Adding large solar photovoltaic (PV) resources into an electric grid influences the flexibility characteristics of its net load profile. The dispatch of the existing generation fleet changes as it adjusts to accommodate the new net load. This study categorizes and defines these flexibility characteristics. It utilizes a unit commitment and dispatch (UC&D) model to simulate large solar generation assets with different geographic locations and orientations. The simulations show the sensitivity of the wholesale energy price, reserve market prices, total dispatch cost, fuel mix, emissions, and water use to changes in net load flexibility requirements. The results show that generating 22,500 GWh of solar energy in a 2011 simulation of the Electric Reliability Council of Texas (ERCOT) reduces total dispatch cost by approximately $900 Million (a 10.3% decrease) while increasing ancillary services costs by approximately $10 Million (a 3% increase). The results also show that PV reduces water consumption and water withdrawals as well as CO 2 , NO x , and SO x emissions. It also reduces peak load by 4% but increases net load volatility by 40-79% and ramping by 11-33%. In addition, west-located, west-oriented solar resources reduce total dispatch cost more than the other simulated solar scenarios. The west-located, west-oriented solar simulation required greater system flexibility, but utilized more low-cost generators and

This research analyzed an integrated energy system that includes a novel configuration of wind and solar coupled with two storage methods to make both wind and solar sources dispatchable during peak demand, thereby enabling their broader use. Named DSWiSS for Dispatchable Solar and Wind Storage System, the proposed system utilizes compressed air energy storage (CAES) that is driven from wind energy and thermal storage supplied by concentrating solar thermal power (CSP) in order to achieve firm power from intermittent, renewable sources. Although DSWiSS mimics the operation of a typical CAES facility, the replacement of energy derived from fossil fuels with energy generated from renewable resources makes this system unique. West Texas is a useful geographical testbed for this system because it has abundant co-located wind and solar resources; it has competitive electricity markets, which give producers an economic incentive to store night-time wind energy in order to be sold during peak price times; and it has a significant number of locations with geological formations suitable for CAES. Through a thermodynamic and a levelized lifetime cost analysis, the power system performance and the cost of energy are estimated for this integrated wind-solar-storage system. We calculate that the combination of these components yields an energy efficiency of 46% for the CAES main power block, and the overall system cost is only slightly more expensive per unit of electricity generated than the current technologies employed today.

The US power sector is a leading contributor of emissions that affect air quality and climate. It also requires a lot of water for cooling thermoelectric power plants. Although these impacts affect ecosystems and human health unevenly in space and time, there has been very little quantification of these environmental trade-offs on decision-relevant scales. This work quantifies hourly water consumption, emissions (i.e., carbon dioxide, nitrogen oxides, and sulfur oxides), and marginal heat rates for 252 electricity generating units (EGUs) in the Electric Reliability Council of Texas (ERCOT) region in 2011 using a unit commitment and dispatch model (UC&D). Annual, seasonal, and daily variations, as well as spatial variability are assessed. When normalized over the grid, hourly average emissions and water consumption intensities (i.e., output per MWh) are found to be highest when electricity demand is the lowest, as baseload EGUs tend to be the most water and emissions intensive. Results suggest that a large fraction of emissions and water consumption are caused by a small number of power plants, mainly baseload coal-fired generators. Replacing 8-10 existing power plants with modern natural gas combined cycle units would result in reductions of 19-29%, 51-55%, 60-62%, and 13-27% in CO2 emissions, NOx emissions, SOx emissions, and water consumption, respectively, across the ERCOT region for two different conversion scenarios.

No abstract

No abstract