eerduosi Jingchentai Methanol 2 (+1) Tsinghua Oxygen Staged


325 2013

Guanghui Xinjiang Methanol 7 (+1) SEDIN (max 4800 t/d coal) 1120 2013

Guodian Neimenggu Methanol 2 (+1) SEDIN (max 1200 t/d coal) 280 2013

Guodian-Younglight Methanol 2 (+1) GE Gasification (max 2000 t/d

coal)

400 2013

Haohua Methanol Plant 1 (+1) OMB (max 2000 t/d coal) 467 2014

Henan Coals Zhongxin Chemical 2 HTL (max 1200 t/d coal) 280 2012

Henan Junhua 2 HTL (max 2400 t/d coal) 560 2014

Henan Puyang Long Yu Chemical 1 HTL (max 600 t/d coal) 140 2008

Huahe Coal-to-Methanol 2 (+1) GE Gasification (max 1500 t/d

coal)

302 2013

Hualu Hengsheng Methanol 3 (+1) Multi Component Slurry


280 2006

Hualu Methanol 1 TPRI (max 1000 t/d coal) 280 2013

Huisheng Jiangsu 2 (+1) Shell (max 5800 t/d coal) 230 2007

Inner Mongolia Zhuozheng Methanol 4 (+1) GE (max 5600 t/d coal) 1250 2013

Jiangsu SOPO 2 (+1) OMB (max 3000 t/d coal) 551 2009

Jinling Methanol Plant 1 (+1) GE (max 1000 t/d coal) 233 2005

Juhua Zhejiang Methanol 3 (+1) Multi Component Slurry


560 2007

Kaixiang Chemical 1 Shell (max 1100 t/d coal) 257 2008

Lanzhou Gas 5 Lurgi FBDB (max 800 t/d coal) 187 1991

Linyi Shanxi Yangmei Fengxi Methanol 1 Tsinghua Slurry Membrane Wall


163 2011


7 6




capacity

Output

capacity,

MWth

Year

operation

begun

Manzhuoli Methanol 1 TPRI (max 3000 t/d coal) 560 2012

Nanjing Wison 2 (+1) GE (max 1500 t/d coal) 288 2007

Ordos Xinhu MTO 6 (+1) Unspecified (max 7200 t/d coal) 1680 2014

Puyang Methanol 1 Shell (max 2000 t/d coal) 463 2008

Rongxin Inner Mongolia Methanol 2 (+1) OMB (max 6000 t/d coal) 1400 2014

Sanwei Methanol 1 (+1) Multi Component Slurry


187 2008

Sanwei Neimenggu Methanol 4 (+2) GE (max 5000 t/d coal) 1167 2011

Shaanxi Shenmu Chemical 2 (+1) GE (max 600 t/d coal) 120 2005

Shaanxi Shenmu Chemical (Phase II) 2 (+1) GE (max 1200t/d coal) 235 2009

Shanghai Coking & Chemical 2 (+1) GE (max 1500 t/d coal) 209 1995

Shanghai Coking & Chemical 1 OMB (max 2000 t/d coal) 448 2013

Shanxi Fengxi Methanol 2 (+1) Tsinghua Oxygen Staged


116 2006

Shenhua Baotou Coal-to-Olefins 5 (+2) GE (max 6000 t/d coal) 1750 2011

Shenhua Ningmei 2 (+1) OMB (max 3000 t/d coal) 689 2009

Shenhua Ningxia Coal to Polypropylene I 4 (+1) Siemens (max 18,000 t/d coal) 1912 2011

Shenhua Ningxia Coal to Polypropylene II 14 (+2) SEDIN (max 10,600 t/d coal) 2500 2014

Shilin Methanol 1 TPRI (max 1000 t/d coal) 280 2014

Shuangxing Methanol 3 (+1) AFB 300 2014

Tongzi Chemicals 2 GE (max 2800 t/d coal) 596 2012

Wansheng Methanol 2 (+1) Multi Component Slurry


280 2011

Weihe Pucheng Methanol 4 (+2) GE (max 9500 t/d coal) 1856 2014

Wison MTO 3 (+1) Unspecified (max 3450 t/d coal) 826 2013

Wison Nanjing Methanol 2 (+1) GE (max 1500 t/d coal) 284 2006

Wison Nanjing III 1 GE (max 1600 t/d coal) 284 2015

Xianyang Methanol 3(+1) Multi Component Slurry


560 2010

Xinao Methanol 2 (+1) GE (max 3400 t/d coal) 625 2011

Xinsheng Methanol 2(+1) Multi Component Slurry


280 2011

Xukuang Baoji Methanol 2 (+1) GE (max 3200 t/d coal) 635 2013

Yanchang Yulin Methanol 1 (+1) GE (max 2400 t/d coal) 560 2008


7 7




capacity

Output

capacity,

MWth

Year

operation

begun

Yankuang Cathay 2 (+1) OMB (max 2,300 t/d coal) 423 2005

Yankuang Guodong Methanol 2 (+1) GE (max 2000 t/d coal) 467 2007

Yankuang Neimeng 2 (+1) OMB (max 5000 t/d coal) 1167 2014

Yanzhou Yulin Methanol 2 (+1) GE (max 3000 t/d coal) 700 2008

Yima JV 2 (+1) SES/U-GAS Gasification

(max 2400 t/d coal)

550 2012

Yongcheng Phase 1 1 Shell (max 2250 t/d coal) 424 2007

Yulin Yanchang Methanol 1 (+1) GE (max 1600 t/d coal) 280 2007

Yunnan Methanol & DME 4 (+1) BGL Gasification Technology

(max 5000 t/d coal)

1120 2011

Zhonghua Yiye Methanol 2 (+1) GE (max 3000 t/d coal) 612 2008

Zhongtian Hechuang MTO 10 (+4) GE (max 15,000 t/d coal) 3500 20


7 8


TABLE 9 OVERVIEW OF COAL-BASED PROJECTS FOR METHANOL, PROPYLENE AND OLEFINS PRODUCTION IN

PLANNING, DEVELOPMENT AND CONSTRUCTION IN CHINA (GTC, 2015)

Plant Gasification technology and coal feed

capacity

Output

capacity,

MWth

Status and likely year of

operation

Baolong Clean Energy Not specified 16 (+2) gasifiers

(max 21,500 t/d coal)

4780 Under development (2018)

Dow-Shenhua Yulin CTO Not specified 8 (+2)

(max 12,000 t/d coal)

2800 Under development (2018)

ENN Dalateqi Methanol 2 (+1) OMB (max 3000 t/d coal) 700 Under development (2016)

Hebi CTO Not specified 5 (+2) (max 7200 t/d coal) 1680 Under development (2016)

Heilongjiang Dragon Coal

Shuangyashan

2 BGL (max 1200 t/d coal) 280 Under development (2016)

Hualu Hensheng Methanol 1 (+1) OMB (max 2500 t/d coal) 503 Under development (2016)

Huating Zhongxu Methanol 3 (+1) Multi Component Slurry


560 Status unknown

Huayu Liubei Methanol 4 HTL (max 3000 t/d coal) 711 Status unknown

Kaixiang Chemical Plant II 1 Shell (max 1100 t/d coal) 256 Under development (2016)

Linyi Methanol Plant 2 HTL (max 2000 t/d coal) 475 Status unknown

Mengda New Energy MTO 6 (+2) GE (max 7200 t/d coal) 1680 Under construction (2015)

Neimenggu Methanol Plant 11 (+1) SEDIN (max 5344 t/d coal) 1558 Under planning (2015)

Pucheng CTO Plant 6 (+2) Unspecified (max 8160 t/d coal) 1900 Under planning (2016)

Qinghai Yanhu 2 (+1) OMB (max 1000 t/d coal) 1027 Under planning (2016)

Shenhua Xinjiang CTO 5 (+2) GE (max 8000 t/d coal) 1773 Under development (2016)

Sinopec Guizhou MTO 5 (+2) Unspecified (max 7200 t/d coal) 1680 Under development (2016)

Tianxi Methanol 2 HTL (max 1440 t/d coal) 342 Status unknown

Total CPI MTO Plant 8 (+2) Unspecified (max 12,000 t/d coal) 2800 Under development (2016)

Wanhua Yantai Extension 1 (+1) OMB (max 2800 t/d coal) 670 Under development (2018)

Xinjiang Guotai Xinhua

Methanol

2 GE (max 1214 t/d coal) 280 Status unknown

Yanchang Yulin CTO 5 (+2) Unspecified (max 7200 t/d coal) 1680 Under development (2016)

Yulin Methanol 10 (+4) GE (max 11,500 t/d coal) 3383 Under construction (2015)

Zhongtian Hechuang MTO

Plant

10 (+4) GE (max 15,000 t/d coal) 3500 Under construction (2015)

Zhungeer CTO Plant 5 (+2) GE (max 6900 t/d coal) 1400 Under construction (2015)

Zhungeer Northwest

Methanol

5 (+2) Unspecified (max 4800 t/d coal) 1120 Under construction (2015)


7 9


Dimethyl ether synthesis

There are two production processes, direct and indirect DME synthesis, for which the latter represents

the large-scale technology application.

For indirect DME synthesis, methanol derived from syngas-based synthesis is fed into the DME reactor.

Dehydration of the methanol takes place in a fixed bed Al2O3 or zeolite catalyst, typically at 1–1.2 MPa.

Equation 19 shows the overall chemical equation.

2 CH3OH → CH3OCH3 + H2O ∆RH = -23 kJ/mol (19)

Achieving a conversion of up to 80% in a single pass, the unreacted methanol is separated in two stages

via distillation and recirculated. The feed stream is preheated to 250°C and the product temperature

rises to 350–400 C due to an exothermal reaction and adiabatic conditions. The DME can be upgraded

to various purity levels. The overall conversion rate of the methanol can reach 99%. A simplified

flowchart of the indirect DME synthesis is shown in Figure 25.

Figure 25 Schematic of indirect DME synthesis (modified by author)


8 0


Table 10 lists the various production processes for indirect DME synthesis.

TABLE 10 INDIRECT DME SYNTHESIS PROCESSES (DITTRICH, 2008)

Process Lurgi Haldor Topsøe Mitsubishi Gas

Chemicals

Toyo

Engineering

Company

Uhde SK Holdings

Reactor type Fixed bed,

adiabatic

Fixed bed,

adiabatic

Fixed bed Fixed bed Fixed bed Fixed bed

Catalyst Al2O3 DMK-10 Al2O3 Al2O3 Al2O3 Al2O3 & ZSM-5

Temperature, °C 290–400 270 (in)

380 (out)

250–400 220–250 (in)

300–350 (out)

270–310 230–330

Pressure, MPa 1.1–1.24 1.23 1.1–2.6 1.1–2.1 1.2 1.01–1.12

Methanol quality Pure Pure Crude Crude (to be

treated)

Pure/crude Crude

Conversion, % 80 80 70–80 70–85 80 80

Technology

maturity

Commercially

available

Commercially

available,

plants built

Commercially

available,

plants built

Commercially

available,

plants built

Commercially

available,

plants built

Under

development

DME is primarily used for domestic fuel as a substitute for liquefied petroleum gas with the focus on

China, as suggested by the limited data provided in Table 11.

TABLE 11 OVERVIEW OF INDIRECT SYNTHESIS DME PROJECTS ON STREAM IN CHINA (PAYNE, 2007)

Project owner and location Technology

provider

Capacity, t/y Year of first

operation

Shanxi Yuci Jiaxin New Energy Chemical Co (Shanxi) Unknown 10,000 1993

Henan Qingyang Nitrogenous Fertilizer (Henan) Unknown 10,000 1993

Guangdong Zhongshan Kaida (Guangdong) Unknown 10,000 1994

Luthianhua Group (Luchang) Toyo Engineering

Company

10,000 2003

Shandong Jiutai Science and Technology Co (Shandong) Unknown 30,000

150,000

2003

2005

XinAo Group (Anhui) Unknown 10,000 2005

Luthianhua Group (Szechuan) Toyo Engineering

Company

110,000 2006

Shandong Jiutai Science and Technology Co (Guangdong) Unknown 200,000 2006

Yigao Chemical Co (Inner Mongolia) Unknown 20,000 2006

Meishan Lantian Chemicals (Nanchong) Unknown 20,000 2006

Shanghai Coking & Chemical Corp (Shanghai) Unknown 5,000 2006

Hubei Cocause Industrial Group (Hubei) Unknown 100,000 2007

XinAo Group (Shanghai) Unknown 200,000 2007


8 1



Project owner and location Technology

provider

Capacity, t/y Year of first

operation

Hubei Zhongjie (Hubei) Unknown 100,000 2007

Guizhou Tianfu Chemical (Guizhou) Haldor Topsøe 180,000 2008

Yunnan Riches Chemical Industry (Yunnan) Haldor Topsøe 167,000 2008

Shenhua Ningmei Group / Ningxia Coal Group

(Inner Mongolia)

Toyo Engineering

Company

830,000 2009

XinAo Group Corp (Inner Mongolia) Unknown 400,000 2009

Shangdong Jiutai Chemical Group (Inner Mongolia) Unknown 1,000,000 2009

Sichuan LuTianHua (Luzhou, China) Toyo Engineering

Company

110,000 2010

Shenergy Group Inner Mongolia Ltd, Manshi Coal Group,

China National Coal Group, Sinopec (Inner Mongolia,

China)

Unknown 3,000,000 2010

Yuanxing Alkali Unknown 3,000,000 2011

There is one established production plant that provides DME for use as a transportation fuel, which has

an annual capacity of 80,000 t. This is located in Niigata, Japan, is based on Mitsubishi Gas Chemicals

technology, and has been operational since 2008 (Ishiwada, 2011).

Direct DME synthesis differs from the indirect process in that there is only one reactor for the

conversion of syngas to DME. Therefore, the bi-functional catalyst consists of a mixture of both

methanol and dimethyl ether catalyst. Additionally, the homogeneous water-gas-shift reaction

(compare to equation 10) supports the process. Equation 20 shows the overall chemical equation.

3 CO + 3 H2 → CH3OCH3 + CO2 ∆RH = -246 kJ/mol (20)

The molar ratio of H2 and CO equals 1:1 instead of 2:1 for methanol synthesis. In practice this value

ranges from 0.7 to 1.0 depending on temperature and pressure within the reactor. In advance, the

syngas thereby has to be treated the same way as for the syngas-based methanol synthesis to prevent

catalyst contamination. For a once-through process, the conversion of syngas to DME reaches at most

only 50% (based on CO conversion). Thus, there is also a recirculation loop but the separation of syngas,

CO2, DME and partly entrained slurry is more complex. Initially the gas separation is performed by an

absorber using parts of the produced DME as solvent in order to let the unconverted syngas pass and

to capture the CO2. There then follows a separation of the remaining fractions via distillation. Residual

methanol can also be mixed with the initial feed stream to the process. The integration of heat follows

the same principle as the indirect DME synthesis. A simplified flowchart of the direct DME synthesis

is shown in Figure 26.


8 2


Figure 26 Schematic of direct DME synthesis (modified by author)

TABLE 12 COMPARISON OF PROCESSES OF DIRECT DME SYNTHESIS (OHNO, 2004; OHNO AND OTHERS, 2005)

Process JFE Holdings Air Products and Chemicals Inc

Reactor type Slurry Slurry

H2/CO ratio 1.0 0.7

Temperature, °C 250–280 250–280

Pressure, MPa 3–7 5–10

CO conversion once-through, % 50 33

Selectivity of DME per DME+MeOH, % 90 30–80

Technological maturity 100 t/d pilot plant (2002) 4 t/d pilot plant (1991, 1999)

Table 12 provides a comparison of the available direct DME processes, which indicates that this

technology is at the pilot stage.

Gasoline synthesis

The methanol-to-gasoline (MTG) process is based on the methanol acting as an intermediate product,

which is converted to gasoline in one or more stages. The successive reaction steps are described in

equation 21 (Spivey, 1992; Keil, 1999).

2 CH3OH +H2O→ CH3OCH3

+H2O→ light olefins

→ {

paraffinshigher olefinsaromaticsnaphtenes

(21)

The dehydration of methanol results in DME and water (see section above). The DME is then converted

into light olefins and subsequently into higher paraffins, olefins, aromatics and naphthenes, together


8 3


with additional water. These steps are highly exothermic so that the product distribution strongly

depends on the prevailing reaction temperature, as shown in Figure 27 (Joseph and others, 1985). A

maximum yield of the higher aromatics that comprise gasoline can be obtained at 400°C and high

pressure (Stöcker, 1999).

Figure 27 Temperature dependence of MTG product distribution (Pardemann, 2013)

The methanol for gasoline synthesis is produced from syngas either based on coal gasification or natural

gas reforming. From 1986 until 1997 a small commercial plant in Plymouth, New Zealand provided

14,500 bbl/d of gasoline based on methanol production from natural gas reforming. The raw methanol

was evaporated and fed into an adiabatic DME reactor at 2.6 MPa and more than 300°C. Without any

treatment, the products were transferred into five fixed bed adiabatic reactors in parallel for

conversion to gasoline. Inlet temperatures of 320–340°C were adjusted by controlling the mixture of

unconverted and recirculated DME.

Generating high pressure steam, the product hydrocarbons, gases and water were cooled and separated

in a flash drum. The gases were recirculated, the water was post-treated and the hydrocarbons treated

further. Within two distillation columns, the light ends were removed and the remaining gasoline

fractions were handled depending on their chain length. Light gasoline was sent to an alkylation reactor

and split into propane, butane and alkylate. Heavy gasoline was purified from durene. A specific

mixture of heavy and light gasoline was sold as the final product. Figure 28 shows a flowchart of the

ExxonMobil MTG process as applied at the New Zealand plant.


8 4


Figure 28 Schematic of ExxonMobil MTG synthesis (modified by author)

In China, the Jincheng Anthracite Mining Group has taken out a licence for the Mobil process. It first

established a 2,500 bbl/d unit in 2009 and recently began operation of a commercial 25,000 bbl/d plant

in Shanxi Province (Helton and Hindman, 2014).

Lurgi developed a downstream module for gasoline synthesis as part of their process chain of

methanol-based large-scale applications (Wurzel, 2006). Methanol is converted into olefins which then

pass oligomerisation, ultimately to provide kerosene, diesel, gasoline and LPG. The overall process,

called MegaSyn®/MtSynfuels®, is in operation at the Mossel Bay plant (South Africa).

6.1.4 Efficiency and environmental performance

After the synthesis process, the gasification process has the biggest impact on overall process efficiency.

The major parameter for assessment of energetic efficiency is cold gas efficiency – the chemically

bound energy of the produced raw gas (not considering sensitive heat) related to the chemical. Other

criteria for gasification technology assessment include raw gas (syngas) yield, carbon conversion,

specific oxygen consumption and steam to oxygen ratio. All parameters are dependent on the type of

coal and the applied gasification process, as shown in Table 13.

TABLE 13 SUMMARY OF PERFORMANCE PARAMETERS FOR DIFFERENT TYPES OF COAL GASIFIERS

(GRÄBNER, 2015)

Moving bed Fluidised bed Entrained flow

(dry fed)

Entrained flow

(slurry fed)

Cold gas efficiency, % 78–86 ca 80 80–83 72–78

Carbon conversion, % 85–99.9 88–92 98–99.9 98–99.9

Specific syngas yield, m³ STP of

H2+CO per kg coal, daf

1.1–2.25 1.8–2 2.2–2.25 2.1–2.3


8 5


As for all coal liquefaction routes, water consumption is another crucial issue. The minimal water

consumption is reported as five litres of water per litre of Fischer-Tropsch product. Major uses in

indirect liquefaction plants are process water (for example, water required for provision of gasification

steam or water scrubber make-up water), steam for CO conversion, boiler feed water to recover

exothermically released heat of reaction and make-up water to compensate cooling water losses.

Significant amounts of waste water are also produced, for example, from black water treatment after

raw gas quenching, condensates or strip water from water scrubbing or CO-shift conversion, waste

water from acid gas removal and recovery, and from synthesis product purification. The waste water

is often organically loaded with hydrocarbons, has elevated ion or salt concentration and can contain

adsorbed gases. Specific water treatment processes exist dependent on the gasification process and

synthesis route.

The specific product yield of different syntheses is summarised in Table 14.

TABLE 14 SPECIFIC PRODUCT YIELDS OF DIFFERENT LIQUID SYNTHESES (MODIFIED BY AUTHOR)

Fischer-Tropsch synthesis Gasoline synthesis

LT MT HT MtG TIGAS

Feedstock Natural gas Coal Coal Methanol Biomass

Output per feedstock,

as-received

0.004 bbl/m³ (slurry reactor)

0.0055 bbl/m³ (fixed bed)

2.22 bbl/t 1.98 bbl/t 3.20 bbl/t 0.51 bbl/t

Output per syngas in

bbl per m³, STP

0.001 (slurry reactor)

0.002 (fixed bed)

0.0013 0.0018 0.0014 0.0001

SNG Indirect

DME

Direct

DME

MeOH MtG

Energetic efficiency Ca 50.4% Ca 45.1% Ca 49.7% Ca 46.0% Ca 54.2%

* based on coal conversion (Dabas, 2011; NRC, 2009)

Overall environmental process chain performance parameters are provided in Table 15.

TABLE 15 ENVIRONMENTAL PARAMETERS OF COAL LIQUEFACTION ROUTES (COUCH, 2008)

ICL with

high-temperature

FT synthesis

ICL with

low-temperature

FT synthesis

ICL with

high-methanol

ICL with DME

Energetic efficiency ~40% ~39% ~45% ~43%

Carbon emissions ~40 kg/GJ ~40 kg/GJ ~36 kg/GJ ~38 kg/GJ

The major solid waste product from gasification plants is either ash or slag, depending on the

gasification technology employed. An important issue is the immobilisation of hazardous components.

From this point of view, slagging gasifiers produce the best residues. In other cases, thermal upgrading

steps or landfilling might be required (Gräbner, 2015).


8 6


Used catalysts from the synthesis steps are another solid waste source. Metal recovery from catalysts

is needed if the materials pose a risk to the environment. In the case of metals such as platinum or

cobalt, recovery is also mandatory from an economic point of view (Maitlis and de Klerk, 2013).

6.2 DIRECT COAL LIQUEFACTION

The second and fundamentally different route to producing liquid products as oil substitutes or

chemicals from coal is direct liquefaction. The only process category developed to large industrial scale

is slurry-phase hydrogenation of coal.


Whereas almost every coal can be used for indirect liquefaction if a suitable gasification technology is

applied for syngas production, direct coal liquefaction requires rather reactive coals with high volatile

content. In addition, a high hydrogen content is advantageous. Further requirements include being able

to achieve a low moisture content of ≤1% after drying, as well as low oxygen, sulphur, nitrogen and

chlorine contents. Higher water contents cause problems with oil-water separation, requiring the use

of density phase separation or distillation. Hetero-atoms are problematic regarding the refining of the

light and middle product oils to achieve the quality requirements for transportation fuels. In contrast

to indirect liquefaction, with intermediate gas cleaning stages for the raw gas removing all catalyst

poisoning or other harmful contaminants, hetero atoms become part of the product phases during

direct conversion. They are typically removed from the products by using hydrogen and applying

similar processes and catalysts as applied to oil refining (Krzack and Schmalfeld, 2008).

Description of underlying process principle

Direct coal liquefaction relies on catalytic conversion of coal into liquid hydrocarbons as the major

product, with solid residues and gaseous side products. It is not the major coal conversion route, today,

with only one commercial plant operating in Erdos, Inner Mongolia, China. This has an annual capacity

of 1,080,000 t liquid products. It comprises a slurry-phase reactor where coal is suspended in oil, mixed

with a powdery catalyst and split into hydrocarbons, thereby consuming additionally provided

hydrogen. The reactions occurring during that conversion process are mainly exothermic. The

complex coal molecule is split into shorter and lower weight molecules of liquid hydrocarbons.

Hydrogen needs to be provided to the process to saturate split C-C bonds and to hydrogenate,

isomerise and refine the products. Common operating temperature ranges between 450°C and 500°C,

with the pressure for modern applications typically in the range 14–19 MPa.

Major influencing factors on the product yield are the catalyst, temperature, total pressure, specifics of

the oil used for suspension of the coal, residence time, partial pressures and reaction principle (slurry

or gas phase hydrogenation). Products obtained from the process include a heavy oil fraction mainly

composed of asphaltenes (molar weight of >500 kg/kmol) and a lighter fraction as the major product

fraction (~250 kg/kmol) (Krzack and Schmalfeld, 2008).

A P P E N D I X – F U N D A M E N T A L S O F C O A L C O N V E R S I O N T E C H N O L O G I E S

8 7


Significant differences compared to early technology variants are the improved separation processes

for segregation of solid residues from the liquid product phases, the staged refining of the product oil,

enabling higher oil yield and quality, and gasification of the spent catalyst with the carbon containing

residue by applying modern solids gasification technology (entrained-flow gasification) working at

high pressure (up to 4–8 MPa) to satisfy the hydrogen demand of the process (Wanzl and Schmalfeld,

2008).

Within this process, the first stage is the slurry-phase conversion where the powder-grained coal (<0.1 nm)

is mixed with a disposable catalyst and oil forming the slurry with a solids content of 40–45 wt%. The oil

serves both as a suspension agent and a means for improved exchange and transport of hydrogen. It mainly

consists of the heavier product fraction yielded during hydrogenation, which is then recycled for slurry

preparation after separation of the solids. The amount of hydrogen added to the process is in the range of

7–10 wt% compared to the input of coal on a dry- and ash-free basis. The applied catalyst must be resistant

towards sulphur and low cost because it cannot be recovered from the solid phase that also consists of

residual coal and ash. Hence it will be discharged from the process with the other solids and fed into the

gasification stage, where the residual carbon is used for hydrogen production. About 2–3% of catalyst is

mixed into the slurry compared to the input of coal on a dry- and ash-free basis. Typical catalysts for

slurry-phase hydrogenation are mixtures of iron oxides (Wanzl and Schmalfeld, 2008; Krzack and

Schmalfeld, 2008).

The second stage is the separation of light and heavy oil phases and separation of solids from the heavy

oil phase. The solids contain residual, unconverted coal, ash and the spent catalyst. Because of mixing

with the catalyst, the coal ash content should not exceed a certain limit to reduce the mineral matter

content fed into the gasifier. For example, a hard coal was mechanically separated to achieve ash

contents not higher than 5 wt%.

The third stage is the adjustment of hydrocarbon composition, for example, iso-alkanes and aromatics

content, and removal of hetero-atoms from the liquid products. This comprises gas-phase

hydrogenation and refining of the product oil, which will become gaseous if the pressure is reduced

but the temperature is kept high. The catalyst is a solid material, either arranged in a fixed bed or as

monolithic component. In contrast to the disposable, rather inexpensive, catalyst applied to the slurry-

phase stage, higher-quality catalysts are used during refining, often consisting of molybdenum or

tungsten sulphide. (Krzack and Schmalfeld, 2008).

A summary of different process developments is provided in Table 16, while a process layout of a direct

coal liquefaction plant according to the ‘Deutsche Technologie’ approach is presented in Figure 29.


8 8


Figure 29 Common process schematic of a direct coal liquefaction plant according to the ‘Deutsche

Technologie’ approach (Wanzl and Schmalfeld, 2008)


8 9


TABLE 16 SECOND GENERATION COAL LIQUEFACTION DEVELOPMENTS BASED ON THE IG PROCESS ACCORDING TO THE BERGIUS-PIER PRINCIPLE

Process IG-neu

(Wanzl and

Schmalefeld, 2008)

DT

(Deutsche

Technolgie –

German

Technology)

(Wanzl and

Schmalfeld, 2008)

DT-IGOR

(DT process +

integrated refining)

(Wanzl and

Schmalfeld, 2008)

BCL

(Brown Coal

Liquefaction)

(Li, 2004)

H-Coal

(Elliot, 1981)

EDS

(Exxon Donor

Solvent process)

(Whitehurst, 1980;

Mitchel and others,

1979)

SRC

(Berkowitz, 1994;

Elliot, 1981)

Developer Saarbergwerke AG Ruhrkohle AG und

Veba Oel AG

Ruhrkohle AG und

Veba Oel AG

Nippon BCL Ltd Hydrocarbon

Research Inc

Exxon Gulf Oil

Conditions 733 K, 30 MPa,

Fe-based catalyst

743 K, 30 MPa, red mud as slurry-phase

catalyst, Co and W-based catalysts for gas

phase section

723 K, 15 MPa,

Fe2O3-based

sulphur resistant

catalyst, lignite

733 K, 20 MPa,

Co/Mo catalyst,

various hard coals

and lignite

723 K, 17 MPa,

(no catalyst

specified), various

hard coals and

lignite

723 K, 14 MPa

(no catalyst

specified), hard coal

Maturity 6 t/d pilot plant

(1981–1986)

200 t/d pilot plant (1982–1987) 150 t/d pilot plant

(1985–1990)

600 t/d pilot plant

(1980–1982)

250 t/d pilot plant

(1980–1982)

50 t/d pilot plant

(1977–1981)

Product distribution

related to coal

input (for the

specific coals

investigated in the

respective plants)

5.3 wt% H2 input,

C1-C4 gases: 8 wt%

Coal oil: 51.7 wt%

Heavy oil residue:

21 wt%

Coal residue:

6.7 wt%

Other gases: 8 wt%

Input: 6.1 wt% for the DT process and up to

8.3 wt% for the DT-IGOR process

5.3 wt% H2 input,

C1-C4 gases:

11.7 wt%

Coal oil: 52.3 wt%

Heavy oil residue:

12.4 wt%

Other gases:

30.2 wt%

4.9 wt% H2 input,

C1-C4 gases:

0.2 wt%

Coal oil: 58.7 wt%

Heavy oil residue:

12.3 wt%

Coal residue:

10.7 wt%

Other gases:

14 wt%

4.3 wt% H2 input,

C1-C3 gases:

3 wt%

Coal oil:

38.8 (+ 11.8) wt%

Heavy oil residue:

30 wt%

Other gases:

16.4 wt%

5.2 wt% H2 input,

C1-C4 gases:

18.4 wt%

Coal oil: 48.4 wt%

Heavy oil residue:

22.4 wt%

Other gases:

11.8 wt%

Coal residue:

4.1 wt%

C1-C4 gases:

20.3 wt%

Coal oil: 48.9 wt%

Distillation residue:

21.5 wt%

Other gases:

6.5 wt%

C1-C4 gases:

23,8 wt%

Coal oil: 55.1 wt%

Distillation residue:

10.7 wt%

Other gases:

7.9 wt%


9 0


Table 16 also indicates the specific hydrogen consumption (addition of hydrogen in wt% relative to

the dry and ash free coal). The hydrogen is normally produced from unconverted coal and heavy

residues not suitable for use as suspension oil. High-purity hydrogen can be obtained by pressure swing

adsorption with the tail gas from the PSA unit being combusted for provision of heat and electricity.

Major effort has been put on the development of advanced product treatment processes. For example,

the DT – German Technology is characterised by a comprehensive refining initiated by cooling of the

reactor product (to preheat the inlet stream). The cold product stream is sent to the cold separator

where the syncrude is obtained. A warm side stream from the cooler is passed to a first refining reactor

and the heavy residue after separation is sent to the gasifier whereas the light liquids are further refined

in a second reactor and the heavier liquids from the first refining stage are recycled to the slurry-phase

for suspension of the feed coal and the catalyst. The light products are sent to the cooling stage and

recovered in the syncrude stream. Figure 30 shows an example process chain for a product treatment.

Figure 30 Example flow scheme of a direct coal liquefaction product treatment section (Wanzl and

Schmalfeld, 2008)


9 1


Efficiency and environmental performance

As noted previously, major criteria for evaluating the environmental and energetic performance

include specific product yields and energetic efficiency, CO2 emission, water consumption, emission

or handling/treatment of gaseous, solid and liquid pollutants. A comprehensive review of performance

data and comparison of different coal liquefaction routes was performed by Couch (2008).

The energetic efficiency of direct coal liquefaction is some 57–58%, with significantly lower carbon

emissions reported compared to indirect liquefaction routes. Total carbon emissions including CO2

and other minor carbon losses along the process chain (for example, residual carbon in the slag or with

purge gases) are reported at 23–25 kg/GJ product. An important parameter is the specific water

consumption. For direct liquefaction, the vast majority of the fresh water (about 70%) is used as make-

up for losses from cooling towers. About 8% can be assigned to boiler feed water while the remainder

is mainly used as process water for providing the hydrogen by gasification and gas conditioning. The

minimum consumption for a subbituminous coal is about 6.1 litres of water per litre of oil product.

Other process emissions like waste water, off-gases etc can be controlled by application of suitable

environmental technologies.

The synthetic fuel has superior combustion and emissions characteristics compared to conventional

oil-based fuels.

6.3 COAL TO SYNTHETIC NATURAL GAS

6.3.1 Description of underlying process principle

In principle, the preferred gasification process for the production of methane (that is synthetic natural

gas, SNG) is fixed bed gasification because of the high methane yield already obtained from the syngas

exiting the gasifier. That said, the use of entrained flow systems is also favoured because of other

process advantages. The synthesis unit itself consists of three to four sequentially aligned adiabatically

operated reactors. The operating pressure depends on the pipeline pressure after synthesis and

typically ranges between 3 and 5 MPa. The reactors are filled with nickel-based catalysts with the

nickel content varying by reactor dependent on the maximum temperature of some 973 K (about 45%

for the 1st reactor and up to 55% for subsequent reactor stages).

CO + 3 H2 ↔ CH4 + H2O -220 kJ/kmol (700 K) (22)

CO2 + 4 H2 ↔ CH4 + 2 H2O -183 kJ/kmol (700 K) (23)

The temperature decreases with each reactor because of the lower amount of syngas to be converted

within each one. The maximum reactor temperature can be limited by the steam or methane content

of the feed gas or by recycling partially unconverted syngas into the first reactor.


9 2


The current established synthesis technology variants are provided by Lurgi and Haldor Topsøe, as

shown in Figure 31. Both are characterised by 95–98% methane yield and highly integrated heat

recovery systems since some 20% of the chemical heat of the syngas is released as sensitive heat by

the exothermic reactions. High standards are required for the reactor material and the heat exchanger

piping material because of the potential threat of metal dusting in a hydrogen-rich gas atmosphere

between 770 and 1170 K.

Figure 31 Comparison of Lurgi and Haldor Topsøe SNG synthesis (Haldor Topsøe, 2015; Weiss and

others, 2008)


The coal quality requirements for pre-treatment (milling and drying) of coal are strongly determined

by the gasification process providing the syngas, which are based on entrained flow and fixed bed

systems. Advantages of entrained-flow gasification with respect to SNG production include high single

unit raw gas capacity and lower impact for waste water treatment. In particular, the high single unit


9 3


capacity is advantageous considering the need for large amounts of syngas for commercial-scale SNG

plants. In contrast, fixed bed gasification features lower single unit capacity and much higher impact

for waste water treatment, especially for recovery of tar compounds. However, it provides a raw gas

that is significantly better suited for SNG synthesis. The reasons for this are a thermodynamically

implied much higher methane content of the raw gas and a higher H2/CO ratio reducing the need for

CO conversion during gas purification. The significantly higher methane content of the raw gas allows

for simplification of the synthesis loop as the temperature increase occurring in the first reactor is

reduced, eliminating the need for partial recirculation of the gas exiting the first reactor for cooling

purposes. The increased methane content also results in a reduced overall size of the synthesis unit as

less syngas needs to be catalytically converted to methane.

At present, the technology is far from established in China (see main text) and it remains to be seen

whether fixed bed gasification will prove to be the commercial preference, which will ultimately

depend on whether it can meet the stringent environmental constraints.

6.3.3 Efficiency and environmental performance

As inferred above, whereas the efficiency of the gasification island is the same as for typical indirect

coal liquefaction routes, the effort for gas purification differs depending on the gasification process

and the specific synthesis. Generally, the energetic losses of the gas purification process chain increase

with increasing amounts of CO to be converted for H2 enrichment. A major influence on the overall

process chain efficiency can be attributed to the synthesis block. Because of the highly exothermic

heat release during methanation, the efficiency strongly depends on the efficiency of heat recovery

and heat integration. For conventional Lurgi-type or Haldor Topsøe’s TREMP™ processes, there is a

need for maximum heat recovery as approximately 20% of the chemical heat inventory is released as

sensitive heat during reaction. The majority of commercial plants apply high-pressure steam

generation with superheating of the generated steam. This makes it possible to recover up to 93% of

the released heat. Because of the large amount of heat and consequently generated steam, an efficient

use of the steam, that is for electricity generation, needs to be ensured as the steam generation typically

exceeds steam consumption along the process chain (Haldor Topsøe, 2015; Foster Wheeler, 2015).

6.3.4 Technical maturity and industrial applications

The main text of this report notes that the current market for CTSNG plants is in China, although very

few are as yet in commercial operation due to various technical/environmental, regulatory and

management reasons. Consequently, most projects remain at the early stage of development.

6.4 COAL CONVERSION BY-PRODUCTS (TARS)

6.4.1 Origin of coal conversion by-products

These by-products that represent a source for fuels production comprise the direct hydrogenation of

coal, the synthesis of liquid hydrocarbons from coal-derived syngas, and tars obtained from


9 4


carbonisation or moving-bed gasifiers. Tar originating from carbonisation can be obtained as the major

product either in the case of coal pyrolysis or as a by-product of coke production from coal. Coal from

moving-bed gasifiers, which is recovered from a tar-oil-dust-water mixture from the gas cooling

process, represents a by-product. The composition and yield of tar and oil hydrocarbons depend

strongly on the feedstock properties and process characteristics. Generally, the tar yield is reduced

with increasing coal rank and elevated operating temperature.

Tar from moving-bed gasification processes

Multiple hydrocarbon streams of different quality can be collected from the gasification process during

the gas cooling and water scrubbing of the raw gas exiting the moving bed gasifier (Gräbner, 2015).

Because of the counter-current flow regime, between 15% and 25% of the original coal heating value

can be bound in the hydrocarbons. Dependent on their density, solubility in water and pollution with

solids, the hydrocarbon phases include oil (characterised by a density lower than water), gas liquor

(mixture of water and dissolved hydrocarbons, for example, phenols, ammonia and organic acids) and

dust-containing or dust-free tar (heavy hydrocarbons with a density higher than water). Besides these

three hydrocarbon species being collected in the wash cooler, very light non-condensed hydrocarbons

referred to as naphtha can be recovered during downstream low-temperature acid gas removal.

The different hydrocarbon phases are commonly recovered by a multi-stage process separating first

dusty and clear tar and oil from the gas liquor before recovering phenol and separating acidic gases

(for example, CO2, H2S, HCN) before reclaiming ammonia and other organics from the waste water

stream that needs final sewage water treatment.

As an example, the hydrocarbon phases from a lignite fuelled moving bed gasifier include tar/oil with

about 84% carbon, up to 10% hydrogen, up to 5% oxygen and up to 0.5% sulphur. The major

compounds are BTX aromatics and to a lesser extent phenols and cresols. Only minor amounts of

nitrogen or amine group-containing hydrocarbons are contained in that phase. In contrast, naphtha

and crude phenol are mainly carbon and hydrogen, with the naphtha consisting of aromatic

hydrocarbons and aliphatic hydrocarbons.

Hydrocarbons from carbonisation

The tar quality from coal pyrolysis for liquids or coke production differs with coal rank and pyrolysis

carbonisation temperature. Up to 25% hydrocarbon yield (referred to as total product yield) can be

expected for low-temperature (below 700°C) carbonisation compared to 8% for high-temperature

carbonisation. The ratio of heavy tar hydrocarbons to liquor is approximately 0.6:1 for low

temperature processes while it increases for high-temperature carbonisation to about 1:1 to 1.5:1. Both

processes also yield minor amounts of light oils (naphtha).

In 2014, close to 1 billion tonnes of coal was used for coke production in the top ten coking coal

producing countries worldwide, with 54% of that production occurring in China, resulting in close to


9 5


25 million tonnes of tar. In addition, over 4 million tonnes was produced under medium temperature

conditions as found in moving-bed gasification units.

6.4.2 Tar upgrading technologies

There are specific processes and applications that use dedicated hydrocarbons or chemical compounds

extracted from coal tar or gas liquor to produce fine chemicals. However, the major fraction of the

coal tar is processed to either produce fuel oil for industrial furnaces or blended with other

hydrocarbons to provide transportation fuels. Conventional blending results in comparatively low

added value; consequently, recent utilisation routes for these coal-based tars and gas liquors often

include a hydrogenation process to increase the quality of the hydrocarbon product by reducing

potential emissions for fuel applications.

An alternative to refining processes is the gasification of the coal tar which is currently applied at the

Sokolovska Uhelna integrated gasification combined cycle plant located in Vresova in the Czech

Republic. This uses a Siemens gasifier to convert the coal tar produced by a number of fixed bed

gasifiers into a fuel gas which is provided to the power block of the plant.

Besides recovering selected chemicals, hydrorefining and hydrocracking are frequently used to

convert the tar into valuable products. The former aims for removal of sulphur, oxygen, nitrogen and

other hetero atoms to improve the quality by hydrating unsaturated hydrocarbons. In contrast the

latter aims for conversion of heavy hydrocarbons into lighter fractions with adjustment of the

hydrocarbon range (for example, n-/cyclo-/iso-alkanes, aromatics) by cracking and saturation of

bonds using hydrogen.

Many of those technologies are commercially applied in China including coal tar hydrorefining, coal

tar fixed bed hydrocracking, coal tar delayed coking-hydrogenation, fluidised bed hydrogenation and

homogeneous phase slurry-bed hydrocracking technology. In addition, there is heterogeneous phase

slurry-bed hydrocracking, based on principles developed for direct coal liquefaction (BRICC, 2014).

Some information about the indicated processes is summarised in Table 17.


9 6


TABLE 17 TAR TREATMENT PROCESSES (BRICC, 2014)

Process sequence Remarks Commercial application

example

Coal tar

hydrorefining

1 Pretreatment of coal tar

2 Distillative separation of

asphalt and light fraction

(Tboil) <350°C

3 Hydrorefining using of the

light fraction using external

hydrogen to obtain naphtha

and diesel

Widely applied simple

process flow scheme

Demanding

pretreatment and

limited yield of naphtha

and diesel

Harbin Coal Gasification

Plant

Coal tar fixed bed

hydrocracking

technology

1 Pretreatment of coal tar

2 Distillation to obtain high

temperature asphalt (Tboil

>500°C)

3 Hydrorefining (using

external hydrogen) of the

<500°C fraction to obtain a

naphtha and diesel cut

4 Processing of the heavy cut

from hydrorefining by a

hydrocracker (using external

hydrogen) to maximise

naphtha and diesel yield

More complex process

scheme compared to

simple hydrorefining

Increased naphtha and

diesel yield by reduced

amount of asphalt

Higher light oil yield and

increased lights quality

Currently limited

operating time without

catalyst regeneration

Baotailong Coal Chemical

Co Ltd

Inner Mongolia Qinghua

Group

Coal tar delayed

coking

hydrogenation

technology

1 Same process layout like coal

tar fixed bed hydrocracking

but replacement of step 2

(distillation) by delayed

coking unit → production of

petcoke instead of asphalt

2 Recirculation of coker gas oil

into the pretreated tar

stream

High overall tar

conversion to valuable

products

Recovery of 10–20% of

tar as petcoke →

reducing light oil yield

Tianyuan Chemical Industry

Co Ltd

The abovementioned technologies have limitations regarding applicability to heavy tars and light

products yield; heterogeneous coal tar hydrogenation technology (derived from coal hydrogenation

applications) is promising for the processing of a wide range of tar qualities at reduced coking and

catalyst deactivation at simultaneously high yield of light oil fractions. Two technologies are currently

commercially offered, namely Veba™ Combined Cracking (VCC) by KBR and the BRICC technology

by the China Coal Research Institute.

The Veba™ process schematic is shown in Figure 32. Typical operating conditions are

21–23 MPa and 460–480°C. The technology is characterised by using a doped natural mineral catalyst

with little coking activity.


9 7


Figure 32 Schematic of the VCC heterogeneous slurry-bed hydrogenation process (BRICC, 2014)

The BRICC technology for heterogeneous phase slurry-bed hydrocracking technology represents a

further development of the direct coal liquefaction technology demonstrated at the 1,000,000 t/y coal

liquefaction plant located in Ordos, Inner Mongolia, China. The technology dates back to 1979 and has

been commercialised since 2011. Several process layouts were developed accounting for differences

in the treatment of high-temperature and low-temperature coal tar. Schematics of the different process

layouts are provided in Figure 33. For higher value-creation, the phenol extraction stage for low and

medium-temperature tar processing can be extended to recover chemicals like naphthalene.

The first step is independent from tar quality and includes preparation of the tar slurry by mixing the

raw tar with hydrocracking catalyst, sulphur and heavy oil recycled from downstream process units at

a temperature range between 80°C and 200°C. Slurry bed hydrocracking of the raw tar and heavy oil

compounds is performed at about 320–470°C and 12–19 MPa. Operated at a LHSV of 0.3–3 per hour

the process uses 500–1000 g of hydrogen per litre of oil with about 0.1–4% of catalyst in the slurry.

Light oil upgrading by fixed bed hydrorefining aims for the provision of naphtha, jet fuel, diesel, phenol

and fine chemicals like ink solvents. The product ratio can be adjusted according to market

requirements. The naphtha cut can be further converted to gasoline by catalytic reforming, allowing

for additional aromatics extraction. Heterogeneous phase slurry-bed hydrogenation is characterised

by very high conversion rates of heavy tars, in particular close to 100% conversion of asphalt, resulting

in an increased light products yield. Some 78–85% can be recovered as light oil compounds from high-

temperature tar, while for low or medium-temperature tar the number is 87–94%. The process is

commercially marketed by the China Coal Research Institute and Luoyang Engineering Corporation

of Sinopec. The first commercial application is a 500,000 t/y tar upgrading project for the Quinghua

company.


9 8


Figure 33 Schematics of the BRICC process for treatment of low and high-temperature tars

(BRICC, 2014)

6.4.3 Technical maturity and industrial applications

Most of the described processes are adapted from the petrochemical industry and thus are considered

to be technologically mature.

A P P E N D I X R E F E R E N C E S

9 9


7 A P P E N D I X R E F E R E N C E S

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DEVELOPMENT AND DEPLOYMENT OF FUTURE FUELS FROM COAL

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