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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.
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In this report, we evaluate individual options that have the potential to stem the decline in the marginal value of variable generation (VG) with increasing penetration levels. We focus only on the effectiveness of mitigation measures for wind and PV.
In one respect, disclosed is an in-situ current-voltage (I-V) measurement device for photovoltaic modules in a photovoltaic array, comprising a variable load, wherein the variable load is configured to be connected in parallel with a module, wherein the module is connected in series with at least one other module in a string, such that the module supplies current simultaneously to the string and to the variable load, and wherein the variable load is controlled by a controller, and wherein the controller is configured to shift an I-V operating point of the module, based at least upon varying the variable load.
Temperature variations across the continental northern hemisphere at the interdecadal scale are thought to be remotely modulated by oceanic internal climate variability and the Arctic. Nevertheless, further elucidating the dynamics is essential for clarifying ongoing debates. We show that potential vorticity (PV) dynamics provide a concise explanation for these teleconnections. Our findings demonstrate that extratropical oceans and the Arctic can remotely modulate the wintertime continental temperature variations by stimulating PV anomalies, which are constrained by climatological PV gradients and jet streams. A causal explanation includes anomalous temperature and precipitation over oceans and the Arctic inducing local PV anomalies via diabatic heating. Subsequently, meridional and downstream advection distributes the anomalous PV to remote land regions where the climatological PV gradients are strong, that is, involving PV fronts, as well as jet streams; therefore, PV fronts and jet streams jointly indicate land regions that are largely and frequently impacted. However, land can also modulate other regions through the same mechanism when variations over land occur in advance. Clear causality depends on which factor is independent, while interactions among those regions may convolute the causality, thereby causing further debates.
For several years, the Control System Studio (CS-Studio) Scan System has successfully automated the operation of beam lines at the Oak Ridge National Laboratory (ORNL) High Flux Isotope Reactor (HFIR) and Spallation Neutron Source (SNS). As it is applied to additional beam lines, we need to support simultaneous adjustments of temperatures or motor positions. While this can be implemented via virtual motors or similar logic inside the Experimental Physics and Industrial Control System (EPICS) Input/Output Controllers (IOCs), doing so requires a priori knowledge of experimenters requirements. By adding support for the parallel control of multiple process variables (PVs) to the Scan System, we can better support ad hoc automation of experiments that benefit from such simultaneous PV adjustments.
Experiments were conducted on six trained distance runners (21-23 yr) subjected to an eight-day dietary control at sea level, followed by an eight-day stay in an altitude chamber (2287-m altitude) and a four-day recovery at sea level. Fluid and electrolyte shifts during exercise at altitude were evaluated to gain insight into the mechanism of reduction in working capacity. The results are discussed in terms of resting fluid volumes and blood constituents, maximal exercise variables, and maximal exercise fluid-electrolyte shifts. Since there are no significant changes in fluid balance or resting plasma volume (PV) at altitude, it is concluded that neither these nor the excessive PV shifts with exercise contribute to the reduction in maximal oxygen uptake at altitude. During altitude exposure the percent loss in PV is found to follow the percent reduction in maximal oxygen uptake; however, on the first day of recovery the percent change in PV remains depressed while maximal oxygen uptake returns to control levels.
Smart inverters provide additional control capability to help optimize the operation of distribution systems. This paper proposes a framework for exact optimal active and reactive power dispatch of distributed photovoltaic (PV) generation, switched capacitors, and tap changers in large multi-phase unbalanced distribution systems. The objectives of the optimal dispatch are minimization of the energy loss, PV active power curtailment, and capacitor and tap changer switching operations, in addition to elimination of voltage violations and reverse power flow. The optimization problem is formulated in rectangular coordinates as a nonlinear, nonconvex problem. Effective computational strategies are proposed to allow the application of predictorcorrector primal-dual interior point method to solve optimization problems in real-time with a large number of constraints and variables, including discrete variables corresponding to switched capacitors and tap changers. The accuracy of the numerical solution and the ability to implement the proposed framework are validated using the unbalanced multi-phase IEEE 34-bus and EPRI 2,998-bus distribution systems with 15-minute load and PV data. The results show a significant loss reduction and complete removal of both voltage violations and reverse power flow.
This CRADA focused on addressing concerns related to the impact of high penetration PV systems and developing simulation models for PV power plants. Technical work encompassed instrumentation, data collection and analysis, and development and validation of industry-standard models for utility planning and interconnection studies. This collaboration also resulted in dissemination of key research findings and advancement of standards. Sandia National Laboratories (Sandia) and SunPower contributed significantly to stakeholder activities such as the North America Electric Reliability Corporation (NERC) Integration of Variable Generation Task Force (IVGTF) and the Western Electricity Coordinating Council(WECC) Modeling and Validation Work Group. This research and collaboration also contributed to the success of Sandia projects sponsored by the DOE PV Solar Energy Technologies Program.
High penetration of grid-edge, inverter-based photovoltaic (PV) can cause significant voltage fluctuations not only at the distribution but also at the sub-transmission levels due to PV output intermittency. Traditional reactive power planning approaches do not consider intermittency, nor the possibility of coordinating the control of existing and future volt-ampere reactive resources. This paper proposes a reactive power planning tool for sub-transmission systems to mitigate voltage violations and fluctuations caused by high PV penetration and intermittency with a minimum investment cost. The planning tool coordinates with an optimization-based volt-var operational tool for: a) modeling the coordination of all existing var assets in both sub-transmission and distribution systems to reduce the need of new equipment, and b)selecting a set of scenarios with voltage violations, derived from PV intermittency c) testing the final investment decision. The tool obtains an investment need for each intermittency scenario with a proposed optimal power-flow framework with efficient techniques to handle a high number of discrete variables. Two options are provided for final planning decision: i) a conservative direct combination of investment need solutions and ii) a machine learning-based selection of representative investment needs at most time steps. The final investment decision options are verified using a realistic large-scale sub-transmission system and 5-minute PV and load data. The results show a significant voltage performance improvement with a lower investment cost for additional var equipment compared to conventional approaches.
This study examines the impact of reserve margin-based reliability assessment, as commonly used in capacity expansion models, on planning resource-adequate power systems under high penetrations of solar photovoltaics (PV). As a generation resource, PV is operationally different from the conventional dispatchable resources for which most capacity expansion models were designed. The question this study attempts to answer is whether large amounts of PV on a system (in this case, the Western Interconnection of North America) would bias the results of conventional reserve margin-based capacity expansion modeling towards an over- or under-provisioning of resource adequacy. This analysis used NREL’s Resource Planning Model (RPM) for capacity expansion modeling and NREL’s Probabilistic Resource Adequacy Suite (PRAS) for resource adequacy assessment. RPM uses a reserve margin requirement to enforce resource adequacy. PRAS, a collection of tools for studying the resource adequacy of power systems and the adequacy contributions of individual resources on a probabilistic basis, was used to compute multiple resource adequacy metrics across a number of simulated scenarios and system representations with differing regional detail. In all cases, including high PV penetrations (up to 33% annual generation from PV, interconnection-wide), RPM was able to produce resource-adequate systems as measured by normalized expected unserved energy and loss-of-load expectation results from PRAS. The accuracy of reserve margin approaches depends heavily on the underlying assumptions informing the capacity credit assigned to variable and energy-limited resources, particularly when such resources are abundant in the modeled system. RPM’s standard methodology for estimating variable and flexible resources’ capacity contributions, which is based on the top 100 hours of net load, did not appear to systematically undervalue or overvalue variable generation relative to a more rigorous equivalent firm capacity assessment using PRAS, although both over- and under-valuations were observed in specific scenarios. In the worst cases, the top 100 hour method underestimated the equivalent firm capacity of PV by two percentage points, and overestimated the equivalent firm capacity of PV by five percentage points. Calculating capacity contributions based on the top 10 hours of net load systematically underestimated equivalent firm capacities at more modest PV penetrations, but was often a better approximation of equivalent firm capacity than the existing 100-hour approach in scenarios with higher PV penetrations.
The purpose of this investigation was to determine the effects of 6 months of endurance training on resting plasma (PV) and blood volume (BV), and resting hormone and electrolyte concentrations in the elderly. Thirty-eight elderly men and women (ages 60-82 yr) were assigned to endurance exercise training (N = 29) or to control (N = 9) groups. Resting plasma levels of adrenocorticotropic hormone, vasopressin, aldosterone, norepinephrine, epinephrine, sodium, potassium, and protein were measured at the start (T1) and end (T2) of 26 wk of training. PV measurement was performed using the Evan's blue dye technique. Endurance training consisted of uphill treadmill walking or stairclimbing exercise 3 times.wk-1, 30-45 min.d-1, at 75-84% of maximal heart rate reserve. The exercise group increased VO2max by 11.2% (P < or = 0.05) and increased resting PV and BV by 11.2% and 12.7% (P < or = 0.05), respectively. Hormone and electrolyte levels in the exercise group remained unchanged; all variables were unchanged in the control group. These results are similar to findings in younger individuals. Because plasma hormone concentrations were maintained despite a chronically elevated BV, endurance training in healthy, elderly subjects may be associated with a resetting of volume receptors.
In this report we summarize the implications, impacts, and deployment potential of reaching the SunShot 2030 targets for the electricity system in the contiguous United States. We model 25 scenarios of the U.S. power sector using the Regional Energy Deployment Systems (ReEDS) and Distributed Generation (dGen) capacity expansion models. The scenarios cover a wide range of sensitivities to capture future uncertainties relating to fuel prices, retirements, renewable energy capital costs, and load growth. We give special attention to the potential for storage costs to also rapidly decline due to its large synergies with low-cost solar. The ReEDS and dGen models project utility- and distributed-scale power sector evolution, respectively, for the United States. Both models have been designed with special emphasis on capturing the unique traits of renewable energy, including variability and grid integration requirements. Across the suite of scenarios modeled, we find that reaching the SunShot 2030 target has the potential to lead to significant capacity additions of PV in the United States. By 2050, PV penetration levels are projected to reach 28-46 percent of total generation. If storage also sees significant reductions in cost, then the 2050 solar penetration levels could reach 41-64 percent. PV deployment is projected to occur in all of the lower 48 states, though the specific deployment level is scenario dependent. The growth in PV is projected to be dominated by utility-scale systems, but the actual mix between utility and distributed systems could ultimately vary depending on how policies, system costs, and rate structures evolve.
This paper proposes a new methodology to capture the impact of fast moving clouds on utility power demand charges observed in microgrids with photovoltaic (PV) arrays, generators, and electrochemical energy storage. It consists of a statistical approach to introduce sub-hourly events in the hourly economic accounting process. The methodology is implemented in the Distributed Energy Resources Customer Adoption Model (DER-CAM), a state of the art mixed integer linear model used to optimally size DER in decentralized energy systems. Results suggest that previous iterations of DER-CAM could undersize battery capacities. The improved model depicts more accurately the economic value of PV as well as the synergistic benefits of pairing PV with storage.
With increasing penetration of distributed generation (DG) in the distribution networks (DN), the secure and optimal operation of DN has become an important concern. In this paper, an iterative mixed integer quadratic constrained quadratic programming model to optimize the operation of a three phase unbalanced distribution system with high penetration of Photovoltaic (PV) panels, DG and energy storage (ES) is developed. The proposed model minimizes not only the operating cost, including fuel cost and purchasing cost, but also voltage deviations and power loss. The optimization model is based on the linearized sensitivity coefficients between state variables (e.g., node voltages) and control variables (e.g., real and reactive power injections of DG and ES). To avoid slow convergence when close to the optimum, a golden search method is introduced to control the step size and accelerate the convergence. The proposed algorithm is demonstrated on modified IEEE 13 nodes test feeders with multiple PV panels, DG and ES. Numerical simulation results validate the proposed algorithm. Various scenarios of system configuration are studied and some critical findings are concluded.
The 2012 NREL report 'Photovoltaic Shading Testbed for Module-Level Power Electronics' provides a standard methodology for estimating the performance benefit of distributed power electronics under partial shading conditions. Since the release of the report, experiments have been conducted for a number of products and for different system configurations. Drawing from these experiences, updates to the test and analysis methods are recommended. Proposed changes in data processing have the benefit of reducing the sensitivity to measurement errors and weather variability, as well as bringing the updated performance score in line with measured and simulated values of the shade recovery benefit of distributed PV power electronics. Also, due to the emergence of new technologies including sub-module embedded power electronics, the shading method has been extended to include power electronics that operate at a finer granularity than the module level. An update to the method is proposed to account for these emerging technologies that respond to shading differently than module-level devices. The partial shading test remains a repeatable test procedure that attempts to simulate shading situations as would be experienced by typical residential or commercial rooftop photovoltaic (PV) systems. Performance data for multiple products tested using this method are discussed, based on equipment from Enphase, Solar Edge, Maxim Integrated and SMA. In general, the annual recovery of shading losses from the module-level electronics evaluated is 25-35%, with the major difference between different trials being related to the number of parallel strings in the test installation rather than differences between the equipment tested. Appendix D data has been added in this update.
This study examines the impact of concentrating solar power (CSP) on grid reliability by investigating the dynamic behavior of the Western Interconnection under conditions of high solar and wind generation. Reliability in this case refers to the somewhat narrow context of stability: transient stability and frequency response; and control stability, especially that associated with weak grids. The objectives of this study were to identify renewable energy penetration levels and mixes, severe disturbances, and load conditions where grid performance and reliability could be enhanced with CSP plants. Instantaneous penetrations of wind and solar - both photovoltaics (PV) and CSP - up to approximately 60% were considered. The focus is on situations in the Western Interconnection bulk power system during which variable renewable generation has displaced other (non-CSP) synchronous thermal generation under highly stressed, weak system conditions. Particular attention was given to impacts of frequency-responsive controls and synchronous generation characteristics.
This study examines the impact of concentrating solar power (CSP) on grid reliability by investigating the dynamic behavior of the Western Interconnection under conditions of high solar and wind generation. Reliability in this case refers to the somewhat narrow context of stability: transient stability and frequency response; and control stability, especially that associated with weak grids. The objectives of this study were to identify renewable energy penetration levels and mixes, severe disturbances, and load conditions where grid performance and reliability could be enhanced with CSP plants. Instantaneous penetrations of wind and solar - both photovoltaics (PV) and CSP - up to approximately 60% were considered. The focus is on situations in the Western Interconnection bulk power system during which variable renewable generation has displaced other (non-CSP) synchronous thermal generation under highly stressed, weak system conditions. Particular attention was given to impacts of frequency-responsive controls and synchronous generation characteristics.
One of the difficulties in determining constituent trends from the ER-2 flight data is the large amount of day to day variability generated by the motion of the polar vortex. To reduce this variability, the observations have been transformed into the conservative (Lagrangian) reference frames consisting of the coordinate pairs, potential temperature (PT) and potential vorticity (PV), or PT and N2O. The requirement of only two independent coordinates rests on the assumption that constituent distributions and their chemical processes are nearly zonal in that coordinate system. Flight data is used everywhere for these transformation except for potential vorticity. Potential vorticity is determined from level flight segments, and NMC PV values during flight dives and takeoffs are combined with flight data in a smooth fashion.
Due to natural variability and uncertainty, the ever-increasing penetration of solar generation in Hawaii presents challenges to power grid operators to maintain reliable system operation. Demand response (DR) has the potential to be a cost-effective tool for Hawaii to reach its aggressive renewable energy goals while maintaining the reliability of power grids. The Hawaii Public Utilities Commission has approved the Hawaiian Electric Company's revised portfolio of DR programs. The companies have released a grid services purchase agreement and subscribed an initial tranche of load into their DR programs. This paper presents innovative analytical methods and comprehensive economic assessment for distributed photovoltaics (PV) paired with battery energy storage systems (BESSs) for two new DR programs, including fast frequency response and capacity grid service. Optimal dispatch and sizing methods are proposed for the paired system considering different tariff schedules and PV compensation programs across five islands. It was found that while the best resource configuration and potential economic benefits vary with tariff structure, a BESS paired with PV can be optimally dispatched to generate multiple value streams simultaneously. Compensation from DR programs is an important value stream to help increase the cost-effectiveness of the integrated system.