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Journal articles on the topic 'Coal gasification Australia'

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Author: Grafiati

Published: 10 December 2022

Last updated: 29 January 2023

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1

Perkins, Greg, Ernest du Toit, Greg Cochrane, and Grant Bollaert. "Overview of underground coal gasification operations at Chinchilla, Australia." Energy Sources, Part A: Recovery, Utilization, and Environmental Effects 38, no. 24 (November 2016): 3639–46. http://dx.doi.org/10.1080/15567036.2016.1188184.

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2

Mallett, CW. "Environmental controls for underground coal gasification." Proceedings of the Institution of Mechanical Engineers, Part A: Journal of Power and Energy 232, no. 1 (August 2, 2017): 47–55. http://dx.doi.org/10.1177/0957650917723733.

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Effective environmental management of an underground coal gasification pilot has been demonstrated at Kogan in Queensland, Australia. It commenced with selection of a suitable site with a coal seam surrounded by impervious rocks that provided a gas seal for the gasifier and sufficient groundwater pressure to constrain lateral loss of gas and chemicals through coal fractures. Project infrastructure was specified to withstand the temperatures and pressures experienced during gasification and gas processing. During syngas production in the second gasifier, Panel 2, it was shown that all pyrolysis products of environmental concern were retained within the gasifier. This was achieved by maintaining continuous groundwater inflow into the gasifier cavity through control of the relative pressures of the gasifier and surrounding groundwater. In Panel 1, it was shown that when pyrolysis products migrated out of the cavity, they were quickly detected and by modifying relative pressures to increase groundwater inflow the original groundwater conditions were restored. Following production, the cavities were decommissioned and in Panel 2 steam cleaning of the cavity removed 92% of the chemical load from the cavity. As a result, relatively low concentrations of pyrolysis products remained in the cavity. Fate and transport modelling predicted that these products will not migrate into the regional groundwater and will naturally degrade within three decades.

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3

Kritzinger, Niel, Ravi Ravikumar, Sunil Singhal, Katie Johnson, and Kakul Singh. "Blue hydrogen production: a case study to quantify the reduction in CO2 emission in a steam methane reformer based hydrogen plant." APPEA Journal 59, no. 2 (2019): 619. http://dx.doi.org/10.1071/aj18164.

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In Australia, and globally, hydrogen is primarily produced from natural gas via steam methane reforming. This process also produces CO2, which is typically vented to the atmosphere. Under this configuration, the hydrogen produced is known as grey hydrogen (carbon producing). However, if the CO2 from this process is captured and stored after it is produced, the hydrogen product is CO2-neutral, or ‘blue hydrogen’. To enable production of blue hydrogen from existing natural gas steam methane reformers (SMRs) in Australia, gasification of biomass/bio waste can be utilised to produce fuel gas for use in a SMR-based hydrogen plant, and the CO2 in the shifted syngas can be removed as pure CO2 either for sequestration, enhanced oil recovery, or enhanced coal bed methane recovery. Australian liquefied natural gas that is exported and utilised as feedstock to existing SMRs in other countries can incorporate carbon emission reduction techniques for blue hydrogen production. The use of bio-derived syngas as fuel will generate hydrogen with only bio-derived CO2 emissions. Additional carbon credit can be obtained by replacing petrol or diesel consuming automobiles with fuel cell vehicles powered by hydrogen derived from gasification of biomass.

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4

Saw, W., A. Kaniyal, P. van Eyk, G. Nathan, and P. Ashman. "Solar Hybridized Coal-to-liquids via Gasification in Australia: Techno-economic Assessment." Energy Procedia 69 (May 2015): 1819–27. http://dx.doi.org/10.1016/j.egypro.2015.03.158.

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5

Baker, G., and S. Slater. "Coal seam gas—an increasingly significant source of natural gas in eastern Australia." APPEA Journal 49, no. 1 (2009): 79. http://dx.doi.org/10.1071/aj08007.

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The commercial production of coal seam gas (CSG) in Australia commenced in 1996. Since then its production has grown up significantly, particularly in the last five years, to become an integral part of the upstream gas industry in eastern Australia. The major growth in both CSG reserves and production has been in the Bowen and Surat basins in Queensland. Active exploration and appraisal programs with the first pilot operations were established in the Galilee Basin in 2008; however, an important reserve base has been built up in New South Wales in the Clarence-Moreton, Gloucester, Gunnedah and Sydney basins. There has been modest CSG production from the Sydney Basin for some years with commercial production expected to commence in the other three basins by or during 2010. Exploration for CSG has been undertaken in Victoria and Tasmania while programs are being developed in South Australia focussing on the Arckaringa Basin. Elsewhere in Australia planning is being undertaken for CSG exploration programs for the Pedirka Basin in the Northern Territory and the Perth Basin in Western Australia. CSG was being supplied into the eastern Australian natural gas market at 31 December 2008 at a rate of approximately 458 TJ per day (167 PJ per year). Queensland is currently producing 96.7% of this total. Approximately 88% of the natural gas used in Queensland is CSG. Currently, CSG accounts for nearly 25% of the eastern Australian natural gas market, estimated at 670 PJ per year. The production of CSG is now a mature activity that has achieved commercial acceptability, especially for coal seam derived gas from the Bowen and Surat basins. The recent proposals by a number of local CSG producers—in joint venture arrangements with major international groups—to produce liquefied natural gas (LNG) from CSG along with a number of merger and acquisition proposals, is testimony to the growing economic and commercial significance of the CSG sector. Should all of the proposed CSG based LNG projects eventuate, LNG output would be approximately 40 million tones per year. This will require raw CSG production to increase to approximately 2,600 PJ per year, resulting in a four fold increase from the present natural gas consumption in eastern Australia. The proved and probable (2P) reserves of CSG in eastern Australia at 31 December 2008 were 17,011 PJ or 60.2% of the total independently audited 2P natural gas reserves of 28,252 PJ. The Bowen and Surat basins with 16,120 PJ have the largest onshore gas reserves eastern Australia. In New South Wales, the 2P CSG reserves at the end of 2008 were 892 PJ, though this is expected to increase significantly over the next 12 months. Major upstream natural gas producers such as Origin Energy Limited and Santos Limited both hold over 50% of their Australian 2P gas reserves as CSG. The 1P reserves of CSG in eastern Australia at 31 December were reported as 4,197 PJ while the 3P reserves of CSG at the same date were 40,480 PJ. Most companies in the CSG sector are undertaking development work to upgrade their 3P reserves (and contingent resources) into the 2P category. The CSG resource in eastern Australia is very large. Companies with interests in CSG have reported in excess of 200,000 PJ as gas in place in the Bowen, Clarence-Moreton, Galilee, Gloucester, Gunnedah, Queensland Coastal, Surat and Sydney basins. The 2P reserves of CSG are expected to exceed 20,000 PJ by the end of 2009. A significant part of the expected large increase in 2P reserves of gas initially will be dedicated to the proposed LNG projects being considered for Gladstone. The major issues confronting the CSG industry and its rapid growth are concerned with land access, overlapping tenure (particularly in Queensland with underground coal gasification) the management and beneficial use of co-product formation water and gas production ramp up factors associated with the proposed LNG projects.

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6

Bradshaw, Barry E., Meredith L. Orr, and Tom Bernecker. "Distribution and estimates of Australia's identified energy commodity resources." APPEA Journal 61, no. 2 (2021): 325. http://dx.doi.org/10.1071/aj20116.

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Australia is endowed with abundant, high-quality energy commodity resources, which provide reliable energy for domestic use and underpin our status as a major global energy provider. Australia has the world’s largest economic uranium resources, the third largest coal resources and substantial conventional and unconventional natural gas resources. Since 2015, Australia’s gas production has grown rapidly. This growth has been driven by a series of new liquefied natural gas (LNG) projects on the North West Shelf, together with established coal seam gas projects in Queensland. Results from Geoscience Australia’s 2021 edition of Australia’s energy commodity resources assessment highlight Australia’s endowment with abundant and widely distributed energy commodity resources. Knowledge of Australia’s existing and untapped energy resource potential provides industry and policy makers with a trusted source of data to compare and understand the value of these key energy commodities to domestic and world markets. A key component of Australia’s low emissions future will be the development of a hydrogen industry, with hydrogen being produced either through electrolysis of water using renewable energy resources (‘green’ hydrogen), or manufactured from natural gas or coal gasification, with carbon capture and storage of the co-produced carbon dioxide (‘blue’ hydrogen). Australia’s endowment with abundant natural gas resources will be a key enabler for our transition to a low emissions future through providing economically competitive feedstock for ‘blue’ hydrogen.

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7

Tyurina, E. A., A. S. Mednikov, P. Y. Elsukov, P. V. Zharkov, and E. V. Zubova. "Use of underground coal gasification gas for co-production of electric power and synthetic liquid fuel." Vestnik IGEU, no. 1 (February 28, 2022): 22–37. http://dx.doi.org/10.17588/2072-2672.2022.1.022-037.

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The study is relevant due to increased interest to the underground coal gasification technologies (UCG). The interest is determined by the depletion of world oil and gas reserves, the significant amount of coal deposits in various countries of the world, the growing energy demand, as well as the threat of global climate change. The possibility to use technologies of underground gasification of low-grade coal with complex geological environment is huge. Recently, interest to UCG has grown dramatically. In contrast to all major programs of the 20th century, this unprecedented interest is mainly stimulated by private capital in response to high oil and energy prices. Thus, the studies of UCG are carried out. And more than 30 tests are planned in Australia, China, India, South Africa, New Zealand, Canada, and the United States. The development of competitive gas-based technologies of production of electricity and synthetic liquid fuels is a high-priority task. The studies have been carried out using a mathematical model of the unit for the production of electricity and methanol. To design a mathematical model, a software, or the system of machine programs development (SMPP) has been used. It has been developed at Melentiev Energy Systems Institute of Siberian Branch of the Russian Academy of Sciences (ESI SB RAS). The article presents the results of the study of the use of UCG for the coproduction of synthetic liquid fuel (methanol) and electricity. A detailed mathematical model of electricity and methanol production unit has been developed. Based on the model, technical and economic optimization of the schemes and parameters has been carried out. It made possible to estimate the competitiveness conditions of the proposed method of coal processing. In addition, the sensitivity of the economic indicators of the unit to changes in external conditions has been studied. Based on the results of the analysis of the cost of diesel fuel in the eastern regions of Russia, the authors have made the conclusion that at present methanol produced by the energy technological unit is as competitive as delivered expensive diesel fuel. The introduction of such systems is economically reasonable in the near future.

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8

Reidy, B. L., and G. W. Samson. "An Assessment of a Low-Cost Wastewater Disposal System after Twenty-Five Years of Operation." Water Science and Technology 19, no. 5-6 (May 1, 1987): 701–10. http://dx.doi.org/10.2166/wst.1987.0249.

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A low-cost wastewater disposal system was commissioned in 1959 to treat domestic and industrial wastewaters generated in the Latrobe River valley in the province of Gippsland, within the State of Victoria, Australia (Figure 1). The Latrobe Valley is the centre for large-scale generation of electricity and for the production of pulp and paper. In addition other industries have utilized the brown coal resource of the region e.g. gasification process and char production. Consequently, industrial wastewaters have been dominant in the disposal system for the past twenty-five years. The mixed industrial-domestic wastewaters were to be transported some eighty kilometres to be treated and disposed of by irrigation to land. Several important lessons have been learnt during twenty-five years of operating this system. Firstly the composition of the mixed waste stream has varied significantly with the passage of time and the development of the industrial base in the Valley, so that what was appropriate treatment in 1959 is not necessarily acceptable in 1985. Secondly the magnitude of adverse environmental impacts engendered by this low-cost disposal procedure was not imagined when the proposal was implemented. As a consequence, clean-up procedures which could remedy the adverse effects of twenty-five years of impact are likely to be costly. The question then may be asked - when the total costs including rehabilitation are considered, is there really a low-cost solution for environmentally safe disposal of complex wastewater streams?

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9

Lee, Woon-Jae, Sang-Done Kim, and Byung-Ho Song. "Steam gasification of an australian bituminous coal in a fluidized bed." Korean Journal of Chemical Engineering 19, no. 6 (November 2002): 1091–96. http://dx.doi.org/10.1007/bf02707238.

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10

HARRIS, D., D. ROBERTS, and D. HENDERSON. "Gasification behaviour of Australian coals at high temperature and pressure." Fuel 85, no. 2 (January 2006): 134–42. http://dx.doi.org/10.1016/j.fuel.2005.07.022.

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11

Chodankar, Chetan R., Bo Feng, Jingyu Ran, and A. Y. Klimenko. "Kinetic study of the gasification of an Australian bituminous coal char in carbon dioxide." Asia-Pacific Journal of Chemical Engineering 5, no. 3 (March 20, 2009): 413–19. http://dx.doi.org/10.1002/apj.269.

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12

Ilyushechkin, Alexander Y., Daniel G. Roberts, and David J. Harris. "Characteristics of solid by-products from entrained flow gasification of Australian coals." Fuel Processing Technology 118 (February 2014): 98–109. http://dx.doi.org/10.1016/j.fuproc.2013.08.017.

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13

Ilyushechkin, Alexander, Daniel Roberts, David Harris, and Kenneth Riley. "Trace Element Partitioning and Leaching in Solids Derived from Gasification of Australian Coals." Coal Combustion and Gasification Products 3, no. 1 (2011): 8–16. http://dx.doi.org/10.4177/ccgp-d-10-00008.1.

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14

Zhang, Dong-Ke, and Aaron Poeze. "Variation of sodium forms and char reactivity during gasification of a South Australian low-rank coal." Proceedings of the Combustion Institute 28, no. 2 (January 2000): 2337–44. http://dx.doi.org/10.1016/s0082-0784(00)80645-1.

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15

Ilyushechkin, Alexander Y., and Daniel Roberts. "Slagging behaviour of Australian brown coals and implications for their use in gasification technologies." Fuel Processing Technology 147 (June 2016): 47–56. http://dx.doi.org/10.1016/j.fuproc.2015.10.028.

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16

Ye, D. P., J. B. Agnew, and D. K. Zhang. "Gasification of a South Australian low-rank coal with carbon dioxide and steam: kinetics and reactivity studies." Fuel 77, no. 11 (September 1998): 1209–19. http://dx.doi.org/10.1016/s0016-2361(98)00014-3.

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17

van Eyk, Philip J., Adam Kosminski, Peter J. Mullinger, and Peter J. Ashman. "Control of Agglomeration during Circulating Fluidized Bed Gasification of a South Australian Low-Rank Coal: Pilot Scale Testing." Energy & Fuels 30, no. 3 (January 7, 2016): 1771–82. http://dx.doi.org/10.1021/acs.energyfuels.5b02267.

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18

Ajilkumar, A., U. S. P. Shet, and T. Sundararajan. "Numerical Simulation of Pressure Effects on the Gasification of Australian and Indian Coals in a Tubular Gasifier." Heat Transfer Engineering 31, no. 6 (May 2010): 495–508. http://dx.doi.org/10.1080/01457630903409704.

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19

Erincin, Didem, Ali Sınagˇ, Zarife Mısırlıogˇlu, and Muammer Canel. "Characterization of burning and CO2 gasification of chars from mixtures of Zonguldak (Turkey) and Australian bituminous coals." Energy Conversion and Management 46, no. 17 (October 2005): 2748–61. http://dx.doi.org/10.1016/j.enconman.2005.01.009.

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20

MIURA, Kouichi, Haoming ZHA, Kazuhiro MAE, and Kenji HASHIMOTO. "Relationship between the Gasification Reactivity and the Properties of the Chars prepared from an Australian Brown Coal by Several Methods." Journal of the Japan Institute of Energy 73, no. 3 (1994): 194–202. http://dx.doi.org/10.3775/jie.73.194.

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21

"06/02014 Gasification behaviour of Australian coals at high temperature and pressure." Fuel and Energy Abstracts 47, no. 5 (September 2006): 312. http://dx.doi.org/10.1016/s0140-6701(06)82022-9.

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22

"95/01240 Relationship between the gasification reactivity and the properties of the chars prepared from an Australian brown coal by several methods." Fuel and Energy Abstracts 36, no. 2 (March 1995): 88. http://dx.doi.org/10.1016/0140-6701(95)92905-3.

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23

"05/02390 Characterization of burning and CO2 gasification of chars from mixtures of Zonguldak (Turkey) and Australian bituminous coals." Fuel and Energy Abstracts 46, no. 6 (November 2005): 354. http://dx.doi.org/10.1016/s0140-6701(05)00075-5.

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