The integration of large amounts of variable renewable generation can increase the demand on flexible resources in the power system. Conventional hydropower can be an important asset for managing variability and uncertainty in the power system, but multipurpose reservoirs are often limited by nonpower constraints. Previous large-scale variable generation integration studies have simulated the operation of the electric system under different penetration levels but often with simplified representations of hydropower to avoid complex nonpower constraints. This paper illustrates the value of bridging the gap between power system models and detailed hydropower models with a demonstration case. The United States Western Interconnection is modeled with PLEXOS, and ten large reservoirs on the Columbia River are modeled with RiverWare. The results show the effect of detailed hydropower modeling on the power system and its benefits to the power system, such as the decrease in overall production cost and the reduction of variable generation curtailment.

I would like to thank my advisor, Edie Zagona, for providing this research opportunity. This project would not have been possible without her guidance throughout the process.Tim Magee at CADSWES provided invaluable support throughout this project both on technical matters and in analyzing the broader implications of the work. I am grateful to benefit from his experience and expertise. I would also like to thank my other committee members, Balaji Rajagopalan and JoAnn Silverstein for their time and valuable input on this thesis. I am very grateful to the Hydro Research Foundation and the Department of Energy for providing me with a fellowship to fund this research. Joe Taylor from Mid-Columbia Central is responsible for providing Mid-C request data used in this research. In addition, he provided insight into Mid-C operations and policy that influenced this work and facilitated the modeling of realistic operating conditions. Much of the groundwork for this project was laid by a previous project sponsored by Oak Ridge National Laboratory to model wind integration in the Mid-Columbia system. I thank Brennan Smith of ORNL for his contribution and guidance through that project. Bri-Mathias Hodge and Michael Milligan of the National Renewable Energy Laboratory provided insight on wind modeling and facilitated the acquisition of wind forecast data that made possible the development of the wind forecast model in this research.Finally, I would like to thank my wife, Katie, and our daughters, Anna, Josie and Ruthie, for providing endless support, encouragement and patience throughout this process.

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<p>The Western U.S. relies heavily on hundreds of water-dependent power plants, with hydropower and fresh surface water dependent thermo-electric plants accounting for over 60% of generating capacity.  The Western Interconnect overlays 11 States, over three different electricity market areas, and 9 large river basins with tens of unconnected watersheds as well as tens of coordinated watersheds. Such complexity requires computational tradeoffs for the representation of the water-energy dependencies, including a centrally controlled unit commitment and economic dispatch as well as an offline representation of hydropower’s availability and operations. Benchmark hydropower representations for application to resource adequacy studies include i) fixed daily time series and ii) a parameterized monthly representation involving three constraints: a monthly energy target, and hourly minimum and maximum generation. The representations are derived for one year and under average water conditions. We propose a large-scale approach to represent medium-term (weekly) hydropower flexibility for grid-scale reliability studies, as driven by weekly water availability. Using a combination of hydrological models, reservoir operation schemes, and statistical tools, we develop datasets of hydropower plant-specific weekly energy targets, with weekly minimum and maximum hourly generation, for multiple years with varying water conditions. The assumption – and computational tradeoff - is that water availability guides the weekly operations and range of daily operations, leaving enough flexibility for the power system optimization to accommodate intra-day, week days and weekends load variations. We present the hydropower datasets and evaluate how this new representation influences the simulated contribution of hydropower to grid operations as part of resource adequacy and reliability studies.</p>

<p>Production Cost Models (PCMs) simulate the economic dispatch of generators across a large power grid and are used widely by planners to study the reliability of electricity supply. As energy systems transition away from the thermoelectric technologies that have traditionally balanced electricity supply and demand, hydropower and its representation in PCMs is of increasing importance for storage and ramping capabilities. A limitation of PCMs applied to continental power grids with diverse generation portfolios is that hydropower generation is simulated without full consideration of complex river dynamics, leading to possible misrepresentation of grid flexibility and performance.</p><p>Using a detailed hydropower model, we evaluate whether the hourly hydropower schedule from a PCM with simplified monthly parameterization can be attained when accounting for realistic river dynamics, such as spill requirements and general water movement through a cascading reservoir system. We perform this hydropower generation test for the “Big 10” hydropower system on the Columbia River (part of the Western Interconnect of the United States), revealing 9% overestimation of available hydropower generation in a PCM solution in an average hydrologic year.</p><p>We reflect on the sources of differences with implications onto long term planning practices expected to address uncertainties associated with energy transitions, climate change, environmental regulation and competing water uses.</p>