10-MW Plant Research Articles

Exploring the capacity and economic viability of green hydrogen production by utilising surplus energy from wind farms and small hydropower plants in Southern Brazil

This study seeks to estimate the potential hydrogen production from the remaining energy in the small hydropower plants (SHPs). SHPs are plants with a reservoir of three-square miles and an installed capacity between 1 and 30 MW and wind plants in the south of Brazil. Subsequently, to evaluate the generation of chemical and electrical energy and the amount of stored hydrogen and to determine possible applications in the transport sector and its injection into the natural gas network of the regional mesh. Moreover, scenarios 1 and 2 represented 5% and 3% of the surplus power for hydrogen production. The results indicated that green hydrogen production from the remaining energy in the small hydroelectric and wind power plants proved viable. There was an average potential of 5.95 MNm3/day in SHPs and 7.66 MNm3/day in wind farms. Furthermore, the wind farms could generate an average of 16,000 MWh/day through H2 production, while the SHPs have the potential to produce an average of 9340 MWh/day. Further, the proposed scenarios were economically viable since the profit estimated ranged from 27.13 to 617.92 U$/kg in wind farms and from 162.87 to 342.42 U$/kg in SHPs.

A detailed GIS based assessment of bioenergy plant locations using location-allocation algorithm

Logistics plays a crucial role in the operation and planning of biogas plants. To achieve better economic returns and develop effective waste management strategies, optimizing the location of these plants is essential. Geographical Information Systems (GIS) have proven to be a valuable tool for evaluating plant locations and logistics. In this study, a detailed GIS-based mapping of energy sources and plant location optimization was conducted for the Meric-Ergene basin in Northwestern Turkey. This region is well-known for its intensive livestock activities; cattle manure and sewage sludge are considered as energy sources. The model used in this study takes into account various factors, including infrastructural, environmental, and regulatory constraints, transportation distances and costs. Three different scenarios were developed for installed capacities of 5 MW, 1.7 MW, and 1 MW. An energy density map was generated using kernel density interpolation, and the plant locations were determined by solving the location-allocation problem for each scenario. The total energy potential of the study area resulting from cattle manure and sewage sludge was found to be 23.6 MWh per hour. To utilize all the energy sources considered in the study, five plants with a capacity of 5 MW should be constructed. However, when the installed capacity was reduced to 1.7 MW, the number of required plants increased to 14, and for an installed capacity of 1 MW, 24 plants were necessary. The model output revealed that transportation costs increased more than tenfold when installed capacity was increased from 1 MW to 5 MW. Along with transportation costs, the maximum transportation distance should be increased from 40 km to 100 km to cover all energy sources for 5 MW plants. Therefore, it was concluded that installed capacities of 1.7 MW and 1 MW were more suitable than that of 5 MW, considering economic and environmental concerns.

Large-scale solar system design, optimal sizing and techno-economic-environmental assessment

Malaysia targets to achieve an energy mix that is inclusive of at least 20% of renewable energies by the year 2025. Large-scale solar photovoltaic system (LSS-PV) emerged as the most preferable choice in Malaysia. Energy Commission (EC) Malaysia has launched competitive bidding on LSS since 2016 with a capacity of 500 MW in Peninsular Malaysia and targets to add the solar capacity in Peninsula Malaysia to 500 MW by 2021. Solar energy is a very intermittent source which causes voltage variation. This project aims to overcome the shortcomings of the intermittency of solar energy by identifying an optimum PV panel sizing and configuration that reduces the intermittency of the supply. The project was carried out in three distinctive stages; first suitable sites were selected based on the EC proposed locations and further scrutinized to locations near the Main Transmission intake. The second stage was to size of PV panels and the inverters. The optimization was carried out at the PV module level. Suitable inverters for the said configuration was identified with a tool that evaluates the technical aspects of renewable energy power systems. The final stage was the economic analysis and environmental assessment. The optimization method has shown improvement in the system production from a range of 1.7–3.9% in the 30 MW plants. Countries with similar climates as Malaysia like Indonesia, Philippines and Thailand can adopt this optimizing method to size PV farms.

Economic Feasibility of Thermal Energy Storage-Integrated Concentrating Solar Power Plants

Concentrating solar power (CSP) is a high-potential renewable energy source that can leverage various thermal applications. CSP plant development has therefore become a global trend. However, the designing of a CSP plant for a given solar resource condition and financial situation is still a work in progress. This study aims to develop a mathematical model to analyze the levelized cost of electricity (LCOE) of Thermal Energy Storage (TES)-integrated CSP plants in such circumstances. The developed model presents an LCOE variation for 18 different CSP configurations with TES incorporated for Rankine, Brayton, and combined power generation cycles, under regular TES materials and nano-enhanced TES materials. The model then recommends the most economical CSP plant arrangement. Within the scope of this study, it was found that the best configuration for electricity generation is a solar power tower with nano-enhanced phase change materials as the latent heat thermal energy storage medium that runs on the combined cycle. This returns an LCOE of 7.63 ct/kWh with a 22.70% CSP plant efficiency. The most favorable option in 50 MW plants is the combined cycle with a regular TES medium, which has an LCOE of 7.72 ct/kWh with a 22.14% CSP plant efficiency.

The geographical location, current state and forecasting of development of renewable energy facilities within Lviv region


 
 
 
 Ukraine, as a member of the European Energy Community, has committed itself to achieve a share of 12 % renewables in its final energy generation by 2025 and a share of at least 25 % by 2035 (including all hydropower and thermal energy capacities). In 2019, the share of renewables in electricity generation in Ukraine was only 4 %. Renewables produce 4 % of total electricity production in Lviv region. According to this indicator, the region is the leader in the Western Ukraine. The paper analyzes the geographical location and the current state of renewable energy facilities in the Lviv region and forecasting their further development. As of July 1, 2020, in Lviv region there are 67 renewable energy facilities with a total capacity of over 310 MW. Most of the renewables supply electricity to the integrated energy system at a “green” tariff. They include two wind power plants with a total capacity of 33.9 MW in Staryy Sambir district; 59 industrial solar power plants with a total capacity of over than 275 MW in 15 administrative districts of Lviv region, Boryslav and Chervonohrad cities; two mini hydropower plants with a total capacity of 0.576 MW in Drohobych and Turka districts; three mini heat and electricity production plants running on biomass and producing electricity and thermal energy (Radekhiv heat and electricity production plant with a capacity of 2.4 MW, other heat and electricity production plants with a total capacity of 3.66 MW); one biomass electricity production plant operating in the Eco-Mit LLC pig farm in the village of Batyatychi in Kamianka-Buzka district. In addition, 985 solar electricity production plants at private households were built in 20 administrative districts and 9 cities in the region. Their total capacity is over 19 MW, which is equivalent to average capacity of one industrial solar electricity production plant. The leader in the number of industrial facilities for renewable energy is Yavoriv district, where almost half of the total renewables’ capacity of Lviv region is concentrated. The largest number of solar electricity production plants of private households is located in Pustomyty and Yavoriv districts, and Lviv city, whereas the lowest number in mountainous areas, particular in Turka and Skole districts. As of January 1, 2020, solar energy constituted 70 % of renewable energy in Lviv region. At the same time, according to the Development Strategy of Lviv region for the period of 2021–2027, the largest share in the structure of electricity production belongs to wind energy. The development of renewable energy in Ukraine depends on the rate of “green” tariff. The actual financial stimulus has led to a rapid increase in the share of renewables in total electricity generation in Ukraine and Lviv region in particular. Promising areas for renewable energy in Lviv region are wind and bioenergy developments.
 
 
 

Adiabatic compressed air energy storage technology

Adiabatic compressed air energy storage technology

Understanding the Hydropower and Potential Climate Change Impact on the Himalayan River Regimes—A Study of Local Perceptions and Responses from Himachal Pradesh, India

The Himalayas have become synonymous with the hydropower developments for larger electricity demands of India’s energy sector. In the Himachal Himalayas though, there are only three large storage dams with more than 1000 megawatts (hereafter MW) capacity that have very serious environmental issues. However, hundreds of small runoff-river hydropower plants across the Himachal Himalayas are a serious threat to the river regimes and Himalayan biota. There are 965 identified hydropower projects (hereafter HPPs) having a potential capacity of 27,436 MW in the Himachal Pradesh as of December 2019 as per the Directorate of Energy of the state. Out of the 965 identified, 216 are commissioned, including less than 5 MW plants, with an installed capacity of 10,596 MW, and were operational by December 2019. Only 58 projects are under construction among the identified with an installed capacity of 2351 MW, 640 projects are in various stages of clearance and investigation with an installed capacity 9260 MW, 30 projects are to be allotted with 1304 MW installed capacity, and merely four projects are disputed/cancelled with installed capacity of 50.50 MW. The large number of HPPs are sanctioned without proper consideration of negative environmental and geohazard impacts on the Himalayan terrestrial biota. In this work, our focus was on the hydropower and climate change impact on the Himalayan river regimes of the Chenab, the Ravi, the Beas, the Satluj, and the Yamuna river basins. We analyzed basin-wise rainfall, temperature, and soil moisture data from 1955 to 2019 to see the trend by applying the Mann–Kendall test, the linear regression model, and Sen’s slope test. A basin-wise hazard zonation map has been drawn to assess the disaster vulnerability, and 12 hydropower sites have been covered through the primary survey for first-hand information of local perceptions and responses owing to hydropower plants.

Cost analysis of carbon capture and storage for current gas‐fired power plants in Nigeria

AbstractThis study examined the cost of adopting carbon capture and storage (CCS) as a technology when retrofitting current gas‐fired plants in Nigeria to reduce CO2 emissions. Studies show that Nigeria has abandoned or depleted oil fields; it has large coal reserves that are potential sites for CO2 storage. Five power plants with capacities of 1074, 675, 624, 480, and 191 MW were studied using the Integrated Environmental Control Model (IECM) 9.5. The IECM 9.5 was calibrated using available data and some default values to model the performance and cost of retrofitting the power plants. The transport and storage system chosen was pipeline and enhance oil recovery (EOR). The results show that net plant efficiency, CO2 emission rate, quantity of CO2 captured, and CCS energy penalty are 35.78 ± 1.69%, 0.0668 ± 0.0138 kg MWh−1, 0.4478 ± 0.0274 kg MWh−1, and 0.2588 ± 0.0386%, respectively. The results also show that total capital requirement, cost of electricity, and percentage increase in cost of electricity were 1888.2 ± 336.9 $ kW−1, 114.44 ± 10.15 $ MWh−1, and 52.04 ± 3.58%, respectively. In the same manner, the cost of CO2 avoided, cost of capture, and added cost of CCS were 84.442 ± 27.73 $ MWh−1, 60.02 ± 22.51 $ tonne−1, and 28.44 ± 10.16 $ MWh−1, respectively. Further analysis shows that it would be advantageous to retrofit 1074 MW plants because this has a 46.51% increase in cost, which is lower than the cost for the other retrofitted plants. The total CO2 emission rate dropped from 0.4282 ± 0.014 to 0.0668 ± 0.0138 kg MWh−1; this drop is significant as it shows that CCS can reduce the amount of CO2 emitted from Nigeria. The study recommends that CCS is a viable CO2 emission‐reduction alternative but incentives must be put in place to cushion the high cost of electricity. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

Emission Factors of NOx, SO2, and PM for Bathing, Heating, Power Generation, Coking, and Cement Industries in Shanxi, China: Based on Field Measurement

Despite rapid development in China, small-scale boilers (SCBs) still occupy a prominent place in industry. Due to the lack of pollutant removal devices (RDs), SCBs emit large quantities of pollutants, which merit increased attention. In this study, various SCBs (operating on coal, gangue, coke oven gas, coal gas, and natural gas) used in bathing, heating, power generation, and coke and cement making were investigated for their SO2, NOx, and PM emission factors (EFs). The EFs were expressed as the emitted pollutant mass associated with fuel consumption (EFI), product yield (EFII), industrial output (EFIII), and power generation (EFIV). Of 17 civil SCBs, 4, 14, and 10 were not equipped with PM, NOx, and SO2 RDs, respectively. Generally, the EFI values for all of the SCBs decreased with increasing coal consumption. The averaged NOx EFI value for the 3 SCBs with installed NOx RDs was 2.00 kg t–1 versus 3.16 kg t–1 for the 17 SCBs. The sulfur content of the coal and the SO2 removal rate were highly influential factors for the SO2 EFI values. The 4 SCBs without PM RDs possessed an average EFI value of 23.9 kg t–1, which was higher than the corresponding 5.41 kg t–1 for the 13 boilers equipped with PM RDs. The EFI, EFII, and EFIV values for 9 coal-fired power plants (PPs) exhibited the same trends, decreasing as the capacity of the PPs increased from 6 to 330 MW, although slightly higher EFs were found for 600 MW plants compared to 330 MW plants. The gas-fired PPs possessed higher NOx EFs than both the coal- and gangue-fired plants, and the gangue-fired PPs displayed significantly higher EFs than coal-fired PPs with the same individual block power capacity. Because flue gas produced in the coking factories was not fully emitted during the combustion process, no correlation existed between the EFs (expressed as EFII and EFIII) and coke production or industrial output. Moreover, due to the lack of NOx RDs, the EFs of NOx were higher than those of SO2 and PM in the coking industry. Among 6 small- and medium-sized cement companies, the factories with lower cement production possessed higher EFI values for PM. A reverse trend was exhibited by the NOx EFI, however, with high combustion temperatures at factories with high production being the possible explanation.

Oxy-combustion Carbon Capture for Pulverized Coal in the Integrated Environmental Control Model

This paper describes the newly-developed techno-economic models of oxy-combustion carbon capture systems for pulverized coal-fired power plants now available in the Integrated Environmental Control Model (IECM) developed and maintained by Carnegie Mellon University. The new model is used in case studies that compare the overall performance and cost of electricity generation for power plants employing either oxy-combustion (oxyfuel) or an amine-based post-combustion process to capture and sequester 90% of the flue gas CO2 emission using a variety of U.S. coals. The probabilistic results for 500 MW plants using three coal types (bituminous, sub-bituminous and lignite) show that the oxyfuel option is cost-competitive or less costly than the post-combustion option, especially for the lower-rank low-sulfur coals. However, oxy-combustion would not be cost-competitive as a compliance option for the recently promulgated New Source Performance Standard (NSPS) for CO2 in the United States, which requires CO2 capture levels well below the capability of current technology. Other case studies show that alternative policy options, such as a tax on CO2 emissions, could incentivize oxy-combustion capture.

Improvement of Energy Efficiency of Boiler Feed Pumps in Thermal Power Plants through Intelligent Prediction and Operational Optimization

This paper describes the various methods for enhancing the energy efficiency of Boiler Feed Pumps (BFP) in thermal power plants. The specific auxiliary power used by BFPs vary between 2.2 to 3.6 % of the total gross energy generation for units ranging from 30 MW to 800 MW units. The average specific power used by BFPs for 210 MW plants is 2.4 to 3.2 % of gross energy generation. The energy efficiency improvement of BFPs by reducing the re-circulation flow, pressure drop across feed water circuit elements, enhancing overall efficiency of BFPs, etc., are discussed with case studies. The implementation of energy conservation measures reduce the average auxiliary power used by BFPs for 210 MW plant from average value of 3.6 to 2.3 % of gross energy generation and release an additional power of about 10.9 MU/year for one 210 MW unit.

Integrated model for power generation from biomass gasification: A market readiness analysis for northwestern Ontario

Biomass gasification, utilized for various energy uses including power generation, provides an attractive option of energysecurity for remote rural communities and simultaneously helps in reducing greenhouse gas emissions. However, widerapplication of biomass gasification technology is limited due to a number of technical and economic challenges. Althougha few studies have developed process-based models for reducing the costs of biomass supply chains through efficient logisticsoperations, there is a dearth of integrated modeling to capture the behaviour of the entire production system. In thispaper an integrated non-linear dynamic mixed-integer programming model, using optimization and simulation techniques,is developed for biomass gasification power plants using General Algebraic Modeling System (GAMS) computersoftware. The major variables considered in the model are harvesting and processing costs, logistic costs for biomass feedstockdelivery and storage, capital costs of power plant, operation and maintenance costs including labour, insurance andcapital financing, and other regulatory costs. The model provides different cost-benefit trajectories depending upon thescale of power generation from biomass gasification, thereby providing the prospective investors with information regardingmarket potential of the technology. The application of the model for setting up of a biomass gasification plant at a typicallocation in northwestern Ontario shows decreasing costs with increasing plant capacity up to 50 MW. The total costper MWh production ranged from CAD 47.65 for a 50-MW plant to CAD 79.55 for a 10M-W plant. Key words: bioenergy, biomass, market potential, modeling, systems analysis

Pilot combined cycle power plant for testing of natural components for thermal-mechanical equipment for ecologically clean 250–300 MW plants with integrated gasification of solid fuel

Pilot combined cycle power plant for testing of natural components for thermal-mechanical equipment for ecologically clean 250–300 MW plants with integrated gasification of solid fuel

Simulated sea level change alters anatomy, physiology, growth, and reproduction of red mangrove (Rhizophora mangle L.).

Tropical coastal forests - mangroves - will be one of the first ecosystems to be affected by altered sea levels accompanying global climate change. Responses of mangrove forests to changing sea levels depend on reactions of individual plants, yet such responses have not been addressed experimentally. We report data from a long-term greenhouse study that assessed physiological and individual growth responses of the dominant neotropical mangrove, Rhizophora mangle, to levels of inundation expected to occur in the Caribbean within 50-100 years. In this study, we grew potted plants in tanks with simulated semidiurnal (twice daily) high tides that approximated current conditions (MW plants), a 16-cm increase in sea level (LW plants), and a 16-cm decrease in sea level (HW plants). The experiment lasted 2½ years, beginning with mangrove seedlings and terminating after plants began to reproduce. Environmental (air temperature, relative humidity, photosynthetically active radiation) and edaphic conditions (pH, redox, soil sulfide) approximated field conditions in Belize, the source locale for the seedlings. HW plants were shorter and narrower, and produced fewer branches and leaves, responses correlated with the development of acid-sulfide soils in their pots. LW plants initially grew more rapidly than MW plants. However, the growth of LW plants slowed dramatically once they reached the sapling stage, and by the end of the experiment, MW plants were 10-20% larger in all measured growth parameters. Plants did not exhibit differences in allometric growth as a function of inundation. Anatomical characteristics of leaves did not differ among treatments. Both foliar C:N and root porosity decreased from LW through MW to HW. Relative to LW and HW plants, MW plants had 1-7% fewer stomata/mm2, 6-21% greater maximum photosynthetic rates, 3-23% greater absolute relative growth rates (RGRs), and a 30% higher RGR for a given increase in net assimilation rate. Reduced growth of R. mangle under realistic conditions approximating future inundation depths likely will temper projected increased growth of this species under concomitant increases in the atmospheric concentration of CO2.

Developments in West Coast Area in 1979

New-field discoveries in California were down in 1979 from the previous year. The total exploratory footage drilled was slightly lower, but the total number of successful exploratory wells was up 19% from 1978. One new oil field and 5 new gas field discoveries were reported in California. None of these discoveries appear to be of major size. During 1979, hydrocarbons were discovered in commercial quantities for the first time in Oregon--the Mist Gas field, in the northwestern corner of the state, in Columbia County. A pipeline was constructed for initial production in late 1979. This discovery has spurred drilling and leasing activity. Mobil drilled a second deep exploratory well in Oregon, to 10,412 ft, which was subsequently abandoned. Only 1 shallow oil and gas explora ory well was drilled in Washington State this year. As yet it has not been completed. Development drilling in California, although down from 1978, continued at an active pace and is related largely to steam-flood projects. Production of oil outstripped additions to reserves by 285.8 million bbl in 1979. Geothermal activity increased in California's Imperial Valley and Geysers area. Southern California Edison Co. has begun construction of a 10-Mw generating plant near Brawley in the Imperial Valley. Two other geothermal projects in the Imperial Valley sponsored by Southern California Edison include the development of a 50-Mw unit near Heber and a prospective 10-Mw plant south of the Salton Sea. Westmoreland Geothermal Associates also have plans to develop a plant in the valley. In the Geysers area, Sacramento Municipal Utility District plans to construct a 55-Mw plant. The Geysers capacity is expected to increase to 1,238 Mw by the end of 1982.