Jean-Paul Watson

Bolun Xu, Yury Dvorkin, Daniel S. Kirschen et al.

Because energy storage systems have better ramping characteristics than traditional generators, their participation in frequency regulation should facilitate the balancing of load and generation. However, they cannot sustain their output indefinitely. System operators have therefore implemented new frequency regulation policies to take advantage of the fast ramps that energy storage systems can deliver while alleviating the problems associated with their limited energy capacity. This paper contrasts several U.S. policies that directly affect the participation of energy storage systems in frequency regulation and compares the revenues that the owners of such systems might achieve under each policy.

Elizabeth Glista, Tomas Valencia Zuluaga, Amelia Musselman et al.

This study presents a mathematical optimization framework and preliminary analysis for long-term investment planning in Puerto Rico's electric power system. We develop a high-resolution capacity expansion model to identify least-cost generation and storage investments that improve system reliability. The model co-optimizes new investments and thermal generator retirements while representing generator dispatch, unit commitment, fuel selection, and storage operations under constraints of equipment engineering limits, fuel supply limitations, and load satisfaction. Key methodological advances relative to prior long-term planning studies for Puerto Rico include: (i) nodal transmission modeling at 38 kV and above, (ii) hourly chronological operations for representative days, (iii) explicit unit commitment for existing and new thermal units with realistic ramping, minimum up and down times, and startup costs, (iv) system-wide fuel supply constraints, and (v) stochastic operating scenarios reflecting load variation, renewable availability, and the high forced outage rates of legacy units. Using data from LUMA, PREPA, DOE, and public sources, we build present-day (2024) and future (2030) test systems, with the latter including planned generation and storage projects. We evaluate planning scenarios that vary future load, fuel supply assumptions, realization of planned expansion, and allowable new technologies. Results show that, given the recent relaxation of interim renewable goals for the near future in Puerto Rico, an optimal portfolio includes at least 1.5 GW of new H-class combined cycle capacity beyond planned projects. These additions are needed mainly to replace unreliable legacy thermal units rather than to serve new load. The new combined cycle units eliminate modeled bulk-system load shedding and restore a strong reserve margin, even under stressed load and outage conditions.

Tomás Tapia, Ryan Piansky, Yury Dvorkin et al.

In power systems, the risk of wildfire ignition has increased significantly in recent years. The impact and severity of these events on energy dispatch, as well as their societal ramifications, make wildfire prevention critical for power system planning and operation. A common intervention by system operators is to de-energize transmission lines to mitigate the risk of fire caused by equipment failures. With the growing integration of variable renewable generation, managing and preparing the system to de-energization under wildfire risk has become even more challenging. In this context, mitigation decisions such as installing battery energy storage systems and undergrounding transmission lines can reduce the risk and adverse effects associated with de-energization and renewable generation variability. This paper presents a robust optimization model to determine the optimal location of battery storage and undergrounding of transmission line investment, utilizing representative weeks and uncertainty sets to capture the temporal relationship of uncertain variables. Specifically, this paper addresses: (i) the worst-case realization of ignition risk leading to the de-energization of transmission lines, combined with the worst-case realization of renewable energy availability, and (ii) the optimal investment decisions for energy storage capacity and undergrounding of transmission lines that are exposed to ignition risk. The proposed model is formulated as a mixed-integer linear programming (MILP) problem, employing duality theory and binary decomposition to address nonlinearities, and is solved using a column-and-constraint generation algorithm. The proposed framework is evaluated on a model of the San Diego power system, demonstrating its practical effectiveness in improving the resilience to wildfire risk.

Tomas Valencia Zuluaga, Simon Pang, Jean-Paul Watson

We propose explicitly incorporating large-scale load siting into a stochastic nodal power system capacity expansion planning model that concurrently co-optimizes generation, transmission and storage expansion. The potential operational flexibility of some of these large loads is also taken into account by considering them as consisting of a set of tranches with different reliability requirements, which are modeled as a constraint on expected served energy across operational scenarios. We implement our model as a two-stage stochastic mixed-integer optimization problem with cross-scenario expectation constraints. To overcome the challenge of scalability, we build upon existing work to implement this model on a high performance computing platform and exploit scenario parallelization using an augmented Progressive Hedging Algorithm. The algorithm is implemented using the bounding features of mpisppy, which have shown to provide satisfactory provable optimality gaps despite the absence of theoretical guarantees of convergence. We test our approach to assess the value of this proactive planning framework on total system cost and reliability metrics using realistic testcases geographically assigned to San Diego and South Carolina, with datacenter and direct air capture facilities as large loads.