Estimating the health damage costs of syrian electricity generation system using impact pathway approach

Based on the simplified impact pathway approach the environmental impacts from airborne pollutant emissions of Syrian electricity generation system have been assessed and the associated external damage costs to human health have been evaluated. The obtained results indicate that the environmental impacts can add considerable external cost to the typical generation cost. The estimated externalities vary between 2.5 and 0.07 US-cents per generated kWh for heavy fuel oil and NG fired power plants respectively. For the fuel oil fired power plants the resulting external cost, arise mainly from Sulphates impact, amounts to about 25% of the present generation costs. These results indicate the advantage of NG fired power plants as clean generation technology and the necessity of supplying oil fired power plants with SO₂ emission reduction technologies.     

Long-term implications of alternative light-duty vehicle technologies for global greenhouse gas emissions and primary energy demands

This study assesses global light-duty vehicle (LDV) transport in the upcoming century, and the implications of vehicle technology advancement and fuel-switching on greenhouse gas emissions and primary energy demands. Five different vehicle technology scenarios are analyzed with and without a CO₂ emissions mitigation policy using the GCAM integrated assessment model: a reference internal combustion engine vehicle scenario, an advanced internal combustion engine vehicle scenario, and three alternative fuel vehicle scenarios in which all LDVs are switched to natural gas, electricity, or hydrogen by 2050. The emissions mitigation policy is a global CO₂ emissions price pathway that achieves 450 ppmv CO₂ at the end of the century with reference vehicle technologies. The scenarios demonstrate considerable emissions mitigation potential from LDV technology; with and without emissions pricing, global CO₂ concentrations in 2095 are reduced about 10 ppmv by advanced ICEV technologies and natural gas vehicles, and 25 ppmv by electric or hydrogen vehicles. All technological advances in vehicles are important for reducing the oil demands of LDV transport and their corresponding CO₂ emissions. Among advanced and alternative vehicle technologies, electricity- and hydrogen-powered vehicles are especially valuable for reducing whole-system emissions and total primary energy.     

Comparative assessment of future power generation technologies based on carbon price development

The long-term assessment of new electricity generation was performed for various long-run policy scenarios taking into account two main criteria: private costs and external GHG emission costs. Such policy oriented power generation technologies assessment based on carbon price and private costs of technologies can provide information on the most attractive future electricity generation technologies taking into account climate change mitigation targets and GHG emission reduction commitments for world regions.Analysis of life cycle GHG emissions and private costs of the main future electricity generation technologies performed in this paper indicated that biomass technologies except large scale straw combustion technologies followed by nuclear have the lowest life cycle GHG emission. Biomass IGCC with CO₂ capture has even negative life cycle GHG emissions. The cheapest future electricity generation technologies in terms of private costs in long-term perspective are: nuclear and hard coal technologies followed by large scale biomass combustion and biomass CHPs. The most expensive technologies in terms of private costs are: oil and natural gas technologies. As the electricity generation technologies having the lowest life cycle GHG emissions are not the cheapest one in terms of private costs the ranking of technologies in terms of competitiveness highly depend on the carbon price implied by various policy scenarios integrating specific GHG emission reduction commitments taken by countries and climate change mitigation targets.     

World energy analysis: H2 now or later?

This is a study of world energy resource sustainability within the context of resource peak production dates, advanced energy use technologies in the transportation and electricity generation energy use sectors, and alternative fuel production including hydrogen. The finding causing the most concern is the projection of a peak in global conventional oil production between now and 2023. In addition, the findings indicate that the peak production date for natural gas, coal, and uranium could occur by 2050. The central question is whether oil production from non-conventional oil resources can be increased at a fast enough rate to offset declines in conventional oil production. The development of non-conventional oil production raises concerns about increased energy use, greenhouse gas emissions, and water issues. Due to the emerging fossil fuel resource constraints in coming decades, this study concludes that it is prudent to begin the development of hydrogen production and distribution systems in the near-term. The hydrogen gas is to be initially used by fuel cell vehicles, which will eliminate tailpipe greenhouse gas emissions. With a lowering of H₂ production costs through the amortization of system components, H₂ can be an economic fuel source for electricity generation post-2040.     

The long-term life cycle private and external costs of high coal usage in the US

Using four times as much coal in 2050 for electricity production need not degrade air quality or increase greenhouse gas emissions. Current SO_x and NO_x emissions from the power sector could be reduced from 12 to less than 1 and from 5 to 2 million tons annually, respectively, using advanced technology. While direct CO₂ emissions from new power plants could be reduced by over 87%, life cycle emissions could increase by over 25% due to the additional coal that is required to be mined and transported to compensate for the energy penalty of the carbon capture and storage technology. Strict environmental controls push capital costs of pulverized coal (PC) and integrated coal gasification combined cycle (IGCC) plants to $1500–1700/kW and $1600–2000/kW, respectively. Adding carbon capture and storage (CCS) increases costs to $2400–2700/kW and $2100–3000/kW (2005 dollars), respectively. Adding CCS reduces the 40–43% efficiency of the ultra-supercritical PC plant to 31–34%; adding CCS reduces the 32–38% efficiency of the GE IGCC plant to 27–33%. For IGCC, PC, and natural gas combined cycle (NGCC) plants, the carbon dioxide tax would have to be $53, $74, and $61, respectively, to make electricity from a plant with CCS cheaper. Capturing and storing 90% of the CO₂ emissions increases life cycle costs from 5.4 to 11.6 cents/kWh. This analysis shows that 90% CCS removal efficiency, although being a large improvement over current electricity generation emissions, results in life cycle emissions that are large enough that additional effort is required to achieve significant economy-wide reductions in the US for this large increase in electricity generation using either coal or natural gas.     

Baseload electricity from wind via compressed air energy storage (CAES)

This study investigates two methods of transforming intermittent wind electricity into firm baseload capacity: (1) using electricity from natural gas combined-cycle (NGCC) power plants and (2) using electricity from compressed air energy storage (CAES) power plants. The two wind models are compared in terms of capital and electricity costs, CO₂ emissions, and fuel consumption rates. The findings indicate that the combination of wind and NGCC power plants is the lowest-cost method of transforming wind electricity into firm baseload capacity power supply at current natural gas prices (∼$6/GJ). However, the electricity supplied by wind and CAES power plants becomes economically competitive when the cost of natural gas for electric producers is $10.55/GJ or greater. In addition, the Wind-CAES system has the lowest CO₂ emissions (93% and 71% lower than pulverized coal power plants and Wind-NGCC, respectively) and the lowest fuel consumption rates (9 and 4 times lower than pulverized coal power plants and Wind-NGCC, respectively). As such, the large-scale introduction of Wind-CAES systems in the U.S. appears to be the prudent long-term choice once natural gas price volatility, costs, and climate impacts are all considered.     

Internalisation of external cost in the power generation sector: Analysis with Global Multi-regional MARKAL model

The Global MARKAL-Model (GMM), a multi-regional “bottom-up” partial equilibrium model of the global energy system with endogenous technological learning, is used to address impacts of internalisation of external costs from power production. This modelling approach imposes additional charges on electricity generation, which reflect the costs of environmental and health damages from local pollutants (SO₂, NO_x) and climate change, wastes, occupational health, risk of accidents, noise and other burdens. Technologies allowing abatement of pollutants emitted from power plants are rapidly introduced into the energy system, for example, desulphurisation, NO_x removal, and CO₂ scrubbers. The modelling results indicate substantial changes in the electricity production system in favour of natural gas combined cycle, nuclear power and renewables induced by internalisation of external costs and also efficiency loss due to the use of scrubbers. Structural changes and fuel switching in the electricity sector result in significant reduction of emissions of both local pollution and CO₂ over the modelled time period. Strong decarbonisation impact of internalising local externalities suggests that ancillary benefits can be expected from policies directly addressing other issues then CO₂ mitigation. Finally, the detailed analysis of the total generation cost of different technologies points out that inclusion of external cost in the price of electricity increases competitiveness of non-fossil generation sources and fossil power plants with emission control.     

The effects of introducing natural gas in the Canary Islands for electricity generation

This study analyses the economic effects of introducing natural gas in the Canary Islands to generate electricity in combined cycle gas turbine (CCGT) plants. To this end we will evaluate how this measure contributes to achieving the objectives of the islands’ energy policy and we calculate the cost of generating a kWh from this technology. For this calculation we obtain the net present value (NPV) of the total production costs during the economic lifetime of the plant so as to subsequently find the unitary cost per kWh generated. The result obtained indicates that the kWh cost is some 25% lower than the cost of using petroleum derivatives. Additionally, if we consider the positive effect of CO₂ emissions reductions, the cost is 41% lower. The introduction of natural gas will also be a decisive factor in complying with Kyoto requirements and in diversifying supply sources in the Canaries.     

The air quality and human health effects of integrating utility-scale batteries into the New York State electricity grid

In a restructured electricity market, utility-scale energy storage technologies such as advanced batteries can generate revenue by charging at low electricity prices and discharging at high prices. This strategy changes the magnitude and distribution of air quality emissions and the total carbon dioxide (CO₂) emissions. We evaluate the social costs associated with these changes using a case study of 500 MW sodium-sulfur battery installations with 80% round-trip efficiency. The batteries displace peaking generators in New York City and charge using off-peak generation in the New York Independent System Operator (NYISO) electricity grid during the summer. We identify and map charging and displaced plant types to generators in the NYISO. We then convert the emissions into ambient concentrations with a chemical transport model, the Particulate Matter Comprehensive Air Quality Model with extensions (PMCAM_x). Finally, we transform the concentrations into their equivalent human health effects and social benefits and costs. Reductions in premature mortality from fine particulate matter (PM_2.5) result in a benefit of 4.5 ¢ kWh⁻¹ and 17 ¢ kWh⁻¹ from displacing a natural gas and distillate fuel oil fueled peaking plant, respectively, in New York City. Ozone (O₃) concentrations increase due to decreases in nitrogen oxide (NO_x) emissions, although the magnitude of the social cost is less certain. Adding the costs from charging, displacing a distillate fuel oil plant yields a net social benefit, while displacing the natural gas plant has a net social cost. With the existing base-load capacity, the upstate population experiences an increase in adverse health effects. If wind generation is charging the battery, both the upstate charging location and New York City benefit. At $20 per tonne of CO₂, the costs from CO₂ are small compared to those from air quality. We conclude that storage could be added to existing electricity grids as part of an integrated strategy from a human health standpoint.     

Internalizing externalities into capacity expansion planning: The case of electricity in Vietnam

This paper examines the impacts of including external costs such as environmental and health damages from power production on power generation expansion planning in Vietnam. Using the MARKAL model and covering a 20-year period to 2025, the study shows that there are substantial changes in the generation structure in favor of renewable energy technologies and other low emitting technologies. These changes lead to a reduction in fossil fuel requirements, and consequently, a reduction of CO₂, NO_x, SO₂, and PM emissions which could be expected to also reduce the associated environmental and human health impacts. The avoided external costs would be equivalent to 4.4 US cent/kWh. However, these gains are not free as the additional electricity production cost would be around 2.6 US cent/kWh higher if the switch to more expensive, but lower emitting technologies were made. The net benefit of internalizing these externalities is thus around 1.8 US cent/kWh.     

Innovative energy technologies and climate policy in Germany

Due to the size and structure of its economy, Germany is one of the largest carbon emitters in the European Union. However, Germany is facing a major renewal and restructuring process in electricity generation. Within the next two decades, up to 50% of current electricity generation capacity may retire because of end-of-plant lifetime and the nuclear phase-out pact of 1998. Substantial opportunities, therefore, exist for deployment of advanced electricity generating technologies in both a projected baseline and in alternative carbon policy scenarios. We simulate the potential role of coal integrated gasification combined cycle (IGCC), natural gas combined cycle (NGCC), carbon dioxide capture and storage (CCS), and wind power within a computable general equilibrium model of Germany from the present through 2050. These advanced technologies and their role within a future German electricity system are the focus of this paper. We model the response of greenhouse gas emissions in Germany to various technology and carbon policy assumptions over the next few decades. In our baseline scenario, all of the advanced technologies except CCS provide substantial contributions to electricity generation. We also calculate the carbon price where each fossil technology, combined with CCS, becomes competitive. Constant carbon price experiments are used to characterize the model response to a carbon policy. This provides an estimate of the cost of meeting an emissions target, and the share of emissions reductions available from the electricity generation sector.     

The relative contribution of waste heat from power plants to global warming

Evidence on global climate change, being caused primarily by rising levels of greenhouse gases in the atmosphere, is perceived as fairly conclusive. It is generally attributed to the enhanced greenhouse effect, resulting from higher levels of trapped heat radiation by increasing atmospheric concentrations of gases such as CO₂ (carbon dioxide). Much of these gases originate from power plants and fossil fuel combustion. However, the fate of vast amounts of waste heat rejected into the environment has evaded serious scholarly research. While 1 kWh electricity generation in a typical condensing coal-fired power plant emits around 1 kg of CO₂, it also puts about 2 kWh energy into the environment as low grade heat. For nuclear (fission) electricity the waste heat release per kWh is somewhat higher despite much lower CO₂ releases. This paper evaluates the impact of waste heat rejection combined with CO₂ emissions using Finland and California as case examples. The immediate effects of waste heat release from power production and radiative forcing by CO₂ are shown to be similar. However, the long-term (hundred years) global warming by CO₂-caused radiative forcing is about twenty-five times stronger than the immediate effects, being responsible for around 92% of the heat-up caused by electricity production.     

A comparison of electricity and hydrogen production systems with CO2 capture and storage. Part A: Review and selection of promising conversion and capture technologies

We performed a consistent comparison of state-of-the-art and advanced electricity and hydrogen production technologies with CO₂ capture using coal and natural gas, inspired by the large number of studies, of which the results can in fact not be compared due to specific assumptions made. After literature review, a standardisation and selection exercise has been performed to get figures on conversion efficiency, energy production costs and CO₂ avoidance costs of different technologies, the main parameters for comparison. On the short term, electricity can be produced with 85–90% CO₂ capture by means of NGCC and PC with chemical absorption and IGCC with physical absorption at 4.7–6.9 €ct/kWh, assuming a coal and natural gas price of 1.7 and 4.7 €/GJ. CO₂ avoidance costs are between 15 and 50 €/t CO₂ for IGCC and NGCC, respectively. On the longer term, both improvements in existing conversion and capture technologies are foreseen as well as new power cycles integrating advanced turbines, fuel cells and novel (high-temperature) separation technologies. Electricity production costs might be reduced to 4.5–5.3 €ct/kWh with advanced technologies. However, no clear ranking can be made due to large uncertainties pertaining to investment and O&M costs. Hydrogen production is more attractive for low-cost CO₂ capture than electricity production. Costs of large-scale hydrogen production by means of steam methane reforming and coal gasification with CO₂ capture from the shifted syngas are estimated at 9.5 and 7 €/GJ, respectively. Advanced autothermal reforming and coal gasification deploying ion transport membranes might further reduce production costs to 8.1 and 6.4 €/GJ. Membrane reformers enable small-scale hydrogen production at nearly 17 €/GJ with relatively low-cost CO₂ capture.     

Environmental degradation costs in electricity generation: The case of the Brazilian electrical matrix

The main purpose of this paper is to emphasize the importance of including environmental degradation costs in the long-term planning of the Brazilian electricity sector. To this aim, environmental external costs associated to both hydro-power and thermal-power electricity generation are investigated. Monetary valuation methodologies are applied and environmental degradation costs, expressed in per kWh of generated energy, are obtained for the main types of generation sources of the Brazilian electricity matrix. Both local pollution due to particulate matter emissions and global warming effects are assessed. A classification of the sources from the point of view of their impact on the environment is given. Degradation costs associated to the installed capacity expansion in the Brazilian electricity sector during the time horizon 2007–2016 are estimated. These resulting costs represent lower boundary damage estimates associated only with the energy to be generated during the period. Results indicate that local pollution caused by a small number of plants could be even more costly to society than global warming and, also, show the importance of considering not only unitary damage costs but the participation of each source on the generated energy during the time horizon, as a guide to planning and policy making.     

Modeling a clean energy standard for electricity: Policy design implications for emissions,supply, prices,and regions

The electricity sector is responsible for roughly 40% of U.S. carbon dioxide (CO₂) emissions, and a reduction in CO₂ emissions from electricity generation is an important component of the U.S. strategy to reduce greenhouse gas emissions. Toward that goal, several proposals for a clean energy standard (CES) have been put forth, including one espoused by the Obama administration that calls for 80% clean electricity by 2035 phased in from current levels of roughly 40%. This paper looks at the effects of such a policy on CO₂ emissions from the electricity sector, the mix of technologies used to supply electricity, electricity prices, and regional flows of clean energy credits. The CES leads to a 30% reduction in cumulative CO₂ emissions between 2013 and 2035 and results in dramatic reductions in generation from conventional coal. The policy also results in fairly modest increases on national electricity prices, but this masks a wide variety of effects across regions.     

Technical efficiency and CO2 reduction potentials — An analysis of the German electricity and heat generating sector

In this paper, we analyze the technical efficiency and CO₂ reduction potentials of German power and heat plants, using a non-parametric sequential Data Envelopment Analysis. We apply a metafrontier framework to evaluate plant-level efficiency in the transformation of inputs into desirable (energy) and undesirable (CO₂ emissions) outputs, taking into account different fossil fuel generation technologies. We use a unique data set of coal-, lignite-, gas- and biomass-fired power plants from 2003 through 2010 that provides an unbalanced panel of 1459 observations; the results are also checked against a balanced panel with a smaller number of observations. Although we find intra-group differences within energy generation technology, natural gas fired power plants clearly have the highest efficiency. Furthermore, the analysis points to significant savings potentials for CO₂ and fuel-input, and derives policy conclusions for the ongoing electricity sector reformation.     

Multi-criteria evaluation of hydrogen and natural gas fuelled power plant technologies

This paper evaluates nine types of electrical energy generation options with regard to seven criteria. The options use natural gas or hydrogen as a fuel. The Analytic Hierarchy Process was used to perform the evaluation, which allows decision-making when single or multiple criteria are considered.The options that were evaluated are the hydrogen combustion turbine, the hydrogen internal combustion engine, the hydrogen fuelled phosphoric acid fuel cell, the hydrogen fuelled solid oxide fuel cell, the natural gas fuelled phosphoric acid fuel cell, the natural gas fuelled solid oxide fuel cell, the natural gas turbine, the natural gas combined cycle and the natural gas internal combustion engine.The criteria used for the evaluation are CO₂ emissions, NO_X emissions, efficiency, capital cost, operation and maintenance costs, service life and produced electricity cost.A total of 19 scenarios were studied. In 15 of these scenarios, the hydrogen turbine ranked first and proved to be the most preferred electricity production technology. However since the hydrogen combustion turbine is still under research, the most preferred power generation technology which is available nowadays proved to be the natural gas combined cycle which ranked first in five scenarios and second in eight. The last in ranking electricity production technology proved to be the natural gas fuelled phosphoric acid fuel cell, which ranked in the last position in 13 scenarios.     

Dealing with fuel contaminants in biogas-fed solid oxide fuel cell (SOFC) and molten carbonate fuel cell (MCFC) plants: Degradation of catalytic and electro-catalytic active surfaces and related gas purification methods

Fuel cell and hydrogen technologies are re-gaining momentum in a number of sectors including industrial, tertiary and residential ones. Integrated biogas fuel cell plants in wastewater treatment plants and other bioenergy recovery plants are nowadays on the verge of becoming a clear opportunity for the market entry of high-temperature fuel cells in distributed generation (power production from a few kW to the MW scale).High-temperature fuel cell technologies like molten carbonate fuel cells (MCFCs) and solid oxide fuel cells (SOFCs) are especially fit to operate with carbon fuels due to their (direct or indirect) internal reforming capability. Especially, systems based on SOFC technology show the highest conversion efficiency of gaseous carbon fuels (e.g., natural gas, digester gas, and biomass-derived syngas) into electricity when compared to engines or gas turbines. Also, lower CO₂ emissions and ultra-low emissions of atmospheric contaminants (SO_X, CO, VOC, especially NO_X) are generated per unit of electricity output. Nonetheless, stringent requirements apply regarding fuel purity. The presence of contaminants within the anode fuel stream, even at trace levels (sometimes ppb levels) can reduce the lifetime of key components like the fuel cell stack and reformer. In this work, we review the complex matrix (typology and amount) of different contaminants that is found in different biogas types (anaerobic digestion gas and landfill gas). We analyze the impact of contaminants on the fuel reformer and the SOFC stack to identify the threshold limits of the fuel cell system towards specific contaminants. Finally, technological solutions and related adsorbent materials to remove contaminants in a dedicated clean-up unit upstream of the fuel cell plant are also reviewed.     

Role of natural gas in meeting an electric sector emissions reduction strategy and effects on greenhouse gas emissions

With advances in natural gas extraction technologies, there is an increase in the availability of domestic natural gas, and natural gas is gaining a larger share of use as a fuel in electricity production. At the power plant, natural gas is a cleaner burning fuel than coal, but uncertainties exist in the amount of methane leakage occurring upstream in the extraction and production of natural gas. At higher leakage levels, the additional methane emissions could offset the carbon dioxide emissions reduction benefit of switching from coal to natural gas. This analysis uses the MARKAL linear optimization model to compare the carbon emissions profiles and system-wide global warming potential of the U.S. energy system over a series of model runs in which the power sector is required to meet a specific carbon dioxide reduction target across a number of scenarios in which the availability of natural gas changes. Scenarios are run with carbon dioxide emissions and a range of upstream methane emission leakage rates from natural gas production along with upstream methane and carbon dioxide emissions associated with production of coal and oil. While the system carbon dioxide emissions are reduced in most scenarios, total carbon dioxide equivalent emissions show an increase in scenarios in which natural gas prices remain low and, simultaneously, methane emissions from natural gas production are higher.     

Transitioning electricity systems: The environmental benefits and economic cost of repurposing surplus electricity in non-conventional end users

A power grid with a lower global warming impact has the potential to extend its benefits to energy systems that conventionally do not utilize electricity as their primary energy source. This study presents the case of Ontario where the role of complementing policies in transitioning electricity systems is assessed. The policy cost to incentivize surplus low emission electricity via an established mechanism for the transportation sector has been estimated (Electric and Hydrogen Vehicle Incentive Program). It is estimated that the 9056 (4760 battery and 4296 plug-in hybrid) electric vehicles that qualified for incentives from the provincial government at the end of 2016 vehicles cost $732.5-$883.9 to reduce a tonne of CO_2,e emissions over an eight year lifetime. This is then compared with the potential cost incurred by two power to gas energy hubs that utilize clean surplus electricity from the province to offset emissions within the natural gas sector. The use of hydrogen-enriched natural gas and synthetic natural gas (SNG) offsets emissions at $87.8 and $228.7 per tonne of CO_2,e in the natural gas sector. This analysis highlights the potential future costs for incentivizing new clean technologies such as electric vehicles and power to gas energy hubs in jurisdictions with a transitioning electricity system.