Improved accounting of emissions from utility energy storage system operation

Several proposed utility-scale energy storage systems in the U.S. will use the spare output capacity of existing electric power systems to create the equivalent of new load-following plants that can rapidly respond to fluctuations in electricity demand and increase the flexibility of baseload generators. New energy storage systems using additional generation from existing plants can directly compete with new traditional sources of load-following and peaking electricity, yet this application of energy storage is not required to meet many of the Clean Air Act standards required of new electricity generators (e.g., coal- or gas-fired power plants). This study evaluates the total emissions that will likely result from the operation of a new energy storage facility when coupled with an average existing U.S. coal-fired power plant and estimates that the emission rates of SO2 and NOx will be considerably higher than the rate of a new plant meeting Clean Air Act standards, even accounting for the efficiency benefits of energy storage. This study suggests that improved emissions "accounting" might be necessary to provide accurate environmental comparisons between energy storage and more traditional sources of electricity generation.     

Long-Term Energy and Climate Implications of Carbon Capture and Storage Deployment Strategies in the US Coal-Fired Electricity Fleet

To understand the long-term energy and climate implications of different implementation strategies for carbon capture and storage (CCS) in the US coal-fired electricity fleet, we integrate three analytical elements: scenario projection of energy supply systems, temporally explicit life cycle modeling, and time-dependent calculation of radiative forcing. Assuming continued large-scale use of coal for electricity generation, we find that aggressive implementation of CCS could reduce cumulative greenhouse gas emissions (CO(2), CH(4), and N(2)O) from the US coal-fired power fleet through 2100 by 37-58%. Cumulative radiative forcing through 2100 would be reduced by only 24-46%, due to the front-loaded time profile of the emissions and the long atmospheric residence time of CO(2). The efficiency of energy conversion and carbon capture technologies strongly affects the amount of primary energy used but has little effect on greenhouse gas emissions or radiative forcing. Delaying implementation of CCS deployment significantly increases long-term radiative forcing. This study highlights the time-dynamic nature of potential climate benefits and energy costs of different CCS deployment pathways and identifies opportunities and constraints of successful CCS implementation.     

System-wide emissions implications of increased wind power penetration

This paper discusses the environmental effects of incorporating wind energy into the electric power system. We present a detailed emissions analysis based on comprehensive modeling of power system operations with unit commitment and economic dispatch for different wind penetration levels. First, by minimizing cost, the unit commitment model decides which thermal power plants will be utilized based on a wind power forecast, and then, the economic dispatch model dictates the level of production for each unit as a function of the realized wind power generation. Finally, knowing the power production from each power plant, the emissions are calculated. The emissions model incorporates the effects of both cycling and start-ups of thermal power plants in analyzing emissions from an electric power system with increasing levels of wind power. Our results for the power system in the state of Illinois show significant emissions effects from increased cycling and particularly start-ups of thermal power plants. However, we conclude that as the wind power penetration increases, pollutant emissions decrease overall due to the replacement of fossil fuels.     

Net air emissions from electric vehicles: the effect of carbon price and charging strategies

Plug-in hybrid electric vehicles (PHEVs) may become part of the transportation fleet on time scales of a decade or two. We calculate the electric grid load increase and emissions due to vehicle battery charging in PJM and NYISO with the current generation mix, the current mix with a $50/tonne CO(2) price, and this case but with existing coal generators retrofitted with 80% CO(2) capture. We also examine all new generation being natural gas or wind+gas. PHEV fleet percentages between 0.4 and 50% are examined. Vehicles with small (4 kWh) and large (16 kWh) batteries are modeled with driving patterns from the National Household Transportation Survey. Three charging strategies and three scenarios for future electric generation are considered. When compared to 2020 CAFE standards, net CO(2) emissions in New York are reduced by switching from gasoline to electricity; coal-heavy PJM shows somewhat smaller benefits unless coal units are fitted with CCS or replaced with lower CO(2) generation. NO(X) is reduced in both RTOs, but there is upward pressure on SO(2) emissions or allowance prices under a cap.     

Marginal emissions factors for the U.S. electricity system

There is growing interest in reducing emissions from electricity generation in the United States (U.S.). Renewable energy, energy efficiency, and energy conservation are all commonly suggested solutions. Both supply- and demand-side interventions will displace energy-and emissions-from conventional generators. Marginal emissions factors (MEFs) give a consistent metric for assessing the avoided emissions resulting from such interventions. This paper presents the first systematic calculation of MEFs for the U.S. electricity system. Using regressions of hourly generation and emissions data from 2006 through 2011, we estimate regional MEFs for CO(2), NO(x), and SO(2), as well as the share of marginal generation from coal-, gas-, and oil-fired generators. Trends in MEFs with respect to system load, time of day, and month are explored. We compare marginal and average emissions factors (AEFs), finding that AEFs may grossly misestimate the avoided emissions resulting from an intervention. We find significant regional differences in the emissions benefits of avoiding one megawatt-hour of electricity: compared to the West, an equivalent energy efficiency measure in the Midwest is expected to avoid roughly 70% more CO(2), 12 times more SO(2), and 3 times more NO(x) emissions.     

Implications of Near-Term Coal Power Plant Retirement for SO(2) and NO(X) and Life Cycle GHG Emissions

Regulations monitoring SO(2), NO(X), mercury, and other metal emissions in the U.S. will likely result in coal plant retirement in the near-term. Life cycle assessment studies have previously estimated the environmental benefits of displacing coal with natural gas for electricity generation, by comparing systems that consist of individual natural gas and coal power plants. However, such system comparisons may not be appropriate to analyze impacts of coal plant retirement in existing power fleets. To meet this limitation, simplified economic dispatch models for PJM, MISO, and ERCOT regions are developed in this study to examine changes in regional power plant dispatch that occur when coal power plants are retired. These models estimate the order in which existing power plants are dispatched to meet electricity demand based on short-run marginal costs, with cheaper plants being dispatched first. Five scenarios of coal plant retirement are considered: retiring top CO(2) emitters, top NO(X) emitters, top SO(2) emitters, small and inefficient plants, and old and inefficient plants. Changes in fuel use, life cycle greenhouse gas emissions (including uncertainty), and SO(2) and NO(X) emissions are estimated. Life cycle GHG emissions were found to decrease by less than 4% in almost all scenarios modeled. In addition, changes in marginal damage costs due to SO(2), and NO(X) emissions are estimated using the county level marginal damage costs reported in the Air Pollution Emissions Experiments and Policy (APEEP) model, which are a proxy for measuring regional impacts of SO(2) and NO(X) emissions. Results suggest that location specific parameters should be considered within environmental policy frameworks targeting coal plant retirement, to account for regional variability in the benefits of reducing the impact of SO(2) and NO(X) emissions.     

Costs of Solar and Wind Power Variability for Reducing CO(2) Emissions

We compare the power output from a year of electricity generation data from one solar thermal plant, two solar photovoltaic (PV) arrays, and twenty Electric Reliability Council of Texas (ERCOT) wind farms. The analysis shows that solar PV electricity generation is approximately one hundred times more variable at frequencies on the order of 10(-3) Hz than solar thermal electricity generation, and the variability of wind generation lies between that of solar PV and solar thermal. We calculate the cost of variability of the different solar power sources and wind by using the costs of ancillary services and the energy required to compensate for its variability and intermittency, and the cost of variability per unit of displaced CO(2) emissions. We show the costs of variability are highly dependent on both technology type and capacity factor. California emissions data were used to calculate the cost of variability per unit of displaced CO(2) emissions. Variability cost is greatest for solar PV generation at $8-11 per MWh. The cost of variability for solar thermal generation is $5 per MWh, while that of wind generation in ERCOT was found to be on average $4 per MWh. Variability adds ～$15/tonne CO(2) to the cost of abatement for solar thermal power, $25 for wind, and $33-$40 for PV.     

Are renewables portfolio standards cost-effective emission abatement policy?

Renewables portfolio standards (RPS) could be an important policy instrument for 3P and 4P control. We examine the costs of renewable power, accounting for the federal production tax credit, the market value of a renewable credit, and the value of producing electricity without emissions of SO2, NOx, mercury, and CO2. We focus on Texas, which has a large RPS and is the largest U.S. electricity producer and one of the largest emitters of pollutants and CO2. We estimate the private and social costs of wind generation in an RPS compared with the current cost of fossil generation, accounting for the pollution and CO2 emissions. We find that society paid about 5.7 cent/kWh more for wind power, counting the additional generation, transmission, intermittency, and other costs. The higher cost includes credits amounting to 1.1 cent/kWh in reduced SO2, NOx, and Hg emissions. These pollution reductions and lower CO2 emissions could be attained at about the same cost using pulverized coal (PC) or natural gas combined cycle (NGCC) plants with carbon capture and sequestration (CCS); the reductions could be obtained more cheaply with an integrated coal gasification combined cycle (IGCC) plant with CCS.     

Short run effects of a price on carbon dioxide emissions from U.S. electric generators

The price of delivered electricity will rise if generators have to pay for carbon dioxide emissions through an implicit or explicit mechanism. There are two main effects that a substantial price on CO2 emissions would have in the short run (before the generation fleet changes significantly). First, consumers would react to increased price by buying less, described by their price elasticity of demand. Second, a price on CO2 emissions would change the order in which existing generators are economically dispatched, depending on their carbon dioxide emissions and marginal fuel prices. Both the price increase and dispatch changes depend on the mix of generation technologies and fuels in the region available for dispatch, although the consumer response to higher prices is the dominant effect. We estimate that the instantaneous imposition of a price of $35 per metric ton on CO2 emissions would lead to a 10% reduction in CO2 emissions in PJM and MISO at a price elasticity of -0.1. Reductions in ERCOT would be about one-third as large. Thus, a price on CO2 emissions that has been shown in earlier workto stimulate investment in new generation technology also provides significant CO2 reductions before new technology is deployed at large scale.     

The right place for the right job in the photovoltaic life cycle

The potential for photovoltaic power generation (PV) to reduce primary energy consumption (PEC) and CO(2) emissions depends on the physical locations of each stage of its life cycle. When stages are optimally located, CO(2) emissions are reduced nearly ten times as much as when each stage is located in the country having the largest current market share. The usage stage contributes the most to reducing CO(2) emissions and PEC, and total CO(2) emissions actually increase when PV is installed in countries having small CO(2) emissions from electricity generation. Global maps of CO(2) reduction potential indicate that Botswana and Gobi in Mongolia are the optimal locations to install PV due to favorable conditions for PV power generation and high CO(2) emissions from current electricity generation. However, the small electricity demand in those countries limits the contribution to global CO(2) reduction. The type of PVs has a small but significant effect on life cycle PEC and CO(2) emissions.     

Application of hybrid life cycle approaches to emerging energy technologies--the case of wind power in the UK

Future energy technologies will be key for a successful reduction of man-made greenhouse gas emissions. With demand for electricity projected to increase significantly in the future, climate policy goals of limiting the effects of global atmospheric warming can only be achieved if power generation processes are profoundly decarbonized. Energy models, however, have ignored the fact that upstream emissions are associated with any energy technology. In this work we explore methodological options for hybrid life cycle assessment (hybrid LCA) to account for the indirect greenhouse gas (GHG) emissions of energy technologies using wind power generation in the UK as a case study. We develop and compare two different approaches using a multiregion input-output modeling framework - Input-Output-based Hybrid LCA and Integrated Hybrid LCA. The latter utilizes the full-sized Ecoinvent process database. We discuss significance and reliability of the results and suggest ways to improve the accuracy of the calculations. The comparison of hybrid LCA methodologies provides valuable insight into the availability and robustness of approaches for informing energy and environmental policy.     

Process for capturing CO2 arising from the calcination of the CaCO3 used in cement manufacture

This paper outlines a new CaCO3 calcination method for producing a stream of CO2 (suitable for permanent geological storage after purification and compression). The process is based on the use of very hot CaO particles (T >1000 degrees C) to transfer heat from a circulating fluidized bed combustor (CFBC) to a calciner (fluidized with CO2 and/or steam). Since the fluidized bed combustor and calciner have separate atmospheres, the CO2 resulting from the decomposition of CaCO3 can be captured, while the CO2 generated in the combustion of the fuel in air is emitted to the atmosphere. We demonstrate that with this system it is possible to reduce the CO2 emissions of a cement plant by around 60%. Furthermore, since the key pieces of equipment are similar to the commercial CFBCs used in power generation plants, it is possible to establish the additional investment required for the system and to estimate the cost per ton of CO2 avoided for this process to be about 19 $/tCO2 avoided.     

Greenhouse gas emissions from operating reserves used to backup large-scale wind power

Wind farms provide electricity with no direct emissions. However, their output cannot be forecasted perfectly, even a short time ahead. Consequently, power systems with large amounts of wind power may need to keep extra fossil-fired generators turned on and ready to provide power if wind farm output drops unexpectedly. In this work, I introduce a new model for estimating the uncertainty in short-term wind power forecasts, and how this uncertainty varies as wind power is aggregated over larger regions. I then use this model to estimate the reserve requirements in order to compensate for wind forecast errors to a 99.999% level of reliability, and an upper limit on the amount of carbon dioxide that would be emitted if natural gas power plants are used for this purpose. I find that for regions larger than 500 km across, operating reserves will undo 6% or less of the greenhouse gas emission savings that would otherwise be expected from wind power.     

Baseload coal investment decisions under uncertain carbon legislation

More than 50% of electricity in the U.S. is generated by coal. The U.S. has large coal resources, the cheapest fuel in most areas. Coal fired power plants are likely to continue to provide much of U.S. electricity. However, the type of power plant that should be built is unclear. Technology can reduce pollutant discharges and capture and sequester the CO2 from coal-fired generation. The U.S. Energy Policy Act of 2005 provides incentives for large scale commercial deployment of Integrated Coal Gasification Combined Cycle (IGCC) systems (e.g., loan guarantees and project tax credits). This analysis examines whether a new coal plant should be Pulverized Coal (PC) or IGCC. Do stricter emissions standards (PM, SO2, NOx, Hg) justify the higher costs of IGCC over PC? How does potential future carbon legislation affect the decision to add carbon capture and storage (CCS) technology? Finally, can the impact of uncertain carbon legislation be minimized? We find that SO2, NOx, PM, and Hg emission standards would have to be far more stringent than twice current standards to justify the increased costs of the IGCC system. A C02 tax less than $29/ton would lead companies to continuing to choose PC, paying the tax for emitted CO2. The earlier a decision-maker believes the carbon tax will be imposed and the higher the tax, the more likely companies will choose IGCC w/CCS. Having government announce the date and level of a carbon tax would promote more sensible decisions, but government would have to use a tax or subsidy to induce companies to choose the technology that is best for society.     

Reducing the energy penalty costs of postcombustion CCS systems with amine-storage

Carbon capture and storage (CCS) can significantly reduce the amount of CO(2) emitted from coal-fired power plants but its operation significantly reduces the plant's net electrical output and decreases profits, especially during times of high electricity prices. An amine-based CCS system can be modified adding amine-storage to allow postponing 92% of all its energy consumption to times of lower electricity prices, and in this way has the potential to effectively reduce the cost of CO(2) capture by reducing the costs of the forgone electricity sales. However adding amine-storage to a CCS system implies a significant capital cost that will be outweighed by the price-arbitrage revenue only if the difference between low and high electricity prices is substantial. In this paper we find a threshold for the variability in electricity prices that make the benefits from electricity price arbitrage outweigh the capital costs of amine-storage. We then look at wholesale electricity markets in the Eastern Interconnect of the United States to determine profitability of amine-storage systems in this region. Using hourly electricity price data from years 2007 and 2008 we find that amine storage may be cost-effective in areas with high price variability.     

Switch: a planning tool for power systems with large shares of intermittent renewable energy

Wind and solar power are highly variable, so it is it unclear how large a role they can play in future power systems. This work introduces a new open-source electricity planning model--Switch--that identifies the least-cost strategy for using renewable and conventional generators and transmission in a large power system over a multidecade period. Switch includes an unprecedented amount of spatial and temporal detail, making it possible to address a new type of question about the optimal design and operation of power systems with large amounts of renewable power. A case study of California for 2012-2027 finds that there is no maximum possible penetration of wind and solar power--these resources could potentially be used to reduce emissions 90% or more below 1990 levels without reducing reliability or severely raising the cost of electricity. This work also finds that policies that encourage customers to shift electricity demand to times when renewable power is most abundant (e.g., well-timed charging of electric vehicles) could make it possible to achieve radical emission reductions at moderate costs.     

LCA法在木本生物柴油清洁生产评估方面的应用研究

生命周期评价(LCA)作为一种能全程评估产业链和产品环境影响、资源消耗、净能效率的重要方法,近年来得到了越来越多的关注,也开始被用于生物柴油清洁生产领域,能为产业可持续提供决策依据。对木本生物柴油的LCA体系、评估模型与方法、国内外木本生物柴油LCA研究现状进行了综述。结果显示:木本生物柴油在燃烧阶段相比石化柴油具有清洁排放的优点,但整个生命周期的排放未必清洁,主要与我国燃煤发电、化肥和辅料生产排放有关;木本生物柴油产业作为低碳产业,温室效应和能源消耗均低于石化柴油,整个生命周期中以种植和生产阶段的排放和消耗最大并针对性提出改进措施;未来我国木本生物柴油生命周期评价应通过建设产业标准数据库、更多注重不同原料不同工艺的对比评估、兼顾经济性和生态服务功能的评估进一步拓展木本生物柴油研究的深度和广度。     

Should a coal-fired power plant be replaced or retrofitted?

In a cap-and-trade system, a power plant operator can choose to operate while paying for the necessary emissions allowances, retrofit emissions controls to the plant, or replace the unit with a new plant. Allowance prices are uncertain, as are the timing and stringency of requirements for control of mercury and carbon emissions. We model the evolution of allowance prices for SO2, NOx, Hg, and CO2 using geometric Brownian motion with drift, volatility, and jumps, and use an options-based analysis to find the value of the alternatives. In the absence of a carbon price, only if the owners have a planning horizon longer than 30 years would they replace a conventional coal-fired plant with a high-performance unit such as a supercritical plant; otherwise, they would install SO2 and NOx, controls on the existing unit. An expectation that the CO2 price will reach $50/t in 2020 makes the installation of an IGCC with carbon capture and sequestration attractive today, even for planning horizons as short as 20 years. A carbon price below $40/t is unlikely to produce investments in carbon capture for electric power.     

基于风险约束的风电场穿透极限功率优化计算

风电场的穿透极限功率是风电场规划运行的一个重要指标。本文借用金融理论中风险价值的思想,提出一种采用机会约束规划计算风电穿透极限功率的新方法。该方法把风电穿透功率极限看作是在满足网络和设备约束前提下系统允许的风电场最大装机容量。考虑到风电场出力的随机性,在个别情况下可能有某些约束条件无法满足,但发生的概率又很低,如果以确定性的方法处理约束条件,得到的优化结果将趋于保守。机会约束规划为解决这类问题提供了可能,它允许在观测到随机变量的实现之前做出决策,只要该决策使得约束条件成立的概率高于给定的置信水平,便认为满足了机会约束,其中约束条件以概率的形式表示。针对问题特点,求解时应用了随机模拟技术,本文给出在IEEE30节点系统上进行计算的结果。目前,此方法已经应用在了一些风力发电厂的初期规划上,并且经过实践证明,取得了不错的经济和环境效益。