MWe Coal-fired Power Research Articles

A calcium looping process for simultaneous CO2 capture and peak shaving in a coal-fired power plant

CO2 capture and peak shaving are two of the main challenges for coal-fired power plants in China. This paper proposed a calcium looping (CaL) combustion system with cryogenic O2 storage for simultaneous flue gas decarbonization and peak shaving for a 1000 MWe coal-fired power plant. The philosophy of this concept is that: (1) the boiler always operates at maximum continuous rating (MCR) to ensure the highest boiler efficiency; (2) during off-peak times, the excess energy output from coal combustion is used to provide heat for the calciner and produce pure oxygen for energy storage; (3) at peak times, the O2 produced is used to capture CO2 in the flue gas via the CaL process and reduce the CO2 abatement penalty; and (4) any excess O2 is treated as a by-product for commercial utilization. The whole system was simulated in Aspen Plus® which shows that the net electric efficiency of the proposed system without cryogenic O2 storage system is 35.52%LHV (LHV, low heating value), while that of the conventional CaL system is 34.54%LHV. The proposed system can reduce the methane consumption rate by 38.5 t/h when methane is used as fuel in the calciner. Including the cryogenic O2 storage system, the peaking capability of the proposed system can range from 534.6 MWe to 1041 MWe. Correspondingly, the net electric efficiency is improved from 18.98%LHV to 36.97%LHV. Increasing the rate of oxygen production can reduce the minimum net power output to lower than 534.6 MWe. The peaking capability can be regulated by the rate of oxygen production where excess oxygen serves as a byproduct.

Automated process design and optimization of membrane-based CO2 capture for a coal-based power plant

A systematic optimization framework is proposed with the aim to automate the design of multi-stage membrane processes for CO2 capture from flue gas of a coal-fired power plant. This framework utilizes a superstructure approach to determine the optimal configuration of membrane systems and identify the most appropriate operating conditions in a holistic manner. Certain design specifications are satisfied through the use of penalty functions which are used in a Genetic Algorithm (GA) optimization method employed to identify design solutions at or near to the global optimal point. Sensitivity analysis is used to analyze multi-stage membrane designs to understand the effects of different structural and operating parameters on the economics of membrane-based carbon capture. As part of a case study the proposed design framework is applied to design membrane processes for the capture of CO2 from a 600 MWe coal-fired power plant. Fixed membrane permeance and selectivity values are used to analyze sensitivities with respect to costing and structural design parameters. Additionally, the Robeson upper bound correlation between CO2 permeance and CO2/N2 selectivity is used within this framework to identify the optimal membrane properties which give economical separation of CO2 and N2. It is found that membranes having at least 4000 GPU CO2 permeance and over 50 of CO2/N2 selectivity with a commercial available module gave the optimal performance and would be a good guideline for future membrane material development. Also, if different membrane properties are used in each stage (in a multi-stage configuration) then using a higher CO2 permeance for the first stage (e.g. 6000 GPU CO2 permeance and CO2/N2 selectivity of 40) and higher selectivity membranes are used for subsequent downstream membrane stages (e.g. 1334 GPU CO2 permeance and CO2/N2 selectivity of 72) helps to reduce the electricity consumption and product purity which can reduce the overall cost of CO2 capture.

Burner air-fuel ratio monitoring in large pulverised-fuel boilers using advanced sensors: Case study of a 660 MWe coal-fired power plant

In this paper, a novel methodology is proposed for the online monitoring of the air-fuel ratio in large pulverised-fuel boilers at the burner level. Using standard measurements, this parameter can only be estimated, as the fuel distribution between burners is generally missing. The detailed air flow distribution to the burners can also be unknown depending on the available measurements. An accurate control of local and global air-fuel ratios is however crucial in terms of boiler efficiency and various pollutant emission reductions, leading to lower overall operational cost, improved performance and increased fuel and load flexibility. It is here proposed to combine two advanced techniques to quantify air and fuel flow rates per burner: microwave probes for fuel particles and smart soft sensors for air. When combined, those measurements allow for the calculation of the local air-fuel ratios. The proposed methodology was successfully applied to the boiler of a 660 MWe coal-fired power plant. While the burner equivalence ratios predicted by the standard equipments were in the range 0.9-1.05, it was shown that the actual range was significantly broader (0.65-1.25). Looking at the averaged ratios per burner level, it was concluded that the expected values were globally overestimated compared to the measured values (>+14%). The performed air flow measurements were also used to partially tune the combustion process by solving hardware and software issues. Oxygen, flue gas flow rate, temperature and NOx imbalances at the outlet of the furnace were significantly reduced.

On-going and Future Research at the Sulcis Site in Sardinia, Italy – Characterization and Experimentation at a Possible Future CCS Pilot

National Italian funding has recently been allocated for the construction of a 350 MWe coal-fired power plant / CCS demonstration plant in the Sulcis area of SW Sardinia, Italy. In addition, the recently approved EC-funded ENOS project (ENabling Onshore CO2 Storage in Europe) will use the Sulcis site as one of its main field research laboratories. Site characterization is already ongoing, and work has begun to design gas injection experiments at 100-200 m depth in a fault. This article gives an overview of results to date and plans for the future from the Sapienza University of Rome research group.

Integrating geothermal into coal-fired power plant with carbon capture: A comparative study with solar energy

A new system integrating geothermal energy into post-combustion carbon capture is proposed in this paper. Geothermal energy at medium temperatures is used to provide the required thermal heat for solvent regeneration. The performance of this system is compared with solar assisted carbon capture plant via technical and economic evaluation. A 300 MWe coal-fired power plant is selected as the reference case, and two different locations based on the local climatic conditions and geothermal resources are chosen for the comparison. The results show that the geothermal assisted post-combustion carbon capture plant has better performances than the solar assisted one in term of the net power output and annual electricity generation. The net plant average efficiency based on lower heating value can be increased by 2.75% with a thermal load fraction of about 41%. Results of economic assessment show that the proposed geothermal assisted post-combustion carbon capture system has lower levelized costs of electricity and cost of carbon dioxide avoidance compared to the solar assisted post-combustion carbon capture plant. In order to achieve comparative advantages over the reference post-combustion carbon capture plant in both locations, the price of solar collector has to be lower than 70 USD/m2, and the drilling depth of the geothermal well shall be less than 2.1km.

Assessing the feasibility and CO2 storage capacity of CO2 enhanced shale gas recovery using Triple-Porosity reservoir model

The depletion of conventional energy sources is leading to increased demand for unconventional energy sources. Shale gas is an important unconventional energy source that has been successfully developed and utilized in the United States. CO2 enhanced shale gas recovery (CO2-ESG) is a promising shale gas extraction technology. Supercritical CO2 injection can enhance the shale gas recovery through competitive absorption between the methane and the CO2 while also providing CO2 geological sequestration. However, assessments of the feasibility of CO2 enhanced shale gas recovery in field scale trials is quite complicated given the complex pore structures in shale reservoirs and the ultralow permeability. This paper describes a triple porosity, dual permeability (TP-DK) model that includes the effects of the shale gas adsorption and desorption, the competitive adsorption and binary gas diffusion. The Sichuan basin in China is selected as the target reservoir. The key parameters in this simulation were determined by experimental measurements of shale samples from the Lower Silurian Longmaxi Formation (LSLF) shale in the Sichuan basin. The results show that the CO2 injection can significantly enhance the shale gas recovery. A 90m thick shale gas reservoir with a 1200m horizontal well absorb injections of CO2 captured from a large 1000 MWe coal-fired power plant for 2years. However, the volume flow rate of the CO2 sequestration decreased with time as the production pressure decreased. Both the production time and the production pressure should be considered on the synergy between the CO2 sequestration and the shale gas recovery.

Performance and economic assessments of integrating geothermal energy into coal-fired power plant with CO2 capture

A novel carbon capture and storage system integrated with geothermal energy was proposed to reduce energy consumption in the post-combustion CO2 capture (PCC) process. Geothermal energy at medium temperature was used to provide the heat required for solvent regeneration. A technical and economic assessment was conducted based on a 300 MWe coal-fired power plant. Additionally, the integrated system was also compared with a stand-alone geothermal power (GP) plant to evaluate individual advantages. Both an enhanced geothermal system (EGS) and a hot sedimentary aquifer (HSA) reservoir were selected to identify the effect of geological properties and heat characteristics on system performance. The results indicated that the geothermal-assisted post-combustion CO2 capture (GPCC) plant exhibited better performance than the PCC plant. The net plant average efficiency increased 5.56% and 4.42% in the EGS scenario and HSA scenario, respectively. Furthermore, the net incremental geothermal efficiency obtained corresponded to 21.34% and 20.35% in the EGS scenario and HSA scenario, respectively. The economic assessment indicated that the GPCC systems in both the EGS scenario and HSA scenario had lower marginal cost of electricity (70.84 $/MWh and 101.06 $/MWh) when compared with that of the stand-alone GP systems (151.09 $/MWh and 101.95 $/MWh).

Performance evaluation of co-firing various kinds of biomass with low rank coals in a 500 MWe coal-fired power plant

Recently in Korea, the co-firing of biomass in existing pulverized coal power plants has become an important mean to comply with the nation's renewable portfolio standard (RPS). This study investigated boiler efficiency, net plant efficiency, and combustion characteristics from co-firing various biomasses along with two coal blends and the combustion of low rank coals through process simulation based on an existing 500 MWe coal fired power plant using a commercial process simulator (gCCS). Five sources of biomass - wood pellet, empty fruit bunch pellet, palm kernel shell, walnut shell, and torrefied biomass were selected as renewable fuels for co-firing. In addition, hardgrove grindability index tests were conducted for a blend of coal (90%) and each selected biomass (10%) based on thermal share input to investigate the milling power consumption of each blended fuel for a more rigorous simulation. The results show quantitatively that when biomass is co-fired the plant efficiency is decreased due to its lower heating value and more power consumption in mills. The plant efficiency of torrefied biomass co-firing was the highest among all biomass co-firing and combustion of low rank coals due to higher energy density and enhanced grindability of torrefied biomass after torrefaction.

Power Generation From Coal Mill Rejection Using Kalina Cycle

This paper proposes an ammonia–water Kalina cycle driven by low-grade waste energy released from the combustion reactions of mill's rejection which is coupled with 500 MWe coal-fired thermal power plant to quantify the additional electrical power. Energy of combustion for mill rejection is computed by combustion modeling equations. A thermodynamic property calculator for the binary mixture and a computer simulation program have been developed by MS-Excel and Visual Basic for Application (VBA) to calculate and optimize the Kalina cycle operating parameters based on thermodynamic modeling equations. Variation of key operating parameters, namely, turbine inlet pressure, mass flow rate of binary mixture, and ammonia mass fraction in mixture is studied and filters the optimum value accordingly to maximize the cycle efficiency. Techno-commercial feasibility is also done through economic analysis. The results show that about 562.745 kWe power generation can be added with total plant generation for organization profit. This will enhance the combined plant efficiency from 38.559% to 38.604%. Maximum net Kalina cycle efficiency of 24.74% can be achieved with ammonia mass fraction of 0.4 at condenser back pressure of 1.957 bar and turbine inlet pressure and temperature of 20 bar and 442.40 K, respectively. Ammonia mass fraction of 0.4 is the optimum choice for 20 bar turbine inlet pressure to get maximum output after maintaining minimum 50 K degree of superheat compared to ammonia mass fraction of 0.3. The cycle performance at ammonia mass fraction of 0.4 is better than 0.5 due to less condenser back pressure. Kalina cycle operating with less mass flow rate performs higher cycle efficiency when dryness fraction at turbine exhaust is less than 1 and performance deteriorates at above 1. This deterioration is due to higher condenser energy loss carried away by cooling water (CW) flow. The simple payback period of this system is around 5.5 years if the system is running with 80% plant availability factor and 100% plant load factor.

Online monitoring of coal particle size and flow distribution in coal-fired power plants: Dynamic effects of a varying mill classifier speed

The fineness of the coal powder and the uniformity of the coal flow sent to the burners are crucial parameters to achieve an effective combustion in coal-fired power plants. This study presents a methodology for the online monitoring of the (i) coal particle size distribution and (ii) coal flow distribution between burners at the outlet of a roller mill installed in 660 MWe coal-fired power plant. The effect of a varying centrifugal classifier speed on these two properties was investigated. To the best knowledge of the authors, it is the first time that such an effect is monitored online in a large scale utility boiler. For a classifier speed between 73 and 99 rpm, the mass fraction of particles smaller than 75 µm varied between 66 and 74%. The coal flow distribution between burners was strongly improved when the particle size was the smallest: the maximum deviation from the average flow rate was reduced from 14% at 73 rpm to 9% at 99 rpm.

Integration Options and Economic Analysis of an Integrated Chemical Looping Air Separation Process for Oxy-fuel Combustion

This paper is concerned about a detailed techno-economic assessment of a hypothetical 500 MWe coal-fired power plant in New South Wales, Australia, for oxy-fuel conversion using integrated chemical looping air separation (ICLAS) technology and cryogenic air separation unit (CASU). The key objectives of this study are to (i) investigate and compare the detailed integration options for oxy-fuel conversion using ICLAS and CASU and (ii) determine the technical merits of the above integration options and the conditions at which the technologies become economically feasible. The study produced scientific evidence that confirms the viability of the CLAS process from both technical and economic points of view under certain conditions. The detailed technical analysis revealed that ICLAS with natural gas integration is energy-efficient compared to CASU running on parasitic load. This is primarily due to the fact that ICLAS needs less auxiliary power compared to CASU. Despite the fact that ICLAS natural gas integrat...

Comparative prediction analysis of 600 MWe coal-fired power plant production rate using statistical and neural-based models

Electrical energy is a crucial phenomenon for daily human life & industry, and various types of production plants such as nuclear, thermal, wind, geothermal, hydro, biomass, solar, etc. are developed with distinct advantages and disadvantages recently. Overall production cost is a significant constraint for the power plants and serious optimization problem to be solved in terms of productivity, hence technical, economical and environmental aspects should be considered due to raw material and fuel prices, NOx, SOx and CO2 emission regulations, operational costs and thermodynamic efficiency constraints in the operation. In this research, production rate of a coal-fired thermal power plant is modeled and predicted using Artificial Neural Networks (ANN), Autoregressive Integrated Moving Average (ARIMA) and Multiple Linear Regression (MLR) algorithms selecting appropriate process parameters those effect total amount of generator production output rate. All data was collected from the 600 MWe ICDAS Coal-fired Thermal Power Plant located in the region of Marmara, Turkey during 3 months of operation obtaining the consolidated control system data and reports. The selected performance criterion, regression coefficient and root mean squared error, is found satisfactory after the analysis of computational results and it is seen that the ANN model shows better prediction performance against the MLR and ARIMA approaches in this case study.

Process simulation of co-firing torrefied biomass in a 220 MWe coal-fired power plant

Torrefaction based co-firing in a pulverized coal boiler has been proposed for large percentage of biomass co-firing. A 220MWe pulverized coal-power plant is simulated using Aspen Plus for full understanding the impacts of an additional torrefaction unit on the efficiency of the whole power plant, the studied process includes biomass drying, biomass torrefaction, mill systems, biomass/coal devolatilization and combustion, heat exchanges and power generation. Palm kernel shells (PKS) were torrefied at same residence time but 4 different temperatures, to prepare 4 torrefied biomasses with different degrees of torrefaction. During biomass torrefaction processes, the mass loss properties and released gaseous components have been studied. In addition, process simulations at varying torrefaction degrees and biomass co-firing ratios have been carried out to understand the properties of CO2 emission and electricity efficiency in the studied torrefaction based co-firing power plant. According to the experimental results, the mole fractions of CO2 and CO account for 69–91% and 4–27% in torrefied gases. The predicted results also showed that the electrical efficiency reduced when increasing either torrefaction temperature or substitution ratio of biomass. A deep torrefaction may not be recommended, because the power saved from biomass grinding is less than the heat consumed by the extra torrefaction process, depending on the heat sources.

Thermal Performance and Economic Analysis of 210 MWe Coal-Fired Power Plant

This paper presents the thermal and economic performance of a 210 MWe coal-fired power plant situated in North India. Analysis is used to predict coal consumption rate, overall thermal efficiency, mass flow rate of steam through boiler, and Net present value (NPV) of plant for given load. Thermodynamic analysis was carried out using mass and energy equations followed by empirical correlations. Predicted mass flow rate of steam, coal consumption rate, and thermal efficiency give fair agreement with plant operating data. The economic analysis includes operational activities such as equipment cost, fuel cost, operations and maintenance cost, revenue, and plant net present value. From economic point of view, the effect of condensate extraction pump redundancy on net present value is observed to be sensitive than boiler feed pump redundancy.

Techno-economic Study of Solar-assisted Post-combustion Carbon Capture System Integrated with Desalination

Solvent-based Post-combustion Carbon Capture (PCC), which can reduce CO2 emissions from coal-fired power plants, is one of the most advanced mature Carbon Capture and Storage (CCS) technologies at present. Two problems limit its development. One is the output reduction of power plant due to the steam extraction from turbine. The other is a large amount of water consumption for the evaporation of the solution in the absorber and desorber.In this paper we propose an integrated system to reduce the steam extraction from turbine and to produce freshwater by using solar thermal energy. The new system produces more electricity and freshwater during the daytime, and uses the steam extraction to reduce CO2 emissions at night. A techno-economic feasibility study is performed as a case study for a 300 MWe coal-fired power plant assisted by solar desalination. As for the potential impact parameters, the local climatic conditions and CO2 capture rate are discussed. Low-cost collectors and desalting equipment would make the technology more cost-effective.

Performance analysis of a 500 MWe coal-fired power plant with a post-combustion CO2 capture process

In this study, a performance analysis of a 500 MWe coal-fired power plant with a post-combustion CO2 capture system was performed. The amine-based chemical absorption process was considered as a base CO2 capture system. Based on the design conditions of the flue gas from the supercritical coal-fired power plant operating in the Republic of Korea, the energy consumption of the CO2 capture system was simulated using a process simulator. The simulation of the CO2 capture system was undertaken using Aspen Plus software with ELECNRTL property packages; based on these results, the energy requirement of the CO2 capture system and the overall efficiency of a power plant with the CO2 capture system was estimated. It was observed that the thermal energy required to regenerate the solvent reduces the efficiency of the power plant by 8.36%, the energy required to compress the CO2 from 0.1 to 11 MPa is the next largest factor, reducing the efficiency by 3.59%, and the other energy requirement amounts to 0.45%.

4-E (Energy-Exergy-Environment-Economic) Analysis of Stand-Alone Solar Thermal Power Plants and Solar-Coal Hybrid Power Plants

This article deals with 4-E (energy-exergy- environment-economic) analysis of stand-alone solar thermal power plants (SASTPs) to establish their techno economic feasibility in comparison with coal-fired (CFPs) and solar-coal hybrid power (SCHPs) plants. The analysis is carried out out for various plant capacities ranging 1- 50 MWe considering a 50 MWe coal-fired power cycle as reference. The plant energy efficiency of SASTPs without thermal energy storage is compared to CFPs. The inclusion of thermal storage in SASTPs reduces plant energy and exergy efficiencies. The CO2 emission and ash production for a 50 MWe SCHP are less by 0.3 kg/kWh and 8400 tons/year, respectively, as compared to CFP. The levelized cost of electricity (LCoE) of a reference plant is Rs. 2.75/kWh whereas the LoE is higher by Rs. 10.59- 11.30/kWh and Rs. 2.10/kWh, respectively, for SASTPs and SCHPs. The plant energy and exergy efficiencies decrease by 3 to 4 percentage points for 1 MW power plants.

연소 후 CO2포집공정이 적용된 500MWe 석탄화력발전소의 성능 및 경제성평가

연소 후 <TEX>$CO_{2}$</TEX> 포집기술이 적용된 500 MWe 석탄화력발전소의 경제성평가를 수행하고 <TEX>$CO_{2}$</TEX> 저감비용(Cost of <TEX>$CO_{2}$</TEX> avoided)을 산출하였다. 본 연구에서 고려된 <TEX>$CO_{2}$</TEX> 포집기술은 이미 상업적으로 적용이 가능하고, 기존의 화력발전에 적용이 용이한 화학 흡수법을 기초로 하였으며 투자비용 산출을 위해 IEA Greenhouse Gas R&D Programme에서 제시하는 데이터를 활용하였다. 또한 <TEX>$CO_{2}$</TEX> 포집공정 중 가장 많은 발전효율 저하를 가져오는 재열기(리보일러)에 투입되는 열에너지(재생에너지)를 대상으로 민감도분석을 수행하고 각각의 경우에서의 <TEX>$CO_{2}$</TEX> 저감비용을 산출하였다. 분석결과 <TEX>$CO_{2}$</TEX> 포집공정에 적용될 흡수제로 MEA(모노에탄올아민)가 사용되고 재생탑에서 필요한 재생에너지가 3.31 GJ/ton<TEX>$CO_{2}$</TEX> 인 경우 발전효율은 <TEX>$CO_{2}$</TEX> 포집설비 설치 전의 41.0에서 31.6%로 9.4% 감소하고 이때의 <TEX>$CO_{2}$</TEX> 저감비용은 43.3 $/ton<TEX>$CO_{2}$</TEX> 로 산출되었다. 그러나, 흡수제 재생에너지를 변수로 한 민감도분석에서 재생에너지가 2.0 GJ/ton<TEX>$CO_{2}$</TEX>로 낮아질 경우 <TEX>$CO_{2}$</TEX> 저감비용은 36.7 $/ton<TEX>$CO_{2}$</TEX>까지 낮아질 것으로 분석되었다. In this study, performance and economic analysis of 500 MWe coal-fired power plant with <TEX>$CO_{2}$</TEX> capture process was performed. For this purpose, chemical absorption method which is commercially available and most suitable for thermal power plant was studied and a criteria for technical and economic assessment of power plants suggested by IEA Greenhouse Gas R&D Programme was used. And we performed the sensitivity analysis focused on regeneration energy which exceed half of the total capture energy. Based on MEA(Monoethanoleamine) as a main chemical solvent and 3.31 GJ/ton<TEX>$CO_{2}$</TEX> regeneration energy in the stripper, net power efficiency was reduced from 41.0% (no capture) to 31.6%(with capture) and the cost of <TEX>$CO_{2}$</TEX> avoided was estimated 43.3 $/ton<TEX>$CO_{2}$</TEX>. And in case of 2.0 GJ/ton<TEX>$CO_{2}$</TEX> regeneration energy, the cost of <TEX>$CO_{2}$</TEX> avoided was calculated as 36.7 $/ton<TEX>$CO_{2}$</TEX>.

Optimum design and control of amine scrubbing in response to electricity and CO2 prices

Abstract This paper presents steady state and dynamic modelling of post combustion CO 2 capture using 30 wt% MEA integrated with models of CO 2 compression and the steam power cycle. It uses multivariable optimization tools to maximize hourly profit of a 100 MWe coal-fired power plant. Steady state optimization for design provided optimum lean loading and CO 2 removal as a function of price ratio (CO 2 price/electricity price). The results indicated that for price ratio between 2.1 and 7, the plant should be designed at removal between 70% and 98% and lean loading in the range of 0.22–0.25. Dynamic optimization determined the operation of the capture system in response to two partial load scenarios (reboiler steam load reduction and power plant boiler load reduction) and provided optimum set points for steam rate, solvent circulation rate and stripper pressure control loops. Maximum profit is maintained by allowing the stripper pressure to drop and implementing a ratio control between solvent and steam rate (and flue gas rate for partial boiler load operation).

HEN optimization for efficient retrofitting of coal-fired power plants with post-combustion carbon capture

This study aims at reducing the energy penalty burdened by integration of pulverized coal-fired power plants with solvent-based post-combustion carbon capture (PCC) processes via heat exchanger network (HEN) optimization. The base case used is a 300 MWe coal-fired power plant burning pulverized black coal and emitting 256 tonnes/h of CO 2. Integration of the base case with PCC showed that achieving 90% CO 2 capture with purity of 99% using 30 wt% monoethanolamine (MEA) solvent admits an energy penalty of 19.4% to the overall plant output. Pinch analysis showed that a reduction in the mentioned energy penalty down to 15.9% can be achieved via integration.