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Fujioka M.,Japan Coal Energy Center | Yamaguchi S.,Akita University | Nako M.,General Environmental Technos Co
International Journal of Coal Geology | Year: 2010

The feasibility of extracting gas from coal seam while storing carbon dioxide underground was evaluated in Japan. A CO2-ECBM project had begun near the town of Yubari on the island of Hokkaido in northern Japan. The primary coal seam of interest was a 5-6m thick Yubari coal seam located at the depth of 900m. A micro-pilot test with a single well and multi-well CO2 injection tests, involving an injection and production wells, were carried out in the period between May 2004 and October 2007. There were a variety of tests conducted in the injection well, including an initial water injection fall-off test and a series of CO2 injection and fall-off tests. Although gas production rate was obviously enhanced by CO2 injection, water production rate was not clearly affected by CO2 injection. Several injection tests suggested that injectivity of CO2 into the virgin coal seam saturated with water was eventually increased as the water saturation near the injector was decreased by the injected CO2. It was estimated that low injectivity of CO2 was caused by the reduction in permeability induced by coal swelling. N2 flooding test was performed in 2006 to evaluate the effectiveness of N2 injection on improving well injectivity. The N2 flooding test showed that daily CO2 injection rate was boosted, but only temporarily. Moreover, the permeability did not return to the initial value after CO2 and N2 were repeatedly injected. It was also indicated that the coal matrix swelling might create a high stress zone near to the injection well. © 2010 Elsevier B.V.


Kiyama T.,Hokkaido University of Science | Nishimoto S.,Japan Central Research Institute of Electric Power Industry | Fujioka M.,Japan Coal Energy Center | Xue Z.,Kyoto University | And 3 more authors.
International Journal of Coal Geology | Year: 2011

CO2 sequestration in deep unmineable coalbeds is regarded as a viable option for carbon storage. On the other hand, many uncertainties still remain due to the fact that coal interacts with CO2 in a variety of ways. In Japan, the first CO2 Enhanced Coalbed Methane Recovery field trials at Yubari were carried out. CO2 was injected from an injection well into a coalbed at a depth of 900m, and coalbed methane was collected from an observation well. Since the CO2 injection rate was an order of magnitude lower than that estimated by preliminary analyses, N2 was injected in an attempt to improve it. However, this caused only a temporary increase in the CO2 injection rate. To better understand the phenomena observed in the Yubari field tests, two laboratory experiments were conducted under stress-constrained conditions. In Test I, liquid CO2 was injected into a water-saturated coal specimen and then heated and injected as supercritical CO2. This was to simulate the initial stage of CO2 injection at Yubari when the coal seam was saturated with water. In Test II, supercritical CO2 was injected into a coal specimen saturated with N2, and then N2 and CO2 were repeatedly injected. This test was to simulate the case of N2 injection and CO2 re-injection at Yubari. In Test I, a volumetric swelling strain of 0.25 to 0.5% was observed after injecting liquid CO2. However, in Test II, the swelling strain was about 0.5 to 0.8% after injecting supercritical CO2. Following further injection of N2 in Test II, slow strain recovery was observed in the coal. At an effective stress of 2MPa, the permeability of the water-saturated coal specimen was 2×10-6darcy. In contrast, the permeability of the N2-saturated coal specimen was originally 5×10-4 to 9×10-4darcy, and after injection of supercritical CO2 it decreased to 2×10-4darcy. Further injections of N2 and supercritical CO2 caused little subsequent change in permeability. These results suggest that when liquid CO2 was injected into the water-saturated coal specimen, it did not completely displace the water in the coal matrix. To further investigate the coal swelling and permeability behavior during gas injection, elastic wave velocity measurements were carried out and the results were found to validate those obtained using strain gauges. The results indicate that coal swelling is likely to be the main cause for the permeability change in the Yubari field tests and thus provide useful information for modeling the field trial. © 2010 Elsevier B.V.


Ordowich C.,SRI International | Chase J.,SRI International | Steele D.,SRI International | Malhotra R.,SRI International | And 2 more authors.
Energy and Fuels | Year: 2012

Coal and natural gas have and will likely continue to be key components of the world energy supply for years to come. Currently, the most efficient commercial technologies for power production are supercritical pulverized coal combustion (SCPC) and natural gas combustion with combined cycle (NGCC). Emerging technologies for more efficient power generation from coal include ultra-super-critical pulverized coal (USCPC), advanced ultra-super-critical PC, integrated gasification combined cycle (IGCC), integrated gasification fuel cell combined cycle (IGFC), and direct carbon fuel cell. They each have different capital and operating costs leading to different levelized cost of electricity (LCOE). To forecast each of these competing technologies under various scenarios of electricity demand, fuel cost, and research investment, we created a Power Technology Futures Model (PTFM) based on "learning curves" methodology. Technology learning curves are a powerful tool for forecasting anticipated performance improvements due to a broad range of technical improvements without specifying the parameters of every possible improvement. The model can help planners and policy makers explore, visualize, and communicate how research and development (R&D) investments in certain technologies affect the mix of technologies deployed in the future. We utilized the Analytica modeling package and included detailed economic calculations to estimate the levelized costs for several types of coal and natural gas power plants with and without carbon capture technologies. Future improvements in plant efficiency and reductions in capital and operating and mantainence (O&M) costs were modeled using technology learning curves that were established by a detailed analysis of historic performance data. We used published estimates of future demand and fuel costs where available, but the model allows the user to easily input other numbers as tables or equations. Adoption of carbon capture was modeled in a variety of ways including being driven by a carbon cap or a carbon tax. The results of the model depict the difficulty of meeting a 50% reduction in annual CO 2 production by 2050, even with significant R&D investments, ambitious CO 2 pricing, and decreased demand for energy from coal and natural gas. © 2011 American Chemical Society.


Song W.,East China University of Science and Technology | Sun Y.,East China University of Science and Technology | Wu Y.,East China University of Science and Technology | Zhu Z.,East China University of Science and Technology | Koyama S.,Japan Coal Energy Center
AIChE Journal | Year: 2011

The viscosities of 45 coal ash slag samples at high temperature have been measured under different temperatures and shear rates. The computer thermodynamic software package FactSage has been used to predict liquidus temperatures, volume fractions of crystallized solid particles (φ{symbol}), and the compositions of remaining liquid phase for 45 coal ash slag samples. The flow properties of completely liquid and partly crystallized coal ash slag samples have been predicted by three viscosity models. The Urbain formalism has been modified to describe the viscosities of fully liquid slag and homogeneous remaining liquid phase in coal ash slag samples. The modified Einstein equation and Einstein-Roscoe equation have been used to describe the viscosities of heterogeneous coal ash slag samples of φ{symbol} < 10.00 vol % and φ{symbol} ≥ 10.00 vol %, respectively. These three models provided a good description of the experimental data of fully liquid and heterogeneous coal ash slag samples. The new models also predicted flow properties of mixtures of coal ash slags with CaO, Fe2O3, MgO, SiO2, and Al2O3. Copyright © 2010 American Institute of Chemical Engineers (AIChE).


Wang Y.,CAS Institute of Process Engineering | Lin S.,Japan Coal Energy Center | Suzuki Y.,Japan National Institute of Advanced Industrial Science and Technology
Fuel Processing Technology | Year: 2010

In this study, the decomposition conditions of limestone particles (0.25-0.50 mm) for CO2 capture in a steam dilution atmosphere (20-100% steam in CO2) were investigated by using a continuously operating fluidized bed reactor. The results show that the decomposition conversion of limestone increased with the steam dilution percentage in the CO2 supply gas. At a bed temperature of 920 °C, the conversions were 72% without steam dilution and 98% with 60% steam dilution. The conversion was 99% with 100% steam dilution at 850 °C of the bed temperature. Steam dilution can decrease not only the decomposition temperature of limestone, but also the residence time required for nearly complete decomposition of CaCO 3. The hydration and carbonation reactivities of the CaO produced were also tested and the results show that both the reactivities increased with the steam dilution percentage for decomposing limestone. © 2009 Elsevier B.V. All rights reserved.


Lin S.,Japan Coal Energy Center
Energy Procedia | Year: 2013

In-situ CO2 capture in coal utilization captures CO2 during coal combustion or gasification such as Oxygen fuel combustion or Chemical looping coal gasification processes. Japan coal energy center (JCOAL) have proposed a chemical looping coal gasification method. This method utilizes a chemical looping with the calcium cycle, in which CaO (or Ca(OH)2) captures CO2 during coal gasification to form CaCO3 and release heat for gasification to produce hydrogen in one gasifier. This paper introduces the current developing status of the method, mainly including the experimental examination of the transition of sorbent particle size distribution, ash and sulfur concentration of materials at several locations of gasification and calcination system for the process. As results it is shown that, the product gases from the chemical looping coal gasification only contained nearly 80% H2 with 20% CH4 with dry base. It was also found that coal ash and sulfur concentrated highly in the process of calcination after cyclone. And the plant cold gas efficiency which should be affected by ash separation was also analyzed. If it is possible, separate and remove ash and sulfur by applying devices like filter or/and cyclone separator, the plant coal gas efficiency may raise 2 points than that in the previous study in which a part of recycled sorbent was rejected without separation. As an application of the chemical looping coal gasification, exergy regeneration type IGFC power generation was proposed. Exhaust heat of FC can be used for reforming of CH4 which produced by coal gasification. This system was analyzed by use AspenPlus. The result shown that, hydrogen cold gas efficiency was about 10% higher than the cold gas efficiency of the chemical looping coal gasification. © 2013 The Author.


Lin S.-Y.,Japan Coal Energy Center
Energy Procedia | Year: 2014

It is a prerequisite for the increasing use of biomass energy that its introduction and acceptance be increased. The technologies for biomass use face the challenge of overcoming the following issues: (1) Stable supply of gasification material; (2) Heat supply for biomass gasification; (3) Auxiliary facilities for post-gasification tar removal, gas composition adjustment, and desulfurization; (4) Use of various biomass; We proposed Ca looping three-tower biomass/coal co-gasification process. CaO circulates as the heat transfer material, catalyst and a CO2/H2S sorbent. Biomass and supplemental fuel coal are supplied to the gasification tower and generate volatile matter and char through the pyrolysis and gasification, as well as a part of CO2 in volatile matter are absorbed by CaO to form CaCO3 and release heat for the pyrolysis and gaisification. The volatile matter is then introduced to the reforming tower for the catalytic reforming of hydrocarbon (CH4, Tar et al.) by contact with the CaO particles. The char and CaCO3 are introduced to the combustion tower. The char is burnt using air to heat the CaO particle and CaCO3 for decomposition to CaO. The heated CaO particles return to the reforming tower and the gasification tower through a cyclone. The CaO particle heated in the combustion tower provides heat to the catalytic reforming of hydrocarbon as CH4, tar et al. in reforming tower. The catalytic action of CaO for hydrocarbon reforming was investigated by using a two stage fluidized bed reactor which upper stage is reforming reactor, and lower stage is gasification reactor. Biomass/coal were fed in to gasification reactor, and volatile matter produced by biomass/coal gasification was raised in to reforming reactor. It also shows that, with CaO catalysis in the reforming reactor, no tar remained in the cooling zone and condenser from biomass gasification 2.5hr. However without CaO addition, tar generated terribly after biomass supply only 3 minutes. Liquid products from reforming reactor for biomass and coal gasification were collected by using ice water and liquid nitrogen baths. Total carbon (TOC) contained in the liquid product was analyzed. Tar contained in product gas from biomass and coal gasification were estimated by the amount of total carbon. The results shown that, only 5.7 mg/m3 and 2.5 mg/m3 tar contained in products gas for biomass and coal gasification, respectively. In this study, we also built a small hot 3-T CFB facility, to investigate the particle circulating and fluidization. And, the effect of CaO catalysis on steam reforming of hydrocarbons as methane, tar produced by biomass or coal gasification also be investigated. First we tested silica sand and CaO particle circulating in the three-tower CFB. Results shown that, three-tower type CFB can make stability particle circulating not only under room temperature and also circulated well under high temperature 800°C. Control the differential pressure (δP) between exits of cyclone and reformer is much important for the stability of circulating of 3-T CFB. Particle circulating velocity, Gs was obtained about 100-200. © 2014 The Authors Published by Elsevier Ltd.


Lin S.,Japan Coal Energy Center | Kiga T.,Japan Coal Energy Center | Nakayama K.,Japan National Institute of Advanced Industrial Science and Technology | Suzuki Y.,Japan National Institute of Advanced Industrial Science and Technology
Energy Procedia | Year: 2011

In-situ CO2 capture in coal utilization captures CO2 during coal combustion or gasification such as Oxygen fuel combustion or HyPr-RING. coal gasification processes. Regarding Oxufuel combustion, Callide Oxyfuel Project has been being conducted as the world first project to apply the technology to an existing power plant, Callide A Power Station #4 unit (30MWe) with injection of captured CO2 into the underground. This is a Japan-Australia collaboration project and JCOAL participates in it as a supporting collaborator. JCOAL also proposed a novel coal gasification method-,HyPr-RING (Hydrogen Production by Reaction-Integrated Novel Gasification). HyPr-RING method utilizes a chemical looping with the calcium cycle, in which CaO (or Ca(OH)2) captures CO2 during coal gasification completely to form CaCO3 and release heat for gasification to produce near pure hydrogen in one gasifier. This paper introduces the current developing status of the HyPr-RING method, mainly including the experimental examination of the transition of sorbent particle size distribution, ash and sulfur concentration of materials at several locations of gasification and calcination system for the HyPr-RING process. And the plant cold gas efficiency which should be affected by ash separation was also analyzed. As the results, it was found that coal ash and sulfur concentrated highly in the process of calcination after cyclone. If it is possible, separate and remove ash and sulfur by applying devices like filter or/and cyclone separator, the plant coal gas efficiency may raise 2 points than that in the previous study in which a part of recycled sorbent was rejected without separation. One method for reducing CO2, the green house gas emissions is to capture CO2 before it releases into the atmosphere and then sequestrate it. Active lime (main component, CaO) can be used to capture CO2 in the exhaust gas or in the reactor from fossil fuels utilization effectively. That is calcium oxide (CaO) absorbs CO2 to yield calcium carbonate (CaCO3) (Eq.(1)), then the CaCO3 is thermally decomposed to CaO again and release nearly pure CO2 (Eq. (2)) for sequestration. To obtain a nearly pure CO2 stream from CaCO 3 decomposition, the heat for decomposing CaCO3 can be supplied by combusting fossil fuels, such as coal and natural gas, in a calciner with oxygen fuel combustion. The oxygen diluted by CO2 (CO 2 cycle) or H2O (steam cycle), in order to obtain near pure CO2 stream from CaCO3 decomposition. In our previous studies4-6, it was clarified that calcinations of limestone (main component, CaCO3) in a fluidized bed calciner can be performed in CO2 cycle atmosphere when the bed temperature was raised above 1293 K, whereas with 60% steam cycle in atmosphere, limestone can be decomposed at comparatively lower temperature, such as 1173 K. The decomposition conversions of the limestone were about 95% and 98%, in CO2 cycle and in steam cycle atmospheres, respectively. Reducing the calcinations temperature of limestone was helpful to produce more than 30% active CaO as shown in previous study4-6. In this study, the energy of CaCO3 calcination process by H2O (steam) cycle was analyzed and compared with CaCO 3 calcination process by CO2 cycle. For process calculations, the mass and energy flows were calculated iteratively, based on the input and output balances, until err [(input-output)/input] was < 0.01. Analysis showed that, although H2O (steam) cycle calcination had calcination energy more about 3.6% than CO2 cycle due to water evaporation latent heat loss, however, the calcination energy per active CaO was lowest for H2O (steam) cycle. © 2011 Published by Elsevier Ltd.


Lin S.,Japan Coal Energy Center | Kiga T.,Japan Coal Energy Center | Wang Y.,Chinese Academy of Sciences | Nakayama K.,Japan National Institute of Advanced Industrial Science and Technology
Energy Procedia | Year: 2011

One method for reducing CO2, the green house gas emissions is to capture CO2 before it releases into the atmosphere and then sequestrate it. Active lime (main component, CaO) can be used to capture CO 2 in the exhaust gas or in the reactor from fossil fuels utilization effectively. That is calcium oxide (CaO) absorbs CO2 to yield calcium carbonate (CaCO3) (Eq.(1)), then the CaCO3 is thermally decomposed to CaO again and release nearly pure CO2 (Eq. (2)) for sequestration. To obtain a nearly pure CO2 stream from CaCO 3 decomposition, the heat for decomposing CaCO3 can be supplied by combusting fossil fuels, such as coal and natural gas, in a calciner with oxygen fuel combustion. The oxygen diluted by CO2 (CO 2 cycle) or H2O (steam cycle), in order to obtain near pure CO2 stream from CaCO3 decomposition. In our previous studie s4-6, it was clarified that calcinations of limestone (main component, CaCO3) in a fluidized bed calciner can be performed in CO2 cycle atmosphere when the bed temperature was raised above 1293 K, whereas with 60% steam cycle in atmosphere, limestone can be decomposed at comparatively lower temperature, such as 1173 K. The decomposition conversions of the limestone were about 95% and 98%, in CO2 cycle and in steam cycle atmospheres, respectively. Reducing the calcinations temperature of limestone was helpful to produce more than 30% active CaO as shown in previous study4-6. In this study, the energy of CaCO3 calcination process by H2O (steam) cycle was analyzed and compared with CaCO 3 calcination process by CO2 cycle. For process calculations, the mass and energy flows were calculated iteratively, based on the input and output balances, until err [(input-output)/input] was < 0.01. Analysis showed that, although H2O (steam) cycle calcination had calcination energy more about 3.6% than CO2 cycle due to water evaporation latent heat loss, however, the calcination energy per active CaO was lowest for H2O (steam) cycle. © 2011 Published by Elsevier Ltd.


Makino K.,Japan Coal Energy Center
Cleaner Combustion and Sustainable World - Proceedings of the 7th International Symposium on Coal Combustion | Year: 2012

Needs for electricity is growing rapidly in many countries and it is expected the increase of electricity by 2030 is almost double. Fossil fuels, renewables, nuclear energy will play leading parts in the future, but fossil power generation will continue to play a major role. Especially, coal will be used continuously due to its stable supply and lower price. However, global warming countermeasures should be considered for large amount of coal use. High efficient systems and Carbon Capture and Storage (CCS) will be most applicable solution for the problems. USC, IGCC and A-USC have higher efficiencies, but costs are normally higher. So it is very important to evaluate the future trend of the plants, that is the cost, performance and the share of each plant. It is also essential to evaluate high efficient plants which will be constructed mainly and which system investment should be paid to. But no less important is to evaluate each system from the neutral position. So Japan Coal Energy Center (JCOAL) constructed its own program to expect the future trend of each plant. JCOAL made a basic concept and the programming was done by SRI International of the United States. The considered systems of coal fired power generation are Supercritical Unit, Ultra Supercritical Unit, Advanced- Supercritical Unit, Integrated Gasification Combined Cycle (IGCC) and Integrated Gasification Fuel Cell (IGFC). In order to compare with the natural gas case, Natural Gas Combined Cycle (NGCC) is included. Evaluation will be done for both without and with CCS cases.This program covers by the year of 2050. The results are trends of following items:- capital cost, operational and maintenance cost, levelized cost of electricity, etc. We can also expect the future share of high efficient coal fired systems by 2050. Here the share will be decided by the levelized cost of electricity. The plant that has the lowest cost will get more share under the scenario of this program. This paper summarizes the program and the results of the evaluation. © Tsinghua University Press, Beijing and Springer-Verlag Berlin Heidelberg 2012.

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