Oil-fired Generation Research Articles

Pathways to Secure and Stable Island Power Systems [Guest Editorial

In a fast-changing world, island power systems face urgent environmental, economic, sustainability, and social challenges. Historically, island power systems were built to rely on oil-fired generation, causing carbon-intensive power generation, high costs to consumers, and dependance on market price volatilities, thus hindering their economic development and social stability. Reducing or eliminating the dependence on costly imported fossil-fuels has many benefits but also presents significant challenges when shifting to local but variable and power electronic-based sources, such as wind and solar. Island power systems are at the forefront of integrating extremely high shares of variable renewable generation and face related reliability challenges that are yet to be seen in larger interconnected power systems on the continental mainland. This is because island power systems operate in isolation and rely on their local grid resources to ensure stable operation.

Modelling electric vehicles uptake on the Greek islands

For decades, the Greek islands have been facing challenges in terms of quality of power supply, increased carbon dioxide equivalent (CO2eq) emissions, and costs due to their reliance on oil-fired generation subsidised by the Greek state. In light of the recent reforms to decarbonise the islands' region while enhancing their local grids, this study investigates the impact of electromobility considering an autonomous electricity system supported by storage versus an interconnected one. Two Electric Vehicles (EVs) deployment scenarios coupled with several charging strategies have been modelled using the PLEXOS energy systems model. The results highlight that the Vehicle-to-Grid (V2G) scenarios demonstrate the most evident benefits for the islands' electricity systems, performing adequately under both the Autonomous and Interconnection scenarios concerning the economic and environmental impact. Such scenarios have the potential to reduce emissions by 8.5% while dropping costs up to 20% by 2040, when combined with the required renewables expansion plan. From the security of supply perspective, the results demonstrate improvements under the interconnected context accompanied by thermal generation restrictions without however eliminating power shortages recorded already in a non-EV case. The analysis also showcases an escalated impact on power shortages and curtailments during the maximum week, particularly when combined with an ambitious EV deployment. Yet, V2G may increase renewables share up to 7% in 2040. In this context, EVs could mobilise the additional deployment of 600 MW renewables by 2040 if interconnections with the mainland are realised. Assuming islands continue operating as autonomous electricity systems, the additional capacity to accommodate may reach 720 MW.

Addressing multiple externalities from electricity generation: a case for EU renewable energy policy beyond 2020?

Subsidies to electricity generation from renewable energy sources (RES-E) implemented next to an emissions trading scheme (ETS) are frequently criticised for producing no additional benefit in terms of mitigating climate change and increasing the costs of emissions abatement. We re-assess the performance of this policy mix in a setting in which electricity generation produces multiple externalities (beyond climate change) and in which these externalities cannot be addressed by first-best policies. Using an analytical partial equilibrium model, we show that the optimal composition of the policy mix depends on the market interactions between the multiple externalities. We complement this analysis by a quantitative policy assessment, combining a top-down, global macro-economic model and a bottom-up, global electricity sector model. The quantitative analysis suggests that RES-E subsidies may be effective in partly reducing externalities from fossil fuel combustion (by crowding out gas- and oil-fired generation) and in mitigating radiation hazards (by crowding out nuclear generation). However, RES-E subsidies are not necessarily suited to address externalities related to the extraction and transportation of fossil fuels or risks of sudden supply interruptions for imported fuels. With respect to these latter externalities, tightening the ETS cap may be a more effective, but politically less feasible approach.

Natural gas in Cyprus: The need for consolidated planning

The electricity supply system of Cyprus is currently dominated by oil-fired generation, with small but increasing contributions from renewable energy technologies. As regulations regarding emissions of greenhouse gases and air pollutants will become stricter with the turn of the decade, change is imminent. Available offshore gas reserves and the possibility of natural gas imports have shown that the substitution of oil with gas can reasonably be expected in the not-so-distant future. However, the framework under which change could occur has not yet been established. Should imports of gas serve as a short-term bridge until domestic gas becomes available? What are the infrastructure implications associated with such a medium-term solution? How does a policy-driven transition to gas affect energy security and how compatible is this with a liberalized electricity market? Can short- and longer term strategies be consistently designed and implemented? A cost-optimization model (OSeMOSYS), representing the electricity system of the island, is used to provide insights to these questions. Results regarding generation mix, capacity and system costs are presented for a set of scenarios. In all cases investigated, compliance with environmental regulations of the European Union after 2020 makes gas the strategic fuel of choice for low cost electricity generation.

Economic and GHG impacts of natural gas for Hawaii

Hawaii generates the majority of its electricity through oil-fired generation. New production technologies have led to rapidly declining natural gas prices that has renewed Hawaii’s interest in liquefied natural gas (LNG) imports. This study integrates a detailed model of Hawaii’s electric sector with a computable general equilibrium model of Hawaii’s economy to estimate the economic and greenhouse gas (GHG) impacts of importing LNG for use in the electric sector. Incorporating a range of possible price pathways (low, medium and high) out to the year 2040 for LNG imports, we find Hawaii could lower electric sector costs in a range from 6 to 16 % and petroleum refining output declines by over 20 % (in 2040). Gross state product increases in a range of $300 million to $5 billion in net present value. Using natural gas reduces out-of-stack GHG emissions but can also increase GHG emissions in other jurisdictions. Moreover, introducing natural gas could reduce the incentive to pursue renewable energy and energy efficiency. As such, adopting and enforcing policies encouraging renewable energy and efficiency becomes even more important to meet Hawaii’s clean energy and GHG mitigation goals.

Effects of a Carbon Tax and Wind Power Penetration on CO2 Emissions in Wholesale Electric Power Markets

During the December 2009 Copenhagen Climate Change Summit, President Barack Obama committed the U.S. to a 83% reduction below 2005 levels in CO2 emissions by 2050. The U.S. Federal Government is thus currently considering several policy options to reduce CO2 emissions. In the U.S. the largest source of CO2 emissions is the electricity sector; in 2012 it was responsible for 32% of total CO2 emissions. This paper develops an empirically-based computational test bed of a wholesale electric power market to analyze how the imposition of a carbon tax and the increased penetration of wind power in such markets could impact CO2 emissions and other key outcomes, such as energy demands, energy prices, market participant profits (by fuel type), and government tax revenues. The test bed captures core features of the Midcontinent Independent System Operator (MISO), the central manager of one of the world's largest energy and operating reserve markets covering parts of fifteen U.S. states and the Canadian province of Manitoba. Another innovation of this paper is that the effects of increases in a carbon tax and wind power penetration are studied jointly. It is shown, for example, that CO2 emissions decrease from 0.23% to 6.17% as the carbon tax and the degree of wind penetration are systematically varied from a base case of zero tax and zero wind. The profits of coal- and oil-fired generation systematically decrease with increases in the carbon tax and/or increases in wind penetration, but the profits of other types of generation exhibit a more complex response. Comparisons with current MISO conditions are also given, and key policy implications are discussed.

The Short-Run Effects of Time-Varying Prices in Competitive Electricity Markets

We analyze the efficiency, distributional, and environmental effects of real-time pricing (RTP) adoption in the short run. Consistent with theory, our simulations of the PJM electricity market show that RTP adoption improves efficiency and compresses the distributions of loads and prices. Adoption increases average load but decreases operating profits with the largest decrease for oil-fired generation (59% when all customers adopt). Consumer surplus and welfare gains are modest (2.5% and 0.24% of the energy bill), and emissions of SO2 and NOx increase but CO2 emissions decrease. Approximately 30% of these efficiency gains could be captured by varying flat rates monthly instead of annually. Monthly flat rate adjustment has many of the same effects as RTP adoption, captures more of the deadweight loss than time of use (TOU) rates, and requires no new metering technology.

No sunset for the energy industry

No sunset for the energy industry

98/01115 Despite increasing refinery power production, oil-fired generation is declining: Paffenbarger, J. Oil Gas J., 1997, 95, (28), 35–38, 40

98/01115 Despite increasing refinery power production, oil-fired generation is declining: Paffenbarger, J. Oil Gas J., 1997, 95, (28), 35–38, 40

Variability in Thermal Performance and Measured Heat Rate in Fossil-Fuelled Power Plants

The paper examines the variability of key parameters in the operation of ten thermal power plants in various commercial grid environments with a view to assessing the viability of ‘on-demand’ plant performance monitoring for heat rate declaration. The plants of various types are limited to coal- and oil-fired units in the capacity range of 305–690 MW generated output. The paper illustrates the influence of control system configuration on effective and flexible power plant management. The analysis of variability indicates that there is a reasonable probability of achieving adequately stable operating periods within the normal operating envelope of grid dispatch instructions when thermal performance monitoring and display can be undertaken with a high confidence level. The levels of variability in fuel quality, which were measured during nominally constant levels of fuel input and generated output, range from about +1 per cent for oil-fired plants to about ±5 per cent for coal-fired power plants. The implications of adopting on-line monitoring of unit heat rate as an input to the generation ordering and unit commitment process are potentially significant cost and energy conservation benefits for utilities having a high proportion of coal- and oil-fired generation.

A Load Management Feasibility Study for South Carolina Electric&Gas Co.

This paper describes the methods used and results obtained in a study of the feasibility of residential load control. The study was conducted by Systems Control, Inc., and South Carolina Electric and Gas Company. It examined the costs and capabilities of the available load control equipment and compared those costs to the expected benefits of implementing load control. Three load control strategies were identified as the most economically viable based upon a screening analysis. These three strategies were subjected to a detailed multi-year simulation procedure using computer programs to (1) model appliance loads, (2) determine viable controlled appliance dispatch strategies, (3) calculate production costs and reliability, and (4) determine the resulting effects of load control on corporate finances. The study found that load control is not expected to be cost-effective on the SCE&G system because of SCE&G's broad summer peak, its use of the Fairfield pumped hydro facility, the lack of peaking units in its present generation expansion plans, and limited amount of oil-fired generation now being used.