Attachment C – Draft text for P1547 revision (June 26-27, 2014 meeting)

The following information provides the draft text submitted and discussed at the P1547 working group meeting. This is for background/informational purposes only. It does not identify final disposition (accept in principle, revise, or reject its use). The respective individual author or discussion leader has recorded the WG feedback for their potential revisions of the draft text/topics.

P1547 Subclause and/or Topic Author, or Onsite Discussion Leader Draft below?3.1 Definitions; Interfaces and interoperability issues; and security issues.

M. Siira Yes

1.3 Limitations (with bearing on some definitions)

D. Forrest (R. Cummings could not attend)

No

4.1.6 Monitoring provisions B. Escott Yes4.2.1 Area EPS faults T. McDermott lead author (could not

attend)Yes

4.2.2 Area EPS reclosing coordination T. McDermott lead author (could not attend)

Yes

VFRT (voltage and frequency ride through) 4.2.3 & 4.2.4

R. Walling Yes

4.2.3 Voltage (VFRT)4.2.4 Frequency (FRT)4.2.6 Reconnection/Reenergization

J. Berdner Yes

4.2.6 Reconnection B. Lydic Yes4.2.6 Reconnection T. McDermott lead author (could not

attend)Yes

5.1 (new text) Interconnection test specifications and requirements5.2 [new] Integration of DER w/EPS {protection}

M. Siira Yes

4.4.1 Unintentional islanding T. McDermott lead author (could not attend)

Yes

New 5.3 Power systems simulations (simulation & modeling)

D. Kurthakoti (David Lovelady could not attend)

Yes

(new) 5.1.7 Short circuit current;(new) 5.1.8 Loss of load behavior

R. Walling (T. McDermott could not attend)

yes

Annex B. R. Walling (T. McDermott could not attend)

Yes

New 5.3 Power systems simulations (simulation & modeling)

D. Kurthakoti (David Lovelady could not attend)

Yes

P1547 WG Meeting 201406 Minutes Annex C pg 1

Definitions; Interoperability Issues; and Security Issues -- M. Siira

Add the following definitions to Clause 3.1

3.1 Definitions

data flow: Application-level communications from a producer of data to a consumer of data.

data link: A physical communication connection (wireless, cabled [including wire and fiber optic], etc.)from a source to a destination.

data volume: The quantity of data to be transferred to accomplish an action.

distributed energy resource (DER): Source of electric power that is not directly connected to a bulkpower transmission system. DERs include both generators and energy storage technologies.

Domain: A major component of the electric power system that has a primary function – these include Generation, Transmission, Distribution, Customer, Markets, Utility Operation and Control, and Service provider

Entities: Logical description of elements of a system domain.

interface: A logical connection from one entity to another that supports one or more data flowsimplemented with one or more data links.

interoperability: The capability of two or more networks, systems, devices, applications, or components toexternally exchange and readily use information securely and effectively.

latency: A measure of time delay experienced in a system, the precise definition of which depends on thesystem and the time being measured.

load: The true or apparent power consumed by power utilization equipment. (IEEE Std C37.100™-1992)

Security; aspects of design that ensure The infrastructure is protected against unauthorized access and interference with normal operation. It consistently implements information privacy and other security policies.

Smart Grid: The integration of power, communications, and information technologies for an improvedelectric power infrastructure serving loads while providing for an ongoing evolution of end-use applications

4.5 Interoperability Principles

Interoperability is the standardization of interfaces within the infrastructure is organized such that

— The system can be easily customized for particular geographical, application-specific,or business circumstances, but

— Customization does not prevent necessary communications between elements of the infrastructure.

— Cybersecurity is an important attribute of any architecture moving forward

Since the formation of the original IEEE 1547-2003, there have been significant advances in developing communications and information technology standards. Additionally, NIST has published a roadmap that presents requirements and a vision for smart grid. A central requirement in smart grid is interoperability. This roadmap present a conceptual model of the Smart Grid along the 7 domains depicted in the following figure:

Smart Grid Conceptual Model

Source: Updated NIST Smart Grid Framework version 3.0; February 2014

This was taken closer to reality in the Development of IEEE 2030-2011 which introduced the Smart grid Interoperability Reference Model (SGIRM). This concept allows each of the domain in the conceptual model to be viewed from three perspectives; Power, Communications and Information technology. IEEE 1547-2003 also implements a three-architectural perspectives’ view in all its components.

One characteristic of interoperability as set in GridWise® Interoperability Framework includes a requisite quality of service: reliability, fidelity, and security. The Figure below depicts the GridWise Architecture

P1547 WG Meeting 201406 Minutes Annex C pg 3

Council (GWAC) stack on the left, where the OSI 7-layer model essentially maps into the technical levels of the GWAC stack. The right side of the figure lists cross-cutting issues are areas that need to be addressed and agreed upon to achieve interoperation. They usually are relevant to more than one interoperability category of the framework. .

- GWAC Stack with cross cutting issues

4.6Security for DER Interconnection

4.7 Introduction

The control of the power grid is based on the SCADA systems that control the balancing of generating and consuming electricity and display the status to the system operators. However, SCADA may have interconnections to the standard corporate intranets and Internet.

Although standards and guidelines are identified to support the implementation of minimum security measures that set a baseline for cybersecurity across energy sector, there are many security challenges that require solutions based on an effective security program. As described in IEEE Std. 2030-2011, an organization has to apply analysis and risk management methods to identify the appropriate solutions to ensure the security of the distributed energy resources including related systems and smart grid.

DERs are typically smaller electricity generation or ESS located in a community, business, or home. They can serve consumers’ energy needs locally and can provide support for the grid. Distributed generation includes combined heat and power, solar photovoltaic systems, and other small generators such as micro-turbines and fuel cells. Distributed ESS include batteries as well as thermal storage devices that heat or chill water to provide building services. Also, in this clause we discuss practices and techniques in a comprehensive security and privacy implementation for interoperable ESS.

4.8 Security Issues

The electric power infrastructure is transforming from a system of power interconnections to a very complex diverse, interconnected, interdependent, and adaptive system. Besides regulatory mandates (e.g., NERC CIP in North America), guidelines from energy industry, and standards organizations, it is mandatory that security of DER systems and applications is addressed in the early phases of design and architecture and continues through implementation, testing, deployment, and operation. Effective security management is required to enable resilience, safety, and interoperability of applications. Security management includes risk management, information security plans and policies, procedures, standards, guidelines, baselines, information classification, security organization, and security education.

At the local level, DER systems must manage their own generation and ESS activities autonomously, based on local conditions, pre-established settings, and DER owner preferences. The lowest level includes the actual cyber-physical DER systems operated autonomously. This autonomous operation can be modified by DER owner preferences and/or by settings and commands issued by utilities. The configurations include the security profiles as defined by standard profiles. However, prohibiting the incorrect settings or modification of settings by an intruder are critical to ensure accuracy of data and quality DER functionality.

Security programs typically focus on protection of human life, safety, tangible and intangible assets. With a system that interacts with power generation, transmission, and distribution, security responsibility for interconnected ESS extends beyond the traditional walls of the data center. Therefore, the approach of understanding vulnerabilities and the associated attack vectors to exploit the critical systems and other systems is essential to building effective security mitigation strategies.

For the purposes of IEEE 1547 Revision, this standard acknowledges the practices outlined in IEEE 2030-2011 to result in interoperability. This standard will not outline in depth the application of the SGIRM, but refer to these concepts as needed.

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20140626 – 0900 PDT Brian Escott

4.1.6 Monitoring and control provisions

The level of monitoring and control provisions required at each PCC (multiple sources/types of DR may be available within the DR unit) depends upon the type of DR and EPS characteristics. Table 4.1.6-1 lists several types of DR with other system parameters to help determine the Level of monitoring and control required. Table 4.1.6-2 lists the Levels and defines the monitoring and control functions required. Table 4.1.6-1 may be used as a guide, but the Level required for each PCC shall be negotiated between the DR operator / owner and the EPS operator depending upon system criteria such as penetration, size of DR, type of DR controls and protective relaying, and system parameters.

Additionally, the specific data flows or network paths will depend on which of the power systems domain is interacting with the DR:

Distribution - The distributers of electricity to and from customers. Service providers - The organizations providing services to electrical customers and

utilities. Markets - The operators and participants in electricity markets. Control/operations - The management of the movement of electricity. Customers - The end users of electricity.

P1547 WG Meeting 201406 Minutes Annex C pg 5

Do we need all the Types and Levels?

Type #

Level

Example of DR connected to the distribution system (This is redundant; the entire 1547 is distribution level…help with some better words, please, Clay. )

I-1 1 Inverter based generation, no energy storage, less than 10kW, single phase, low penetration.I-2 2 Inverter based generation, no energy storage, less than 10kW, single phase, moderate

penetration.I-3 3 Inverter based generation, with or without energy storage, 10-15kW, single phase, moderate

penetration and/or voltage sensitive feeder.I-4 4 Inverter based generation, with energy storage, 10-20kW, single or 3 phase, high

penetration.I-5 11 Inverter based generation, with or without energy storage, 3 phase, greater than 20kW, on

sensitive feeders or high levels of penetration or where remote control is needed to maintain system integrity.

I-6 14 Inverter based generation that also supports local loads, with or without energy storage, 3 phase, greater than 20kW, on sensitive feeders or high levels of penetration.

I-7 16 Inverter based generation that also supports local loads, with energy storage, 3 phase, greater than 500kW, medium voltage, with no transformers, on sensitive feeders or high levels of penetration..

S-1 1 Synchronous generation DG, any size, designed primarily to support local loads not intended to supply power to EPS. Parallels to EPS only for the purpose of transferring load to/from the EPS. Must have directional relaying and active anti-islanding protection. Maximum parallel time less than 30 seconds.

S-2 2 Synchronous generation Sync DG, less than 20kW, single phase, low penetration, with directional relaying

S-3 15 Synchronous generation Sync DG installed for primarily supporting local loads, also able to supporting the EPS via load curtailment, any size, with active anti-islanding functionality.

S-4 12 Synchronous generation Sync DG installed for EPS support, any size, with sensitive relaying or active methods to support anti- islanding. with low levels of penetration.

S-5 16 Synchronous generation Sync DG installed for EPS support, greater than 500kW, on sensitive feeders with high penetration.

S-6 5 Synchronous generation Sync DG designed to provide local loads and to export to EPS. kW and kVAR regulated (not droop regulated) when exporting to EPS. With active anti-islanding functionality. Any size. Installed on a low to moderate penetration EPS.

Level 1 2 3 4 5 10

11

12

13

14

15

16

Monitor

kW X X X X X X X X X XkVAR X X X X X X X X XVolts X X X X X X X X XStatus (Available? On line?) X X X X X X X XToggle mode from kW support to var support Trend X X X X X X X XVoluntary Separation from EPS X X X X X X X

ControlAnd

Monito

Direct Transfer Trip X X X X XLoad Curtailment Command with kW/kVAR levels

X X X X

r

DR Permitted to parallel X X XTrip on loss of communication link

X

Bring on available generationGen Curtailment command with kw/kvar levels.Droop

The method of communication is independent on the content to be communicated. The method of communication shall be agreed upon between the DR operator and the EPS operator.

Definitions:

Status. Is the DR available to operate? Is it currently in parallel with the EPS?

Trend. Is the DR output increasing (+), stable (/), or decreasing (-).

Voluntary Separation from EPS. The DR operator has decided to voluntarily separate from the EPS. Examples of this could be DR testing, “storm mode” or financially motivated.

Direct Transfer Trip. The EPS operator is commanding the DR no longer operate in parallel with the EPS. The DR operator must immediately, with no intentional delay, separate from the EPS. The DR operator may elect to take the local load or leave it on the EPS.

Load Curtailment Command/kW. The EPS operator requests the local DR to provide support to the EPS via previously agreed upon methods to the kW/kVAR level(s) specified. kW/kVAR units shall be in percent of previously agreed upon units. Examples include peak shaving, peak lopping, or full Interruptible Rate agreement. In Interruptible Rate agreement mode, the kW/kVAR is not needed.

DR permitted to parallel. The EPS operator shall set this bit to inform the DR operator when the DR will be allowed on the EPS. If this is not set, the DR operator may move the local load from the EPS to the DR, but only in open transition mode. Examples of this might be for local testing, maintenance or a EPS with varying penetration levels when the DR’s operation might threaten the stability of the EPS.

Trip on loss of communications link. The DR shall immediately separate from the EPS in the event of the loss of communications. The DR may leave the local loads on the EPS or may move them to the DR via open transition. No parallel operation is allowed until the communications link is repaired.

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20140625 Mark Siira

5.1 System Level Testing

Electric power distribution and transmission systems involve complex control, communication and coordination of multiple devices and subsystems. Because of this complexity and ongoing evolution of control software and communication, it’s increasingly important to acknowledge the importance of commissioning and systems

P1547 WG Meeting 201406 Minutes Annex C pg 7

integration testing as well as ongoing maintenance testing. Effective execution of these allows all parties involved in a project to know that the system will perform its intended function and that critical failures are unlikely to occur.

Testing is commonly undertaken at different levels during the commissioning of a facility depending on the critical nature of the equipment installed and the effect of downtime on the facility owner’s business. Additionally, testing is done on a recurring basis depending on the maintenance guidelines set by company policies, specific industries or regulatory agencies. Finally, testing is often done to validate corrective actions resulting from a facility power system failure or downtime of the facility owner’s business.

5.1.1 Types of Testing

Design Test

This design test (sometimes referred to as type test) shall be performed as applicable to the specific interconnection system technology. The test shall be performed on a representative sample, either in the factory, at a testing laboratory, or on equipment in the field. This test applies to a packaged interconnection system using system components that are type-tested to a standard or to an interconnection system that uses an assembly of discrete components that are type-tested to a standard..

Commissioning Testing

The purpose of commissioning is to provide documented confirmation that the systems function in compliance with the criteria set forth in the project documents to satisfy the owner’s operational needs.

Commissioning testing may be performed in the following areas:

Power quality – Testing for the presence of harmonics, voltage, or frequency abnormalities.

Grid interconnection – Testing of the paralleling switchgear and other interconnection subsystems to ensure that

the system meet required codes and standards, and perform in accordance with the electric power provider.

Additionally, testing for the generators to perform under load and load transients and load transfer

management.

Intentional islanding – If it is part of the system function, testing should be performed for intentional islanding

transitions from grid connect to island and backSystem Testing

During this phase, testing is performed to evaluate the performance of the system. In addition, any anomalies or issues identified in earlier Investigations that have not previously been resolved will be evaluated. Steps should be considered for further evaluation during system testing to determine root causes and possible solutions. It is recommended that the testing process include the verification and calibration of critical sensors. Typically, critical sensors are those sensors which are essential to the effective and efficient operation of the system.

Performance Assurance

This testing will evaluate methods of measuring system performance and verifying proper implementation to demonstrate the succESS of specific performance criteria. Each measure should have a verification methodology appropriate to the size and complexity of the measure. The identified verification methodology is then incorporated into a Measurement and Verification (M&V) Plan. The M&V plan is intended to provide a comprehensive protocol to verify the performance of the measure/system and confirm that the predicted performance have been achieved upon the completion of implementation.

Recurring Maintenance Testing

Maintenance tests are performed on regular intervals as determined by the facility owner's policies, the industry's recommended practices, and the regulatory agencies requirements. As a general rule, recurring testing comparable to commissioning tests can be performed on a scheduled basis and serves the purpose to ensure that all of the subsystems in a complex facility are operating as intended by the designers.

--

5.2 Integration of DER with EPS – Protection

The DER and EPS form an integrated power system. The protection of the EPS, and all connected equipment, requires appropriate protection systems for each DER along with EPS and protection systems for other equipment. Each DER has several protection requirements that are needed to properly protect the DER and the EPS. These protection systems may be standalone systems or may communicate with other systems. But in all cases they are coordinated in such a way to provide protection of the system.

Protection issues are of critical importance in order to avoid outages and operation out of acceptable ranges. The more information provided to the protective devices, the more adaptable they can be to properly protect for complex operating and fault situations. The combination of traditional protection systems, communications, and IT can create levels of protection and reliability that are not feasible with traditional protection schemes.

Protection Requirements

There are several protection requirements when a DER is connected to an EPS. These requirements require proper protection for the EPS and the DER. Proper protection includes protecting the EPS and DER from the potential damaging effects of short circuits, overloads, voltage deviations, frequency deviations, and anti-islanding. Basic protection requirements include anti-islanding protection, over/under voltage protection, over/under frequency protection, and overcurrent/short circuit protection.

Since the operation of the DER may be critical for EPS operations, the EPS may require particular voltage or frequency settings for the DER to coordinate properly with operating requirements of the EPS.

Protection Standard Practices

Standard protection typically consists of overcurrent protection, short circuit protection, under/over voltage protection and frequency protection. In some cases protection may include automatic reclosing. These devices as outlined are stand alone devices that require no or limited interoperability.

Other common practices include transfer trip schemes that result in fast operating opening of the DER breakers when certain events occur such as the opening of a breaker or sensing of a fault.

Communication (Interoperability) Needs

Communication needs can be thought of as on several levels of speed. The first level is extremely fast communications (milliseconds) that is needed for as close to as instantaneous tripping of circuit breakers and disconnecting.

The second level of communications is that of slower acting communications (seconds) for monitoring system status and identifying alternative settings.

The third level is for communicating data required from and to the protective devices and for monitoring data provided by the protective devices. These include settings and alternate settings, downloading settings actually in

P1547 WG Meeting 201406 Minutes Annex C pg 9

place, uploading settings to protective devices, implementing settings, getting event data and transient data, and state of the system data.

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5.3 Power Systems Simulations (Mark Siira)

Note: Testing certain controls functionality via simulation, for example RTDS simulation which can include hardware-in-the-loop, is starting to bridge the traditional physical-only testing process to add simulation based testing aspects. The following section is proposed to float the idea of including simulation-based or simulation-supported testing as an emerging industry practice that could be at least identified in the revision.

Interoperability of DER requires that a product from any vendor should be able to easily integrate into the existing power system infrastructure, which includes the existing IT systems, communication systems and the physical grid (the wires). Power system simulations ensure the DER is controlled in a suitable manner (dispatch of active and reactive power) though the control and communications systems and that it interacts with the existing grid as envisioned.

In general there are five main categories of power system modeling as described below:

Electromagnetic transients.

Electrical control and mechanical dynamics.

Steady state power flow.

Stochastic steady state.

Short circuit calculations.

HarmonicsIn order to determine the most appropriate type of simulation to be performed and the associated models we need to understand several issues:

1) The time period the problems of concern occur within and therefore the associated potential solutions.

2) The characteristics of technology (i.e. synchronous generator, battery with inverter, mechanical

flywheel etc.).

3) Interconnection technology

4) The application of the DER, i.e. load following, frequency regulation, voltage control etc.

5) Time latencies of any communication systems used within the control loop.It is common in the industry to perform power system simulations before any changes/additions to the physical power grid are made, to ensure the following:

The anticipated performance is verified.

The optimal configuration and specifications are determined.

No adverse impact is caused to the system operation.

Accurate economic evaluations are made, based on simulated performance.DER is often implemented to provide benefit to the power system, for example added capacity or increased renewable footprint. Therefore, it is advantageous to perform power system simulations using an accurate and verified (actual recorded results match the simulated results) model representation of the physical DER technology. The simulation enables the anticipated benefits before going to the expense of physical installation and operation.

Power system simulations allow decisions to be made on optimal location with respect to the power grid, system specifications (e.g. energy and power), type of technology and control methodology. The variables can be optimized through system model adjustments or through an automatic optimization process.

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201406 (T. McDermott, and R. Walling at WG Meeting)

4.2.1 Area EPS faults (T. McDermott) The DER unit shall cease to energize the Area EPS for faults on the Area EPS circuit to which it is connected. The DER unit shall not be required to detect faults that cannot be detected by the Area EPS protection systems. Where the fault current contribution of the DER is less than 200% of the DER rating, Fault detection by the DER unit shall take place within__ ms of disconnection of the faulted section of the Area EPS from the remainder of the Area EPS. Where DER current contribution to an Area EPS fault is greater than 200% of DER current rating, the DER shall cease to energize the Area EPS within ___ ms of the occurrence of that fault, and shall not be dependent on prior detection and isolation by the Area EPS protection systems.

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201406 (T. McDermott by R. Walling at WG Meeting

4.2.2 Area EPS Reclosing Coordination (T. McDermott)The DER shall cease to energize the Area EPS circuit to which it is connected prior to reclosure by the Area EPS, inclusive of reclosure times that are less than the islanding detection times specified in 4.4.1

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201406 (T. McDermott) by R. Walling at WG Meeting

4.2.3 Voltage (T. McDermott) 4.2.3.1 Applicable Voltages

The voltages applicable to the requirements of this clause shall be the voltages present at the PCC unless any of the following conditions exist:

a) The aggregate capacity of DER systems connected to a single PCC is less than or equal to 30 kW,b) The interconnection equipment is certified to pass a non-islanding test for the system to which it

is to be connected,

P1547 WG Meeting 201406 Minutes Annex C pg 11

c) The aggregate DER capacity is less than 50% of the total Local EPS minimum annual integrated electrical demand for a 15 minute time period, and export of real or reactive power by the DER to the Area EPS is not permitted except for brief transient periods during Area EPS disturbances.

When any of the excepted conditions above exist, the voltages at the point of DER connection shall be applicable to the requirements of this clause.

Where the transformer connecting the Local EPS to the Area EPS is a grounded wye-wye configuration, or the DER is a single-phase installation, the effective (rms) of the individual phase-to-neutral voltage(s) are applicable to the requirements of this Clause. For all other transformer configurations, the effective (rms) the phase-to-phase voltage(s) are applicable.

4.2.3.2 Mandatory Voltage Tripping Requirements

When any voltage is in a range given in Table 1, the DER shall cease to energize the Area EPS within the clearing time as indicated. Under mutual agreement between the EPS and DER operators, other static or dynamic voltage and clearing time settings shall be permitted. Clearing time is the time between the start of the abnormal condition and the DER ceasing to energize the Area EPS. For DER less than or equal to 300 W in peak capacity, the voltage set points and clearing times shall be either fixed or field adjustable. For DER greater than 300 W, the voltage set points and clearing times shall be field adjustable. Under- and over-voltage trip settings shall be sufficiently greater in delay time and with sufficient margin in voltage thresholds such that the mandatory voltage ride-through requirements specified in 4.2.3.3 are achieved considering all tolerances in voltage measurements and protection system response characteristics.

Table 1 -Default Interconnection system default response to abnormal voltages

Default settingsa

Voltage range (% ofbase voltageb)

Clearing time (s) Clearing time: adjustableup to and including (s)

V < 45 0.16 0.1645 ≤ V < 60 1 1160 ≤ V < 88 10 21

110 < V < 120 1 13V ≥ 120 0.16 0.16

a Under mutual agreement between the EPS and DER operators, other static or dynamic voltage and clearing time trip settings shall be permittedb Base voltages are the nominal system voltages stated in ANSI C84.1-2011, Table 1.

4.2.3.3 Voltage Disturbance Ride-Through Requirements

The performance required of DER during voltage disturbances are specified in this clause. An informative graphical depiction of these requirements is provided in Annex B.

4.2.3.3.1 Voltage Disturbances Within Normal Range

Voltage disturbances of any duration, for which the applicable voltage as specified in 4.2.3.1 remains within Range B as defined by ANSI C84.1, shall not cause the DER to disconnect from the Area EPS. The DER shall remain in operation during any such disturbance, and shall continue to deliver real power at least as great as its pre-disturbance level of power, prorated by the per-unit voltage level of the least phase voltage if that voltage is less than the nominal voltage, and subject to availability of the DER’s primary source of energy.11

4.2.3.3.2 Low-Voltage Ride-Through

During temporary voltage disturbances, for which the applicable voltage on the phase having the least voltage magnitude is less than the minimum of Range B as defined in ANSI C84.1, and greater than or equal to 75% of the base voltage, and having a cumulative duration outside of Range B of less than five seconds in any one minute period, the DER:

a) Shall not disconnect from the Area EPS and b) Shall remain in operation and continue to deliver both apparent power at least as great as

the pre-disturbance level of apparent power and real power equal to at least 90% of the pre-disturbance level or real power, each prorated by the per-unit voltage level of the least phase voltage, and subject to availability of the prime source of energy. The positive-sequence component of the fundamental frequency current injected by three-phase DER shall be in an angular range between 0 and 90 lagging the positive sequence voltage at the point of DER interconnection. For single-phase DER, the fundamental frequency current injected shall be in an angular range between 0 and 45 lagging the fundamental-frequency voltage at the point of DER interconnection.

Following temporary voltage disturbances, for which the applicable voltage on the phase having the least voltage magnitude is less than 75% of the base voltage and greater than or equal to 50% of the base voltage, for a cumulative period 0.25 second or less in any one minute period, the DER shall meet each of the following requirements:

c) Resume apparent and real power output greater than 25% of the amount prescribed in a) above within 0.1 seconds of the recovery of the applicable voltage to a value greater than 75% of the base voltage, subject to the availability of the prime source of energy.

d) Resume apparent and real power output greater than or equal to 100% of the amount prescribed in a) above within 0.5 seconds of the recovery of the applicable voltage to a value greater than 75% of the base voltage, subject to the availability of the prime source of energy.

e) Temporary cessation of energization or physical disconnection of the DER may take place when the applicable voltage is less than 75% of the base voltage, provided the performance specified in c) and d) above are achieved.

11 Decrease of solar irradiance in the case of a photovoltaic DER, or decrease of wind speed for a wind turbine generator, occurring during a voltage disturbance, are examples where DER power output decrease is compliant with this requirement. Any decrease of DER power output to less than the product of pre-disturbance power times per-unit voltage magnitude on the least phase, that is directly due to the voltage disturbance, is non-compliant. Examples include loss of auxiliary or control power to the prime mover.

P1547 WG Meeting 201406 Minutes Annex C pg 13

For voltage disturbances where the applicable voltage is less than 50% of the base voltage, or less than 75% of the base voltage for cumulative duration greater than 0.25 seconds, or less than ANSI C84.1 Range B for more than five seconds, in any one-minute period, requirements for continued operation (ride through), or resumption of operation subsequent to the voltage disturbance, do not apply.

4.2.3.3.3 High-Voltage Ride-Through

During temporary voltage disturbances, for which the voltage at the PCC on the phase having the greatest voltage magnitude is greater than the maximum of Range B as defined in ANSI C84.1, and less than or equal to 115% of the base voltage, and having a cumulative duration outside of Range B of less than 0.8 seconds in any one minute period, the DER:

a) Shall not disconnect from the Area EPS and b) Shall remain in operation and continue to deliver apparent power at least as great

as the pre-disturbance level of apparent power, subject to availability of the prime source of energy. The positive-sequence component of the fundamental frequency current injected by three-phase DER shall be in an angular range between 0 and 90 leading the positive sequence voltage at the point of DER interconnection. For single-phase DER, the fundamental frequency current injected shall be in an angular range between 0 and 90 leading the fundamental-frequency voltage at the point of DER interconnection.

Following temporary voltage disturbances, for which the applicable voltage on the phase having the greatest voltage magnitude is more than 115% of the base voltage and less than or equal to 120% of the base voltage, for a cumulative period 0.1 second or less in any one minute period, the DER shall meet each of the following requirements:

c) Resume apparent power output greater than 25% of the amount prescribed in a) above within 0.1 seconds of the applicable voltage decreasing to a value less than 115% of the base voltage, subject to the availability of the prime source of energy.

d) Resume apparent power output greater than or equal to 100% of the amount prescribed in a) above within 0.5 seconds of the applicable voltage decreasing to a value less than 115% of the base voltage, subject to the availability of the prime source of energy.

e) Temporary cessation of energization or physical disconnection of the DER may take place when the applicable voltage is greater than 115% of the base voltage, provided the performance specified in c) and d) above are achieved.

For voltage disturbances where the applicable voltage is greater than 120% of the base voltage, or greater than 115% of the base voltage for a cumulative duration greater than 0.1 seconds, or greater than ANSI C84.1 Range B for more than 0.8 seconds, in any one-minute period, requirements for continued operation or resumption of operation subsequent to the voltage disturbance do not apply.

4.2.3.3.4 Load Shedding or Transfer

The low and high voltage ride through requirements of 4.2.3.3.2 and 4.2.3.3.3 shall not apply if either:

a) The real power across the Point of Common Coupling is continuously maintained at a value less than 10% of the aggregate rating of DER connected to the Local EPS prior to any voltage disturbance, and the Local EPS disconnects from the Area EPS, along with Local EPS load, such that the net change in real power flow from or to the Area EPS is less than 10% of the aggregate DER capacity, or

b) Local EPS load real power demand equal to 90% to 120% of the pre-disturbance aggregate DER real power output is shed within 0.1 seconds of DER disconnection.

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20140627 (after WG meeting) 4.2.3 Voltage (John Berner – work in progress)

The protection functions of the interconnection system shall detect the effective (rms) or fundamentalfrequency value of each phase-to-phase voltage, . except where Where the three phase transformer connecting the Local EPS to the Area EPS is other than a grounded wye-wye configuration or single-phase installation, or where the DER is connected line to neutral, the phase-to-neutral voltage shall be detected. Where single phase DER is connected Phase to Neutral the phase-to-neutral voltage shall be detected

When any voltage is in a range given in Table 1, the DR shall cease to energize the Area EPS within the clearing time as indicated. Clearing time is the time between the start of the abnormal condition and the DR ceasing to energize the Area EPS. For DR less than or equal to 30 kW in peak capacity, the voltage set points and clearing times shall be either fixed or field adjustable. For DR greater than 30 kW, the voltage set points shall be field adjustable.

Substantiation:The intent of this section is to detect and avoid neutral shift caused by transformer self excitation during a loss of phase event in a three phase system. Phase to phase interconnected single phase DER is inherently balanced and there is no way for the DER to create a neutral shift. A neutral shift may be exist as a result of external events, e.g. loose neutral connection, but the presence of a phase to phase connected DER neither mitigates nor exacerbates the neutral shift. The present requirement adds costs unnecessarily and increases nuisance shifts.I am not sure if all transformer configuration are susceptible to self excitation and resultant neutral shift. I recall that the transformer of concern was a grounded Wye-Delta (distant memory). Who can verify this concern and transformer types ?The section was changed to consider the following use cases:

1) Three phase DER, connected phase to phasea. Connected to grounded Wye – Wyeb. Connected to other than grounded Wye – Wye

2) Single phase DER connected phase to phase in three phase systems.a. Connected to grounded Wye – Wyeb. Connected to other than grounded Wye – Wye

3) Single phase DER connected phase to neutral in three phase systemsa. Connected to grounded Wye – Wye

4) Single phase DER connected to single phase (split phase)systemsa. Connected phase to phaseb. Connected phase to neutral

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P1547 WG Meeting 201406 Minutes Annex C pg 15

201406 (T. McDermott) by R. Walling at WG Meeting

4.2.4 Frequency (T. McDermott) 4.2.4.1 Mandatory Frequency Tripping Requirements

When the system frequency is in a range given in Table 2, the DER shall cease to energize the Area EPS within a pre-set clearing time as indicated. Under mutual agreement between the EPS and DER operators, other static or dynamic frequency and clearing time settings shall be permitted. Clearing time is the time between the start of the abnormal condition and the DER ceasing to energize the Area EPS.

The frequency and time set points in Table 2 shall be field adjustable. Adjustable under-frequency (UF) and over-frequency (OF) trip settings shall be coordinated with the Area EPS operators. DER settings for frequency response shall be coordinated with load shedding schemes of the Area EPS. All under-and over-frequency trip settings shall be sufficiently greater in delay time and with sufficient margin in frequency thresholds such that the mandatory frequency ride-through requirements specified in 4.2.4.2 are achieved considering all tolerances in frequency measurements and protection system response characteristics.

Table 2 - Interconnection system default response to abnormal frequencies

Default settings Ranges of adjustabilityFunction Frequency

(Hz)Clearin

gtime (s)

Frequency

(Hz)

Clearing time (s)adjustable up to and including

UF1 57 0.16 56 – 59.5 10UF2 58.5 12 56 – 59.5 300OF1 61 12 60.5 – 64 300OF2 62 0.16 60.5 – 64 10

4.2.4.2 Frequency Disturbance Ride-Through Requirements

4.2.4.2.1 Normal Frequency Variations

Frequency disturbances of any duration, for which the system frequency remains between 59.5 Hz and 60.5 Hz, shall not cause the DER to disconnect from the Area EPS. The DER shall remain in operation during any such disturbance, and shall continue to deliver real power at least as great as its pre-disturbance level of power, subject to availability of the DER’s primary source of energy.

4.2.4.2.2 Low-Frequency Ride Through

During temporary frequency disturbances, for which the system frequency is less than 59.5 Hz and greater than or equal to 58.5 Hz, , and having a cumulative duration below 59.5 Hz of less than 10 seconds in any one minute period, the DER:

a) Shall not disconnect from the Area EPS and

b) Shall remain in operation and continue to deliver apparent power at least as great as the pre-disturbance level of apparent power, prorated by the per-unit frequency, and subject to availability of the prime source of energy.

4.2.4.2.3 High-Frequency Ride Through

During temporary frequency disturbances, for which the system frequency is greater than 60.5 Hz and less than or equal to 61.5 Hz, , and having a cumulative duration greater than 60.5 Hz of less than 10 seconds in any one minute period, the DER:

a) Shall not disconnect from the Area EPS and b) Shall remain in operation and continue to deliver apparent power equal to the

product of the pre-disturbance level of apparent power times a factor Kof , subject to availability of the prime source of energy. Factor Kof is defined as follows:

Kof = (fsystem – 60.5) Kdroop

where fsystem is the system frequency, and Kdroop shall be specified by the Area EPS operator, between values of ___ per Hz and ___ per Hz. The default value of Kdroop shall be ___ per Hz.

c) Shall return to the pre-disturbance level of real power within 0.5 seconds following recovery of the frequency to the normal 59.5 to 60.5 Hz range.

4.2.4.2.4 Load Shedding or Transfer

The low and high frequency ride through requirements of 4.2.4.2.2 and 4.2.4.2.3 shall not apply if:

a) The real power across the Point of Common Coupling is continuously maintained at a value less than 10% of the aggregate rating of DER connected to the Local EPS prior to any frequency disturbance, and the Local EPS disconnects from the Area EPS, along with Local EPS load, such that the net change in real power flow from or to the Area EPS is less than 10% of the aggregate DER capacity.

b) Local EPS load real power demand equal to 90% to 120% of the pre-disturbance aggregate DER real power output is shed within 0.1 seconds of DER disconnection.

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201406 (T. McDermott) Not previewed at 201406 WG Meeting

4.2.6 Reconnection to Area EPS (T. McDermott) After an Area EPS disturbance, no DER reconnection shall take place until the Area EPS voltage is within Range B of ANSI C84.1-1995, Table 1, and frequency range of 59.3 Hz to 60.5 Hz.

The DER interconnection system shall include an adjustable delay that may delay reconnection for up to five minutes after the Area EPS steady-state voltage and frequency are restored to the ranges identified above

P1547 WG Meeting 201406 Minutes Annex C pg 17

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201406 J. Berdner

4.2.6 Reconnection Re-energization of to Area EPSAfter an Area EPS disturbance, no DR reconnection re-energization shall take place until the Area EPS voltage is within Range B of ANSI C84.1-1995, Table 1, and frequency range of 59.3 Hz to 60.5 Hz. Other reconnection values for voltage and frequency shall be permitted with mutual agreement between the DER system operator and Area EPS operator.

The DR interconnection system shall include an adjustable delay (or a fixed delay of five minutes) that may delay reconnection for up to five minutes after the Area EPS steady-state voltage and frequency are restored to the ranges identified above.

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(Not previewed at 201406 WG meeting)

4.4 Islanding (T. McDermott) 4.4.1 Unintentional Islanding

For an unintentional island in which the DER energizes a portion of the Area EPS through the PCC, the DER interconnection system shall detect the island and cease to energize the Area EPS within five seconds of the formation of an island.11

11 Some examples by which this requirement may be met are: 1. The DER aggregate capacity is less than one-third of the minimum load of the Local EPS.2. The DER is certified to pass an applicable non-islanding test.3. The DER installation contains reverse or minimum power flow protection, sensed between the Point of DER Connection and the PCC, which will disconnect or isolate the DER if power flow from the Area EPS to the Local EPS reverses or falls below a set threshold. 4. The DER contains other non-islanding means, such as transfer trip.

IEEE P1547 June 26-27, 2014 WG meeting: drafts received onsite during meeting (works in progress; not final products)

19 Copyright © 2003 IEEE. All rights reserved.

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201406 (T. McDermott) by R. Walling at WG Meeting

5.1.7 Short circuit behavior test (T. McDermott) The DER interface unit shall be design-tested to determine the maximum instantaneous and symmetrical rms values of fault current contribution for three-phase-to-ground, single-phase-to-ground and phase-to-phase faults for these time periods:

a) Time 0 to 1 cycles for close and latch consideration.b) Time 1 to 4 cycles for equipment withstand.c) Time 4 to 30 cycles for interrupt ratings.d) Time 30 cycles and beyond for backup protection analysis.

The reported instantaneous current maximums shall encompass any fault initiation point-on-wave effects and any asymmetries among phases. The reported symmetrical rms values shall include phase angles of the current with respect to the rms voltage. For three-phase DER, the rms values shall be reported for the positive, negative and zero sequence. Test results shall be reported in either per-unit or amperes, and zero values shall be reported as appropriate. The test shall be performed with all packaged anti-islanding, control, and protection systems operating as intended for installation. The test report shall document the interconnection transformer or any other external impedance included, if any, along with any requirements on the interconnection transformer or external impedance for the test results to be valid. The design test report shall be deemed applicable to other interconnection transformers or external impedances that satisfy the following:

a) Transformers with the same high-side and low-side nominal voltages.b) Transformers with the same high-side and low-side winding connection types,

including any wye neutral connections and impedances.c) Impedance values within 10% of the tested impedance values, including both real

and imaginary parts, expressed in ohms on the same voltage base.

as in clause 5.1.7.

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201406 (T. McDermott) by R. Walling at WG Meeting

5.1.8 Loss of load behavior test (T. McDermott) The DER interface unit shall be design-tested to determine the overvoltage that occurs at the DER terminals upon sudden loss of load. The DER shall be tested for these loadings:

a) Rated output at unity power factor.b) Rated output at the minimum rated leading power factor.c) Rated output at the minimum rated lagging power factor.d) Half of rated output at unity power factor.

For each such test, the DER output current shall be zero after loss of load. The maximum rms voltage values 1 cycle and 10 cycles after loss of load shall be reported. These values

shall not exceed 200% of nominal during the first cycle, or 139% of nominal after the first cycle. Test conditions for the operation of packaged systems, interconnection transformers and external impedances shall be the same

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201406 (T. McDermott)

Annex B (T. McDermott)

(informative)

The performance during voltage disturbances, specified in 4.2.3, is depicted graphically in Figure B-1. For each of the zones of voltage magnitude and duration ranges, the performance required is summarized as follows:

A. Normal voltage range. The DER is required to maintain continuous operation for any voltage disturbance, of unlimited duration, for which the voltage magnitude remains within this normal range.

B. In this undervoltage zone, the DER must remain in operation and supply current as specified in 4.2.3.3.2.

C. In this more severe undervoltage zone, the DER may cease to energize the Area EPS, or may even physically disconnect, provided that it resumes the current injection required of Zone B within the time constraints as specified in 4.2.3.3.2, when the voltage rises above the upper value of this Zone C.

D. In this overvoltage zone, the DER must remain in operation and supply current as specified in 4.2.3.3.2.

E. In this more severe overrvoltage zone, the DER may cease to energize the Area EPS, or may even physically disconnect, provided that it resumes the current injection required of Zone B within the time constraints as specified in 4.2.3.3.2 when the voltage decreases below the lower value of this Zone E.

IEEE P1547 June 26-27, 2014 WG meeting: drafts received onsite during meeting (works in progress; not final products)

21 Copyright © 2003 IEEE. All rights reserved.

Figure B-1

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Modeling and Simulation (Divya Kurthakoti Chandrashekhara; & David Lovelady) The proposed wording is provided below and is suggested to be placed in-between sections “5.2 Production tests” and “5.3 Interconnection installation evaluation” of the current standard (1547:2003) as a new 5.3 section.

(add as new; renumber existing 5.3) 5.3 DER Interconnection power systems computer simulationsFor each DER interconnection request validated parameters suitable for power system computersimulations shall be provided to the area EPS owner. The power system computer simulationparameters shall cover at a minimum, steady state, instantaneous short circuit and dynamics(differential models) time frames. Parameter validation shall be provided by 3rd party verification ofthe simulated results vs real world test results of the DER, under the associated conditionsdescribed in Section 5.1. DER parameters for harmonics and EMT power system simulations arehighly desirable and will help to increase the area EPS owner’s confidence in the DER interconnection request.

David Lovelady Divya Kurthakoti Sudipta ChakrabortyJohn Berdner Brian Lydic Bob Nelson Harish Sharma Emma Stewart Reigh Walling