Engineering topics

Jorgenson, Jennie L.

Publications and source records attributed to Jorgenson, Jennie L..

5 records

DOE OSTI2022

On the operational characteristics and economic value of pumped thermal energy storage

Pumped thermal energy storage (PTES) systems use an electrically-driven heat pump to store electricity in the form of thermal energy, and subsequently dispatch the stored thermal energy to generate electricity using a thermodynamic heat engine. Optimal day-ahead operational scheduling and annual value of a PTES system based on Joule-Brayton thermodynamic cycles and two-tank molten salt hot thermal storage is evaluated in this work. Production cost models, which simultaneously optimize commitment and dispatch schedules for an entire set of generators to minimize the cost of satisfying electricity demand, are employed to determine system-optimal operation and day-ahead energy value of the PTES system within each of six hypothetical near-future grid scenarios intended to approximately represent the U.S. Western Interconnection or the Texas Interconnection. Sensitivity to grid scenario (including the contribution of variable renewable energy sources), thermal storage capacity, relative heat pump and heat engine capacities, and startup/shutdown cycling costs are evaluated. PTES energy value and heat engine annual capacity factor increase strongly as the contribution of variable renewable resources increases, heat pump capacity increases relative to heat engine capacity, or PTES cycling costs decrease. Grid scenarios in which the contribution of variable renewable energy is dominated by solar photovoltaics (PV) vs. wind produce inherently different PTES operational patterns. Annual PTES energy value within PV-dominated scenarios increased with storage capacity only up to approximately seven hours of full-load discharge capacity, whereas that within wind-dominated scenarios exhibited a continual increase with storage duration up to at least 16 hours.

24 POWER TRANSMISSION AND DISTRIBUTION↗

DOE OSTI2020

The Potential Impact of Offshore Wind Energy on a Future Power System in the U.S. Northeast

This study aims to understand and quantify the potential impact of offshore wind on a future electricity system in the U.S. Northeast. In this analysis, a detailed representation of the Northeast power system is adopted, using a generation portfolio for 2024 paired with offshore wind nameplate capacities of 0 gigawatts (GW), 2 GW, and 7 GW. The analysis identifies points of offshore wind interconnection in the ISO-New England and New York Independent System Operator control areas and uses hourly wind profiles from the Wind Integration National Dataset Toolkit. Hourly simulations of the 2024 power system operations show an ability to accommodate the prescribed offshore wind capacities by adapting the system's generation dispatch. Curtailment levels of offshore wind range between 4% and 5%. Offshore wind generation displaces primarily natural-gas combined-cycle generation; however, requires increased flexibility from combined cycles through more frequent start-ups. The number of hours with transmission congestion increases because of offshore wind injection, with varying impact on a subregional level. Offshore wind's capacity credit was found to be 14.5%-28.3% and is lower than estimated in other large-scale power system studies, in part because this study considered a different weather year and a power system representation with higher shares of solar PV and onshore wind. The reliability contribution of resources is a topic area identified for more research and collaboration. The 7-GW scenario shows a reduction in locational marginal price of 11%, with production cost savings of up to 18% compared to the 0-GW scenario.

17 WIND ENERGY↗

DOE OSTI2019

Modeling Primary Frequency Response for Grid Studies

For the electric power grid, maintaining nearly constant frequency is important measure of system reliability and stability. Primary frequency response (PFR) is one of the important reserve services used by grid operators to uphold steady frequency. Modeling PFR is historically rare in grid integration and planning studies, but could become more importantly with greater deployment of non-synchronous generators. In this work, we illustrate how a PFR constraint can be implemented into production cost models, which are a key component of grid planning studies. We also discuss the complexities and nuances associated with PFR modeling and provide results of a case study implementing PFR in a section of the western U.S. power grid.

14 SOLAR ENERGY↗

DOE OSTI2018

A Guide to Implementing Concentrating Solar Power in Production Cost Models

Concentrating solar power (CSP) is a unique form of renewable energy because it can be integrated with thermal energy storage (TES). CSP-TES can provide value to the power grid by supplying a dispatchable source of renewable energy and potentially other grid services such as operating reserves. These characteristics of CSP-TES are often incompletely captured in utility-planning or technology-valuation analyses. We describe an approach for representing the dispatchability of CSP-TES accurately in production cost models, while considering the resource-dependent nature of the technology. We also discuss the challenge of properly representing the ability of CSP-TES to provide operating reserves because of the technology's energy-limited nature. We apply our modeling methods to illustrate how the value of providing dispatchable energy and ancillary services can be captured together and independently. This approach can be applied to most commercial, academic, and open-source production cost models to value CSP-TES appropriately in power system planning studies.

14 SOLAR ENERGY↗

DOE OSTI2018

Value to the Grid From Managed Charging Based on California's High Renewables Study

Managed charging of electric vehicle (EV) loads has the potential to use renewable energy more effectively, shave peak demand, and fill demand valleys while serving transportation needs. However, the potential value to the grid from managed charging has not been fully quantified. This paper adopts the tools used in the National Renewable Energy Laboratory's California Low Carbon Grid Study to quantify value to the grid from managed charging by using three levels of managed loads for 13 terawatt-hours of annual load from three million EVs in a 2030 California grid scenario. Simulation results show that management of the EV fleet's aggregate load from unmanaged to 100% managed results in savings between 210 million and 660 million annually in generation system costs, depending on grid conditions. The simulation results also suggest that targeted EV supply equipment (EVSE) deployments at workplaces and other mid-day parking locations will be needed to support managed charging in a high-renewables California and enable the identified value to the grid. Although the value of generation to the grid from managed EV load paired with high renewables seems substantial, we estimate that the installed cost of an EVSE must be between 1,000 and 3,000 for a 10-year life to be cost neutral, depending on grid conditions.

24 POWER TRANSMISSION AND DISTRIBUTION↗