By: Adam Baker
Solar Developers: Make Your PV Project Viable Again
UPDATE JANUARY 2017: Check out CAISO & NREL's 2017 Solar Advanced Reliability Report to read more about voltage regulation.
Getting a utility to approve an interconnect agreement can be a pain. According to EQ Research, “as distributed generation penetration levels increase, utilities are more likely to deny distributed generation system interconnection by raising safety and grid reliability concerns, further complicating and delaying the interconnection process.”
Perhaps the biggest letdown for utility-scale solar developers are the results of an interconnect agreement system impact study.
After the hard work of getting a power purchase agreement (PPA) and conditional use permit (CUP) approved, and after applying for an interconnect agreement, the system impact study might inform you that the grid is too soft or your voltage variability is too high. To successfully get the interconnect agreement approved, you are required to add inductors or capacitors to maintain grid voltage stability at the POI.
The problem is, capacitor and inductor bank expenses will break your project financing…. which means your project is no longer viable.
Most people believe they have two choices:
- Install expensive capacitor banks and inductor banks and extend project ROI.
- Dump the interconnect location (and land lease) and begin again at a new location with a new site selection and system impact study.
In actuality, you have a third and better choice:
- Use inverter VARs in place of inductors and capacitors
PV voltage regulation reduces the need for inductor/capacitor banks
Whatever you do, don’t scrap your project after learning your interconnect point is too soft. There is another way to make your project viable again and meet utility requirements in cost effective manner.
Implement virtual inductors and capacitors instead of physical inductor/capacitor banks.
How? A plant monitoring and control system (SCADA) automatically monitors voltage through high speed communications from metering that then commands inverters to inject inductive or capacitive VARs to stabilize voltage variability on the grid.
Using a controls and monitoring system, your PV plant can inject the equivalent amount of VARs as it could if it were using inductor/capacitor banks. In fact, without the fixed VAR steps that capacitor banks or inductor banks are sized for, inverter VARs allow for much finer stabilization of grid voltage.
Virtual voltage control using inverters has been used since 2010, but is gaining more popularity among PV developers. In fact, an IEEE standard is under development (IEEE 1547) “that would allow inverters to actively contribute to voltage and frequency regulation.” In addition, the Smart Inverter Working Group (SIWG) has plans to achieve smart inverter adoption in late 2016.
Case study: Using inverter VARs to correct grid voltage conditions
The following figures are taken from a paper entitled Grid Integration of Large Utility-Scale PV Plants: Key Lessons Learned by Mahesh Morjaria.
One of the largest solar power plants in the U.S., Agua Caliente, runs off a transmission line shared by the largest nuclear power plant in the U.S. (see Figure 1). I had the privilege of being part of the development of Agua Caliente, as Control Systems Architect.
Figure 1: Agua Caliente
As part of the project, we implemented an inverter VAR control capability that had not been tried before at this scale. In addition to capacitor banks in the substation, we were also able to command inverters to inject capacitive or inductive VARs at incredibly fast rates. Inverter VAR injection could start within 20 cycles of detected voltage changes.
In testing the VAR capability of the system, we were given unlimited ability to vary VAR output, and it was soon clear that our ability to affect grid voltage was apparent. Even on a 500kV transmission line.
Our research was soon put to the test in a real-life grid emergency scenario.
On March 14, 2014, the line between the nuclear power station and its substation was taken out of service. At about 6am, there was a significant spike in voltage (see Figure 2). The grid operator called upon Agua Caliente for assistance.
Figure 2: Voltage Support During Abnormal Conditions
The solar plant was switched from constant power factor to voltage control mode, and the voltage variability was reduced by several orders of magnitude, right up until the point where the plant shut down at the end of the generation day.
If this were installed today, the ability of many inverters to be able to produce “night VARs” would have helped stabilize grid voltage beyond the end of the solar generation day.
3 benefits of virtual voltage control
If you aren’t already convinced, here are three reasons you should seriously look into virtual voltage control.
It’s more affordable
The cost of a SCADA monitoring and control system that includes PV voltage regulation capabilities will be a fraction of the expense of inductor/capacitor banks, assuming inverters are able to operate in variable VAR mode (most control inverters today are). Essentially, these systems help make a plant viable again after expensive requirements of an interconnect agreement when inductors, capacitors, or DVAR are considered.
It allows for more fine tuning
Unlike inductor/capacitor banks, VAR injection is proportionally controlled. Instead of stepping up VARs in one giant chunk, it ramps up proportional to size of deviation. Using inverters instead of capacitors means you’ll get more gradual, smaller VAR injection increments to ensure the transmission/distribution voltage remains stable.
It allows you to meet more interconnect requirements
SCADA and instrumentation systems might already be a requirement of your interconnect agreement, in which case you would kill two birds with one stone. Many utilities will require the ability to curtail or trip large sites. With some expertise, and hardware that may already be installed at the site, some form of AVR (Automatic Voltage Regulation) can be implemented to provide grid stability where it might otherwise be a challenge.
According to the IFA, a monitoring system is essential to a PV plant. “Monitoring devices are crucial for the calculation of liquidated damages (LDs) and confirmation that the EPC contractor has fulfilled its obligations.” Without a reliable monitoring system, it can take months to identify performance problems, which can lead to serious revenue loss.
In cases where interconnect agreement requirements for capacitors or inductors might break a project financing model, there’s no need find a different place to interconnect. Voltage control using inverters may make your project viable again. A project that may not be financially viable because of the cost of capacitor banks should be instead evaluated for inverter voltage control by an Affinity Energy control system. We’ll be happy to work with you and your utility to define a control strategy that will work for everyone.
Adam Baker is Senior Sales Executive at Affinity Energy with responsibility for providing subject matter expertise in utility-scale solar plant controls, instrumentation, and data acquisition. With 23 years of experience in automation and control, Adam’s previous companies include Rockwell Automation (Allen-Bradley), First Solar, DEPCOM Power, and GE Fanuc Automation. Adam was instrumental in the development and deployment of three of the largest PV solar power plants in the United States, including 550 MW Topaz Solar in California, 290 MW Agua Caliente Solar in Arizona, and 550 MW Desert Sunlight in the Mojave Desert. After a 6-year stint in controls design and architecture for the PV solar market, Adam joined Affinity Energy in 2016 and returned to sales leadership, where he has spent most of his career. Adam has a B.S. in Electrical Engineering from the University of Massachusetts, and has been active in environmental and good food movements for several years.