136,698 research outputs found
Generation Expansion Models including Technical Constraints and Demand Uncertainty
This article presents a Generation Expansion Model of the power system taking into account the operational constraints and the uncertainty of long-term electricity demand projections. The model is based on a discretization of the load duration curve and explicitly considers that power plant ramping capabilities must meet demand variations. A model predictive control method is used to improve the long-term planning decisions while considering the uncertainty of demand projections. The model presented in this paper allows integrating technical constraints and uncertainty in the simulations, improving the accuracy of the results, while maintaining feasible computational time. Results are tested over three scenarios based on load data of an energy retailer in Colombia
Renewable electricity generation and transmission network developments in light of public opposition: Insights from Ireland. ESRI Working Paper No. 653 March 2020
This paper analyses how people’s attitudes towards onshore wind power and overhead transmission lines affect the costoptimal
development of electricity generation mixes, under a high renewable energy policy. For that purpose, we use a power
systems generation and transmission expansion planning model, combined with information on public attitudes towards energy
infrastructure on the island of Ireland. Overall, households have a positive attitude towards onshore wind power but their
willingness to accept wind farms near their homes tends to be low. Opposition to overhead transmission lines is even greater. This
can lead to a substantial increase in the costs of expanding the power system. In the Irish case, costs escalate by more than 4.3%
when public opposition is factored into the constrained optimisation of power generation and grid expansion planning across the
island. This is mainly driven by the compounded effects of higher capacity investments in more expensive technologies such as
offshore wind and solar photovoltaic to compensate for lower levels of onshore wind generation and grid reinforcements. The
results also reveal the effect of public opposition on the value of onshore wind, via shadow prices. The higher the level of public
opposition, the higher the shadow value of onshore wind. And, this starkly differs across regions: regions with more wind resource
or closest to major demand centres have the highest shadow prices. The shadow costs can guide policy makers when designing
incentive mechanisms to garner public support for onshore wind installations
Impact of Forecast Errors on Expansion Planning of Power Systems with a Renewables Target
This paper analyzes the impact of production forecast errors on the expansion
planning of a power system and investigates the influence of market design to
facilitate the integration of renewable generation. For this purpose, we
propose a stochastic programming modeling framework to determine the expansion
plan that minimizes system-wide investment and operating costs, while ensuring
a given share of renewable generation in the electricity supply. Unlike
existing ones, this framework includes both a day-ahead and a balancing market
so as to capture the impact of both production forecasts and the associated
prediction errors. Within this framework, we consider two paradigmatic market
designs that essentially differ in whether the day-ahead generation schedule
and the subsequent balancing re-dispatch are co-optimized or not. The main
features and results of the model set-ups are discussed using an illustrative
four-node example and a more realistic 24-node case study
Dynamic Robust Transmission Expansion Planning
Recent breakthroughs in Transmission Network Expansion Planning (TNEP) have
demonstrated that the use of robust optimization, as opposed to stochastic
programming methods, renders the expansion planning problem considering
uncertainties computationally tractable for real systems. However, there is
still a yet unresolved and challenging problem as regards the resolution of the
dynamic TNEP problem (DTNEP), which considers the year-by-year representation
of uncertainties and investment decisions in an integrated way. This problem
has been considered to be a highly complex and computationally intractable
problem, and most research related to this topic focuses on very small case
studies or used heuristic methods and has lead most studies about TNEP in the
technical literature to take a wide spectrum of simplifying assumptions. In
this paper an adaptive robust transmission network expansion planning
formulation is proposed for keeping the full dynamic complexity of the problem.
The method overcomes the problem size limitations and computational
intractability associated with dynamic TNEP for realistic cases. Numerical
results from an illustrative example and the IEEE 118-bus system are presented
and discussed, demonstrating the benefits of this dynamic TNEP approach with
respect to classical methods.Comment: 10 pages, 2 figures. This article has been accepted for publication
in a future issue of this journal, but has not been fully edited. Content may
change prior to final publication. Citation information: DOI
10.1109/TPWRS.2016.2629266, IEEE Transactions on Power Systems 201
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Long-term Framework for Electricity Distribution Access Charges
In order to achieve overall economic efficiency, incentive regulation of electricity distribution utilities must address two important and inter-related issues. First, the utilities’ allowed revenues need to be set at correct levels. Second, the access charging mechanism by which the utilities recover the allowed revenues must give the correct economic signals to generation and load connected to the network. This paper is concerned with the latter aspect of regulation. The paper discusses the main economic principles that should form the basis on which a distribution access charging model is developed. The charging model should have a number of attributes: be calibrated to each existing network; contain an asset register; be able to determine assets needed to meet new demand; find least-cost system expansion; compute network losses and handle ancillary services; estimate incremental operating and maintenance costs; be available to users; and be simple enough for external users to understand
Impact of Equipment Failures and Wind Correlation on Generation Expansion Planning
Generation expansion planning has become a complex problem within a
deregulated electricity market environment due to all the uncertainties
affecting the profitability of a given investment. Current expansion models
usually overlook some of these uncertainties in order to reduce the
computational burden. In this paper, we raise a flag on the importance of both
equipment failures (units and lines) and wind power correlation on generation
expansion decisions. For this purpose, we use a bilevel stochastic optimization
problem, which models the sequential and noncooperative game between the
generating company (GENCO) and the system operator. The upper-level problem
maximizes the GENCO's expected profit, while the lower-level problem simulates
an hourly market-clearing procedure, through which LMPs are determined. The
uncertainty pertaining to failures and wind power correlation are characterized
by a scenario set, and their impact on generation expansion decisions are
quantified and discussed for a 24-bus power system
Climate policy costs of spatially unbalanced growth in electricity demand: the case of datacentres. ESRI Working Paper No. 657 March 2020
We investigate the power system implications of the anticipated expansion in electricity
demand by datacentres. We perform a joint optimisation of Generation and Transmission Expansion
Planning considering uncertainty in future datacentre growth under various climate policies.
Datacentre expansion imposes significant extra costs on the power system, even under the cheapest
policy option. A renewable energy target is more costly than a technology-neutral carbon reduction
policy, and the divergence in costs increases non-linearly in electricity demand. Moreover, a carbon
reduction policy is more robust to uncertainties in projected demand than a renewable policy. High
renewable targets crowd out other low-carbon options such as Carbon Capture and Sequestration.
The results suggest that energy policy should be reviewed to focus on technology-neutral carbon
reduction policies
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An Assessment of PIER Electric Grid Research 2003-2014 White Paper
This white paper describes the circumstances in California around the turn of the 21st century that led the California Energy Commission (CEC) to direct additional Public Interest Energy Research funds to address critical electric grid issues, especially those arising from integrating high penetrations of variable renewable generation with the electric grid. It contains an assessment of the beneficial science and technology advances of the resultant portfolio of electric grid research projects administered under the direction of the CEC by a competitively selected contractor, the University of California’s California Institute for Energy and the Environment, from 2003-2014
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