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

Circuit breaker nameplates sometimes indicate only rating on symmetrical short circuit current. In such cases, the rating only reflects the AC component of the short circuit current. A common misinterpretation occurs when one compares the symmetrical short circuit current against the symmetrical short circuit current rating of the circuit breaker for the purposes of circuit breaker duty evaluation. This article provides pointers to avoid making the mistake.

Why is X/R Ratio Important?

Short circuit analysis is a critical piece of the engineering study for a power system. This analysis determines the maximum available fault current in the system, and hence the maximum level that the electrical equipment should be able to withstand.

When a short circuit occurs, the total short circuit current consists of:

• ·        AC component (varies sinusoidally with time), also known as symmetrical current
• ·        DC component (non periodic and decays exponentially with a time constant L/R;  L/R is proportional to X/R)
• ·        The DC component makes the symmetrical current become asymmetrical.

The X/R ratio affects the dc component, and therefore, also the total current. The higher the X/R ratio of a circuit, the longer the dc component will take to decay (longer time constant).

(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.

A wave of new solar photovoltaic (“PV”) installations for power generation is hitting many distribution circuits around the country. These installations are typically in the range of 10-2000 kW and comprise of a set of solar PV arrays or trays and inverter modules. The inverters are needed to change the direct-current produced by the arrays to the alternating current standard used by the distribution circuits. The smaller installations connect single-phase, while the larger sizes are three-phase. Interconnection voltage at the point of common coupling between the PV installation and the distribution circuit varies from 120 volt up to 34.5 kilovolt (“kV”).

The concept of integrating these new PV installations with existing distribution circuits is similar to that of interconnecting larger generators in the transmission grid; i.e., the new installation should “do no harm” to the existing system. There are three aspects to this concept as follows. (1) If the existing circuit meets specified standards or criteria of performance, the circuit should still meet the same standard or criteria when the new PV is installed. (2) If the new PV introduces a violation of standard or criteria, mitigation measures need to be included as part of the the new PV’s installation to resolve the violation. (3) If the existing circuit already violates a standard or criteria, the new PV either should not make the violation worse, or limit its impact such that the violation is not worse or even reduced or eliminated.

Distributed generation (DG) has become a viable option and is gaining wider acceptance to utilities, customers, and independent power producers. While DG offers many advantages, the interconnecting utility typically requires a system impact study for interconnecting DG to the existing electric grid to ensure it would not adversely impact the operation, reliability and safety of the grid. By its nature, DG would interconnect to lower voltage systems generally classified as “distribution”. The studies can range from relatively quick feasibility assessments to comprehensive studies involving extensive equipment and power system modeling, measurements, and detailed simulations. Specific topics for such studies include: islanding, steady state power flow, voltage regulation, short-circuit, protective relaying, power quality (flicker and harmonic), power factor, system stability, grounding, and ground fault overvoltage.

Distributed generators (DGs) are small generating units that are connected to the distribution network at voltages below 69 kV. DG units usually have capacities of 10MW or less, and are based on different energy sources, such as wind, solar and diesel. The distribution network is generally a radial system and designed for one direction of load flow, i.e. from the electric grid to the load. The unidirectional flow assumption is no longer valid when DG is interconnected at the customer or load side since the flow of power can now go in either direction: from the load side to the grid or from the grid to the load side. This fundamental change affects how an impact study, generally required to identify and mitigate any changes to reliability of the distribution system, for DG interconnection is conducted. Reference 1 summarizes several typical tasks required in an interconnection impact study.

by K. Dartawan, R. Austria

What is Distributed Generation (DG)? Unlike big generation stations connected directly to the utility’s transmission grid, DG is typically smaller, about 10 MW or less connected to the distribution network or customer side. The DG could be fueled by renewable sources such as photovoltaic (solar), wind, bio mass or could be non-renewable energy such as diesel or gas.