Gas For Electricity Generation Research Articles

Electricity production from biogas in Serbia: Assessment of emissions reduction

Biogas represents a promising source for the production of clean energy. The objective of this paper was to quantify the potential for the reduction of emissions to the environment during the production of electricity from biogas in comparison with environmental effects of the production of the same amount of electricity from fossil resources (coal from Kolubara basin and natural gas). Basis for comparison of environmental impacts in this work was the annual production of electricity in biogas plants of the total capacity of 80 MW. This study has shown that the annual production of electricity from biogas power plants of 80 MW results in: substitution of up to 840 kt of coal from Kolubara basin and 123.2 million m3 of natural gas; reduction in emissions of greenhouse gases in the range of 491.16 kt - 604.97 kt CO2-eq, depending on the energy efficiency of the process of electricity production from biogas; reduction in emissions of greenhouse gases up to 92.37 kt CO2-eq compared to the use of natural gas for electricity generation.

Natural Gas Plays Central Role in Clean Power Plan

President Obama and the Environmental Protection Agency (EPA) recently passed new regulations requiring America's electric power plants to reduce greenhouse gas emissions. These regulations come in the form of the Clean Power Plan (CPP). The purpose of the CPP is to reduce the amount of carbon dioxide emitted from existing and new electric power plants, also referred to as electric‐generating units (EGUs). In order to achieve the lower CO2 emission goals of the CPP, this nation will need to increase its use of natural gas for electricity generation.

Natural Gas Plays Central Role in Clean Power Plan

President Obama and the Environmental Protection Agency (EPA) recently passed new regulations requiring America's electric power plants to reduce greenhouse gas emissions. These regulations come in the form of the Clean Power Plan (CPP). The purpose of the CPP is to reduce the amount of carbon dioxide (CO2) emitted from existing and new electric power plants, also referred to as electric generating units (EGUs). In order to achieve the lower CO2 emission goals of the CPP, this nation will need to increase its use of natural gas for electricity generation. CO2 is a greenhouse gas emission produced when fossil fuels are burned. The CPP requires states to develop a plan to reduce the CO2 gas emissions produced by fossil fuel-fired EGUs. Each state must establish standards of performance that limit the degree of emissions to a level that can be achieved by using the “best system of emission reduction.” The EPA identifies three measures or “building blocks” that states should use when developing a plan. One of these building blocks encourages states to switch from coal-fired EGUs to lower-CO2-emitting natural gas-fired EGUs. The effect of this shift in energy production should benefit the natural gas industry and allow states to meet the required CO2 reductions.This article first examines what CO2 and greenhouse gases are, how the type of fossil fuel burned affects CO2 emissions, and why the CPP has targeted them. Next, it takes a closer look at the CPP, including an examination of the three building blocks. Lastly, this article looks at the effect of the CPP on the natural gas industry and why the lower CO2 emitting properties of natural gas drive support for this cleaner fuel.

Exploring the Potential of Organic Waste as a Source of Methane Gas for Electricity Generation in Nigeria

Open dumps and ill equipped landfills are some of the characteristics of solid waste management in Nigeria. This paper therefore seeks to investigate the viability of anaerobic digestion as part of an integrated waste management strategy for the city of Port Harcourt, Nigeria. In order to achieve this aim, the paper reviews literature on solid waste management in the study area. Alaboratory experiment was also conducted using organic solid wastefrom Port Harcourt. From the findings, it was revealed that anaerobic digestion could play a major role towards the attainment of sustainable solid waste management in Port Harcourt. The small laboratory sample of 10 grams used for the experiment produced about 0.796 litres of methane gas, means that 1 tonne of organic waste in Port Harcourt will generate about 79600 litres of methane gas with energy equivalent of about 1592000_kj. The paper concluded that in a city like Port Harcourt where several tonnes of solid wastes are produced every day, a substantial amount of methane gas could be recovered for electricity generation. It was therefore recommended that anaerobic digestion should be used in order to boost the electricity capacity of the city whilst also improving the quality of life of the people.

The feasibility of the introduction of natural gas into the electricity production system in the island of Crete (Greece)

This article examines the technical and economic feasibility for the introduction of natural gas for electricity generation in non-interconnected insular systems. In such systems, the introduction of natural gas constitutes a fundamental perspective towards the substitution of oil or coal, commonly used for electricity production. On the contrary, the expensive transportation of natural gas for long overseas distances, the required technical infrastructures and the expected limited consumption of natural gas in islands with low populations, constitute issues that can negatively affect the feasibility of the project.The aforementioned tasks are examined in the present article for the island of Crete (Greece) chosen as a case study. The size of the island and its consequent electricity consumption create the fundamental prerequisites for the introduction of natural gas. The annual operation of the existing system and the new one, as it would be modified after the natural gas introduction, is simulated using all the required parameters and data as provided by the utility company. The annual production specific cost is calculated for both systems and the economic benefit from the substitution of oil with natural gas is evaluated. The CO2 annual emissions are also calculated for both systems.The annual electricity production cost in Crete with the introduction of natural gas is reduced 38%, while the CO2 annual emissions are reduced 54%, compared to existing levels in 2013. The required investments exhibit a payback period above 3.5years. On the other hand, the energy dependence of the island on imported energy sources remains.

Metal Organic Frameworks for Selective Adsorption of t-Butyl Mercaptan from Natural Gas

Pipeline natural gas is typically “odorized” with ∼10 ppm of sulfur-containing components, such as mercaptans, for ease of detection. Such odorants can be removed before being burned in electricity generation gas turbines to prevent or limit turbine corrosion and increase turbine lifetime. Selective adsorption of these odorants onto solid materials is an attractive approach to address this problem because of the ability to remove these trace levels of sulfur and to be operated at low temperatures, meaning that it is less energy-intensive than other traditional sulfur removal methods. Adsorbent material selection is important for this approach, and a material with high sulfur capacity, selectivity, and regenerability is desired for a practical implementation of such an adsorption system. In this study, several adsorbent materials are gravimetrically screened for t-butyl mercaptan (TBM) adsorption capacity and the best candidates, Cu-BTC, MIL-53(Al), and UiO-66(Zr), are compared to a benchmark material, zeolite NaY. These selected materials are evaluated with regard to their cyclic regenerability/stability and selectivity toward TBM over methane and other impurities. From the results of this study, UiO-66(Zr) emerges as a promising candidate material for this application.

Life cycle greenhouse gas emissions from U.S. liquefied natural gas exports: implications for end uses.

This study analyzes how incremental U.S. liquefied natural gas (LNG) exports affect global greenhouse gas (GHG) emissions. We find that exported U.S. LNG has mean precombustion emissions of 37 g CO2-equiv/MJ when regasified in Europe and Asia. Shipping emissions of LNG exported from U.S. ports to Asian and European markets account for only 3.5-5.5% of precombustion life cycle emissions, hence shipping distance is not a major driver of GHGs. A scenario-based analysis addressing how potential end uses (electricity and industrial heating) and displacement of existing fuels (coal and Russian natural gas) affect GHG emissions shows the mean emissions for electricity generation using U.S. exported LNG were 655 g CO2-equiv/kWh (with a 90% confidence interval of 562-770), an 11% increase over U.S. natural gas electricity generation. Mean emissions from industrial heating were 104 g CO2-equiv/MJ (90% CI: 87-123). By displacing coal, LNG saves 550 g CO2-equiv per kWh of electricity and 20 g per MJ of heat. LNG saves GHGs under upstream fugitive emissions rates up to 9% and 5% for electricity and heating, respectively. GHG reductions were found if Russian pipeline natural gas was displaced for electricity and heating use regardless of GWP, as long as U.S. fugitive emission rates remain below the estimated 5-7% rate of Russian gas. However, from a country specific carbon accounting perspective, there is an imbalance in accrued social costs and benefits. Assuming a mean social cost of carbon of $49/metric ton, mean global savings from U.S. LNG displacement of coal for electricity generation are $1.50 per thousand cubic feet (Mcf) of gaseous natural gas exported as LNG ($.028/kWh). Conversely, the U.S. carbon cost of exporting the LNG is $1.80/Mcf ($.013/kWh), or $0.50-$5.50/Mcf across the range of potential discount rates. This spatial shift in embodied carbon emissions is important to consider in national interest estimates for LNG exports.

Pipeline to Reliability: Unraveling Gas and Electric Interdependencies Across the Eastern Interconnection

Uncertainties surrounding the continued operation of older coal generation units, the increased penetration of renewable resources, and the aging or retirement of certain nuclear units have exposed vulnerabilities in the natural gas supply chain. The increased availability and low price of natural gas for electric generation in many parts of the United States compounds them by increasing the economic pressure on various non-gas-fired base-load generation plants. Our growing dependence on natural gas as a primary fuel for electricity generation offers environmental and efficiency benefits, but it also presents operational challenges for independent system operators (ISOs) and regional transmission organizations (RTOs) that depend on the natural gas pipeline and storage network to facilitate reliability objectives. During the peak heating season, pipeline congestion can result in interruptions of gas deliveries to those gas-fired generators lacking primary firm entitlements. Scheduling restrictions associated with the provision of nonfirm transportation for gas-fired generators stress the capability of the electric system to meet demand and maintain operating reserves, as RTOs must quickly replace output from more efficient natural gas-fueled combined-cycle plants and quick-start peakers to maintain electric reliability. In this article, we address the gas-electric interdependencies across the Eastern Interconnection that are the subject of a multitarget research project sponsored by the U.S. Department of Energy (DOE) with the participation of PJM Interconnection, Midcontinent Independent System Operator (MISO), New York Independent System Operator (NYISO), ISO New England (ISO-NE), TVA, and the Independent Electricity System Operator of Ontario (IESO), collectively known as the participating planning authorities (PPAs).

The Environmental Costs and Benefits of Fracking

Unconventional oil and natural gas extraction enabled by horizontal drilling and hydraulic fracturing (fracking) is driving an economic boom, with consequences described from “revolutionary” to “disastrous.” Reality lies somewhere in between. Unconventional energy generates income and, done well, can reduce air pollution and even water use compared with other fossil fuels. Alternatively, it could slow the adoption of renewables and, done poorly, release toxic chemicals into water and air. Primary threats to water resources include surface spills, wastewater disposal, and drinking-water contamination through poor well integrity. An increase in volatile organic compounds and air toxics locally are potential health threats, but the switch from coal to natural gas for electricity generation will reduce sulfur, nitrogen, mercury, and particulate air pollution. Data gaps are particularly evident for human health studies, for the question of whether natural gas will displace coal compared with renewables, and for decadal-scale legacy issues of well leakage and plugging and abandonment practices. Critical topics for future research include data for (a) estimated ultimate recovery (EUR) of unconventional hydrocarbons, (b) the potential for further reductions of water requirements and chemical toxicity, (c) whether unconventional resource development alters the frequency of well integrity failures, (d) potential contamination of surface and ground waters from drilling and spills, (e) factors that could cause wastewater injection to generate large earthquakes, and (f) the consequences of greenhouse gases and air pollution on ecosystems and human health.

How competitive are EU electricity markets? An assessment of ETS Phase II

This paper studies the interactions between electricity and carbon allowance prices in the year-ahead energy markets of France, Germany, United Kingdom and the Nordic countries, during Phase II of the EU ETS. VAR and Granger-causality methods are used to analyze causal interfaces, whereas the volatility of electricity prices is studied with basic and asymmetric AR-GARCH models. Among the main results, the marginal rate at which carbon prices feed into electricity prices is shown to be ca. 135% in the EEX and Nord Pool markets, where electricity and carbon prices display bidirectional causality, and 109% in the UK. Therefore, generators in these markets internalized the cost of freely allotted emission allowances into their electricity prices considerably more than the proportionate increase in costs justified by effective carbon intensity. Moreover, electricity prices in France are found to Granger-cause the carbon price. This study also shows how European electricity prices are deeply linked to coal prices among other factors, both in terms of levels and volatility, regardless of the underlying fuel mix, and that coal was marginally more profitable than gas for electricity generation. EU policies aimed at increasing the carbon price are likely to be crucial in limiting the externalities involved in the transition to a low-carbon system.

Electric Regulation: FERC Streamlines Natural Gas/Electric Integration, Increasing Natural Gas Demand

AbstractThe Federal Energy Regulatory Commission's (FERC's) release of a Notice of Proposed Rulemaking (NOPR) on March 20, 2014, provides another sign of the importance that natural gas will play in the future of electric power generation in the United States. FERC's NOPR proposes to revise standards for pipeline business operations and communications, including changes to the industry's operating day and the scheduling of transportation service. FERC states clearly that the impetus for the revisions is the “increased reliance on natural gas for electric generation.”

An assessment of energy security in Thailand’s power generation

Presently, electricity power generation in Thailand mainly relies on natural gas approximately 70% of the total primary energy demand. Furthermore, around 37% of the total natural gas consumption is imported from neighboring countries. The Thai government developed a new power development plan in 2010 (PDP) to strengthen its energy security due to excessive reliance on natural gas for electricity generation and mitigate CO2 emissions by planning to install new nuclear power plants by 2030. Particularly after the nuclear power disaster in Fukushima, Japan in 2011, public opinion remains in opposition with nuclear technology, raising issues concerning the feasibility of this potential energy source.It is found that an intensive coal power plants scenario is the highest emission of CO2 per kWh and its electricity unit cost is higher than PDP about 7.35%. If nuclear and new coal power plants cannot be implemented according to PDP plan, a renewable energy scenario is possible. This option not only strengthens the energy security, but it significantly mitigates the intensity of CO2 emission per kWh higher than PDP about 7.14%. However, this only can be achieved by increasing the electricity unit cost by 14% compared to the price estimated by the 2010 PDP.

A financial evaluation of the design concept for a ‘clean energy producing vessel’

The design concept for a ‘clean energy producing vessel’ proposes the exploitation of remote offshore gas reserves, primarily from stranded fields, using a floating electrical power generation plant. In comparison to conventional approaches utilising liquefied natural gas and pipeline technologies, the clean energy producing vessel represents a highly innovative approach to the production and transportation logistics of natural gas for electricity generation. The main objective of this article is to undertake a financial evaluation of the clean energy producing vessel design concept. This is achieved by developing a financial model comprising cost and revenue modular elements that reflect the major technical components of the design concept: the floating production, storage and offloading unit; the electrical generation plant; cable transmission; carbon capture and electricity prices. The results for net present value and internal rate of return are derived for all combinations of either high- or low-revenue scenarios and for high- or low-cost scenarios. With a rather low internal rate of return of just 15.53%, the only scenario that yields a positive outcome is that of the high-revenue and low-cost combination. Accounting for savings in carbon dioxide emissions exerts only a negligible impact upon the results. Analysis of future research required concludes that following its deployment and implementation, the feasibility of the clean energy producing vessel design concept depends on the outcomes of economic and technological assessments, which are difficult to predict with any degree of certainty.

From Whence the Wood? Supply Chain Transparency and the Origin of Solid Biomass for Electricity Generation in the Netherlands

The use of solid biomass as feedstock for electricity generation is becoming an increasingly prominent and controversial topic in the global debate about the transition to a sustainable system of energy provision and consumption. Increasing emissions of carbon dioxide (CO2) from the combustion of fossil fuels such as coal, lignite, oil, and natural gas for electricity generation is currently the most significant driver of anthropogenic greenhouse gas (GHG) emissions and climate change. If produced under sustainable conditions, solid biomass can offer a potential path to addressing climate change by substituting fossil fuels and reducing GHG emissions. On the other hand, if produced and procured in an unsustainable manner, the use of biomass for electricity production can actually lead to an increase in CO2 emissions and thus have a negative overall climate effect.The production of solid biomass for electricity generation also carries with it several other social and environmental risks related to issues such as forest degradation, loss of biodiversity, land tenure/rights violations, and human rights abuses. Detailed knowledge about the origin of the supply of solid biomass used for electricity generation is thus essential for determining whether biomass-based electricity generation is genuinely contributing to sustainable development.Given the potential direct and indirect social and environmental impacts of solid biomass production, it is crucial that civil society, regulators, consumers and companies themselves have sufficient and specific information about from where the biomass entering the Netherlands one of the worlds largest consumers of biomass comes: where it is produced, what the feedstock is, and who is responsible for importing it. The question From whence (i.e. from where) the wood? has never been more relevant.This report aims to improve the social and environmental conditions under which solid biomass is produced. By examining the degree of biomass supply chain transparency provided by the six largest individual consumers of solid biomass for electricity generation in the Netherlands electric utilities E.ON, Eneco, EPZ (DELTA), GDF Suez, RWE/Essent, and Vattenfall/Nuon the report aims to increase the public and political pressure on electricity companies to take responsibility for ensuring that minimum social and environmental standards are respected throughout the biomass supply chain.

Life cycle greenhouse gas impacts of ethanol, biomethane and limonene production from citrus waste

The production of biofuel from cellulosic residues can have both environmental and financial benefits. A particular benefit is that it can alleviate competition for land conventionally used for food and feed production. In this research, we investigate greenhouse gas (GHG) emissions associated with the production of ethanol, biomethane, limonene and digestate from citrus waste, a byproduct of the citrus processing industry. The study represents the first life cycle-based evaluations of citrus waste biorefineries. Two biorefinery configurations are studied—a large biorefinery that converts citrus waste into ethanol, biomethane, limonene and digestate, and a small biorefinery that converts citrus waste into biomethane, limonene and digestate. Ethanol is assumed to be used as E85, displacing gasoline as a light-duty vehicle fuel; biomethane displaces natural gas for electricity generation, limonene displaces acetone in solvents, and digestate from the anaerobic digestion process displaces synthetic fertilizer. System expansion and two allocation methods (energy, market value) are considered to determine emissions of co-products. Considerable GHG reductions would be achieved by producing and utilizing the citrus waste-based products in place of the petroleum-based or other non-renewable products. For the large biorefinery, ethanol used as E85 in light-duty vehicles results in a 134% reduction in GHG emissions compared to gasoline-fueled vehicles when applying a system expansion approach. For the small biorefinery, when electricity is generated from biomethane rather than natural gas, GHG emissions are reduced by 77% when applying system expansion. The life cycle GHG emissions vary substantially depending upon biomethane leakage rate, feedstock GHG emissions and the method to determine emissions assigned to co-products. Among the process design parameters, the biomethane leakage rate is critical, and the ethanol produced in the large biorefinery would not meet EISA’s requirements for cellulosic biofuel if the leakage rate is higher than 9.7%. For the small biorefinery, there are no GHG emission benefits in the production of biomethane if the leakage rate is higher than 11.5%. Compared to system expansion, the use of energy and market value allocation methods generally results in higher estimates of GHG emissions for the primary biorefinery products (i.e., smaller reductions in emissions compared to reference systems).

Implications of Near-Term Coal Power Plant Retirement for SO2 and NOX 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.

Revision of reserve requirements following wind power integration in island power systems

This contribution studies the impact of wind power on the operation of island power systems. The analysis focuses on the available flexibility of thermal generation to balance wind power variations and prediction errors. This issue is highly relevant for small and medium sized islands where interconnections are absent and the smoothing of variations is limited due to a small geographical surface. The main objective is to determine if additional reserve requirements are necessary for ensuring reliable wind power integration in an isolated transmission system. In this context, a case study is performed for Cyprus, a medium-sized island, where wind developments towards 2020 schedule an installed capacity of 300 MW, reaching 7% of the annual electricity consumption. Simulations with installed wind power capacities up to 400 MW show that the current available flexibility in the generation system is inadequate to balance real-time wind power fluctuations and prediction errors. Consequently, large amounts of wind curtailment and demand shedding may be expected. Therefore, current reserve requirements should be revised, in order to reliably facilitate wind power into the system. Furthermore, the impact of introducing natural gas for electricity generation in Cyprus on the reserve requirements, following wind power integration, is examined.

THE ECONOMIC ANALYSIS OF ENERGY MERGERS IN EUROPE AND IN SPAIN

This article surveys, from an economic perspective, the recent application of merger control in the European energy sector. It considers ten significant transactions in the energy sector: the eight largest energy transactions assessed by the European Commission since 2004, as well as two major gas-electricity mergers in Spain over roughly the same period. Merger decisions in the energy sector have been characterized by a significant concern for potential horizontal unilateral effects, even in situations where the merging parties accounted for a limited combined share of the market, or where one of the parties was only a small competitor. A variety of non-horizontal concerns have also been considered by the competition authorities, including effects flowing from the increasing use of gas for electricity generation or from limited ownership unbundling of network assets. Remedy packages have typically included extensive structural divestments to remove competition concerns. Given the nature of competition in energy markets, particularly effective remedies are those that involve the sale of price-setting generation plants, network assets, and controlling stakes in merging parties' competitors.

Present Coal Potential of Turkey and Coal Usage in Electricity Generation

Total coal reserve (hard coal + lignite) in the world is 984 billion tons. While hard coal constitutes 52% of the total reserve, lignite constitutes 48% of it. Turkey has only 0.1% of world hard coal reserve and 1.5% of world lignite reserves. Turkey has 9th order in lignite reserve, 8th order in lignite production, and 12th order in total coal (hard coal and lignite) consumption. While hard coal production meets only 13% of its consumption, lignite production meets lignite consumption in Turkey. Sixty-five percent of produced hard coal and 78% of produced lignite are used for electricity generation. Lignites are generally used for electricity generation due to their low quality. As of 2003, total installed capacity of Turkey was 35,587 MW, 19% (6,774 MW) of which is produced from coal-based thermal power plants. Recently, use of natural gas in electricity generation has increased. While the share of coal in electricity generation was about 50% for 1986, it is replaced by natural gas today.

Landfilling of waste: accounting of greenhouse gases and global warming contributions

Accounting of greenhouse gas (GHG) emissions from waste landfilling is summarized with the focus on processes and technical data for a number of different landfilling technologies: open dump (which was included as the worst-case-scenario), conventional landfills with flares and with energy recovery, and landfills receiving low-organic-carbon waste. The results showed that direct emissions of GHG from the landfill systems (primarily dispersive release of methane) are the major contributions to the GHG accounting, up to about 1000 kg CO(2)-eq. tonne( -1) for the open dump, 300 kg CO(2)-eq. tonne( -1) for conventional landfilling of mixed waste and 70 kg CO(2)-eq. tonne(-1) for low-organic-carbon waste landfills. The load caused by indirect, upstream emissions from provision of energy and materials to the landfill was low, here estimated to be up to 16 kg CO(2)-eq. tonne(-1). On the other hand, utilization of landfill gas for electricity generation contributed to major savings, in most cases, corresponding to about half of the load caused by direct GHG emission from the landfill. However, this saving can vary significantly depending on what the generated electricity substitutes for. Significant amounts of biogenic carbon may still be stored within the landfill body after 100 years, which here is counted as a saved GHG emission. With respect to landfilling of mixed waste with energy recovery, the net, average GHG accounting ranged from about -70 to 30 kg CO(2)-eq. tonne(- 1), obtained by summing the direct and indirect (upstream and downstream) emissions and accounting for stored biogenic carbon as a saving. However, if binding of biogenic carbon was not accounted for, the overall GHG load would be in the range of 60 to 300 kg CO(2)-eq. tonne( -1). This paper clearly shows that electricity generation as well as accounting of stored biogenic carbon are crucial to the accounting of GHG of waste landfilling.