Coal To Liquids (CTL) processes can convert coal to a range of fuels from methane through to the heavy distillates and beyond to waxes. There are three separate processes. Direct liquefaction of coal (Bergius process) and indirect liquefaction (Fischer-Tropsch process) were developed in Germany in the 1920s. The methanol to gasoline process (MTG) was developed by Mobil in the 1970s.
In direct liquefaction, hydrogen atoms are forced into the structure of coal molecules under pressure and temperature and in the presence of a catalyst. Wandoan coals in Queensland are likely to be good feedstocks for direct liquefaction because they start with a high hydrogen content. The hydrogen for the process is generated by steam shifting carbon monoxide to hydrogen and water.
Direct liquefaction plants tend to be complicated with a high capital cost. Only one modern plant has been built. This was by the Chinese coal mining company Shenhua in the Ordos Basin. After that plant, Shenhua has gone on to build Fischer-Tropsch (FT) plants.
In an FT plant, coal is burnt in pure oxygen to produce a synthesis gas of carbon monoxide and hydrogen. The synthesis gas is then passed over a catalyst. Different catalysts will produced different suites of products. For example, an iron catalyst at a relatively low temperature will produce a high proportion of heavy waxes which in turn will need to be hydrotreated to produce lighter molecules in the jet fuel and diesel range. This last step points to a minimum scale of operation which may be of the order of 50,000 barrels per day.
There is one problem with the products from the FT process. The molecules in the diesel range that it produces have a specific gravity of about 0.76 while having a very good cetane number. The Australian specification for diesel is a specific gravity in the range of 0.82 to 0.85. Because of their zero sulphur, FT diesels will also require the addition of a lubricity agent though low sulphur diesels from crude oil also require that. The FT process also produces every molecule down to methane including LPGs and petrol.
In the MTG route, the synthesis gas is passed through a zeolite catalyst. The pores in the catalyst limit the size of the molecules to having ten carbon atoms. Thus the MTG route cannot produce diesel and jet fuel. It does make a product though that is exactly on specification for petrol. The MTG route has a lower capital cost than the FT route and is simpler and cheaper to operate. Because the product from the catalyst is at the retail specification, no further refining steps are needed and there is no minimum scale imposed by a refining step. The product yield by process route is shown following:
Thus for an autarkic transport fuel system, FT-based plants will provide the requirement for diesel and jet fuel and MTG plants, which could be more regionally distributed, would provide the balance of the petrol requirement.
Figure 1: FT Process Route Outline
CTL were adopted in Germany in the 1930s and in South Africa in the 1950s. The US built a large coal to synthetic natural gas (SNG) plant in North Dakota in 1984 in response to the second oil shock. This was instead of a CTL plant due to distortion of the natural gas market by a federal act on the pricing of interstate trade in natural gas.
There has been a new burst of activity in China in the last ten years, including 20 coal conversion projects in 2013. Chinese CTL production will rise to 1.1 million barrels per day by 2020, requiring 180 million tonnes of coal per annum. China also has 20 SNG projects in train which will require a further 200 million tonnes of coal per annum.
Rocks will burn in pure oxygen down to a carbon content of 10%. Thus low grade coals which aren’t worth transporting can be used for CTL feedstock. High quality coals can produce up to 2.2 barrels per tonne. Lignite, which is 60% water, can produce 0.6 barrels per tonne. The lignite resources of the Latrobe Valley would produce 60 billion barrels and this is the natural fate of that resource.
The capital cost of CTL processes is about $150,000 per daily barrel of capacity which equates to about $400 per annual barrel of capacity. The relationship between feedstock price and operating cost is shown in Figure 10 following:
Figure 2: CTL Feedstock Cost/Operating Cost
In Figure 2 above, the retail price assumes an oil price of US$100 per barrel and includes the fuel excise levy of $0.386 per litre. Coal at $46 per tonne will provide a 10% IRR at A$75 per barrel of diesel.
The FT route can produce a syncrude similar to Arabian light crude as per Figure 3 following. This means that FT syncrude will have a high yield to finished product if used to feed refineries set up to light crudes.
Figure 3: Product Yield Relative To Carbon Number For Three FT Catalysts
Each state has its own fuel market characteristics and the optimum plant configuration for each state can be determined, as outlined following:
Queensland has combined diesel and jet fuel consumption of 130,000 bpd. This requires FT syncrude production of 195,000 bpd. That would produce 35,000 bpd of petrol as a co-product.
The balance of unmet petrol demand of 35,000 bpd would be met from MTG plants. Half of FT syncrude could go to the Lytton refinery. The other FT plant required could be in Central Queensland.
New South Wales has combined diesel and jet fuel consumption of 134,000 bpd. This requires FT syncrude production of 201,000 bpd. That would produce 36,000 bpd of petrol as a co-product.
The balance of unmet petrol demand of 70,000 bpd would be from MTG plants. Given that NSW has no refineries, two FT plants of 100,000 bpd each in the Hunter Valley would be in the centre of mass of NSW consumption. At 10,000 bpd each, there could be seven regionally distributed MTG plants.
Current Victorian refining capacity exceeds consumption by 50,000 bpd. There is no guarantee that either refinery will remain open. Victorian oil and condensate production is about 30,000 bpd.
Combined diesel and jet fuel consumption in Victoria is 76,000 bpd. This requires FT syncrude production of 100,000 bpd. This would leave unmet petrol demand of 60,000 bpd.
Lignites from the Latrobe Valley could produce 60 billion barrels of synthetic fuels and the Latrobe Valley would be an ideal location for synthetic fuel production.
Tasmania is too small a market for diesel and jet fuel production in the state. The market could support petrol production in the range of 5,000 to 10,000 bpd.
Forestry waste and biomass of 3 mtpa could produce 5,000 bpd of petrol.
Diesel and jet fuel consumption in South Australia totals 31,000 bpd. This would require FT syncrude production of 47,000 bpd. That would produce 8,400 bpd of co-product petrol.
That would leave 14,000 bpd of petrol demand that would be met by MTG plants.
The West Australian fuel market equates to the size of the Kwinana refinery though some demand in the north of the state is met by barge from Singapore.
Western Australia has oil and condensate production centred 1,400 km north of Kwinana. The state could take of the order of 50,000 barrels per day of FT syncrude to supplement domestic oil production.
The capital costs and jobs created by state are summarized in the table following:
The total capex required is about $110 billion with the creation of about 30,000 jobs in the industry. The capital cost is twice what the three LNG plants built on Curtis Island cost but spread around the country instead of being concentrated on a strip a few kilometres long. But that illustrates that the task is well within Australia’s ability.
Coal production to feed these plants would raise Australia’s coal production by 50% and create 27,000 jobs directly and 70,000 indirectly.
That said, the inherent price volatility of the liquid fuels market means that support at all levels of government is needed to develop this nascent industry that is so vital to Australia’s security and economy. The fuel excise levy can provide a mechanism. What is proposed is that the Federal Government pass through the fuel excise levy to the CTL producer until the capital cost of the plant is paid back.
How that would work is shown in Figure 4 following:
Figure 4: Mechanism For Using The Fuel Excise Levy To Accelerate Plant Payback
Under this mechanism, the Federal Government would pass through the fuel excise levy to the CTL producer until plant payback for the investors was achieved. The exercise illustrated above is at an oil price of US$100 per barrel and an operating cost of $70 per barrel. In effect, a $300 million front end investment by the Federal Government results in $200 million per annum of corporate tax paid to the Federal Government, apart from all the other taxes generated to government including GST and payroll taxes.
Under this mechanism, the Federal Government does not have to pick winners. It a plant can’t make product, it doesn’t soak up funds. The funding comes at the critical point when the operators are commissioning and taking production to nameplate capacity.
There has been a recent burst of coal conversion activity in China, with 20 coal conversion projects approved by 2013. CTL production will rise to near 1.0 million barrels per day by 2020, requiring 180 million tonnes of coal per annum. This is just about what Australia needs. China also has 20 coal-to-methane projects in train which will require a further 200 million tonnes of coal per annum. In total that amount is about what Australia mines each year. A recent list of Chinese CTL projects has been compiled by Oxford Energy:
This list totals 783,000 barrels per day. It is not complete because at least one project missing is the 25,000 barrel per day Jincheng coal-to-petrol facility. There may be more. The point from all this Chinese activity is that Australia need not be tentative relying upon CTL to solve our liquid fuel security problem. The technology has been proven and re-proven.
The other thing that China is doing to improve its liquid fuel security is stockpiling oil. At one point in 2014, it was estimated that China was putting 1.4 million barrels per day into storage. Recent reports have stated that China has filled its 700 million barrel strategic petroleum reserve.