Oil shale is a petroleum-source rock, containing sufficient organic matter to make its utilisation feasible and under certain conditions financially worthwhile. In comparison with other fuels, it is regarded as a low-grade fuel with high ash and sulphur contents. Like coal, the world’s known reserves of oil shale are vast, being many times greater than the proven remaining resources of crude oil and natural gas combined. The conversion of solid fuels (e.g. coal, biomass or oil shale) to cleaner-burning and more user-friendly synthetic liquid or gaseous fuels is becoming more desirable. For example, ICGCC, which involves two-stages of combustion, with a clean-up facility between the stages, is being employed in several countries, because of the lower costs, improved reliabilities and efficiency advantages thereby achieved relative to those of traditional power systems. Hence lower unit costs of electricity generation ensue. It is also environmentally more acceptable (e.g. less polluting) when having to use poor-quality fuels, including petroleum coke and waste products.

There are two main designs of oil shale fired power systems. The first is based on the conventional steam turbine, and the second on the gas-turbine combined-cycle power plant. The efficiency of the first option is approximately similar to that achievable with coal-fired plants. But the thermal efficiency, at maximum, could be increased significantly (i.e. from 40 to 49(±1)% compared with 55(±4)% for natural-gas) when a combined-cycle arrangement is used. Improving the overall conversion-efficiency of a system reduces both the rates of fuel consumption as well as the rates of emission of pollutants, which are associated with the generation of a specific-power output. It also has the advantage of incurring less-severe adverse environmental-impacts along the fuel-supply chain (i.e. including mining, preparation, handling as well as transportation of the shale). In addition, one of the main advantages of using GT power systems is their ability to operate using a wide range of different fuels.

Currently, the mined oil shale is either retorted in order to produce liquid fuels (i.e. shale oil) and synthetic gases, or burnt in pulverised fuel or fluidised-bed boilers for electric-power generation and/or industrial purposes. Also, preliminary investigations using supercritical solvent extraction or bio-leaching to recover the shale oil are promising, but they are still in their early stages of development.

A combination of electricity generation and synthetic-fuel production, simultaneously in parallel, from oil shale is expected to improve the prospects for harnessing oil shale deposits in a more economic way. This new approach, namely using “OSITGS”— which involves the use of the following components:

1. A CFBC and a steam turbine.

2. A CCGT.

3. An indirectly-heated retort, for producing shale oil and an MCV fuel-gas. The latter can be employed, on site, to generate further electricity or for the production of synthetic gases and chemical feed-stock materials (e.g. ammonia, methanol and acetic acid). Also, it could be transported in order to be substituted directly for natural gas and/or fuel oil in large industrial plants.

4. A directly-heated gasifier, producing LCV fuel-gas, which is used to fuel a CCGT.

The integration of these processes (so that the waste output of one can serve as the useful input to another) can increase significantly the overall conversion efficiency of oil shale into immediately useful end-products compared with existing processes. This would reduce the cost of the generated electricity (as the main usefully preferred end-product) compared with what can be achieved with conventional technologies. In addition, lower rates of polluting emissions per unit of useful end-products would be released to the environment.

The primary aim of oil-shale gasification is to increase the calorific value per unit mass of the resulting fuel: this is achieved by removing unwanted constituents such as ash, thereby producing a gaseous fuel, which is easier and cheaper to transport and handle. Oil-shale gasification is a relatively simple process requiring the extraction of the volatile contents of the shale through pyrolysis, followed by the partial combustion of the remaining char. This chain of reactions produces a fuel gas, whose composition is dominated by carbon monoxide (CO) and hydrogen (H₂). Also, it contains carbon dioxide (CO₂), nitrogen (N₂) as well as small amounts of methane (CH₄), hydrogen sulphide (H₂S) and carbonyl sulphide (COS). Because the gasifier operates at relatively-high temperatures in a reducing atmosphere, there will be neither oxides of sulphur nor of nitrogen in the end-product gas. The exact composition and the production rate of this gas are affected by the gasification temperature (because, as the temperature is increased, the release rates of CO and H₂, as well as of the fuel gas per unit mass of the raw shale rise) and the char’s residence-time.

In the proposed system, an air-blown, pressurised or atmospheric, fluidised-bed gasifier would be used as in the ICGCC. For atmospheric gasifiers, the fuel gas should be compressed up to a pre-selected pressure (i.e. slightly higher than the combustor’s pressure) before being injected into the combustion chamber: this adversely affects the cycle’s thermal efficiency because of the higher temperatures at the inlet of the fuel compressor. Gasification processes, operating on coal, generally have a conversion efficiency of 85%. But, in the case of oil shale, due to its high ash-content, only about 60 (±5)% is likely to be achieved. Raw crushed oil-shale is fed to the gasifier, where it is pyrolysed and carbonised, so producing a LCV fuel gas and char; the latter being circulated to the CFBC. The raw fuel-gas from the gasifier undergoes an initial stage of cleaning in a cyclone or high-temperature filter to remove particulates. Then it is cooled, via a heat exchanger (from which the extracted heat is used to raise more steam for feeding the steam cycle and other uses within the plant) at least to a temperature (between 400 and 600°C), where the alkali metals (such as potassium and sodium compounds), which can cause severe, high temperature corrosion, would condense and be removed from the fuel gas in order to avoid damaging the gas-turbine. This is followed by the sulphur removal-and-recovery system, where up to 99% of the sulphur compounds (e.g. H₂S) can be extracted and converted to elemental sulphur, possibly for sale as a by-product. It is inherently easier to remove the H₂S from a small stream at high pressure than it is to extract sulphur dioxide (SO₂) from an exhaust stream, at a far higher volumetric rate of flow and at nearly atmospheric pressure. The sulphur content of the fuel gas has little or no impact on the GT, but sulphur oxides (produced as a result of combustion of the fuel gas) would lead to corrosion of the down-stream equipment (e.g. the waste-heat recovery unit and steam generator). Finally, the clean fuel-gas is burnt in an advanced gas-turbine combustor. The resulting hot combustion products are passed to the turbine expander, thereby driving both the compressor and an electric-power generator. The heat from the high-temperature exhaust gases (after passing through the duct burner, which is used to raise the temperature of the hot gases to the required level) is recovered by a waste-heat boiler, which will produce steam that can be used to drive a steam turbine. Alternatively, burning such a low-grade fuel gas in an external combustion chamber with a GT inlet temperature of 1250°C at a pressure ratio of 10, is capable of achieving plant heat rates of about 7.8(±0.1)×10³ kJ/kWh at relatively low capital costs.