A framework for assessing the CO2 mitigation options for the electricity generation sub-sector

The primary objective of this work is to develop an approach for evaluating GHG mitigation strategies that considers the detailed operation of the electricity system in question and to ascertain whether considering the detailed operation of the electricity system materially affects the assessment. A secondary objective is to evalute the potential benefit of flexible CO2 capture and storage. An electricity system simlator is developed based upon a deregulated electricity system containing markets for both real and reserve power. Using the IEEE RTS ’96 as a test case, the performance of the electricity system is benchmarked with GHG regulation. Two different implementations of CO2 capture are added to the electricity system — fixed CO2 capture and flexible CO2 capture — and the impact of having CCS is assessed. The results indicate that: - the assessment of GHG mtigation strategies for the electricity generation subsector should consider the detailed operation of the electricity system in question, - cost of generation alone is not necessarily a good indicator of the economic impact of GHG regulation or the deployment of a GHG mitigation strategy, - adding CCS, at even a single generating unit, can significantly reduce GHG emissions and moderate the ecnomic impact of GHG regulation relative to the cases where CCS is not present, and - a generating unit with a flexible CCS processes participates preferentially in the reserve market enabling it to increase its net energy benefit. It is conclued that there is a significant potential advantage to generating units with flexible CCS processes. The flexibiity of existing and novel CCS process should be an assessment and design criterion, respectively, and the development of novel CCS processes with optimial operability is a suggested area of future research activity. A reduced-order model of a coal-fired generating unit with flexible CO2 capture is developed and integrated into the MINLP formulation of an economic dispatch model. Both of these efforts, not observed previously in the literature, constitute an important contribution of the work as the methodology provides a template for future assessmments of CCS and other electricity mitigation strategies in the electricity generation subsector

An economic evaluation of the potential for distributed energy in Australia

Australia’s Commonwealth Scientific and Industrial Research Organisation (CSIRO) recently completed a major study investigating the value of distributed energy (DE; collectively demand management, energy efficiency and distributed generation) technologies for reducing greenhouse gas emissions from Australia’s energy sector (CSIRO, 2009). This comprehensive report covered potential economic, environmental, technical, social, policy and regulatory impacts that could result from the wide scale adoption of these technologies. In this paper we highlight the economic findings from the study. Partial Equilibrium modeling of the stationary and transport sectors found that Australia could achieve a present value welfare gain of around $130 billion when operating under a 450 ppm carbon reduction trajectory through to 2050. Modeling also suggests that reduced volatility in the spot market could decrease average prices by up to 12% in 2030 and 65% in 2050 by using local resources to better cater for an evolving supply-demand imbalance. Further modeling suggests that even a small amount of distributed generation located within a distribution network has the potential to significantly alter electricity prices by changing the merit order of dispatch in an electricity spot market. Changes to the dispatch relative to a base case can have both positive and negative effects on network losses.Distributed energy; Economic modeling; Carbon price; Electricity markets

Parametric study on the regeneration heat requirement of an amine-based solid adsorbent process for post-combustion carbon capture

The thermal energy required for regeneration of CO2-rich adsorbents or absorbents is usually regarded as the most important criterion to evaluate different materials and processes for application in commercialscale CO2 capture systems. It is expected that the regeneration heat can be greatly reduced by replacing the mature aqueous monoethanolamine (MEA) technology with amine-based solid adsorbents capturing systems, due to the much lower heat capacity of solid adsorbents comparing to aqueous MEA and the avoidance of evaporating a large amount of water in the regenerator. Comparing to the MEA technology, the regeneration heat for solid adsorbent based systems has not received adequate attention especially on the impacts of process related parameters. Further, the methodologies used in previous investigations to calculate the regeneration heat may have deficiencies in defining the working capacities, adopting proper heat recovery strategies and/or evaluating the effect of moisture co-adsorption. In this study, an energy equation to calculate the regeneration heat has been revised and proposed to systematically evaluate the most important parameters affecting the regeneration heat, including the physical properties of the adsorbents and process related variables including the heat of adsorption, specific heat capacity, working capacity, moisture adsorption of the polyethyleneimine (PEI)/silica adsorbent, the swing temperature difference and the degree of heat recovery. Based on the parametric analysis, the calculated regeneration heat for the PEI/silica adsorbent based system is found to be around 2.46 GJ/tCO2, which is much lower than the value of 3.9 GJ/tCO2 for a typical aqueous MEA system and is also lower than 3.3 GJ/tCO2 for an advanced MEA system. Sensitivity analysis of all the parameters has also been conducted and the results have shown that working capacity, moisture adsorption and heat recovery ratios are the most influential factors. With more proficiency and development in the energy efficient process designs, the advantages of a solid adsorbent based capturing system over typical MEA systems will be justified

Process simulations of post-combustion CO2 capture for coal and natural gas-fired power plants using a polyethyleneimine/silica adsorbent

The regeneration heat for a polyethyleneimine (PEI)/silica adsorbent based carbon capture system is first assessed in order to evaluate its effect on the efficiency penalty of a coal or natural gas power plant. Process simulations are then carried out on the net plant efficiencies for a specific supercritical 550 MWe pulverized coal (PC) and a 555 MWe natural gas combined cycle (NGCC) power plant integrated with a conceptually designed capture system using fluidized beds and PEI/silica adsorbent. A benchmark system applying an advanced MEA absorption technology in a NETL report (2010) is used as a reference system. Using the conservatively estimated parameters, the net plant efficiency of the PC and NGCC power plant with the proposed capture system is found to be 1.5% and 0.6% point higher than the reference PC and NGCC systems, respectively. Sensitivity analysis has revealed that the moisture adsorption, working capacity and heat recovery strategies are the most influential parameters to the power plant efficiency. Under an optimal scenario with improvements in increasing the working capacity by 2% points and decreasing moisture adsorption by 1% point, the plant efficiencies with the proposed capture system are 2.7% (PC) and 1.9% (NGCC) points higher than the reference systems

CO₂ Capture With MEA: Integrating the Absorption Process and Steam Cycle of an Existing Coal-Fired Power Plant

In Canada, coal-fired power plants are the largest anthropogenic point sources of atmospheric CO2. The most promising near-term strategy for mitigating CO2 emissions from these facilities is the post-combustion capture of CO2 using MEA (monoethanolamine) with subsequent geologic sequestration. While MEA absorption of CO2 from coal-derived flue gases on the scale proposed above is technologically feasible, MEA absorption is an energy intensive process and especially requires large quantities of low-pressure steam. It is the magnitude of the cost of providing this supplemental energy that is currently inhibiting the deployment of CO2 capture with MEA absorption as means of combatting global warming. The steam cycle of a power plant ejects large quantities of low-quality heat to the surroundings. Traditionally, this waste has had no economic value. However, at different times and in different places, it has been recognized that the diversion of lower quality streams could be beneficial, for example, as an energy carrier for district heating systems. In a similar vein, using the waste heat from the power plant steam cycle to satisfy the heat requirements of a proposed CO2 capture plant would reduce the required outlay for supplemental utilities; the economic barrier to MEA absorption could be removed. In this thesis, state-of-the-art process simulation tools are used to model coal combustion, steam cycle, and MEA absorption processes. These disparate models are then combined to create a model of a coal-fired power plant with integrated CO2 capture. A sensitivity analysis on the integrated model is performed to ascertain the process variables which most strongly influence the CO2 energy penalty. From the simulation results with this integrated model, it is clear that there is a substantial thermodynamic advantage to diverting low-pressure steam from the steam cycle for use in the CO2 capture plant. During the course of the investigation, methodologies for using Aspen Plus® to predict column pressure profiles and for converging the MEA absorption process flowsheet were developed and are herein presented

Carbon capture and storage from the boiler to the fleet - A canadian case study

This paper presents a techno-economic analysis of the capture and storage of CO2 from a single coal fired boiler with extensions to a fleet of coal, natural gas, nuclear, hydroelectric and wind generating stations. AspenPlus™ was used to simulate a 500 MW coal boiler c/w steam cycle and MEA absorption process. The energy required by the absorption process resulted in a ~30% de-rate in the generating station output. 14,000 tonnes/day of pure CO2 captured and compressed from the boiler was transported and injected into a saline aquifer approximately 125 km from the generating station and at least 800 m beneath the earth’s surface under supercritical conditions, (31.1°C, 7.38 MPa). The cost to transfer CO2 from the boiler and inject it underground is ~10 US$/tonne of CO2. The extension from a single boiler to the entire fleet of generating stations was formulated as an MILP and implemented in GAMS. A 3% fleet-wide reduction in CO2 emissions was achieved by fuel-balancing alone. Deeper reductions, however, required a combination of CO2 capture and storage, fuelswitching and new capacity including IGCC, NGCC and nuclear. For example, the cost of electricity increased by ~59% when reducing the fleet-wide emissions by 60%

An economic evaluation of the potential for distributed energy in Australia

We present here economic findings from a major study by Australia's Commonwealth Scientific and Industrial Research Organisation (CSIRO) on the value of distributed energy technologies (DE; collectively demand management, energy efficiency and distributed generation) for reducing greenhouse gas emissions from Australia's energy sector (CSIRO, 2009). The study covered potential economic, environmental, technical, social, policy and regulatory impacts that could result from their wide scale adoption. Partial Equilibrium modeling of the stationary energy and transport sectors found that Australia could achieve a present value welfare gain of around $130 billion when operating under a 450 ppm carbon reduction trajectory through to 2050. Modeling also suggests that reduced volatility in the spot market could decrease average prices by up to 12% in 2030 and 65% in 2050 by using local resources to better cater for an evolving supply–demand imbalance. Further modeling suggests that even a small amount of distributed generation located within a distribution network has the potential to significantly alter electricity prices by changing the merit order of dispatch in an electricity spot market. Changes to the dispatch relative to a base case can have both positive and negative effects on network losses

Clinical features of patients isolated for suspected Ebola virus disease at Connaught Hospital, Freetown, Sierra Leone: a retrospective cohort study.

BACKGROUND: The size of the west African Ebola virus disease outbreak led to the urgent establishment of Ebola holding unit facilities for isolation and diagnostic testing of patients with suspected Ebola virus disease. Following the onset of the outbreak in Sierra Leone, patients presenting to Connaught Hospital in Freetown were screened for suspected Ebola virus disease on arrival and, if necessary, were admitted to the on-site Ebola holding unit. Since demand for beds in this unit greatly exceeded capacity, we aimed to improve the selection of patients with suspected Ebola virus disease for admission by identifying presenting clinical characteristics that were predictive of a confirmed diagnosis. METHODS: In this retrospective cohort study, we recorded the presenting clinical characteristics of suspected Ebola virus disease cases admitted to Connaught Hospital's Ebola holding unit. Patients were subsequently classified as confirmed Ebola virus disease cases or non-cases according to the result of Ebola virus reverse-transcriptase PCR (EBOV RT-PCR) testing. The sensitivity, specificity, positive predictive value, negative predictive value, and likelihood ratio of every clinical characteristic were calculated, to estimate the diagnostic accuracy and predictive value of each clinical characteristic for confirmed Ebola virus disease. RESULTS: Between May 29, 2014, and Dec 8, 2014, 850 patients with suspected Ebola virus disease were admitted to the holding unit, of whom 724 had an EBOV RT-PCR result recorded and were included in the analysis. In 464 (64%) of these patients, a diagnosis of Ebola virus disease was confirmed. Fever or history of fever (n=599, 83%), intense fatigue or weakness (n=495, 68%), vomiting or nausea (n=365, 50%), and diarrhoea (n=294, 41%) were the most common presenting symptoms in suspected cases. Presentation with intense fatigue, confusion, conjunctivitis, hiccups, diarrhea, or vomiting was associated with increased likelihood of confirmed Ebola virus disease. Three or more of these symptoms in combination increased the probability of Ebola virus disease by 3·2-fold (95% CI 2·3-4·4), but the sensitivity of this strategy for Ebola virus disease diagnosis was low. In a subgroup analysis, 15 (9%) of 161 confirmed Ebola virus disease cases reported neither a history of fever nor a risk factor for Ebola virus disease exposure. INTERPRETATION: Discrimination of Ebola virus disease cases from patients without the disease is a major challenge in an outbreak and needs rapid diagnostic testing. Suspected Ebola virus disease case definitions that rely on history of fever and risk factors for Ebola virus disease exposure do not have sufficient sensitivity to identify all cases of the disease. FUNDING: None