Pulverized Coal Power Plants Research Articles

Predictive modeling of a subcritical pulverized-coal power plant for optimization: Parameter estimation, validation, and application

As renewable power generation deployment increases, fossil fuel plants are increasingly required to operate more flexibly. Many coal-fired power plants were originally designed to operate at base load and do not operate optimally at partial load. Predictive first-principles plant-wide models can be employed to identify opportunities for flexibility improvements and diagnose low-load operating issues. This paper describes the application of the Institute for the Design of Advanced Energy Systems Integrated Platform (IDAES) to model and optimize flexible power plant operations. The key benefits of using IDAES are that it provides an open-source, fully equation-oriented modeling framework for efficient modular model construction, reuse, and customization, together with a mathematical optimization framework leveraging powerful, state-of-the-art solvers. The process systems engineering workflow from predictive process simulation to parameter estimation, model validation, and plant optimization is applicable to a variety of existing and next-generation energy systems as well as other chemical and environmental processes. To demonstrate this capability, a physics-based, steady-state model was developed to improve full- and part-load performance of the Escalante Generating Station, a 245 MWe (net) subcritical pulverized coal-fired power plant owned and operated by Tri-State Generation and Transmission Association. Specifically, sixty-nine model parameters were simultaneously estimated from several months of operating data enabling prediction of flow rates, temperatures, pressures, and steam quality throughout the plant. The validated model was leveraged by Escalante to reduce the minimum operating load from 90 MW to 50 MW by diagnosing a low-load water-hammer issue, enabling coal usage and emissions reductions during periods of low power demand. Additionally, opportunities for heat rate reduction (i.e., efficiency improvement) through a steeper sliding-pressure approach to load-following and optimization of other boiler operating variables were also identified and quantified. For example, a potential efficiency improvement of 0.7 percentage points was observed at half-load operation.

Zero- and negative-emissions fossil-fired power plants using CO2 capture by conventional aqueous amines

This work investigated the technical and economic feasibility of achieving zero and negative CO2 emissions in both pulverized coal (PC) and natural gas combined cycle (NGCC) power plants, using conventional amine scrubbing with 30 wt% aqueous monoethanolamine. In this work, we refer to “zero emissions” when the amount of CO2 in the exhaust flue gas is equal to that in the intake combustion air, and “negative emissions” when the amount of CO2 in the exhaust flue gas is less that in the intake combustion air. Increasing CO2 capture from 90% to that at zero-emissions for fossil-fired power plants can reduce global CO2 emissions by up to ∼1 Gt/y for the current global power generation mix. Even higher CO2 capture leads to negative emissions of the power plant with part of the CO2 from the intake air removed along with the fossil-fuel derived CO2. With an absorber configuration including a simple solvent intercooler, both PC and NGCC power plants can achieve zero-emissions with a ∼5% and ∼13% increase in CO2 avoidance costs, compared with the costs at 90% CO2 capture. The larger cost penalty for NGCC was mainly due to a temperature bulge at the absorber top. Replacing the simple solvent intercooler with a pump-around intercooler was able to reduce this cost penalty to ∼8%. Further decarbonization of flue gases from zero-emissions to direct air capture (DAC)-level of negative emissions (∼100 ppmv of CO2 in exhaust gases) has incremental costs of over $1000/t CO2 avoided for both PC and NGCC.

Cost-benefit comparison of carbon capture, utilization, and storage retrofitted to different thermal power plants in China based on real options approach

A trinomial tree model based on a real options approach was developed to evaluate the investment decisions on carbon capture, utilization, and storage (CCUS) retrofitted to the three main types of thermal power plants in China under the same power generation and CO2 emissions levels. The plant types included pulverized coal (PC), integrated gasification combined cycle (IGCC), and natural gas combined cycle (NGCC) plants. We take into account a subsidy policy consistent with the 45Q tax credit of the U.S., as well as uncertainty factors, such as carbon price, technological progress, CO2 geological storage paths, oil price, and electricity price. The results showed that the investment benefit of ordinary NGCC power plants is 93.04 million USD. This provides greater economic advantages than the other two plant types as their investment benefit is negative if the captured CO2 was used for enhanced water recovery (EWR), even if 45Q subsidies are provided. Compared with NGCC + CCUS power plants, PC + CCUS and IGCC + CCUS power plants have more advantages in terms of economic benefits and emission reduction. The 45Q subsidy policy reduced the critical carbon price, which determines the decision to invest or not, by 30.14 USD t−1 for the PC and IGCC power plants and by 15.24 USD t−1 for the NGCC power plants. Nevertheless, only when the subsidy reaches at least 71.84 USD t−1 and the period limit is canceled can all three types of power plants be motivated to invest in CCUS and used the capture CO2 for EWR. Overall, the government should focus on the application of CCUS in coal-fired power plants (in addition to developing gas power generation), especially when CO2 is used for enhanced oil recovery (EOR). The government could introduce fiscal policies, such as 45Q or stronger, to stimulate CCUS technology development in China.

Nano-Scale Rare Earth Distribution in Fly Ash Derived from the Combustion of the Fire Clay Coal, Kentucky

Fly ash from the combustion of eastern Kentucky Fire Clay coal in a southeastern United States pulverized-coal power plant was studied by scanning electron microscopy (SEM), transmission electron microscopy (TEM), and selected area electron diffraction (SAED). TEM combined with elemental analysis via energy dispersive X-ray spectroscopy (EDS) showed that rare earth elements (REE; specifically, La, Ce, Nd, Pr, and Sm) were distributed within glassy particles. In certain cases, the REE were accompanied by phosphorous, suggesting a monazite or similar mineral form. However, the electron diffraction patterns of apparent phosphate minerals were not definitive, and P-lean regions of the glass consisted of amorphous phases. Therefore, the distribution of the REE in the fly ash seemed to be in the form of TEM-visible nano-scale crystalline minerals, with additional distributions corresponding to overlapping ultra-fine minerals and even true atomic dispersion within the fly ash glass.

Improved flexibility and economics of Calcium Looping power plants by thermochemical energy storage

In this work, a Calcium looping (CaL) system including high temperature sorbent storage is presented, allowing to reduce the size of the calciner and the associated capital-intensive equipment (ASU and CPU). Reduction of the capital costs is particularly important for power plants with low capacity factors, which is becoming increasingly frequent for fossil fuel power plants in electric energy mixes with increasing share of intermittent renewables. The process assessment is performed by: (i) defining pulverized coal power plant (PCPP) with CaL capture system with and without sorbent storage and their mass and energy balances at nominal load; (ii) defining a simple method to predict the performance of the plant at part-load; (iii) defining the economic model, including functions for the estimation of the plant equipment cost; (iv) performing yearly simulations of the systems to calculate yearly electricity production, CO2 emissions and levelized cost of electricity for different sizes of the calcination line and the storage system and (v) performing sensitivity analysis with different power production plans and carbon taxes. With this process, optimal size of the calciner and of the storage system minimizing the cost of electricity have been found.The optimal plant design was found to correspond to a solids storage system sized to manage the weekly cycling and a calciner line sized on the average weekly load. However, to avoid excessively large solids storage system, sizing the calciner on the average daily load and the storage system to manage the daily cycling appears more feasible from the logistic viewpoint and leads to minor economic penalty compared with the optimal plant design. For the selected case sized on the daily cycling, reduction of the cost of CO2 avoided between 16% and 26% have been obtained compared to the reference CaL plant without solids storage, for representative medium and low capacity factor scenarios respectively.

유기성폐기물을 이용한 bio-SRF제조 및 미분탄과 혼합연소에 관한 연구

Bio-SRF (Solid Refuse Fuel) pellets was manufactured, in which three types of biomass wastes, i.e., paper sludge, waste coffee ground, and waste wood, were chosen as the raw material and pelletized with several mixing recipes. Physicochemical analysis showed that coffee ground has a high calorific value of 5,800 kcal/kg, which is approximately 50% higher than normal wood. The higher heating value of paper sludge has a wide range from 2,000 to 4,000 kcal/kg according to its generation source company. The more waste coffee ground was used, the weaker strength of the bio-SRF pellet. To manufacture a strong bio-SRF pellet, less than 50% waste coffee ground was desirable in its ingredient recipe. Three types of bio-SRF manufactured with different recipes were co-combusted with a 3~4% mixing ratio of total fuel in a 500 MW commercial pulverized-coal power plant for twelve hours continuously to assess its possibility as a renewable fuel. The data showed that the boiler performance, such as the generated power, carbon residue in bottom ash, and pressure stability in the coal mill, were maintained in the normal state and the air pollutant concentrations, such as NOx, SOx, and dust, in the emission stack were similar to the only coal combustion condition.

Ultra-fine particulate matters (PMs) formation during air and oxy-coal combustion: Kinetics study

Although both air (21O2/N2) and oxy-coal (27O2/CO2) combustion are widely adopted in pulverized coal (PC) fired power plants, the formation mechanisms of ultra-fine PMs during PC char combustion under both atmospheres with various flue gas recirculation (FGR) ratios are still unclear. Moreover, conventional experimental measurement devices cannot provide detailed information on the formation and evolution of the size-number of ultra-fine PMs. Therefore, the formation of ultra-fine PMs during PC char combustion under both atmopspheres with and without FGR are studied by a self-developed Char Burning and Particulate Matters Kinetics model (CBPMK). The PC char shows similar burning temperature and thus ash vaporization rate under both atmospheres, whereas the vaporization amount under oxy-coal combustion atmosphere is lower than that under air combustion atmosphere due to the shortened burnout time caused by CO2 gasification reaction under the former. Consequently, during nucleation and condensation stages (before successive coalescence), both the particle size and number under air combustion atmosphere are higher than those under oxy-coal combustion atmosphere. However, after coalescence, the final particle shows fewer but larger size under oxy-coal combustion atmosphere due to the higher cohesion factor between the smaller sized nucleation particles, which improves particle collision and coalescence. Meanwhile, both mean size and number density of the nucleation particles decrease with increased FGR ratio under both air and oxy-coal combustion atmospheres, however, after coalescence the final PMs show increasing number density and decreasing size. As results, oxy-coal combustion advantages PMs removal through an ash collector, but elevated FGR ratio disadvantages PMs removal. Oxy-coal combustion with low FGR ratio should be recommended in PC thermal and power plants.

Heat Integration of KIERDRY Process with a Power Plant Using gPROMS

In this study, thermal efficiency of power plant has been evaluated by integrating the KIER-developed dry-sorbent CO2 capture process (KIERDRY) with a pulverized coal-fired power plant using a commercial simulator, gPROMS. A simple basic KIERDRY model has been developed and connected it to PCPP (Pulverized Coal Power Plant) example in gCCS, a system modelling tool for support of design and operating decisions across the CCS chain. The PCPP capacity of 500 MWe and the KIERDRY capacity of 150 MW (125 tonCO2/hr based on captured amount) have been set as a base case. We consider HP steam(307 oC, 31bar) and IP steam(461 oC, 14∼14.6bar) as the utility steam of a regenerator in KIERDRY since the steam condition of a regenerator has been set to approximately 14.6∼15bar, saturated. Totally 5 cases have been evaluated: (1-1) Use HP steam, use condensate to make a process steam, and return to condensate(1bar); (1-2) Use HP steam and return to 5th feed water heater(12bar); (2-1) Use IP steam, use condensate to make a process steam, and return to condensate(1bar); (2-2) Use IP steam and return to 5th feed water heater(12bar); (2-3) Use IP steam, do additional heat integration by preheating dry sorbents at loop-seal, and return to 5th feed water heater(12bar). As a result, the condensate generated at the regenerator should be returned to the power plant rather than used to make a process steam, which is supplied as a reactant for the carbonation reaction. Based on several case studies, the reduction of the power output of the PCPP with KIERDRY has been varied from 29.2 MWe(minimum penalty) to 71.7 MWe(maximum penalty). Thus, it can be concluded that the energy penalty of KIERDRY has been significantly reduced by how heat has been integrated with PCPP.

Comparison of Different CO2 Recovery Processes in their Optimum Operating Conditions from a Pulverized Coal Power Plant

To capture CO2, ammonia solution is a good chemical solvent compared to monoethanolamine (MEA) and methyldiethanolamine (MDEA) because its reactivity and its low enthalpy of solution. In the idea of having a relevant comparison, this study compares the different processes using these solvents in their optimal operating conditions. With respect to ammonia, the experimentally determined optimal conditions are: 3 wt%, 303K, 1 atm. The purpose of this study is modelling CO2 capture from a pulverized coal (PC) fired power plant and estimated its efficiency when CO2 capture is integrated. A relevant comparison between ammonia solvent and conventional amines: MEA and MDEA are made. This study has allowed us to select the solvent that reduces the cost of CO2 capture in power plants. The net electrical power of the plant decreased with CO2 capture: from 555.6 MW without capture to 451.9 with NH3 capture, and 385.16 with MEA capture.

Chemical Looping for Pre-combustion and Post-combustion CO2 Capture

In the paper, performance models are developed for two CO2 capture technologies – (a) a chemical looping combustion (CLC) process for pre-combustion CO2 capture from the syngas of a coal-based integrated gasification combined cycle (IGCC) power plant; and (b) a CaL cycle for post-combustion CO2 capture from a pulverized coal (PC) power plant –and used to conduct detailed thermodynamic analyses of IGCC and PC power plants with the respective chemical looping-based CO2 capture processes. Results from the performance models are used to estimate the capital cost ($/kW) and operating cost ($/MWh) of each capture process as well as the complete power plant. Results of the case studies using the techno-economic model indicate that, in terms of performance, both of the chemical looping technologies modelled here are thermodynamically much better than conventional CO2 capture technologies, resulting in lower overall plant energy penalties. However, both the technologies are found to be more capital-intensive. As a result, the overall cost (capital and LCOE) of plants with chemical looping CO2 capture technologies is greater than or similar to the conventional technologies.

Techno-economic Optimization of First Generation Oxy-fired Pulverized-coal Power Plant

In this paper, a holistic approach taking into account process economics is employed in order to assess the true potential of first generation oxy-fired power plants. The proposed methodology is carried out in two-steps. The first step consists in the minimization of the energy penalty: an exergy analysis is performed on a conventional base-case oxy-fired power plant in order to identify the possible improvement paths, including structural modifications and thermal integrations. At the end of this step, the process layout leading to a minimized energy penalty is obtained. However, as the introduction of a process modification impacts the plant's CAPEX, each modification highlighted in the previous step is characterized by a techno-economic criterion in order to determine its profitability in a second step. The marginal cost of electricity production, defined as the ratio between additional CAPEX and the net production increase is used for the process modification assessment.This procedure has been applied on state-of-the-art processes in order to estimate the potential of first generation oxy-combustion power plant. The optimization solely based on an energetic criterion leads to a plant layout with an energy penalty of 6.0%-pts, which represents a 38% reduction (the energy penalty of the base case plant is 9.4%-pts). However, the consideration of economic aspects has highlighted that some of the considered process modifications were not justified on an economic stand point. The optimal oxy-fired power plant, from a techno-economic point of view, exhibits an energy penalty of 6.9%-pts and allows a 20% reduction of the CO2 avoidance cost compared to the base-case oxy-fired plant.

Ability of Two Dam Fine-Grained Sediments to be Used in Cement Industry as Raw Material for Clinker Production and as Pozzolanic Additional Constituent of Portland-Composite Cement

Fine-grained sediment deposition is a phenomenon that occurs at different extents in all the reservoirs. This particle accumulation has to be properly managed, in accordance with the operational needs and the environment. As an extracted and on-land managed sediment has to be considered as a waste material according to both European and French regulations, sustainable reuse options need to be investigated. One of them could be a beneficial reuse as a raw material in cement industry either as partial substitution in Portland clinker raw mix or as a supplementary cementitious material (SCM) after thermal treatment in order to activate its possible pozzolanic activity. Two dredged materials, labelled SEP and STA, both from French hydroelectric reservoirs, are characterized on physical, chemical and mineralogical aspects. SEP is used as raw material partial replacement for clinker synthesis and the other one is calcined in the range 550–1000 °C aiming to obtain a pozzolanic reactive material that could be used as supplementary cementitious material in blended Portland cement. After thermal treatments, the products are characterized and compared to ordinary Portland cement (OPC) and to pozzolanic active materials (fly ash from pulverized-coal power plant). Results showed that each sediment is suitable for the only tested reuse option. For the clinker prepared with SEP sediment, the morphology and the mineralogical composition correspond to those of a typical Portland clinker. Concerning calcined STA pozzolanic activity, the optimum thermal treatment was found to be 900 °C using the chemical Frattini test. Similar compressive strength results were obtained with calcined STA and silico-aluminous fly ash.Graphical

Process simulations of post-combustion CO2 capture for coal and natural gas-fired power plants using a polyethyleneimine/silica adsorbent

The regeneration heat for a polyethyleneimine (PEI)/silica adsorbent based carbon capture system is first assessed in order to evaluate its effect on the efficiency penalty of a coal or natural gas power plant. Process simulations are then carried out on the net plant efficiencies for a specific supercritical 550MWe pulverized coal (PC) and a 555MWe natural gas combined cycle (NGCC) power plant integrated with a conceptually designed capture system using fluidized beds and PEI/silica adsorbent. A benchmark system applying an advanced MEA absorption technology in a NETL report (2010) is used as a reference system. Using the conservatively estimated parameters, the net plant efficiency of the PC and NGCC power plant with the proposed capture system is found to be 1.5% and 0.6% point higher than the reference PC and NGCC systems, respectively. Sensitivity analysis has revealed that the moisture adsorption, working capacity and heat recovery strategies are the most influential parameters to the power plant efficiency. Under an optimal scenario with improvements in increasing the working capacity by 2% points and decreasing moisture adsorption by 1% point, the plant efficiencies with the proposed capture system are 2.7% (PC) and 1.9% (NGCC) points higher than the reference systems.

Carbon capture from pulverized coal power plant (PCPP): Solvent performance comparison at an industrial scale

Coal is the most abundant fossil fuel on the planet. However, power generation from coal results in large amounts of greenhouse gas emissions. Solvent-based carbon capture is a relatively mature technology which can potentially mitigate these emissions. Although, much research has been done on this topic, single-point performance analysis of capture plant and ignoring operational characteristics of the upstream power plant may result in unrealistic performance assessments. This paper introduces a new methodology to assess the performance of CO2 capture solvents. The problem is posed as retrofitting an existing pulverized coal power plant with post-combustion carbon capture using two solvents: CDRMax, a recently developed amine-promoted buffer salt (APBS) solvent by Carbon Clean Solutions Limited (CCSL) and the monoethanolamine (MEA) baseline solvent. The features of interest include model development and validation using pilot plant data, as well as integrated design and control of the capture process. The emphasis is on design and operation of the capture plant, when integrated with the upstream coal-fired power plant, subject to variations in the electricity load. The results suggest that optimal design and operation of capture plant can significantly mitigate the energetic penalties associated with carbon capture form the flue gas, while providing effective measures for comparing solvent performances under various scenarios.

Reassessing the Efficiency Penalty from Carbon Capture in Coal-Fired Power Plants.

This paper examines thermal efficiency penalties and greenhouse gas as well as other pollutant emissions associated with pulverized coal (PC) power plants equipped with postcombustion CO2 capture for carbon sequestration. We find that, depending on the source of heat used to meet the steam requirements in the capture unit, retrofitting a PC power plant that maintains its gross power output (compared to a PC power plant without a capture unit) can cause a drop in plant thermal efficiency of 11.3-22.9%-points. This estimate for efficiency penalty is significantly higher than literature values and corresponds to an increase of about 5.3-7.7 US¢/kWh in the levelized cost of electricity (COE) over the 8.4 US¢/kWh COE value for PC plants without CO2 capture. The results follow from the inclusion of mass and energy feedbacks in PC power plants with CO2 capture into previous analyses, as well as including potential quality considerations for safe and reliable transportation and sequestration of CO2. We conclude that PC power plants with CO2 capture are likely to remain less competitive than natural gas combined cycle (without CO2 capture) and on-shore wind power plants, both from a levelized and marginal COE point of view.

Experimentally determined storage and handling properties of fuel pellets made from torrefied whole-tree pine chips, logging residues and beech stem wood

Torrefaction is currently of interest for the production of a new generation of fuel pellets suitable for increasing co-firing rates at pulverised-coal power plants. However, few results have been reported on properties of pellets which can currently be produced from torrefied materials. This data is required in order to evaluate the suitability of this fuel for its primary application.The objective of this study was to obtain measured results on storage and handling properties of pellets made of torrefied pine, logging residues (with and without wheat flour binder) and beech. Experimental methods, most of which adhere to standard procedures, are described. The measured properties include calorific value, bulk density, durability, hardness and equilibrium moisture content (EMC). Additionally, EMC isotherms of torrefied beech wood are presented. The results are analysed and their influence on the feasibility of large-scale pellet production is discussed. The measured and derived values presented will be of use in determining feasibility of torrefied pellet production in offsetting the use of fossil coal.From the results the following statements can be made regarding produced pellet samples:•Feedstock choice has a strongly influence on properties of torrefied pellets.•Durability of torrefied pellets is problematic compared to wood pellets.•Outdoor heap storage of torrefied pellets is not recommended.•Logging residues do not seem to be an optimal feedstock choice for torrefied pellets.•Wheat flour does not appear suitable as binder for torrefied pellets production due to water absorption.•Pelletising using high die temperature (above 170°C) should be investigated.

Calcium Looping Cycle for CO2 Capture: Performance, Cost And Feasibility Analysis

Abstract Calcium looping (CaL) systems have been proposed as a lower-cost method of CO2 capture for power plants. This paper presents the results of a techno-economic assessment of a CaL system for post-combustion CO2 capture at a pulverized coal (PC) power plant. Comparisons are made with a conventional MEA-based CO2 capture process in terms of performance and cost. Considering the significant quantities of solid flows required for a CaL process, the applicability and operational feasibility of a CaL system for new or existing PC power plants also is studied. It was found that though the CaL system has better performance than the MEA-based CO2 capture process, the capital cost of the power plant and the cost of electricity is much higher than when the MEA-based system is used.

A Novel System for Carbon Dioxide Capture Utilizing Electrochemical Membrane Technology

FuelCell Energy, Inc. (FCE), in collaboration with Pacific Northwest National Laboratory (PNNL) and URS Corporation, is developing a novel Combined Electric Power and Carbon-Dioxide Separation (CEPACS) system, under a contract from the U.S. Department of Energy (DE-FE0007634), to efficiently and cost effectively separate carbon dioxide from the emissions of existing coal fired power plants. The CEPACS system is based on FCE’s electrochemical membrane (ECM) technology utilizing the Company’s internal reforming carbonate fuel cell products carrying the trade name of Direct FuelCell® (DFC®). The unique chemistry of carbonate fuel cells offers an innovative approach for separation of CO2 from existing fossil-fuel power plant exhaust streams (flue gases). The ECM-based CEPACS system has the potential to become a transformational CO2-separation technology by working as two devices in one: it separates the CO2 from the exhaust of other plants such as an existing coal-fired plant and simultaneously produces clean and environmentally benign (green) electric power at high efficiency using a supplementary fuel.The overall objective of this project is to successfully demonstrate the ability of FCE’s electrochemical membrane-based CEPACS system technology to separate ≥ 90% of the CO2 from a simulated Pulverized Coal (PC) power plant flue-gas stream and to compress the captured CO2 to a state that can be easily transported for sequestration or beneficial use. Also, a key project objective is to show, through a Technical and Economic Feasibility Study and bench scale testing (11.7 m2 area ECM), that the electrochemical membrane-based CEPACS system is an economical alternative for CO2 capture in PC power plants, and that it meets DOE objectives for the incremental cost of electricity (COE) for post-combustion CO2 capture.

Two-in-One Fuel Combining Sugar Cane with Low Rank Coal and Its CO2Reduction Effects in Pulverized-Coal Power Plants

Coal-fired power plants are facing to two major independent problems, namely, the burden to reduce CO(2) emission to comply with renewable portfolio standard (RPS) and cap-and-trade system, and the need to use low-rank coal due to the instability of high-rank coal supply. To address such unresolved issues, integrated gasification combined cycle (IGCC) with carbon capture and storage (CCS) has been suggested, and low rank coal has been upgraded by high-pressure and high-temperature processes. However, IGCC incurs huge construction costs, and the coal upgrading processes require fossil-fuel-derived additives and harsh operation condition. Here, we first show a hybrid coal that can solve these two problems simultaneously while using existing power plants. Hybrid coal is defined as a two-in-one fuel combining low rank coal with a sugar cane-derived bioliquid, such as molasses and sugar cane juice, by bioliquid diffusion into coal intrapores and precarbonization of the bioliquid. Unlike the simple blend of biomass and coal showing dual combustion behavior, hybrid coal provided a single coal combustion pattern. If hybrid coal (biomass/coal ratio = 28 wt %) is used as a fuel for 500 MW power generation, the net CO(2) emission is 21.2-33.1% and 12.5-25.7% lower than those for low rank coal and designed coal, and the required coal supply can be reduced by 33% compared with low rank coal. Considering high oil prices and time required before a stable renewable energy supply can be established, hybrid coal could be recognized as an innovative low-carbon-emission energy technology that can bridge the gulf between fossil fuels and renewable energy, because various water-soluble biomass could be used as an additive for hybrid coal through proper modification of preparation conditions.

Bio-coal, torrefied lignocellulosic resources – Key properties for its use in co-firing with fossil coal – Their status

Abstract Bio-coal has received generous amounts of media attention because it potentially allows greater biomass co-firing rates and net CO2 emission reductions in pulverised-coal power plants. However, little scientific research has been published on the feasibility of full-scale commercial production of bio-coal. Despite this, several companies and research organisations worldwide have been developing patented bio-coal technologies. Are the expectations of bio-coal realistic and are they based on accepted scientific data? This paper examines strictly peer-reviewed scientific publications in order to find an answer. The findings to date on three key properties of torrefied biomass are presented and reviewed. These properties are: the mass and energy balance of torrefaction, the friability of the product and the equilibrium moisture content of torrefied biomass. It is these properties that will have a major influence on the feasibility of bio-coal production regardless of reactor technology employed in production. The presented results will be of use in modelling commercial production of bio-coal in terms of economics and green-house gas emission balance.