Time filter

Source Type

Kittas C.,University of Thessaly | Katsoulas N.,University of Thessaly | Bartzanas T.,Institute for Research and Technology | Boulard T.,French National Institute for Agricultural Research | Kacira M.,University of Arizona
Acta Horticulturae | Year: 2014

Greenhouse workers constitute a particularly interesting group, as their exposure to pesticides is not only greater in comparison to outdoor agricultural workers, but also occurs continuously throughout the whole year. In the present paper the dermal and inhalation exposure of greenhouse workers after pesticides application was evaluated based on experimental data from a plastic round arch greenhouse with a tomato crop. For risk assessment of greenhouse workers, the internal exposure, which was estimated based on dermal and inhalation exposure values was compared with the systemic Acceptable Operator Exposure Level. For a greenhouse worker who works 3 h per day the risk index was high, indicating in this way safe re-entry period, after 36 h from the pesticide application. This value was increased to 86 h for a worker who works 6 h per day. The above values have been calculated assuming that the worker does not use any personal protective equipment. With the use of complete equipment for protection, for a worker who works 6 hours per day, the risk index becomes low 2 h after the pesticide application.


Zalavras A.,University of Thessaly | Fatouros I.G.,Democritus University of Thrace | Fatouros I.G.,Institute for Research and Technology | Deli C.K.,University of Thessaly | And 10 more authors.
Oxidative Medicine and Cellular Longevity | Year: 2015

Redox status changes during an annual training cycle in young and adult track and field athletes and possible differences between the two age groups were assessed. Forty-six individuals (24 children and 22 adults) were assigned to four groups: trained adolescents, (TAD, N=13), untrained adolescents (UAD, N=11), trained adults (TA, N=12), and untrained adults (UA, N=10). Aerobic capacity and redox status related variables [total antioxidant capacity (TAC), glutathione (GSH), catalase activity, TBARS, protein carbonyls (PC), uric acid, and bilirubin] were assessed at rest and in response to a time-trial bout before training, at mid- and posttraining. TAC, catalase activity, TBARS, PC, uric acid, and bilirubin increased and GSH declined in all groups in response to acute exercise independent of training status and age. Training improved aerobic capacity, TAC, and GSH at rest and in response to exercise. Age affected basal and exercise-induced responses since adults demonstrated a greater TAC and GSH levels at rest and a greater rise of TBARS, protein carbonyls, and TAC and decline of GSH in response to exercise. Catalase activity, uric acid, and bilirubin responses were comparable among groups. These results suggest that acute exercise, age, and training modulate the antioxidant reserves of the body. © 2015 Athanasios Zalavras et al.


Mazzer H.R.,State University of Maringá | Santos J.C.O.,State University of Maringá | Cabral V.F.,State University of Maringá | Dariva C.,Institute for Research and Technology | And 4 more authors.
Journal of Thermodynamics | Year: 2012

High pressure phase behavior experimental data have been measured for the systems carbon dioxide (CO + 1-butyl-3-methylimidazolium hexafluorophosphate ([bmim] [PF) and carbon dioxide (CO + 1-butyl-3-methylimidazolium hexafluorophosphate ([bmim] [PF) + 1-amino-2-phenoxy-4-hydroxyanthraquinone (C.I. Disperse Red 60). Measurements were performed in the pressure up to 18 MPa and at the temperature (323 to 353 K). As reported in the literature, at higher concentrations of carbon dioxide the phase transition pressure increased very steeply. The experimental data for the binary and ternary systems were correlated with good agreement using the Peng-Robinson equation of state. The amount of water in phase behavior of the systems was evaluated. © 2012 Helen R. Mazzer et al.


News Article | December 31, 2015
Site: www.theenergycollective.com

Ignacio Pérez-Arriaga of the MIT Sloan School of Management and the Institute for Research and Technology at Comillas University in Spain and a team of Comillas and MIT researchers are examining how the large-scale adoption of solar power may affect operations, costs, and other aspects of today’s electric power systems. Photo: Carlos Rosillo Deploying solar power at the scale needed to alleviate climate change will pose serious challenges for today’s electric power system, finds a study performed by researchers at MIT and the Institute for Research and Technology (ITT) at Comillas University in Spain. For example, local power networks will need to handle both incoming and outgoing flows of electricity. Rapid changes in photovoltaic (PV) output as the sun comes and goes will require running expensive power plants that can respond quickly to changes in demand. Costs will rise, yet market prices paid to owners of PV systems will decline as more PV systems come online, rendering more PV investment unprofitable at market prices. The study concludes that ensuring an economic, reliable, and climate-friendly power system in the future will require strengthening existing equipment, modifying regulations and pricing, and developing critical technologies, including low-cost, large-scale energy storage devices that can smooth out delivery of PV-generated electricity. Most experts agree that solar power must be a critical component of any long-term plan to address climate change. By 2050, a major fraction of the world’s power should come from solar sources. However, analyses performed as part of the MIT “Future of Solar Energy” report found that getting there won’t be straightforward. “One of the big messages of the solar study is that the power system has to get ready for very high levels of solar PV generation,” says Ignacio Pérez-Arriaga, a visiting professor at the MIT Sloan School of Management from IIT-Comillas. Without the ability to store energy, all solar (and wind) power devices are intermittent sources of electricity. When the sun is shining, electricity produced by PVs flows into the power system, and other power plants can be turned down or off because their generation isn’t needed. When the sunshine goes away, those other plants must come back online to meet demand. That scenario poses two problems. First, PVs send electricity into a system that was designed to deliver it, not receive it. And second, their behavior requires other power plants to operate in ways that may be difficult or even impossible. The result is that solar PVs can have profound, sometimes unexpected impacts on operations, future investments, costs, and prices on both distribution systems — the local networks that deliver electricity to consumers — and bulk power systems, the large interconnected systems made up of generation and transmission facilities. And those impacts grow as the solar presence increases. To examine impacts on distribution networks, the researchers used the Reference Network Model (RNM), which was developed at IIT-Comillas and simulates the design and operation of distribution networks that transfer electricity from high-voltage transmission systems to all final consumers. Using the RNM, the researchers built — via simulation — several prototype networks and then ran multiple simulations based on different assumptions, including varying amounts of PV generation. In some situations, the addition of dispersed PV systems reduces the distance electricity must travel along power lines, so less is lost in transit and costs go down. But as the PV energy share grows, that benefit is eclipsed by the need to invest in reinforcing or modifying the existing network to handle two-way power flows. Changes could include installing larger transformers, thicker wires, and new voltage regulators or even reconfiguring the network, but the net result is added cost to protect both equipment and quality of service. Figure 1 below presents sample results showing the impact of solar generation on network costs in the United States and in Europe. The outcomes differ, reflecting differences in the countries’ voltages, network configurations, and so on. But in both cases, costs increase as the PV energy share increases from 0 to 30 percent, and the impact is greater when demand is dominated by residential rather than commercial or industrial customers. The impact is also greater in less sunny regions. Indeed, in areas with low insolation, distribution costs may nearly double when the PV contribution exceeds one-third of annual load. The reason: When insolation is low, many more solar generating devices must be installed to meet a given level of demand, and the network needs to be ready to handle all the electricity flowing from those devices on the occasional sunny day. One way to reduce the burden on distribution networks is to add local energy storage capability. Depending on the scenario and the storage capacity, at 30 percent PV penetration, storage can reduce added costs by one-third in Europe and cut them in half in the United States. “That doesn’t mean that deployment of storage is economically viable now,” says Pérez-Arriaga. “Current storage technology is expensive, but one of the services with economic value that it can provide is to bring down the cost of deploying solar PV.” Another concern stems from methods used to calculate consumer bills — methods that some distribution companies and customers deem unfair. Most U.S. states employ a practice called net metering. Each PV owner is equipped with an electric meter that turns one way when the household is pulling electricity in from the network and the other when it’s sending excess electricity out. Reading the meter each month therefore gives net consumption or (possibly) net production, and the owner is billed or paid accordingly. Most electricity bills consist of a small fixed component and a variable component that is proportional to the energy consumed during the time period considered. Net metering can have the effect of reducing, canceling, or even turning the variable component into a negative value. As a result, users with PV panels avoid paying most of the network costs — even though they are using the network and (as explained above) may actually be pushing up network costs. “The cost of the network has to be recovered, so people who don’t own solar PV panels on their rooftops have to pay what the PV owners don’t pay,” explains Pérez-Arriaga. In effect, the PV owners are receiving a subsidy that’s paid by the non-PV owners. Unless the design of network charges is modified, the current controversy over electricity bills will intensify as residential solar penetration increases. Therefore, Pérez-Arriaga and his colleagues are developing proposals for “completely overhauling the way in which the network tariffs are designed so that network costs are allocated to the entities that cause them,” he says. In other work, the researchers focused on the impact of PV penetration on larger-scale electric systems. Using the Low Emissions Electricity Market Analysis model — another tool developed at IIT-Comillas — they examined how operations on bulk power systems, the future generation mix, and prices on wholesale electricity markets might evolve as the PV energy share grows. Unlike deploying a conventional power plant, installing a solar PV system requires no time-consuming approval and construction processes. “If the regulator gives some attractive incentive to solar, you can just remove the potatoes in your potato field and put in solar panels,” Pérez-Arriaga says. As a result, significant solar generation can appear on a bulk power system within a few months. With no time to adjust, system operators must carry on using existing equipment and methods of deploying it to meet the needs of customers. A typical bulk power system includes a variety of power plants with differing costs and characteristics. Conventional coal and nuclear plants are inexpensive to run (though expensive to build), but they don’t switch on and off easily or turn up and down quickly. Plants fired by natural gas are more expensive to run (and less expensive to build), but they’re also more flexible. In general, demand is met by dispatching the least expensive plants first and then turning to more expensive and flexible plants as needed. For one series of simulations, the researchers focused on a power system similar to the one that services much of Texas. Results presented in Figure 2 in the slideshow above show how PV generation affects demand on that system over the course of a summer day. In each diagram, yellow areas are demand met by PV generation, and brown areas are “net demand,” that is, remaining demand that must be met by other power plants. Left to right, the diagrams show increasing PV penetration. Initially, PV generation simply reduces net demand during the middle of the day. But when the PV energy share reaches 58 percent, the solar generation pushes down net demand dramatically, such that when the sun goes down, other generators must go from low to high production in a short period of time. Since low-cost coal and nuclear plants can’t ramp up quickly, more expensive gas-fired plants must cut in to do the job. As a result, when PV systems are operating and PV penetrations are high, prices are low, and when they shut down, prices are high. Owners of PV systems thus receive the low prices and never the high. Moreover, their reimbursement declines as more solar power comes online, as shown by the downward sloping blue curve in Figure 1 in the slideshow above. Under current conditions, as more PV systems come online, reimbursements to solar owners will shrink to the point that investing in solar is no longer profitable at market prices. “So people may think that if solar power becomes very inexpensive, then everything will become solar,” Pérez-Arriaga says. “But we find that that won’t happen. There’s a natural limit to solar penetration after which investment in more solar will not be economically viable.” However, if goals and incentives are set for certain levels of solar penetration decades ahead, then PV investment will continue, and the bulk power system will have time to adjust. In the absence of energy storage, the power plants accompanying solar will for the most part be gas-fired units that can follow rapid changes in demand. Conventional coal and nuclear plants will play a diminishing role — unless new, more flexible versions of those technologies are designed and deployed (along with carbon capture and storage for the coal plants). If high subsidies are paid to PV generators or if PV cost diminishes substantially, conventional coal and nuclear plants will be pushed out even more, and more flexible gas plants will be needed to cover the gap, leading to a different generation mix that is well-adapted for coexisting with solar. A powerful means of alleviating cost and operating issues associated with PVs on bulk power systems — as on distribution networks — is to add energy storage. Technologies that provide many hours of storage — such as grid-scale batteries and hydroelectric plants with large reservoirs — will increase the value of PV. “Storage helps solar PVs have more value because it is able to bring solar-generated electricity to times when sunshine is not there, so to times when prices are high,” Pérez-Arriaga says. As Figure 3 in the slideshow above demonstrates, adding storage makes investments in PV generation more profitable at any level of solar penetration, and in general the greater the storage capacity, the greater the upward pressure on revenues paid to owners. Energy storage thus can play a critical role in ensuring financial rewards to prospective buyers of PV systems so that the share of generation provided by PVs can continue to grow — without serious penalties in terms of operations and economics. Again, the research results demonstrate that developing low-cost energy storage technology is a key enabler for the successful deployment of solar PV power at a scale needed to address climate change in the coming decades. This research was supported by the MIT Future of Solar Energy study and by the MIT Utility of the Future consortium. This article appears in the Autumn 2015 issue of Energy Futures, the magazine of the MIT Energy Initiative.


News Article | December 30, 2015
Site: news.mit.edu

Deploying solar power at the scale needed to alleviate climate change will pose serious challenges for today’s electric power system, finds a study performed by researchers at MIT and the Institute for Research and Technology (ITT) at Comillas University in Spain. For example, local power networks will need to handle both incoming and outgoing flows of electricity. Rapid changes in photovoltaic (PV) output as the sun comes and goes will require running expensive power plants that can respond quickly to changes in demand. Costs will rise, yet market prices paid to owners of PV systems will decline as more PV systems come online, rendering more PV investment unprofitable at market prices. The study concludes that ensuring an economic, reliable, and climate-friendly power system in the future will require strengthening existing equipment, modifying regulations and pricing, and developing critical technologies, including low-cost, large-scale energy storage devices that can smooth out delivery of PV-generated electricity. Most experts agree that solar power must be a critical component of any long-term plan to address climate change. By 2050, a major fraction of the world’s power should come from solar sources. However, analyses performed as part of the MIT "Future of Solar Energy" report found that getting there won’t be straightforward. “One of the big messages of the solar study is that the power system has to get ready for very high levels of solar PV generation,” says Ignacio Pérez-Arriaga, a visiting professor at the MIT Sloan School of Management from IIT-Comillas. Without the ability to store energy, all solar (and wind) power devices are intermittent sources of electricity. When the sun is shining, electricity produced by PVs flows into the power system, and other power plants can be turned down or off because their generation isn’t needed. When the sunshine goes away, those other plants must come back online to meet demand. That scenario poses two problems. First, PVs send electricity into a system that was designed to deliver it, not receive it. And second, their behavior requires other power plants to operate in ways that may be difficult or even impossible. The result is that solar PVs can have profound, sometimes unexpected impacts on operations, future investments, costs, and prices on both distribution systems — the local networks that deliver electricity to consumers — and bulk power systems, the large interconnected systems made up of generation and transmission facilities. And those impacts grow as the solar presence increases. To examine impacts on distribution networks, the researchers used the Reference Network Model (RNM), which was developed at IIT-Comillas and simulates the design and operation of distribution networks that transfer electricity from high-voltage transmission systems to all final consumers. Using the RNM, the researchers built — via simulation — several prototype networks and then ran multiple simulations based on different assumptions, including varying amounts of PV generation. In some situations, the addition of dispersed PV systems reduces the distance electricity must travel along power lines, so less is lost in transit and costs go down. But as the PV energy share grows, that benefit is eclipsed by the need to invest in reinforcing or modifying the existing network to handle two-way power flows. Changes could include installing larger transformers, thicker wires, and new voltage regulators or even reconfiguring the network, but the net result is added cost to protect both equipment and quality of service. Figure 1 below presents sample results showing the impact of solar generation on network costs in the United States and in Europe. The outcomes differ, reflecting differences in the countries’ voltages, network configurations, and so on. But in both cases, costs increase as the PV energy share increases from 0 to 30 percent, and the impact is greater when demand is dominated by residential rather than commercial or industrial customers. The impact is also greater in less sunny regions. Indeed, in areas with low insolation, distribution costs may nearly double when the PV contribution exceeds one-third of annual load. The reason: When insolation is low, many more solar generating devices must be installed to meet a given level of demand, and the network needs to be ready to handle all the electricity flowing from those devices on the occasional sunny day. One way to reduce the burden on distribution networks is to add local energy storage capability. Depending on the scenario and the storage capacity, at 30 percent PV penetration, storage can reduce added costs by one-third in Europe and cut them in half in the United States. “That doesn’t mean that deployment of storage is economically viable now,” says Pérez-Arriaga. “Current storage technology is expensive, but one of the services with economic value that it can provide is to bring down the cost of deploying solar PV.” Another concern stems from methods used to calculate consumer bills — methods that some distribution companies and customers deem unfair. Most U.S. states employ a practice called net metering. Each PV owner is equipped with an electric meter that turns one way when the household is pulling electricity in from the network and the other when it’s sending excess electricity out. Reading the meter each month therefore gives net consumption or (possibly) net production, and the owner is billed or paid accordingly. Most electricity bills consist of a small fixed component and a variable component that is proportional to the energy consumed during the time period considered. Net metering can have the effect of reducing, canceling, or even turning the variable component into a negative value. As a result, users with PV panels avoid paying most of the network costs — even though they are using the network and (as explained above) may actually be pushing up network costs. “The cost of the network has to be recovered, so people who don’t own solar PV panels on their rooftops have to pay what the PV owners don’t pay,” explains Pérez-Arriaga. In effect, the PV owners are receiving a subsidy that’s paid by the non-PV owners. Unless the design of network charges is modified, the current controversy over electricity bills will intensify as residential solar penetration increases. Therefore, Pérez-Arriaga and his colleagues are developing proposals for “completely overhauling the way in which the network tariffs are designed so that network costs are allocated to the entities that cause them,” he says. In other work, the researchers focused on the impact of PV penetration on larger-scale electric systems. Using the Low Emissions Electricity Market Analysis model — another tool developed at IIT-Comillas — they examined how operations on bulk power systems, the future generation mix, and prices on wholesale electricity markets might evolve as the PV energy share grows. Unlike deploying a conventional power plant, installing a solar PV system requires no time-consuming approval and construction processes. “If the regulator gives some attractive incentive to solar, you can just remove the potatoes in your potato field and put in solar panels,” Pérez-Arriaga says. As a result, significant solar generation can appear on a bulk power system within a few months. With no time to adjust, system operators must carry on using existing equipment and methods of deploying it to meet the needs of customers. A typical bulk power system includes a variety of power plants with differing costs and characteristics. Conventional coal and nuclear plants are inexpensive to run (though expensive to build), but they don’t switch on and off easily or turn up and down quickly. Plants fired by natural gas are more expensive to run (and less expensive to build), but they’re also more flexible. In general, demand is met by dispatching the least expensive plants first and then turning to more expensive and flexible plants as needed. For one series of simulations, the researchers focused on a power system similar to the one that services much of Texas. Results presented in Figure 2 in the slideshow above show how PV generation affects demand on that system over the course of a summer day. In each diagram, yellow areas are demand met by PV generation, and brown areas are “net demand,” that is, remaining demand that must be met by other power plants. Left to right, the diagrams show increasing PV penetration. Initially, PV generation simply reduces net demand during the middle of the day. But when the PV energy share reaches 58 percent, the solar generation pushes down net demand dramatically, such that when the sun goes down, other generators must go from low to high production in a short period of time. Since low-cost coal and nuclear plants can’t ramp up quickly, more expensive gas-fired plants must cut in to do the job. As a result, when PV systems are operating and PV penetrations are high, prices are low, and when they shut down, prices are high. Owners of PV systems thus receive the low prices and never the high. Moreover, their reimbursement declines as more solar power comes online, as shown by the downward sloping blue curve in Figure 1 in the slideshow above. Under current conditions, as more PV systems come online, reimbursements to solar owners will shrink to the point that investing in solar is no longer profitable at market prices. “So people may think that if solar power becomes very inexpensive, then everything will become solar,” Pérez-Arriaga says. “But we find that that won’t happen. There’s a natural limit to solar penetration after which investment in more solar will not be economically viable.” However, if goals and incentives are set for certain levels of solar penetration decades ahead, then PV investment will continue, and the bulk power system will have time to adjust. In the absence of energy storage, the power plants accompanying solar will for the most part be gas-fired units that can follow rapid changes in demand. Conventional coal and nuclear plants will play a diminishing role — unless new, more flexible versions of those technologies are designed and deployed (along with carbon capture and storage for the coal plants). If high subsidies are paid to PV generators or if PV cost diminishes substantially, conventional coal and nuclear plants will be pushed out even more, and more flexible gas plants will be needed to cover the gap, leading to a different generation mix that is well-adapted for coexisting with solar. A powerful means of alleviating cost and operating issues associated with PVs on bulk power systems — as on distribution networks — is to add energy storage. Technologies that provide many hours of storage — such as grid-scale batteries and hydroelectric plants with large reservoirs — will increase the value of PV. “Storage helps solar PVs have more value because it is able to bring solar-generated electricity to times when sunshine is not there, so to times when prices are high,” Pérez-Arriaga says. As Figure 3 in the slideshow above demonstrates, adding storage makes investments in PV generation more profitable at any level of solar penetration, and in general the greater the storage capacity, the greater the upward pressure on revenues paid to owners. Energy storage thus can play a critical role in ensuring financial rewards to prospective buyers of PV systems so that the share of generation provided by PVs can continue to grow — without serious penalties in terms of operations and economics. Again, the research results demonstrate that developing low-cost energy storage technology is a key enabler for the successful deployment of solar PV power at a scale needed to address climate change in the coming decades. This research was supported by the MIT Future of Solar Energy study and by the MIT Utility of the Future consortium. This article appears in the Autumn 2015 issue of Energy Futures, the magazine of the MIT Energy Initiative.

Loading Institute for Research and Technology collaborators
Loading Institute for Research and Technology collaborators