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
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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).
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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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
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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).
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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).
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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.
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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.
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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
– 4.0 – Approved
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TABLE 3 – CONTINUED
Suxin Energy Tacheng
Xinjiang
– 4.0 – Under development
Huadian Hunlunbuir
Inner Mongolia
– 4.0 – Approved
Xinmeng Energy Erdos, Inner
Mongolia
– 4.0 – Under development
Beijing Enterprises Erdos, Inner
Mongolia
– 4.0 – Under development
China Coal Changii
Xinjiang
– 4.0 – Approved
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
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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
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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
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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
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(~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
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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)
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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).
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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
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(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%
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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.
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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.
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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.
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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
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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.
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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
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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.
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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
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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
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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).
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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
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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
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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
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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.
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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
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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
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(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.
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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).
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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).
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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.
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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.
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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
Gasification (max 1400 t/d coal)
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
Gasification (max 1000 t/d coal)
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
Gasification (max 2400 t/d coal)
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
Gasification (max 600 t/d coal)
163 2011
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TABLE 8 – CONTINUED
Plant in China Gasification technology and coal feed
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
Gasification (max 800 t/d coal)
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
Gasification (max 500 t/d coal)
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
Gasification (max 1200 t/d coal)
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
Gasification (max 2400 t/d coal)
560 2010
Xinao Methanol 2 (+1) GE (max 3400 t/d coal) 625 2011
Xinsheng Methanol 2(+1) Multi Component Slurry
Gasification (max 1200 t/d coal)
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
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TABLE 8 – CONTINUED
Plant in China Gasification technology and coal feed
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
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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
Gasification (max 2400 t/d coal)
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)
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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)
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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
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TABLE 11 – CONTINUED
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.
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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
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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.
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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
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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).
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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.
6.2.1 Suitable feedstock range
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).
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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.
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Figure 29 Common process schematic of a direct coal liquefaction plant according to the ‘Deutsche
Technologie’ approach (Wanzl and Schmalfeld, 2008)
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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%
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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)
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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.
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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)
6.3.2 Suitable feedstock range
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
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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
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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
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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.
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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.
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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.
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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.
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7 A P P E N D I X R E F E R E N C E S
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