How-to, Tips and Articles: Development Status of Coal to Future Fuels

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.

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.

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

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.

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).

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.

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).

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.

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).

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 longterm, 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).

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).

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. 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).

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.

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.

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 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 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.

The 10 largest coal producers and exporters in the Indonesia:

Source: IEA Clean Coal Centre

Friday, July 19, 2019

Development Status of Coal to Future Fuels

Total Pageviews