By Ketut Dartawan

(This topic was presented at the PSCAD Users group Meeting held in Atlanta, GA on Sept. 20-21, 2018. For the full presentation, please see this link.)

Many interconnection challenges exist when connecting photovoltaic (PV) resources to the electrical distribution grid. Various challenges on the distribution feeders are covered in some technical papers; however, one of the urgent topics – as recently mentioned by utilities and recognized by inverter manufacturers as well as the developers – is the potential for ground fault overvoltage (GFO) on sub-transmission systems feeding distribution feeders via a delta-wye transformer (see Figure 1).

Figure 1: Ground fault overvoltage occurrence for a distribution feeder fed through a delta-wye transformer.

GFO can arise on the following sequence of events:

1. A solid or low impedance single-line-to-ground fault occurs on the transmission side of the service.
2. The fault is detected by the transmission protection which then disconnects the transmission source. This islands the transmission line and connected distribution feeders.  Normally, the island will de-energize if all the connected facilities are typical customer loads.
3. With sufficient amount of PV on the island, the island may stay energized with the fault still present.
4. GFO then arises on the sub-transmission segment of the island. The duration that the GFO remains can potentially be long enough to pose a safety risk to personnel and/or damage electrical devices and equipment.

Utilities have advocated the implementation of a protection scheme based on measurement of zero sequence voltage (referred to simply as a “3V0” scheme). This scheme requires that potential transformers (PT) be installed on the high side of the substation transformer as shown in Figure 2.  The scheme can be costly, especially for single PVs connecting to distribution feeder that does not yet have any PVs.

Figure 2

Pterra conducted a research project (funded by the New York State Energy Research and Development Authority, NYSERDA) to identify an alternative means of detection and protection.  The initial phase of the research used PSCAD as the simulation tool.

The focus of the investigation was on:

• Detection on low-voltage side of the substation transformer.
• Do not require extensive amounts of additional equipment, material or construction.
• Monitor parameters that distinctly identify a potential GFO condition without being overly subject to over sensitivity (such as failing to detect the onset or presence of GFO).

In line with the above, the research looked at electrical parameters on the low-voltage side of the substation.  These included such measurements as voltage imbalance, transient voltage rate of rise, and negative sequence current.  However, none of these parameters provided sufficient sensitivity to meet the objectives of an alternative protection scheme.  The parameters that proved most promising were the secondary (or “low-side”) positive and negative sequence voltages.  Based on this, the Negative Sequence Voltage (NSV) protection scheme was developed.

Figure 3 shows the PSCAD plot of the three phase voltages on the high side of the substation transformer.  At t=0.6 sec, the SLG fault is applied.  After 5 cycles, the transmission side breaker opens, islanding the distribution feeder with PV.  After this, GFO forms on the high-side voltage.

Figure 3: PSCAD plot of high-side voltages.

With the NSV logic, the GFO condition is detected and trips the distribution side breaker.  The overvoltage is dissipated before it has a chance to reach its maximum value.  This is shown in Figure 4.

Figure 4: NSV applied to detect GFO and open the distribution side breaker.

PSCAD provided a working platform that allowed the Pterra researchers to identify potential alternatives to the 3V0 protection scheme.  Following this software-based approach, Pterra is testing the concept of NSV protection using actual hardware.

by  Ketut Dartawan, Amin M. Najafabadi

Pterra is presenting a paper on the above subject at the IEEE General Meeting 2017- Chicago 16~20 July.  Abstract of the paper follows:

IEEE updated its recommended practice and requirement for harmonic control in electric power system after more than two decades. The most updated version of the standard (IEEE Std. 519-2014) revised the 1992 version and its static harmonic voltage and current limits. Unlike the 1992 and the older versions of the standard, the 2014 version introduces a newer approach which considers the stochastic nature of harmonic distortions.  Furthermore, it recommends limits based on the number of times distortions may occur. For example, for the harmonic current distortion, it recommends three limits: daily 99th percentile, weekly 99th percentile, and weekly 95th percentile values. Applying the IEEE Std. 519-2014 for planning studies and for harmonic assessment of proposed projects can be very challenging because presently there is no known commercial tool which fully considers the stochastic simulations and limits required in the standard. This paper demonstrates the approach used by the authors in applying IEEE Std. 519-2014 to a harmonic study recently performed for a 180 MW solar farm.

Index Terms- harmonic analysis, harmonic filters, solar power generation, statistical analysis, time series analysis

In recent work performed by Pterra, the issue of ground fault overvoltage (GFOV) was raised in relation to integration of distributed generation (DG).  In particular, can inverter-based photovoltaic systems, connected in distribution feeders, induce GFOV on the high -side of the substation transformer?  And if so, under what conditions could this occur?  Pterra was engaged to conduct a research study by NYSERDA (the New York State Energy Research and Development Authority) to answer these very questions.  The resulting study and findings are documented and presented in the attached PowerPoint presentation.

Pterra ITWG – Phase I GFOV Study – 011717

For those who want to skip right to the answers: Yes, they can.  Subject to DG/load ratios, performance of surge arresters and interaction of inverter controls from different manufacturers.

The seemingly innocuous flickering of lamps could be a new technical battleground for the further growth and spread of photovoltaic (“PV”) electric power. On one side of the impending conflict is the flicker standard, a venerable reference that could very well trace its roots back to the advent of the electric age. On the other side are the new darlings of the power industry — environment-friendly, renewable solar power. The one thing about solar power is that in bulk amounts, its units need to be connected to existing electrical systems, and a side effect of this integration is the production of flicker. The more PV devices connected to the same electrical circuit, the more flicker is produced and the closer the level of flicker is to the allowable limit defined by the flicker standard.

(This Blog is a continuation of an ongoing series on integrating inverter-based solar photovoltaic generation with existing electric distribution circuits. Link to Part 1)

Solar PV (shorthand for photovoltaic) generation is growing in support and implementation in part because of a supportive regulatory environment. Among the more common types of interconnection terms are NEM and FIT.

Harmonics is a very specialized and not widely understood topic in the electric power field which can become a major issue when inverter-based photovoltaic (“PV”) generators, (popularly referred to as solar power), are added to existing distribution circuits. This Blog provides a quick overview of the phenomena, potential negative impacts, causal conditions, and mitigating measures associated with harmonics. The bulk of the material presented here is based on an oral presentation at the SOLAR 2012 Conference of the World Renewable Energy Forum (WREF 2012) held last May 13-17, 2012, at the Colorado Convention Center in Denver.

“Harmonics Issues that Limit Solar Photovoltaic Generation on Distribution Circuits,” by K. Dartawan, L. Hui – Pterra, M. Suehiro – Maui Electric Co., presented at SOLAR 2012, World Renewable Energy Forum (WREF 2012), May 13-17, 2012, at the Colorado Convention Center in Denver.

One more item to add to the list of technical items to consider when interconnecting solar and wind farms is grounding. The grounding issue often appears when (a) integrating solar power inverters or wind turbines to existing distribution circuits, or (b) designing collector systems for solar and windpower farms.

In study after study, we (Pterra) are encountering this seemingly mounting issue of ride-through capability in solar photovoltaic (“PV”) inverters. For now, the matter is isolated to frequency ride-through in small grids such as those that may be found in the Hawaiian islands. However, there is potential for this to be critical in even larger systems as the number of inverter-based PV arrays interconnecting to existing distribution and transmission systems increases.

The crux of the present issue relates to the frequency ride-through settings and capability for commercial PV inverters. The industry standard that addresses frequency settings for solar PV is IEEE standard 1547, Interconnecting Distributed Resources With Electric Power Systems, which specifies that (for 60 Hz systems):

• For inverters < 30 kW, trip at frequency < 59.3 Hz clearing in 0.16 sec
• For inverters > 30 kW, trip at frequencies 57-59.8 Hz clearing in 0.16 to 300 sec (adjustable setpoint), or at frequency < 57 Hz clearing in 016 sec

Certain commercial PV inverters are equipped with extended frequency ride-through capability that will not trip until frequency drops below 55 Hz.

Renewable energy resources such as solar and wind, produce power in a manner that generally does not contribute to frequency control of interconnected power systems. For wind turbines, the reason for this is that the generators used to convert wind to electric energy have small inertias that dissipate rotational energy more readily than conventional steam turbines. Also, wind turbines are operated such as to generate optimal power from the available wind, and hence do not have much spinning reserve. For inverter-based solar generation, the solid-state controls have no rotating component at all. (Solar thermal power is usually produced with synchronous generators and thus contribute to frequency control as most thermal-type power plants are able to do.)

However, both wind turbines and solar inverters have the important characteristic of fast, programmable controls. The question then comes up: Is it possible for these power sources to participate in frequency control response of interconnections? This is an intriguing question that merits some further investigation.