| Underground coal gasification | |
|---|---|
| Process type | chemical |
| Industrial sector(s) | oil and gas industry coal industry |
| Feedstock | coal |
| Product(s) | coal gas |
| Leading companies | Linc Energy Cougar Energy |
| Main facilities | Angren Power Station (Uzbekistan) Majuba Power Station (South Africa) Chinchilla Demonstration Facility (Australia) |
| Inventor | Carl Wilhelm Siemens |
| Year of invention | 1868 |
| Developer(s) | Ergo Exergy Technologies Skochinsky Institute of Mining |
Underground coal gasification (UCG) is an industrial process, which converts coal into product gas. UCG is an in-situ gasification process carried out in non-mined coal seams using injection of oxidants, and bringing the product gas to surface through production wells drilled from the surface. The product gas could to be used as a chemical feedstock or as fuel for power generation. The technique can be applied to resources that are otherwise unprofitable or technically complicated to extract by traditional mining methods, and it also offers an alternative to conventional coal mining methods for some resources.
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The earliest recorded mention of the idea of underground coal gasification was in to 1868, when Sir William Siemens in his address to the Chemical Society of London suggested the underground gasification of waste and slack coal in the mine.[1][2] Russian chemist Dmitri Mendeleyev further developed Siemens' idea over the next couple of decades.[2][3] In 1909–1910, American, Canadian, and British patents were granted to American engineer Anson G. Betts for "a method of using unmined coal".[2][3] The first experimental work on UCG was planned to start in 1912 in Durham, the United Kingdom, under the leadership of Nobel Prize winner Sir William Ramsay. However, he was unable to commence the UCG field work before the beginning of the World War I, and the project was abandoned.[2][3]
In 1913, Ramsay's work was noticed by Russian exile Vladimir Lenin who wrote in the newspaper Pravda an article "Great Victory of Technology" promising to liberate workers from the hazardous work in the mines by underground coal gasification.[2][3][4] Between 1928 and 1939, underground tests were conducted in the Soviet Union by the state-owned organization Podzemgaz.[4] The first test using the chamber method started on 3 March 1933 in the Moscow coal basin at Krutova mine. This test and several following tests failed. The first successful test was conducted on 24 April 1934 in Lysychansk, Donetsk Basin by the Donetsk Institute of Coal Chemistry. The first pilot-scale process started 8 February 1935 in Horlivka, Donetsk Basin. Production gradually increased, and, in 1937–1938, the a local chemical plant began using the produced gas. In 1940, experimental plants were built in Lysychansk and Tula.[3] After the World War II, the Soviet activities culminated in the operation of five industrial-scale UCG plants in the early the 1960s. However, Soviet activities subsequently declined due to the discovery of extensive natural gas resources. In 1964, the Soviet program was downgraded.[3] As of 2004[update] only Angren site in Uzbekistan and Yuzhno-Abinsk site in Russia continued operations.[5]
After World War II, the shortage in energy and the diffusion of the Soviets' results provoked new interest in Western Europe and the United States. In the United States, tests were conducted in 1947–1960 in Gorgas, Alabama. From 1973–1989, an extensive test was carried out. The United States Department of Energy and several large oil and gas companies conducted several tests. Lawrence Livermore National Laboratory conducted three tests in 1976–1979 at the Hoe Creek test site in Campbell County, Wyoming.[2][3] In cooperation with Sandia National Laboratories and Radian Corporation, Livermore conducted experiments in 1981–1982 at the WIDCO Mine near Centralia, Washington.[2] In 1979–1981, an underground gasification of steeply dipping seams was demonstrated near Rawlins, Wyoming. The program culminated in the Rocky Mountain trial in 1986–1988 near Hanna, Wyoming.[3][5]
In Europe, the stream method was tested at Bois-la-Dame, Belgium, in 1948 and in Jerada, Morocco, in 1949.[5] The borehole method was tested at Newman Spinney and Bayton, United Kingdom, in 1949–1950. A few years later, a first attempt was made to develop a commercial pilot plan, the P5 Trial, at Newman Spinney in 1958–1959.[3][5] During the 1960s, European work stopped, due to an abundance of energy and low oil prices, but recommenced in the 1980s. Field tests were conducted in 1981 at Bruay-en-Artois and in 1983–1984 at La Haute Deule, France, in 1982–1985 at Thulin, Belgium, and in 1992–1999 the El Tremedal site, Province of Teruel, Spain.[2] In 1988, the Commission of the European Communities and six European countries formed a European Working Group.[5]
In New Zealand, a small scale trial was operated in 1994 in the Huntly Coal Basin. In Australia, tests were conducted starting in 1999.[5] China has operated the largest program since the late 1980s, including 16 trials.[2][6]
Underground coal gasification converts coal to gas while still in the coal seam (in-situ). Gas is produced and extracted through wells drilled into the unmined coal–seam. Injection wells are used to supply the oxidants (air, oxygen, or steam) to ignite and fuel the underground combustion process. Separate production wells are used to bring the product gas to surface.[5][7] The high pressure combustion is conducted at temperature of 700–900 °C (1290–1650 °F), but it may reach up to 1,500 °C (2,730 °F).[2][5] The process decomposes coal and generates carbon dioxide (CO2), hydrogen (ḥ), carbon monoxide (CO), methane (CH4). In addition, there are small quantities of various contaminants including sulfur oxides (SOx), mono-nitrogen oxides (NOx), and hydrogen sulfide(H2S).[5] As the coal face burns and the immediate area is depleted, the oxidants injected are controlled by the operator.[2]
There are a variety of designs for underground coal gasification, all of which are designed to provide a means of injecting oxidant and possibly steam into the reaction zone, and also to provide a path for production gases to flow in a controlled manner to surface. As coal varies considerably in its resistance to flow, depending on its age, composition and geological history, the natural permeability of the coal to transport the gas is generally not adequate. For high pressure break-up of the coal, hydro-fracturing, electric-linkage, and reverse combustion may be used in varying degrees.[2][7]
The simplest design uses two vertical wells: one injection and one production. Sometimes it is necessary to establish communication between the two wells, and a common method to use reverse combustion to open internal pathways in the coal. Another alternative is to drill a lateral well connecting the two vertical wells. UCG with simple vertical wells was used in the Soviet Union and was later adopted by Ergo Exergy and tested at Linc's Chinchilla site in 1998–2003. It does work, but the method accesses relatively little coal from each well set and is only likely to cost-effective for very shallow coals with low drilling costs.
In the 1980s and 1990s, a method known as CRIP (controlled retraction and injection point) was demonstrated in the United States and Spain. This method uses a vertical production well and an extended lateral well drilled directionally in the coal. The lateral well is used for injection of oxidant and steam, and the injection point can be changed by retracting the injector. This method accesses a greater quantity of coal from one set of wells. Carbon Energy was the first to adopt a system, which uses a pair of lateral wells in parallel. This system allows a consistent separation distance between the injection and production wells while progressively mining the coal between the two wells. It provides access to the greatest quantity of coal per well set and also allows greater consistency in production gas quality.
A wide variety of coals are amenable to the UCG process. Coal grades from lignite through to bituminous may be successfully gasified. A great many factors are taken into account in selecting appropriate locations for UCG, including surface conditions, hydrogeology, lithoglogy, coal quantity, and quality. According to Andrew Beath other important criteria includes:
According to Peter Sallans these criteria are:
Underground coal gasification allows access to coal resources that are not economically recoverable by other technologies, e.g., that are too deep, low grade, or seams too thin.[2] By some estimates, UCG will increase economically recoverable reserves by 600 billion tonnes.[10] Livermore estimates that UCG could increase recoverable coal reserves in the USA by 300%.[11] Livermore and Linc Energy claim that UCG capital and operating costs are lower than in traditional mining.[2][12]
UCG product gas is optimally used to fire combined cycle gas turbine (CCGT) power plants, with some studies suggesting power island efficiencies of up to 55%, with a combined UCG/CCGT process efficiency of up to 43%. CCGT power plants using UCG product gas instead of natural gas can achieve higher outputs than pulverized-coal-fired power stations (and associated upstream processes, resulting in a large decrease in greenhouse gas (GHG) emissions.
UCG product gas can also be used for:
In addition, carbon dioxide produced as a by-product of underground coal gasification may be re-directed and used for enhanced oil recovery.
Underground product gas is an alternative to natural gas and potentially offers cost savings by eliminating mining, transport, and solid waste. The expected cost savings could increase given higher coal prices driven by emissions trading, taxes, and other emissions reduction policies, e.g. the Australian Government's proposed Carbon Pollution Reduction Scheme.
Cougar Energy and Linc Energy have conducted pilot projects in Australia.[13][14][15][16][17] Yerostigaz, a subsidiary of Linc Energy, produces about 1 million cubic metres (35 million cubic feet) of syngas per day in Angren, Uzbekistan. The produced syngas is used as fuel in the Angren Power Station.[18] In South Africa, Eskom (with Ergo Exergy as technology provider) has operated a demonstration plant in preparation for supplying commercial quantities of syngas for commercial production of electricity.[19][20][21] ENN has also operated a successful pilot project in China.
In addition, there are companies developing projects in Australia, UK, Hungary, Poland, Canada, US, Chile, China, Indonesia, India, South Africa, Botswana, and other countries.[19]
Eliminating mining eliminates mine safety issues.[22] Compared to traditional coal mining and processing, the underground coal gasification eliminates surface damage and solid waste discharge, and reduces sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions.[2][23] For comparison, the ash content of UCG syngas is estimated to be approximately 10 mg/m³ compared to smoke from traditional coal burning where ash content may be up to 70 mg/m³.[11] However, UCG operations cannot be controlled as precisely as surface gasifiers. Variables include the rate of water influx, the distribution of reactants in the gasification zone, and the growth rate of the cavity. These can only be estimated from temperature measurements, and analyzing product gas quality and quantity.[2]
Subsidence is a common issue with all forms of extractive industry. While UCG leaves the ash behind in the cavity, the depth of the void left after UCG is typically more than other methods of coal extraction.[2]
Underground combustion produces NOx and SO2 and lowers emissions, including acid rain. The process has advantages for geologic carbon storage.[2] Combining UCG with CCS technology allows re-injecting some of the CO2 on-site into the highly permeable rock created during the burning process, i.e. where the coal used to be.[24] Contaminants, such as ammonia and hydrogen sulfide, can be removed from product gas at a relatively low cost.
Aquifer contamination is a potential environmental concerns.[2][25] Organic and often toxic materials (such as phenol) remain in the underground chamber after gasification and, therefore, are likely to leach into ground water, absent appropriate site selection. Phenol leachate is the most significant environmental hazard due to its high water solubility and high reactiveness to gasification. Livermore conducted a burn at Hoe Creek, Wyoming, producing operating pressure in the burn cavity greater than the surrounding rock, forcing contaminants (including the carcinogen benzene) into potable groundwater.[11] However, some research has shown that the persistence of such substances in the water is short and that ground water recovers within two years.[23]