Case Studies on Ground-Fault Protection of Microgrid Power Systems With Diverse Power Sources
Authors: Dirk Danninger, Scott Manson, Fernando Calero, and Ceeman Vellaithurai
Affiliation: Schweitzer Engineering Laboratories, Inc.
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This paper was presented at the 69th Annual Petroleum and Chemical Industry Technical Conference and can be accessed at https://doi.org/10.1109/PCIC42668.2022.10181255.
Revised edition released September 2022. Originally presented at the 69th Annual Petroleum and Chemical Industry Technical Conference, September 2022.
I. INTRODUCTION
The proliferation of distributed energy resources (DERs) in microgrids and the variety of vendors with different protection philosophies make the interconnection of these resources to utility grids, while maintaining ground fault detection and isolation, increasingly complex. This complexity arises because, in industrial and commercial low-voltage distribution, the ground conductor normally carries no current to ensure equipment and personnel grounds are at the same potential. In a three-wire system, this is straightforward as there is no neutral conductor. However, in a four-wire system, loads are connected line-to-line and line-to-neutral. Thus, the neutral and ground must be isolated throughout the distribution and bonded to ground at only one point, typically at the service entrance. When multiple sources have their neutrals grounded, additional measures are needed to detect and trip upon current flow on multipoint grounded systems. Furthermore, many microgrid projects are funded by utility entities, which are often exempt from National Electric Code (NEC) requirements applicable at DER sites.
This paper discusses several ground fault detection schemes and provides an example for each, as listed in TABLE I.
| Type | In This Paper | Apply NEC Code |
|---|---|---|
| Building Service Entrance | Yes | Yes |
| Distribution | Yes | Depends on line ownership (IEEE and NESC) |
| Microgrid | Yes | Depends on voltage level and ownership |
| Transmission | No | IEEE and NESC |
II. LOW-VOLTAGE BUILDING SERVICE ENTRANCE
A. Background
Figure 1 illustrates a typical indoor service entrance with both utility and generator sources and branch distribution breakers. This type of service entrance provides emergency backup power to a critical facility. Each source may or may not be grounded at the source itself or at the service entrance. The multiple-point grounding possibilities present challenges for proper ground fault detection when one or both sources are supplying the load (paralleled operation).
The NEC Article 250 covers general requirements for grounding and bonding systems [1]. It also includes equipment-specific requirements and various grounding types (e.g., solid, low-resistance, high-resistance). A grounded system has at least one conductor or point (usually the neutral point of a transformer or generator winding) intentionally grounded, either solidly or through an impedance, as discussed in Section 3.1 of [2]. System grounding controls voltage with respect to earth within predictable limits and provides a current flow for detecting unwanted connections between system conductors and ground, allowing for their removal, as discussed in Section 1.3 of [2]. Grounding and bonding ensure voltage potentials between conductive parts are minimized during normal operation and faults, protecting personnel from electric shock.
For low-voltage building service entrances (277/480 V), NEC Article 230.95 requires ground fault protection for services of 1,000 A or larger, detecting and tripping for faults below 1,200 A. Faults at or above 3,000 A must be cleared within one second. These NEC requirements are for equipment protection, not personnel protection, which is the focus of this paper.
It is important to distinguish between system grounding and equipment grounding. A system can be grounded or ungrounded. In an ungrounded system, none of the transformer secondary conductors are intentionally connected to ground. In a grounded system, the neutral is typically bonded to the grounding electrode. Other grounding schemes, like corner delta or center tap grounding, are not within the scope of this paper. System grounding is the grounding of the power system. Equipment grounding involves installing the equipment grounding conductor (EGC) to provide a low-impedance path for ground fault current back to the source. The absence of a low-impedance path can leave equipment parts energized, leading to shocks or flashovers.
Systems with a single service entrance provide ground fault protection using circuit breakers (CBs) with ground fault protection, often marked with a 'G' in their function (e.g., LSIG for long, short, instantaneous, and ground). Service entrances can also serve as a microgrid point of common coupling (PCC) and are protected/controlled by programmable protective relays (PPRs) with advanced features beyond LSIG.
A microgrid, by definition, may have many DERs, and a building's service might originate from multiple sources. For instance, an automatic transfer switch (ATS) can supply a building from two different sources. To minimize power outages during microgrid operations, a closed-transition transfer might be used to switch loads between sources without interruption. It may also be beneficial to maintain both sources connected in parallel to support the microgrid, such as using a building emergency generator for peak load shaving.
Operating multiple sources in parallel at the PCC poses a challenge if each source is grounded. If a ground fault occurs within the building's electrical distribution, the fault current has multiple paths to return to its source, potentially preventing service breakers from tripping and desensitizing ground fault detection. In four-wire systems, the common neutral between two sources presents additional challenges for ground fault sensing, as it provides another path for ground current to flow [3].
Figure 1 Description: A diagram showing a typical indoor service entrance with connections from a utility source and a generator source to a main breaker, then to a distribution bus with branch breakers. It illustrates multiple sources feeding a common bus.
B. Detecting and Protecting
Detecting a ground fault on multiple three-wire sources is conceptually simple: sum all current transformer (CT) secondary currents. If the sum is greater than zero, a ground fault exists, as illustrated in Figure 2.
Figure 2 shows a single source to a load and a detection system. The goal is to protect the load, which is the protected zone. For a three-wire system, a phase-to-ground fault is readily detected by the PPR as the sum of the three-phase currents. Summing three-phase currents works well for three-wire systems where loads are connected only between phases. However, many low-voltage commercial and industrial systems use both line-to-line and line-to-neutral loads and are four-wire systems (e.g., 120/208 V and 277/480 V), as illustrated in Figure 3.
Figure 3 illustrates a four-wire system with a load connected between a phase and the neutral. The relay measures a current proportional to the load in the neutral. This means the technique of summing three-phase currents includes load and fault currents. Elements based on Ig in Figure 3 must be set above the largest load imbalance, which can cause coordination issues with large single-phase cold load pickups and inrush conditions. To remedy this, adding another CT on the neutral to the summation network cancels out the phase current.
Figure 4 illustrates a differential current scheme where the ground current, Ig, is the difference of current on all current-carrying conductors, including the neutral. The relay can supervise Ig and trip when necessary, independent of phase and neutral loads.
The NEC classifies grounding systems as nonseparately derived systems (NSDSs) (see Figure 5) or separately derived systems (SDSs) (see Figure 7).
In a system with a utility service and backup generator, the ATS or CB can be three- or four-pole. In a three-pole ATS or CB, the neutral conductor is not switched. The system maintains a direct electrical connection between the service neutral and the generator neutral through the neutral bus in the ATS. This type of system is considered an NSDS. An EGC must run from the generator to the ATS to provide a low-impedance path for ground fault current. The NEC requires that the system is grounded at only one location for an NSDS, typically through a bonding jumper at the service utility transformer. This prevents parallel paths during ground faults. The issue with multiple grounds in such a system is shown in Figure 6, where fault current splits across the neutral and EGC. Because part of the fault current returns through the neutral conductor, ground fault detection using a scheme similar to Figure 4 can be desensitized or defeated (affecting relay dependability), depending on the fault location.
In a four-pole ATS, the neutral conductor is switched. This severs the direct electrical connection between the service and generator during ATS operation. Such a system is considered an SDS, requiring a separate grounding electrode conductor and grounding electrode for the SDS generator to maintain proper grounding when the load is supplied by the generator. Figure 7 shows a representation of an SDS.
Ground fault protection on an NSDS can be complex with multiple standby generators or other sources. The scheme in Figure 4 might not work because fault current from the generator would return on the neutral, resulting in a zero value. The fault current must return to the source through the neutral; therefore, a residual calculation of phase currents or a direct measurement of neutral current is suitable. However, a study is needed to examine circulating currents between parallel generators and load imbalances that could contribute to neutral currents. Even generators of the same type and manufacturer can have circulating currents due to winding and impedance asymmetries, similar to paralleled transformers. In this case, the pickup should be set above the maximum normally expected current in the neutral conductor and coordinated with other feeder protection. Additionally, service entrance ground fault protection operation needs supervision based on breaker or ATS status to prevent false indications on non-load supplying breakers when operating from an alternate source.
The use of three- and four-pole ATSs complicates ground fault detection due to parallel paths when multiple grounds are provided and sources are paralleled. When more than one source supplies a load, such as a paralleled ATS to a utility and generator or a main-tie-main supplying a service entrance, a scheme similar to Figure 4 can be employed with modifications for ground fault protection. A common scheme is the Modified Differential Ground Fault (MDGF) scheme, shown in Figure 8 [3] [4] [5].
Figure 8 illustrates the MDGF scheme for multiple sources. Load currents on phases or neutral are canceled, and only current associated with a ground fault is sensed by the PPR. The ground fault current is the sum of individual source contributions, which may differ due to impedances. In this configuration, these differing fault current contributions are not relevant.
The diagrams presented thus far use CTs in a summation configuration. A core-balanced CT is typically impractical or uneconomical due to physical bus size and routing. Using dedicated CTs for differential ground fault measurements and separate CTs for phase current monitoring is also uneconomical. A CT arrangement serving both purposes is needed.
Figure 9 illustrates a complete solution for a protection system, including ground fault protection. In this arrangement, eight CTs provide signals for individual phase currents for traditional protection, and the summation of current signals routed through the relay (IN) provides differential ground fault protection.
The arrangement requires no additional CTs or relays beyond those needed for individual service feeder protection, making it economical and simple. A PPR with seven current inputs economically satisfies the relaying requirements in this arrangement [6].
It should be noted that this differential scheme is generally applicable only to solidly grounded systems, as differential currents (IN) measured by the relay for ground faults depend on the ratios of phase and neutral CTs. For proper current summation, the ratios, class, and manufacturer of all CTs in Figure 9 must match. On resistance-grounded systems, the neutral is connected to earth ground via an impedance, limiting let-through primary current to typically 5–20 A. The CT ratio (CTR) on the neutral of a resistance-grounded system is much lower than the phase CTR, rendering the method in Figure 9 ineffective. For impedance-grounded systems, an alternative scheme that digitally sums all phase and neutral primary currents must be employed, which is not in the scope of this paper.
Figure 2 Description: A simplified schematic showing a single source connected to a load. A current transformer (CT) is placed around the phase conductor. The diagram indicates that summing the phase currents (Ig) can detect a ground fault.
Figure 3 Description: A schematic of a four-wire system with a load connected between a phase and the neutral. It shows a relay measuring phase currents and a neutral current. The text explains that the neutral current can include both load and fault current, complicating detection.
Figure 4 Description: A schematic illustrating a differential current scheme for ground fault detection. It shows current transformers (CTs) on each phase and the neutral conductor. The ground current (Ig) is represented as the difference between the sum of phase currents and the neutral current, aiming to isolate fault current from load current.
Figure 5 Description: A diagram representing a Nonseparately Derived System (NSDS). It shows a service entrance, an Automatic Transfer Switch (ATS), a load, and a generator, all connected via a common neutral bus. It highlights the direct electrical connection between the service and generator neutrals.
Figure 6 Description: A diagram illustrating fault current paths in a multigrounded system with a three-pole ATS. It shows a ground fault where current splits between the neutral conductor and the Equipment Grounding Conductor (EGC), potentially desensitizing ground fault detection.
Figure 7 Description: A diagram representing a Separately Derived System (SDS). It shows a service entrance, an ATS, a load, and a generator. Crucially, it depicts a four-pole ATS where the neutral is switched, and a separate grounding electrode conductor and grounding electrode for the generator, disconnecting the generator neutral from the service neutral during operation.
Figure 8 Description: A schematic of a Modified Differential Ground Fault (MDGF) scheme for multiple sources. It shows multiple current transformers (CTs) on phase and neutral conductors, feeding into a relay that sums these currents to detect ground faults, canceling out normal load currents.
Figure 9 Description: A schematic illustrating a complete solution for a protection system using a Programmable Protective Relay (PPR) with multiple current inputs. It shows CTs on phase and neutral conductors feeding into the PPR, which performs both traditional protection and differential ground fault detection.
III. SERVICE ENTRANCE EXAMPLE
The solution of Figure 9 has been employed at several facilities. The following example presents a dual-fed indoor service entrance, as shown in Figure 1. The service entrance is rated for 2,500 A, 277/480 V, with a 600-kW backup diesel generator. Figure 10 shows two protection relays, one for each service (utility and generator).
Figure 10 illustrates the single line of the dual-fed service entrance shown in Figure 1. In this configuration, the MDGF units sum currents similarly to Figure 8. The summed current is routed through the LSIG breaker's external Ig sensor terminals, allowing the breaker's trip unit to monitor ground fault current magnitude and trip when settings are exceeded, similar to the PPR in Figure 8.
The advantage of using a PPR (as illustrated in Figure 9) and eliminating the MDGF hardware and associated CTs results in a simplified protection system that can accomplish phase, neutral, and ground current protection, along with many other protection elements available in modern digital relays. The logic programming capability of a PPR allows it to detect power supply interruptions, properly sequence breakers for load transfer, and ensure bus synchronism during make-before-break automatic transfer schemes. Additionally, the PPR offers oscillography, Sequence of Events (SOE) recording, and various communications protocols.
This simple yet effective solution provides a robust relay-based automatic transfer scheme and serves as a significant building block for microgrids, enabling seamless transfer between utility and generator power or interconnection of multiple microgrids.
Figure 10 Description: A single-line diagram of a dual-fed service entrance. It shows a utility section and a generator section, each with a Modified Differential Ground Fault (MDGF) unit and a circuit breaker (3P LSIG). The MDGF units sum currents and feed into the breaker's external Ig sensor terminals for ground fault detection.
IV. RENEWABLE POWER PLANT EXAMPLE
A. Background
Distribution substations with DER generation have been proposed [7]. Photovoltaic (PV) generation and a controllable battery energy storage system (BESS) linked to a distribution substation can offer benefits like resilience and peak load shaving.
Figure 11 illustrates this concept. The distribution substation is traditionally connected to the Bulk Electric Power System (BEPS) via a Point of Common Coupling (PCC) breaker. However, PV and BESS generation can be dispatched according to the distribution system's needs.
The substation transformer is central to the substation, defining the High Voltage (HV) side (possibly transmission or subtransmission voltage levels) and the Medium Voltage (MV) side, transforming voltage to standard distribution levels (2.4–35 kV).
In North America, the MV side of the substation transformer is solidly grounded, and the system is four-wire. The four-wire feeders include three-phase conductors and a neutral conductor. The neutral conductor is often grounded periodically along the feeder (multigrounded distribution network) [8]. Distribution utilities typically use three-pole reclosers at key feeder locations. The grounded nature of the system allows significant ground fault current, enabling coordination with inverse-time overcurrent relays (51P/51G) when the utility is connected.
The HV side of the substation relies heavily on the BEPS, which is typically a solidly grounded source in North America. The BESS and PV are connected to the HV side via ungrounded transformers.
If the PCC breaker opens while BESS and PV sources are online, the HV side of the substation becomes an unexpectedly ungrounded system. As explained in [9], a ground fault in the ungrounded part of the substation (HV) can impose high voltages on healthy phases. To prevent this, a grounding transformer is provided, as shown in Figure 11.
The grounding transformer in the HV bus is a permanent connection and the sole grounding source in the substation. The BESS and PV transformer grounds are not connected. The grounding transformer's ground impedance is selected to be larger than the BEPS impedance. The ground impedance is generally chosen to: 1) minimize overvoltages, 2) allow measurable ground fault current for a relay connected to its neutral, and 3) be large enough to shunt ground currents to the BEPS if the system is grid-connected. Specifics on grounding transformer size and type are beyond the scope of this document.
B. Detecting Ground Faults
When connected to the BEPS, with the PCC breaker closed, the ground fault contribution from the BEPS is significant, allowing traditional inverse-time overcurrent (51) schemes to operate as expected.
When islanded, the BESS three-wire design is configured in grid forming with droop (GFMD) and provides positive- and negative-sequence quantities for ground faults. The PV is a three-wire inverter, configured as grid-following, providing only positive-sequence current. The grounding transformer provides the zero-sequence path, allowing ground faults on the HV side to be detected at the grounding transformer neutral [7].
Ground fault detection on the MV side is aided by the solidly grounded neutral of the station transformer. When the PCC breaker is closed, the ground fault current in the feeders is relatively high, limited by the BEPS source impedance and the substation transformer, allowing for traditional inverse-overcurrent (51P/51G) coordination. When islanded, only inverter-based resource (IBR) generation is available, and fault magnitudes are limited to 1.2–1.3 pu of the BESS inverter rating. The PV provides no current during a fault and likely trips offline.
When islanded, a more sensitive scheme than 51P/51G coordination is required due to these low fault currents. In [7], an undervoltage controlled definite time overcurrent (50C) scheme is described, which qualifies the overcurrent element with the presence of low voltage. This works well, as the BESS reduces voltage to limit current during overload conditions like faults. During a fault, the BESS IBR acts as a current source when the PCC is closed and a voltage source when the PCC is open. Faults at every recloser are similar during BESS islanded operation. Thus, during an islanded condition, there is no time-overcurrent (51) relationship, only a 50 current element with 27 voltage supervision. Coordination is achieved using different time delay settings at each recloser. A coordination time interval of 0.2 seconds is selected between subsequent series reclosers. Figure 12 illustrates the distribution feeder.
Figure 11 Description: A diagram of an Inverter-Based Power Plant Connected to a Radial Distribution System. It shows the Bulk Electric Power System (BEPS) connected via a Point of Common Coupling (PCC) breaker to a substation's High Voltage (HV) bus. The HV bus connects to a grounding transformer and then to a Medium Voltage (MV) bus. The MV bus feeds distribution feeders, loads, a Battery Energy Storage System (BESS), and a Photovoltaic (PV) system.
Figure 12 Description: A schematic illustrating time coordination for an Inverter-Based Generation (IBG)-Only Distribution Feeder using an undervoltage controlled definite time overcurrent (50C) scheme. It shows multiple reclosers with time delays (t1, t2, t3) and the 50C element triggered by fault current (Ipu) and low voltage.
V. TRANSPORTABLE MICROGRID EXAMPLE
A. Background
Transportable/mobile/portable microgrids are collections of power sources intended for plug-and-play use. They can provide power where needed by quickly moving and interconnecting to deliver power. Common uses include military forward operating bases, remote oil and gas drilling locations, mining, and disaster relief.
Transportable microgrids can be viewed as emergency power sources requiring ground fault indication. Some designs use high-impedance grounding, which detects and alarms but does not trip when a phase conductor becomes grounded.
Regardless of philosophy, all possible DER formations should have a ground reference for detecting and preventing transient overvoltage that could damage equipment, as discussed in Section 1.3 of [10]. With portable equipment, one or more DERs (battery-backed IBR, utility, or generators) may be connected at any time.
B. Detection and Protection
Equipment protection for transportable microgrids draws from the principles discussed in this paper. Detection and protection depend on whether the microgrid is connected as an SDS or NSDS.
There are two options for installing transportable microgrids. One is to treat it as an NSDS, requiring the interconnection system to use a three-pole ATS with a single point of neutral grounding at the utility transformer. The protection system for this configuration can use neutral CTs to detect fault current returning to each source. In the case of a switched neutral system, such as a four-pole ATS, it may be useful to treat the transportable microgrid as a single SDS and provide neutral grounding at a single grounding electrode, in addition to the grounding at the utility transformer. For configurations involving parallel operation with the utility, two or more neutral grounding bonding points may be required, necessitating an MDGF scheme for proper detection.
The transportable microgrid can be on a trailer, in a container, or placed on the ground adjacent to a building. Equipment grounding is provided through a grounding electrode at these locations. However, users must be careful not to create paths for fault current from other locations to travel through building equipment. Given that the configuration of use for a transportable microgrid may not be known, it should be designed to fit into any system and provide adequate protection.
C. Example
In this project, the end user required a containerized transportable microgrid to provide portable power to critical fixed plant loads. The microgrid consists of a synchronous condenser (SC), two BESS IBRs, an electric vehicle charging station, and an auxiliary 120/208 V lighting panel. The transportable microgrid and its interconnection to the end user's fixed plant electrical distribution are illustrated as a simplified single-line diagram in Figure 13.
The SC is a 3,600-RPM design with shaft-mounted weights providing kinetic energy storage for the grid. This increases fault currents, improves protection coordination, and keeps adjacent inverters online as frequency is stabilized due to kinetic ride-through (inertia).
The transportable microgrid interfaces with an existing fixed plant electrical system comprising a PCC fed by the utility power transformer, a diesel backup generator, and a PV DER system. A three-pole circuit breaker ATS switches the diesel generator and the PCC. For economic and space reasons, the breakers are three-pole, and all systems use four-wire cables laid directly on the ground. In this project, the transportable microgrid is installed as an NSDS into the existing system, maintaining the system ground at a single point at the utility transformer. Proper EGC grounding is performed via a ground bus in both the main and containerized transportable microgrid switchgear for equipment grounding. Care is taken to ensure no break in neutral or ground connections occurs, as any break of the neutral conductor results in an ungrounded system. Ground fault protection is provided by residually connected phase CTs and measured by the PPR (IN) current input.
Figure 13 Description: A simplified single-line diagram of a containerized transportable microgrid. It shows the interconnection to an existing system (utility, diesel generator, PV) via a main switchgear. The transportable microgrid itself includes a synchronous condenser (SC), two BESS units, an EV charging station, and lighting panel, all connected to a neutral bus and protected by Programmable Protective Relays (PPRs). It details the grounding and protection schemes.
VI. CHECKLIST
When designing any ground fault detection system, the following items should be verified in the design:
- All possible island formations are determined, either by a PCC, ATS, or other means.
- One or more grounds exist on each island.
- The differential ground fault system is in place for multiple-point grounded systems, if paralleling distributed energy sources and/or BEPS.
- All ground faults at all locations can be detected and discriminated from single-phase loads.
- Adequate compliance and testing to NEC and other regulatory codes are applicable.
- The inverter acts as a 1.0 pu current source for coordinating IBRs.
- An SC is considered in the design to aid fault current production, as well as inrush and motor starting support.
- A multifunction relay with SOE and oscillography recording capabilities is used to augment the circuit breaker between grid-connected and islanded operation to maintain coordination at these locations.
- A protection expert is consulted if uncertain.
VII. CONCLUSION
DER proliferation and interest in transportable microgrids are increasing. Understanding the differences between system and equipment grounding, and their respective purposes, is crucial for designing protection systems.
A relay-based ground fault detection and protection system was presented for several examples involving multiple sources with multiple grounds. The relay-based solution offers design simplicity and additional features from programmable logic in PPRs, such as bus synchronism checks for make-before-break switching, utility interruption detection, and benefits like oscillography, SOE, and various communications protocols.
This paper provided case studies and detailed the design process and methodology behind the selection of protection and detection methods for ground faults.
VIII. REFERENCES
- NFPA 70, National Electric Code (NEC).
- IEEE 3003.1.2019, IEEE Recommended Practice for Grounding of Industrial and Commercial Power Systems.
- P. Mike, “Avoiding Ground Fault Problems When Designing For Multiple Low Voltage Sources,” GE ESL Magazine, 2005.
- Schneider Electric, “Ground-Fault Systems for Circuit Breakers Equipped with Micrologic Electronic Trip Units,” March 2016. Available: download.schneider-electric.com.
- D. Swindler and C. Fredericks, "Modified Differential Ground Fault Protection For Systems Having Multiple Sources And Grounds," Schneider Electric, 1994.
- SEL-700GT Generator and Intertie Protection Relay Instruction Manual, Schweitzer Engineering Laboratories, 2021.
- R. Ruppert, R Schlake, S. Manson, F. Calero, and A. Kokkinis, “Inverter-Based Radial Distribution System and Associated Protective Relaying," proceedings of the 48th Annual Western Protective Relaying Conference, Spokane, WA, October 2021.
- J. Roberts, H. Altuve, and D. Hou, “Review of Ground Fault Protection Methods for Grounded, Ungrounded, and Compensated Distribution Systems,” proceedings of the 28th Annual Western Protective Relaying Conference, Pullman, WA, October 2001.
- K. Behrendt, "Protection for Unexpected Delta Sources," proceedings of the 57th Annual Georgia Tech Protective Relaying Conference, Atlanta, GA, May 2003.
- IEEE 2030.9-2019, IEEE Recommended Practice for the Planning and Design of the Microgrid.
IX. VITAE
Dirk Danninger received his MS and BS in engineering and systems control from Montana Technological University. He worked for over 24 years in the mining industry, where he held the positions of process engineer, electrical engineer, automation group manager, and electrical instrumentation and control engineering (EI&C) subject matter expert. Dirk can be reached at dirk_danninger@selinc.com.
Scott Manson received his MSEE from the University of Wisconsin-Madison and his BSEE from Washington State University. Scott is the engineering services technology director at Schweitzer Engineering Laboratories, Inc. (SEL). He is a registered professional engineer in 6 states and holds 20 patents. Scott can be reached at scott_manson@selinc.com.
Fernando Calero is a principal engineer at Schweitzer Engineering Laboratories, Inc. (SEL) in the research and development (R&D) division with over 30 years in the industry. For 20 years, he was an application engineer in the SEL international organization. In 2020, he transferred to R&D and is currently working on projects related to renewable sources, protection, and control. He is a registered professional engineer in the state of Florida.
Ceeman B. Vellaithurai (S'09–M'12–SM'20) received the BE degree in electrical and electronics engineering from Anna University Tiruchirappalli, Tiruchirappalli, India, in 2011 and the MS degree in electrical engineering with specialization in power systems from Washington State University, Pullman, WA, USA, in 2013. He is currently working with Schweitzer Engineering Laboratories, Inc. (SEL), Pullman, as a protection engineer and pursuing his PhD from WSU. His research interests include real-time modeling and simulation of cyber-power systems. Ceeman has authored several technical papers with over 600 citations, patents, and is a registered professional engineer. Ceeman can be reached at ceeman_vellaithurai@selinc.com.
