Hard Coal Power Plants Research Articles

Stranded Asset Risk and Political Uncertainty: The Impact of the Coal Phase-Out on the German Coal Industry

We assess the value of stranded coal-fired power plants in Germany in the light of the critical decision to phase them out by 2038. In a Monte Carlo simulation, the scenarios under consideration (slow decommissioning at the end of the technical lifetime in 2061, the highly probable phase-out by 2038, and an accelerated phase-out by 2030) are additionally assigned distributions to display the uncertainty of future developments. The results show an overall stranded asset value of €2.6 billion given the phase-out by 2038 and an additional €11.6 billion if the phase-out is brought forward by 8 years. This study also describes the impacts of carbon pricing and the feed-in from renewable energy sources on the merit order and eventually the deterioration in economic conditions for hard coal and lignite power plants. Lastly, we discuss the immediate concerns for the share prices of the affected companies and help to close the research gap regarding stranded physical and financial assets.

Electricity Production and Consumption Perspectives in the Opinion of the Youth of South-Eastern Poland

In Poland, in 2021, an increase in demand for electricity was recorded, and hard coal and lignite power plants still had a dominant share in its production. Another source of electricity was renewable energy sources (RES), mainly wind farms. Young people in Poland are aware that electricity is not only its production, but also consumption in households. Therefore, it is also essential to properly educate young people, aiming at a cost-effective, sustainable lifestyle, in relation to electricity consumption. The article presents the current state of the electricity generation sector in Poland along with the proposed changes in this respect, in particular in terms of the development prospects for the use of renewable energy sources and the influence of government administration on the production and consumption of electricity. The aim of this research was to broaden the knowledge of young people’s opinions on energy production and consumption. The research results can be used to create long-term directions of energy policy and to build a social attitude of sustainable energy consumption in Poland. The research was non-probabilistic, based on questionnaires, using the CAWI (Computer Assisted Web Interview) technique. The questionnaire was conducted in 2021, and the analysis was made on the basis of 741 correctly completed research questionnaires. The results of the research confirmed the research hypotheses—that the surveyed youth see the need to reduce consumption as a way to counteract climate change and excessive energy consumption. They also expect government support in the energy transformation in Poland, based on a diversified scenario, using both renewable energy sources (RES) and nuclear energy.

Carbon Capture Utilisation and Storage Technology Development in a Region with High CO2 Emissions and Low Storage Potential—A Case Study of Upper Silesia in Poland

The region of Upper Silesia, located in southern Poland, is characterised by very high emissions of carbon dioxide into the air—the annual emission exceeds 33 Mt CO2 and the emission ‘per capita’ is 7.2 t/y in comparison to the EU average emission per capita 6.4 t/y and 8.4 t/y for Poland in 2019. Although in the region there are over 100 carbon dioxide emitters covered by the EU ETS, over 90% of emissions come from approximately 15 large hard coal power plants and from the coke and metallurgical complex. The CCUS scenario for Upper Silesia, which encompasses emitters, capture plants, transport routes, as well as utilisation and storage sites until 2050, was developed. The baseline scenario assumes capture of carbon dioxide in seven installations, use in two methanol plants and transport and injection into two deep saline aquifers (DSA). The share of captured CO2 from flue gas was assumed at the level of 0.25–0.9, depending mainly on the limited capacity of storage. To recognise the views of society on development of the CCUS technologies in Upper Silesia, thirteen interviews with different types of stakeholders (industry, research and education, policy makers) were conducted. The respondents evaluated CCU much better than CCS. The techno-economic assessment of CCUS carried out on a scenario basis showed that the economic outcome of the scenario with CCUS is EUR 3807.19 million more favourable compared to the scenario without CO2 capture and storage.

Inland Hard Coal Transportation Costs in the European Union—A Model Based Approach

Although some EU countries have already ceased coal-fired electricity generation, coal will still be a relevant topic within the European electricity mix in the medium term. A hard coal power plant competes in the merit order mainly with other hard coal power plants and also with gas power plants. One of the main cost drivers of fuel supply is the transport costs of steam coal from import harbors to the power plant sites. These costs consist either of freight rates of the barges, charges for transport by train, or a combination of both, and additional transshipment costs that arise during transport. The resulting costs differ considerably depending on the country and the region within a country. This work aims at determining country-specific regional transport costs for hard coal to power plant sites in the European Union. The geographical resolution for this work is at the municipal level of each country, in which each municipality is characterized by specific costs, depending on distance and means of transport. In total, transport costs are modelled for 119,978 municipalities. The results show a clear ranking of preferred locations with regard to transport costs, starting with locations close to the open sea followed by inland locations near riverbanks. Locations remote from both sea and waterway access are the most expensive sites. The resulting data basis can be used as an input for energy system models.

New flowing system in cooling system axial-flow pump in a hard coal electric power plant

This article presents the new construction of a centrifugal impeller pump which supplies the cooling system in coal power plants. The article also shows the history of producing this kind if pumps for unified 125 MW and 200 MW power units which dominate in Poland. The process of numerical analysis and conventional calculations leading to the improvement of qualities of the flowing system exceeding literature indicators are presented. The article shows the problems which appeared during assembling the pump in its target workplace. The results of the measurements of the pump flowing system in its target workplace are presented.

Identification of Technogenic Magnetic Particles and Forms of Occurrence of Potentially Toxic Elements Present in Fly Ashes and Soil

Solid fossil fuel power plants are the main source of energy in Poland. In 2018, the most important energy carrier was hard coal with a share of 57.9%, followed by lignite with a share of 18.1%. In addition to CO2, NOx and SOx, the combustion of fossil fuels produces dusts containing, among others, potentially toxic elements (PTEs), e.g., Pb, Zn, Cu, Cr, Cd. Although the currently operating power plants have efficient filter systems, the total dust emission in Poland in 2017 amounted to 341,000 t, of which approximately 36,000 t was from the power plants. PTEs present in the power plant dust are often accompanied by technogenic magnetic particles (TMPs)—mainly iron oxides and hydroxides formed in high-temperature technological processes as a result of the transformations of iron minerals contained in raw materials and additives. The presence of magnetic iron minerals (e.g., magnetite, hematite, maghemite, metallic iron) in the tested ashes from hard coal and lignite power plants was confirmed by scanning electron microscopy with energy dispersive spectroscopy (SEM/EDS) analysis. The sequential extraction analysis showed that most of the analyzed PTEs found in dust after hard coal combustion were mainly related to amorphous and crystalline FeOx or in the residual fraction and in dust after lignite combustion, mainly in the most mobile fractions.

Stranded Asset Risk and Political Uncertainty: The Impact of the Coal Phase-out on the German Coal Industry

We assess the value of stranded coal-fired power plants in Germany due to the critical phase-out by 2038. Within a Monte Carlo simulation, the scenarios under consideration (a slow decommissioning at the end of the technical lifetime in 2061, the highly probable phase-out by 2038, and an accelerated phase-out by 2030) are additionally assigned distributions to display the uncertainty of future developments. The results show an overall stranded asset value of €0.4 billion given the phase-out by 2038 and additional €14.3 billion if the phase-out is brought forward by eight years. This study also depicts the impacts of carbon pricing and the feed-in from renewable energy sources on the merit order and eventually the deterioration in economic conditions for hard coal and lignite power plants. Lastly, we illustrate immediate concerns for share prices of affected companies and contributes to closing the research gap between stranded physical and financial assets.

Scenarios for Coal-Exit in Germany—A Model-Based Analysis and Implications in the European Context

The political discussion to reduce the carbon footprint of Germany’s electricity sector, focusing on coal, is intensifying. In this paper, we develop scenarios for phasing out lignite and hard coal power plants in Germany prior to the end of their technical lifespan (“coal-exit”). Our analysis bases upon two coal-exit instruments, the retirement of coal generation capacities and the limiting of how much aged coal power plants with high carbon intensity can be used within a year. Results show that phasing out coal in Germany would have a considerable impact on Central European electricity markets, in terms of decarbonization efforts and electricity trade. An ambitious coal-exit could avert foreseeable shortcomings in Germany’s climate performance in the short-run and release additional carbon savings, thus compensating for potential shortfalls in other energy-intensive sectors by 2030. Limited emissions in the range of 27% would be shifted to neighboring countries. However, tremendous positive climate effects on European scale would result, because Germany’s annual emission savings in 2030 would be substantial. Totaling 85 million tons of CO2, the overall net reduction is equivalent to 17.5% of total European emissions in 2030 without retirements of coal-firing power plants prior to the end of their technical lifespan.

Thermodynamic Analysis of Advanced Gas Turbine Combined Cycle Integration with a High-Temperature Nuclear Reactor and Cogeneration Unit

The EU has implemented targets to achieve a 20% share of energy from renewable sources by 2020, and 32% by 2030. Additionally, in the EU countries by 2050, more than 80% of electrical energy should be generated using non-greenhouse gases emission technology. At the same time, energy cost remains a crucial economic issue. From a practical point of view, the most effective technology for energy conversion is based on a gas turbine combined cycle. This technology uses natural gas, crude oil or coal gasification product but in any case, generates a significant amount of toxic gases to the atmosphere. In this study, the environmentally friendly power generation system composed of a high-temperature nuclear reactor HTR integrated with gas turbine combined cycle technology and cogeneration unit is thermodynamically analysed. The proposed solution is one of the most efficient ways for energy conversion, and what is also important it can be easily integrated with HTR. The results of analysis show that it is possible to obtain for analysed cycles thermal efficiency higher than 50% which is not only much more than could be proposed by typical lignite or hard coal power plant but is also more than can be offered by nuclear technology.

PM1 in Ambient and Indoor Air—Urban and Rural Areas in the Upper Silesian Region, Poland

(1) Background: The work presents results of concentration measurements of PM1, collected in the indoor air of four preschool buildings in Gliwice and its environs (Silesia Province) and in ambient air in the vicinity of four working hard coal power plants and four coking plants located in southern Poland. (2) Methods: The samples of <1 µm, 1–2.5 µm, 2.5–10 µm, and >10 µm fractions were collected with the use of Dekati® PM10 cascade impactor, and concentrations of seven trace elements (Cd, Cr, Mn, Ni, Pb, Sb, and Se) were determined. (3) Results: The concentrations of PM1 changed in the range of 3.1 μg/m3–65.3 μg/m3. Among trace elements, the highest concentrations in indoor air were evidenced for Cr (129–219 ng/m3), while in outdoor air for Pb (12.6–21.2 ng/m3). Principal Component Analysis PCA analysis extracted three factors of rural dusts, city dusts, and natural soils. (4) Conclusions: The paper points to accumulation of carcinogenic Cd, Cr, and Ni in indoor air, and significant contribution of trace elements in PM1, which, owing to long-lasting exposure and elevated sensitivity of developing organisms, may evoke effects on health of children.

Will Germany move into a situation with unsecured power supply?

Together with a huge number of other countries, Germany signed the Paris Agreements in 2015 to prevent global temperature increase above 2°C. Within this agreement, all countries defined their own national contributions to CO2 reduction. Since that, it was visible that CO2 emissions in Germany decreased, but not so fast than proposed in this German nationally determined contribution to the Paris Agreement. Due to increasing traffic, CO2 emissions from this mobility sector increased and CO2 emission from German power generation is nearly constant for the past 20 years, even a renewable generation capacity of 112 GW was built up in 2017, which is much higher than the peak load of 84 GW in Germany. That is why the German National Government has implemented a commission (often called “The German Coal Commission”) to propose a time line: how Germany can move out of coal-fired power stations. This “Coal Commission” started its work in the late spring of 2018 and handed over its final report with 336 pages to the government on January 26th, 2019. Within this report the following proposals were made: ① Until 2022: Due to a former decision of the German Government, the actual remaining nuclear power generation capacity of about 10 GW has to be switched off in 2022. Besides, the “Coal Commission” proposed to switch off additionally in total 12.5 GW of both, hard coal and lignite-fired power plants, so that Germany should reduce its conventional generation capacity by 22.5 GW in 2022. ② Until 2030: Another 13 GW of German hard coal or lignite-fired power plants should be switched off. ③ Until 2038: The final 17 GW of German hard coal or lignite-fired power plants should be switched off until 2038 latest. Unfortunately the “Coal Commission” has not investigated the relevant technical parameter to ensure a secured electric power supply, based on German’s own national resources. Because German Energy Revolution mainly is based on wind energy and photovoltaic, this paper will describe the negligible contribution of these sources to the secured generation capacity, which will be needed for a reliable power supply. In addition, it will discuss several technical options to integrate wind energy and photovoltaic into a secured power supply system with an overall reduced CO2 emission.

Techno-economic and Environmental Analysis of Calcium Carbonate Looping for CO2 Capture from a Pulverised Coal-Fired Power Plant

Pulverised coal-fired (PC) power plants are among the major technologies used to generate electricity for power generation around the world. Coal-fired systems are generally considered to have high greenhouse gas emission intensities, apart from power plants that employ CO2 capture and storage (CCS) technology. As a technology option, calcium carbonate looping can be employed to remove carbon dioxide from the PC flue gas streams. Calcium carbonate looping is an attractive technology due to relatively low efficiency penalties. To better understand the performance characteristics and benefits of such a system integration, the ECLIPSE modelling software is used to perform a techno-economic analysis of the calcium carbonate looping system integrated in to an existing hard coal power plant. The overall system efficiency and the CO2 capture rate is evaluated based on a mass and energy balance calculation as part of the modelling. The capital costs, and maintenance and operating costs are estimated according to a bottom-up approach using the information gained through a mass and energy balance. The SimaPro software is used to perform a life cycle analysis of the capture technology to determine its environmental impact. The calcium carbonate looping system is also compared to other CCS solutions.

Fluor's Econamine FG PlusSM Completes Test Program at Uniper's Wilhelmshaven Coal Power Plant

Fluor and Uniper collaborated to jointly build a demonstration carbon dioxide recovery plant. The capture plant is based on Fluor's Econamine FG PlusSM technology and is located at Uniper's hard coal power plant in Wilhelmshaven, Germany. The demonstration plant, which has a CO2 capture capacity of 70 t/d, utilizes a process configuration that incorporates several recent technology enhancements that can be directly applied to a full sized plant. In late 2015, the project successfully completed a 3 year test campaign. The test program generated useful data related to energy consumption, emissions profiles, and other information to facilitate the scale-up of the process to a full-sized coal based power plant.

Environmental assessment of energy generation from agricultural and farm waste through anaerobic digestion

While Turkey is one of the world's largest producers and exporters of agricultural goods, it is also, at the same time a net importer of energy carriers. This dichotomy offers a strong incentive to generate energy from agricultural and farming waste; something which could provide energy security for rural areas. Combined with the enhanced energy security for farming areas, the production of energy in this manner could conceivably contribute to the overall national effort to reduce the Turkey's carbon footprint. This study explores the environmental benefits and burdens of one such option, that is, biogas production from a mixture of agricultural and animal waste through anaerobic digestion (AD), and its subsequent use for electricity and heat generation. A life-cycle assessment methodology was used, to measure the potential environmental impact of this option, in terms of global warming and total weighed impact, and to contrast it with the impact of producing the same amount of energy via an integrated gasification combined cycle process and a hard coal power plant. This study concentrates on an AD and cogeneration pilot plant, built in the Kocaeli province of Turkey and attempts to evaluate its potential environmental impacts. The study uses laboratory-scale studies, as well as literature and LCI databases to derive the operational parameters, yield and emissions of the plant. The potential impacts were calculated with EDIP 2003 methodology, using GaBi 5 LCA software. The results indicate that N2O emissions, resulting from the application of liquid and solid portions of digestate (a by-product of AD), as an organic fertilizer, are by far the largest contributors to global warming among all the life cycle stages. They constitute 68% of the total, whereas ammonia losses from the same process are the leading cause of terrestrial eutrophication. The photochemical ozone formation potential is significantly higher for the cogeneration phase, compared to other life cycle stages of the proposed scenario, due to NOx being emitted from the gas engine during combustion. Overall, the total environmental impact of the option was determined to be ten times lower than that of a hard coal option and 50% lower than the gasification option, since the latter does not generate digestate that is able to replace mineral fertilizer, thus mitigating the environmental footprint. Finally, the sustainability of energy production from agricultural and farm waste, via AD, was further enhanced by eliminating it from conventional waste management system practiced in the region, i.e. landfilling.

Material use for electricity generation with carbon dioxide capture and storage: Extending life cycle analysis indices for material accounting

Understanding of life cycle material use from novel technologies can assist informed decision making on technology and material selection consistent with natural physical boundaries. Though an intermediate process in conventional life cycle assessment (LCA), the information on material use is only translated into environmental impact potentials. In this study, we present a procedure to extract the intermediate information on material evaluation and perform a systematic life cycle material use analysis. The approach is then used to analyze electricity systems including electricity generation and transmission, with and without post-combustion carbon capture and storage (CCS) technology. Scenario analysis is then performed to understand the relations to the respective annual material production volumes.Results from the analysis of life cycle material use in the studied systems show that the implementation of CCS in a hard coal power plant results in the increased use of about 35% coal and limestone, 20% copper, 60% steel and 400% of the selected chemicals, as compared to the without CCS system. In addition to the complementary increase in specific resource use, the CCS technology uses over 35% and 70% increase in land and water requirement respectively. CCS scenario with coal power plant using CO2 capture (scenario S4) provides 83% reductions in the life cycle CO2 emissions and significant increase in the life cycle material use varying from 13% for coal to 168% for ammonia, as compared to the scenario with no CCS and with global average coal power plant efficiency (scenario S1).

Multi-commodity real options analysis of power plant investments: discounting endogenous risk structures

The value of power generation technologies can be derived from the investment cost, the plant’s expected lifetime, and the discounted cash flows, the latter of which typically are a combination of several underlyings, such as the price of fuel, electricity, and CO\(_2\). To determine this value, most studies assume predefined, uniform, and constant discount rates, irrespective of the fact that the specific risk strongly varies with the technology concerned and also over time. In order to endogenize the technology-specific risk, we develop a new model that explicitly accounts for the (likewise technology-specific) combination of the underlyings. More specifically, we use a multivariate binomial tree real options approach for analyzing the value of different power plants (gas-fired and coal-fired, with and without carbon capture and storage (CCS); hydro; wind; photovoltaics) and for taking into account technical change. We further investigate the influence of alternative CO\(_2\) policies on the plants’ values, modeling the CO\(_2\) price in three different ways and for three different carbon price levels (5, 25, 45 €/t\(_\mathrm{CO_2}\)): (1) as a stochastic process (geometric Brownian motion), reflecting the price development in the Emissions Trading Scheme of the European Union (EU ETS); (2) as a (constrained) stochastic process with a price floor, and (3) as a deterministic carbon tax. From the model application, using data from German exchange-based markets and a much-cited pilot study on future energy strategies and scenarios in Germany, we find a strong preference for hard-coal power plants in the low CO\(_2\) price scenario (\(P_{2015}=\) €5) and a low value of waiting in case of using the real options model. For all price scenarios, the value of waiting is much higher for both the CO\(_2\) permits with a price floor and the CO\(_2\) tax policy. This leads, for the medium and high CO\(_2\) price scenario, to a dominance of the CCS power plants. In the high CO\(_2\) price scenario (\(P_{2015}=\) €45), the value of waiting only delays the investment decision in the case of the floored CO\(_2\) permit prices. For the two other policies, the model predicts an immediate investment in CCS power plants once the CCS technology becomes commercially available in 2020.

Economic viability of biomass cofiring in new hard-coal power plants in Germany

Biomass cofiring in coal power plants (with thermal contributions of typically 5–20%) is an interesting option to mitigate CO2 emissions, since the additional costs are relatively minor and a secondary benefit is provided by the increased fuel flexibility. Worldwide, about 150 cofiring plants are in operation. In Germany, the electrical power potential for biomass cofiring in coal plants is about 28 TWh per annum, assuming a 10% replacement of coal combustion by biomass. In this paper, we study the economic potential of biomass cofiring in hard coal power plants in Germany. To this end, we identify suitable biomass input fuels, investment and operating costs, and the profitability of cofiring investments. In a sensitivity analysis, we check for the robustness of the results gained, and in a Monte Carlo simulation (MCS) uncertainties are explicitly taken into account. We find that both regional and international biomass supplies are relevant, and that the cost effectiveness of cofiring is strongly affected by the prices for biomass, coal and CO2 permits, while investment and operating costs only have a modest influence. According to our calculations, electrical power generation costs attributable to biomass combustion for a plant put into operation in 2020 are between 70 and 75 € MWh−1, while the average costs of biomass fuel from various sources and markets are calculated to be around 4.1 € GJ−1.

Initial Results from Fluor's CO2 Capture Demonstration Plant Using Econamine FG PlusSM Technology at E.ON Kraftwerke's Wilhelmshaven Power Plant

Fluor and E.ON have built a carbon dioxide recovery pilot plant using Fluor's proprietary Econamine FG PlusSM technology at E.ON's hard coal power plant in Wilhelmshaven, Germany. The capture plant is designed to recover approximately 70 Te/d of CO2 and will be used for data collection to facilitate scaling the design to a full sized coal power plant. The pilot plant has the configuration of a full size plant, including several technology improvements. The CO2 capture plant design includes technology advancements that are expected to lower energy demand, reduce costs, and improve the environmental signature of CO2 capture plant. The paper summarizes the technological advancements and initial results from the commissioning of the capture unit.

Economics of Biomass Co-Firing in New Hard Coal Power Plants in Germany

Biomass cofiring in coal power plants (with shares of typically 5-20%th) is an interesting option to mitigate CO2 emissions, since the additional costs are relatively minor and a secondary benefit is provided by the increased fuel flexibility. Worldwide, about 150 cofiring plants are in operation. In Germany, the potential for biomass cofiring in coal plants is about 28 TWhel per annum, assuming a 10% replacement of coal combustion by biomass. In this paper, we study the economic potential of biomass cofiring in hard coal power plants in Germany. To this end, we identify suitable biomass input fuels, investment and operating costs, and profitability of cofiring investments. In a sensitivity analysis, we check for the robustness of the results gained, and in a Monte Carlo simulation (MCS) uncertainties are explicitly taken into account. We find that both regional and international biomass supplies are relevant, and that the cost effectiveness of cofiring is strongly affected by prices for biomass, coal and CO2 permits, while investment and operating costs only have a modest influence. According to our calculations, power generation costs attributable to biomass combustion for a plant put into operation in 2020 are between 70-75 € MWhel -1 , while the average costs of biomass fuel from various sources and markets are calculated to be around 4.1 € GJ -1 .

NGCC and Hard-Coal Power Plant with CO2 Capture Based on Absorption

When integrating a power plant with post-combustion CO2 capture (e.g. chemical absorption) an efficiency penalty is induced on the joint process. The largest part of this penalty is related to lost power in the power plant steam turbine due to steam extraction used for solvent regeneration. In this work, a detailed integration study has been performed on a natural gas combined cycle (NGCC) and conventional steam power plant. The main task was to minimize the efficiency penalty by identifying the optimal extraction point and steam conditions. Alternative configurations within the capture process were investigated aiming at reducing the overall energy requirement of the capture process. GT PRO and STEAM PRO were used to model the NGCC and hard-coal plant, respectively, while UniSim® was used for capture process modeling. When including CO2 capture, results show an efficiency penalty 7%-points for the NGCC case (reduced from 58.3% to 51.2%), while the penalty of the coal-fired power plant was between 10.6%-points (reduced from 44.2% to 33.6%).Internal process modifications of the capture process indicated an overall energy saving potential of 11.4% when compared to the base case absorption process for the NGCC plant. The corresponding savings potential for the hard-coal plant was 12.1%. This improvement corresponded to an efficiency increase from 51.2% to 52.0% for the NGCC case, and 33.6% to 34.9% for the hard-coal case. Part-load simulations were performed in order to identify how the overall process was affected during part-load operation, with emphasis on parametric variations in the connecting points between the capture plant and power plant cycles.