Low-carbon Generation Technologies Research Articles

Opportunities for low-carbon generation and storage technologies to decarbonise the future power system

Alternatives to cope with the challenges of high shares of renewable electricity in power systems have been addressed from different approaches, such as energy storage and low-carbon technologies. However, no model has previously considered integrating these technologies under stability requirements and different climate conditions. In this study, we include this approach to analyse the role of new technologies to decarbonise the power system. The Spanish power system is modelled to provide insights for future applications in other regions. After including storage and low-carbon technologies (currently available and under development), batteries and hydrogen fuel cells have low penetration, and the derived emission reduction is negligible in all scenarios. Compressed air storage would have a limited role in the short term, but its performance improves in the long term. Flexible generation technologies based on hydrogen turbines and long-duration storage would allow the greatest decarbonisation, providing stability and covering up to 11–14 % of demand in the short and long term. The hydrogen storage requirement is equivalent to 18 days of average demand (well below the theoretical storage potential in the region). When these solutions are considered, decarbonising the electricity system (achieving Paris targets) is possible without a significant increase in system costs (< € 114/MWh).

Constructing practices of engagement with users and communities: Comparing emergent state-led smart local energy systems

Energy transitions require engagement with users, local communities and wider publics in order to be fair, acceptable and, ultimately, successful. Here we focus on the development of decentralised energy systems instigated by central government. Smart Local Energy Systems (SLES), involving low carbon generation, demand sources and smart technologies in a geographically-bounded location, are important but unexplored contexts for public engagement. Drawing on 23 interviews with partner organisations in 12 UK SLES projects, we investigate the targets, methods and rationales of engagement. Partners engage a range of user and community groups around multiple energy system components using a variety of methods, directly and via intermediary organisations. Project size is not a major influence on breadth and intensity of engagement. Project partners rationalise practices with reference to characterisations of users and engagement, and practices are conditioned by a range of factors (e.g. technological boundaries, place, partners involved, and the wider organisational context within which SLES projects take place). We highlight a need for future SLES policy to emphasise engagement as a key facet, institute systematic social learning between SLES projects, and consider how to engage publics beyond the boundaries of individual projects.

Local Electricity Markets for Electric Vehicles: An Application Study Using a Decentralized Iterative Approach

Local electricity markets are emerging solutions to enable local energy trade for the end users and provide grid support services when required. Various models of local electricity markets (LEMs) have been proposed in the literature. The peer-to-peer market model appears as a promising structure among the proposed models. The peer-to-peer market structure enables electricity transactions between the players in a local energy system at a lower cost. It promotes the production from the small low–carbon generation technologies. Energy communities can be the ideal place to implement local electricity markets as they are designed to allow for larger growth of renewable energy and electric vehicles, while benefiting from local transactions. In this context, a LEM model is proposed considering an energy community with high penetration of electric vehicles in which prosumer-to-vehicle (P2V) transactions are possible. Each member of the energy community can buy electricity from the retailer or other members and sell electricity. The problem is modeled as a mixed-integer linear programing (MILP) formulation and solved within a decentralized and iterative process. The decentralized implementation provides acceptable solutions with a reasonable execution time, while the centralized implementation usually gives an optimal solution at the expense of reduced scalability. Preliminary results indicate that there are advantages for EVs as participants of the LEM, and the proposed implementation ensures an optimal solution in an acceptable execution time. Moreover, P2V transactions benefit the local distribution grid and the energy community.

Impact of carbon dioxide removal technologies on deep decarbonization of the electric power sector

Carbon dioxide removal technologies, such as bioenergy with carbon capture and direct air capture, are valuable for stringent climate targets. Previous work has examined implications of carbon removal, primarily bioenergy-based technologies using integrated assessment models, but not investigated the effects of a portfolio of removal options on power systems in detail. Here, we explore impacts of carbon removal technologies on electric sector investments, costs, and emissions using a detailed capacity planning and dispatch model with hourly resolution. We show that adding carbon removal to a mix of low-carbon generation technologies lowers the costs of deep decarbonization. Changes to system costs and investments from including carbon removal are larger as policy ambition increases, reducing the dependence on technologies like advanced nuclear and long-duration storage. Bioenergy with carbon capture is selected for net-zero electric sector emissions targets, but direct air capture deployment increases as biomass supply costs rise.

Beyond short-duration energy storage

Long-duration energy storage technologies can be a solution to the intermittency problem of wind and solar power but estimating technology costs remains a challenge. New research identifies cost targets for long-duration storage technologies to make them competitive against different firm low-carbon generation technologies.

The design space for long-duration energy storage in decarbonized power systems

Long-duration energy storage (LDES) is a potential solution to intermittency in renewable energy generation. In this study we have evaluated the role of LDES in decarbonized electricity systems and identified the cost and efficiency performance necessary for LDES to substantially reduce electricity costs and displace firm low-carbon generation. Our findings show that energy storage capacity cost and discharge efficiency are the most important performance parameters. Charge/discharge capacity cost and charge efficiency play secondary roles. Energy capacity costs must be ≤US$20 kWh–1 to reduce electricity costs by ≥10%. With current electricity demand profiles, energy capacity costs must be ≤US$1 kWh–1 to fully displace all modelled firm low-carbon generation technologies. Electrification of end uses in a northern latitude context makes full displacement of firm generation more challenging and requires performance combinations unlikely to be feasible with known LDES technologies. Finally, LDES systems with the greatest impact on electricity cost and firm generation have storage durations exceeding 100 h. Wind and solar energy must be complemented by a combination of energy storage and firm generating capacity. Here, Sepulveda et al. assess the economic value and system impact of a wide range of possible long-duration energy storage technologies, providing insights to guide innovation and policy.

Energy justice discourses in citizen deliberations on systems flexibility in the United Kingdom: Vulnerability, compensation and empowerment

This article details the application of energy justice as an analytic lens for exploring the social acceptability of energy systems flexibility and governance in the UK. Drives towards the uptake of inflexible, low-carbon generation technologies are expected to generate new challenges for balancing energy supply with demand, requiring changes in network management. From the uptake of new storage technologies to shifts in practices and governance, such changes may impact on everyday energy users in a variety of ways. Drawing on data collected from deliberative workshops conducted in England, Scotland and Wales, we examine how members of the public interpret and respond to six models for governing future, more flexible energy systems. In so doing, we illustrate the value of the energy justice literature in making sense of the ways citizens identify and balance concerns relating to how distributions of needs, capacities, and benefits, may shape novel forms of energy system participation. We also draw attention to the ways in which alternative discourses about fairness rooted in neoliberal understandings of market exchange may interact with and contradict more socially salient understandings of flexibility justice rooted in concern for vulnerable groups.

The impact of heterogeneous market players with bounded-rationality on the electricity sector low-carbon transition

The energy sector transition requires large financial investments in low-carbon generation technologies, to be delivered by a variety of actors with heterogeneous characteristics. Real-world actors have bounded-rationality, reflected by their limited foresight and heterogeneous expectations, and as past trends influence their investments. Agent-based models are highly suitable modelling frameworks to study such realistic and complex energy transition dynamics. This paper introduces BRAIN-Energy, a novel agent-based model which explicitly allows to explore the impacts of actors' heterogeneous characteristics, and of their interactions, on the transition pathways of the UK, German and Italian electricity sectors. Results show that actors' heterogeneous characteristics pose barriers to effective decarbonisation efforts, affect the speed of the transition, and impact the transition's security of supply and affordability dimensions. Limited foresight and path-dependency lead to investment cycles (both virtuous and vicious). The country comparison highlights how such effects are stronger in markets with more heterogeneous market players.

Perspective Analysis of Emerging Natural Gas-based Technology Options for Electricity Production

Abstract The growing worldwide interest in low carbon electric generation technologies has renewed interest in natural gas because it is considered a cleaner burning and more flexible alternative to other fossil fuels. Recent shale gas developments have increased natural gas production and availability while lowering cost, allowing a shift to natural gas for electricity production to be a cost-effective option. Natural gas generation in the U.S. electricity sector has grown substantially in recent years (over 31 percent in 2012, up from 17 percent in 1990), while carbon dioxide (CO2) emissions of the sector have generally declined. Natural gas-fired electrical generation offers several advantages over other fossil (e. g. coal, oil) fuel-fired generation. The combination of the lower carbon-to-hydrogen ratio in natural gas (compared to other fossil fuels) and the higher efficiency of natural gas combined cycle (NGCC) power plants (using two thermodynamic cycles) than traditional fossil-fueled electric power generation (using a single cycle) results in less CO2 emissions per unit of electricity produced. Furthermore, natural gas combustion results in considerably fewer emissions of air pollutants such as nitrogen oxides (NOx), sulfur dioxide (SO2), and particulate matter (PM). Natural gas is not the main option for deep de-carbonization. If deep reduction is prioritized, whether of the electricity sector or of the entire economy, there are four primary technologies that would be assumed to play a prominent role: energy efficiency equipment, nuclear power, renewable energy, and carbon capture and storage (CCS). However, natural gas with low carbon generation technologies can be considered a “bridge” to transition to these deep decarbonization options. This paper discusses the economics and environmental impacts, focusing on greenhouse gas (GHG) emissions, associated with alternative electricity production options using natural gas as the fuel source. We also explore pairing NGCC with carbon capture, explicitly examining the costs and emissions of amine absorption, cryogenic carbon capture, carbonate fuel cells, and oxy-combustion.

Comparison of the LCOE between coal-fired power plants with CCS and main low-carbon generation technologies: Evidence from China

China is a coal dominated country, where CCS has a great potential to be used in coal-fired power plants (CFPP) but it is limited by the high investment cost. The competitiveness of the CFPP that responsible for the entire chain of carbon capture, the transportation and storage (CPCCS) was compared with the natural gas combined cycle power plants (NGCC), the centralized solar photovoltaic power station (CPV), the on-shore wind farms (WF), and the agro-forestry biomass direct combustion power plants (BPP), through calculating the levelized cost of electricity (LCOE) at the same emission reduction level from the national and regional perspectives. The results showed that 1) the CPCCS had an advantage over other technologies when it had suitable storage sites within short distances and low coal prices. 2) The LCOE of the CPCCS was effectively affected by the CO2 transportation distance and the coal price. The initial investment cost of the CPV and WF, as well as the fuel price of the NGCC and the BPP were the decisive factors for their LCOE. 3) The LCOE of the CPCCS had the largest advantage in Shanxi, Tianjin, Gansu, and Xinjiang when compared to the NGCC, BPP, CPV, and WF.

Whole-System Assessment of the Benefits of Integrated Electricity and Heat System

The interaction between electricity and heat systems will play an important role in facilitating the cost effective transition to a low carbon energy system with high penetration of renewable generation. This paper presents a novel integrated electricity and heat system model in which, for the first time, operation and investment timescales are considered while covering both the local district and national level infrastructures. This model is applied to optimize decarbonization strategies of the U.K. integrated electricity and heat system, while quantifying the benefits of the interactions across the whole multi-energy system and revealing the trade-offs between portfolios of: 1) low carbon generation technologies (renewable energy, nuclear, and CCS) and 2) district heating systems based on heat networks and distributed heating based on end-use heating technologies. Overall, the proposed modeling demonstrates that the integration of the heat and electricity system (when compared with the decoupled approach) can bring significant benefits by increasing the investment in the heating infrastructure in order to enhance the system flexibility that in turn can deliver larger cost savings in the electricity system, thus meeting the carbon target at a lower whole-system cost.

Optimal design of neighbouring offshore wind farms: A co-evolutionary approach

This paper presents a new approach for the optimization of neighbouring offshore wind farms. Offshore wind energy is one of the most promising and developed low-carbon generation technologies. However, the high capital costs, which are strongly dependent on seabed depth, currently limit the geographical expansion of this technology to areas with relatively shallow waters and appropriate wind resource. This, along with the advantages of sharing a submarine transmission system among several projects, leads to a high concentration of offshore wind farms in certain zones, as happens, for example, in the North Sea. The presence of other neighbouring offshore wind farms has to be taken into account when a developer plans a new project, since the wake effect of wind turbines belonging to other neighbouring wind farms will affect the annual energy production and, consequently, the profitability of the project under study. However, not only already operating or installed neighbouring projects have to be borne in mind, but also the possible design of future neighbouring wind farms yet to be developed. In order to tackle this issue, an innovative co-evolutionary algorithm is proposed in this paper with the objective of determining a Nash equilibrium solution that would provide the best possible configuration of the wind farm under study by taking into account and limiting the disturbance introduced by other neighbouring projects. The performance of the proposed methodology has been successfully tested through the analysis of a realistic case and compared with other collaborative approaches and the classic single-project optimization methods already existing in the literature.

The Impact of CCS Readiness on the Evolution of China's Electric Power Sector

In this study, GCAM-China is exercised to examine the impact of CCS availability on the projected evolution of China's electric power sector under the Paris Increased Ambition policy scenario developed by Fawcett et al. based on the Intended Nationally Determined Contributions (INDCs) submitted under the COP-21 Paris Agreement. This policy scenario provides a backdrop for understanding China's electric generation mix over the coming century under several CCS availability scenarios. In all scenarios, the electric power sector shifts towards low-carbon generation technologies including significant nuclear, wind, and solar to meet growing demands and emissions targets. The availability and timing of CCS technologies to deploy at scale impacts the resulting generation mix and mitigation costs. Should large-scale CCS deployment be delayed in China by 25 years, the modeled per-ton cost of climate change mitigation is projected to be roughly $420/tC (2010 US dollars) by 2050, relative to $360/tC in the case in which CCS is available to deploy by 2025, a 16% increase. Once CCS is available for commercial use, mitigation costs for the two cases converge, equilibrating by 2085. However, should CCS be entirely unavailable to deploy in China, the mitigation cost spread, compared to the 2025 case, doubles by 2075 ($580/tC and $1130/tC respectively), and triples by 2100 ($1050/tC vs. $3200/tC). However, while delays in CCS availability may have short-term impacts on China's overall per-ton cost of meeting the emissions reduction target evaluated here, the net impact is much smaller compared with not having CCS available within the century and in each case the carbon price is likely to approach the price path associated with the full CCS availability case within a decade following CCS deployment. Having CCS available before the end of the century, even under the delays examined here, could reduce the total amount of nuclear and renewable energy that must deploy, significantly reducing the overall cost of meeting the emissions mitigation targets.

The value of conservation voltage reduction to electricity security of supply

In the specific event that there is not enough electricity being produced in the power market of Great Britain to meet demand, the system operator can use a set of mitigation tools to manage these supply shortfalls that are outside of normal operation of the market and that are used ahead of any controlled customer disconnections. Demand control is an emergency mitigation tool used by the system operator that instructs distribution network operators to implement voltage reduction across the electricity distribution system with the intent of achieving a reduction in customer's demand. The introduction of new low carbon generation and demand technologies in the electricity distribution networks, with fundamentally different technical and operating characteristics from the incumbent technologies, is likely to drive a dissimilar impact on the level of demand reduction that can be achieved through voltage reduction compared to those previously expected. Thus, there is a need to comprehensively understand the effectiveness of the voltage reduction in electricity distribution networks that can be realised through demand control events. The delivery of demand control can be achieved through conservation voltage reduction (CVR) techniques based on the principle of lowering the supply voltage to end-use consumers of electricity in order to reduce the energy consumption of some types of loads while maintaining customer service voltage within statutory limits. This paper presents a methodology to quantify and assess the value of CVR to security of supply of electricity systems. Specifically, it estimates the response of electricity demand to demand control events in the electricity distribution system to reduce customer's demand during periods of significantly low supply-demand margins. The methodology is applied to a network structure representative of the electricity distribution network of Great Britain and the value of CVR is estimated for individual distribution network feeders and for the distribution system over an annual load cycle. The analysis demonstrates that the response of demand to voltage reduction is relatively different from substation to substation, feeder to feeder and especially load to load. The CVR factor for the Great Britain electricity distribution network is assessed to vary on average from 0.81 in the summer season to 1.13 in the winter season. The CVR factors for the electricity distribution network of Great Britain are expressed in the form of a look up table to provide a simple framework for network operators to estimate the response of demand to voltage reduction/demand control events.

Techno-economic and business case assessment of low carbon technologies in distributed multi-energy systems

Increasing focus on energy affordability and environmental impact is drawing interest towards the potential value of low carbon technology (LCT) interventions in buildings and district energy systems. Relevant interventions may include improvements of the insulation levels and installation of low carbon and renewable generation technologies (e.g., combined heat and power, photovoltaics, heat pumps). These LCT interventions for both electricity and heat supply can, in principle, reduce energy costs and CO2 emissions for final energy consumers. This can be achieved by coupling, and possibly optimising, multiple energy vectors from traditionally independent systems (e.g., electricity, heat and gas). However, this transition to distributed multi-energy systems introduces complex physical and commercial interactions between the different energy vectors. Further, these interactions can be fundamentally different at different aggregation levels (e.g., premises, district, and commercial level). This makes the assessment of business cases for LCT interventions in a multi-energy context a grand challenge, and given the potentially disruptive commercial impact of many such novel technologies, such complexity might result in a barrier to their development. In light of this, this paper proposes a techno-economic framework for the assessment of business cases of LCTs, which systematically models the physical and commercial multi-energy flows at the premises, grid connection point, and commercial levels. This is particularly important given the commonly asymmetrical nature of various energy price components, which can have significant effects on the business cases of LCTs and associated actors (e.g., retailers and energy service companies). The proposed framework is demonstrated through a series of case studies that highlight the value of various LCT interventions and of aggregation, in terms of energy, emission and operational cash flow metrics. The relevance and importance of the framework to developing business cases for various energy system actors, including policy makers and regulators, is discussed, with the final aim of facilitating the uptake of low carbon multi-energy technologies.

Beyond designed functional margins in CANDU type NPP. Radioactive nuclei assessment in an LOCA type accident

European Union's energy roadmap up to year 2050 states that in order to have an efficient and sustainable economy, with minimum or decreasing greenhouse gas emissions, along with use of renewable resources, each constituent state has the option for nuclear energy production as one desirable option. Every scenario considered for tackling climate change issues, along with security of supply positions the nuclear energy as a recommended option, an option that is highly competitive with respect to others. Nuclear energy, along with other renewable power sources are considered to be the main pillars in the energy sector for greenhouse gas emission mitigation at European level. European Union considers that nuclear energy must be treated as a highly recommended option since it can contribute to security of energy supply. Romania showed excellent track-records in operating in a safe and economically sound manner of Cernavoda NPP Units 1&2. Both Units are in top 10 worldwide in terms of capacity factor. Due to Romania's need to ensure the security of electricity supply, to meet the environmental targets and to move to low carbon generation technologies, Cernavoda Units 3&4 Project appears as a must. This Project was started in 2010 and it is expected to have the Units running by 2025. Cost effective and safety operation of a Nuclear Power Plant is made taking into consideration functional limits of its equipment. As common practice, every nuclear reactor type (technology used) is tested according to the worse credible accident or equipment failure that can occur. For CANDU type reactor, this is a Loss of Cooling Accident (LOCA). In a LOCA type accident in a CANDU NPP, using RELAP/SCDAP code for fuel bundle damage assessment the radioactive nuclei are to be quantified. Recently, CANDU type NPP accidents are studied using the RELAP/SCDAP code only. The code formerly developed for PWR type reactors was adapted for the CANDU geometry and can assess the accident progression consequences up to a certain point. The code assesses the fuel bundle damage progression, but cannot assess further core damage for a CANDU type core, and starting from these data the amount of damaged fuel can be calculated. The radio nuclei present in the damaged fuel are supposed to be released into the main heat transport system and after that into the containment building in the worst case scenario. Assessing the radioactive nuclei maximum release is the purpose of the present paper. The radioactive nuclei release is needed for the accident management plan, limiting the environmental and population impact of the supposed accident, and furthermore for a later site remediation plan that can be put in action after the complete mitigation of the accident consequences. The maximum quantity of radio nuclei released during the accident calculated in this paper is a worst case scenario evaluation that can lead to better preparedness in an accident scenario.

Environmental assessment for corporate sustainability by resource utilization and technology innovation: DEA radial measurement on Japanese industrial sectors

This study proposes a new use of DEA (Data Envelopment Analysis) radial approach to examine the corporate sustainability of Japanese industrial sectors. The concept of corporate sustainability is measured by its subcomponent measures, including UEN (Unified Efficiency under Natural Disposability), UEM (Unified Efficiency under Managerial Disposability), UENM (Unified Efficiency under Natural and Managerial Disposability), UEI (Unified Efficiency for Intermediate measurement) and UENM(DC) (Unified Efficiency under Natural and Managerial Disposability with Desirable Congestion). Among the five measures, the UEI examines a degree of how each firm can efficiently utilize its resources. The UENM(DC) examines a degree of how the firm can reduce an amount of undesirable outputs by technology innovation and/or managerial change. Such a combined use between UEI and UENM(DC) has been never explored in DEA environmental assessment. The empirical results obtained from the proposed approach have identified two important implications. One of the two implications is that the Japanese energy industry has been long under governmental regulation so that energy firms do not have corporate governance capabilities at the level of other industrial sectors which are competing in a global market. In particular, the implication is applicable to Japanese electric power firms. It is necessary for them to change their corporate governances (e.g., by adding new executive board members who have international experience and/or woman executives, as widely found in American and European energy industries) so that they can pay attention to consumers, not regulatory agencies of the Japanese government. The other implication is that technology innovation can more effectively improve the performance of the energy sector. Employing high efficiency and low carbon generation technologies to achieve desirable fuel mix is essential for improving the corporate sustainability of the Japanese energy sector.

Multi-Source Energy Networks and the ICT Revolution

Oil and gas provided the cheap energy source for the era of mass production and consumption and the first half of the information and communication technology (ICT) revolution. However, increasing scarcity and the addition of carbon pollution taxes are making this source of energy more costly, while economies of scale, the Internet and the use of microprocessors are making multi-source renewable energy networks an attractive alternative. How might the emergence of low-carbon energy generation technologies, such as solar photovoltaic fit into the current techno-economic paradigm? This article explores some of the possibilities and anticipates how the ICT revolution might unfold over the next decades.

Economic analysis of PV/diesel hybrid power systems in different climatic zones of South Africa

Recently hybrid power systems (HPSs) consisting of integrated operation of two or more different types of energy sources and storage devices are being deployed for rural electrification or electrification of remote areas in many countries across the world. This is seen as a cost effective solution in contrast to extending the utility grid in remote areas. The types of upcoming renewable and low-carbon generation technologies are being preferred for such systems depending on their availability and economic viability in these countries. Moreover, HPSs are also being preferred in order to improve the overall energy efficiency of the system and to get a judicious generation mix which would minimise the operating cost of the system. Rural communities in South Africa endure poor access to electricity mostly due to the lack of grid connected power lines. It is therefore the ideal place to conduct a study on the economic feasibility of introducing HPSs for typical residential loads for the rural community in South Africa. This paper reports on the investigating economic feasibility of a PV/diesel HPS in various climatic zones within South Africa.

The economic costs of reducing greenhouse gas emissions under a U.S. national renewable electricity mandate

The electricity sector is the largest source of greenhouse gas emissions (GHGs) in the U.S. Many states have passed and Congress has considered Renewable Portfolio Standards (RPS), mandates that specific percentages of electricity be generated from renewable resources. We perform a technical and economic assessment and estimate the economic costs and net GHG reductions from a national 25 percent RPS by 2025 relative to coal-based electricity. This policy would reduce GHG emissions by about 670 million metric tons per year, 11 percent of 2008 U.S. emissions. The first 100 million metric tons could be abated for less than $36/metric ton. However, marginal costs climb to $50 for 300 million metric tons and to as much as $70/metric ton to fulfill the RPS. The total economic costs of such a policy are about $35 billion annually. We also examine the cost sensitivity to favorable and unfavorable technology development assumptions. We find that a 25 percent RPS would likely be an economically efficient method for utilities to substantially reduce GHG emissions only under the favorable scenario. These estimates can be compared with other approaches, including increased R&D funding for renewables or deployment of efficiency and/or other low-carbon generation technologies.