Renewable and Sustainable Energy Transition最新文献

This paper tells the story of off-grid remote renewable energy rollouts in Indigenous communities in Northern Australia. While the analysis is specific to Australia, it has broader lessons about incorporating Indigenous governance approaches into renewable energy rollouts so that Indigenous communities in financially constrained contexts share in the intended benefit of installed electricity systems. Using energy sociotechnical imaginaries and energy justice, the paper explores the emergence, impact and contemporary legacy of Bushlight (2002–2013), a government funded renewable energy program delivered by an Indigenous-led non-profit organisation. Bushlight was part of Australia's early efforts to build its renewable energy sector, operating with a dual mandate of decarbonisation and community development in Indigenous Homelands communities. Research draws on empirical data from qualitative research methods (interviews and participant observation) as well as archival records and other documentation. The analysis of sociotechnical imaginaries explains how collectives come together to anticipate and address distributional justice issues through policy development and how these collectives and their vision for renewable energy evolve through implementation. Tracing how these imaginaries extend into the present highlights the influence of broader socio-political dynamics shaping Indigenous-settler-colonial relations. The paper's findings have important implications for decolonisation, supporting Indigenous people to live on and care for Country while retaining their right to essential services.

British Columbia (BC) is committed to transitioning to a low-carbon energy system to meet its CO₂ emission reduction targets, but this shift towards renewable energy sources may have significant implications for land use. This paper investigates the land-use impacts of different electrification pathways and technology choices in BC's energy system using the BC Nexus model. Our analysis highlights the potential increase in land-use requirements associated with transitioning from fossil fuels to renewable energy sources, with the occupied land of the power system potentially increasing up to six times larger than the current total build-up land (depending on the scale of electrification and technology choice). These findings have important implications for policymakers in terms of balancing the trade-offs between energy security, economic development, and environmental sustainability. By understanding the physical footprint of the energy transition, decision-makers can develop more effective climate policies and sustainable development strategies.

Isolated mini-grids (MG) can be an efficient option for rural electrification worldwide. Nonetheless, a large share of MG fail after a few years and inadequate sizing has been identified as a major risk. Academia, public authorities and funding agencies tend to consider the sizing of mini-grids mostly from a technical and economic angle, looking to optimize performance for MG developers and operators with tools such as HOMER. This paper proposes a different approach. We study the strategies adopted by different MG stakeholders to deal with their own uncertainties and constraints in the sizing process. Based on field work in Kenya, we detail how MG funders and regulators transfer risks to private MG developers and operators. As a result, the latter face risks regarding demand estimation, funding and regulatory aspects when sizing MGs. In turn, they adapt their methods and business models, sometimes transferring risks to end users. While flexible sizing might be a solution, we show that regulatory and funding issues limit MG modularity, leading low-income customers to eventually bear the consequences of ill-suited sizing.

The Benin energy sector faces serious challenges, including an unfavorable energy mix with regular power shortages, erratic power outages, reliance on electricity imports, and dependence on traditional cooking stoves. This study has investigated strategies critical for Benin to employ to achieve 24.6 %, 44 %, and 100 % renewable energy (RE) integration targets in the final electricity mix in 2025, 2030, and 2050, respectively. This study used the EnergyPLAN model to develop different energy scenarios suitable for Benin to achieve its proposed RE penetration target. A combination of natural gas (NG) with solar photovoltaic (PV), wind energy, hydropower, and concentrated solar power (CSP) is used to develop three scenarios for RE integration namely the government targets scenario, 2 % RE per year scenario and 50 % RE in 2050 scenario. The results show that the government targets scenario is too ambitious because of the current trend and pace of developing the energy sector. Moreover, a combination of 563 MW of NG, 125 MW of PV, 200 MW of wind, 600 MW of hydropower, and 60 MW of CSP would achieve 50 % RE by 2050 under the 50 % RE scenario. This scenario would decrease CO₂ emissions by 50 % with no CEEP generation. Furthermore, the total electricity generation from MSW in Benin is estimated to be 0.232, 0.3215, and 1.16 TWh/yr in 2025, 2030, and 2050, respectively. The study's findings could help decision-makers and stakeholders make informed decisions to promote the integration of RE resources in the Benin Republic.

The transition from fossil fuels to carbon-neutral energy sources is necessary to reduce greenhouse gas (GHG) emissions and combat climate change. Hydrogen (H₂) provides a promising path to harness fossil fuels to reduce emissions in sectors such as transportation. However, regional economic analyses of various H₂ production techniques are still lacking. We selected a well-known fossil fuel-exporting region, the USA's Intermountain-West (I-WEST), to analyze the carbon intensity of H₂ production and demonstrate regional tradeoffs. Currently, 78 % of global H₂ production comes from natural gas and coal. Therefore, we considered steam methane reforming (SMR), surface coal gasification (SCG) and underground coal gasification (UCG) as H₂ production methods in this work. We developed the cost estimation frameworks of SMR, SCG and UCG with and without carbon capture, utilization and sequestration (CCUS). In addition, we identified optimal sites for H₂ hubs by considering the proximity to energy sources, energy markets, storage sites and CO₂ sequestration sites. We included new production tax credits (PTCs) in the cost estimation to quantify the economic benefit of CCUS. Our results suggest that the UCG has the lowest levelized cost of H₂ production due to the elimination of coal production cost. H₂ production using the SMR process with 99 % carbon capture is profitable when the PTCs are considered. We also analyzed carbon utilization opportunities where CO₂ conversion to formic acid is a promising profitable option. This work quantifies the potential of H₂ production from fossil fuels in the I-WEST region, a key parameter for designing energy transition pathways.

Striving to mitigate climate change, the European Union has adopted net-zero greenhouse gas emissions as a target for 2050. In this paper, European chemical industry roadmaps from the past six years are assessed and compared to uncover how the industry envisions its role in the transition to net-zero emissions. The roadmaps are assessed in terms of ambition level, technology and feedstock strategies, investment needs and costs, agency and dependency on other actors, as well as timeline and concretion. Although net-zero pathways are often drawn out in the roadmaps, some also choose to emphasize and argue for less ambitious pathways with emission reductions of only 40–60 %. The roadmaps vary widely in terms of the importance they assign to mechanical and chemical recycling, switching to biogenic carbon and carbon dioxide as feedstock, electrification and hydrogen, and carbon capture and storage. A commonality though, is that low-tech or near-term mitigation pathways such as demand reduction, reuse or material efficiency are seldom included. High investment needs are generally highlighted, as well as the need for policy to create enabling conditions, whereas the agency and responsibility of the chemical industry itself is downplayed. Our analysis highlights that the chemical industry does not yet have a strong and shared vision for pathways to net-zero emissions. We conclude that such a future vision would benefit from taking a whole value chain approach including demand-side options and consideration of scope 3 emissions.

Indonesia is one of the fastest growing economies in the world, with an electricity system reliant on fossil fuels and renewable electricity contributing a small portion of their growing demand. In this study, an optimization approach is utilized to analyze different policy-driven pathways for Indonesia's long-term electricity planning by formulating different scenarios based on current policy discussions and changes in the power sector. Through an optimization model, several scenarios incorporating multiple changes such as cost reductions of technologies, halting coal capacity beyond the current pipeline, and carbon taxation schemes are built. The findings show the magnitude of transformation needed to achieve net zero goals and consolidate the discussion around halting coal capacity addition beyond currently planned in terms of technical, environmental, and economic aspects. These findings will be useful to electricity sector policymakers and planners as Indonesia continues along its sustainable economic development pathway.

As power systems integrate increasing quantities of wind, solar and energy storage resources, it is important to revisit power system capacity expansion modeling methods and assumptions that have been utilized in thermal-dominated systems. We conduct a series of case study analyses using a simplified representation of the Electric Reliability Council of Texas (ERCOT) system to demonstrate how least-cost capacity expansion outcomes are impacted by changes in model resolution across two temporal dimensions: 1) the number of considered representative periods, and 2) the system dispatch interval. First, we find that the least-cost generation portfolio can differ significantly for small changes in the number of representative days, but largely converges to the 365-day result once 104 representative days are considered. Furthermore, systems with wind, solar and storage resources were more sensitive to changes in the number of representative days than a thermal-dominated system. Second, we find that considering five-minute dispatch resolution consistently results in least-cost generation portfolios with less solar capacity and more energy storage capacity than corresponding scenarios with hourly dispatch intervals. This suggests that hourly dispatch representation fails to capture the intra-hour volatility of solar generation, and therefore also overlooks opportunities for storage resources to provide system value by balancing this volatility. Collectively these results indicate that capacity expansion modelers should revisit conventional approaches to temporal representation when conducting analyses of deeply decarbonized power systems to ensure that such analyses are robust and actionable. To our knowledge, this is the first study to analyze capacity expansion outcomes with five-minute dispatch resolution in this manner.