Добірка наукової літератури з теми "Coal gasification Australia"

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.

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.

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.

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.

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.

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?

The accumulation in the atmosphere of man-made gaseous emissions, including CO2, CH4, and N2O, are seen as a major contributor to climate change via global warming. Electricity generation is a major contributor to the production of these ‘Greenhouse Gases’ in Australia, mainly due to the reliance of the electricity industry on coal combustion. Vast reserves of lignite in South Eastern Australia ensure that coal will continue to be an important fuel for base load power generation for many years to come. Fluidised bed gasification is a process that has the potential to significantly reduce gaseous emissions from coal-based power generation. However, the ash-related problems of agglomeration and defluidisation may prevent the widespread commercialisation of such technology unless a control methodology for these problems can be developed. An experimental program was developed for the current study to test the impact of agglomeration and defluidisation in a 77 mm spouted bed gasification reactor, utilising high-sodium, high-sulphur content lignite. Lignite from the Lochiel deposit in South Australia was used as the test coal. Gasification tests of 4 hour duration each were performed over a wide range of different operating parameters, including bed temperature (759 to 967°C), spouting velocity (0.50 to 0.68 m/s), air to fuel mass ratio (0.3 to 3.5), and steam to fuel mass ratio (0.4 to 10.5). The effect of steam content of the gasification environment on agglomeration and defluidisation was of particular interest. Steam content of the inlet fluidising gas was subsequently varied from 10 to 90 wt% over the range of experiments conducted. In addition, a limited number of tests were conducted in a 300 mm pilot-scale gasification reactor, which were designed to test the practicality of findings obtained from the spouted bed gasification tests. Agglomeration and defluidisation in the pure char bed is governed by the ‘high temperature defluidisation limit’, which describes the increase in minimum fluidisation velocity with bed temperature beyond the temperature at which the ash begins to sinter. When operating at a superficial velocity below this limit, coating of solid mineral particles from the coal by molten ash phase creates particle growth. This particle growth eventually causes the bed to defluidise, resulting in a reduction of pressure drop from below the distributor to the freeboard. The temperature excursions that this creates results in an increase of ash sintering, causing coalescence of ash particles into larger ash deposits that form at the walls of the bed. Lochiel coal demonstrated defluidisation behaviour at temperatures as low as approximately 860°C under atmospheric pressure conditions. At 8 bar pressure, defluidisation was observed in the temperature range of 800 to 850°C. The high sodium content in Lochiel coal was found to result in the formation of the sodium disilicate-quartz eutectic (approximately 76 wt% SiO2) in the steam gasification environment. This species has a eutectic melting point of approximately 790°C, which corresponded to the minimum defluidisation temperature encountered in a set of experiments operated with extreme steam content in the fluidising gas (i.e. approximately 90 wt% steam). This species was held primarily responsible for initiating molten ash formation during gasification, and this corresponds to findings from a previous fundamental study in the Cooperative Research Centre (CRC) for Clean Power from Lignite. Agglomeration and defluidisation control methods for fluidised bed gasification of high-sodium coal were developed. Bed temperature is a key factor in the control of molten ash formation, and should be minimised to avoid formation of molten sodium silicate phases in the ash. A bed temperature of approximately 850°C at atmospheric pressure was suggested as the maximum temperature that a gasification reactor should be operated at when using high-sodium lignite. At higher pressures, this maximum temperature should be lowered further, as the sodium disilicate melting point decreases with increasing pressure. Under these conditions, maximum bed temperature should be maintained below approximately 800°C to avoid agglomeration and defluidisation. Use of steam in the gasification reactions should also be limited as much as possible, with the finding that the minimum temperature of agglomeration decreased with increasing steam content of the fluidising gas. A maximum steam to fuel ratio value of approximately 0.4 wt/wt at atmospheric conditions will limit the formation of low melting point sodium silicates. Additives high in calcium and magnesium, such as dolomite, can also be used to promote the formation of high melting point calcium and magnesium silicates in the ash. The results of this study demonstrate that lignite containing high levels of sodium in the ash can be used effectively for commercial gasification operations, provided that the operating parameter limits described in the preceding paragraph are adhered to wherever process considerations permit. This presents the opportunity for utilising lignite reserves in South Eastern Australia that are currently not viable for use in conventional combustion boiler systems due to the significant fouling that is incurred by these fuels. Recommendations for future study include conducting more extensive pilot scale trials, including an in-depth assessment of the use of additives for chemical control of molten ash formation, and the role of pressure in the formation of low melting point silicates. Other fuels, such as lignite from lower quality seams, and biomass, should also be investigated to determine the applicability of results from this study to different fuel types.
Thesis(PhD)-- University of Adelaide, School of Chemical Engineering, 2007

Underground Coal Gasification (UCG) is a gasification process carried out in non-mined coal seams using injection and production wells drilled from the surface, enabling the coal to be converted into product gas. The UCG process practiced by Ergo Exergy is called Exergy UCG or εUCG. εUCG was applied in the Chinchilla UCG-IGCC Project in Australia. The IGCC project in Chinchilla, Australia has been under development since July 1999. The project involves construction of the underground gasifier and demonstration of UCG technology, and installation of the power island. Since December 1999 the plant has been making gas continuously, and its maximum capacity is 80,000 Nm3/h. Approximately 32,000 tonnes of coal have been gasified, and 100% availability of gas production has been demonstrated over 30 months of operation. The UCG operation in Chinchilla is the largest and the longest to date in the Western world. The εUCG facility at Chinchilla has used air injection, and produced a low BTU gas of about 5.0 MJ/m3 at a pressure of 10 barg (145 psig) and temperature of 300° C (570° F). It included 9 process wells that have been producing gas manufactured from a 10 m thick coal seam at the depth of about 140 m. The process displayed high efficiency and consistency in providing gas of stable quality and quantity. The results of operations in Chinchilla to date have demonstrated that εUCG can consistently provide gas of stable quantity and quality for IGCC power projects at very low cost enabling the UCG-IGCC plant to compete with coal-fired power stations. This has been done in full compliance with rigorous environmental regulations. A wide range of gas turbines can be used for UCG-IGCC applications. The turbines using UCG gas will demonstrate an increase in output by up to 25% compared to natural gas. The power block efficiency reaches 55%, while the overall efficiency of the UCG-IGCC process can reach 43%. A UCG-IGCC power plant will generate electricity at a much lower cost than existing or proposed fossil fuel power plants. CO2 emissions of the plant can be reduced to a level 55% less than those of a supercritical coal-fired plant and 25% less than the emissions of NG CC.

Underground Coal Gasification (UCG) is a gasification process carried on in non-mined coal seams using injection and production wells drilled from the surface, converting coal in situ into a product gas usable for chemical processes and power generation. The UCG process developed, refined and practiced by Ergo Exergy Technologies is called the Exergy UCG Technology or εUCG® Technology. The εUCG technology is being applied in numerous power generation and chemical projects worldwide. These include power projects in South Africa (1,200 MWe), India (750 MWe), Pakistan, and Canada, as well as chemical projects in Australia and Canada. A number of εUCG based industrial projects are now at a feasibility stage in New Zealand, USA, and Europe. An example of εUCG application is the Chinchilla Project in Australia where the technology demonstrated continuous, consistent production of commercial quantities of quality fuel gas for over 30 months. The project is currently targeting a 24,000 barrel per day synthetic diesel plant based on εUCG syngas supply. The εUCG technology has demonstrated exceptional environmental performance. The εUCG methods and techniques of environmental management are an effective tool to ensure environmental protection during an industrial application. A εUCG-IGCC power plant will generate electricity at a much lower cost than existing or proposed fossil fuel power plants. CO2 emissions of the plant can be reduced to a level 55% less than those of a supercritical coal-fired plant and 25% less than the emissions of NG CC.