National Renewable Energy Laboratory 

Innovation for Our Energy Future 

A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 

Subcontract Report 

NREL/SR-560-38019 

May 2005 

Facility Microgrids 

Z. Ye, R. Walling, N. Miller, P. Du, K. Nelson 

General Electric Global Research Center 

Niskayuna, New York 
National Renewable Energy Laboratory 

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov 

Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy 

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337

Subcontract Report 

NREL/SR-560-38019 

May 2005 

Facility Microgrids 

Z. Ye, R. Walling, N. Miller, P. Du, K. Nelson 

General Electric Global Research Center 

Niskayuna, New York 

NREL Technical Monitor: Ben Kroposki 

Prepared under Subcontract No(s). NAD-1-30605-01 
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iii 

Executive Summary 

Over the past several decades, the North American power grid has evolved into four large 

interconnected networks that are continuously regulated by sophisticated power-flow control 

equipment. These grids are robust to most perturbations, but their vulnerability is evident in 

incidents such as the Aug. 14, 2003, blackout. To avoid such problems, actions must be taken to 

reduce stress and congestion on this overtaxed transmission and distribution system. Incremental 

changes to grid infrastructure will not achieve the reliability needed in a digital society; new 

infrastructures and operational concepts must be explored. 

In the Department of Energy’s vision of the electric power infrastructure, “Grid 2030” [1], 

microgrids (also called minigrids) are one of three technical cornerstones. Microgrids are 

envisioned as local power networks that use distributed energy resources and manage local 

energy supply and demand. Although they would typically operate connected with a national 

bulk power transmission and distribution system, they would have the ability to pull themselves 

off the grid and function in island mode when necessary to increase reliability for the local load. 

Microgrids are receiving a considerable interest from the power industry, partly because their 

business and technical structure shows promise as a means of taking full advantage of distributed 

generation. Concepts for microgrids fall into two categories: 

1. Systems that are intended to always be operated in isolation from a large utility grid 

2. Systems that are normally connected with a larger grid. 

Conceptually, the isolated microgrid is like a scaled-down version of a large-scale utility grid. 

Many of the technical requirements are the same. However, there are distinguishing features 

because of the nonconventional generation contemplated for microgrid applications. These types 

of generation include power electronic interfaces and are sometimes intermittent in nature (for 

example, wind and solar power). To supply reliable, quality power, the microgrid must have 

mechanisms to regulate voltage and frequency in response to changes in customer loads and 

system disturbances. The penetration of distributed generation in an isolated microgrid is, by 

definition, 100%. All power comes from the distributed generation within the microgrid. 

The grid-connected microgrid is integrated with the bulk grid. The penetration of distributed 

generation on a grid-connected microgrid could approach or even exceed 100%. The microgrid is 

designed and operated such that it appears to be a single predictable and orderly load or 

generator to the bulk grid at the point of interconnection. This arrangement provides several 

advantages: 

• DG owners may be able to rate and operate their generation more economically by 

exporting power to (and importing it from) the microgrid. 

• Local customers may be able to have continued service (although possibly at a reduced 

level) when connection with the host utility is lost. 

• The microgrid can be controlled to be an active asset to bulk system reliability (for 

example, by providing spinning reserve or black-start services). 
iv 

• The host utility may be able to depend on the microgrid to serve local customers so 

substation and bulk power infrastructure do not need be rated (or expanded) to meet the 

entire load. 

The business and regulatory environments presently do not favor (or allow) multiparty 

microgrids (those in which power and services are exchanged with third parties over regulated 

power distribution infrastructures). In fact, in many jurisdictions, the interchange of power 

between adjacent properties, even if it does not involve public utility infrastructure, is illegal as a 

violation of the monopoly franchise granted to the utility. 

The result is that individual entities, such as industrial and institutional facilities, represent the 

first generation of microgrids. The entities that turn to distributed generation for their power 

needs are the “first adopters” from which industry understanding and best practice can evolve. 

The explorations of microgrids in this report are focused on these single-business-entity 

microgrids. For clarity, these are called “facility microgrids.” 

This report investigates three key issues associated with facility microgrids: 

• Multiple-distributed generation facility microgrids’ unintentional islanding protection 

• Facility microgrids’ response to bulk grid disturbances 

• Facility microgrids’ intentional islanding. 
v 

Table of Contents 

1 Introduction...........................................................................................................................................1

1.1 Background..................................................................................................................... 1 

1.2 Scope and Objectives...................................................................................................... 2

1.3 Report Outline................................................................................................................. 3

2 Facility Microgrid Unintentional Islanding Protection......................................................................4

2.1 Multiple Inverter-Based Distributed Generation ............................................................ 4 

2.2 Multiple Machine-Based Distributed Generation........................................................... 7 

2.3 Multiple Inverter-Based and Machine-Based Distributed Generation ........................... 9 

2.4 Summary....................................................................................................................... 10

3 Facility Microgrid Fault Event Case Studies....................................................................................12

3.1 Facility Microgrid System Description......................................................................... 12 

3.2 Case Studies.................................................................................................................. 14 

3.3 Observations ................................................................................................................. 17

4 Facility Microgrid Intentional Islanding Case Studies....................................................................18

4.1 Intentional Islanding Needs .......................................................................................... 18 

4.2 Case Studies.................................................................................................................. 19 

4.3 Observations ................................................................................................................. 22

5 Summary .............................................................................................................................................24

5.1 Findings......................................................................................................................... 24 

5.2 Future Work.................................................................................................................. 25

6 References ..........................................................................................................................................26
vi 

List of Figures 

Figure 1. Active voltage scheme for inverter-based distributed generation................................. 4 

Figure 2. Active frequency scheme for inverter-based distributed generation ............................ 5 

Figure 3. Simulation results in PSCAD for a two inverter-based distributed generation 

system ........................................................................................................................... 7 

Figure 4. Schematic of the machine with the anti-islanding compensators ................................. 8 

Figure 5. Simulation results in PSCAD for the interconnection of two machine-based 

distributed generation systems...................................................................................... 9 

Figure 6. Islanded system frequency and voltage with mixed inverter and machine 

distributed generation.................................................................................................. 10 

Figure 7. One-line diagram of the facility microgrid – active and reactive power flows .......... 13 

Figure 8. One-line diagram of the facility microgrid – network impedance.............................. 13 

Figure 9. Microgrid load bus voltage following non-islanding grid disturbance....................... 15 

Figure 10. Active power into microgrid following non-islanding grid disturbance .................... 15 

Figure 11. Microgrid load motor speed following non-islanding grid disturbance ..................... 16 

Figure 12. Microgrid load current following non-islanding grid disturbance.............................. 16 

Figure 13. Microgrid load voltage following grid disturbance and trip to island ........................ 20 

Figure 14. Microgrid main bus voltage following grid disturbance and trip to island................. 20 

Figure 15. Microgrid distributed generation reactive power output following grid 

disturbance and trip to island ...................................................................................... 21 

Figure 16. Microgrid distributed generation active power output following grid disturbance 

and trip to island.......................................................................................................... 21 

Figure 17. Microgrid distributed generation current following grid disturbance and trip to 

island........................................................................................................................... 22
vii 

List of Tables 

Table 1. Case Studies for Inverter-Based Distributed Generators................................................. 6 

Table 2. Case Studies for Machine-Based Distributed Generation ............................................... 8 

 
viii 
1 

1 Introduction 

1.1 Background 

1.1.1 The Definition of Microgrids 

Forming a definition for microgrids has been a difficult and elusive endeavor. Most agree that 

important elements include co-located power generation sources, energy storage elements, and 

end-use loads. However, opinions differ about the aggregated generation capacity that should be 

contained within the power system and whether there should be a single point of common 

coupling with the main grid or multiple coupling points. 

In this report, microgrids are power systems in which generation elements are co-located with 

loads, regardless of the aggregated generation capacity or the grid interconnection. This 

definition covers a large application space that ranges from remote rural electrification and 

residential/community power networks to commercial, industrial, municipal, hospital, campus, 

and military base power grids. The applications also vary. Some are focused on cost of electricity 

(e.g., peak shaving), some are focused on local resource use (e.g., wind, solar, biomass systems), 

and some are focused on energy reliability and security (therefore, sophisticated generation and 

load controls are required). 

1.1.2 Technical Issues 

1.1.2.1 Interconnectivity 

The complexity of the interconnection between a microgrid and the main grid is affected by the 

types of power generation on the microgrid, the number and location of points of interconnection 

with the main grid, and the penetration level of microgrid systems with the main grid. 

1.1.2.1.1 Power Generation Types 

For a microgrid that uses conventional generation, such as natural gas or diesel reciprocating 

engines, system design and engineering is relatively well-understood. However, for many 

emerging microgrids that use alternative energy sources—such as fuel cells, photovoltaics, and 

microturbines—system design and integration with the main grid are a challenging task because 

of a lack of experience with nonconventional generation types. 

1.1.2.1.2 Points of Interconnection 

Most grid-connected microgrids have a single point of interconnection with the bulk grid. The 

interconnection requirements are relatively well-defined for the single interconnection point. 

However, large-scale microgrids and microgrids that seek grid-connected reliability through 

redundancy may require multiple interconnection points. The coordination of control and 

protection becomes more complicated as the number of interconnection points increases. 
2 

The location of the point of interconnection can also have an effect on the design and performance 

of a microgrid. If the microgrid is in a remote area, as is the case with some village and industrial 

plants, the grid can be weak because voltage and frequency regulation are not tight. In these 

situations, transient dynamics in the grid can have a significant effect on system voltage regulation 

and stability. Additional difficulties can arise when microgrids are connected with a secondary grid 

network or a spot network. In these situations, the control and protection algorithms are more 

complicated than those used when connecting with a radial distribution system. 

1.1.2.1.3 Penetration Level 

System events such as lightning strikes, equipment failures, and downed power lines are 

commonplace in the bulk grid. Microgrids are typically expected to respond to these events by 

tripping offline to protect themselves until the grid recovers. However, if the bulk grid is 

populated with a multitude of microgrids and several of these entities are net power exporters to 

the bulk grid, response behavior could be detrimental. Ideally, the bulk grid would expect the 

microgrids to cope with, and help recover from, system events. 

One aspect of this challenging requirement is referred to as low-voltage ride-through capability. 

This capability would not only maintain high availability for the microgrids but also demonstrate 

“good citizenship” with the bulk grid by enhancing resiliency. 

1.1.2.2 Intentional Islanding 

Although grid-connected microgrids can be designed with the capability of isolated operation, 

the transition between grid-parallel and standalone operation can be challenging. In some cases, 

the microgrids will be expected to shut down once the main grid is lost and then start back up to 

continue to supply local loads. The power outage to the local loads could last between seconds 

and minutes, depending on the black-start time of the generation assets within the microgrids. In 

many cases, however, a disruption or transient effect to the loads within the microgrids will not 

be acceptable. For these systems, a seamless transition control is needed. This transition process 

is called intentional islanding. 

To prevent the large voltage and frequency transients that follow the loss of the main grid, the 

intentional islanding control must be capable of maintaining voltage and frequency regulation 

while exhibiting fast transient disturbance rejection qualities. The distributed generation (DG) 

must be able to support transient and temporary currents far in excess of the connected load 

demand because of magnetizing inrush and motor dynamics. Intentional islanding will be one of 

the most significant challenges for making grid-connected microgrids an attractive solution for 

high-reliability customers. 

1.2 Scope and Objectives 

In most applications, multiple DG units are used in a facility microgrid. Similar to a single DG 

unit, the facility microgrid is required to detect unintentional islanding and isolate itself from the 

host utility at the point of common coupling. However, most anti-islanding protection and 

control schemes are developed and tested for a single DG unit isolated from other DG. 
3 

The interactions and effects on the overall detection at the point of common coupling are not 

fully investigated when multiple DG units operate in parallel. One example is the impedance 

detection scheme. This scheme requires a current signal injection, a terminal voltage 

measurement, and then a calculation of the impedance. The islanding can be detected by 

monitoring the impedance changes. When multiple DG units with the same scheme operate in 

parallel, the measured voltage may be diluted and result in no impedance change under islanding 

condition. To avoid this, all DG should be synchronized with their injection signals. However, 

synchronizing the injection signals may be impractical for two reasons: 

1. It discourages a plug-and-play autonomous operation approach because of the 

synchronization link. 

2. Unless the DG units are from the same vendor, the injection signals for will be 

different at particular frequencies or magnitudes, which makes the dilution effect 

more unpredictable. 

Active anti-islanding control is another approach commonly used for DG. The interaction among 

multiple DG units with active anti-islanding control is not fully explored. The first objective of 

this report is to investigate the interaction and effectiveness of anti-islanding protection for 

multiple DG units with proposed General Electric active anti-islanding controls. Cases with 

multiple inverter-based DG units and multiple machine-based DG units are investigated, and 

recommendations for applying the General Electric schemes to multiple DG units are made. 

A facility microgrid is normally connected with the host utility macrogrid, or area electric power 

system (Area EPS). Depending on the design, operation philosophy, and contractual arrangement 

with the host utility, the facility microgrid is most likely to rely on the host grid for a portion of 

its power, with the balance being generated by the DG imbedded in the microgrid. One issue is 

that facility microgrids are subject to host utility disturbances. The response of the facility 

microgrid will, in turn, affect the host utility dynamics. The second objective of this report is to 

explore these dynamics. 

One of the most attractive aspects of facility microgrids is their potential to separate, or island, 

from the grid. In the simplest sense, this provides a higher level of reliability for the facility than 

can be obtained from the grid alone. This extra reliability is often the primary motivation for 

considering individual applications of DG, and it easily expands to the microgrid. To realize 

these benefits, the DG in the microgrid must have, at the least, additional controls. The third 

objective of this report is to investigate the facility microgrid system intentional islanding 

behaviors and control strategies. 

1.3 Report Outline 

The report is organized by the following sections: 

• Facility microgrid unintentional islanding protection with multiple DG units 

• Facility microgrid dynamic response under fault events 

• Facility microgrid intentional islanding dynamics. 
4 

2 Facility Microgrid Unintentional Islanding Protection 

Typically, a facility microgrid has multiple distributed generators. The unintentional islanding 

protection developed for a single DG unit may not work for multiple DG units operating in 

parallel. This section investigates the effectiveness of the active anti-islanding control developed 

for a single DG unit when it is applied to multiple DG units. The combinations of multiple DG 

units include multiple inverter-based DG units, multiple machine-based DG units, and multiple 

inverter- and machine-based DG units. 

2.1 Multiple Inverter-Based Distributed Generation 

Two typical schemes are used for inverter-based DG [2]: the active voltage scheme, shown in 

Figure 1, and the active frequency scheme, shown in Figure 2. These schemes were proposed by 

General Electric. Detailed discussion can be found in an earlier report [2]. 

DQ-PLL

Σ

Idref

Σ Iqref + -

ABC

DQ

ABC

DQ

Ia

Grid

RLC Load

DC

Power

Input

Va

Vb Ib

Vc Ic

ABC

DQ

Vd Vq Id Iq

Inverter

PWM

Control

ω

+ - Current

Regulator

dd

dq

Three-Phase

Inverter

BPF

Gain

Limiter

∆v

∆i

Σ

+

+

da,db,dc

(duty cycle)

Controller Functions

 θ

 θ

 θ

Figure 1. Active voltage scheme for inverter-based distributed generation 
5 

DQ-PLL

Σ

Idref

Σ Iqref + -

ABC

DQ

ABC

DQ

Ia

Grid

RLC Load

DC

Power

Input

Va

Vb Ib

Vc Ic

ABC

DQ

Vd Vq Id Iq

Inverter

PWM

Control

ω

+ - Current

Regulator

dd

dq

Three-Phase

Inverter

BPF

Gain

Limiter

∆i

Σ

+

+

da,db,dc

(duty cycle)

Controller Functions

∆ω

 θ

 θ

 θ

Figure 2. Active frequency scheme for inverter-based distributed generation 

For demonstration and simplification, two inverter-based DG units with the same rating were 

used to illustrate the effect of multiple DG-unit parallel operation. The conclusion drawn from 

the study can be extended to more than two DG units and to units with different ratings. The 

studies were carried out in PSCAD. The overall system includes two inverters with impedance in 

between, RLC load, and a grid with impedance. 

Prior to the islanding, the inverters’ total output is well balanced by the load (i.e., zero power 

exchange with the utility). This constitutes the worst case for islanding detection, although in 

most practical cases, islanding occurs after faults. Seven cases, as defined in Table 1, were 

simulated. 

• Case 1 is the base case. In it, both inverters have no active anti-islanding control enabled. 

Figure 3 shows that the voltage and frequency stay within nominal ranges after islanding. 

• In Case 2, only one DG unit has active anti-islanding control. Figure 3 shows that the 

voltage and frequency are within nominal ranges after islanding. That means the overall 

system, including the DG with anti-islanding control, will fail the unintentional islanding 

detection within the required time. 
6 

• In Case 3, one DG has only the voltage scheme, and the other has only the frequency 

scheme. The detection failed. 

• In Case 4, both DG units have the same voltage scheme, and the unintentional islanding 

can be successfully detected. 

• In Case 5, both DG units have the same frequency scheme, and the unintentional 

islanding can be successfully detected. 

• Cases 6 and 7 are similar to cases 4 and 5, respectively, except there is an impedance 

between the two DG units’ point of common coupling. For cases 1–5, the two DG units 

are directly connected at their terminals without any impedance in between. 

Table 1. Case Studies for Inverter-Based Distributed Generators 

DG1 DG2 

Line Impedance 

Between DG 

Voltage 

Scheme 

Frequency 

Scheme 

Voltage 

Scheme 

Frequency 

Scheme 

Resistance 

(pu) 

Inductance 

(pu) 

 

Case 1 0.0 0.0 

Case 2 Enabled Enabled 0.0 0.0 

Case 3 Enabled Enabled 0.0 0.0 

Case 4 Enabled Enabled 0.0 0.0 

Case 5 Enabled Enabled 0.0 0.0 

Case 6 Enabled Enabled 0.0 0.2 

Case 7 Enabled Enabled 0.0 0.2 

 

The results from the simulations are: 

• When both DG units are equipped with the same anti-islanding control, the unintentional 

islanding can be detected successfully. 

• When multiple DG units with active anti-islanding control operate in parallel, the 

impedance (up to 0.2 pu simulated) between the DG terminals has little effect on the 

schemes. This indicates the geographical separation of the DG units within a microgrid is 

insignificant as far as the active anti-islanding protection is concerned. 

• Even though each scheme works for a single DG unit, the unintentional islanding 

detection may fail when some DG units have no active anti-islanding control or use 

different schemes. This phenomenon can be analyzed and explained with the 

Middlebrook extra element theorem [3]. Detailed analysis is not presented in this report. 

However, the concept is that one DG unit’s active anti-islanding control loop gain can be 

reduced by another DG unit that has no active anti-islanding control. If the loop gain is 

reduced significantly, the anti-islanding control becomes ineffective and the overall 

parallel DG units are not able to detect the islanding. 
7 

0.0 0.5 1.0 1.5 2.0 2.5 3.0

58.0

58.5

59.0

59.5

60.0

60.5

61.0

61.5

62.0

 case1

 case2

 case3

Frequency(Hz)

Time(Seconds)

 

0.0 0.5 1.0 1.5 2.0 2.5 3.0

0

10

20

30

40

50

60

70

 case4

 case5

 case6

 case7

Frequency(Hz)

Time(Seconds)

(a) Frequency (Hz) in response to the islanding at t = 1s 

0.0 0.5 1.0 1.5 2.0 2.5 3.0

0.92

0.96

1.00

1.04

1.08 case1

 case2

 case3

Terminal Voltage(p.u.)

Time(Seconds)

 

0.0 0.5 1.0 1.5 2.0 2.5 3.0

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

 case4

 case5

 case6

 case7

Terminal Voltage(p.u.)

Time(Seconds)

(b) Terminal voltage (pu) in response to the islanding at t = 1s 

Figure 3. Simulation results in PSCAD for a two inverter-based distributed generation system 

2.2 Multiple Machine-Based Distributed Generation 

Figure 4 shows the anti-islanding controls for synchronous machine-based DG. Two schemes 

can be implemented for machine-based DG [4]: an active power scheme, programmed as part of 

the governor control, and a reactive power scheme, programmed as part of the excitation control. 

These schemes were proposed by General Electric in an earlier report [4]. 
8 

+

Grid

Load

Generator

Qe

Σ PI

Q

Calculation

Qref

+

-

LPF

ωr

Σ

Tm

-

+

Prime

Mover

Σ +

Governor

+ Pref

AVR Exciter

Vref

Vt

Σ

G qai (s) Σ LPF

G (s) pai

ω0

+

-

fd

+ e -

+

Vabc

Iabc

Figure 4. Schematic of the machine with the anti-islanding compensators 

Two machine-based DG units were used to illustrate the effect of multiple-machine DG in 

parallel operation. The simulations were carried out in PSCAD. Table 2 shows the simulation 

cases. Figure 5 shows the simulation results. 

Table 2. Case Studies for Machine-Based Distributed Generation 

 DG1 DG2 

Active Power 

Scheme 

Reactive Power 

Scheme 

Active Power 

Scheme 

Reactive Power 

Scheme 

 

Case1 

Case2 Enabled 

Case3 Enabled 

Case 4 Enabled Enabled 

Case 5 Enabled Enabled 

 
9 

0.0 0.5 1.0 1.5 2.0 2.5 3.0

57.5

58.0

58.5

59.0

59.5

60.0

60.5

61.0

61.5

62.0

 case1

 case2

 case3

 case 4

 case 5

Frequency(Hz)

Time(Seconds)

 

0.0 0.5 1.0 1.5 2.0 2.5 3.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

 case1

 case2

 case3

 case 4

 case 5

Voltage(p.u.)

Time(Seconds)

(a) Frequency in response to the islanding (b) Terminal voltage in response to the islanding 

Figure 5. Simulation results in PSCAD for the interconnection 

of two machine-based distributed generation systems 

The results from the simulations are: 

• Similar to the case of inverter-based DG, when both machine-based DG units are 

equipped with the same anti-islanding control, the unintentional islanding can be detected 

successfully (as in cases 4 and 5). 

• Even though each scheme works for a single DG unit, the unintentional islanding 

detection may fail when some DG does not have the same active anti-islanding control 

(as in cases 2 and 3). 

2.3 Multiple Inverter-Based and Machine-Based Distributed Generation 

The mixture of inverter-based DG and machine-based DG presents a design challenge for any 

anti-islanding scheme. With the penetration of distributed resources continuously increasing, this 

situation will become common, and the performance of the anti-islanding protection must be 

tested in this context. 

This mixture condition has not yet been explored extensively. First, the interactions between 

inverter-based DG and machine-based DG in the island are unknown. Second, existing active 

anti-islanding schemes have been developed with the assumption of either machine-based DG or 

inverter-based DG. The schemes for machine-based DG and inverter-based DG are not 

necessarily compatible because of their different mechanisms. 
10 

The distinct feature of active schemes is a positive feedback that breaks down the active or 

reactive power balance to cause voltage or frequency trips. This mechanism must be preserved 

and unaffected when multiple DG units of different types and power ratings operate in parallel. 

Based on this principle, the most effective combination is to have the inverter apply the 

frequency scheme and the machine apply the reactive power scheme. This combination will lead 

to effective islanding detection. 

The other combinations are not as effective, as indicated by simulation studies. Figure 6 shows 

the simulation results with the inverter equipped with the frequency scheme and the machine 

equipped with the reactive power scheme. Once islanded, the frequency and voltage of the 

inverter-machine-load system drift away quickly so the under/over frequency/voltage relay will 

detect the islanding. 

0.0 0.5 1.0 1.5 2.0 2.5 3.0

57

58

59

60

61

62

63

Frequency(Hz)

Time(Seconds)

0.0 0.5 1.0 1.5 2.0 2.5 3.0

0.0

0.4

0.8

1.2

1.6

2.0

Terminal Voltage(p.u.)

Time(seconds)

Figure 6. Islanded system frequency and voltage 

with mixed inverter and machine distributed generation 

2.4 Summary 

This chapter investigated the performance of active anti-islanding schemes when applied to 

multiple DG units. Three combinations of the DG have been studied: multiple inverter-based 

DG, multiple machine-based DG, and a mixture of inverter- and machine-based DG. 

Effective strategies to ensure islanding detection have been identified. These strategies are: 

• If a facility microgrid is composed of only inverter-based DG, the anti-islanding scheme 

applied to each DG should be the same (either the active voltage anti-islanding scheme or 

the active frequency anti-islanding scheme). They therefore can be designed and operated 

independently. No communication link is needed. 

• If only machine-based DG is present in an island, each DG unit should be designed with 

the same anti-islanding scheme (either the active power anti-islanding scheme or the 

reactive power anti-islanding scheme). This way, they can be designed and operated 

independently. 
11 

• If the inverter-based DG is mixed with machine-based DG, each inverter-based DG unit 

should be equipped with the active frequency anti-islanding scheme, and each machinebased DG unit should be equipped with the reactive power anti-islanding scheme. With 

this combination, the DG units can be designed and operated independently. 

Beyond the context of planned microgrid applications, these results raise concerns about the DG 

anti-islanding performance and qualification testing standards specified in Institute of Electrical 

and Electronics Engineers standard 1547 (IEEE 1547) and Underwriters Laboratories standard 

1741 (UL 1741) when multiple DG units are installed on an Area EPS circuit. Both standards 

provide for testing of anti-islanding performance on a single-unit basis. The results imply that, 

unless the anti-islanding protections of the separate DG units are compatible and coordinated, the 

standards do not protect the grid and its customers from potentially damaging and dangerous 

islanding situations. 
12 

3 Facility Microgrid Fault Event Case Studies 

The facility microgrid is normally connected with a host utility (macrogrid, or Area EPS). 

Although it depends on the design, operation philosophy, and contractual arrangement with the 

host utility, the facility microgrid is likely to rely on the host grid for a portion of its power, with 

the balance being generated by the DG in the microgrid. One immediate concern is the potential 

for microgrids to alter the local dynamics of a specific subsystem or distribution feeder. This 

becomes a concern when there is a significant penetration of microgrids relative to the total load 

power on a feeder. 

3.1 Facility Microgrid System Description 

A relatively simple facility with a variety of loads and DG was used to investigate facility 

microgrid dynamic behaviors. A one-line diagram of the system that shows the loads, DG, and 

power flow for the base condition is shown in Figure 7. It includes most basic distribution 

system components expected to be important for investigation of fundamental frequency 

performance issues. 

 

The facility has a main 13.8-kV service bus with multiple laterals that serve individual blocks of 

load. The loads are a variety of motors with different dynamic characteristics. The facility 

connects with a host utility at a point of common coupling at 115 kV. The 115-kV system is 

greatly simplified, with two equivalent lines leading to an equivalent hub node. Two 6 MVA DG 

units are connected with the main facility bus through individual transformers. The model, 

although simple, is suitable for investigating the performance of microgrid applications. 

The line and transformer impedances for the system are shown in Figure 8. In the figure, 

reactances appear below the line and are given on a 100-MVA base. Each bus is labeled with a 

name, node number, the initial voltage in per unit, and the initial voltage in kilovolts. Circles 

with “m” are motors. 
13 

Figure 7. One-line diagram of the facility microgrid – active and reactive power flows 

Figure 8. One-line diagram of the facility microgrid – network impedance 
14 

3.2 Case Studies 

The initial condition for disturbances studied is with some power imported, as shown in Figure 7. 

In this case, about 10% (1.4 MW) of the facility power is imported. 

Figures 9–12 show the response of the facility microgrid to a fault on the host system. The event 

simulated is a fault at the midpoint of one of the two 115-kV lines from the point of 

interconnection to the system equivalent hub. The fault is cleared by removal of the faulted line, 

which leaves the connection of the microgrid with the host system weakened. Each of the four 

figures shows a different system variable for this event. In each figure, five traces show different 

DG technologies and controls. In this chapter and the next chapter, the active anti-islanding 

controls discussed in the previous chapter are not used for the DG. 

For each figure, the five traces correspond to: 

• Dark blue: No DG, only loads are presented in the facility 

• Pink: Inverter-based DG with full controls (voltage and frequency regulation with droop) 

• Red: Machine-based DG with full controls (conventional voltage regulator/excitation and 

frequency regulation/governor, both with droop) 

• Light blue: Inverter-based DG with power dispatch (passive) mode (no voltage and 

frequency regulation) 

• Purple: Machine-based DG with power dispatch (passive) mode (no voltage and 

frequency regulation). 

Figure 9 shows the voltage at the motor loads within the facility, Figure 10 shows the active 

power exchange between the facility microgrid and the host macrogrid, and Figure 11 shows the 

speed of some of the motors in the facility. Figure 12 shows the current drawn by the loads. 
15 

Micro Grid Study Case F1

Bolted 3ph Fault at 50% of PCC-HUB 115kV Line CKT1

Clear Fault after 16 cycles by tripping PCC-HUB Line CKT1

0

0.2

0.4

0.6

0.8

1

1.2

1 2 3 4 5 6 7 8 9 10

Time (s)

MOTLD3-m1 V pu

No DG

INV DG

ROT DG

INV DG Passive

ROT DG Passive

Figure 9. Microgrid load bus voltage following non-islanding grid disturbance 

Micro Grid Study Case F1

Bolted 3ph Fault at 50% of PCC-HUB 115kV Line CKT1

Clear Fault after 16 cycles by tripping PCC-HUB Line CKT1

-20

-15

-10

-5

0

5

10

15

1 2 3 4 5 6 7 8 9 10

Time (s)

Power into Micro Grid M

W

No DG

INV DG

ROT DG

INV DG Passive

ROT DG Passive

Figure 10. Active power into microgrid following non-islanding grid disturbance 
16 

Micro Grid Study Case F1

Bolted 3ph Fault at 50% of PCC-HUB 115kV Line CKT1

Clear Fault after 16 cycles by tripping PCC-HUB Line CKT1

0.6

0.7

0.8

0.9

1

1.1

12345

Time (s)

MOTLD#-m1 Speed pu

No DG

INV DG

ROT DG

INV DG Passive

ROT DG Passive

Figure 11. Microgrid load motor speed following non-islanding grid disturbance 

Micro Grid Study Case F1

Bolted 3ph Fault at 50% of PCC-HUB 115kV Line CKT1

Clear Fault after 16 cycles by tripping PCC-HUB Line CKT1

1

1.5

2

2.5

3

3.5

4

4.5

5

12345

Time (s)

MOTLD3-m1 It pu

No DG

INV DG

ROT DG

INV DG Passive

ROT DG Passive

Figure 12. Microgrid load current following non-islanding grid disturbance 
17 

3.3 Observations 

A number of observations were made from these cases: 

• The behavior of the system is significantly different for each set of assumptions. The 

cases with no DG and with the power dispatch (passive) mode inverter-based DG fail to 

recover from the fault (i.e., the load in the facility is disrupted, and the facility would 

likely trip some or all of its load and DG). The collapse of the motor speed is evidence of 

the failed recovery; the motors have stalled and, in the process, collapsed the voltage. As 

a result of the collapsed voltage, the motors cannot restart and the voltage cannot recover. 

• Failed recovery is disruptive not only to the microgrid load but also to the host grid. This 

is evident in the high currents drawn after the load stalls. This could cause false trips of 

protective relaying and possibly result in outage of other customers on the host grid. The 

addition of controls (voltage and frequency droop regulation mode) for both types of DG 

allows a successful recovery, and all parties benefit. 

• The presence of DG in the microgrid with appropriate controls can be beneficial to both 

the microgrid (DG owner) and grid. (The no-DG case failed.) 

• The machine-based DG with dispatch mode was more benign than the inverter-based DG 

with dispatch mode. This may be because of the inherent mechanical (and magnetic) 

inertia of the machine, which may make recovery naturally easier. Conversely, the best 

performance results were from the inverter-based DG with full control (voltage and 

frequency regulation). (Here, “best performance” is based on fastest recovery to normal 

voltage and speed.) This is not surprising. Inverter-based technologies are more 

controllable and more dependent on good control—different faces of the same nature of 

the equipment. 
18 

4 Facility Microgrid Intentional Islanding Case Studies 

4.1 Intentional Islanding Needs 

One of the most attractive aspects of a facility microgrid is its potential to separate, or island, 

from the grid. Although the microgrid can be designed with the capability of isolated operation, 

the transition between grid-parallel and standalone operation can be challenging. In most 

applications, the microgrid will be expected to shut down when the main grid is lost and then 

start back up to supply local loads. The power outage to the local loads could last between 

seconds and minutes, depending on the black-start time of the generation assets within the 

microgrid. In some cases, however, a disruption or transient effect to the loads within the 

microgrid is not acceptable. For these systems, a seamless transition control is needed. 

This transition process is called intentional islanding. Although islanding allows the microgrid to 

recover, the microgrid will be exposed to voltage deviations caused by grid faults before 

islanding can be accomplished. Therefore, a grid-connected microgrid cannot be viewed as a 

means of disturbance-free performance, but a microgrid can improve power supply availability 

for critical loads. Loads subject to transient voltage disturbances (e.g., data centers) will still 

need an uninterruptible power supply device to ride grid disturbances, but the amount of energy 

storage in the uninterruptible power supply can be reduced if the load is supplied by a microgrid. 

Intentional islanding can be preplanned or unplanned. Unplanned intentional islanding imposes 

greater challenges than preplanned intentional islanding. First, the loss of the main grid must be 

detected. Second, to prevent the large voltage and frequency transients that follow the loss of the 

main grid, the intentional islanding must maintain voltage and frequency regulation while 

exhibiting fast transient disturbance rejection qualities. The islanded system will then impose very 

large transient currents on its generation because of magnetic inrush when the microgrid is isolated 

from the faulted grid. (These highly distorted currents are not simulated in the power frequency 

simulations discussed here but need to be addressed when an actual microgrid is designed.) 

Different levels of power balance (power import/export from the bulk grid) impose different 

challenges for unplanned intentional islanding. The case of closer power balance (minimal power 

import/export) is a worse case for loss of grid detection but a better case for smooth transition 

from grid-connected to island mode. The case of large power imbalance (large power 

import/export at the point of common coupling) is a better case for loss of grid detection but a 

worse case for transition because of large transient. 

The ability of a microgrid to survive loss of connection with the host utility depends on a number 

of factors. The microgrid must have sufficient dynamic regulating capability to tolerate the 

changes in active and reactive power flow that will result from loss of the utility tie. This means 

at least some of the DG must have both voltage and frequency regulation functions. If the 

microgrid imports power from the main grid, once it is islanded, not all of the load within the 

facility can be supplied. In this case, non-essential load (which can be predefined) must be 

disconnected to allow for secure operation of the critical load. The ability to differentiate 

between critical and noncritical load is a major reliability consideration and potential advantage 

for a facility microgrid. 
19 

4.2 Case Studies 

This section examines facility microgrid behavior under islanding events. The events are 

unplanned and followed by system faults that cause loss of the main grid. The facility microgrid 

system is as presented in Chapter 3. 

Figures 13, 14, 15, 16, and 17 show the response of the facility microgrid to faults at the point of 

common coupling that result in a trip of the microgrid from the host system. The events 

simulated are faults at the terminal 115-kV point of common coupling cleared by removal of the 

microgrid main transformer. In one pair of cases, the fault is bolted (i.e., has no fault impedance) 

and more severe than the other pair of cases, in which some fault impedance is assumed. 

Each of the following five figures shows a different system variable for this pair of events. In 

each figure, there are four traces. These traces correspond to: 

• Dark blue: Inverter DG for bolted three-phase fault 

• Pink: Rotating DG for bolted three-phase fault 

• Red: Inverter DG for impedance fault 

• Light blue: Rotating DG for impedance fault. 

Voltage and frequency regulation are a prerequisite for islanded operation. The cases with power 

dispatch mode are not studied in this chapter. Thus, only cases with full control are considered. 

The two fault events are intended to illustrate that having these controls is a necessary condition; 

it may not be sufficient to ensure successful islanding. The dynamics of tripping from grid 

connection to islanded operation can be very important. 

Figure 13 shows the voltage at the motor loads within the facility, and Figure 14 shows the main 

bus voltages with the facility microgrid. Figure 15 shows the reactive power output of one of the 

DG units in the facility, and Figure 16 shows the active power output. Figure 17 shows the 

currents delivered by one of the DG units in the facility. 
20 

Micro Grid Trip to Islands Fault Study Cases

Fault at PCC 115kV with 6 cycles clearing

Trip Micro Grid Transformer to Islands

-0.1

0.1

0.3

0.5

0.7

0.9

1.1

1.3

1 2 3 4 5 6 7 8 9 10

Time (s)

MOTLD3-m1 V pu

IDG Bolted 3PH Fault

RDG Bolted 3PH Fault

IDG Impedance Fault

RDG Impedance Fault

Figure 13. Microgrid load voltage following grid disturbance and trip to island 

Micro Grid Trip to Islands Fault Study Cases

Fault at PCC 115kV with 6 cycles clearing

Trip Micro Grid Transformer to Islands

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1 2 3 4 5 6 7 8 9 10

Time (s)

Microgrid V pu 

IDG Bolted 3PH Fault

RDG Bolted 3PH Fault

IDG Impedance Fault

RDG Impedance Fault

Figure 14. Microgrid main bus voltage following grid disturbance and trip to island 
21 

Micro Grid Trip to Islands Fault Study Cases

Fault at PCC 115kV with 6 cycles clearing

Trip Micro Grid Transformer to Islands

-1

1

3

5

7

9

11

13

1 2 3 4 5 6 7 8 9 10

Time (s)

Q MVA

R

IDG Bolted 3PH Fault

RDG Bolted 3PH Fault

IDG Impedance Fault

RDG Impedance Fault

Figure 15. Microgrid distributed generation reactive power output 

following grid disturbance and trip to island 

Micro Grid Trip to Islands Fault Study Cases

Fault at PCC 115kV with 6 cycles clearing

Trip Micro Grid Transformer to Islands

0

2

4

6

8

10

12

14

1 2 3 4 5 6 7 8 9 10

Time (s)

P pu

IDG Bolted 3PH Fault

RDG Bolted 3PH Fault

IDG Impedance Fault

RDG Impedance Fault

Figure 16. Microgrid distributed generation active power output 

following grid disturbance and trip to island 
22 

Micro Grid Trip to Islands Fault Study Cases

Fault at PCC 115kV with 6 cycles clearing

Trip Micro Grid Transformer to Islands

0

0.5

1

1.5

2

2.5

3

3.5

4

1 2 3 4 5 6 7 8 9 10

Time (s)

I pu

IDG Bolted 3PH Fault

RDG Bolted 3PH Fault

IDG Impedance Fault

RDG Impedance Fault

Figure 17. Microgrid distributed generation current 

following grid disturbance and trip to island 

4.3 Observations 

A number of observations were made from these cases. First, and most important, for this 

particular microgrid, not all of the load within the facility can be served when the microgrid trips 

to islanded operation. In all cases, roughly half of the load in the facility is tripped. Nonessential 

load is disconnected to allow secure operation of the critical load. The ability to differentiate 

between critical and noncritical load is a major reliability consideration and a potential advantage 

for a facility microgrid. In these cases, facility microgrid control disconnects the non-essential 

load after the transformer circuit breaker opens and creates the island. The transient swings of the 

system variables reflect the dynamics of the loads responding to the fault and their interaction 

with the DG controls. 

Second, the microgrid fails to tolerate the dynamics associated with the trip to an island in one 

case: the very severe fault and the machine-based DG. In this case, the motor recovery fails in a 

fashion similar to the failed recovery cases discussed in the previous chapter. In these cases, the 

faster response of the inverter-based DG with aggressive controls allows a better recovery. 

However, this simulation was somewhat idealized; an inverter-based DG might not be able to 

sustain the temporary overcurrents seen in this case unless it is specially rated for this duty. This 

particular comparison illustrates that different responses will have an effect on the success (and 

therefore viability) of the island. 
23 

One might be tempted to conclude from this example that inverter-based DG is superior for 

islanded operation. However, other experience shows that inverter-based DG is generally more 

sensitive to voltage dips that result from faults and is more likely to trip in response to such 

stimulus. Inverters, unless over-designed, have limited overcurrent capability. The thermal timeconstants of solid-state power electronic devices are short compared with the copper windings of a 

rotating generator. Unless these devices are selected so that they normally operate well below their 

maximum allowable temperatures, overcurrents must necessarily be limited by either tripping or 

limitation of output current via control action. Limitation of current output by DG in a recovering 

system, where loads demand more current than DG can supply, will result in voltage collapse. 

For DG to support microgrid islanding: 

• The DG must not trip in response to the initiating disturbance. 

• The load in the island must not exceed the capability of the DG in the islanded microgrid. 

If exceeded, noncritical load-shedding schemes should be incorporated so that the 

islanded microgrid can support critical load. 

• Having enough capability is not sufficient alone. The DG must have the necessary 

dynamic response to survive the disturbances that cause the trip to island and the dynamic 

behavior of the loads following islanding, including inrush currents drawn by 

transformers and motors (which may be highly distorted) and reacceleration of motors 

and their mechanical loads. 
24 

5 Summary 

5.1 Findings 

This report investigated three key issues: 

• Facility microgrid with multiple DG units unintentional islanding protection 

• Facility microgrid response to bulk grid disturbances 

• Facility microgrid intentional islanding. 

One recent advancement in unintentional islanding protection is active anti-islanding controls. 

The active schemes were developed for single DG units, inverter- or machine-based. Previously, 

their performance when applied to multiple DG units was not well understood. The first part of 

the report attempted to gain an in-depth understanding of these new anti-islanding schemes. The 

recommendations are: 

• For a facility microgrid with only inverter-based DG, all DG units should be equipped 

with the same anti-islanding control, either active voltage scheme or active frequency 

scheme, or both schemes should be enabled. 

• For a facility microgrid with only machine-based DG, all DG units should be equipped 

with the same anti-islanding control, either active power scheme or reactive power 

scheme, or both schemes should be enabled. 

• For a facility microgrid with mixed inverter- and machine-based DG, all inverter-based 

DG units should be equipped with active frequency scheme, and all machine-based DG 

units should be equipped with reactive power scheme. 

If the recommendations are not followed, the facility microgrid may risk unintentional islanding 

unless other means or design changes are provided. These results are also relevant to the 

performance of multiple DG units not in a planned microgrid but connected to an Area EPS. 

Despite meeting performance requirements, based on the performance of individual DG units in 

isolation, desired anti-islanding performance may not be realized. This poses a potential risk to 

safety and exposes utility and customer equipment to possibly damaging conditions. 

Obviously, the DG with active anti-islanding control will not allow seamless transition from 

grid-paralleled to islanded operation. In this case, the microgrid has to shut down, disconnect 

from main grid, and then start up as needed to supply local load. For microgrid applications that 

require seamless transition, other means for loss of main grid detection must be explored. 

The report also studied facility microgrid dynamics in response to bulk grid disturbances. The 

major observations are: 

• The dynamic behaviors of the facility microgrid are significantly different for different 

cases. The cases with no DG and with the dispatch mode inverter-based DG fail to 

recover from the fault—i.e., the load in the facility is disrupted, and the facility would 

likely trip some or all of its load and DG. 
25 

• Failed recovery is disruptive not only to the microgrid load but also to the host grid. This 

is evident in the high currents drawn after the load stalls. This could cause false trips of 

protective relaying and possibly result in outage of other customers on the host grid. The 

addition of controls (voltage and frequency droop regulation mode) for both types of DG 

allows a successful recovery, and all parties benefit. 

• The presence of DG in the microgrid with appropriate controls can be beneficial to both 

the microgrid (DG owner) and the grid. (The no-DG case failed.) 

• The machine-based DG with dispatch mode was more benign than the inverter-based DG 

with dispatch mode. This may be because the inherent mechanical (and magnetic) inertia 

of the machine may make recovery naturally friendlier. Conversely, the best performance 

results were from the inverter-based DG with full control (voltage and frequency 

regulation). 

Finally, the report studied facility microgrid intentional islanding behaviors. The major 

observations are: 

• Not all of the load within the facility can be served when the microgrid trips to islanded 

operation. In all cases, roughly half of the load in the facility tripped. Non-essential load 

can be disconnected to allow for secure operation of critical load. The ability to 

differentiate between critical and noncritical load is a major reliability consideration and 

potential advantage for a facility microgrid 

• The microgrid fails to tolerate the dynamics associated with the trip to an island for one 

case: the very severe fault and the machine-based DG. The faster response of the 

inverter-based DG with very aggressive controls and with sufficient overcurrent 

capability allows for a better recovery. 

5.2 Future Work 

Generally, facility microgrids are more technically and economically viable than other microgrid 

applications. One key issue of making facility microgrids more practical and attractive is 

autonomous operation. To have autonomous operation, a facility microgrid should be designed to 

be adaptive to both grid-connected and islanded conditions with minimum load interruption. This 

requires a system-level design optimization that includes system-level controls (autonomous or 

self-reconfigurable), energy storage deployment/optimization to deal with transients and the slow 

response of prime movers, and intelligent load-shedding strategies. 

 

Another issue of critical importance is the problem of incompatible active anti-islanding 

controls, which may not work together to provide necessary performance. This issue extends 

beyond the narrow context of microgrids to include DG applications in general. Current industry 

standards appear to be inadequate to provide critical system protection in the future as DG 

penetration increases and multiple DG units on a feeder become a routine situation. There is an 

urgent need to further study and define this issue and recommend changes to standards to 

achieve the required protection. 
26 

6 References 

[1] Grid 2030: A National Vision for Electricity's Second 100 Years. Department of Energy 

Office of Electric Transmission and Distribution. July 2003. 

(http://www.climatevision.gov/sectors/electricpower/pdfs/electric_vision.pdf) 

[2] Ye, Z.; Walling, R.; Garces, L.; Zhou, R.; Li, L.; Wang, T. Study and Development of AntiIslanding Control for Grid-Connected Inverters. NREL/SR-560-36243. Golden, CO: 

National Renewable Energy Laboratory. May 2004. 

(http://www.nrel.gov/docs/fy04osti/36243.pdf). 

[3] Middlebrook, R.D.; Vorperian, V.; Lindal, J. “The N Extra Element Theorem.” IEEE 

Transactions on Circuits and Systems – I: Fundamental Theory and Applications; Vol. 45, 

No. 9, September 1998; pp. 919–935. 

[4] Ye, Z.; Walling, R.; Miller, N.; Du, P.; Nelson, K. Study and Development of Anti-Islanding 

Control for Synchronous Machine-Based Distributed Generators. NREL/SR-560-38018. 

Golden, CO: National Renewable Energy Laboratory. 
F1147-E(12/2004) 

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Facility Microgrids 

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14. ABSTRACT (Maximum 200 Words)

Microgrids are receiving a considerable interest from the power industry, partly because their business and technical 

structure shows promise as a means of taking full advantage of distributed generation. This report investigates three 

key issues associated with facility microgrids: 

· Multiple-distributed generation facility microgrids’ unintentional islanding protection 

· Facility microgrids’ response to bulk grid disturbances 

· Facility microgrids’ intentional islanding. 

15. SUBJECT TERMS

distributed energy; DE; distributed generation; DG; distributed power; microgrids; minigrids; interconnection; General 

Electric; National Renewable Energy Laboratory; NREL; Distributed Power Systems Integration 

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