Optimizing Array-to-Inverter Power Ratio: Page 2 of 3
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In their article “Designing for Value in Large-Scale PV Systems” (SolarPro magazine, June/July 2013), Graham Evarts and Matt LeDucq explain how getting the most value for the development costs applies within the context of a ground-mounted PV power plant: “Developers have invested a lot of money in land, interconnection fees, lawyers and personnel to create the project opportunity. They have also built a substantial ac system infrastructure—one that includes inverters, transformers, switchgear and a substation—and they want to push as much energy as possible through that fixed investment over the life of the PPA [power purchase agreement], even if that means sacrificing production efficiency.”
High-value rate structures. System designers have more incentive to increase dc load ratios when the value for the produced energy is high, as is the case with Ontario’s feed-in tariff program, or when energy generated on summer afternoons is subject to preferential on-peak pricing, as is the case with some utilities serving the desert Southwest. Increasing dc load ratios allows designers to deliver more high-value electricity.
Evarts and LeDucq explain how TOD multipliers for on-peak energy can influence system design decisions: “To capitalize on energy values that are two to three times the baseline rate, designers oversize the dc-to-ac ratio so that inverters run at full power when energy is the most valuable. The general idea is that you are willing to give away (via clipping) 2 MWh of energy at $100/MWh to get 1 MWh of energy at $250/MWh, because this nets you $50.” Figure 1 illustrates how designers can use a high dc-to-ac load ratio in response to on-peak pricing to generate more high-value energy.
AC capacity limits. Since the NEC 2011 edition, Section 705.12(A) specifically limits the capacity of supply-side interconnected electric power production sources: “The sum of the ratings of all overcurrent devices connected to power production sources shall not exceed the rating of the service.” Furthermore, Section 690.8 requires that the overcurrent device rating for an inverter output circuit be no less than 125% of the inverter continuous output-current rating. Taken together, these requirements effectively limit the inverter capacity rating for a supply-side connection to no more than 80% of the service transformer kVA rating. For a site served by a 500 kVA transformer, the maximum interconnected inverter capacity is 400 kW.
In this scenario and others pertaining to load-side interconnections, the NEC places a hard limit on inverter capacity. However, manufacturer product specifications and available array area are the only hard limits to dc system capacity. Therefore, as long as system designers use the inverter according to the manufacturer’s installation instructions, they can increase the PV array capacity until the available array area is fully utilized or there is no economic justification for installing additional modules.
There are also scenarios where a designer might choose to limit the ac system capacity and use a high dc load ratio to avoid high capital costs associated with purchasing specialized equipment or upgrading a service. For example, the utility may have special requirements—such as redundant relaying or direct transfer trip—above a certain capacity threshold, or the existing electrical infrastructure or building service may limit the ac system size. A designer might also opt to limit inverter capacity in response to break points in a feed-in tariff program.
Suboptimal conditions. In the desert Southwest, PV modules are routinely exposed to irradiance values approaching and even exceeding 1,000 W/m2. These high-irradiance conditions are less common in other parts of North America. For example, in Ontario or New England the plane-of-array irradiance on a typical clear day might reach 800 W/m2. In locations like these, it makes sense for designers to increase the dc load ratio.
PV system designers can also use a high dc load ratio to offset the inevitable impacts of array degradation. As PV arrays age, module performance degrades. Ideally, this degradation is linear and the annual power loss does not exceed 0.5% annually. If designers want to ensure that a PV array’s power output fully loads an inverter under certain conditions in the summer of year 10 or year 20, then they must specify a higher dc-to-ac ratio than is required to accomplish this same loading in year 1.
The best way for system designers to optimize the array-to-inverter power ratio for a specific project is to use a PV system modeling program such as HelioScope, PVsyst, PV*SOL or System Advisor Model (SAM). By keeping the inverter capacity constant and varying the array capacity, designers can model the financial and production efficiencies resulting from different dc loading options. They can then select the optimal design based on typical meteorological year weather data and other project-specific variables. When choosing the PV system model, designers must select a simulation program that can model the effects of inverter power limiting and changes in inverter efficiency based on different voltage and power levels.