Attachment_13_-_Engineering_Technical_Letter_(ETL)_14-6_Use_of_DER_IAW_IEEE_1547_Reqts_(Draft).pdf

DEPARTMENT OF THE AIR FORCE

AIR FORCE CIVIL ENGINEER CENTER

TYNDALL AIR FORCE BASE FLORIDA

XX XXX 2014

FROM: AFCEC/DD

139 Barnes Drive Suite 1 Tyndall AFB FL 32403-5319

SUBJECT: Engineering Technical Letter (ETL) 14-6: Use of Distributed Energy

Resources (DER) in Accordance with IEEE 1547 Requirements

1. Purpose.

1.1. This ETL provides criteria for the use and connection of all distributed energy resources (DER or DR), including generators, energy storage, renewable energy sources, and microgrids in accordance with IEEE Standard 1547-2003, Standard for Interconnecting Distributed Resources with Electric Power Systems.

1.2. DRs include, but are not limited to, motor generator systems (portable and in-place, fueled by diesel, natural gas, jet fuel, and biomass and multi-fuel combinations). Energy storage includes, but is not limited to, batteries (all types), flywheels, and pumped water. Renewables include, but are not limited to, photovoltaic, wind, water, and biomass systems. A microgrid is a localized grouping of electrical power generation, energy storage, and loads that can operate independent of a traditional grid (islanding mode) and also operate connected to a traditional centralized grid (normal operating mode).

1.3. Criteria supplemented or clarified by this ETL include: A-Gram 11-03, Electrical System Microgrid Definitions; A-Gram 13-02, Air Force-Wide Characterization of Unauthorized Industrial Control Interconnections; ETL 11-1, Civil Engineer Industrial Control System Information Assurance Compliance; Air Force instruction (AFI) 32- 1063, Electric Power Systems; and ETL 13-4, Emergency and Standby Generator Design, Maintenance, and Testing Criteria.

2. Application. Requirements in this ETL are mandatory and apply to all Air Force installations, including Air Force Reserve Command (AFRC) and Air National Guard (ANG) units, and joint bases when connecting and utilizing DRs, energy storage systems, or renewables to the base electrical power system. Contractor personnel responsible for installation, inspection, maintenance, or testing of Air Force DR, energy storage, or renewable energy sources shall comply with this ETL. This ETL is intended to provide discussion, summarization, and clarification of IEEE 1547-2003 for Air Force applications; however, some situations are not addressed in these IEEE standards. This ETL provides additional details regarding Air Force interconnected distributed energy resources and standalone microgrid applications. Additional requirements may be negotiated with the serving utility in the form of an interconnection agreement.

APPROVED FOR PUBLIC RELEASE: DISTRIBUTION UNLIMITED

DRAFT

2.1. Authority: Air Force policy directive (AFPD) 32-10, Air Force Installations and Facilities

2.2. Effective Date: Immediately

2.3. Intended Users:

• Base electrical engineers

• Base energy managers

• Major command (MAJCOM) electrical engineers

• MAJCOM energy staff (A7E)

2.4. Coordination:

• MAJCOM civil engineers (A7)

• AFCEC Facility Engineering Directorate, Technical Services (AFCEC/CFT)

• AFCEC Energy Directorate (AFCEC/CN)

• The Civil Engineer, Operations Division (AF/A7CO)

2.5. Existing Waivers. All existing waivers remain effective until one of the following occurs, at which time this ETL’s requirements are mandatory:

• System-wide or individual existing system upgrades are required

• Installation of new systems to support both new or existing Air Force facilities and infrastructure

3. Acronyms and Glossary: See Attachment 1, Acronyms and Glossary

4. References: See Attachment 2, References

5. Scope of DR Applications.

5.1. This ETL provides requirements (based on facility load type) for the use of all energy systems or sources connected in parallel with an installation’s electrical distribution system, creating a point of common coupling (PCC) with the area electric power station (EPS).

5.2. Mission-Essential Loads.

5.2.1. In general, mission-essential loads shall be excluded from operation with renewable energy sources and microgrids. Mission-essential facility DR (i.e., standby/emergency generators) shall not be included in microgrid applications.

Closed transition transfers of facility standby generators shall not be considered an interconnected energy resource. Each mission-essential standby generator shall operate independent of the utility or microgrid in accordance with ETL 13-4.

Renewable energy resources shall not be connected to the facility’s mission-essential backup power system. Mission-essential facilities include all Tier 1 critical assets (disruption causes mission failure) and all Tier 2 critical assets (disruption causes mission degradation). Figure 1 shows the proper switching configuration between a base grid or microgrid, with or without DRs and renewable energy resources, the mission-essential backup power system (i.e., standby/emergency generator), and critical facility load.

5.2.2. Exception (Dedicated Area EPS). If the mission-essential facility has its own dedicated area EPS, such as a prime power plant or combined heat and power (CHP) plant, then DRs may be connected and must comply with paragraph 5.4. Typical examples would be deployed bases, where the base generates their own primary power, or power systems used in remote areas. In these cases the area EPS is the same as the dedicated power for the base’s grid and DRs may be connected.

Figure 1. Switching Configuration

5.3. Non-Mission-Essential Loads. DRs, energy storage, and renewable energy sources may be approved for parallel operation with the utility provider, or for use in a local EPS (i.e. islanded/microgrid configuration), or on Air Force installations with a dedicated area EPS (see paragraph 5.2.2).

5.4. Interconnection and Interoperability Requirements. In general, IEEE 1547-2003 is the Air Force standard for technical requirements, including interconnection equipment certification and commissioning. Additional DR application requirements are outlined below for use at either the facility or installation levels.

5.4.1. Application #1 (DR Connected to/Operated in Parallel with Area or Local EPS at 600 Volts or Below [Low-Voltage Distribution]). DRs commonly operate below 600 volts [V], with minimal capacity to back-feed the utility system, at the PCC. A utility interconnection agreement may not be required based on loading, aggregate installation generation capacity, and location of DRs. Inverter or relay-based protection must be installed to isolate DRs from facility or installation distribution systems during system outages. It must not reclose to the DR until a stable utility source is restored.

5.4.2. Application #2 (DR Connected to/Operated in Parallel with Area or Local EPS between 601 V to 69,000 V [Medium-Voltage Distribution]). A utility

Automatic or Manual Transfer Switch

Emergency Generator

Area EPS (i.e.

Conventional Grid) or

Local EPS (i.e.

Island/Microgrid) with or without DRs or Renewable Energy

Sources

Facility Emergency Panel to Critical Facilities interconnection agreement is required. Supervisory Control and Data Acquisition (SCADA), telemetry and communication-aided protection schemes must be addressed to identify cyber-security vulnerabilities in accordance with ETL 11-1.

DRs are designed for continuous synchronous operation with the utility grid.

Protection schemes must isolate the DR from the installation distribution and EPS during utility outages.

5.4.3. Application #3 (DR Connected to/Operated Independent of any Area EPS [Islanded Microgrid Configuration]). An integrated DR is capable of operating in parallel with the utility grid or in an islanded configuration. The system must provide the total power, voltage, and frequency requirements, and address system stability through DR control and/or demand response. The complexity of control and communication schemes increase with the number of DRs included in the microgrid configuration. SCADA, telemetry, and communication-aided protection schemes must be addressed to identify cybersecurity vulnerabilities in accordance with ETL 11-1. System transition states between grid-connected and islanded modes must be clearly defined in addition to black start procedures for microgrid configurations. Installation microgrids must be configured to support only the installation power system load requirements during utility outages.

6. DR Limitations and Constraints. Area EPS and DRs supplying power to an Air Force installation must carefully balance and control the components of complex power such as real power (kilowatts [kW]), reactive power (kilovolt-amperes reactive [kVAR]), and apparent power (kilovolt-amperes [kVA]). Balance and control ensures that the installation’s electrical distribution system does not waste energy and system voltage and frequency is properly regulated.

6.1. DR Contribution.

6.1.1. As a general rule of thumb, the total amount of installation real power (kW) supplied by variable/intermittent/direct current (DC) DR must be limited to 30% of the installation demand. The power factor (pf) must be greater than or equal to 0.94 (94%) pf, unless the base utility contract allows for a lower pf.

Additionally, each individual DR must provide active surge suppression and must not exceed voltage, frequency, and phase deviations outlined in paragraph 7.

6.1.2. Exception (DR-provided Reactive Power). The 30% limit may be exceeded, if, and only if, the DR’s added contribution includes the ability to supply the reactive power (kVAR) required such that power supplied by the area EPS never falls below 0.94 pf. Reactive power compensation may be provided at the point of connection or PCC with the utility provider. The utility interconnection agreement may require reactive compensation to be owned and operated by the serving utility.

Note: Many DRs may have limited reactive power output capability if they are not using an interface that produces reactive power. A DC to alternating current (AC) inverter (and any other type of interface) that is not specified to provide the reactive power required by the installation load should not be used.

6.2. Microgrid Configuration. When DRs are utilized for microgrid applications, the total real and reactive power must be provided locally regardless of contributions from variable resources. In accordance with paragraph 5.4.3, microgrid models must address dynamic power flows and system stability for both normal and contingency operations and ensure minimal impact to the area EPS upon connection.

7. IEEE 1547-2003 Requirements. IEEE 1547-2003 provides a standard for interconnection of DRs with an EPS. The purpose of the standard is to minimize the impact to EPS operation, reliability, and safety when DRs such as generators and renewable energy technologies are connected to the utility system, also known as the area EPS. For example, a photovoltaic (PV) array operationally tested and connected in parallel with an Air Force installation’s area EPS is considered a DR. IEEE 1547-2003 includes requirements for the performance, operation, testing, safety considerations, and maintenance of DR interconnections to the area EPS. See Attachment 3, “IEEE 1547-2003 Interconnect Evaluation Checklist.” The requirements are intended to be met at the PCC, although the devices may be located throughout an installation’s power system. Electric utilities typically accept the interconnection of a DR based on compliance with IEEE 1547-2003.

7.1. Voltage Regulation.

7.1.1. IEEE 1547.2-2008, IEEE Application Guide for IEEE Standard 1547, IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems, describes voltage regulation as the process and equipment to maintain voltage within acceptable limits. The primary objective of area EPS voltage regulation is to provide each customer or user connected to the area EPS with voltage that conforms to the design limitations of the customer’s end-use equipment. Outlined below are area EPS quality concerns when DR systems are connected and operating.

7.1.1.1. DR power injected into the area EPS often offsets current and reduces voltage drop that may result in equipment operation issues because of the elimination of the existing voltage drop.

7.1.1.2. DR devices that supply reactive power (capacitive) into the power system or absorbs reactive power (inductive) from the power system may also affect the voltage drop on the area EPS. Typically, a DR device that supplies reactive power (capacitive) will reduce voltage drop on the area EPS while a DR device that absorbs reactive power (inductive) will increase voltage drop on the area EPS.

7.1.1.3. The DR must never regulate the feeder voltage level at the PCC as shown in Figure 2, and must operate satisfactorily within the voltage level variation limits required of the utility as specified in ANSI C84.1-2011, Electric Power Systems and Equipment – Voltage Ratings (60 Hertz), Range A (favorable zone) or Range B (tolerable zone), as shown in Figure 3.

Figure 2. DR PCC to Utility

Figure 3. ANSI C84.1-2011 Range A (Favorable) or B (Tolerable) Voltage Limits Note a: The shaded portions of the ranges do not apply to lighting loads.

Note b: The shaded portion of the range does not apply to 120 V to 600 V systems.

7.1.1.4. For islanded microgrid operation, voltage regulation must be maintained with local generation assets. Control, protection, and demand response schemes may be required based on transient/stability results.

7.1.2. In general, and regardless of DR application in paragraph 5, voltage regulation must be maintained under a variety of operating conditions for the DR.

During normal operation the DR must be gradually loaded and unloaded (soft load/unload) to allow adequate time for regulating devices to respond smoothly.

Additionally, and specific to paragraph 5.4.3, microgrid voltage regulation must be maintained with local generation assets. Control, protection, and demand response schemes may be required based on electrical transient/stability study results.

7.2. Grounding and Integration with Utility Grounding.

7.2.1. The DR transformer configuration and grounding arrangement must be compatible with the area EPS to which it is to be connected. Furthermore, the DR grounding system design and its interconnection must be coordinated with the utility provider and shall not cause voltage disturbances or disrupt coordination of distribution system ground fault protection on the area EPS. This requirement is intended to:

• Prevent damaging phase-to-ground voltages that may exist in unintentional islands after the island forms but before it is detected and de-energized by the DR

• Prevent desensitization of the area EPS ground fault detection devices

• Facilitate detection of area EPS faults by the DR

7.2.2. A DR application that does not maintain effective grounding upon islanding can cause severe over-voltages to single-phase loads, resulting in damage. IEEE 1547.2-2008 provides additional discussion on the importance of and methods to address effective grounding. In general, most single-phase inverter-based DRs will not require special grounding. The utility interconnection agreement should address specific requirements for effective grounding.

7.3. Synchronization. IEEE 1547.2-2008 defines synchronization as the act of matching, within allowable limits, the voltage magnitude, phase angle, and frequency of a DR with an area EPS prior to closing the DR paralleling device. To minimize the transients to both the DR and the area EPS, it is important that all three quantities (voltage, phase angle, and frequency) be closely matched across the paralleling device before closing the paralleling device. Therefore, IEEE 1547-2003 requires that the DR shall parallel with the area EPS without causing voltage fluctuation at the PCC greater than ±5% of the prevailing voltage level of the area EPS. In the case of renewable DRs, these sources may be manually paralleled with the installation’s primary distribution system according to established procedures. Automatic synchronization and connection is recommended but redundant relay protection must be provided to ensure the generator cannot have its output breaker closed beyond a certain degree of voltage/frequency phase difference as required by IEEE 1547-2003, paragraph 4.1.3, and IEEE 1547.2-2008, paragraph 8.1.3.

Note: An improper manual synchronization, such as closing a DR output breaker when the DR is 180 degrees out-of-phase with the primary distribution system, can cause DR damage and create fault-like conditions. Because of this, all systems will require electric or mechanical interlocks to prevent manual out-of-synch operation of breakers and protect the source from damage. Redundant utility-grade sync-check relays are required. Proper manual or automatic synchronization will close the generator breaker at the point of synchronization when the generator speed is slightly fast and the voltage is slightly high, allowing the prime mover to pick up the load; otherwise, the DR generator may act as a motor and with proper protection will be tripped offline.

7.4. Interconnection to Distributed Secondary Grid Networks. In some situations, the utility interfaces to a low-voltage network distribution system referred to as a secondary grid network or spot network. Secondary grid networks serve numerous areas from a grid of low-voltage circuits at either 480Y/277V or 208Y/120V.

Secondary spot networks usually serve only a single site, building, or a part of a building. IEEE 1547-2003 requires the following:

• A DR must be incorporated on spot networks, provided the timing of reverse power relays and the tripping of the DR can be coordinated.

• If a DR is installed on a primary feeder that serves a secondary spot network, specialized control schemes are required to ensure the DR is isolated if the primary feeder breaker trips; otherwise, the DR must provide power to the secondary network.

• Parallel operation of a DR is prohibited on spot networks where mission-essential standby generation is also connected.

• All inverters connected to spot or area networks must be effectively grounded on the secondary side.

7.5. Inadvertent Energization of the Utility System. It is essential that inadvertent energization of an area EPS be prevented to avoid injury to personnel during maintenance, testing, or service restoration when the area EPS is de-energized. The protective relays required by IEEE 1547-2003 for parallel operation are intended to disconnect the DR(s) from faulty or isolated lines before delayed reclosing occurs.

Sometimes, especially for larger DR units, the installation interconnection relaying is not adequate or quick enough to ensure DR separation before a utility delayed reclose. An out-of-synchronism reclose may result in damage to load or source equipment and, for direct-connected rotating generation units, may result in severe damage. In addition to high transient torques, transient voltages (up to three per unit) can be generated. This is seldom an issue for smaller, inverter-based interconnections. Therefore, IEEE 1547-2003 requires the following:

7.5.1. The DR will not transfer power to the area EPS side of the PCC when the area EPS has been de-energized for any reason.

7.5.2. When a microgrid operates in an islanded configuration (see paragraph 5.4.3), power from the DR to the area EPS must not go beyond the PCC when the voltage or frequency of the area EPS is outside acceptable limits. In the case of a system fault, this will allow the area EPS to step through its relaying and reclosing schemes to clear the fault without interference from the DR beyond initial fault-clearing.

7.5.3. After an area EPS power outage, DR reconnection will not occur until the area EPS voltage is maintained within Range B of ANSI C84.1-2011, Table 1 (see Figure 3), and frequency is in the range of 59.3 hertz (Hz) to 60.5 Hz for a stabilization period of up to five minutes.

7.5.4. The protective relays required by IEEE 1547-2003 for parallel generator installations are intended to disconnect the generator(s) from faulty or isolated lines before delayed reclosing occurs. Sometimes, especially for larger units, the installation interconnection relaying is not adequate or quick enough to ensure generator separation before a utility delayed reclose. An out-of-synchronism reclose may result in damage to load or generation equipment and, for direct-connected rotating generation units, may result in severe generation unit damage. In addition to high transient torques, transient voltages (up to three per unit) can be generated. This is seldom an issue for smaller, inverter-based interconnections.

7.5.5. Specific to Air Force installations only, the utility must provide synchronous check supervision on utility reclosing. The hazards and possible remedies for out-of-sync reclosing are discussed in detail in IEEE 1547.2-2008.

7.6. Monitoring and Control Provisions.

7.6.1. IEEE 1547.3-2007, IEEE Guide for Monitoring, Information Exchange, and Control of Distributed Resources Interconnected with Electric Power Systems, provides guidelines for monitoring (information exchange) and control of DRs interconnected with an area or local EPS. Specifically, the standard requires that each DR unit of 250 kVA or more or a DR aggregate of 250 kVA or more at a single PCC shall have provisions for monitoring its connection status (e.g., real power output [kW], reactive power output [kVAR], and voltage [V]) at the point of DR connection, usually the PCC. The “provisions for monitoring” may be local or geographically distributed across the Air Force installation. Monitored information may be available in near real-time or electronically stored data with periodic read-out as appropriate for the application. Examples of typical monitoring include, but are not limited to:

• Connection status

• Real power

• Reactive power

• Voltage

• Current flow

• Power factor

• Frequency

• Alarms (if applicable)

7.6.2. Information Security. The security of individual DR units, and possibly the whole area EPS, could be threatened by inadvertent actions, malfunctions, or deliberate manipulations of the monitoring and control system. Specific to Air Force installations only, where a DR’s monitoring and control system is part of or interfaces with the critical infrastructure of an interconnected area EPS, appropriate security measures must be addressed in system design and operation in accordance with ETL 11-1. Incorporating security requirements early in the design of a DR monitoring and control system will not only improve the security posture of the delivered system but will also help mitigate/eliminate interoperability issues across multiple vendor computer hardware/software products. Under ETL 11-1, a series of table-top risk analyses and on-site risk assessments are conducted throughout the design and development process of the DR monitoring and control system in order to verify and validate that the appropriate level of security measures are in place to mitigate vulnerabilities to an acceptable level of risk that the Air Force Civil Engineering (CE) Industrial

Control Systems (ICS) Platform Information Technology (PIT) Designated Accrediting Authority (DAA) is willing to accept in order to issue an Approval to Operate (ATO).

7.7. Isolation Device. When required by the area EPS operating procedures and practices, IEEE 1547-2003 requires the following:

7.7.1. A readily accessible, lockable, visible-break isolation device located between the area EPS and the DR unit. IEEE 1547.2-2008 states that the isolation device is not required to be a paralleling or interrupting device; however, it needs to be able to provide sufficient isolation such that if the area EPS or the DR unit is powered after the isolation device is activated then the isolation device will not constitute an unsafe condition.

7.7.2. Compliance with the requirements of Title 29 Code of Federal Regulations Section 1910.269 (29 CFR 1910.269), Electric Power Generation, Transmission, and Distribution, for de-energizing lines and equipment for employee protection, which states:

All switches, disconnectors, jumpers, taps, and other means through which known sources of electric energy may be supplied to the particular lines and equipment to be deenergized shall be opened. Such means shall be rendered inoperable, unless its design does not so permit, and tagged to indicate that employees are at work.

7.7.3. Specific to Air Force installations only, in accordance with paragraph 5.4.2, all medium-voltage DR isolation devices must have a visible isolation switch in series with a high-speed stored energy interrupting device to pick up load and interrupt available fault current.

7.8. Interconnect Integrity. Interconnect integrity refers to DR interconnect equipment protection from electromagnetic interference (EMI), surge withstand performance, and paralleling devices’ ability to withstand voltage spikes. The purpose of this requirement is to ensure the DR interconnection system is essentially held to the same standard of performance as generators, protective relaying, and other electrical equipment so that a malfunction or unpredictable operation does not occur when subject to EMI sources (e.g., radios, solar flares), voltage and current surges, and system over-voltages. IEEE 1547-2003 requires the following:

7.8.1. For EMI integrity, the interconnection relays, programmable logic controllers, and computers must be designed and constructed to withstand EMI environments in accordance with IEEE C37.90.2-2004, IEEE Standard for Withstand Capability of Relay Systems to Radiated Electromagnetic Interference from Transceivers, to ensure the influence of EMI does not result in uncontrolled operation of the interconnection system.

7.8.2. The DR interconnection system has the capability to withstand voltage and current surges in accordance with the environments defined in IEEE C62.41.2-

2002, IEEE Recommended Practice on Characterization of Surges in Low- Voltage (1000 V and Less) AC Power Circuits, or IEEE C37.90.1-2012, IEEE Standard for Surge Withstand Capability (SWC) Tests for Relays and Relay Systems Associated with Electric Power Apparatus, as applicable. These surge voltages and currents can result from lightning strikes or switching transients.

7.8.3. The DR interconnection device must be capable of withstanding 220% of the connection electrical distribution system-rated voltage at the PCC. This is not a phase-to-ground withstand requirement, however; it is because the voltage on the high-side of the DR unit could be 180 degrees out-of-phase with 100% of the nominal system voltage and operating in a long-term steady-state of 220% nominal voltage across the open paralleling device contacts.

7.9. Response to Utility Abnormal Conditions. Abnormal conditions can occur on the area EPS that require action from a connected DR. The response of the DR ensures the safety of personnel and the avoidance of damage to connected equipment, including the DR.

7.9.1. Utility Faults. IEEE 1547-2003 requires that the DR unit cease to energize the area EPS for faults on the area EPS circuit to which it is connected. This requirement is based on the premise that if an area EPS has detected a fault and de-energizes a circuit, any other source on that circuit needs to also stop energizing it.

Note: This requirement does not imply that the DR responds to faults that are not seen by the area EPS or faults seen on another circuit.

Note: Communication-aided protection schemes, out-of-step, overcurrent, and distance relaying may be required to meet this requirement.

7.9.2. Utility Reclosing Coordination. IEEE 1547-2003 requires that the DR must not energize the area EPS circuit to which it is connected before reclosure action by the area EPS. This prevents the DR source from interfering with a reclosure event and from creating an out-of-synchronization condition during reclosure that may cause damage to equipment or nuisance tripping of protective devices.

7.9.3. Voltage. The sensing of voltage deviations outside a normal range is critical to detecting faults and, possibly, unintentional islands. Many DR units will have difficulty maintaining a voltage within narrowband if they are supplying either a faulted area EPS circuit or a mildly fluctuating load without the stabilizing influence of the area EPS. Consequently, voltage measurement monitoring at the PCC is a criterion to system stability and protection. For induction generators, very high resonant over-voltages can result on an islanded system, which can damage equipment. Because equipment failures related to these over-voltages happen quickly, an over-voltage trip level less than the equipment insulation level should be established with an instantaneous trip. IEEE 1547-2003 requires the following:

7.9.3.1. The protection functions of the DR interconnected system shall detect the effective (root mean square [RMS]) or fundamental frequency value of each phase-to-phase voltage, except where the transformer connecting the local EPS to the area EPS is a grounded wye-wye configuration or single-phase installation then the phase-to-neutral voltage shall be detected.

7.9.3.2. When any voltage is in a range given in Table 1, the DR must cease to energize the area EPS within the clearing time, as indicated.

Table 1. Interconnection System Response to Abnormal Voltages

Voltage Range

(% of base voltagea) Clearing Time(s)b

V < 50 0.16 50 ≤ V < 88 2.00

110 < V < 120 1.00 V ≥ 120 0.16 aBase voltages are the nominal systems voltages stated in ANSI C84.1-2011, Table 1.

bDR ≤ 30 kW, maximum clearing times; DR > 30 kW, default clearing times.

7.9.4. Frequency. IEEE 1547-2003 requires the following:

7.9.4.1. The DR must not energize the area EPS when the system frequency is in a range given in Table 2, within the clearing time as indicated. Clearing time is defined as the time between the start of the abnormal condition and the DR ceasing to energize the area EPS. The purpose of the allowed time delay in this requirement is to ride through short-term disturbances on the area EPS to avoid excessive nuisance tripping of the DR.

Table 2. Interconnection System Response to Abnormal Frequency

DR Size Frequency Range Clearing Time(s)a

≤ 30 kW > 60.5 0.16 < 59.3 0.16 > 60.5 0.16

> 30 kW < (59.8-57.0) (adjustable set point) Adjustable 0.16 to 300

< 57.0 0.16 aDR ≤ 30 kW, maximum clearing times; DR > 30 kW, default clearing times.

7.9.4.2. For DR less than or equal to 30 kW in peak capacity, the frequency set points and clearing times must be either fixed or field adjustable.

7.9.4.3. For DR greater than 30 kW in peak capacity, the frequency set points must be field adjustable. Adjustable under-frequency trip settings must be coordinated with area EPS operations.

7.9.5. Loss of Synchronism (Aurora Vulnerability). See Attachment 3, Item 9. Loss-of-synchronism protection applies when out-of-phase conditions occur with the area EPS and DR unit that affect the electrical and mechanical integrity of the generator and prime mover. Serious damage can result from this condition because a loss-of-synchronism produces large currents and high torque stresses in many parts of the generator-prime mover system. For these reasons, IEEE 1547-2003 requires that out-of-synchronism conditions need to be rapidly detected through protective relaying.

7.9.6. Reconnection to Utility System. IEEE 1547-2003 requires the following:

7.9.6.1. A DR reconnection is permitted once the area EPS voltage is within Range B of ANSI C84.1-2011 (see Figure 2) and frequency range of 59.3 Hz to

60.5 Hz.

7.9.6.2. The DR interconnection system includes an adjustable delay or a fixed delay of five minutes after the area EPS steady-state voltage and frequency are restored to the specified ranges.

Note: This reconnection requirement is intended to delay the reconnection of the DR to the area EPS following an upstream outage.

7.10. Power Quality. There is a concern that DR interconnected systems, especially with solid-state inverter technologies, impact power quality. DC injection, flicker, and harmonics are the key power quality measurement.

7.10.1. DC Injection. IEEE 1547-2003 requires that the DC current injected by a DR unit be less than or equal to 0.5% of the full rated output current at the point of DR connection. This is especially important when using solid-state or transformerless inverters because excessive DC current injection can cause distribution transformer saturation. This can lead to unacceptable harmonics, excessive heating, and poor pf.

7.10.2. Amount of Flicker Induced by DR. Flicker is a power quality issue predominately associated with noticeable changes in light output from incandescent and fluorescent lighting caused by changes in voltage levels. IEEE 1547-2003 requires the following:

7.10.2.1. The DR unit must not create objectionable flicker for other customers on the area EPS. Specific to Air Force installations only, comply with the Computer Business Equipment Manufacturer’s Association (CBEMA) curve detailed in IEEE 446-1995, IEEE Recommended Practice for Emergency and Standby Power Systems for Industrial and Commercial Applications, Section 3.11, for typical computer sensitivity to very short voltage disturbances.

7.10.2.2. The interconnection flicker must be within the requirements of IEEE 519-1992, IEEE Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems.

7.10.3. Harmonics. Harmonic distortion is a power quality issue caused by operating equipment (e.g., inverters and adjustable speed drives) that distorts the sinusoidal waveform. Harmonics are electrical signals at multiple frequencies of the power line frequency that distort the voltage waveform, which may cause overheating of conductors or impact the operation of certain electrical equipment throughout the area EPS. IEEE 1547-2003 requires the following:

7.10.3.1. The harmonic current injection into the area EPS at the PCC must not exceed the values in Table 3 when the DR is serving balanced linear loads.

Table 3. Maximum Harmonic Current Distortion in Percent of Current (I)

Individual Harmonic (h)

Order (Odd Harmonics)b h < 11 11 ≤ h < 17 17 ≤ h < 23 23 ≤ h < 35 35 ≤ h Total

Demand Distortion

Percent (%) 4 2 1.5 0.6 0.3 5.0 I = The greater of the local EPS maximum load current integrated demand (15 minutes or 30 minutes) without the DR unit or the DR unit rated current capacity (transformed to the PCC when a transformer exists between the DR unit and the PCC).

h = Odd harmonics such as 1, 3, 5, 7, 9, 11, 13, 15, 17, 19, and 35. Even harmonics are limited to 25% of the odd harmonic limits shown.

7.10.3.2. The harmonic current injections must be exclusive of any harmonic currents due to harmonic voltage distortion present in the area EPS without the DR connected.

7.11. Islanding on an Air Force Installation.

7.11.1. IEEE 1547-2003 defines islanding as a condition in which a portion of an area EPS is energized solely by one or more local EPSs (e.g., conventional or smart microgrid; see paragraph 9 for more information) through the associated DR unit PCCs while that portion of the area EPS is electrically separated from the rest of the area EPS. For clarification purposes, the local EPS is equivalent to a microgrid.

7.11.2. Unintentional Islanding.

7.11.2.1. For an unintentional islanding condition in which the DR energizes a portion of the Area EPS through the PCC, IEEE 1547-2003 requires the DR interconnection system detect the island condition and stop energizing the Area EPS within two seconds of the formation of an island.

7.11.2.2. Exception (Non-Islanding Characteristics):

• The DR aggregate capacity is less than one-third of the minimum load of the local EPS.

• The DR is certified to pass an applicable non-islanding test.

• The DR installation contains reverse or minimum power flow protection, sensed between the point of DR connection and the PCC, which will disconnect or isolate the DR if power flow from the area EPS to the local EPS reverses or falls below a set threshold.

• The DR contains other non-islanding means, such as:

o Forced frequency or voltage shifting;

o Transfer trip; or o Governor and excitation controls that maintain constant power and constant pf

8. Recommended Protective Relaying.

8.1. For most installations, utility-grade relays are required. Certified interconnection packages are accepted as complying with this criterion. A utility grade relay should include the following:

• Meets or exceeds ANSI/IEEE standards for protective relays (i.e., IEEE C37.90-2005, IEEE Standard for Relays and Relay Systems Associated with Electric Power Apparatus; IEEE C37.90.1-2012; and IEEE C37.90.2-2004)

• Extensive documentation covering application, testing, maintenance, and service

• Positive indication of what caused a trip (targets)

• A means of testing that does not require extensive unwiring (e.g., a draw out case, test blocks, FT-1 switches)

8.2. The interconnection study will determine specific protective requirements.

Typical relays are listed below:

• Over-voltage (59)

• Under-voltage (27)

• Over/under frequency (81O/81U)

• Two zone distance, phase and ground (21) (On short transmission lines current differential relay(s) may be substituted.)

• Ground overcurrent relay (51TN)

• Transformer differential relay (87T)

• Breaker failure initiate from all appropriate protective relays

• Reverse power (32)

• Synchronizing check (25X)

• Speed-matching (15) for induction generators

8.3. The following additional protection functions may be suggested or required, depending upon the size of the generator, nature of interconnection, and coordination requirements with the utility:

• Out-of-step (68)

• Breaker failure relay (50BF)

• Voltage balance (60)

• Phase sequence (47)

• Transfer-trip (TT)

• Directional overcurrent (67)

• Additional surge arresters

8.4. Redundant electronic multifunction relays are recommended for reliability and maintenance. Event report and disturbance monitoring should be included in the protective relay scheme.

9. Microgrid Synopsis. Industry-coined terms like "smart rid" and "microgrid" often focus on using digital technology to save energy, improve reliability, and reduce cost.

For the Air Force there are three definitions of microgrid: conventional, smart, and next generation. Each impacts energy security and our ability to meet critical mission needs differently.

9.1. Conventional Microgrid (CM). CM is an island or "looped"-feed electrical system that can stand alone during power loss and is manually separated from the grid using a simple process. It consists of a group of two or more buildings supplied by one or more (in parallel) portable generators or substations (generators with step-up transformers) in a single location. CMs may incorporate renewable generation sources if interfaced properly per IEEE 1547-2003. CM is the most reliable and secure microgrid solution. CMs are the approved and preferred method at Air Force installations. There can be exceptions to this at Air Force installations that do not connect to a conventional EPS system. Examples would be bases that generate their own power using motor generator sets and/or CHP systems using DRs that do not connect to an area EPS grid.

9.2. Smart Microgrid (SM). SM is a more sophisticated and complicated microgrid.

Portable substations are still in place, but with automatic control for load shedding and sharing excess generation capacity. It can be fully automated to come online when the utility loses power and uses centralized control for generators.

Interconnection with other SMs is possible. An SM can power non-critical (nice-to-have) loads while a CM focuses on mission-critical loads. An SM may or may not incorporate low- or high-energy security risks to renewable sources. SM connections require careful relay protection and frequency/voltage control. Use of SMs to replace mission-critical generators is not allowed except for Air Force systems that produce their own power in isolation from an area EPS. All SMs must be coordinated with and approved by the Air Force Energy Surety Subject Matter Expert (SME).

9.3. Next Generation Microgrid (NGM). NGM is an extremely complex microgrid where excess generation capacity from emergency generators is used to back-feed the base medium-voltage network to supply energy. An NGM might include portable substations. It starts with critical facilities powered by their onsite generators.

Additional microgrids dynamically form once conditions allow without undue risk. The distribution system automatically disconnects from the utility substations and connects across multiple feeders to support an interconnected microgrid. Noncritical loads are automatically shed (either whole or parts of buildings) and the system supports remote automated management of non-critical (nice-to-have) loads during prolonged outages. System control and protection are significantly complex.

Generation sources may operate in parallel with the utility to provide ancillary services (when feasible and approved by the local utility and the Air Force Energy Surety SME. An energy surety microgrid is an example of an NGM. NGMs are not allowed at any Air Force installation except for systems that produce their own power in isolation from an area EPS and future applications where an Air Force base will be using a CHP electrical generation system, which may include several types of DRs.

9.4. Microgrid Implementation Guidance. Energy security portfolios should include CM system designs, which do not require headquarters approval. SMs and NGMs are still in the research and development phases and not approved at Air Force bases unless the system is approved by the Air Force Energy Surety SME. Microgrid design solutions and implementation guidance is readily available from the Air Force Civil Engineer Center at Tyndall AFB, Florida. The Air Force Electrical Distribution SME and Air Force Energy Surety SME routinely solve tough implementation problems while ensuring compliance with Air Force energy and cyber-security directives.

10. Safety. All safety requirements from the following standards and criteria must be met:

• 29 CFR 1910, Occupational Safety and Health Standards

• AFI 91-202, The US Air Force Mishap Prevention Program

• AFI 32-1064, Electrical Safe Practices

• Unified Facilities Criteria (UFC) 3-560-01, Electrical Safety, O&M

10.1. Interlocks. Electrical or mechanical interlocks must be used to prevent unauthorized switching or closure into out-of-sync power sources.

10.2. Remote Operating Panels. Remote operating panels should be considered, where feasible, to mitigate worker exposure to arc flash and switching hazards.

10.3. Infrared (IR) Scan Windows. Use IR scan windows to allow for periodic IR scans without having to open switchgear panels.

11. Point of Contact. The authority having jurisdiction on all matters addressed in this ETL is the Air Force Energy Surety SME in the AFCEC Engineering Division Electrical/Mechanical Branch (AFCEC/COSM). Questions and comments about this ETL are encouraged and should be directed to the Air Force Energy Surety SME, DSN 523-6352, or commercial (850) 283-6352; e-mail: afcec.rbc@tyndall.af.mil, mail:

139 Barnes Drive, Suite 1, Tyndall AFB, FL 32403-5319.

ANTHONY A. HIGDON, Colonel, USAF 4 Atchs Deputy Director 1. Acronyms and Glossary

2. References

3. IEEE Standard 1547-2003 Checklist

4. Distribution List mailto:afcec.rbc@tyndall.af.mil

ACRONYMS AND GLOSSARY

AC - alternating current AFCEC - Air Force Civil Engineer Center AFI - Air Force instruction AFPD - Air Force policy directive ANSI - American National Standards Institute ATO - Authority to Operate black start - ability to bring up a system from zero power CE PIT ICS DAA - Civil Engineering Industrial Control Systems Platform Information

Technology Designated Accrediting Authority CFR - Code of Federal Regulations CHP - combined heat and power CM - conventional microgrid DC - direct current DER - distributed energy resource DOD - Department of Defense DR - distributed resource EMI - electromagnetic interference EPS - electric power system ETL - Engineering Technical Letter Hz - hertz I - amperes IEEE - Institute of Electrical and Electronics Engineers IR - infrared kVA - kilovolt-amperes kVAR - kilovolt-amperes reactive kW - kilowatts MAJCOM - major command ms - millisecond NEC - National Electrical Code NESC - National Electric Safety Code NFPA - National Fire Protection Association NGM - next generation microgrid PCC - point of common coupling pf - power factor RMS - root mean square SCADA - Supervisory Control and Data Acquisition SM - smart microgrid SME - subject matter expert V - volt

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REFERENCES

A2.1. IEEE:

• IEEE 1547-2003 (reaffirmed 2008), IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems

• IEEE 1547.2-2008, IEEE Application Guide for IEEE Standard 1547, IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems

• IEEE 1547.3-2007, IEEE Guide for Monitoring, Information Exchange, and Control of Distributed Resources Interconnected with Electric Power Systems

• IEEE C37.90-2005, IEEE Standard for Relays and Relay Systems Associated with Electric Power Apparatus

• IEEE C37.90.1-2012, IEEE Standard for Surge Withstand Capability (SWC) Tests for Relays and Relay Systems Associated with Electric Power Apparatus

• IEEE C37.90.2-2004, IEEE Standard for Withstand Capability of Relay Systems to Radiated Electromagnetic Interference from Transceivers

• IEEE C62.41.2-2002, IEEE Recommended Practice on Characterization of Surges in Low-Voltage (1000 V and Less) AC Power Circuits

• IEEE/ANSI 446-1987, IEEE Recommended Practice for Emergency and Standby Power Systems for Industrial and Commercial Applications

• IEEE 519, IEEE Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems

A2.2. Air Force:

• AFPD 32-10, Air Force Installations and Facilities, http://www.e-publishing.af.mil/

• AFI 32-1063, Electric Power Systems, http://www.e-publishing.af.mil/

• AFI 32-1064, Electrical Safe Practices, http://www.e-publishing.af.mil/

• AFI 91-202, The US Air Force Mishap Prevention Program, http://www.e-publishing.af.mil/,

• ETL 11-1, Civil Engineer Industrial Control System Information Assurance

Compliance, http://www.wbdg.org/ccb/browse_cat.php?o=33&c=125

• ETL 13-4, Emergency and Standby Generator Design, Maintenance, and Testing

Criteria, http://www.wbdg.org/ccb/browse_cat.php?o=33&c=125

• A-Gram 11-03, Electrical System Microgrid

Definitions, https://www.my.af.mil/USAF/AFP40/d/s6925EC13537D0FB5E0440800 20E329A9/Files/editorial/electrical%20system%20microgrid%20final%20CHARLIE.

pdf

• A-Gram 13-02, Air Force-Wide Characterization of Unauthorized Industrial Control Interconnections, https://www.my.af.mil/gcss-af/USAF/ep/contentView.do?contentType=EDITORIAL&contentId=c2D8EB9D63E F1AADB013F43572C320FFF&programId=t2D8EB9D639C56C14013A9315AB142 386&channelPageId=s2D8EB9D637283B5601377B2CE4030666

A2.4. Joint:

• UFC 3-560-01, Electrical Safety, O&M, http://www.wbdg.org/ccb/browse_cat.php?o=29&c=4

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A2.5. ANSI:

• ANSI C84.1-2011, Electric Power Systems and Equipment – Voltage Ratings (60 Hertz)

A2.6. CFR:

• 29 CFR 1910, Occupational Safety and Health Standards, https://www.osha.gov/pls/oshaweb/owastand.display_standard_group?

p_toc_level=1&p_part_number=1910

• 29 CFR 1910.269, Electric Power Generation, Transmission, and Distribution, https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table =standards&p_id=9868

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IEEE STANDARD 1547-2003 INTERCONNECTION EVALUATION CHECKLIST

This checklist is not intended to be all-inclusive but is a good reference to ensure all aspects of IEEE Standard 1547-2003 are considered.

IEEE 1547-2003 Interconnect Evaluation Checklist

IEEE 1547-2003 Interconnection Evaluation General

Requirement Question Yes No Design Recommendation

1 Voltage Regulation

Does the generator operation cause the service voltage to go out of prescribed limits as specified in ANSI C84.1- 2011, Range A?

Does the generator loading and unloading prevent adequate time for…