Investigation of Environmental Effects Based on Exergetic Irreversibility for Display Cases’ Units in Commercial Cooling

This study examines energetic and exergetic performances of display cases’ units used in market applications depending on different refrigerants. Besides CO₂ emission potential of each refrigerant based on exergetic irreversibility obtained from analyses is calculated by the method of Total Equivalent Warming Impact (TEWI). In this study, 1 kW cooling capacity and vapor compression cooling cycle is taken as reference and refrigerants of R-22, R-134a, R-404A, and R-507 together with alternative refrigerant R-407C and R152a are examined separately. According to analyses, R-404A gas, used widely in market applications, has low performance with average COP 3.89 and average exergy efficiency 55.20%. R-152a gas has the best performance by the thermodynamics parameters including COP 4.49, exergy efficiency 63.79%, and 0.23 kW power consumption and emission parameter 14097.490 ton CO₂/year. Although COP is used as a criterion to evaluate the systems, this study finally emphasizes the importance of exergy analysis and TEWI method which are important methods to determine irreversibility and emission potential of the systems.     

Developing CO2 Emission Parameters to Measure the Environmental Impact on Cooling Applications

This study examines parametric approaches to the calculation of refrigerant-based CO₂ emissions in different cooling areas. Both the exergy analyses of refrigerants, used in domestic, commercial, transportation and industrial applications, and the environmental performances regarding exergetic irreversibility are investigated separately. Then, CO₂ emissions caused by systems are examined via two different parameters, I°) Environmental Impact Factor and ??°) Integrated Impact Factor (CIF). The study is based on a vapor compression cooling cycle model, commonly preferred by cooling applications, and the analyses have been made for 1 kW cooling capacity in relation to evaporator temperatures of the systems. In all cooling application, R134A gas stands out among the others in terms of coefficient of performance and exergy efficiency. Moreover, both emission analyses show that it has the lowest emission value. The paper concludes with an evaluation of the reasons for the refrigerant choice, the design and the selection of such a system, and why exergetic and environmental parameters should be preferred.     

An investigation of a heat pump system using CO2/propane mixture as a working fluid

In order to decrease the heat rejection pressure of heat pump using pure working fluid, CO₂ or R744, other natural component including hydrocarbons (R290, R600a, R600, R1270, R170, R601) and dimethyl ether (RE170) is added to CO₂, respectively, and then six binary mixtures are achieved. By environmental and thermodynamic comparisons, R290 is selected to be the most appropriate component candidate to mix with CO₂, and meanwhile to weaken the flammability and explosivity for pure R290. Then, the system performances of heat pump using mixture of CO₂ and R290 were experimentally studied when R290 is added to CO₂ with a small fraction, and compared with that of the pure CO₂. The experimental test rig is designed and set up for the transcritical heat pump system. When the refrigerant charge is variable, the heating coefficient performance, optimum heat rejection pressure, compressor power, mass flow rate of refrigerant, and total heat coefficient of gas cooler were researched. The variation ratios of heating coefficient performance and heating capacity with deviation from the optimum refrigerant charge were also investigated. The optimum refrigerant charge of CO₂/R290 is obtained and the research results show that the addition of R290 to CO₂ can efficiently reduce the heat rejection pressure and improve the system performance. The results in the present work could provide useful guidelines for the design and operation of heat pump system using CO₂-based mixture.     

Thermodynamic analysis on post-combustion CO2 capture of natural-gas-fired power plant

A chemical absorption, post-combustion CO₂ capture unit is simulated and an exergy analysis has been conducted, including irreversibility calculations for all process units. By pinpointing major irreversibilities, new proposals for efficient energy integrated chemical absorption process are suggested. Further, a natural-gas combined-cycle power plant with a CO₂ capture unit has been analyzed on an exergetic basis. By defining exergy balances and black-box models for plant units, investigation has been made to determine effect of each unit on the overall exergy efficiency. Simulation of the chemical absorption plant was done using UniSim Design software with Amines Property Package. For natural-gas combined-cycle design, GT PRO software (Thermoflow, Inc.) has been used. For exergy calculations, spreadsheets are created with Microsoft Excel by importing data from UniSim and GT PRO. Results show the exergy efficiency of 21.2% for the chemical absorption CO₂ capture unit and 67% for the CO₂ compression unit. The total exergy efficiency of CO₂ capture and compression unit is 31.6%.     

The potential for increased atmospheric CO2 emissions and accelerated consumption of deep geologic CO2 storage resources resulting from the large-scale deployment of a CCS-enabled unconventional fossil fuels industry in the U.S.

Desires to enhance the energy security of the United States have spurred renewed interest in the development of abundant domestic heavy hydrocarbon resources including oil shale and coal to produce unconventional liquid fuels to supplement conventional oil supplies. However, the production processes for these unconventional fossil fuels create large quantities of carbon dioxide (CO₂) and this remains one of the key arguments against such development. Carbon dioxide capture and storage (CCS) technologies could reduce these emissions and preliminary analysis of regional CO₂ storage capacity in locations where such facilities might be sited within the U.S. indicates that there appears to be sufficient storage capacity, primarily in deep saline formations, to accommodate the CO₂ from these industries. Nevertheless, even assuming wide-scale availability of cost-effective CO₂ capture and geologic storage resources, the emergence of a domestic U.S. oil shale or coal-to-liquids (CTL) industry would be responsible for significant increases in CO₂ emissions to the atmosphere. The authors present modeling results of two future hypothetical climate policy scenarios that indicate that the oil shale production facilities required to produce 3 MMB/d from the Eocene Green River Formation of the western U.S. using an in situ retorting process would result in net emissions to the atmosphere of between 3000 and 7000 MtCO₂, in addition to storing potentially 900–5000 MtCO₂ in regional deep geologic formations via CCS in the period up to 2050. A similarly sized, but geographically more dispersed domestic CTL industry could result in 4000–5000 MtCO₂ emitted to the atmosphere in addition to potentially 21,000–22,000 MtCO₂ stored in regional deep geologic formations over the same period. While this analysis shows that there is likely adequate CO₂ storage capacity in the regions where these technologies are likely to deploy, the reliance by these industries on large-scale CCS could result in an accelerated rate of utilization of the nation's CO₂ storage resource, leaving less high-quality storage capacity for other carbon-producing industries including electric power generation.     

A model for the CO2 capture potential

Global warming is a result of increasing anthropogenic CO₂ emissions, and the consequences will be dramatic climate changes if no action is taken. One of the main global challenges in the years to come is therefore to reduce the CO₂ emissions.Increasing energy efficiency and a transition to renewable energy as the major energy source can reduce CO₂ emissions, but such measures can only lead to significant emission reductions in the long-term. Carbon capture and storage (CCS) is a promising technological option for reducing CO₂ emissions on a shorter time scale.A model to calculate the CO₂ capture potential has been developed, and it is estimated that 25 billion tonnes CO₂ can be captured and stored within the EU by 2050. Globally, 236 billion tonnes CO₂ can be captured and stored by 2050. The calculations indicate that wide implementation of CCS can reduce CO₂ emissions by 54% in the EU and 33% globally in 2050 compared to emission levels today.Such a reduction in emissions is not sufficient to stabilize the climate. Therefore, the strategy to achieve the necessary CO₂ emissions reductions must be a combination of (1) increasing energy efficiency, (2) switching from fossil fuel to renewable energy sources, and (3) wide implementation of CCS.     

Economic evaluation of the geological storage of CO2 considering the scale of economy

CO₂ capture and storage (CCS) technology is expected to play an important role in the efforts directed toward long-term CO₂ emission reduction. This paper analyzes the cost of the geological storage of CO₂ in Japan in order to consider future research, development and deployment (RD&D); these would be based on the information of the obtained cost structure. According to the analysis results, the costs, particularly those of the transportation by pipeline and of CO₂ injection, strongly depend on the scale of the facilities. Therefore, the distance of the transportation of CO₂ should be minimized in the case of small-scale storage, particularly in Japan. In addition, the potential injection rate per well is another key factor for the injection cost. Based on the analyzed cost, the injection cost of the geological storage of CO₂ in Japan for individual storage sites is estimated, and the cost–potential curve is obtained. A mixed-integer programming model has been developed to take into account these characteristics of the CCS technology and its adverse effects arising from the scale of economy with regard to the transportation and injection cost for the geological storage of CO₂. The model is designed to evaluate CCS and other CO₂ mitigation technologies in the energy systems of Japan. With all these adverse effects due to the scale of economy, the geological storage of CO₂ will be one of the important options for CO₂ emission reduction in Japan.     

Energy technology modelling of major carbon abatement options

The International Energy Agency Energy Technologies Perspectives (ETP) model is used to assess the prospects for carbon abatement options, including carbon capture and storage, up to 2050. Three main scenarios are considered: a Baseline scenario with current energy policies, an accelerated technology scenario that seeks to return energy-related CO₂ emissions in 2050 to their level in 2005, and a scenario for which CO₂ emissions are reduced at 50% of current levels by 2050. To reach these emissions reduction targets, annual global CO₂ emissions in the year 2050 must be reduced by 35 GtCO₂ to 48 GtCO₂ compared to the Baseline scenario. The analysis presented here shows that a broad portfolio of emissions reducing technologies will need to be deployed across all economic sectors of the global economy to reach these targets. Carbon dioxide capture and storage (CCS) is one of the suite of technologies employed across the globe to reach these targets. CCS adoption occurs in many aspects of the global economy and accounts for 14–19% of all emissions reductions. The total amount of CO₂ captured and stored in deep geologic reservoirs up to 2050 ranges between 5.1 GtCO₂ and 10.4 GtCO₂ in these two climate policy scenarios. Up to 2030, more than half of total CCS deployment takes place in OECD countries. After 2035, emerging economies account for more than half of total CCS use. This paper also demonstrates that as the climate policy becomes more stringent it will be necessary for CCS to deploy more extensively in many different industries outside of the electric power sector which often receives the most attention in discussions of CCS's role in addressing climate change.     

Modeling the impacts of climate policy on the deployment of carbon dioxide capture and geologic storage across electric power regions in the United States

This paper summarizes the results of a first-of-its-kind holistic, integrated economic analysis of the potential role of carbon dioxide (CO₂) capture and storage (CCS) technologies across the regional segments of the United States (U.S.) electric power sector, over the time frame 2005–2045, in response to two hypothetical emissions control policies analyzed against two potential energy supply futures that include updated and substantially higher projected prices for natural gas. This paper's detailed analysis is made possible by combining two specialized models developed at Battelle: the Battelle CO₂-GIS to determine the regional capacity and cost of CO₂ transport and geologic storage; and the Battelle Carbon Management Electricity Model, an electric system optimal capacity expansion and dispatch model, to examine the investment and operation of electric power technologies with CCS against the background of other options. A key feature of this paper's analysis is an attempt to explicitly model the inherent heterogeneities that exist in both the nation's current and future electricity generation infrastructure and in its candidate deep geologic CO₂ storage formations. Overall, between 180 and 580 gigawatts (GW) of coal-fired integrated gasification combined cycle with CCS (IGCC + CCS) capacity is built by 2045 in these four scenarios, requiring between 12 and 41 gigatonnes of CO₂ (GtCO₂) storage in regional deep geologic reservoirs across the U.S. Nearly all of this CO₂ is from new IGCC + CCS systems, which start to deploy after 2025. Relatively little IGCC + CCS capacity is built before that time, primarily under unique niche opportunities. For the most part, CO₂ emissions prices will likely need to be sustained at over $20/tonne CO₂ before CCS begins to deploy on a large scale within the electric power sector. Within these broad national trends, a highly nuanced picture of CCS deployment across the U.S. emerges. Across the four scenarios studied here, power plant builders and operators within some North American Electric Reliability Council (NERC) regions do not employ any CCS while other regions build more than 100 GW of CCS-enabled generation capacity. One region sees as much as 50% of its geologic CO₂ storage reservoirs’ total theoretical capacity consumed by 2045, while most of the regions still have more than 90% of their potential storage capacity available to meet storage needs in the second half of the century and beyond. A detailed presentation of the results for power plant builds and operation in two key regions: ECAR in the Midwest and ERCOT in Texas, provides further insight into the diverse set of economic decisions that generate the national and aggregate regional results.     

Viscosities, thermal conductivities and diffusion coefficients of CO2 mixtures: Review of experimental data and theoretical models

Accurate experimental data on the thermo-physical properties of CO₂-mixtures are pre-requisites for development of more accurate models and hence, more precise design of CO₂ capture and storage (CCS) processes. A literature survey was conducted on both the available experimental data and the theoretical models associated with the transport properties of CO₂-mixtures within the operation windows of CCS. Gaps were identified between the available knowledge and requirements of the system design and operation. For the experimental gas-phase measurements, there are no available data about any transport properties of CO₂/H₂S, CO₂/COS and CO₂/NH₃; and except for CO₂/H₂O(/NaCl) and CO₂/amine/H₂O mixtures, there are no available measurements regarding the transport properties of any liquid-phase mixtures. In the prediction of gas-phase viscosities using Chapman–Enskog theory, deviations are typically <2% at atmospheric pressure and moderate temperatures. The deviations increase with increasing temperatures and pressures. Using both the Rigorous Kinetic Theory (RKT) and empirical models in the prediction of gas-phase thermal conductivities, typical deviations are 2.2–9%. Comparison of popular empirical models for estimation of gas-phase diffusion coefficients with newer experimental data for CO₂/H₂O shows deviations of up to 20%. For many mixtures relevant for CCS, the diffusion coefficient models based on the RKT show predictions within the experimental uncertainty. Typical reported deviations of the CO₂/H₂O system using empirical models are below 3% for the viscosity and the thermal conductivity and between 5 and 20% for the diffusion coefficients. The research community knows little about the effect of other impurities in liquid CO₂ than water, and this is an important area to focus in future work.     

Pathways towards large-scale implementation of CO2 capture and storage: A case study for the Netherlands

We sketch four possible pathways how carbon dioxide capture and storage (CCS) (r)evolution may occur in the Netherlands, after which the implications in terms of CO₂ stored and avoided, costs and infrastructural requirements are quantified. CCS may play a significant role in decarbonising the Dutch energy and industrial sector, which currently emits nearly 100 Mt CO₂/year. We found that 15 Mt CO₂ could be avoided annually by 2020, provided some of the larger gas fields that become available the coming decade could be used for CO₂ storage. Halfway this century, the mitigation potential of CCS in the power sector, industry and transport fuel production is estimated at maximally 80–110 Mt CO₂/year, of which 60–80 Mt CO₂/year may be avoided at costs between 15 and 40 €/t CO₂, including transport and storage. Avoiding 30–60 Mt CO₂/year by means of CCS is considered realistic given the storage potential represented by Dutch gas fields, although it requires planning to assure that domestic storage capacity could be used for CO₂ storage. In an aggressive climate policy, avoiding another 50 Mt CO₂/year may be possible provided that nearly all capture opportunities that occur are taken. Storing such large amounts of CO₂ would only be possible if the Groningen gas field or large reservoirs in the British or Norwegian part of the North Sea will become available.     

Life cycle assessment of a pulverized coal power plant with post-combustion capture, transport and storage of CO2

In this study the methodology of life cycle assessment has been used to assess the environmental impacts of three pulverized coal fired electricity supply chains with and without carbon capture and storage (CCS) on a cradle to grave basis. The chain with CCS comprises post-combustion CO₂ capture with monoethanolamine, compression, transport by pipeline and storage in a geological reservoir. The two reference chains represent sub-critical and state-of-the-art ultra supercritical pulverized coal fired electricity generation. For the three chains we have constructed a detailed greenhouse gas (GHG) balance, and disclosed environmental trade-offs and co-benefits due to CO₂ capture, transport and storage. Results show that, due to CCS, the GHG emissions per kWh are reduced substantially to 243 g/kWh. This is a reduction of 78 and 71% compared to the sub-critical and state-of-the-art power plant, respectively. The removal of CO₂ is partially offset by increased GHG emissions in up- and downstream processes, to a small extent (0.7 g/kWh) caused by the CCS infrastructure. An environmental co-benefit is expected following from the deeper reduction of hydrogen fluoride and hydrogen chloride emissions. Most notable environmental trade-offs are the increase in human toxicity, ozone layer depletion and fresh water ecotoxicity potential for which the CCS chain is outperformed by both other chains. The state-of-the-art power plant without CCS also shows a better score for the eutrophication, acidification and photochemical oxidation potential despite the deeper reduction of SO_x and NO_x in the CCS power plant. These reductions are offset by increased emissions in the life cycle due to the energy penalty and a factor five increase in NH₃ emissions.     

Exergy analysis of the transcritical N2O refrigeration cycle with a vortex tube

In this article, a comparative study is presented for the transcritical cycle with expansion valve (TCEV) and transcritical cycle with vortex tube (TCVT) mainly based on the second law of thermodynamics. Natural refrigerant nitrous oxide (N₂O) is used in both the cycles for analysis. The evaporator and gas cooler temperatures are varied from ?55°C to 5°C and 35°C to 60°C, respectively. The effects of various operating and design parameters on the optimum heat rejection pressure, coefficient of performance (COP), exergy loss (irreversibility), and the exergetic efficiency are studied. Exergy analysis of each component in TCEV and TCVT is performed to identify the amount and locations of irreversibility. It is observed that the use of the vortex tube in place of the expansion valve reduces the total exergy losses and increases the exergetic efficiency as well as COP. The exergetic efficiency and COP of the TCVT are on average 10–12% higher compared to TCEV for the considered operating conditions. The computed values of the exergetic efficiency for TCVT using refrigerant N₂O are the highest at an evaporator temperature of ?55°C, and the corresponding values of exergetic efficiency and exergy losses varies between 25.35% and 15.67% and between 74.65% and 84.33%, respectively. However, COP at the same evaporator temperature of ?55°C varies between 0.83 and 0.51. Furthermore, the optimum heat rejection pressure in TCVT is lower compared to that in TCEV. The results offer significant help for the optimum design and operating conditions of TCVT with refrigerant N₂O.     

Regulatory challenges and managing public perception in planning a geological storage pilot project in Australia

The implementation of geological storage of CO₂ requires not only further research and development but also the demonstration of carbon dioxide capture and storage (CCS) technology as a viable option. A pilot program is an important first step towards building industry and community confidence in the application of CCS. The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), Australia's leading research organisation in CCS, has initiated a comprehensive research and demonstration program in the Otway Basin in South-West Victoria. As the first project of its kind in Australia, the Otway Basin Pilot Project (OBPP) has faced a number of regulatory and organisational challenges while having to concurrently address public perception. The Otway Basin site with its natural CO₂ accumulations and many depleted natural gas fields offers an appropriate CO₂ storage site to test scientific and regulatory concepts and evaluate public response through social research. The project aims to show that CO₂ can be safely captured, transported and stored deep underground under local conditions, and also monitored and verified. Planning has been ongoing for over a year, baseline studies are underway and the project is targeted to start injection in 2007.     

Exergy analysis as a tool for the integration of very complex energy systems: The case of carbonation/calcination CO2 systems in existing coal power plants

A common characteristic of carbon capture and storage systems is the important energy consumption associated with the CO₂ capture process. This important drawback can be solved with the analysis, synthesis and optimization of this type of energy systems. The second law of thermodynamics has proved to be an essential tool in power and chemical plant optimization. The exergy analysis method has demonstrated good results in the synthesis of complex systems and efficiency improvements in energy applications.In this paper, a synthesis of pinch analysis and second law analysis is used to show the optimum window design of the integration of a calcium looping cycle into an existing coal power plant for CO₂ capture. Results demonstrate that exergy analysis is an essential aid to reduce energy penalties in CO₂ capture energy systems. In particular, for the case of carbonation/calcination CO₂ systems integrated in existing coal power plants, almost 40% of the additional exergy consumption is available in the form of heat. Accordingly, the efficiency of the capture cycle depends strongly on the possibility of using this heat to produce extra steam (live, reheat and medium pressure) to generate extra power at steam turbine. The synthesis of pinch and second law analysis could reduce the additional coal consumption due to CO₂ capture 2.5 times, from 217 to 85 MW.     

Life cycle assessment of carbon dioxide capture and storage from lignite power plants

In this article, we present a life cycle assessment (LCA) of CO₂ capture and storage (CCS) for several lignite power plant technologies. The LCA includes post-combustion, pre-combustion and oxyfuel capture processes as well as subsequent pipeline transport and storage of the separated CO₂ in a depleted gas field.The results show an increase in cumulative energy demand and a substantial decrease in greenhouse gas (GHG) emissions for all CO₂ capture approaches in comparison with power plants without CCS, assuming negligible leakage within the time horizon under consideration. Leakage will, however, not be zero. Due to the energy penalty, CCS leads to additional production of CO₂. However, the CO₂ emissions occur at a much lower rate and are significantly delayed, thus leading to different, and most likely smaller, impacts compared to the no-sequestration case. In addition, a certain share of the CO₂ will be captured permanently due to chemical reactions and physical trapping.For other environmental impact categories, the results depend strongly on the chosen technology and the details of the process. The post-combustion approach, which is closest to commercial application, leads to sharp increases in many categories of impacts, with the impacts in only one category, acidification, reduced. In comparison with a conventional power plant, the pre-combustion approach results in decreased impact in all categories. This is mainly due to the different power generation process (IGCC) which is coupled with the pre-combustion technology.In the case of the oxyfuel approach, the outcome of the LCA depends highly on two uncertain parameters: the energy demand for air separation and the feasibility of co-capture of pollutants other than CO₂. If co-capture were possible, oxyfuel could lead to a near-zero emission power plant.     

Global energy and emissions scenarios for effective climate change mitigation—Deterministic and stochastic scenarios with the TIAM model

The achievement possibilities of the EU 2 °C climate target have been assessed with the ETSAP TIAM global energy systems model. Cost-effective global and regional mitigation scenarios of carbon dioxide, methane, nitrous oxide and F-gases were calculated with alternative assumptions on emissions trading. In the mitigation scenarios, an 85% reduction in CO₂ emissions is needed from the baseline, and very significant changes in the energy system towards emission-free sources take place during this century. The largest new technology groups are carbon-capture and storage (CCS), nuclear power, wind power, advanced bioenergy technologies and energy efficiency measures. CCS technologies contributed a 5.5-Pg CO₂ annual emission reduction by 2050 and 12 Pg CO₂ reduction by 2100. Also large-scale forestation measures were found cost-efficient. Forestation measures reached their maximum impact of 7.7 Pg CO₂ annual emission reduction in 2080. The effects of uncertainties in the climate sensitivity have been analysed with stochastic scenarios.     

Dynamis CO2 quality recommendations

In the carbon capture and storage (CCS) chain, transport and storage set different requirements for the composition of the gas stream mainly containing carbon dioxide (CO₂). Currently, there is a lack of standards to define the required quality for CO₂ pipelines. This study investigates and recommends likely maximum allowable concentrations of impurities in the CO₂ for safe transportation in pipelines. The focus is on CO₂ streams from pre-combustion processes. Among the issues addressed are safety and toxicity limits, compression work, hydrate formation, corrosion and free water formation, including the cross-effect of H₂S and H₂O and of H₂O and CH₄.