dnp3 profile for advanced photovoltaic generation and storage...dnp3. the purpose of defining this...

DNP Application Note AN2013-001

DNP3 Profile for Advanced Photovoltaic Generation and Storage

1 Introduction This document describes a standard data point configuration, set of protocol services and settings – also known as a profile – for communicating with photovoltaic (PV) generation and storage systems using DNP3. The purpose of defining this profile is to make it easier to interconnect the DNP3 masters and outstations that are used to control such systems.

This document is an application note, meaning it does not specify any changes to the DNP3 standard at all; it merely describes how to use DNP3 for a particular purpose. It is, however, intended to be an interoperability standard for those wishing to build and specify PV generation and storage systems.

Although this document describes a DNP3 profile, it is designed based on the structured data models of the International Electrotechnical Commission (IEC) 61850 protocol standards family. In particular, it is based on those data models that are specific to distributed generation and photovoltaic systems. The intent is that a system implementing this DNP3 application note can be easily integrated with an IEC 61850 network by means of a gateway, while remaining conformant with DNP3 best practices.

This application note supersedes application note AN2011-001 DNP3 Profile for Basic Photovoltaic Generation and Storage and is intended to be backward-compatible with it. The point numbers and definitions specified in that previous document shall also be valid in a device complying with this note. The Basic Profile (AN2011-001) remains valid but is not recommended for new implementations.

With these goals in mind, the design of this profile is based on the following documents:

• IEC 61850-7-420 Communication networks and systems for power utility automation - Part 7-420: Basic communication structure - Distributed energy resources logical nodes. This document is the IEC specification for standard data models to be used for distributed energy resources such as photovoltaic generation and storage systems.

• Common Functions for Smart Inverters (EPRI reference 1023059). This document was produced as a result of the work of the Photovoltaic Inverter Data Identification Focus Group (DIFG), organized by the Electric Power Research Institute (EPRI). The members of this group include photovoltaic inverter and storage manufacturers, utilities, research institutions and integrators. The document specifies a common set of application functions required for communicating with a photovoltaic or storage system controlled by a “smart” inverter.

• IEC 61850-90-7: IEC 61850 object models for inverters in distributed energy resources (DER) systems. This IEC technical report (TR) captures the set of functions defined in the EPRI document and describes how to implement these functions using IEC 61850. It specifies enhancements to IEC 61850-7-420 to make it more comprehensive for photovoltaic systems.

• IEEE 1815.1: Standard for exchanging information between networks implementing IEC 61850 and IEEE 1815 (DNP3) (in development). This is the current title of the emerging specification for mapping data between IEC 61850 and DNP3 networks and for configuring a gateway between such networks. The DNP3 specification itself is published by the IEEE as the IEEE Std. 1815, so the gateway standard will be IEEE Std. 1815.1. This standard is being developed through the

2013-01-14 AN2013-001 DNP3 Profile for Advanced PV Generation and Storage

assistance of the National Institute of Standards and Technology (NIST) and the Smart Grid Interoperability Panel (SGIP) under the label Priority Action Plan Twelve (PAP12).

To summarize, this document describes a DNP3 profile that implements the photovoltaic generation and storage functions specified by the EPRI Common Functions for Smart Inverters document and that can be mapped to an IEC 61850-7-420 and IEC 61850-90-7 object model according to the guidelines specified in the emerging IEEE Std. 1815.1. Naturally, complying with specifications from multiple groups with differing mandates in this way requires compromises. Where such compromises are required, the design attempts to follow DNP3 principles of simplicity, reliability, and conciseness.


Contents 1 Introduction .............................................................................................................................. 1

2 Details ....................................................................................................................................... 5

2.1 Overview of the Profile ....................................................................................................... 5

2.1.1 Assumptions in this Profile ....................................................................................... 5

2.1.2 High-Level Data Model ............................................................................................ 6

2.1.3 Differences between the Basic and Advanced Profiles .......................................... 10

2.2 Points List .......................................................................................................................... 12

2.2.1 Event Classes .......................................................................................................... 12

2.2.2 IEC 61850 Mapping ................................................................................................ 12

2.2.3 Binary Inputs........................................................................................................... 14

2.2.4 Double-Bit Binary Inputs ........................................................................................ 19

2.2.5 Binary Outputs ........................................................................................................ 21

2.2.6 Counters .................................................................................................................. 29

2.2.7 Analog Inputs .......................................................................................................... 34

2.2.8 Analog Outputs ....................................................................................................... 44

2.2.9 Other Data Types .................................................................................................... 92

2.3 Inverter Modes and Functions ........................................................................................... 97

2.3.1 Timing Parameters .................................................................................................. 97

2.3.2 Generic Curves and Schedules................................................................................ 97

2.3.3 General Response-Time Filtering ........................................................................... 99

2.3.4 Use of Broadcasting .............................................................................................. 101

2.3.5 Function INV1: Connect/Disconnect .................................................................... 101

2.3.6 Function INV2: Adjust Maximum Generation Level Up/Down .......................... 102

2.3.7 Function INV3: Adjust Power Factor ................................................................... 102

2.3.8 Function INV4: Charge/Discharge Storage .......................................................... 104

2.3.9 Function INV5: Pricing Signal for PV/Storage .................................................... 106

2.3.10 Function DS91: Modify PV/Storage Settings ....................................................... 107

2.3.11 Function DS92: Event/History Logging ............................................................... 107

2.3.12 Function DS93: “Status” Reporting ...................................................................... 108

2.3.13 Function DS94: Time Synchronization ................................................................ 108

2.3.14 Function VV: Configurable Volt/VAR Curves .................................................... 109

2.3.15 Function VV: Constant VARs .............................................................................. 114

2.3.16 Function FW22: Frequency-Watt Mode ............................................................... 115

2.3.17 Function TV31: Dynamic Reactive Current Mode ............................................... 119

2.3.18 Functions MD and MRC: Low/High Voltage Ride-Through .............................. 123 2013-01-14 AN2013-001 DNP3 Profile for Advanced PV Generation and Storage

2.3.19 Function WP42: Watt-Power Factor Mode ......................................................... 126

2.3.20 Functions VW51-VW52: Volt-Watt Modes ........................................................ 128

2.3.21 Function PS and TMP: Non-power Parameter Modes ......................................... 130

2.3.22 Function RPS: Real Power Smoothing ................................................................ 131

2.3.23 Function DVW: Dynamic Volt-Watt Mode.......................................................... 133

2.3.24 Function PPL: Peak Power Limiting .................................................................... 136

2.3.25 Function LGF: Load and Generation Following................................................... 137

2.3.26 Scheduling ............................................................................................................ 138

2.4 Interaction Between Settings ........................................................................................... 141

2.4.1 Remote/Local Mode ............................................................................................. 141

2.4.2 Automatic/Manual Mode ...................................................................................... 142

2.4.3 Priority of Last Command .................................................................................... 142

2.4.4 Guidelines for Precedence of Settings .................................................................. 143

2.5 Grid Configurations and Islanding .................................................................................. 146

2.5.1 Possible Grid Configurations ................................................................................ 146

2.5.2 Settings Groups ..................................................................................................... 146

2.5.3 Settings Group Control Parameters ...................................................................... 147

2.5.4 Sensing the Grid Configuration ............................................................................ 148

2.5.5 Modes of Operation When Islanded ..................................................................... 148

2.6 Implementation Table ..................................................................................................... 150

3 Conclusions .......................................................................................................................... 156

4 Submitted By ........................................................................................................................ 156

5 Disclaimer............................................................................................................................. 156

6 Technical Committee Commentary ...................................................................................... 156


2 Details This section describes the profile in detail. The profile consists of:

• An overview describing the assumed structure of the PV system and the high-level organization of the IEC 61850-7-420 data model used.

• The list of DNP3 data points that shall be provided by devices implementing this application note and the IEC 61850 name that corresponds to each point. The intent is that any device that implements this application note shall use the same point indices and data objects. Data specific to a particular supplier can be added using indices higher than those listed here.

• The list of DNP3 services (i.e. function codes, objects and point indices) that shall be used to implement each of the functions specified by the IEC 61850-90-7 technical report and the EPRI document Common Functions for Smart Inverters. These functions are arranged in groups with abbreviated names as listed in the sub-sections of section 2.3, e.g. VV for Volt/VAR management. Various tables in this document contain a column labeled “Inverter Function” or “Inv Func” containing these abbreviations, to illustrate which data and actions are associated with particular functions.

• A protocol implementation conformance statement (PICS) form showing which functions are required and which are optional.

The reader of this profile is expected to be familiar with DNP3 and understand photovoltaic generation and storage systems. It is useful, but not required, for the reader to be familiar with IEC 61850.

2.1 Overview of the Profile As described in the reference documents, photovoltaic generation and storage systems may be deployed in a variety of configurations. There are many different possible combinations and topologies of panels, inverters, switches, storage units, controllers and other equipment. If this profile attempted to address all these different possibilities it is likely that it would become too flexible or vague to be of any use in encouraging interoperability.

Therefore, to simplify this profile and make it easier to implement, a number of assumptions have been made. This section lists those assumptions and graphically presents the assumed structure of the corresponding photovoltaic system. It is presented in two formats: a network diagram, and the IEC 61850 data model.

2.1.1 Assumptions in this Profile This profile makes the following assumptions about the structure of the actual photovoltaic system, as illustrated in Figure 1:

• Communications is between a DNP3 master and a single outstation. Some PV systems include multiple processors and controllers. However, this profile assumes that the DNP3 communications takes place with a single device that acts as a proxy for any others. This device may be the inverter, but it could just as easily be some other device. The area monitored and controlled by the outstation is labeled “Distributed Energy Resource” in the figure.

• The system that is being monitored and controlled using DNP3 consists of a single inverter, a single battery storage unit and a single switch, marked the “DER Connect/Disconnect Switch” in Figure 1. In the actual system, there may be many of these devices (i.e. many inverters), but they are modeled assuming some piece of equipment aggregates their effect on the data being controlled and monitored.

• The actual photovoltaic generation panels are not specifically described except as they affect the inputs and outputs of the inverter.


• This model recognizes that an outstation might be a PV-only system, a battery-only system, or a combination of the two. In the case of a combination system, this model acts as though both the PV and battery utilize a single inverter (i.e. both connected through the DC side of the inverter). In actual practice, a combination system could involve two inverters and connect together on the AC side (dashed line). In such a case, the implementer could choose to present the system as a single outstation with both PV and storage capabilities, or as two separate outstations.

• Local load, if present, is not described.

• “Islanding” of the customer site or neighborhood using another switch between the photovoltaic system and the utility is discussed in section 2.5, but only with regard to the configuration and communications of one particular inverter. System-level interactions and algorithms to support multiple devices in an islanded condition are the domain of an island master controller and are out of the scope of this document.

Figure 1 – Assumed Photovoltaic System Structure

2.1.2 High-Level Data Model This section is of interest only to those readers who wish to understand the IEC 61850 data model underlying the points list in section 2.2.

Users of DNP3 may be familiar with the concept that the data reported to the master station is just a simplified view, or model, of what is actually happening at the remote site. There may be many complex interactions between devices that are simply summarized for the benefit of the master. The collection of data reported and controlled by the DNP3 outstation is known as its data model. This terminology is not commonly used in the DNP3 documentation, but each DNP3 outstation has a data model nonetheless.

In DNP3, the data model is “flat”. Each data point is simply numbered and there is no indication within the protocol itself of how one point relates to another. In IEC 61850 data models, each piece of data has a human-readable text name that uniquely identifies it. IEC 61850 names have a hierarchical structure, similar to a file system, so that each point of data has an implied relationship with the others.

IEC 61850 names consist of the hierarchy shown in Figure 2: logical devices which contain logical nodes, which contain data objects, which may contain several layers of data attributes.

A logical node is a grouping of data associated with a particular electrical system function. Logical nodes are designated by four-character class names. If there is more than one logical node of the same class (performing the same function but on another part of the system) they are distinguished by one-or-two-

Battery Storage

Photovoltaic Generation

Inverter

Local Load (the home)

Utility

DERConnect/

Disconnect Switch

Utility Switch

Distributed Energy Resource

Customer Site

DC Grid (AC)

Measurement Points

Output (AC)


character instance numbers. If a device implements a particular electrical system function, it must report and/or control the set of mandatory data objects associated with the corresponding logical node as specified by the IEC 61850-7 set of standards.

Figure 2 - Example of an IEC 61850 Name

The logical nodes included in this photovoltaic profile are identified in Table 1. The logical nodes fall into the following general categories:

• Nodes that model physical equipment: Battery (ZBAT), Operational Characteristics of Connection Point (DOPR), and Connect/Disconnect Switch (CSWI).

• Nodes that describe the modes of behavior of the battery and inverter: several instances of DER Mode (DOPM). This minimum set of behavior modes has been defined by the EPRI specification Common Functions for Smart Inverters and IEC 61850-90-7, as described in section 2.3. The set points defined in these logical nodes control automatic behavior of the physical equipment. Associated with some of these modes are curve definitions (FMAR), e.g Volt/VAR curves.

• Nodes that monitor the status of the system: Measurements (MMXU), Metering (MMTR), DC Measurements, Distributed Resource Controller Status (DRCS) and Status at the DR Connection Point (DRST). There are two instances of MMXU to represent the measurements of the system output and the grid respectively.

• Nodes that control the system at a higher level, choosing when to act in each mode and what the limits of the system are: DER Supervisory Control (DRCC), DER Controller Characteristics (DRCT), DER Economic Dispatch (DCCT) and DER Schedule Control (DSCC). Settings in the Schedule Control logical node select from several possible Schedules (FSCH). Each schedule specifies changes in the operating setpoints of the equipment based on time, temperature, or price.

NOTE: The controller logical nodes were created specifically for modeling systems that have many inverters. In such systems, the controller would aggregate the information from all the inverters. Because this model includes only a single inverter, the controller logical nodes and the inverter logical node would contain duplicate data, so there is no Inverter logical node (ZINV).

The mandatory data objects and data attributes associated with these logical nodes are defined in the IEC 61850-7-4, IEC 61850-7-420 and IEC 61850-90-7 standards. They were used to determine the DNP3 points list in section 2.2.

Bay12Unit2/MMXU3.PhV.phsA.cVal.mag.f

Part of name What it means Example of an alternativeLogical Device Name Chosen by the utility Feeder3

Logical Node Prefix -- not used in this example --

Logical Node Class Metering Measurement Unit PDIS – Protection, Distance

Logical Node Instance Feeder number 3 7

Data Name Phase-to-Ground Voltages PPV – Phase-to-phase volts

Data Attribute Name Phase A PhsB – Phase BNeut – Neutral

Data Attribute Name Complex value after deadbanding instMag – Instantaneous value

Data Attribute Name Magnitude of the complex value ang – angle in degrees

Data Attribute Name Floating point value i – integer value

Data Attribute Names – defined in a Common Data Class (CDC)


Table 1 – IEC 61850 Logical Nodes in this Profile Class Instance Description Source Inverter Function

CSWI 1 DER Connect/Disconnect Switch Basic INV1

DGSM 1 Volt/VAR Curve 1 Commands Basic VV










DGSM n Generic Curve Commands IEC All Curves

DOPM 1 Connect/Disconnect Operational Mode Basic INV1

DOPM 2 Limited Watts Operational Mode Basic INV2

DOPM 3 Fixed Power Factor Mode Basic INV3

DOPM 4 Charge/Discharge Storage Operational Mode Basic INV4

DOPM 5 Pricing Signal Operational Mode Basic INV5

DOPM 6 Constant Var Operational Mode IEC VV

DOPM 7 Real Power Smoothing Operational Mode EPRI RPS

DOPM 8 Dynamic Volt-Watt Operational Mode EPRI DVW

DOPM 9 Peak Power Limiting Operational Mode EPRI PPL

DOPM 10 Load/Generation Following Operational Mode EPRI LGF

DOPR 1 Operational characteristics at connection to grid Basic DS93, FW22

DRCC 1 DER Supervisory Control (no longer in 90-7) Basic All

DRCS 1 DER Controller Status Basic All

DRCT 1 DER Controller Characteristics All All

DSCH 1 Schedule 1 (obsolete) Basic SCD













Class Instance Description Source Inverter Function

FMAR 1 Volt/VAR Curve 1 Basic VV










FMAR n Generic Curve > 10 currently selected for viewing and editing IEC All Curves

FSCC 1 Schedule Controller IEC SCD

FSCH 1 Schedule 1 Basic SCD












FSCH n Schedule > 12 currently selected for viewing and editing IEC SCD

MMDC 1 Measurements at input to inverter and storage Basic DS93

MMTR 1 Energy Metering at connection point EPRI

MMXU 1 Measurements at output of inverter Basic DS93

MMXU 2 Measurements at connection to grid Basic DS93

MMXN 1 Reference Power Input for Real Power Smoothing IEC RPS

MMXN 2 Reference Power Input for Peak Power Limiting IEC PPL

MMXN 3 Reference Power Input for Load or Generation Following IEC LGF

PTOV 1 Overvoltage Disconnect Protection (must disconnect) IEC MD

PTUV 1 Undervoltage Disconnect Protection (must disconnect) IEC MD

RDGS 1 Dynamic Reactive Current Support IEC TV31

ZBAT 1 Battery storage Basic DS93, INV4


2.1.3 Differences between the Basic and Advanced Profiles The following is a list of the differences between this document and AN2011-001 DNP3 Profile for Basic Photovoltaic Generation and Storage.

• The Advanced Profile makes a parameter visible that in IEC 61850 would be used for forcing the system to either produce VARs or absorb VARs in power factor (INV3) mode. However, because this profile only uses the IEEE power factor convention, this value is not writeable in DNP3. It is provided for alignment with IEC 61850 only.

• The Advanced Profile permits the master to select whether the DER should reverse producing or absorbing VARs when switching between charging and discharging. In the Basic Profile, the DER always reversed the VAR action when switching.

• In the Advanced Profile, using the INV5 mode requires an additional control operation to enable Price Signal after setting the price signal value. This permits the Price Signal mode to be disabled, which was not possible in the Basic Profile.

• The following functions appear only in the Advanced Profile:

o Frequency-Watt (FW)

o Dynamic Reactive Current (TV)

o Must Disconnect (MD) and Must Remain Connected (MRC)

o Watt-Power Factor (WP)

o Voltage-Watt (VW)

o Temperature Curves (TMP)

o Pricing Signal Curves (PS)

o Real Power Smoothing (RPS)

o Dynamic Volt-Watt (DVW)

o Peak Power Limiting (PPL)

o Load and Generation Following (LGF)

• A generic curve specification mechanism is provided in the Advanced Profile in order to make several of the new functions possible. This mechanism is described in detail in section 2.3.2.

• Curves defined using the generic mechanism are limited to 20 points instead of 10 as in the Basic Profile.

• The number of schedules is no longer limited to 12.

• Schedules defined using the generic mechanism are limited to 20 points instead of 10 as in the Basic Profile.

• The number of Volt/VAR curves is no longer limited to 10.

• The Basic Profile permitted only one Volt/VAR curve to be active at a time, while the Advanced Profile permits more than one.

• The only permitted X-value for a schedule in the Advanced Profile is time, while the Basic Profile also permitted temperature and price schedules.

• The DS91 through DS94 functions were called INV6, INV7, INV8 and INV10 in the Basic Profile.

• The Advanced Profile provides several additional binary input and analog input status values beyond those found in the Basic Profile.


• The Advanced Profile provides specific setpoints for providing a fixed level of VARs while in the Basic Profile it was necessary to create a horizontal Volt/VAR curve to do this.

• The Advanced Profile includes an “Amps” rating for the system in addition to Volts, Volt-Amps, Watts and VARs.

• The Advanced Profile permits the storage Capacity Rating and Storage Reserve to be optionally specified in Watt-hrs instead of Amp-hrs as in the Basic Profile.


2.2 Points List This section describes the points list to be used by DNP3 outstations controlling photovoltaic generation and storage. Any device claiming to implement this DNP3 application note shall report all the DNP3 object instances (points) specified in the following subsections, using the protocol options and parameters specified.

An outstation may claim to implement this DNP3 application note without implementing all the inverter modes and functions described in 2.3. The DNP3 object instances corresponding to non-implemented functions shall be reported with the OFFLINE flag set.

If an outstation reports additional DNP3 object instances, they must be added after the last point index listed in the following subsections. This capability permits an outstation to add to their outstation any proprietary or innovative functionality that is not part of this standard.

These point lists are supersets of the corresponding point lists in AN2011-0001 DNP3 Profile for Basic Photovoltaic Generation and Storage. Each table is marked with double borders separating the DNP3, IEC 61850, and Inverter Functions columns. A triple border marks the end of the points from the basic profile as shown in Table 2.

Table 2 – Points List Formatting

DNP3 Columns IEC 61850 Columns Inverter Functions

“Basic” Points

“Advanced” Points

The table formats and protocol parameters specified here are taken from the standard DNP3 Device Profile document. The section numbers in the “protocol options” tables are references within that document.

2.2.1 Event Classes

This profile uses the following criteria for assigning points to default classes:

Table 3 – Default event classes in this profile Class Criteria

1 Critical data. Alarms and other events requiring immediate action.

2 Feedback 3 Measurements and Configuration

The operator/engineer may choose to change these defaults at runtime using the ASSIGN CLASS function code from the master.

2.2.2 IEC 61850 Mapping The rightmost columns of the points list tables show how each point would be mapped onto an IEC 61850 gateway. The values in the columns are as shown in Table 4.


Table 4 – Meanings of the IEC 61850 Columns Column Meaning LN Class Logical node class LN Inst Logical node instance Data Object Data object within the logical node CDC Common data class of the data object

The IEC 61850 Common Data Classes are defined in the IEC 61850-7-3 specification. Table 5 lists the names of those used in this profile.

Table 5 – IEC 61850 Common Data Classes referenced by this profile CDC Name APC Analog setpoint controllable ASG Analog setting CSG Curve setting DPC Double point controllable ENG Enumerated setting ENS Enumerated status INC Integer status controllable ING Integer setting INS Integer status MV Measured value SPC Single point controllable SPS Single point status WYE Wye-Connected 3-phase measurement


2.2.3 Binary Inputs Table 6 lists the binary input points to be used in the DNP3 Profile for Photovoltaic Generation and Storage Systems. Table 7 specifies the options to be used by outstations when reporting these points. Note that these are read/only values that represent the current state of the system. Some of these values can be changed using corresponding binary output points listed in section 2.2.5. The point numbers for the writeable values and the read/only values are not the same.

Table 6 – Binary Input Points List

Point Index Name / Description

Default Event Class

Name for State when value is 0


IEC 61850

Inverter Function LN

Class LN Inst Data Object CDC

0 Mode of operation – limited Watts 2 Disabled Enabled DOPM 2 OpModWLim SPC INV2

1 Mode of operation – fixed power factor 2 Disabled Enabled DOPM 3 OpModPFAng SPC INV3

2 Mode of operation – charge/discharge rate 2 Disabled Enabled DOPM 4 OpModWRte SPC INV4

3 Start inverter operation 2 Null Started DRCC 1 DERStr SPC

4 Stop inverter operation 2 Null Stopped DRCC 1 DERStop SPC

5 Set automatic mode 2 Not Auto Auto DRCC 1 AutoManCtl SPC

6 Set local/remote control mode 2 Remote Local DRCS 1 LocRemCtl SPC DS93

7 PV system is in automatic mode 3 Not-Auto Auto DRCS 1 AutoMan SPS

8 PV is generating and connected 3 Null On-Connected DRCS 1 ModOnConn SPS DS93

9 PV is generating and available for connection 3 Null On-Not-Connected DRCS 1 ModOnAval SPS DS93

10 PV is off but available to start generating 3 Null Off-Available DRCS 1 ModOffAval SPS DS93

11 PV is off and not available to start generating 3 Null Off-Not-Available DRCS 1 ModOffUnav SPS DS93

12 VAR management capability 3 No VAR Mgmt VAR Mgmt Available DRCS 1 ModVAr SPS DS93

13 Inverter active power output too high 1 Normal Alarm MMXU 1 TotW.range MV DS93

14 Inverter active power output too low 1 Normal Alarm MMXU 1 TotW.range MV DS93

15 Inverter reactive output too high 1 Normal Alarm MMXU 1 TotVAr.range MV DS93

16 Inverter reactive output too low 1 Normal Alarm MMXU 1 TotVAr.range MV DS93



Default Event Class



IEC 61850



17 Current output frequency is too high 1 Normal Alarm MMXU 1 Hz.range MV DS93

18 Current output frequency is too low 1 Normal Alarm MMXU 1 Hz.range MV DS93

19 Active power at the connection is high 1 Normal Alarm MMXU 2 TotW.range MV DS93

20 Active power at the connection is low 1 Normal Alarm MMXU 2 TotW.range MV DS93

21 Reactive power at the connection is high 1 Normal Alarm MMXU 2 TotVAr.range MV DS93

22 Reactive power at the connection is low 1 Normal Alarm MMXU 2 TotVAr.range MV DS93

23 Power factor at the connection is high 1 Normal Alarm MMXU 2 TotPF.range MV DS93

24 Power factor at the connection is low 1 Normal Alarm MMXU 2 TotPF.range MV DS93

25 DC Inverter input power too high 1 Normal Alarm MMDC 1 Watt.range MV DS93

26 DC Inverter input power too low 1 Normal Alarm MMDC 1 Watt.range MV DS93

27 DC Inverter current level too high 1 Normal Alarm MMDC 1 Amp.range MV DS93

28 DC Inverter current level too low 1 Normal Alarm MMDC 1 Amp.range MV DS93

29 DC voltage at inverter too low 1 Normal Alarm MMDC 1 Vol.range MV DS93

30 DC voltage at inverter too high 1 Normal Alarm MMDC 1 Vol.range MV DS93

31 Status of storage 3 Off On ZBAT 1 BatSt SPC

32 External battery voltage (between battery charger and battery) is too high

1 Normal Alarm ZBAT 1 Vol.range MV DS93

33 External battery voltage (between battery charger and battery) is too low

1 Normal Alarm ZBAT 1 Vol.range MV DS93

34 Internal battery voltage is too low 1 Normal Alarm ZBAT 1 InBatV MV DS93

35 Internal battery voltage is too high 1 Normal Alarm ZBAT 1 InBatV MV DS93

36 Schedule 1 has been activated 2 Inactive Active DSCH 1 SchdSt SPS SCD





Default Event Class



IEC 61850












48 Phase A Voltage at the connection is high 1 Normal Alarm MMXU 2 PhV.PhsA.range WYE DS93

49 Phase A Voltage at the connection is low 1 Normal Alarm MMXU 2 PhV.PhsA.range WYE DS93

50 Phase B Voltage at the connection is high 1 Normal Alarm MMXU 2 PhV.PhsB.range WYE DS93

51 Phase B Voltage at the connection is low 1 Normal Alarm MMXU 2 PhV.PhsB.range WYE DS93

52 Phase C Voltage at the connection is high 1 Normal Alarm MMXU 2 PhV.PhsC.range WYE DS93

53 Phase C Voltage at the connection is low 1 Normal Alarm MMXU 2 PhV.PhsC.range WYE DS93

54 Mode of operation – constant Vars 2 Disabled Enabled DOPM 6 OpModConVAr SPC VV

55 Power Factor Operating Quadrant (not used – here for IEC 61850 compatibility)

1 Producing VARs - Q1/Q2

Absorbing VARs - Q3/Q4 DRCT 1 PFExt SPG INV3

56 Overvoltage Disconnect Protection Blocked 1 Not Blocked Blocked (Disabled) PTOV 1 Blk SPS MD

57 Overvoltage Disconnect Protection Started 1 Not Started Started (Evaluating) PTOV 1 Str.general ACD MD

58 Overvoltage Disconnect Protection Operated 1 Not Operated Operated (Disconnected) PTOV 1 Op.general ACT MD

59 Undervoltage Disconnect Protection Blocked 1 Not Blocked Blocked PTUV 1 Blk SPS MD



Default Event Class



IEC 61850



(Disabled)

60 Undervoltage Disconnect Protection Started 1 Not Started Started (Evaluating) PTUV 1 Str.general ACD MD

61 Undervoltage Disconnect Protection Operated 1 Not Operated Operated (Disconnected) PTUV 1 Op.general ACT MD

62 Storage state of charge (percent) is too high 1 Normal Alarm DRCT 1 ChaMaxPctHi SPS DS93

63 Storage state of charge is too low - reserve reached

1 Normal Alarm DRCT 1 MinRsrvPctLo SPS DS93

64 Storage state of charge is depleted - minimum rating reached

1 Normal Alarm ZBAT 1 MinAHrRtgLo SPS DS93

65 Storage internal temperature too high 1 Normal Alarm ZBAT 1 InBatTmp.range MV DS93

66 Storage external (ambient) temperature too high 1 Normal Alarm ZBAT 1 ExtBatTmp.range MV DS93

67 Mode of operation - Real Power Smoothing 2 Disabled Enabled DOPM 7 OpModWSmth SPC RPS

68 Mode of Operation - Dynamic Volt-Watt 2 Disabled Enabled DOPM 8 OpModDynVW SPC DVW

69 Mode of Operation - Peak Power (Load) Limiting 2 Disabled Enabled DOPM 9 OpModPk SPC PPL

70 Mode of Operation - Load / Generation Following 2 Disabled Enabled DOPM 10 OpModWFol SPC LGF


Table 7 – Binary Input Protocol Options 3.1 SINGLE-BIT BINARY INPUTS Static (Steady-State) Group Number: 1 Event Group Number: 2

Capabilities

3.1.1 Static Variation reported when variation 0 requested or in response to Class polls:

� Variation 1 – Single-bit Packed format ; Variation 2 – Single-bit with flag � Based on point Index (add column to table in part 5)

3.1.2 Event Variation reported when variation 0 requested or in response to Class polls:

Note: The support for binary input events can be determined remotely using protocol object Group 0 Variation 237.

� Variation 1 – without time � Variation 2 – with absolute time ; Variation 3 – with relative time � Based on point Index (add column to table in part 5)

3.1.3 Event reporting mode:

When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event. All events must be checked to be compliant.

� Only most recent ; All events

3.1.4 Binary Inputs included in Class 0 response:

; Always � Never � Only if the point is assigned to a class � Based on point Index (add column to table in part 5)


2.2.4 Double-Bit Binary Inputs Table 8 identifies the double-bit binary input point to be used in the DNP3 Profile for Advanced Photovoltaic Generation and Storage Systems. Only one binary point, the switch between the generation and storage system and the grid, could potentially be moving between the open and closed positions. Implementers are free to add additional points as appropriate. Table 9 specifies the options to be used by outstations when reporting this point.

Table 8 - Double-Bit Binary Input Points List


Default Event Class





IEC 61850

LN Class

LN Inst Data Object CDC

0 Status of the DER connect/disconnect switch 2 Moving Disconnected Connected Error CSWI 1 Pos DPC

Table 9 - Double-Bit Binary Input Protocol Options

3.2 DOUBLE-BIT INPUT POINTS Static (Steady-State) Group Number: 3 Event Group Number: 4

Capabilities


Note: The support for double-bit inputs can be determined remotely using protocol object Group 0 Variation 234.

� Variation 1 – Double-bit Packed format ; Variation 2 – Double-bit with flag � Based on point Index (add column to table in part 5)


� Variation 1 – without time � Variation 2 – with absolute time ; Variation 3 – with relative time � Based on point Index (add column to table in part 5)

3.2.3 Event reporting mode:

When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event. All events must be checked to be compliant.



3.2 DOUBLE-BIT INPUT POINTS Static (Steady-State) Group Number: 3 Event Group Number: 4

Capabilities

3.2.4 Double-bit Inputs included in Class 0 response:



2.2.5 Binary Outputs Table 10 lists the binary output points to be used in the DNP3 Profile for Photovoltaic Generation and Storage Systems. Table 11 specifies the options to be used by outstations when reporting these points.

Although all operation pairs (Pulse, Latch, Trip/Close) are permitted, the outstation shall behave as if all points were Latched. Pulse time values in the Control Relay Output Block objects shall be ignored by the outstation. Note that Binary Output Event objects are required and that all objects require select-before-operate functionality.

“Start PV Generation” and “Stop PV Generation” are mutually exclusive. Changing one of these points to the “1” state shall cause the other to change to the “0” state.


Table 10 - Binary Output Points List

Poin

t Ind

ex

Name / Description

Supported Control Operations



Default Event Class

IEC 61850

Inv Func

Sel

ect/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

No

Ack

Pul

se O

n

Pul

se O

ff

Lat

ch O

n

Lat

ch O

ff

Trip

Clo

se

Cou

nt >

1

Can

cel C

urre

nt O

pera

tion

Chg Cmd

LN Class

LN Inst

Data Object CDC

0 DER connect/ disconnect switch. X X X X X X X X X Open Closed 2 2 CSWI 1 Pos DPC INV1

1 Mode of operation - limited Watts X X X X X X X X X Disabled Enabled 2 2 DOPM 2 OpModConW SPC INV2

2 Mode of operation - maintaining fixed power factor X X X X X X X X X Disabled Enabled 2 2 DOPM 3 OpModConPF SPC INV3

3 Mode of operation - charge or discharge rate X X X X X X X X X Disabled Enabled 2 2 DOPM 4 OpModExIm SPC INV4

4 Start inverter operation X X X X X X X X X Null Started 2 2 DRCC 1 DERStr SPC

5 Stop inverter operation X X X X X X X X X Null Stopped 2 2 DRCC 1 DERStop SPC

6 Set automatic mode X X X X X X X X X Not Auto Auto 2 2 DRCC 1 AutoManCtl SPC

7 Battery Status X X X X X X X X X Off On 2 2 ZBAT 1 BatSt SPC

8 Power factor operating quadrant (here for IEC 61850 compatibility, not implemented)1

Producing VARs - Q1/Q2

Absorbing VARs - Q3/Q4

2 2 DRCT 1 PFExt SPG INV3

9 Mode of operation - pricing signal X X X X X X X X X Disabled Enabled 2 2 DOPM 5 OpModPrc SPC INV5

10

Mode of operation - constant Vars There are three options for setpoints - See DRCT.VArRef

X X X X X X X X X Disabled Enabled 2 2 DOPM 6 OpModConVAr SPC VV

11 Volt/VAR Curve 1 Enable X X X X X X X X X Disabled Enabled 2 2 DGSM 1 ModEna SPC VV

1 The DNP3 outstation shall respond with the NOT_SUPPORTED status code if the master attempts to operate this point


Poin

t Ind

ex

Name / Description




Default Event Class

IEC 61850

Inv Func

Sel

ect/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

No

Ack

Pul

se O

n

Pul

se O

ff

Lat

ch O

n

Lat

ch O

ff

Trip

Clo

se

Cou

nt >

1

Can

cel C

urre

nt O

pera

tion

Chg Cmd

LN Class

LN Inst

Data Object CDC










21 Generic Mode Curve Enable. Enable the currently selected curve >10.

X X X X X X X X X Disabled Enabled 2 2 DGSM n > 10 ModEna SPC VV

22 Mode of operation - Dynamic Reactive Current Support X X X X X X X X X Disabled Enabled 2 2 RDGS 1 ModEna SPC TV31

23

Enable Event-Based Reactive Current Support, in which the moving average voltage and the base reactive current are frozen until after the voltage has returned to within the deadband for a specified hold time. Dynamic Reactive Current Support mode must be Enabled for this setting to apply.

X X X X X X X X X Disabled Enabled 2 2 RDGS 1 EvtModEna SPC TV31

24 Mode of operation - Real Power Smoothing X X X X X X X X X Disabled Enabled 2 2 DOPM 7 OpModWSmth RPS RPS


Poin

t Ind

ex

Name / Description




Default Event Class

IEC 61850

Inv Func

Sel

ect/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

No

Ack

Pul

se O

n

Pul

se O

ff

Lat

ch O

n

Lat

ch O

ff

Trip

Clo

se

Cou

nt >

1

Can

cel C

urre

nt O

pera

tion

Chg Cmd

LN Class

LN Inst

Data Object CDC

25 Mode of Operation - Dynamic Volt-Watt X X X X X X X X X Disabled Enabled 2 2 DOPM 8 OpModDynVW DVW DVW

26 Mode of Operation - Peak Power (Load) Limiting X X X X X X X X X Disabled Enabled 2 2 DOPM 9 OpModPk PPL PPL

27 Mode of Operation - Load / Generation Following X X X X X X X X X Disabled Enabled 2 2 DOPM 10 OpModWFol LGF LGF

28

Repeat Current Regular Schedule. Set whether the currently running schedule shall repeat at the interval that was configured when it was started. Note: this is the currently running schedule, not the currently selected schedule.

X X X X X X X X X Do not Repeat Repeat 2 2 FSCC 1 RepRegSchd SPC SCD

29

Set Schedule 1 Ready Not Ready - schedule is in state <1> Not available Ready - schedule is in one of the following states: <2> Inactive, <3> Ready-to-run, or <4> Running based on the value last written to the corresponding "Time and Date with Interval" object before the schedule was set to Ready.

X X X X X X X X X Not Ready Ready 2 2 FSCH 1 SetReady SPC SCD

30 Set Schedule 2 Ready X X X X X X X X X Not Ready Ready 2 2 FSCH 2 SetReady SPC SCD




Poin

t Ind

ex

Name / Description




Default Event Class

IEC 61850

Inv Func

Sel

ect/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

No

Ack

Pul

se O

n

Pul

se O

ff

Lat

ch O

n

Lat

ch O

ff

Trip

Clo

se

Cou

nt >

1

Can

cel C

urre

nt O

pera

tion

Chg Cmd

LN Class

LN Inst

Data Object CDC









41 Set Schedule n Ready. Set the currently selected schedule >12 to Ready.

X X X X X X X X X Not Ready Ready 2 2 FSCH n > 12 SetReady SPC SCD

42

Enable Sensed Grid Config Detection. If Enabled, the inverter may independently change its Active Settings Group based on locally observed grid conditions. <0> No Autonomous Detection. <1> Autonomous Detection. Inverter's Active Settings Group (AI67) may differ from the Requested Settings Group (AO

X X X X X X X X X Not Ready Ready 2 2 DRCC 1 EnaCfgDet SPC GCF


Poin

t Ind

ex

Name / Description




Default Event Class

IEC 61850

Inv Func

Sel

ect/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

No

Ack

Pul

se O

n

Pul

se O

ff

Lat

ch O

n

Lat

ch O

ff

Trip

Clo

se

Cou

nt >

1

Can

cel C

urre

nt O

pera

tion

Chg Cmd

LN Class

LN Inst

Data Object CDC

43

Islanded Mode. Determines how the DER behaves when in an Islanded configuration. <0> Isochronous Mode. DER attempts to control voltage and frequency independent of configured curves and settings up to the limits of the machine's capabilities in order to achieve nominal voltage (AO25 + AO26) and nominal frequency (AO711) <1> Droop Mode. DER acts as a follower using Volt/VAR curves, Freq/Watt curves, and others as deemed appropriate.

X X X X X X X X X Not Ready Ready 2 2 DRCC 1 EnaCfgDet SPC GCF

44

Storage Limit Units. Determines whether the storage Capacity Rating and Storage Reserve are set in units of Amp-hrs or Watt-hrs. If Amp-hrs is selected (the default), Capacity Rating and Storage Reserve are set using AO53 and AO54. If Watt-hrs is selected, Capacity Rating and Storage Reserve are set using AO915 and AO916.

X X X X X X X X X Amp-hrs (default) Watt-hrs 2 2 n/a INV4


Poin

t Ind

ex

Name / Description




Default Event Class

IEC 61850

Inv Func

Sel

ect/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

No

Ack

Pul

se O

n

Pul

se O

ff

Lat

ch O

n

Lat

ch O

ff

Trip

Clo

se

Cou

nt >

1

Can

cel C

urre

nt O

pera

tion

Chg Cmd

LN Class

LN Inst

Data Object CDC

45

Generic Mode Curve High/Low Limit If the type of the generic curve (AO819) is <6>Must Remain Connected, this value specifies whether the currently selected curve is a Swell (overvoltage) curve or Sag (undervoltage) curve. All points in a swell curve must be greater than 100 percent and all points in a sag curve must be less than 100 percent of nominal voltage. This value is ignored for all other curve types.

X X X X X X X X X Sag Curve (Low Limit)

Swell Curve (High Limit) 2 2 n/a VV

Table 11 – Binary Output Protocol Options

3.3 Binary Output Status and Control Relay Output Block Binary Output Status Group Number: 10 Binary Output Event Group Number: 11 CROB Group Number: 12 Binary Output Command Event Object Num: 13

Capabilities


3.3.1 Minimum pulse time allowed with Trip, Close, and Pulse On commands: ; Fixed at __0__ms � Based on point Index (add column to table in part 5)

3.3.2 Maximum pulse time allowed with Trip, Close, and Pulse On commands: ; Fixed at ___65535__ms � Based on point Index (add column to table in part 5)

3.3.3 Binary Output Status included in Class 0 response:

� Always � Never ;Only if the point is assigned to a class � Based on point Index (add column to table in part 5)

3.3.4 Reports Output Command Event Objects: � Never � Only upon a successful Control ; Upon all control attempts


� Variation 1 – Continuous control ; Variation 2 – Continuous control, binary output status � Based on point Index (add column to table in part 5)


Note: The support for binary output events can be determined remotely using protocol object Group 0 Variation 222.

� Variation 1 – without time ; Variation 2 – with absolute time � Based on point Index (add column to table in part 5)

3.3.7 Command Event Variation reported when variation 0 requested or in response to Class polls:

� Variation 1 – without time ; Variation 2 – with absolute time � Based on point Index (add column to table in part 5)

3.3.8 Event reporting mode: When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event


3.3.9 Command event reporting mode: When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event


3.3.10 Maximum Time between Select and Operate

� Not Applicable � Fixed at _____ seconds


2.2.6 Counters

Table 12 lists the counter points to be used in the DNP3 Profile for Photovoltaic Generation and Storage Systems. Table 13 specifies the options to be used by outstations when reporting these points.

The purpose of these points is to provide the master with a log of the energy transferred in and out of the PV/Storage system that can be used to analyze the efficiency of the system. The values of these points are not intended to represent the output of a revenue-quality meter or to be used for billing purposes.

The following rules apply to these counters:

1. The outstation shall freeze these counters periodically beginning at startup.

2. The master shall control the period of freezing using the Counter Freeze Period analog output (AO ). The time period is in milliseconds (ms). On startup, the default period shall be 5 minutes. If the outstation supports non-volatile storage of parameters, it shall use the last period set by the master on startup.

3. All counters shall be frozen at the same moment. Although IEC 61850 defines a separate freezing period for each counter, outstations implementing this profile shall use a single value to control the freeze period of all counters.

4. The outstation shall not clear (zero) counters when it freezes them. The energy transferred in a given interval can be calculated by subtracting the counter values at the start and end of an interval. Note in Table 13 that all counter values and frozen counter values shall be timestamped.

5. The freezing period is not necessarily aligned with clock time. For instance, if a period of 5 minutes is set, the outstation may freeze the counters at 2 minutes after the hour and 7 minutes after the hour instead of 5 minutes and 10 minutes.

6. The outstation shall implement the following normal behavior of DNP3 counters:

a. As noted in Table 12 and Table 13 , the outstation shall provide the following for each energy value listed:

• a Static Counter with Flag object (g20v1) containing the current value of the counter at any time

• a Static Frozen Counter with Flag and Time object (g21v5) containing the most recently frozen value of the counter and the time it was frozen

b. The Static Counter and the Static Frozen Counter for the same energy value shall have the same point index.

; Configurable, range 1 to 60 seconds � Configurable, selectable from___,___,___ seconds � Configurable, other, describe________________ � Variable, explain _______________________ � Based on point Index (add column to table in part 5)


c. The Static Counter shall update every time the outstation counts an energy value.

d. When the outstation freezes the counters, it shall copy the value in the Static Counter point into the Frozen Counter point and buffer a Frozen Counter Event with Flag and Time object (g23v5) with the same value. It shall update the timestamps on these objects with the time of freezing.

e. The next time the outstation freezes the counters, it will buffer another Frozen Counter event for each point (not just update the value in the first object). In this way, the outstation will build a timestamped log of the energy values in the Frozen Counter Event buffer.

f. At any time after the Frozen Counter Events have been buffered, the master can retrieve them (including timestamps) by reading g23v0 or by reading event class 3 (assuming the master does not reassign the class of these events).

g. After the master has retrieved the Frozen Counter events, it must send a confirmation to the outstation, after which the outstation will clear its buffer. It is assumed the master is responsible for the integrity of the energy log after it has sent the confirmation message.

7. The minimum size of the Frozen Counter Event buffer within the outstation is not specified by this profile. It is noted that a day’s worth of 5-minute energy intervals can be calculated as follows: (4 bytes value + 6 bytes timestamp + 1 byte flag) x 4 counters/event x 12 events/hr x 24 hrs = 12672 bytes minimum, not including any internal overhead, per day.

8. Outstations implementing this profile shall not buffer (non-frozen) Counter Event objects (g22). If the master requests these objects, the outstation shall send a DNP3 null response.

9. All the energy values shall be measured at the connection point, including the total for both generation and storage.

Table 12 – Counter Points List


Default Class Assigned to Counter Events

Frozen Counter Exists

(Yes or No)

Default Class Assigned to Frozen Counter Events

IEC 61850

LN Class

LN Inst

Data Object CDC

110 Real energy supplied to grid (Watt-hours) n/a Yes 3 MMTR 1 SupWh BCR

111 Reactive energy supplied to grid (VAR-hours) n/a Yes 3 MMTR 1 SupVArh BCR

112 Real energy received (demanded) from grid (Watt-hours) n/a Yes 3 MMTR 1 DmdWh BCR

113 Reactive energy received (demanded) from grid (VAR-hours) n/a Yes 3 MMTR 1 DmdVArh BCR


Table 13 – Counter Protocol Options

3.4 COUNTERS/FROZEN COUNTERS Static Counter Group Number: 20 Static Frozen Counter Group Number: 21 Counter Event Group Number: 22 Frozen Counter Event Group Number: 23

Capabilities

3.4.1 Static Counter Variation reported when variation 0 requested or in response to Class polls:

; Variation 1 – 32-bit with flag � Variation 2 – 16-bit with flag � Variation 5 – 32-bit without flag � Variation 6 – 16-bit without flag � Based on point Index (add column to table in part 5)

3.4.2 Counter Event Variation reported when variation 0 requested or in response to Class polls: Note: The support for counter events can be determined remotely using protocol object Group 0 Variation 227.

� Variation 1 – 32-bit with flag � Variation 2 – 16-bit with flag � Variation 5 – 32-bit with flag and time � Variation 6 – 16-bit with flag and time � Based on point Index (add column to table in part 5)

3.4.3 Counters included in Class 0 response:


3.4.4 Counter Event reporting mode: When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event. Only the most recent event is typically reported for Counters. When reporting “only most recent”, the counter value reported in the response may be the value at the time of the original event or it may be the value at the time of the response.

� A: Only most recent (value at time of event) � B: Only most recent (value at time of response) � C: All events � Based on point Index (add column to table in part 5)



Capabilities

3.4.5 Static Frozen Counter Variation reported when variation 0 requested or in response to Class polls:

� Variation 1 – 32-bit with flag � Variation 2 – 16-bit with flag ; Variation 5 – 32-bit with flag and time � Variation 6 – 16-bit with flag and time � Variation 9 – 32-bit without flag � Variation 10 – 16-bit without flag � Based on point Index (add column to table in part 5)

3.4.6 Frozen Counter Event Variation reported when variation 0 requested or in response to Class polls: Note: The support for frozen counter events can be determined remotely using protocol object Group 0 Variation 225.

� Variation 1 – 32-bit with flag � Variation 2 – 16-bit with flag ; Variation 5 – 32-bit with flag and time � Variation 6 – 16-bit with flag and time � Based on point Index (add column to table in part 5)

3.4.7 Frozen Counters included in Class 0 response:


3.4.8 Frozen Counter Event reporting mode: When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event. All events are typically reported for Frozen Counters.

� A: Only most recent frozen value ; B: All frozen values � Based on point Index (add column to table in part 5)

3.4.9 Counters Roll Over at: � 16 Bits (65,535) ; 32 Bits (4,294,967,295) � Other Fixed Value _________ � Configurable; range _________ to__________ �Configurable, selectable from ___,___,___ �Configurable, other, describe________________ �Based on point Index (add column to table in part 5)



Capabilities

3.4.10 Counters frozen by means of: � Master Request ; Freezes itself without concern for time of day � Freezes itself and requires time of day � Other, explain _____________________________


2.2.7 Analog Inputs Table 14 lists the analog input points to be used in the DNP3 Profile for Photovoltaic Generation and Storage Systems. Table 15 specifies the options to be used by outstations when reporting these points.

Note that these are read/only values that represent the current state of the system. Some of these values can be changed using corresponding analog output points listed in section 2.2.8. Other points are measurement points whose values change indirectly depending on the mode of operation of the device. The point numbers for the writeable values and the read/only values are not the same.

Note that support for floating point analog input objects is required by this specification and they shall be the default data format for all analog input points. Floating-point quantities are not scaled by the outstation; they are reported in the units specified in Table 14. For instance, 1kW is reported as 1.0E+3 Watts.

However, per the rules of DNP3, any device that supports floating-point objects must also support integer analog input objects. The “Transmitted Value”, “Scaling” and “Resolution” columns refer only to the situation when integers are specifically requested. When the master makes such a request, the value is to be reported with as little scaling as possible, as specified in Table 14. Only those values typically measured in fractions of an integer (power factor, angle, etc.) shall be scaled. This means that for some systems, the master may need to request 32-bit analog input object variations in order to transmit the data as integers without overflow; e.g. a 50kW real power output cannot be represented with a 16-bit value because it would exceed 32767 Watts.

The Device Profile document for the outstation should not just copy the 32-bit minimum and maximum values shown here, but show the actual maximum and minimum values for the system. Because the actual minimum and maximum of some quantities vary from system to system, a notation of (1%) is shown in the resolution column to indicate that a 1% resolution from the nominal value is preferred.

Support for frozen analog input objects is not required.


Table 14 – Analog Input Points List


Def Evt Cls

Transmitted Value Scaling Units Reso-

lution

IEC 61850 Inv

Func Minimum Maximum Multi-plier

Off-set LN Class LN

Inst Data Object CDC

0 Limited Watts setpoint in use. See section 2.3.6. 2 0 1000 0.1 0 Percent 0.1 DRCT 1 WMaxLimPct ING INV2

1

Discharge/charge setpoint in use. Percentage of maixmum charge rate or discharge rate. Positive means discharging, while negative means charging. See section 2.3.8.

2 -1000 +1000 0.1 0 Percent 0.1 DRCT 1 OutWRte ASG INV4

2 Power factor setpoint in use. See section 2.3.7. 2 -100 +100 0.01 0 None 0.01 DRCT 1 OutPFSet ASG INV3

3 Volt/VAR curve in use. See section 2.3.14. Only valid for the first 10 Volt/VAR curves, and only if just one of them is in used.

2 1 10 1 0 None 1 No longer mapped to IEC 61850

VV11

4

Type of connection point: <0> unknown, <1> DER to local load, <2> DER to local EPS, <3> local EPS with load to area EPS, <4> local EPS w/o load to area EPS <5> other. Most likely value is <1>

3 1 5 1 0 None (list) 1 DOPR 1 ECPType ENS DS93

5

Type of circuit phases: <0> unknown <1> single phase <2> 3-phase <3> delta <4> wye <5> wye-grounded <6> other

3 1 6 1 0 None (list) 1 DOPR 1 CctPhs ENS DS93

6 Number of hours the DER has been connected to the power system 3 0 2147483647 1 0 Hours 1 DRCS 1 OpTmh INS DS93

7 Operational time in seconds since commissioning 3 0 2147483647 1 0 Seconds 1 DPST 1 OpTms INS DS93



Def Evt Cls


lution

IEC 61850 Inv


Off-set LN Class LN


8 Inverter active power output - Present real power output level (negative = charging) 3 -2147483648 2147483647 1 0 Watts 1 MMXU 1 TotW MV DS93

9 Inverter reactive output - Present reactive power output level (negative = absorbing) 3 -2147483648 +2147483647 1 0 VARs (1%) MMXU 1 TotVAr MV DS93

10 Frequency at the connection point 3 0 7000 0.01 0 Hz 0.01 MMXU 2 Hz MV DS93

11 Active power at the connection point 3 -2147483648 2147483647 1 0 Watts (1%) MMXU 2 TotW MV DS93

12 Reactive power at connection point 3 -2147483648 +2147483647 VARs (1%) MMXU 2 TotVAr MV DS93

13 Power factor at the connection point 3 -100 +100 0.01 0 n/a 0.01 MMXU 2 TotPF MV DS93

14 Phase A Volts at connection point 3 0 2147483647 1 0 Volts (1%) MMXU 2 PhV.PhsA.mag WYE DS93

15 Phase A Volts angle 3 0 3600 0.1 0 Degrees 0.1 MMXU 2 PhV.PhsA.ang WYE DS93

16 Phase B Volts at connection point 3 0 2147483647 1 0 Volts (1%) MMXU 2 PhV.PhsB.mag WYE DS93

17 Phase B Volts angle 3 0 3600 0.1 0 Degrees 0.1 MMXU 2 PhV.PhsB.ang WYE DS93

18 Phase C Volts at connection point 3 0 2147483647 1 0 Volts (1%) MMXU 2 PhV.PhsC.mag WYE DS93

19 Phase C Volts angle 3 0 3600 0.1 0 Degrees 0.1 MMXU 2 PhV.PhsC.ang WYE DS93

20 DC Inverter input power 3 0 2147483647 1 0 Volts (1%) MMDC 1 Watt MV DS93

21 DC current level available to inverter 3 0 2147483647 1 0 Amp (1%) MMDC 1 Amp MV DS93

22 DC voltage between PV system and inverter 3 0 2147483647 1 0 Volts (1%) MMDC 1 Vol MV DS93

23 External battery voltage (between battery charger and battery) 3 0 2147483647 1 0 Volts

(1%) ZBAT 1 Vol MV DS93

24 Internal battery voltage 3 0 2147483647 1 0 Volts (1%) ZBAT 1 InBatV MV DS93

25 State of Charge – currently available energy in the battery, as a percentage of capacity rating 3 0 1000 0.1 0 Percent 0.1 ZBAT 1 AhrPct ASG DS93

26 VArs Available that can be produced without impacting active power (Watts) output 2 -

2147483648 2147483647 1 0 VARs (1%) ZINV 1 VArAval MV VV

27 Constant VAr Setpoint in use. Percentage of maximum Watts, maximum VArs, or available VArs. See section ____

2 -1000 1000 0.1 0 Percent 0.1 DRCT 1 VArWMaxPct VArMaxPct, or VArAvalPct

ASG VV



Def Evt Cls


lution

IEC 61850 Inv


Off-set LN Class LN


28 Actual Apparent Power output as percentage of maximum apparent power (VAMax) 2 0 1000 0.1 0 Percent 0.1 DRCS 1 VAPct MV DS93

29 Actual amount of charging as a percentage of maximum apparent charging power (VAChaMax)

2 0 1000 0.1 0 Percent 0.1 DRCS 1 VAChaPct MV DS93

30 Moving Average Voltage used for Dynamic Reactive Current Support 2 0 2147483647 1 0 Volts 1 RDGS 1 Vav MV TV31

31

Present Delta Voltage used for Dynamic Reactive Current Support. Difference in Volts between the present measured Voltage and the Moving Average Voltage (RDGS.Vav) as a percentage of the reference voltage (VRef)

2 0 1000 0.1 0 Percent 1 RDGS 1 DelV MV TV31

32 Reference Power Input for Real Power Smoothing 2 0 2147483647 1 0 Watts 1 MMXN 1 Watt MV RPS

33 Reference Power Input for Peak Power Limiting 2 0 2147483647 1 0 Watts 1 MMXN 2 Watt MV PPL

34 Reference Power Input for Load or Generation Following 2 0 2147483647 1 0 Watts 1 MMXN 3 Watt MV LGF

35 ID of the schedule that is currently controlling inverter operation 2 0 2147483647 1 0 n/a 1 FSCC 1 CtlSchdSt ORC SCD

36

Schedule 1 Status <0> unknown <1> Not available <2> Inactive <3> Ready-to-Run <4> Running

2 0 4 1 0 n/a 1 FSCH 1 SchSt ENS SCD

37

Schedule 1 Active Entry. This is the index of the entry the schedule is currently running. First entry is 1. Zero if the schedule is not running.

2 0 10 1 0 n/a 1 FSCH 1 ActSchEntr INS SCD

38 Schedule 2 Status 2 0 4 1 0 n/a 1 FSCH 2 SchSt ENS SCD

39 Schedule 2 Active Entry 2 0 10 1 0 n/a 1 FSCH 2 ActSchEntr INS SCD





Def Evt Cls


lution

IEC 61850 Inv


Off-set LN Class LN




















60 Schedule n Status. Status of the schedule > 12 currently selected. 2 0 4 1 0 n/a 1 FSCH n SchSt ENS SCD

61 Schedule n Active Entry. Active entry of the schedule >12 selected. 2 0 10 1 0 n/a 1 FSCH n ActSchEntr INS SCD

62

Generic Curve Dependent Variable Snapshot Reference. This is the snapshot value of the dependent variable (Y-Value, e.g. Watts) stored when the independent variable (X-Value, e.g. Frequency) reaches a threshold value. Currently only used with Curve Mode Type <223> Frequency Deviation.

2 See Table 18 FMAR n DeptSnptRef MV FW

22



Def Evt Cls


lution

IEC 61850 Inv


Off-set LN Class LN


63

Overvoltage Disconnect Protection Behavior <0> unknown <1> on <2> on-blocked <3> test <4> test-blocked <5> off

2 0 5 1 0 n/a 1 PTOV 1 Beh ACD MD

64

Overvoltage Disconnect Protection Direction Detected <0> unknown <1> forward <2> backward <3> both

2 0 3 1 0 n/a 1 PTOV 1 Str.dirGeneral ACD MD

65

Undervoltage Disconnect Protection Behavior <0> unknown <1> on <2> on-blocked <3> test <4> test-blocked <5> off

2 0 5 1 0 n/a 1 PTUV 1 Beh ACD MD

66

Undervoltage Disconnect Protection Direction Detected <0> unknown <1> forward <2> backward <3> both

2 0 3 1 0 n/a 1 PTUV 1 Str.dirGeneral ACD MD



Def Evt Cls


lution

IEC 61850 Inv


Off-set LN Class LN


67

Active Settings Group. Note this may differ from the Requested Settings Group or Settings Group Being Edited analog outputs depending on whether communications has been lost and how the Enable Sensed Grid Config Detection binary output is set. <0> Not Used <1> Unspecified / Autonomously Determined (see BO42) <2> Factory Configuration <3> Default Configuration / Comms Lost <4> Normal Grid-Connected Configuration <5> Islanded Condition 1 (small, local island) <6> Islanded Condition 2 (larger, area island) <7> Islanded Condition 3 (largest, regional island) <8> 1st Alternate Grid-Connected Configuration <9> 2nd Alternate Grid-Connected Configuration <10> 3rd Alternate Grid-Connected Configuration <11-255> Reserved for future assignment

2 0 255 1 0 n/a 1 DRCS 1 GridCfgSt ENS GCF

68 Apparent power at the connection point 3 0 2147483647 1 0 VA (1%) MMXU 2 TotVA MV DS93


Table 15 – Analog Input Protocol Options 3.5 ANALOG INPUT POINTS Static (Steady-State) Group Number: 30 Static Frozen Group Number: 31 Event Group Number: 32 Frozen Analog Input Event Group Number: 33 Deadband Group Number: 34

Capabilities

3.5.1 Static Variation reported when variation 0 requested or in response to Class polls: � Variation 1 – 32-bit with flag � Variation 2 – 16-bit with flag � Variation 3 – 32-bit without flag � Variation 4 – 16-bit without flag ; Variation 5 – single-precision floating point with flag � Variation 6 – double-precision floating point with flag � Based on point Index (add column to table in part 5)

3.5.2 Event Variation reported when variation 0 requested or in response to Class polls: Note: The support for analog input events can be determined remotely using protocol object Group 0 Variation 231.

� Variation 1 – 32-bit without time � Variation 2 – 16-bit without time � Variation 3 – 32-bit with time � Variation 4 – 16-bit with time � Variation 5 – single-precision floating point w/o time � Variation 6 – double-precision floating point w/o time ; Variation 7 – single-precision floating point with time � Variation 8 – double-precision floating point with time � Based on point Index (add column to table in part 5)

3.5.3 Event reporting mode: When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event. Only the most recent event is typically reported for Analog Inputs. When reporting “only most recent”, the analog value reported in the response may be the value at the time of the original event or it may be the value at the time of the response.

; A: Only most recent (value at time of event) � B: Only most recent (value at time of response) � C: All events • Based on point Index (add column to table in part 5)

3.5.4 Analog Inputs Included in Class 0 response:



3.5 ANALOG INPUT POINTS Static (Steady-State) Group Number: 30 Static Frozen Group Number: 31 Event Group Number: 32 Frozen Analog Input Event Group Number: 33 Deadband Group Number: 34

Capabilities

3.5.5 How Deadbands are set: � A. Global Fixed ; B. Configurable through DNP � C. Configurable via other means � D. Other, explain _____________________________ � Based on point Index - column in part 5 specifies which of the options applies, B, C, or D

3.5.6 Analog Deadband Algorithm: • simple - just compares the difference from the previous reported value • integrating - keeps track of the accumulated change • other - indicating another algorithm

; Simple � Integrating � Other, explain _____________________________ � Based on point Index (add column to table in part 5)

3.5.7 Static Frozen Analog Input Variation reported when variation 0 requested or in response to Class polls:

� Variation 1 – 32-bit with flag � Variation 2 – 16-bit with flag � Variation 3 – 32-bit with time-of-freeze � Variation 4 – 16-bit with time-of-freeze � Variation 5 – 32-bit without flag � Variation 6 – 16-bit without flag � Variation 7 – Single-precision, floating-point with flag � Variation 8 – Double-precision, floating-point with flag � Based on point Index (add column to table in part 5)


3.5 ANALOG INPUT POINTS Static (Steady-State) Group Number: 30 Static Frozen Group Number: 31 Event Group Number: 32 Frozen Analog Input Event Group Number: 33 Deadband Group Number: 34

Capabilities

3.5.8 Frozen Analog Input Event Variation reported when variation 0 requested or in response to Class polls:

Note: The support for frozen analog input events can be determined remotely using protocol object Group 0 Variation 230.

� Variation 1 – 32-bit without time � Variation 2 – 16-bit without time � Variation 3 – 32-bit with time � Variation 4 – 16-bit with time � Variation 5 – Single-precision, floating-point without time � Variation 6 – Double-precision, floating-point without time � Variation 7 – Single-precision, floating-point with time � Variation 8 – Double-precision, floating-point with time � Based on point Index (add column to table in part 5)

3.5.9 Frozen Analog Inputs included in Class 0 response:

� Always ; Never � Only if point is assigned to Class 1, 2, or 3 � Based on point Index (add column to table in part 5)

3.5.10 Frozen Analog Input Event reporting mode: When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event. All events are typically reported for Frozen Analog Inputs.

� A: Only most recent frozen value � B: All frozen values � Based on point Index (add column to table in part 5)


2.2.8 Analog Outputs Table 16 lists the analog output points to be used in the DNP3 Profile for Photovoltaic Generation and Storage Systems. Table 19 specifies the options to be used by outstations when processing and reporting these points.

Note that support for floating point analog output objects is required by this specification and they shall be the default data format for reporting all analog output points. Floating-point quantities are not scaled by the outstation; they are transmitted in the units specified in Table 16. For instance, 1kW is transmitted as 1.0E+3 Watts.

However, per the rules of DNP3, any device that supports floating-point objects must also support integer objects. The “Transmitted Value”, “Scaling” and “Resolution” columns refer only to the situation when integers are specifically transmitted. When the master makes such a request, the value is to be sent with as little scaling as possible, as specified in Table 16. Only those values typically measured in fractions of an integer (power factor, percent, etc.) shall be scaled. This means that for some systems, the master may need to request or transmit 32-bit analog input object variations in order to transmit the data as integers without overflow; e.g. a 50kW real power output cannot be represented with a 16-bit value because it would exceed 32767 Watts.

This profile includes a set of analog output points that provide a “generic curve” definition used by several different inverter functions. The units and scaling of these points depends on the context in which they are used, as described in Table 17 and Table 18 on page 88. If floating point analog outputs are not used, the master and outstation are expected to use these scaling parameters.

The Device Profile document for the outstation should not just copy the 32-bit minimum and maximum values shown here, but show the actual maximum and minimum values for the system. Because the actual minimum and maximum of some quantities vary from system to system, a notation of (1%) is shown in the resolution column to indicate that a 1% resolution from the nominal value is preferred.

Note that analog output event objects are required.


Table 16 – Analog Output Point List

Point Index Name


Transmitted Value Scaling

Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck

Minimum Maximum Multi-plier

Off- set Chg Cmd LN


0 Time window for Connect/Disconnect X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 1 WinTms ING INV1

1 Timeout period for Connect/Disconnect X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 1 RevtTms ING INV1

2 Time window for limited Watts mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 2 WinTms ING INV2

3 Timeout period for limited Watts mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 2 RevtTms ING INV2

4 Ramp time for limited Watts mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 2 RmpTms ING INV2

5 Time window for fixed power factor mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 3 WinTms ING INV3

6 Timeout period for fixed power factor mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 3 RevtTms ING INV3

7 Ramp time for fixed power factor mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 3 RmpTms ING INV3

8 Time window for charge or discharge rate mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 4 WinTms ING INV4

9 Timeout period for charge or discharge rate mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 4 RevtTms ING INV4

10 Ramp time for charge or discharge rate mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 4 RmpTms ING INV4

11 Time window for price mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 5 WinTms ING INV5

12 Timeout period for price mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 5 RevtTms ING INV5

13 Ramp time for price mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 5 RmpTms ING INV5


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


14

Setpoint for Volt/VAR Modes 1-10. Identifier of the Volt/VAR curve to be used. (zero means Volt/VAR curves are inactive)

X X X 0 2147483647 1 0 None 1 2 2 No longer mapped to IEC 61850 VV

11-12

15

Setpoint for Limited Watts Mode. Maximum allowed Watts as a percentage of Maximum Active Power capability, for combined storage and PV

X X X 0 1000 0.1 0 Percent 0.1 2 2 DRCT 1 WMaxLimPct ING INV2

16

Setpoint for Charge or Discharge Rate Mode. Percentage of maximum charging rate or maximum discharging rate. Positive means discharging, while negative means charging.

X X X -1000 +1000 1 0 Percent 0.1 2 2 DRCT 1 OutWRte ING INV4

17

Setpoint for Fixed Power Factor Mode. Meaning of sign varies depending on convention and quadrant selection settings.

X X X -100 +100 0.01 0 None 0.01 2 2 DRCT 1 OutPFSet APC INV3

18

Sign convention in fixed power factor mode:2 <1> IEC – active power <2> IEEE – lead/lag

1 3 1 0 None 1 2 2 MMXU 1 PFSign ENG INV3

19

Setpoint for Pricing signal mode. Price per (active) kilowatt-hour in one-hundredths of the local currency

X X X -2147483648 2147483647 0.01 0 100ths of Local Currency

0.01 2 2 DCCT 1 PrcCod ING INV5

20 Number of DER units connected to controller X X X 0 Varies. May

not be r/w 1 0 None 1 2 2 DRCT 1 DERNum ING

2 The DNP3 outstation shall respond with the NOT_SUPPORTED status code if the master attempts to change this point


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


21

PV Present Indicator, Storage Present Indicator - enumerated: <0>Unknown, <1> mixed, <2>reciprocating engine <3> fuel cell <4> PV <5> combined heat and power <6> PV and battery storage, <7> Battery storage

X X X 0 7 1 0 None (list) 1 2 2 DRCT 1 DERtyp ENG

22 Maximum Active Power capability X X X 0 2147483647 1 0 Watts (1%) 2 2 DRCT 1 WMax ASG INV2

23 Maximum Apparent Power capability X X X 0 2147483647 1 0 VA (1%) 2 2 DRCT 1 VAMax ASG VV

24 Maximum Reactive Power capability X X X 0 2147483647 1 0 VARs (1%) 2 2 DRCT 1 VArMax ASG VV

25 Reference Voltage (see 2.3.14) X X X 0 2147483647 1 0 Volts (1%) 2 2 DRCT 1 Vref ASG VV

26 Reference Voltage Offset (see 2.3.14) X X X 0 2147483647 1 0 Volts (1%) 2 2 DRCT 1 VrefOfs ASG VV

27

Default maximum ramp rate for active power. Percentage change of maximum active power per minute.

X X X 0 1000 0.1 0 Percent 1 2 2 DRCT 1 WGra ASG INV2

28

Setpoint for minimum reserve for storage, as a percentage of the nominal maximum storage (ZBAT.AhrRtg)

X X X 0 1000 0.1 0 Percent 1 2 2 DRCT 1 MinRsrvPct ING INV4

637 Inverter active power output - high threshold X X X 0 2147483647 1 0 Watts (1%) 2 2 MMXU 1 TotW MV DS93

29 Inverter active power output - low threshold X X X 0 2147483647 1 0 Watts (1%) 2 2 MMXU 1 TotW MV DS93


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


30 Inverter reactive output – high threshold X X X 0 2147483647 1 0 VARs (1%) 2 2 MMXU 1 TotVAr MV DS93

31 Inverter reactive output – low threshold X X X 0 2147483647 1 0 VARs (1%) 2 2 MMXU 1 TotVAr MV DS93

32 Current output frequency – high threshold X X X 0 700 0.1 0 Hz 1 2 2 MMXU 1 Hz MV DS93

33 Current output frequency – low threshold X X X 0 700 0.1 0 Hz 1 2 2 MMXU 1 Hz MV DS93

34 Active power at connection point – high threshold X X X 0 2147483647 1 0 Watts (1%) 2 2 MMXU 2 TotW MV DS93

35 Active power at connection point – low threshold X X X 0 2147483647 1 0 Watts (1%) 2 2 MMXU 2 TotW MV DS93

36 Reactive power at connection point – high threshold X X X 0 2147483647 1 0 VARs (1%) 2 2 MMXU 2 TotVAr MV DS93

37 Reactive power at connection point – low threshold X X X 0 2147483647 1 0 VARs (1%) 2 2 MMXU 2 TotVAr MV DS93

38 Power factor at connection point – high threshold X X X -100 +100 0.01 0 None 0.01 2 2 MMXU 2 TotPF MV DS93

39 Power factor at connection point – low threshold X X X -100 +100 0.01 0 None 0.01 2 2 MMXU 2 TotPF MV DS93

40 Phase A Volts – high threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 MMXU 2 PhV WYE DS93

41 Phase A Volts – low threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 MMXU 2 PhV WYE DS93

42 Phase B Volts – high threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 MMXU 2 PhV WYE DS93

43 Phase B Volts – low threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 MMXU 2 PhV WYE DS93

44 Phase C Volts – high threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 MMXU 2 PhV WYE DS93

45 Phase C Volts – low threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 MMXU 2 PhV WYE DS93


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


46 DC Inverter input power - high threshold X X X 0 2147483647 1 0 Watts (1%) 2 2 MMDC 1 Watt MV DS93

47 DC Inverter input power - low threshold X X X 0 2147483647 1 0 Watts (1%) 2 2 MMDC 1 Watt MV DS93

48 DC input current available – high threshold X X X 0 2147483647 1 0 Amps (1%) 2 2 MMDC 1 Amp MV DS93

49 DC input current available – low threshold X X X 0 2147483647 1 0 Amps (1%) 2 2 MMDC 1 Amp MV DS93

50 DC voltage between PV system and inverter – high threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 MMDC 1 Vol MV DS93

51 DC voltage between PV system and inverter – low threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 MMDC 1 Vol MV DS93

52

Type of storage: <0> n/a, Unknown <1> Lead-acid <2> Nickel-metal hydrate (NiMH) <3> Nickel-cadmium (NiCad) <4> Lithium <5> Carbon zinc <6> Zinc chloride <7> Alkaline <8> Rechargeable alkaline <9> Sodium sulphur (NaS) <10> Flow <99> Other

X X X 0 99 1 0 None (list) 1 2 2 ZBAT 1 BatTyp ENG DS93

53

Capacity Rating - The useable capacity of the storage system in Amp-hrs. Also possible to set Capacity Rating in Watt-hrs using AO915 and BO44.

X X X 0 2147483647 1 0 Amp-Hrs (1%) 2 2 ZBAT 1 AhrRtg ASG INV4


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


54 Storage Reserve in Amp-hrs. Also possible to set Storage Reserve in Watt-hrs using AO916 and BO44.

X X X 0 2147483647 1 0 Amp-Hrs (1%) 2 2 ZBAT 1 MinAhrRtg ASG INV4

55 Maximum Charge Rate X X X 0 2147483647 1 0 Watts (1%) 2 2 ZBAT 1 WChaMax ASG INV4

56 Maximum Discharge Rate X X X 0 2147483647 1 0 Watts (1%) 2 2 ZBAT 1 WDisChaMax ASG INV4

57 Maximum battery charge voltage X X X 0 2147483647 1 0 Volts (1%) 2 2 ZBAT 1 MaxChaV ASG INV4

58 External battery voltage (between battery charger and battery) – high threshold

X X X 0 2147483647 1 0 Volts (1%) 2 2 ZBAT 1 Vol MV DS93

59 External battery voltage (between battery charger and battery) – low threshold

X X X 0 2147483647 1 0 Volts (1%) 2 2 ZBAT 1 Vol MV DS93

60 Internal battery voltage – high threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 ZBAT 1 InBatV MV DS93

61 Internal battery voltage – low threshold X X X 0 2147483647 1 0 Volts (1%) 2 2 ZBAT 1 InBatV MV DS93

62 Volt/VAR Curve 1 Identity X X X 0 2147483647 1 0 n/a 1 2 2 DGSM 1 InCurve ORG VV11

63 Volt/VAR Curve 1 Number of Points X X X 0 10 1 0 n/a 1 2 2 FMAR 1 PairArray. NumPts CSG VV11

64 Volt/VAR Curve 1 Maximum Points X X X 0 10 1 0 n/a 1 2 2 FMAR 1 PairArray. MaxPts CSG VV11

65 Volt/VAR Curve 1 Point 1 Volts X X X 0 +1000 0.1 0 Percent 1 2 2 FMAR 1 PairArray.CrvPts[0].xVal CSG VV11

66 Volt/VAR Curve 1 Point 1 VARs X X X -1000 +1000 0.1 0 Percent 1 2 2 FMAR 1 PairArray.CrvPts[0].yVal CSG VV11




Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



















Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


85 Volt/VAR Curve 1 Time Window X X X 0 2147483647 1 0 Seconds 2 2 DGSM 1 WinTms ING VV11

86 Volt/VAR Curve 1 Ramp Time X X X 0 2147483647 1 0 Seconds 2 2 DGSM 1 RmpTms ING VV11




90-109

Volt/VAR Curve 2 Volt/VAR Curve Points X X X As above As above 1 0 Volts/

Percent 2 2 FMAR 2 PairArray.CrvPts CSG VV11






115-134









Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


140-159








165-184








190-209








Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



215-234








240-259








265-284







Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN




290-309





312 Schedule 1 Identity X X X 0 2147483647 1 0 n/a 1 2 2 FSCH 1 SchdId ING SCD

313

Schedule 1 Category (obsolete) <0> n/a, Unknown <1> Regular <2> Backup <3> Emergency <4> Maintenance <9> Other

X X X 0 9 1 0 n/a 1 2 2 DSCH 1 SchdCat ING SCD

314

Type of schedule 1 (obsolete) <0> n/a, Unknown <1> Energy <2> Contingency reserve

“spinning” <3> Contingency reserve

supplemental <4> Emergency reserve <5> Emission reserve <6> Energy balancing <7> Reactive power <8> Black start <9> Emergency islanding <99> Other

X X X 0 99 1 0 n/a 1 2 2 DSCH 1 SchdTyp ING SCD


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


315 Schedule 1 Num Points X X X 0 10 1 0 n/a 1 2 2 FSCH 1 SchdVal.numPts SCR SCD

316 Schedule 1 Max Points (obsolete) X X X 0 10 1 0 n/a 1 2 2 DSCH 1 Schdxxx.maxPts CSG SCD

317 Sched 1 Point 1 X-value (range) X X X 0 2147483647 Varies 0 Seconds 1 2 2 FSCH 1 SchdVal.tmOffset[ 0 ] SCR SCD

318 Sched 1 Point 1 Y-value (target) X X X -2147483648 2147483647 Varies 0 Varies 1 2 2 FSCH 1 SchdVal.val[ 0 ] SCR SCD




















Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


337

Schedule 1 xVal Meaning (obsolete, always <1> now) <0> n/a, unknown <1> Relative time <2> Temperature <3> Price for active power <9> Other

X X X 0 9 1 0 n/a 2 2 DSCH 1 SchdRng* ING SCD

338

Schedule 1 Value (previously yVal) Meaning <0> Not applicable / Unknown <1> Active power (2.3.6), Percent

of maximum <2> Reserved <3> Power factor ( 2.3.7) <4> Reserved <5> Price for active power (2.3.9) <6> Price for reactive power <7> Reserved <8> Curve Identifier (previously

Volt/VAR Array) (2.3.14) <9> Charge/Discharge rate

(2.3.8), percent of maximum <10> State of Charge (percent of

full charge) <99> Other

X X X 0 99 1 0 n/a 2 2 FSCH 1 SchdVal.valEq ING SCD


340 Schedule 2 Category X X X 0 9 1 0 n/a 1 2 2 DSCH 2 SchdCat ING SCD

341 Schedule 2 Type X X X 0 99 1 0 n/a 1 2 2 DSCH 2 SchdTyp ING SCD


343 Schedule 2 Max Points X X X 0 10 1 0 n/a 1 2 2 DSCH 2 Schdxxx.maxPts CSG SCD


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


344 Schedule 2 Array of Targets X X X -2147483648 2147483647 Varies 0 Varies 2 2 FSCH 2 SchdVal.tmOffset, SchdVal.val SCR SCD

364 Schedule 2 xVal Meaning X X X 0 9 1 0 n/a 2 2 DSCH 2 SchdRng* ING SCD

365 Schedule 2 yVal Meaning X X X 0 99 1 0 n/a 2 2 FSCH 2 SchdVal.ValEq SCR SCD







391 Schedule 3 xVal Meaning X X X 0 9 1 0 n/a 1 2 2 DSCH 3 SchdRng* ING SCD

392 Schedule 3 yVal Meaning X X X 0 99 1 0 n/a 1 2 2 FSCH 3 SchdVal.ValEq SCR SCD













Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN

























Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



















636 ID of schedule to be activated X X X 0 2147483647 1 0 n/a 1 2 2 FSCC 1 RunRegSchd (ORC) SCD

637 Inverter active power output - high threshold X X X 0 2147483647 1 0 Watts (1%) 2 2 MMXU 1 TotW MV SCD


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


638

Schedule 1 Ramp Type (same for all points in schedule) <1> Fixed <2> Ramp <3> Average

X X X 0 3 1 0 n/a 1 2 2 FSCH 1 SchdVal.rmpTyp[0-11] ENG SCD

639 Schedule 2 Ramp Type X X X 0 3 1 0 n/a 1 2 2 FSCH 2 SchdVal.rmpTyp[0-11] ENG SCD











650 Schedule 1 Priority (0 invalid, higher supersedes lower) X X X 0 2147483647 1 0 n/a 1 2 2 FSCH 1 SchdPrio ENG SCD

651 Schedule 2 Priority X X X 0 2147483647 1 0 n/a 1 2 2 FSCH 2 SchdPrio ENG SCD



Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN











662

Schedule Edit Selector. Selects which of the schedules (beyond schedule 12) can be currently viewed and changed, i.e. which is schedule "n".

X X X 13 2147483647 1 0 n/a 1 2 2 FSCC 1

Not mapped. Selects which instance of FSCH greater than 12 is currently visible.

SCD

663 Schedule n Identity X X X 0 2147483647 1 0 n/a 1 2 2 FSCH n SchdId ING SCD

664 Schedule n Priority X X X 0 2147483647 1 0 n/a 1 2 2 FSCH n SchdPrio ENG SCD

665 Schedule n Number of Points X X X 0 9 1 0 n/a 1 2 2 FSCH n SchdVal.numPts SCR SCD

666 Schedule n Meaning of Value (see previous) X X X 0 99 1 0 n/a 1 2 2 FSCH n SchdVal.valEq SCR SCD

667 Schedule n Value 1 X X X 0 2147483647 1 0 n/a 1 2 2 FSCH n SchdVal.val[ 0 ] SCR SCD







Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN
















687 Schedule n Ramp Type 1 X X X 0 3 1 0 n/a 1 2 2 FSCH n SchdVal.RmpTyp[ 0 ] SCR SCD










Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



697 Schedule n Ramp Type 11 X X X 0 3 1 0 n/a 1 2 2 FSCH n SchdVal.RmpTyp[ 10] SCR SCD










707 Schedule n Time Offset 1 X X X 0 2147483647 1 0 Seconds 1 2 2 FSCH n SchdVal.tmOffset[ 0 ] SCR SCD










717 Schedule n Time Offset 11 X X X 0 2147483647 1 0 Seconds 1 2 2 FSCH n SchdVal.tmOffset[ 10] SCR SCD



Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


719 Schedule n Time Offset 13 X X X 0 2147483647 1 0 Seconds 1 2 2 FSCH n SchdVal.tmOffset[ 12 SCR SCD








727 Minimum Voltage X X X 0 2147483647 1 0 Volts (1%) 2 2 DRCT 1 VMin ASG VV

728 Maximum Voltage X X X 0 2147483647 1 0 Volts (1%) 2 2 DRCT 1 Vmax ASG VV

729

VAR Action to take when switching between charging and discharging: <0> Reserved <1> Reverse producing/absorbing

VARs when changing between charging and discharging (go to diagonal quadrant Q1/Q3 or Q2/Q4)

<2> Do not reverse producing/ absorbing Vars (go to adjacent quadrant Q1/Q2 or Q3/Q4)

X X X 0 2 1 0 n/a 1 2 2 DRCT 1 VArAct ENG INV3,VV

730 Maximum Apparent Charging Power X X X 0 2147483647 1 0 VA (1%) 2 2 DRCT 1 VAChaMax ASG INV4

731

Active Power charging gradient (ramp rate) - percentage of Maximum Charging Rate (WChaMax) that the charging rate can change per minute

X X X 0 1000 0.1 0 Percent per min 1 2 2 DRCT 1 WChaGra ASG INV4


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


732

Calculation Method for total apparent power calculation <0> Reserved <1> Vector <2> Arithmetic

X X X 0 2 1 0 n/a 1 2 2 DRCT 1 ClcTotVA ENG

733

Reference for Reactive Power Setpoints. Selects which setpoint is active. Default is <3>. Also specifies whether Watts or VARs take precedence when providing reactive current support. If set to <3>, generating Watts has precedence. At any other setting, reactive current has precedence. <0>Not applicable / Unknown <1> Percent of Maximum Active

Power (WMax) – Not valid in this profile

<2> Percent of Maximum Reactive Power (VArMax) – VAR priority

<3> Percent of Available Reactive Power (VArAval)

<4> Percent of Maximum Reactive Power (VArMax) – Watt priority

X X X 0 3 1 0 n/a 1 2 2 DRCT 1 VArRef ENG VV, TV31

734 Not used in this profile. 3 (Setpoint for Constant VAr mode - % of Max Watts. ) Use AO735 instead.

0 1000 0.1 0 Percent 1 2 2 DRCT 1 VArWMaxPct ASG VV

735 Setpoint for Constant VAr mode - % of Max VArs X X X 0 1000 0.1 0 Percent 1 2 2 DRCT 1 VArMaxPct ASG VV

736 Setpoint for Constant VAr mode - % of Available VArs X X X 0 1000 0.1 0 Percent 1 2 2 DRCT 1 VArAvalPct ASG VV

3 The DNP3 outstation shall respond with the NOT_SUPPORTED status code if the master attempts to change this point


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


737 Time window for Constant VAr mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 6 WinTms ING VV

738 Timeout period for constant VAr mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 6 RevtTms ING VV

739 Ramp time for constant VAr mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 6 RmpTms ING VV

740 Maximum Ramp Rate as percentage of nominal maximum ramp rate

X X X 0 1000 0.1 0 Percent 1 2 2 DRCT 1 RmpRtePct ING

741 Setpoint for Nominal Frequency X X X 0 7000 0.01 0 Hz 1 2 2 DOPR 1 ECPNomHz ASG FW22

742

Dynamic Reactive Current Support - Gradient Mode: <0> Undefined <1> Gradients reach 0 at the moving average Voltage <2> Gradients reach 0 at the Voltage deadbands

X X X 0 2 1 0 n/a 1 2 2 RDGS 1 ArGraMod ENG TV31

743

Deadband Minimum Voltage when applying reactive current support. This is a percentage of the reference voltage (DRCT.Vref), measured from the moving average voltage (RDGS.VAv). Support is no longer applied when the voltage stays above this value for the length of the Hold Time.

X X X 0 1000 0.1 0 Percent 1 2 2 RDGS 1 DbVMin ASG TV31


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


744

Deadband Maximum Voltage when applying reactive current support. This is a percentage of the reference voltage (DRCT.Vref), measured from the moving average voltage (RDGS.VAv). Support is no longer applied when the voltage stays below this value for the length of the Hold Time.

X X X 0 1000 0.1 0 Percent 1 2 2 RDGS 1 DbVMax ASG TV31

745

Reactive Current Support Gradient for Sags. This is the percentage of the rated current (DRAT.ARtg) to apply capacitively per percentage of the negative deviation from the moving average voltage (RDGS.Av). It is a ratio of percent and is therefore unitless.

X X X -2147483648 2147483647 0.001 0 n/a 1 2 2 RDGS 1 ArGraSag ASG TV31

746

Reactive Current Support Gradient for Swells . This is the percentage of the rated current (DRAT.ARtg) to apply inductively per percentage of the positive deviation from the moving average voltage (RDGS.Av). It is a ratio of percent and is therefore unitless.

X X X -2147483648 2147483647 0.001 0 n/a 1 2 2 RDGS 1 ArGraSwell ASG TV31

747

Filter Time for Moving Average Voltage (RDGS.VAv) used to determine amount of dynamic reactive current support

X X X 0 2147483647 1 0 Seconds 1 2 2 RDGS 1 FiltTms ING TV31

748

Block Zone Voltage for applying dynamic reactive current support. This is a percentage of the reference voltage (DRCT.VRef) below which no reactive current support shall be applied.

X X X 0 1000 0.1 0 Percent 1 2 2 RDGS 1 BlkZnV ASG TV31


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


749

Hysteresis Block Zone Voltage for applying dynamic reactive current support. This is a percentage of the reference voltage (DRCT.VRef). After being blocked, reactive current support shall not resume until the voltage has been above BlkZnV + HysBlkZnV.

X X X 0 1000 0.1 0 Percent 1 2 2 RDGS 1 HysBlkZnV ASG TV31

750

Block Zone Time for applying dynamic reactive current support. This is a time in milliseconds from the beginning of any "sag" event, before which dynamic reactive current support will always continue, regardless of how low voltage may sag.

X X X 0 2147483647 1 0 ms 1 2 2 RDGS 1 BlkZnTmms ING TV31

751

Hold Time for applying dynamic reactive current support. When the voltage returns to within the deadband limits (RDGS.dbVMin annd RDGS.dbVMax) for this length of time (measured in milliseconds), the "sag" or "swell" event is considered to be over. Reactive current support ends, frozen values are unfrozen, and a new event can begin.

X X X 0 2147483647 1 0 ms 1 2 2 RDGS 1 HoldTmms ING TV31


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


752

Real Power Smoothing Gradient. This is a signed quantity that establishes the ratio of additional smoothing Watts provided to the present delta-watts of the reference load or generation (MMXN1.Watt). Delta Watts is the difference between the moving average and the present value of the reference power. Positive values of this gradient are for following load (increased reference load results in a dynamic increase in DER output), and negative values are for following generation (increased reference generation results in a dynamic decrease in DER output).

X X X -2147483648 2147483647 0.001 0 n/a 1 2 2 DRCT 1 DRCT.WSmthGra ASG RPS

753

Real Power Smoothing Filter Time. This is the time in seconds used to calculate the moving average of the reference load or generation (MMXN1.Watt) being smoothed.

X X X 0 2147483647 1 0 Seconds 1 2 2 DRCT 1 DRCT.WFilTms ASG RPS

754

Real Power Smoothing Lower Limit. This is a difference in Watts from the moving average of the reference power (MMXN1.Watt) above which no smoothing shall be applied.

X X X 0 2147483647 1 0 Watts 1 2 2 DRCT 1 DRCT.DbWLo ASG RPS

755

Real Power Smoothing Upper Limit. This is a difference in Watts from the moving average of the reference power (MMXN.Watt) below which no smoothing shall be applied.

X X X 0 2147483647 1 0 Watts 1 2 2 DRCT 1 DRCT.DbWHi ASG RPS


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


756 Time window for Real Power Smoothing mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 7 WinTms ING RPS

757 Timeout period for Real Power Smoothing mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 7 RevtTms ING RPS

758 Ramp time for Real Power Smoothing mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 7 RmpTms ING RPS

759

Dynamic Volt-Watt Gradient. This is a signed unit-less quantity that establishes the ratio of additional Watts supplied (expressed in terms of % DRCT.WMax) to the present difference from the moving average voltage (expressed as % DRCT.VRef).

X X X -2147483648 2147483647 0.001 0 n/a 1 2 2 DRCT 1 DynVWGra ASG DVW

760

Dynamic Volt-Watt Filter Time. The time in seconds used to calculate the moving average voltage for dynamic Volt-Watt support.

X X X 0 2147483647 1 0 Seconds 1 2 2 DRCT 1 VWFilTms ASG DVW

761

Dynamic Volt-Watt Lower Deadband. This value is a percentage of the reference voltage (DRCT.Vref) measured below the moving average voltage. If the present voltage is above this value, no additional Watts shall be supplied.

X X X 0 1000 0.1 0 Volts 1 2 2 DRCT 1 DbVWLo ASG DVW

762

Dynamic Volt-Watt Upper Deadband. This value is a percentage of the reference voltage (DRCT.Vref) measured above the moving average voltage. If the present voltage is below this value, no additional Watts shall be supplied.

X X X 0 1000 0.1 0 Volts 1 2 2 DRCT 1 DbVWHi ASG DVW


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


763 Timeout period for Dynamic Volt-Watt mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 8 RevtTms ING DVW

764

Peak Power Limit. This is the target value of the reference load power (MMXN2.Watt). The inverter shall discharge Watts to ensure the reference load does not exceed this limit.

X X X 0 2147483647 1 0 Watts 1 2 2 DRCT 1 DRCT.PkWLim ASG PPL

765 Time window for Peak Power Limiting mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 9 WinTms ING PPL

766 Timeout period for Peak Power Limiting mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 9 RevtTms ING PPL

767 Ramp time for Peak Power Limiting mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 9 RmpTms ING PPL

768

Load/Generation Following Starting Threshold. If this power power level is not exceeded (in absolute value), load/generation following does not occur. Expressed in Watts. The Starting Watt Threshold may be set to zero. Negative means generation, positive means load.

X X X -2147483648 2147483647 1 0 Watts 1 2 2 DRCT 1 WFolStr ASG LGF

769

Load/Generation Following Ratio. This is a configurable setting that controls the ratio by which the DER follows the load once the magnitude of the load exceeds the starting threshold. This setting is a unitless percentage value.

X X X 0 1000 0.1 0 Percent 1 2 2 DRCT 1 WFolRat ASG LGF

770 Timeout period for Load/Generation Following Mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 10 RevtTms ING LGF

771 Ramp time for Load/Generation Following Mode X X X 0 2147483647 1 0 Seconds 1 2 2 DOPM 10 RmpTms ING LGF


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


772

Generic Mode Curve Edit Selector Writing to this point selects which curve (beyond curve number 10) can currently be viewed and changed.

X X X 11 2147483647 1 0 n/a 1 2 2 DGSM FMAR n

Not mapped. Selects which instance of DGSM and FMAR greater than 10 are "visible".

773 Generic Mode Curve Identity X X X 0 2147483647 1 0 n/a 1 2 2 DGSM n InCurve ORG CRV

774 Generic Mode Curve Number of Points X X X 0 20 1 0 n/a 1 2 2 FMAR n PairArray. NumPts CSG CRV

775 Generic Mode Curve Maximum Number of Points (always 20) X X X 0 20 1 0 n/a 1 2 2 FMAR n PairArray. MaxPts CSG CRV

776 Generic Mode Curve Point 1 X-Value X X X See Table 17 0 Varies 1 2 2 FMAR n PairArray.CrvPts[0].x

Val CSG CRV

777 Generic Mode Curve Point 1 Y-Value X X X See Table 18 0 Varies 1 2 2 FMAR n PairArray.CrvPts[0].y

Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV


Val CSG CRV

796 Generic Mode Curve Point 11 X-Value X X X See Table 17 0 Varies 1 2 2 FMAR n PairArray.CrvPts[10].

xVal CSG CRV

797 Generic Mode Curve Point 11 Y-Value X X X See Table 18 0 Varies 1 2 2 FMAR n PairArray.CrvPts[10].

yVal CSG CRV


xVal CSG CRV


yVal CSG CRV


xVal CSG CRV


yVal CSG CRV


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



xVal CSG CRV


yVal CSG CRV


xVal CSG CRV


yVal CSG CRV


xVal CSG CRV


yVal CSG CRV


xVal CSG CRV


yVal CSG CRV


xVal CSG CRV


yVal CSG CRV


xVal CSG CRV


yVal CSG CRV


xVal CSG CRV


yVal CSG CRV

816 Generic Mode Curve Time Window X X X 0 2147483647 1 0 Seconds 1 2 2 DGSM n WinTms ING CRV

817 Generic Mode Curve Ramp Time X X X 0 2147483647 1 0 Seconds 1 2 2 DGSM n RmpTms ING CRV


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


818 Generic Mode Curve Revert Time X X X 0 2147483647 1 0 Seconds 1 2 2 DGSM n RvrtTms ING CRV

819

Generic Mode Curve Mode Type <0> Curve disabled <1> Not applicable / Unknown <2> Volt-Var modes VV11-VV12 <3> Frequency-Watt mode FW22 <4> Watt-Power Factor mode

WP42 <5> Voltage-Watt modes VW51-

VW52 <6> Remain Connected RC <7> Temperature mode TMP <8> Pricing signal mode PS

X X X 0 8 1 0 n/a 1 2 2 DGSM n ModTyp ENG CRV

820

Independent (X-Value) Units for Generic Curve <0> Curve disabled <1> Not applicable / Unknown <4> Time <29> Voltage <33> Frequency <38> Watts <23> Celsius Temperature <129> Percent Voltage <133> Percent Frequency <138> Percent Watts <233> Frequency Deviation

X X X 0 233 1 0 n/a 1 2 2 FMAR n IndpUnits ENG CRV


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


821

Dependent (Y-Value) Units for Generic Curve

<0> Curve disabled <1> Not applicable / unknown <2> VArs as percent of max VArs

(VARMax) <3> VArs as percent of max

available VArs (VArAval) <4> Vars as percent of max Watts

(Wmax) <5> Watts as percent of max

Watts (Wmax) <6> Watts as percent of frozen

active power (DeptSnptRef) <7> Power Factor in EEI notation <8> Volts as a percent of the

nominal voltage (VRef) <99+> Other

X X X 0 255 1 0 n/a 1 2 2 FMAR n DeptRef ENG CRV

822

Generic Curve Time Constant. Time constant of the low-pass filter to be applied to the output of the Generic Mode Curve, in seconds. This is the 3T (tau) value specifying the time at which a step change of the Dependent Variable (e.g. Watts) will settle to 95% of the final value.

X X X 0 2147483647 1 0 Seconds 1 2 2 FMAR n RmpPT1Tms ENG CRV


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


823

Generic Curve Decreasing Max Ramp Rate. The maximum rate at which the dependent value (output, Y-Value) may be reduced in response to changes in the independent value (input, X-Value). This restriction is applied after the low-pass filter. This is represented in terms of % of Reference value (e.g. WMax) per minute .

X X X 0 2147483647 0.1 0 Percent per min 2 2 FMAR n RmpDecDmm ENG CRV

824

Generic Curve Increasing Max Ramp Rate. The maximum rate at which the dependent value (output, Y-Value) may be reduced in response to changes in the independent value (input, X-Value). This restriction is applied after the low-pass filter. This value is represented in terms of % of Reference value (e.g. WMax) per minute .

X X X 0 2147483647 0.1 0 Percent per min 1 2 2 FMAR n RmpIncTmm ENG CRV

825

Generic Curve Release Max Ramp Rate. The maximum rate at which the dependent value (ouput, Y-Value) may be increased after releasing the frozen value of snap shot function. This restriction is applied after the low-pass filter. This value is represented in terms of % of Reference value (e.g. WMax) per minute.

X X X 0 1000 0.1 0 Percent per min 1 2 2 FMAR n RmpRsUp ENG CRV


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


826

Generic Curve Dependent Variable Snapshot Start. Deviation from nominal value of the independent variable (X-Value, e.g. Frequency) at which to take a snapshot of the dependent variable (e.g. WRef) and start constraining the output ( e.g. Watts). Currently only used with Independent Value Units of <223> Frequency Deviation.

X X X see Table 17 depending on Mode Type

0 Varies (1%) 2 2 FMAR n DeptRefStr ENG FW22

827

Generic Curve Dependent Variable Snapshot Stop. Deviation from nominal value of the independent variable (X-Value, e.g. Frequency) at which to release the output (Y-Value, e.g. Watts). Currently only used with Independent Curve Units of <223> Frequency Deviation.

X X X see Table 17 depending on Mode Type

0 Varies (1%) 2 2 FMAR n DeptRefStop ENG FW22

828 Overvoltage Curve Number of Points X X X 0 20 1 0 n/a 1 2 2 PTOV 1 TmVChr33. NumPts CSG MD

829 Overvoltage Curve Maximum Points (always 20) X X X 0 20 1 0 n/a 1 2 2 PTOV 1 TmVChr33. MaxPts CSG MD

830 Overvoltage Curve Point 1 Time X X X 0 2147483647 1 0 ms 1 2 2 PTOV 1 TmVChr33.CrvPts[0].xVal CSG MD

831 Overvoltage Curve Point 1 Percent of Nominal Voltage X X X 0 1000 0.1 0 Percent 1 2 2 PTOV 1 TmVChr33.CrvPts[0].

yVal CSG MD



yVal CSG MD



Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



yVal CSG MD



yVal CSG MD



yVal CSG MD



yVal CSG MD



yVal CSG MD



yVal CSG MD



yVal CSG MD



yVal CSG MD



Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


851 Overvoltage Curve Point 11 Percent of Nominal Voltage X X X 0 1000 0.1 0 Percent 1 2 2 PTOV 1 TmVChr33.CrvPts[10]

.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



.yVal CSG MD



.yVal CSG MD

870 Undervoltage Curve Number of Points X X X 0 20 1 0 n/a 1 2 2 PTUV 1 TmVChr33. NumPts CSG MD

871 Undervoltage Curve Maximum Points (always 20) X X X 0 20 1 0 n/a 1 2 2 PTUV 1 TmVChr33. MaxPts CSG MD

872 Undervoltage Curve Point 1 Time X X X 0 2147483647 1 0 ms 1 2 2 PTUV 1 TmVChr33.CrvPts[0].xVal CSG MD

873 Undervoltage Curve Point 1 Percent of Nominal Voltage X X X 0 1000 0.1 0 Percent 1 2 2 PTUV 1 TmVChr33.CrvPts[0].

yVal CSG MD



yVal CSG MD



yVal CSG MD



yVal CSG MD



yVal CSG MD



Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



yVal CSG MD



yVal CSG MD



yVal CSG MD



yVal CSG MD



yVal CSG MD


893 Undervoltage Curve Point 11 Percent of Nominal Voltage X X X 0 1000 0.1 0 Percent 1 2 2 PTUV 1 TmVChr33.CrvPts[10]

.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD



.yVal CSG MD


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


912

Requested Settings Group <0> Not Used <1> Unspecified / Autonomously

Determined (see BO42) <2> Factory Configuration <3> Default Configuration /

Comms Lost <4> Normal Grid-Connected

Configuration <5> Islanded Condition 1 (small,

local island) <6> Islanded Condition 2 (larger,

area island) <7> Islanded Condition 3 (largest,

regional island) <8> 1st Alternate Grid-Connected

Configuration <9> 2nd Alternate Grid-Connected

Configuration <10> 3rd Alternate Grid-

Connected Configuration <11-255> Reserved for future

assignment

X X X 0 10 1 0 n/a 1 2 2 DRCC 1 GridCfgSel ENG GCF


Point Index Name



Units Reso-lution

Default Event Class

IEC 61850

Inv Func

Sele

ct/O

pera

te

Dire

ct O

pera

te

Dire

ct O

pera

te –

N

o A

ck


Off- set Chg Cmd LN


913

Settings Group Being Edited <0> Not Used <1> Unspecified / Autonomously

Determined (see BO42) <2> Factory Configuration <3> Default Configuration /

Comms Lost <4> Normal Grid-Connected

Configuration <5> Islanded Condition 1 (small,

local island) <6> Islanded Condition 2 (larger,

area island) <7> Islanded Condition 3 (largest,

regional island) <8> 1st Alternate Grid-Connected

Configuration <9> 2nd Alternate Grid-Connected

Configuration <10> 3rd Alternate Grid-

Connected Configuration <11-255> Reserved for future assignment

X X X 0 10 1 0 n/a 1 2 2 DRCC 1 GridCfgEdt ENG GCF

914 Setpoint for maximum State of Charge (percent full) X X X 0 1000 0.1 0 Percent 1 2 2 DRCT 1 ChaMaxPct ASG INV4

915

Capacity Rating - The useable capacity of the storage system in Watt-hrs. Can be used instead of B053 by selecting Watt-hrs in BO44.

X X X 0 2147483647 1 0 Watt-hrs (1%) 2 2 ZBAT 1 WhrRtg ASG INV4

916 Storage Reserve in Watt-hrs. Can be used instead of AO54 by selecting Watt-hrs in BO44.

X X X 0 2147483647 1 0 Watt-hrs (1%) 2 2 ZBAT 1 MinWhrRtg ASG INV4


Table 17 – Scaling for Generic Curve Independent Variables (X-Value) Independent Variable (X-Value) Units AO 820 (FMAR.IndpUnts)

Generic Curve Mode Type AO 819 (DGSM.ModTyp) Min Max Multiplier Units

<0> Curve disabled <0> Curve disabled -- -- -- --

<1> Not applicable / Unknown <1> Not applicable / Unknown -- -- -- --

<4> Time <6> Remain connected 0 2147483647 1 ms

<29> Voltage <2> Volt-VAr modes VV11-VV12 0 2147483647 1 Volts

<33> Frequency <3> Frequency-Watt mode FW22 0 7000 0.01 Hz

<38> Watts <4> Watt-Power Factor mode WP42 0 2147483647 1 Watts

<23> Celsius Temperature <7> Temperature mode -5000 5000 0.1 Degrees

<100> Price in hundredths of local currency <8> Price Signal -2147483648 2147483647 0.01 100ths of local currency

<129> Percent Voltage (of VRef - AO25) <2> Volt-VAr modes VV11-VV12 <5> Voltage-Watt modes VV51-VV52 0 1000 0.1 %

<133> Percent Frequency (of ECPNomHz - AO741) <3> Frequency-Watt mode FW22 0 1000 0.1 %

<138> Percent Watts (of WMax - AO22) <4> Watt-Power Factor mode WP42 0 1000 0.1 %

<233> Frequency Deviation <3> Frequency-Watt mode FW22 0 7000 0.01 Hz


Table 18 – Scaling for Generic Curve Dependent Variables (Y-Value) Dependent Variable (Y-Value) Units AO821 (FMAR.DeptRef)

Generic Curve Mode Type AO819 (DGSM.ModTyp) Min Max Multiplier Units

<0> Curve disabled <0> Curve disabled -- -- -- --

<1> Not applicable / unknown <1> Not applicable / Unknown -- -- -- --

<2> VArs as percent of max VArs (VArMax - AO24) <2> Volt-VAr modes VV11-VV12 -1000 1000 0.1 %

<3> VArs as percent of max available VArs (VArAval - AI26) <2> Volt-VAr modes VV11-VV12 -1000 1000 0.1 %

<4> Vars as percent of max Watts (WMax - AO22) <2> Volt-VAr modes VV11-VV12 -1000 1000 0.1 %

<5> Watts as percent of max Watts (WMax - AO22) <3> Frequency-Watt mode FW22 <5> Voltage-Watt modes VV51-VV52 0 1000 0.1 %

<6> Watts as percent of frozen active power (DeptSnptRef - AI62) <3> Frequency-Watt mode FW22 0 1000 0.1 %

<7> Power Factor in EEI notation <4> Watt-Power Factor mode WP42 -100 100 0.01 None

<8> Volts as a percent of nominal Voltage (VRef, AO25 + AO26) <6> Remain connected 0 1000 0.1 %

<99+> Other NOTE: This profile does not require that an outstation support any particular Y-Value Units (e.g. Watts) for Mode Type of <7> Temperature or <8> Price Signal. It is possible that an outstation may permit the master to choose between different Y-Value units by selecting a different value in AO821.


Table 19 – Analog Output Protocol Options

3.6 ANALOG OUTPUT STATUS and ANALOG OUTPUT CONTROL BLOCK Analog Output Status Group Number: 40 Analog Output Control Block Group Number: 41 Analogue Output Event Group Number: 42 Analogue Output Command Event Group Number: 43

Capabilities

3.6.1 Static Analog Output Status Variation reported when variation 0 requested or in response to Class polls:

� Variation 1 – 32-bit with flag � Variation 2 – 16-bit with flag ; Variation 3 – single-precision floating point with flag � Variation 4 – double-precision floating point with flag � Based on point Index (add column to table in part 5)

3.6.2 Analog Output Status Included in Class 0 response:

� Always � Never (must poll for them separately) ; Only if the point is assigned to a class � Based on point Index

3.6.3 Reports Output Command Event Objects: � Never � Only upon a successful Control ; Upon all control attempts


Note: The support for analog output events can be determined remotely using protocol object Group 0 Variation 219.

� Variation 1 – 32-bit without time � Variation 2 – 16-bit without time � Variation 3 – 32-bit with time � Variation 4 – 16-bit with time � Variation 5 – single-precision floating point w/o time � Variation 6 – double-precision floating point w/o time ; Variation 7 – single-precision floating point with time � Variation 8 – double-precision floating point with time � Based on point Index (add column to table in part 5)


3.6 ANALOG OUTPUT STATUS and ANALOG OUTPUT CONTROL BLOCK Analog Output Status Group Number: 40 Analog Output Control Block Group Number: 41 Analogue Output Event Group Number: 42 Analogue Output Command Event Group Number: 43

Capabilities

3.6.5 Command Event Variation reported when variation 0 requested: � Variation 1 – 32-bit without time � Variation 2 – 16-bit without time � Variation 3 – 32-bit with time � Variation 4 – 16-bit with time � Variation 5 – single-precision floating point w/o time � Variation 6 – double-precision floating point w/o time ; Variation 7 – single-precision floating point with time � Variation 8 – double-precision floating point with time � Based on point Index (add column to table in part 5)

3.6.6 Event reporting mode: When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event.

; Only most recent � All events

3.6.7 Command Event reporting mode: When responding with event data and more than one event has occurred for a data point, an Outstation may include all events or only the most recent event.

; Only most recent � All events

3.6.8 Maximum Time between Select and Operate: � Not Applicable � Fixed at _____ seconds ; Configurable, range ___1___ to ___30___ seconds � Configurable, selectable from___,___,___seconds � Configurable, other, describe________________ � Variable, explain _______________________ � Based on point Index (add column to table in part 5)


2.2.9 Other Data Types To set the time and repeat interval for activating the next operating schedule to be enabled, the master shall perform a WRITE (0x02) function code to point index number 0 of the Indexed Time and Date: Absolute Time with Long Interval Objects (g50v4) using qualifier 0x17. The use of this object is defined in IEEE Std. 1815-2012.

To set the time and repeat interval for internal freezing of all counters on the outstation, the master shall perform a WRITE (0x02) function code to point index number 1 of these objects, as shown in Table 20.

Table 20 – Indexed Date and Time: Indexed Absolute Time with Long Interval Objects


IEC 61850

LN Class LN Inst Data Object CDC

0 Start Time and Interval to perform the next schedule that is enabled DSCH strTm, schdRepPer TNG, ING

1 Start Time and Interval to regularly freeze all counters MMTR 1 (all).frPd, (all).strTm BCR

Some of the PV system status information required by the DIFG specification is available online as Device Attribute (g0) objects. (See Annex A of IEEE 1815). These are highlighted in Table 21 and Table 22.

Table 21 contains all the standard Device Attribute objects, found by reading point number 0 of object group 0. The outstation shall provide all of these objects to the master when the master requests them, as indicated in section 2.6. Note that further information regarding the time synchronization source and accuracy shall also be provided by the outstation in section 10.1 of the Device Profile document.

Table 22 contains Device Attribute objects that are specific to this DNP3 PV/Storage Profile, found by reading point number 2 of object group 0. Point number 1 of object group 0 is left for any vendor-specific device attributes the outstation may report. The attributes in Table 22 are nameplate ratings. They are not writeable. The structure of these Device Attribute objects is shown below the table.

When the master reads the “Identifier of support for user-specific attributes” at Group 0 Variation 211, point index 0, the outstation shall identify the namespace of the Device Attribute objects in Table 22 as follows:

• Attribute data type code: 1 (VSTR)

• Length: 19

• User attribute set: “PVStorage.Basic, 2”


If the device supports additional user attribute sets, their namespace identifiers shall be included in the User Attribute Set string along with “PVStorage.Basic, 2” as described in the DNP3 specification.

Table 21 – Standard Device Attribute Objects (Point Number 0)

Group 0 Variation Name / Description

IEC 61850


211 Device Attributes – Identifier of support for user-specific attributes

212 Device Attributes – Number of master-defined data set prototypes

213 Device Attributes – Number of outstation-defined data set prototypes

214 Device Attributes – Number of master-defined data sets

215 Device Attributes – Number of outstation-defined data sets

216 Device Attributes – Max number of binary outputs per request

217 Device Attributes – Local timing accuracy LTMS 1 TmAcc INS

218 Device Attributes – Duration of timing accuraccy LTMS 1 TmAcc INS

219 Device Attributes – Support for analog output events

220 Device Attributes – Max analog output index

221 Device Attributes – Number of analog outputs

222 Device Attributes – Support for binary output events

223 Device Attributes – Max binary output index

224 Device Attributes – Number of binary outputs

225 Device Attributes – Support for frozen counter events

226 Device Attributes – Support for frozen counters

227 Device Attributes – Support for counter events

228 Device Attributes – Max counter index

229 Device Attributes – Number of counter points

230 Device Attributes – Support for frozen analog inputs

231 Device Attributes – Support for analog input events

232 Device Attributes – Maximum analog input index



IEC 61850


233 Device Attributes – Number of analog input points

234 Device Attributes – Support for double-bit binary input events

235 Device Attributes – Maximum double-bit binary input index

236 Device Attributes – Number of double-bit binary input points

237 Device Attributes – Support for binary input events

238 Device Attributes – Max binary input index

239 Device Attributes – Number of binary input points

240 Device Attributes – Max transmit fragment size

241 Device Attributes – Max receive fragment size

242 Device Attributes – Device manufacturer’s software version

243 Device Attributes – Device manufacturer’s hardware version

244 Not available – Reserved for future assignment

245 Device Attributes – User-assigned location name

246 Device Attributes – User-assigned ID code/number

247 Device Attributes – User-assigned device name

248 Device Attributes – Device serial number LPHD 1 PhyNam DPL

249 Device Attributes – DNP subset and conformance

250 Device Attributes – Device manufacturer’s product name and model LPHD 1 PhyNam DPL


252 Device Attributes – Device manufacturer’s name LPHD 1 PhyNam DPL


254 Device Attributes – Non-specific all attributes request

255 Device Attributes – List of attribute variations


Table 22 – PV/Storage Device Attribute Objects (Point Number 2)


IEC 61850


1 - 248 Reserved

249 Nameplate rating – Amps DRAT 1 ARtg ASG

250 Nameplate rating – Volts DRAT 1 VRtg ASG

251 Nameplate rating – Watts DRAT 1 WRtg ASG

252 Nameplate rating - VA DRAT 1 VARtg ASG

253 Nameplate rating – VAR DRAT 1 VarRtg ASG

254 Device Attributes – Non-specific all attributes request

255 Device Attributes – List of attribute variations


The following structure describes the nameplate rating attribute objects for Group 0 (point index 2) variations 250, 251, 252 and 253.

Pictorial

octet transmission order ↓

7 6 5 4 3 2 1 0 ← bit position Attribute data type code

Length

Nameplate rating

Formal structure UINT8: Attribute data type code.

Specifies the attribute data type code, UINT. (Refer to section 1 of the DNP3 Data Object Library.)

UINT8: Length.

Specifies the number of octets in the attribute. This octet is always 4 for these attributes.

UINT32: The nameplate rating: Watts, VA or VAR

The rated Watts, VA or VARs for this device


2.3 Inverter Modes and Functions This section describes specifically how to use DNP3 to implement the modes and functions of a photovoltaic generation and storage system that are identified in the IEC 61850-90-7 technical report and the EPRI document Common Functions for Smart Inverters. The sub-sections that follow list the steps described in that document and identify which DNP3 function codes, data types and point numbers shall be used to implement them.

Each function has an abbreviation e.g. VV for Volt/VAR management, RPS for Real Power Smoothing. These are defined in the title of each sub-section that follows and are used in the “Inverter Function” or “Inv Func” columns of various tables in this document to illustrate which data points apply to each function.

In the tables that follow, the DNP3 data types are abbreviated: BI – binary input; DBBI – double-bit binary input; BO – binary output; CTR – counter, AI – analog input; and AO – analog output.

NOTE: The tables that follow have an “Optionality” column. If this column contains the word “Optional” this means that the master or outstation may not need to perform the step every time it executes the function. It does not mean that the master or outstation is not required to implement the necessary DNP3 features to support the step. To ensure interoperability, all outstations and masters conforming to this profile shall be capable of performing all the steps described for a particular function, given that it implements that function.

2.3.1 Timing Parameters

The control-oriented functions described herein each include three parameters that affect the timing of the function:

• A Time window within which to randomly execute the command. If the time window is zero, the command will be executed immediately.

• A Reversion timeout period, after which the function will be disabled.

• A Ramp time for the system to gradually move from its current settings to the new settings (if applicable), beginning after the Time Window.

When the outstation restarts, the outstation shall set these parameters to default values preconfigured at the outstation. In addition, the values specified in Table 23 have special meanings.

Table 23 – Values for Timing Parameters Parameter Meaning of Zero Meaning of 0xFFFF

Time Window Execute the command immediately Use default value

Timeout Period Infinity; never time out Use default value

Ramp Time Change to the new setting immediately Use default value

2.3.2 Generic Curves and Schedules

As discussed in section 2.1.3, this profile defines several new functions in addition to those described in the AN2011-001 DNP3 Profile for Basic Photovoltaic Generation and Storage. Most of these new functions require the definition of a curve, i.e. a set of “X-values” and “Y-values” expressing a


relationship between a measured quantity and a desired output. To accommodate these new functions without adding an excessive number of DNP3 data points, this profile uses the concept of a “generic curve” as illustrated in Figure 3.

Figure 3 – Generic Curve Concept

In the Basic Profile, the only curves defined were Volt/VAR curves. As shown in Figure 3, there were up to ten of them permitted, defined by ten sequential blocks of DNP3 analog output points. These blocks of points are retained in this Advanced Profile for backward compatibility, however are not recommended for use in new designs.

To permit the definition of a larger number of curves, and so that curves can be defined for many different functions, this Advanced Profile includes one additional block of analog output points to define a “generic” curve. This block of points permits just one curve beyond the first ten to be read or modified by the master at any time. However, because this block of points may describe one of many curves, the maximum number of possible curves is only limited by the resources of the outstation.

The value of the Generic Curve Edit Selector point (AO772) determines which curve is “visible” to the master at any time. To create a new curve, the master performs the following steps:

1. Changes the Edit Selector to an index number that has not yet been used. The master may be managing which curves are in use on the outstation using the master’s own internal records, or the master may be able to identify an available curve by reading that the number of points in the curve (AO774) is zero and/or the curve is disabled (BO21). If the master attempts to select a curve that does not exist on the outstation, the outstation shall respond to the request with a PARAMETER ERROR internal indication.

Outstation

Curve #n

Curve #13

Volt/VAR Curve #1AO65

AO86

Volt/VAR Curve #2AO87

AO111 …

Volt/VAR Curve #10A287

AO311

Generic CurveAO773

AO818

Curve #12

Curve #11

AO772 Generic Curve Edit Selector

Communicationswith Master

Defined in Basic Profile

• Identity• Num Points• Max Points• X-Values, Y-Values• Curve Type• X and Y Value Units• Timing Parameters


2. Modifies points that define the type (AO819 ) and units (AO820 and AO821 ) for each curve. For instance, instead of a Volt/VAR curve, the curve may be a Frequency-Watt curve, or a Watt-Power Factor curve.

3. Modifies DNP3 data points that define the number of curve points (AO774) and X and Y-Values of each curve (AO776 through AO815). As in the original Volt/VAR curve definitions, the active curve points in the generic curve are defined in a contiguous block starting at the lowest index of the DNP3 point array. A contiguous block of higher-numbered DNP3 points will be unused depending on the number of curve points specified.

4. Modifies points that affect the timing and filtering of the outstation’s response to the curve

5. Enables the curve by writing to the Generic Mode Curve Enable point (BO21). This is a different process than that defined in the Basic Profile, which required writing the Identifier of the curve to AO14. Use of the Generic Curve Edit Selector (AO772) and the Generic Mode Curve Enable point (BO21) permits multiple curves to be enabled at once. Once enabled, the curve remains enabled even if the master selects a different curve for viewing or modification. In general, only one curve of each type (e.g. Volt/VAR) may be enabled at one time, and some types of curves cannot be enabled simultaneously. Refer to 2.4.4 for details of the precedence of curves and settings.

AO14 may still be used by the master to set which Volt/VAR curve is active at a time, but it will disable any other Volt/VAR curves currently active.

This is a general overview of the process. The specific steps and values required to implement each function are defined in the sections that follow.

In addition to the Generic Curve points, the Advanced Profile also includes points for a Generic Schedule, so there is no longer a limitation on the number of schedules the master can define. The blocks of points for the 12 schedules permitted in the Basic Profiles are retained for backward compatibility but not recommended for future use. Also note that price-based or temperature-based schedules are not permitted in the Advanced Profile. Price-based and temperature-based functions are now correctly identified as types of curve functions rather than schedules.

Both the Generic Curve and Generic Schedule definitions permit the master to define up to 20 points. In the Basic Profile, this limitation was 10 points.

Two curves in this Advanced Profile are not defined using the Generic Curve: the Must Disconnect curves for Overvoltage and Undervoltage described in 2.3.18. These are defined in separate blocks of points because they are mapped to different logical nodes in an IEC 61850 data model than the generic curve. The Must Remain Connected curves, however, are defined using the Generic Curve because there are no other corresponding IEC 61850 logical nodes that perform this function.

2.3.3 General Response-Time Filtering The functions described in the following sections that define a curve relating two values may use the parameters described in Table 24 to filter the response time of the output from the function. This filtering may be applied to prevent damage to the equipment or to reduce undesirable fast variations in the output of the DER.


Table 24 – Response Filtering Parameters Parameter Description Analog

Output

Generic Curve Time Constant

Time constant of the first-order low-pass filter to be applied to the output of the Generic Mode Curve, in seconds. This is the 3T (tau) value specifying the time over which the Dependent Variable (e.g. Watts) will settle to 95% of the final value in response to a step change in the independent (controlling) variable, as shown in Figure 4.

822

Generic Curve Decreasing Max Ramp Rate

The maximum rate at which the dependent value (output, Y-Value) may be reduced in response to changes in the independent value (input, X-Value). This restriction is applied after the low-pass filter. This is represented in terms of % of Reference value (e.g. WMax) per minute .

823

Generic Curve Increasing Max Ramp Rate

The maximum rate at which the dependent value (output, Y-Value) may be increased in response to changes in the independent value (input, X-Value). This restriction is applied after the low-pass filter. This value is represented in terms of % of Reference value (e.g. WMax) per minute .

824

The Low-Pass filter is a simple first-order filter with a frequency response magnitude given by:

2)(11ωτ+

=Input

Output

And in the time domain:

Output = Input * ( 1 - e t/τ)

Where ω = 2π*frequency and τ = the time constant of the filter (AO822).

Figure 4 – Example Time Domain Response from First-order Low-Pass Filter

Wat

t Lim

it

Time

Input

Output

95% settled in 3 τ


Figure 5 illustrates how the parameters listed in Table 24 are applied together to affect the output of the function. The low-pass filter defined by the Time Contant (AO822) is applied first to the output of the curve, followed by the Max Ramp Rates (AO823 and AO824).

Figure 5 – Response-Time Filtering Block Diagram

2.3.4 Use of Broadcasting The sections which follow specify the interactions between master and outstation assuming that the master is performing the functions on a single outstation. However, it is also envisioned that the master may wish to perform the same functions on many inverters at once. To do so, in Table 25 through Table 48 the following rules apply:

• The master shall send all messages to the Broadcast Address 0xFFFF.

• The master shall substitute “Direct Operate – No Acknowledgement” for any step with “Direct Operate / Response” or “Select/Response, Operate/Response” in the “Function Codes” column to prevent responses from multiple outstations. Note that this lessens the potential reliability of the operation unless follow-up queries are made on a device-by-device basis to verify receipt.

• The master shall omit any step with “Read / Response” in the Function Codes column to avoid flooding the communications network with responses from many devices at once.

The outstation shall permit a user to configure the ability to accept broadcast messages. If the outstation is configured to not accept broadcast messages, it shall return the INVALID PARAMETER internal indication when it receives a broadcast request and shall not perform the function.

2.3.5 Function INV1: Connect/Disconnect

The steps in Table 25 describe how to cause the photovoltaic generation and/or storage system to physically connect or disconnect from the grid. This function refers to the operation of the DER Connect/ Disconnect” switch identified in Figure 1. It disconnects the DER from both the utility and local customer loads and leaves any local loads connected to the grid. This function is not the same as an activation of the “Utility Switch” which would leave the DER connected to local loads.

The outstation shall start the time window and reversion timeout at the moment the master successfully delivers the switch control command. Since the switch position is not an analog value, there is no ramp time parameter associated with this function.

Y

X

Y

frequency time

Utility-Defined Curve Low-Pass Filter Linear Ramp Rates


Table 25 – Steps to perform a Connect/Disconnect using the DNP3 PV Profile

Step Description Optionality Function Codes Data Type

Point Number

1. Set time window Optional Direct Operate / Response AO 0 2. Set reversion timeout Optional Direct Operate / Response AO 1

3. Retrieve status of switch Optional Read / Response or Unsolicited Response DBBI 0

4. Issue switch control command and receive response

Required Select / Response, Operate / Response BO 0

2.3.6 Function INV2: Adjust Maximum Generation Level Up/Down The steps in Table 26 describe how to set the maximum generation level of the photovoltaic generation and/or storage system at the electrical coupling point as a percentage of its nominal capacity. The outstation shall start the time window, reversion timeout, and ramp time at the moment the master successfully operates the mode enable command.

The setpoint for maximum active power generation is calculated as follows:

Setpoint for Limited Watts Mode (AO15) =

Desired Maximum Active Power (Watts) x 100 %

Maximum Active Power Capability (AO22)

Table 26 – Steps to adjust maximum generation using the DNP3 PV Profile


Point Number

1. Set time window Optional Direct Operate / Response AO 2 2. Set reversion timeout Optional Direct Operate / Response AO 3 3. Set ramp time Optional Direct Operate / Response AO 4

4. Retrieve Maximum Active Power Capability Optional Read / Response AO 22

5. Set maximum output in percent of nominal Watts Required Direct Operate / Response AO 15

6. Enable limited Watts mode and receive response Required Select / Response,

Operate / Response BO 1

2.3.7 Function INV3: Adjust Power Factor

The steps in Table 27 describe how to set the power factor produced by the photovoltaic generation and/or storage system. The outstation shall start the time window, reversion timeout, and ramp time at the moment the master successfully operates the mode enable command. Note that this function and the Volt/VAr mode (VV) functions are mutually exclusive, it only being possible for one or the other to be in effect at any time.


Table 27 – Steps to adjust power factor using the DNP3 PV Profile


Point Number


4.

Set whether to reverse production/absorbtion of VARs when switching between generating or storing active power

Optional Direct Operate / Response AO 729

5. Set fixed power factor Required Direct Operate / Response AO 17

6. Enable fixed power factor mode and receive response Required Select / Response,


In IEC 61850 and in this profile, power factor is a signed value between -1.00 and +1.00. Both -1.00 and +1.00 produce the same result, no VARs. A PF setting of Zero is not allowed. In IEC 61850, the meaning of the sign of the value varies depending on the sign convention used, as shown in Figure 6:

• IEC, in which supplying or generating active power is positive and demanding active power is negative

• IEEE, in which a leading (capacitive) power factor is positive and a lagging (inductive) power factor is negative

IEC 61850 provides a parameter, DRCC.OutPFSign, which normally permits changing the sign convention between IEC and IEEE. This parameter is readable in this profile as AO18.

However, in this photovoltaic / storage profile, the IEEE convention is always used. The outstation shall reject any attempt to change AO18 by responding with the NOT_SUPPORTED status code. .

Similarly, IEC 61850 also provides a parameter to force whether the system must produce VARs or absorb VARs. This profile makes this parameter visible in BO8 but the outstation shall reject any attempt to issue a control to change this value by responding with the NOT_SUPPORTED status code.

The use of the IEEE sign convention means that for a given signed power factor setting, the system normally moves diagonally between quadrants, either Q1/Q3, or Q2/Q4, as the direction of active power flow varies. For instance, a system commanded to use a negative power factor shall by default be permitted to move from generating both active power and VARs in Q1 to charging the battery and absorbing VARs in Q3, along a diagonal line in Figure 6.

If it is desired that the VAR action should remain the same when switching between charging and discharging, this Advanced Profile permits that choice to be made by writing to AO729. When the value of <2> Do Not Reverse is written to this point, the system will move between adjacent quadrants, either Q1/Q2 or Q3/Q4, when it switches from charging to discharging and vice versa. This parameter also applies to all the Volt/VAR (VV) functions. In the Basic Profile, this parameter was not available and the DER always reversed VAR direction when switching active power direction.


Figure 6 – Power Factor Sign Conventions

2.3.8 Function INV4: Charge/Discharge Storage The steps in Table 29 describe how to directly manage the charging and discharging of the storage portion of the photovoltaic generation and/or storage system. The outstation shall start the time window, reversion timeout, and ramp time at the moment the master successfully operates the mode enable command.

When discharging, the setpoint is calculated as follows:

Setpoint for Charge or Discharge Rate (AO16) =

Desired Discharge Rate (Watts) x 100 %

Maximum Discharge Rate (AO56)

When charging, the setpoint is calculated as follows:

Setpoint for Charge or Discharge Rate (AO16) =

Desired Charge Rate (Watts) x -100 %

Maximum Charge Rate (AO55)

Note that the setpoint is negative when charging is desired. 2013-01-14 AN2013-001 DNP3 Profile for Advanced PV Generation and Storage

When charging, the outstation will continue to charge at the selected rate until the Maximum State of Charge (percent full) is reached (AO914).

When discharging, the outstation will continue to discharge at the selected rate until the Minimum Storage Reserve (percent full) is reached (AO28).

If the Charge or Discharge Rate (AO16) is changing as a result of a schedule or a curve, the amount this setpoint can change per minute is limited by the Active Power Charging Gradient (AO731). Charging and discharging active power is also limited by the Maximum Apparent Charging Power (AO730).

The present State of Charge (AI25) can be read by the master at any time.

The Maximum State of Charge (AO914), the present State of Charge (AI25) and the Minimum Storage Reserve (AO28) are expressed as percentage of the Capacity Rating. The Capacity Rating and the absolute minimum Storage Reserve may be set in units of either Amp-hrs or Watt-hrs, as shown in Table 28. The Storage Limit Units point (BO44) selects which pair of analog outputs are used. The outstation shall ignore the pair of analog outputs that are not selected. By default, Amp-hrs is used for backward-compatibility with the Basic Profile, but Watt-hrs is preferred for new implementations. Note that using Amp-hrs as a measure of storage capacity assumes a nominal DC voltage. The documentation for the storage system shall describe how this assumption is calculated.

Table 28 – Setting Storage Limits When Storage Limit Units (BO44)

is set to Capacity Rating is set using Storage Reserve is set using

<0> Amp-hrs (default) AO53 AO54 <1> Watt-hrs (1) AO915 AO916

The outstation will raise alarm indications (BI62, BI63, BI64) if any of these limits are exceeded. The relationship between these values is illustrated in Figure 7.

Figure 7 – Relationships Between Storage Parameters

Minimum Reserve (% Capacity Rating, e.g. 20%)

Nameplate Capacity(Watt-hrs)

Capacity Rating (Amp-hrs or Watt-hrs)

State of Charge (% Capacity Rating, e.g. 70%)

Storage Reserve(Amp-hrs or Watt-hrs)

100% Capacity RatingMax State of Charge (% Capacity Rating, e.g. 85%)


Table 29 – Steps to charge or discharge storage using the DNP3 PV Profile


Point Number


4. Set Maximum Apparent Charging Power if not already set


5. Set Active Power Power Charging Gradient if not already set


6. Set Battery Capacity Rating (Amp-Hrs) Optional Direct Operate / Response AO 53

7. Set Absolute Storage Reserve (Amp-Hrs) Optional Direct Operate / Response AO 54

8. Set Maximum State of Charge (percent of Battery Capacity Rating)


9. Set Minimum Storage Reserve (percent of Battery Capacity Rating)


10. Set discharge/charge rate. Positive is discharging, negative is charging.

Required Direct Operate / Response AO 16

11. Enable charge/discharge mode and receive response Required Select / Response,


2.3.9 Function INV5: Pricing Signal for PV/Storage The steps in Table 30 describe how to initiate changes in the photovoltaic generation and/or storage system based on a pricing signal.

The format of the pricing signal and the behavior of the system after receiving the pricing signal are not specified in detail. In this version of the specification, the pricing signal is simply considered to be an number representing a price per (active) kilowatt-hour in one-hundredths of the local currency. In North America, for example, it would be appropriate for the price value to represent cents of U.S. Dollars, with sufficient resolution to represent hundredths of cents. Utilities must make agreements with suppliers regarding the meaning of the pricing signal within their service area.

Table 30 – Steps to signal a price change using the DNP3 PV Profile


Point Number


4. Set pricing signal and receive response Required Select / Response,

Operate / Response AO 19

5. Enable pricing signal mode and receive response4 Required Select / Response,


4 This step was not required in the Basic Profile. It is required in the Advanced Profile to allow Pricing Signal mode to be disabled. 2013-01-14 AN2013-001 DNP3 Profile for Advanced PV Generation and Storage

2.3.10 Function DS91: Modify PV/Storage Settings The steps in Table 31 describe how to initiate changes in some of the key PV generation and storage settings. There are no timing parameters (e.g. time window or ramp time) associated with this function.

Table 31 – Steps to modify PV or Storage settings using the DNP3 PV Profile


Point Number

1. Set maximum active power capability Optional Select / Response, Operate / Response AO 22

2. Set maximum apparent power capability Optional Select / Response,


3. Set maximum reactive power capability Optional Select / Response,


4. Set maximum ramp rate as a percentage of maximum active power (AO22) per minute

Optional Select / Response, Operate / Response AO 27

5. Set minimum reserve for storage, as a percentage of the Capacity Rating (AO53)


6. Set maximum storage charge rate Optional Select / Response, Operate / Response AO 55

7. Set maximum storage discharge rate Optional Select / Response, Operate / Response AO 56

8. Set maximum apparent charging power Optional Select / Response,


9. Set maximum state of charge, as a percentage of the Capacity Rating (AO53)


2.3.11 Function DS92: Event/History Logging

The following information should be logged:

• All errors or failures

• All startup and shutdown actions

• All control actions

• All responses to control actions

• All limit violations, including returns within limits

Outstations wishing to create event logs shall use the DNP3 Data Set mechanism as defined in Volume 2, Part 2, of the DNP3 Specification. This mechanism allows the outstation to define the format of the event logs it will report, and describe them to the master so the master can interpret them correctly. The following rules shall apply:

1. The data sets for PV event logs shall be defined by the outstation, not the master. Outstations are not required to permit masters to dynamically define PV event log data sets.

2. The outstation shall provide a Data Set Descriptor object (g86) for each PV event log that the master can read to find out what it contains.

3. The PV event logs shall be Event Data Sets (g88), not Static Data Sets (g87).

4. Use of Data Set Prototype objects (g85) by the outstation is not required but masters must be able to interpret them.


5. The outstation shall initially assign PV event logs to Class 1 on startup, although the master may later re-assign it using the ASSIGN CLASS function code.

6. The Data Set Descriptor for each data set shall include human-readable text descriptions of each element

7. PV event log data sets shall be read-only.

8. Once the PV event log data set has been read and the response has been confirmed by the master, the outstation is not required to retain the event information. It is assumed that the master is storing the event log as it is retrieved.

2.3.12 Function DS93: “Status” Reporting

The steps in Table 32 describe how to read and report “status” information from the photovoltaic generation and/or system as described in IEC 61850-90-7. Note that some users of DNP3 may expect the term “status” to refer only to Binary Inputs, while IEC 61850-90-7 uses that term to describe many different data types describing the operational state of the PV system.

The “status” values are listed in the “points lists” in section 2.2. Because many of them (over 800) are Analog Output setpoints which do not change very often, the Analog Output Status objects shall not be included in a DNP3 Class 0 poll, as noted in Table 19. To retrieve them shall require a separate poll, as shown in step 3 of Table 32.

Similarly, the term “data set” used by IEC 61850-90-7 for status reporting does not refer to DNP3 data set objects in this case. In DNP3, the assignment of data into groups for reporting is performed by the ASSIGN CLASS function code, as shown in Table 32.

Table 32 – Steps to read and report status using the DNP3 PV Profile

Step Description Optionality Function Codes Data Type Point Number

1. Read all status values except setpoints Required Read /

Response Class 0, Class 1, Class 2, AND Class 3

All (qualifier 0x06)

2. Read all status values changed (e.g. exceeded a deadband) since the last report

Required Read / Response

Class 1, Class 2, AND Class 3

All (qualifier 0x06)

3. Read the status of all the setpoints Required Read / Response Analog Output Status All

(qualifier 0x06)

4. Read the current value of a particular status item Optional Read /

Response See section 2.2 See section 2.2 (qualifier 0x01)

5. Report the value of a particular status item spontaneously upon change or exceeding a deadband

Optional Unsolicited Response See section 2.2 See section 2.2

(qualifier 0x28)

6. Assign a particular status item to a “data set” Optional Assign

Class See section 2.2 and one of Class 1, 2 or 3

See section 2.2 (qualifier 0x28)

7. Remove a particular status item from a “data set” Optional Assign

Class See section 2.2 and Class 0

See section 2.2 (qualifier 0x28)

8. Read all changes in a current “data set” Optional Read /

Response Class 1, 2 OR 3 All (qualifier 0x06)

9. Read nameplate information Optional Read / Response

Device Attribute Objects See section 2.2.9

2.3.13 Function DS94: Time Synchronization Time synchronization shall take place using the standard methods described in the DNP3 specifications. (Refer to section 10.3 of IEEE 1815-2012) Note that the method varies depending on whether communications takes place over a serial link or a local-area-network (LAN). Implementations of this profile must support the DNP3 time synchronization methods, but other methods (e.g. SNTP, NTP, IRIG- 2013-01-14 AN2013-001 DNP3 Profile for Advanced PV Generation and Storage

B) are also permitted. The master shall be configurable to permit DNP3 time synchronization to be disabled if such other methods are used.

2.3.14 Function VV: Configurable Volt/VAR Curves This section describes how to cause the photovoltaic generation and/or storage system to produce or absorb reactive power (VARs) as a function of the locally-observed voltage. Section 2.3.15 describes how to provide a fixed amount of reactive power without defining a horizontal Volt/VAR curve.

NOTE: IEC 61850-90-7 provides a few specific examples of Volt/VAR curves and assigns specific function numbers to them (e.g. VV11). Any of these examples can be implemented using the generalized methods described in this section and section 2.3.15.

This function makes use of the concept of generic curves as described in section 2.3.2. 2.3.14.1 Precedence of Generation

In the Basic Profile, the Volt/VAR curves were defined such that Watt production always took precedence over VAR generation. The VAR levels specified by the settings were essentially a requested level, to be provided only if and when the end device was able to do so without compromising Watt production.

For example, consider an inverter with a 10KVA rating that at a given moment is producing a full 10KW. Further consider that this inverter has been configured with a Volt-VAR curve that requests capacitive VARs of 50% of available VAR capacity. (Note: the meaning of percent settings are defined below) when voltage is at its present value of 117Vac. In this case, the unit would produce no VARs because the full capability of the inverter is engaged in producing Watts.

Now, further consider that clouds pass over the array, dropping the Wattage to ~70% of its previous value, or 7KW. Even with no change in local voltage, the unit would now have the ability to produce up to 7KVARs, according to the 10KVA power circle. Since the request at this voltage is only 50% of 7KVARs, or 3.5KVARs, the unit is now able to provide the requested VARs. The effect is such that the reduction in generated Watts is immediately replaced by some level of VARs.

In this Advanced Profile, production of active power (Watts) still has precedence by default, as just described. However, it is also possible to change the precedence by changing the VAR reference, as described in the next section. 2.3.14.2 Choice of Reference

In the Basic Profile, the VAR output specified in the Volt/VAR curve was always defined as a percentage of the maximum reactive power the system could produce (VArMax, AO24). In the Advanced Profile, a parameter is provided (AO733) to select the reference for VAR output as described in Table 33.


Table 33 – Choice of Reference Reactive Power

Selection in AO733

VARs are specified as a percent of

IEC 61850 Name Point Num Description Precedence

of Generation

<0> Not applicable / Unknown

-- -- -- --

<1> Maximum Active Power

DRCT1.WMax AO22 This choice is specified in IEC 61850-90-7 but is not valid in this profile.

--

<2> Maximum Reactive Power

DRCT1.VArMax AO24 The system is requested to produce the specified percentage of its maximum reactive power output.

VARs before Watts

<3> Maximum Available Reactive Power

ZINV1.VArAval AI26 The system is requested to produce the specified percentage of the VARs available, given its current active power (Watt) output. The amount of VAR production available at any time is reported in AI26. This is the default setting of AO733.

Watts before VARs

<4> Maximum Reactive Power

DRCT1.VArMax AO24 The system will attempt to follow the specified curve until unable to do so because of the present level of acive power (Watt) output. This mode is specified for backward compatibility with the Basic PV Profile.

Watts before VARs

2.3.14.3 Editing Volt/VAR Curves

The desired Volt-VAR behavior for each function is defined by a piece-wise linear curve of up to 10 curve points, each of which is specified by a %Voltage (X-Value) and a %VAR (Y-Value).

This function makes use of the concept of generic curves as described in section 2.3.2. The Basic Profile required outstations to support a total of ten Volt/VAR curves to be defined by the users of the system. An outstation implementing the Advanced Profile shall support the same ten curves (AO62 - AO311) plus the ability to define any number of additional Volt/VAR curves by writing to an indexed set of “generic” curve points (AO772 – AO827 ). This generic curve definition is also used for a variety of other functions, such as Frequency-Watt, Watt-Power Factor, Volt-Watt, etc. Because the generic curve point array is shared, only one of these additional curves may be edited at a time. The curve currently being edited is selected by writing to AO772. The other curves (beyond the initial 10) are not “visible” but are stored in memory. More than one may be in use by the inverter at a time, for example, a Volt-VAR curve and a Volt-Watt curve may both be active.

The maximum number of Volt/VAR curves is therefore only limited by the resources available on the outstation. This could mean that the outstation only provides the initial 10 Volt/VAR curves, or that it uses only the generic curve definition.

Outstations shall be pre-configured so all curves produce zero VARs at all voltages.

Note that Analog Output objects for the maximum number of points on each curve (e.g. point AO64 ) are included only for correspondence with IEC 61850 and are always set to 10. 2.3.14.4 Defining Hysteresis

This profile permits each Volt/VAR curve to be set in such a way that hysteresis can be specified, i.e. a different curve is to be used depending on whether voltage is increasing or decreasing. To do so, the master shall follow the following rules:

1. The Voltage (X-values) of each curve must initially always increase, up to a Maximum Voltage value for that curve. In Figure 8, the Maximum Voltage is shown as P4.


Figure 8 – Volt/VAR Curve with Hysteresis

1. If the curve used by the outstation is to be different when Voltage is decreasing, the Voltage (X-

Value) of the next point and all subsequent points after the Maximum Voltage point must always decrease (e.g. P5, P6 and P7)

2. If the curve used by the outstation is to be the same regardless of whether the voltage is increasing or decreasing, the curve shall end at the Maximum Voltage point. Figure 9 illustrates this type of curve.

Figure 9 – Volt/VAR Curve without Hysteresis

2.3.14.5 Interpreting the Curve

When operating in a Volt/VAR mode, the outstation shall implement the following rules:

1. If the locally measured voltage is increasing, the outstation shall use the points of the curve that were specified BEFORE the Maximum Voltage point and including that point.

2. If the locally measured voltage is decreasing and there are points defined after the Maximum Voltage point, the outstation shall use the points of the curve that were specified by the master AFTER the Maximum Voltage point and including that point.

3. When the direction of the voltage changes (moving between the curves) or the voltage is beyond the ends of the curves, either increasing or decreasing, the outstation shall keep VARs constant, as shown by the horizontal arrows in Figure 8, until the appropriate curve is reached.

Percent Voltage

P1

P6

P5P3 P4

P2

P7

Voltage RisingVoltage Falling

100%

% A

vaila

ble

VARs

% A

vaila

ble

VARs

Capa

citiv

eIn

duct

ive

Percent VoltageV1

V2

V3

Q1

0%

Q4

100%

P1

P2

P3

P4

V4


4. If there were no points specified after the Maximum Voltage point, the outstation shall use the same points regardless of whether the locally measured voltage is increasing or decreasing, as shown in Figure 9.

5. The X-Values of the curve points shall be defined as a percentage of the nominal voltage at the outstation, as follow:

Percent Voltage (X-Value of Curve) = Voltage at the Curve Point

x 100 %

Nominal Voltage

When executing the curve, the outstation shall calculate the nominal voltage as:

Nominal Voltage = Reference Voltage (AO25) + Reference Voltage Offset (AO26)

This calculation permits the master to write the same Percent Voltage values to many different outstations without adjusting for local conditions at each outstation. Such adjustments can be made by setting the Reference Voltage or Reference Voltage Offset when the device is first commissioned and occasionally after, without affecting the curve settings.

6. The requested VAR (Y-Value) to be written for each curve point shall be a percentage to be calculated as follows:

Percent VARs (Y-Value of Curve) =

Desired Reactive Power (AI9) x 100 % Reference Reactive Power

(as selected by AO733 - see Table 33)

The percentage of VARs is a signed value, so that it can represent VARs generated (positive) or absorbed (negative).

7. The source of the locally measured voltage may vary by outstation. It may be one of the phase-to-ground voltages (AI14 to AI19), an average of these voltages, or some other measurement.

2.3.14.6 Using One of the First 10 Curves

Table 34 illustrates how to create and select one of the first 10 Volt/VAR curve in this profile. The point numbers listed are for Curve 1; each of the first 10 curves has its own set of data points.

The steps to edit the shape of the curve and the timeout parameters are optional if they have already been performed once, or if the desired curve was pre-defined in the configuration of the outstation.

The outstation shall evaluate and start using each curve only at the moment when the master writes the identity of the curve to Analog Output 14 , the Volt/VAR Mode Enable point. If the curve does not conform to the rules above, the outstation shall respond with the INVALID PARAMETER internal indication.


Table 34 – Steps to change and select one of the first ten Volt/VAR curves


1. Select the Reference Reactive Power (see Table 33)


2. Set Volts(X-Values) for each curve point as a percentage of the nominal Voltage

Optional Direct Operate / Response AO e.g. 65, 67, 69 etc.

3.

Set VARs (Y-Values) for each curve point, as a percentage of the Reference Reactive Power


4. Set number of points used for the curve. Set this value to zero to disable the curve.

Optional Direct Operate / Response AO e.g. 63

5. Set the timeout window for this curve Optional Direct Operate / Response AO e.g. 85

6. Set the ramp rate for this curve Optional Direct Operate / Response AO e.g. 86

7. Set the identity of the curve to a unique number. Required Direct Operate / Response AO e.g. 62

8.

EITHER Enable the mode corresponding to the curve by writing the corresponding unique identity value to this data point (Zero is reserved to indicate that no Volt/VAR mode is active)

Required Select / Response, Operate / Response AO 14

OR Enable the curve directly by writing to one of the “curve enable” binary output points. Only one Volt/VAR curve may be active at a time.

Required Select / Response, Operate / Response BO e.g. 11

2.3.14.7 Creating a Volt/VAR Curve using the Generic Curve Points

The process for creating and selecting a Volt/VAR curve using the generic curve data points is slightly different than using one of the 10 dedicated Volt/VAR curves. The process is outlined in Table 35. The concept of using generic curves is described in section 2.3.2.

The steps to define the type of curve, and to edit the shape of the curve and the timeout parameters are optional if they have already been performed once, or if the desired curve was pre-defined in the configuration of the outstation.


Table 35 – Steps to change and select a Volt/VAR curve using the generic curve points


1.

Select which generic curve to edit by writing a number greater than 10 to this point. This is the “index” of the curve, not its “identity”. The indexes shall be the monotonically increasing integers 11, 12, 13..etc. while the curve identities may be any unique number.


2. Specify that that the Curve Mode Type is <2> Volt/VAR modes VV11-VV12.


3. Specify that the Independent (X-Value) units are <129> Percent Voltage


4.

Specify that the Dependent (Y-Value) units are either: <2> VARs as a percent of

max VARs <3> VARs as a percent of

max available VARs


5. Set Volts(X-Values) for each curve point as a percentage of the nominal Voltage

Optional Direct Operate / Response AO 776, 778, 780 794

6.

Set VARs (Y-Values) for each curve point, as a percentage of the Reference Reactive Power (see Table 33)


7. Set number of points used for the curve. Optional Direct Operate / Response AO 774

8. Set the timeout window for this curve Optional Direct Operate / Response AO 816

9. Set the ramp rate for this curve Optional Direct Operate / Response AO 817

10. Set the identity of the curve to a unique number. Required Direct Operate / Response AO 773

11. Enable the currently selected curve Required Select / Response,


2.3.15 Function VV: Constant VARs The outstation may be requested to provide either a constant amount of reactive power or zero reactive power using a few setpoints rather than defining a horizontal curve. The steps required to do so are listed in Table 36.

The requested constant VARs are specified as a percentage of the Reference Reactive Power, as described in section 2.3.14.2. A different analog output point is used as the setpoint depending on which reference is selected. The setpoint shall not take effect until the mode is enabled using the appropriate binary output point.

If the Reference Reactive Power is selected to be <3> Maximum Available Reactive Power, the amount of VARs produced by the system is only “constant” for a given amount of active power (Watts) output. As the system varies its active power output, it shall adjust its reactive power output to the specified percentage of the maximum available VARs accordingly.


Table 36 – Steps to request constant VARs using the DNP3 PV Profile


1. Select the Reference Reactive Power (see Table 33)



5.

EITHER Set the requested constant VARs as a percentage of Max VARs


OR Set the requested constant VARs as a percentage of Available VARs


6. Enable constant VAR mode. This will disable any Volt/VAR curves currently enabled.

Required Select / Response, Operate / Response BO 10

2.3.16 Function FW22: Frequency-Watt Mode The steps in Table 37 describe how to cause the photovoltaic generation and storage system to alter its active power output in response to the measured deviation from a specified nominal frequency. The master defines the curve relating frequency to Watts using the generic curve data points (AO772 – AO827). The concept of using generic curves is described in section 2.3.2.

A typical curve is illustrated in Figure 10.

Figure 10 – Basic Frequency-Watt Curve The X-value of each point on the curve is defined as

Frequency Deviation (X-Value)

= Locally Measured Frequency (AI10) – Nominal Frequency (AO741

Max

Pow

er (%

of P

ref)

System Frequency

P1

P3 P4

P2

Fnominal


The Y-value of each point on the curve is the percentage of active power (Watts) to be provided at the given amount of deviation from nominal frequency. This percentage may be calculated in relation to the maximum active power that the system can generate, as follows:

Maximum Percent Active Power

Output (Y-Value) =

Maximum Allowed Output Active Power (AI11) x 100 %

Maximum Active Power (AO22)

This is the default calculation and default behavior – essentially a function that is continuously active when enabled.

Alternatively, this function may be setup to operate intermittently, activated by a certain frequency deviation and deactivated when frequency returns to normal. In this mode of operation, the maximum output limits specified by the curve are calculated in relation to a “snapshot” of the active power that the system is producing at the moment the measured frequency deviates from the nominal frequency by a specified threshold, as follows:

Maximum Percent Active Power

Output (Y-Value) =

Maximum Allowed Output Active Power (AI11) x 100 %

Snapshot Active Power (AI62)

The frequency deviation, in Hertz, at which the Snapshot Active Power is captured is AO826. When the frequency deviates that number of Hertz from the nominal frequency, the instantaneous value of the active output power is captured and stored in AI62. The frequency threshold, in Hertz, at which the snapshot ends is AO827. When the frequency deviates that number of Hertz from the nominal frequency, the Frequency-Watt curve ceases to apply and the outstation no longer adjusts active power output due to this function.

The parameter which selects the calculation to be used for the Y-Value is AO821.

The curve may be defined with hysteresis, as described for Volt/VAR curves in 2.3.14.4 and illustrated in Figure 11. The curve will have a maximum frequency point (in this case P4). If the frequency is rising, the outstation shall apply the points defined before that maximum point (in this case, P1, P2, P3), and if the frequency is falling the outstation shall apply the points on the curve defined beyond that maximum (in this case, P5, P6 and P7).

Figure 11 – Frequency-Watt Curve with Hysteresis The response may be filtered as described in 2.3.3 to limit how quickly the Y-Value Maximum Watts Limit can be changed.

System Frequency

P1

P6

P5

P3 P4

P2

P7

Frequency Rising Frequency Falling

Fnom

Max

Pow

er (%

of P

ref)


Table 37 – Steps to enable a Frequency-Watt curve using the DNP3 PV Profile


1. Select which generic curve to edit by writing a number greater than 10 to this point. 5


2. Specify that that the Curve Mode Type is <3> Frequency-Watt Mode FW22


3. Specify that the Independent (X-Value) units are <233> Frequency Deviation


4. Set the nominal frequency for measuring frequency deviation Optional Direct Operate / Response AO 741

5.

Specify that the Dependent (Y-Value) Units are either: <5> Watts as a percent of

maximum Watts (WMax) <6> Watts as a percent of frozen

(snapshot) active power (DeptSnpRef)


6.

If the Dependent Units are <6> percent of snapshot active power, set the frequency deviation for taking the snapshot and starting the function


7.

If the Dependent Units are <6> percent of snapshot active power, set the frequency deviation for ending the function


8.

If the Dependent Units are <5> percent of maximum Watts, ensure the maximum Watts is set correctly.


9.

Set Frequency(X-Values) for each curve point as the deviation from the nominal frequency (AO741) in Hz.


10.

Set Watts (Y-Values) for each curve point, as a percentage of either the maximum Watts (AO22) or the snapshot Watts (AI62)





14. Set the response filtering parameters for this curve Optional Direct Operate / Response AO 822, 823, 824




5 This is the “index” of the curve, not its “identity”. The indexes shall be the monotonically increasing integers 11, 12, 13..etc. while the curve identities may be any unique number. 2013-01-14 AN2013-001 DNP3 Profile for Advanced PV Generation and Storage

2.3.17 Function TV31: Dynamic Reactive Current Mode The steps in Table 38 describe how to cause the photovoltaic generation and/or storage system to support the stabilization of the electrical system by providing additive reactive current in proportion to the instantaneous difference from a moving average of the measured voltage. 2.3.17.1 Basic Operation

Figure 12 illustrates how the outstation calculates a continuous Moving Average Voltage (AI30) over a specified number of seconds known as the Filter Time (AO747).

Figure 12 – Delta Voltage Calculation

The difference between this Moving Average Voltage and the currently measured voltage at any moment is calculated as:

Percent Delta Voltage (AI31) =

Measured Voltage – Moving Average Voltage (AI30) x 100 %

Reference Voltage (AO25)

It is a local matter whether the designated measured voltage is one of the per-phase voltages (AI14, AI16, or AI18) or an average or total of these voltages, provided the moving average voltage is calculated the same way.

Figure 13 illustrates how the outstation provides reactive current, either inductive or capacitive, in proportion to the Delta Voltage at any moment, in addition to any reactive current that may be applied by other functions such as the static Volt/VAR (VV) curve functions.

Volta

ge

Present

V Average over FilterTms

FilterTms

Time

Delta Voltage @ time = Present (negative value

shown)


Figure 13 – Dynamic Current Support Function

The master specifies the curve in Figure 13 using four values. Firstly, it specifies two voltage thresholds that define a “Deadband” in which the outstation provides no reactive current support. When the Delta Voltage is below the Deadband Minimum Voltage (AO743) a “sag” is said to be occurring. When the Delta Voltage is above the Deadband Maximum Voltage (AO744) a “swell” is said to be occurring. The deadbands are expressed as a percentage of the reference voltage, as the Delta Voltage is.

Secondly, the master specifies two gradients. The gradients are defined as follows:

Percent Reactive Current =

Additional Reactive Current to Supply (Amps) x 100 %

Maximum Current Rating (See Table 22)

Reactive Current Support Gradient =

Percent Reactive Current

Percent Delta Voltage

The outstation applies the Reactive Current Support Gradient for Sags (AO745) when the Delta Voltage is negative and applies the Reactive Current Support Gradient for Swells (AO746) when the Delta Voltage is positive. 2.3.17.2 Alternative Gradient Option

The master can also specify the alternate curve shape shown in Figure 14 by selecting <1> Gradients reach 0 at the Moving Average Voltage as the Dynamic Reactive Current Support Gradient Mode (AO742). The normal curve shape shown in Figure 13 is selected using <2> Gradients reach 0 at the Voltage deadbands. Note that the current support follows different paths if the Delta Voltage is increasing or decreasing.

Moving Average of Voltage

DbVMax

ArGraSagDelta Voltage (% of VRef)

Deadband

DbVMin

ArGraSwell

Indu

ctiv

eCa

paci

tive

Addi

tiona

l Rea

ctiv

e Cu

rren

t (%

of A

Rtg)


Figure 14 – Alternate Dynamic Current Gradient Mode

2.3.17.3 Event-Based Behavior Option

The master can enable “event-based” dynamic current support by writing to the appropriate binary output (BO23). Figure 15 illustrates this behavior. When this feature is enabled, a voltage sag or swell “event” is considered to start when the voltage exceeds one of the deadband thresholds (shown as time t0).

Figure 15 – Event-Based Dynamic Current Support

When this option is activated, the Moving Average Voltage and any reactive current levels that might exist due to other functions - such as the static Volt-VAR (VV) function – are frozen at t0 when the event begins and are not free to change again until t2 when the event ends. The additional reactive current level specified by this function (as shown in Figure 13 or Figure 14) continues to vary throughout the event and is added to any frozen reactive current.

Assuming the voltage returns within the deadband at t1, additional reactive current support continues until a specified Hold Time (AO751) has elapsed (t2 = t1 + Hold Time).

Moving Average of Voltage

Addi

tiona

l Rea

ctiv

e Cu

rren

t (%

of A

Rtg)

DbVMax

ArGraSag

Delta Voltage (% of VRef)

Deadband

DbVMin

ArGraSwell

Indu

ctiv

eCa

paci

tive

Delta

Vol

tage

Rela

tive

to V

Aver

age

(exp

ress

ed in

% V

Ref)

Time

DbVMin

DbVMax

Moving Average of Voltage (0% Delta)

Dead-band (No Dynamic Reactive Current Support)

Dynamic Reactive Current Support

Dynamic Reactive Current Support

t0t1

HoldTmms

t2


If Event-Based Behavior is not enabled, the Hold Time is not applied, freezing of the Moving Average Voltage and static VARs does not occur, and the gradient curve in either Figure 13 or Figure 14 is applied continuously

2.3.17.4 Blocking Zone Option

The master may define a “blocking zone” in which no dynamic reactive current support is applied, as illustrated in Figure 16. If the absolute voltage, expressed as a percentage of the reference voltage, drops below a specified Block Zone Voltage (AO748), the outstation shall stop applying support (time t0). The outstation shall not return to providing support until the voltage rises above the Hysteresis Block Zone Voltage (AO749) (time t1).

The master can also specify that regardless how low the voltage sags, dynamic reactive current support will be applied for at least a guaranteed Block Zone Time (AO750) after the voltage exceeds the deadband (i.e. an “event” has begun).

Figure 16 – Settings to Define a Dynamic Reactive Current Blocking Zone

All the steps marked as “Required” in Table 38 are required the first time the function is enabled. If all the settings have already been established, only the final step is required.

Volta

ge (

expr

esse

d in

% V

Ref)

Time

100% (=VRef)

BlkZnV

BlkZnV+HysBlkZnV

BlkZnTmms

No Dynamic Reactive Current Support

Dynamic Reactive Current Support Zone

Hysteresis

t0 t1

0%


Table 38 – Steps to enable Dynamic Reactive Current Mode


Point Number

1. Set the Gradient Mode to select the curve shape Required Direct Operate / Response AO 742

2. Set the Deadband Minimum Voltage Required Direct Operate / Response AO 743

3. Set the Deadband Maximum Voltage Required Direct Operate / Response AO 744

4. Set the Reactive Current Support Gradient for Sags Required Direct Operate / Response AO 745

5. Set the Reactive Current Support Gradient for Swells Required Direct Operate / Response AO 746

6. Set the Filter Time for the Moving Average Voltage in seconds Required Direct Operate / Response AO 747

7. Enable Event-Based Reactive Current Support if required. It shall default to Disabled.

Optional Direct Operate / Response BO 23

8. Set the Hold Time in milliseconds if Event-Based Reactive Current Support is required.


9. Set the Block Zone Voltage if required. Otherwise it shall default to zero.


10. Set the Hysteresis Block Zone Voltage if required. Otherwise it shall default to zero.


11. Set the Block Zone Time in milliseconds if required. Otherwise it shall default to zero.


12. Enable Dynamic Reactive Current Mode Required Select / Response,


2.3.18 Functions MD and MRC: Low/High Voltage Ride-Through

The steps in Table 39 and Table 40 describe how to cause the photovoltaic generation and storage system to determine when to disconnect or remain connected during a voltage excursion. Figure 18 illustrates typical Low-Voltage Ride-Through curves and Figure 17 illustrates typical High-Voltage Ride-Through curves. In general, large voltage excursions are “tolerated” for only very short intervals, while smaller excursions cause disconnection after a much longer interval. The two sets of curves define three different zones of outstation behavior, as illustrated:

• Must Remain Connected

• Remaining Connected or Disconnecting is Allowed

• Must Disconnect


Figure 17 – Example High-Voltage Ride-Through (HVRT) Curves

Figure 18 – Example Low-Voltage Ride-Through (LVRT) Curves

The “Must Disconnect” curves are required to perform the voltage ride-through functions. If no “Must Remain Connected” curves are defined, the outstation shall assume they are the same as the “Must Disconnect” curves and there is no intermediate zone defined.

The “Must Disconnect” curves are defined using two dedicated arrays of DNP3 analog outputs. Over-voltage is evaluated using one set of points (AO828 - AO849) and under-voltage is evaluated using a second set of points (AO870 – AO891 ). These are basic protection functions and are mapped to the IEC 61850 PTOV and PTUV logical nodes. Because these curves directly affect the safety and reliability of the power grid, they are typically defined as requirements by regulators and therefore might not be writeable by the DNP3 master. Nevertheless, Table 39 describes the steps necessary to change a “Must Disconnect” curve if the outstation permits it, and within the range that the outstation permits. The maximum number of points (AO829 and AO871) shall always be 10.

The “Must Remain Connected” curves are defined using the “generic curve” analog output points ((AO772 – AO827). The concept of using generic curves is described in section 2.3.2.

The steps necessary to define these curves are listed in Table 40. A “Must Remain Connected” curve cannot logically cross or extend beyond a “Must Disconnect” curve, and in general must have some clearance between them to account for tolerances and noise. Either all the voltages in a “Must Remain Connected” curve must be greater than the nominal voltage (>100%), describing a curve for evaluating swells, or they must all be less than the nominal voltage (<100%), describing a curve for evaluating sags. A binary output point (BO45) is used to distinguish which is which. Manufacturers’ documentation may

Volta

ge(%

of V

nom

)100%

Must Remain Connected

Must Disconnect

Remaining Connected or Disconnecting is Allowed

P6

P1

P5

P4P3

P2

P3 P4

P2P1

Event Duration

Event Duration

Volta

ge(%

of V

nom

)

100%

Must Disconnect

P1

P6P5

P3

P4

P2

Must Remain Connected

Remaining Connected or Disconnecting is Allowed

P1

P6P5

P3 P4

P2


identify the specific limitations of outstations. The outstation shall reject any attempt to enable an illegal curve with a PARAMETER ERROR internal indication.

The timeout parameters described in 2.3.1 and the filtering parameters described in 2.3.3 shall be ignored by the outstation for “Remain Connected” curves and do not exist for “Must Disconnect” curves.

All the curves are assumed to extend horizontally to zero seconds from the first point defined in the array and horizontally to the right beyond the right-most point in the array. All times in the curves are defined in milliseconds. The voltages in the curves are defined as:

Percent Voltage (Y-Value of Curve) =

Voltage at the Curve Point x 100 %

Nominal Voltage

Where the outstation will calculate Nominal Voltage as follows when the curve is executed.


Table 39 – Steps to define a “Must Disconnect” curve using the DNP3 PV Profile


1. Set the Reference Voltage if it is not already set Optional Direct Operate / Response AO 25

2. Set the Reference Voltage Offset if it is not already set Optional Direct Operate / Response AO 26

3. Set the number of points used for the curve to zero. This will disable the curve while it is being edited.

Required Select / Response, Operate / Response AO 828 or 870

4.

Set time (X-Values) for each curve point to the number of milliseconds from the start of the event

Optional Direct Operate / Response AO

830, 832, 834 848 or 872, 874, 876 890

5.

Set active power (Y-Values) for each curve point to the voltage as a percentage of the nominal voltage

Optional Direct Operate / Response AO

831, 833, 835 849 or 873, 875, 877 891

6.

Set the number of points used for the curve. This value is zero by default and can be set zero again to disable the curve.

Required Select / Response, Operate / Response AO 828 or 870

Table 40 – Steps to define a “Must Remain Connected” curve using the DNP3 PV Profile




2. Specify that that the Curve Mode Type is <6> Remain Connected Optional Direct Operate / Response AO 819

3. Specify that the Independent (X-Value) units are <4> Time Optional Direct Operate / Response AO 820



4. Specify the Dependent (Y-Value) units are <8> Percent of nominal Voltage


5. Specify whether the curve is for evaluating sags (undervoltage) or swells (overvoltage)

Optional Direct Operate / Response BO 45

6. Set the Reference Voltage if it is not already set Optional Direct Operate / Response AO 25

7. Set the Reference Voltage Offset if it is not already set Optional Direct Operate / Response AO 26

8.

Set time (X-Values) for each curve point to the number of milliseconds from the start of the event


9.

Set active power (Y-Values) for each curve point to the voltage as a percentage of the nominal voltage






2.3.19 Function WP42: Watt-Power Factor Mode

The steps in Table 41 describe how to cause the photovoltaic generation and/or storage system to alter its output power factor (and therefore the amount of reactive power it is producing) based on the amount of active power (Watts) it is producing. The master defines the curve relating output Watts to power factor using the generic curve data points (AO772 – AO827). The concept of using generic curves is described in section 2.3.2. An example Watt-Power Factor curve is shown in Figure 19.

Figure 19 – Example Watt-Power Factor Curve

The X-Value of each point on the curve is a signed value, i.e. it can specify the behavior when the system is charging storage in addition to when the system is producing active power.

Pow

erFa

ctor

(IEEE

) Real Power (Positive X-Values are % of Wmax)

W1

PF3

W3

PF1

W4

W2

PF2

PF4

Real Power( Negative X-Values are % of Wchamax)


When producing active power, the X-Value is defined as follows:

Percent Active Power Output

(X-Value) =

Output Active Power (AI9) x 100 %


When charging, the X-Value is defined as follows, in which AI9 is negative indicating charging.

Percent Active Charging Power

(X-Value) =


Maximum Charging Rate (AO55)

The Y-Value of each point on the curve is the power factor to be used, as defined in section 2.3.7.

Note that the selection of whether to reverse VAR absorption/production in relationship to active power using AO729 does not apply when this curve is enabled, since the curve fully specifies the relationship between Watts and Power Factor. This curve cannot be defined with hysteresis. Table 41 – Steps to enable a Watt-Power Factor Curve using the DNP3 PV Profile




2. Specify that that the Curve Mode Type is <4> Watt-Power Factor mode WP42


3. Specify that the Independent (X-Value) units are <138> Percent Watts


4. Set the Maximum Active Power if not already set Optional Direct Operate / Response AO 22

5. Specify that the Dependent (Y-Value) Units are <7> Power Factor IEEE Notation


6. Set active power (X-Values) for each curve point as a percentage of the the maximum Watts (AO22)


7. Set Power Factor (Y-Values) for each curve point Optional Direct Operate / Response AO 777, 779, 781

795




11. Set the filtering parameters for this curve Optional Direct Operate / Response AO 822, 823, 824





2.3.20 Functions VW51-VW52: Volt-Watt Modes The steps in Table 42 describe how to cause the photovoltaic generation and storage system to alter its active power output based on the locally measured voltage. The master defines the curve relating voltage to output Watts using the generic curve data points (AO772 – AO827). The concept of using generic curves is described in section 2.3.2.

A typical curve for avoiding unintentional high voltage on a feeder is illustrated in Figure 20.

Figure 20 – Example Volt-Watt Curve

The X-Values of the curve points shall be a percentage of nominal voltage, calculated as follows:

Percent Voltage (X-Value of Curve) =

Voltage at the Curve Point x 100 %

Nominal Voltage

Where the outstation shall calculate the nominal voltage as follows when executing the curve:


The Y-values of the curve points shall be calculated as follows:

Percent Active Power Output

(Y-Value) =



This active power is a signed value. If it is negative, it indicates that the system shall charge storage rather than producing power for the given voltage.

This curve cannot be defined with hysteresis.

Max

Wat

t Out

put [

% o

f WM

ax]

Voltage (% of VRef)

V1

100%

P3

V3

P1

V4

V2

P2

P4

Allowed Operating Area


Table 42 – Steps to enable a Volt-Watt curve using the DNP3 PV Profile




2. Specify that that the Curve Mode Type is <5> Voltage-Watt modes WP52-WP52


3. Specify that the Independent (X-Value) units are <129> Percent Voltage


4. Set the reference voltage and offset if not already set Optional Direct Operate / Response AO 25, 26

5. Specify that the Dependent (Y-Value) Units are <5> Watts as a percent of max Watts


6. Set the Maximum Active Power if not already set Optional Direct Operate / Response AO 22

7. Set voltage (X-Values) for each curve point as a percentage of the the nominal voltage


8. Set active power (Y-Values) for each curve point as a percentage of maximum Watts (AO22)





12. Set the curve smoothing parameters for this curve Optional Direct Operate / Response AO 822, 823, 824





2.3.21 Function PS and TMP: Non-power Parameter Modes The steps in Table 43 describe how to cause the photovoltaic generation and storage system to alter one of its outputs in response to either a price signal (PS) or temperature (TMP). The master defines the curve relating the inputs and outputs using the generic curve data points (AO772 – AO827). The concept of using generic curves is described in section 2.3.2.

An example of a price curve would be for the system to change active power (Watts) output in response to the price signal. This price signal could be supplied by the master in AO19, as described in 2.3.9, or it could be changed at intervals using a time-vs-price schedule as described in 2.3.26.

An example of a temperature curve would be for the system to change power factor or VAR output in response to temperature, in order manage voltage due to air conditioning usage. There is no analog input defined for ambient temperature and no requirement that the system be able to measure temperature. Outstations that do not support temperature measurement may reject an attempt to create such a curve by responding with a PARAMETER ERROR internal indication.

If the output (Y-value) chosen is a percentage, it may require a reference value to be initialized before the curve should be enabled.

Table 43 – Steps to enable a Price or Temperature-Based Curve




2.

Specify that that the Curve Mode Type is either of: <7> Temperature Mode <8> Pricing Signal Mode


3.

Specify that the Independent (X-Value) units are either of: <23> Celsius Temperature <1> Not Applicable / Unknown (for the pricing signal)


4.

Specify the Dependent (Y-Value) units, e.g. <5> Watts as percent of max Watts (Wmax)


5. Set the reference for the Y-Value if appropriate, e.g. Maximum Active Power


6. Set voltage (X-Values) for each curve point Optional Direct Operate / Response AO 776, 778, 780

794

7. Set active power (Y-Values) for each curve point Optional Direct Operate / Response AO 777, 779, 781

795




11. Set the curve smoothing parameters for this curve Optional Direct Operate / Response AO 822, 823, 824






2.3.22 Function RPS: Real Power Smoothing The steps in Table 44 describe how to request that the photovoltaic generation and/or storage system absorb or produce additional Watts in such a way as to smooth-out variations in the power level of a remote point of reference.

It is assumed that if a device supports this function, it has a dedicated “remote reference meter” input of some kind, as illustrated by location M2 in Figure 21. The Reference Power Measurement for Real Power Smoothing (AI32) may be representative of a load or generation source or both. It is out of the scope of this document what the source is, where it is located, or how the measurement is gathered by the outstation.

Figure 21 – Possible Measurement Points

This function operates by computing the instantaneous difference in the reference meter power level and a moving average of the power level over a sliding time window. In this way, the system helps to “smooth” the power waveform at the reference point.

This function utilizes the similar basic concepts and settings as the Dynamic Reactive Current function described in section 2.3.17, but uses active power rather than voltage or current as inputs and outputs.

This function identifies “additional Watts”, not absolute Watts, so that it is compatible with other Watt-managing functions, such as scheduled battery system charging and discharging. For example, a battery system that is being charged and discharged daily for arbitrage purposes may, by this function, modulate its charging and discharging levels moment by moment to compensate for variability in some other nearby load or generation resource.

Figure 22 illustrates how the outstation shall calculate a moving average of the Reference Power Measurement over a specified number of seconds known as the Filter Time (AO753).


Figure 22 – Delta Wattage Calculation

The difference between this Moving Average Power and the Measured Reference Power at any moment is defined to be the Delta Wattage, as follows:

Delta Wattage = Measured Reference Power (AI32) – Moving Average Power

Neither the Delta Wattage or the Moving Average Power is available at the outstation for reading by the master.

Figure 23 illustrates how the outstation generates or absorbs active power in proportion to the Delta Wattage at any moment, in addition to any active power produced or absorbed by other functions.

Figure 23 – Real Power Smoothing Function

Wat

tage

of R

efer

ence

Lo

ad o

r Gen

erat

ion

Present

W Average over FilterTms

FilterTms

Time

Delta Wattage at

Present

DbWHiDeadband

DbWLo

Smoothing Gradient

Delta Wattage(Present Wattage

Minus Moving Average)

Addi

tiona

l Wat

ts

Moving Average of ReferencePower

Smoothing Gradient


The master specifies the curve in Figure 23 using three values. Firstly, it specifies two Wattage thresholds that define a “deadband”. When the Delta Wattage is above the Real Power Smoothing Lower Limit (AO754) and below the Real Power Smoothing Upper Limit (AO755) the outstation shall not perform real power smoothing.

Secondly, the master specifies a unit-less gradient, defined as follows:

Real Power Smoothing Gradient (AO752) =

Additional Watts Produced

Delta Wattage

Unlike the Dynamic Reactive Current function, the outstation applies the same gradient regardless of whether the Delta Wattage is positive or negative.

The Real Power Smoothing Gradient is a signed quantity. Positive values of this gradient are for following load (increasing reference load results in a dynamic increase in DER output), and negative values are for following generation (increasing reference generation results in a dynamic decrease in DER output).

Table 44 – Steps to enable Real Power Smoothing using the DNP3 PV Profile


1. Set the Real Power Smoothing Gradient Optional Direct Operate / Response AO 752

2. Set the Real Power Smoothing Filter Time Optional Direct Operate / Response AO 753

3. Set the Real Power Smoothing Lower Limit Optional Direct Operate / Response AO 754

4. Set the Real Power Smoothing Upper Limit Optional Direct Operate / Response AO 755


8. Enable Real Power Smoothing Mode Required Select / Response,


2.3.23 Function DVW: Dynamic Volt-Watt Mode The steps in Table 45 describe how to cause the photovoltaic generation and storage system to dynamically absorb or produce additional Watts in proportion to the instantaneous difference from a moving average of the measured voltage. This function utilizes the same basic concepts and settings as the Dynamic Reactive Current function described in section 2.3.17, but uses active power as an output rather than reactive current.

Figure 24 illustrates how the outstation calculates a continuous Moving Average Voltage over a specified number of seconds known as the Dynamic Volt-Watt Filter Time (AO760).


Figure 24 – Delta Voltage Calculation for Dynamic Volt-Watt Mode

The difference between this Moving Average Voltage and the currently measured voltage at any moment is calculated as:

Percent Delta Voltage =

Measured Voltage – Moving Average Voltage x 100 %

Reference Voltage (AO25)

It is a local matter whether the designated measured voltage is one of the per-phase voltages (AI14, AI16, or AI18) or an average or total of these voltages, provided the moving average voltage is calculated the same way.

Unlike the Dynamic Reactive Current Mode, neither the Moving Average Voltage nor the Percent Delta Voltage for the Dynamic Volt-Watt mode can be read by the master.

Figure 25 illustrates how the outstation either generates or absorbs active power, in proportion to the Delta Voltage at any moment, in addition to any active power produced or absorbed by other functions.

Volta

ge a

t ECP

(% V

ref)

Present

VAverage over FilterTms

FilterTms

Time

Delta Voltage at

Present(% Vref)


Figure 25 – Dynamic Volt-Watt Function

The master specifies the curve in Figure 25 using three values. Firstly, it specifies two voltage thresholds that define a “deadband”. When the Percent Delta Voltage is above the Dynamic Volt-Watt Lower Deadband (AO761) and below the Dynamic Volt-Watt Upper Deadband (AO762) the outstation shall not generate or absorb additional active power. The deadband values are specified as percentages of the Reference Voltage, as is the Percent Delta Voltage.

Secondly, the master specifies a gradient, defined as follows:

Percent Additional Watts =

Additional Watts Supplied x 100 %


Dynamic Volt-Watt Gradient (AO759) =

Percent Additional Watts

Percent Delta Voltage

This active power will be in addition to the active power generated by any other functions active on the outstation.

Unlike the Dynamic Reactive Current function, the outstation applies the same gradient regardless of whether the Percent Delta Voltage is positive or negative.

The Dynamic Volt-Watt Gradient is a signed quantity. A negative value will cause generation at low voltages and charging at high voltages.

Note that this function does not use a time window or ramp time parameter.

DbVHiDeadband

DbVLo

Delta Voltage(Present Voltage

Minus Moving Average

% VRef)Ad

ditio

nal W

atts

(% W

Max

)

Moving Average of Voltage at ECP

Dynamic Watt Gradient

Dynamic Watt Gradient


Table 45 – Steps to enable Dynamic Volt-Watt mode using the DNP3 PV Profile


1. If not already established, set the Reference Voltage Optional Direct Operate / Response AO 25

2. If not already established, set the Reference Voltage Offset Optional Direct Operate / Response AO 26

3. If not already established, set the Maximum Watts Optional Direct Operate / Response AO 22

4. Set the Dynamic Volt-Watt Gradient Optional Direct Operate / Response AO 759

5. Set the Dynamic Volt-Watt Filter Time Optional Direct Operate / Response AO 760

6. Set the Dynamic Volt-Watt Lower Deadband Optional Direct Operate / Response AO 761

7. Set the Dynamic Volt-Watt Upper Deadband Optional Direct Operate / Response AO 762

8. Set reversion timeout Optional Direct Operate / Response AO 763

9. Enable Dynamic Volt-Watt mode Required Select / Response, Operate / Response BO 25

2.3.24 Function PPL: Peak Power Limiting

The steps in Table 46 describe how to cause the photovoltaic generation and storage system to supply active power such that the power transferred at a particular reference point does not exceed a specified limit. This concept is illustrated in Figure 26.

Figure 26 – Peak Power Limiting Function

The Reference Power Input for Peak Power Limiting (AI33) may be located at the same site as the outstation or at another site. The source of this reference measurement, its location, and how it is transferred to the outstation are out of the scope of this specification. The assumption of this function is that increasing the active power output of the outstation will reduce the power transferred at the point of reference, and implementers must ensure this polarity.

When this function is enabled, the outstation shall continuously compare the Reference Power Input to a specified Peak Power Limit (AO764) and adjust its active power output as needed to ensure the Reference Power Input does not exceed the limit.

This function somewhat resembles the Load Following function described in section 2.3.25 in that they both supply active power when the reference power measurement exceeds a threshold. However, they differ in the following fundamental manner: the Load Following function supplies active power in a specified ratio to the power transferred at the reference point, while the Peak Power Limiting function


supplies as much active power as necessary (within the physical limits of the outstation) to ensure the measured reference does not exceed the threshold.

Table 46 – Steps to enable the Peak Power Limiting function using the DNP3 PV Profile


1. Set the Peak Power Limit Optional Direct Operate / Response AO 764 2. Set time window Optional Direct Operate / Response AO 765 3. Set reversion timeout Optional Direct Operate / Response AO 766 4. Set ramp time Optional Direct Operate / Response AO 767

5. Enable Peak Power Limiting mode Required Select / Response, Operate / Response BO 26

2.3.25 Function LGF: Load and Generation Following

The steps in Table 47 describe how to cause the photovoltaic generation and storage system to produce active power in proportion to a measured load (as illustrated in Figure 27), or to absorb active power in proportion to a measured generation source (as illustrated in Figure 28).

Figure 27 – Load Following Function Arrangement and Waveform

Figure 28 – Generation Following Function Arrangement and Waveform

The Reference Power Input for Load and Generation Following (AI34) may be located at the same site as the outstation or at another site. It is shown as “M1” in the figures. The source of this reference measurement, its location, and how it is transferred to the DER are out of the scope of this specification. The assumption of this function regarding this reference is that:


• a positive value represents a load and the DER should produce active power to support the load

• a negative value represents generation and the DER should absorb excess active power

The Load/Generation Following function will not take action unless the reference value exceeds the Load/Generation Following Starting Threshold (AO768) – either a larger positive value if the threshold is positive or a larger negative value if the threshold is negative. The ratio is a percentage.

The function will generate or absorb active power in proportion to the Reference Power Input based on a specified ratio, as follows:

Additional Output Active

Power =

Reference Power Input (AI34) – Starting Threshold (AO768) x

Following Ratio

(AO769) 100 %

This active power will be in addition to the active power generated by any other functions active on the outstation.

Table 47 – Steps to enable Load and Generation Following function using the DNP3 PV Profile


1. Set the Load/Generation Following Starting Threshold Optional Direct Operate / Response AO 768

2. Set the Load/Generation Following Ratio Optional Direct Operate / Response AO 769

3. Set reversion timeout Optional Direct Operate / Response AO 770 4. Set ramp time Optional Direct Operate / Response AO 771

5. Enable Peak Power Limiting mode Required Select / Response, Operate / Response BO 27

2.3.26 Scheduling Many of the functions previously described in this section can be performed according to a schedule. A schedule is a curve in which the X-value is time and the Y-value is the setpoint for one of the core functions described in this document.

The Basic Profile permitted price-based and temperature-based schedules, but these have been replaced with the PS and TMP curve functions (section 2.3.21). Therefore all schedules in this profile are time-based.

When a schedule is enabled by the master, the outstation activates one of the following Y-values when the corresponding time (X-value) has elapsed:

• Limited Watts mode setpoint (AO15, function INV2)

• Power factor setpoint (AO17, function INV3)

• Charge/Discharge rate (AO16, function INV4)

• Price for active power (AO19, function INV5)

• Price for reactive power

• A curve identifier (AO14 or AO773, section 2.3.14)

• Maximum State of Charge (AO914, function INV4)

There were 12 possible schedules defined in the Basic Profile. Each schedule may consist of up to 10 curve points. Note that the maximum number of points per curve (e.g. Analog Output 316) is initialized


to 10 by the outstation and never changed. Time values in a schedule must increase so that the schedule describes a curve, or the outstation may return the INVALID PARAMETER internal indication when the master tries to write the value. The outstation may provide some pre-configured schedules, in which case the master does not necessarily need to modify them.

Note that when the target of the schedule is a curve identifier, the schedule is essentially defining a curve for determining which curve to use.

The steps in Table 48 describe how to initiate one of the first 12 schedules originally defined in the Basic Profile. Note that some of these steps are now no longer necessary and those data points are retained only for backward compatibility with the Basic Profile.

In this Advanced Profile, it is possible for the master to define the priority of schedules, such that if two schedules that control the same parameter (e.g. Watts output) are running at the same time, the one with the higher priority is considered to have control of that parameter.

The Advanced Profile also permits the master to define a “ramp type” for how the Y-Value should change between the defined points of the schedule. The possible values are:

• Fixed – horizontal from the first schedule point until the next defined schedule point

• Ramp – a straight diagonal line from the first schedule point to the next

• Average – the value is permitted to vary somewhat but must average to the value of the first point

For the first 12 schedules, the Ramp Type must be the same for all points. The outstation may reject some Ramp Types with an INVALID PARAMETER internal indication; for instance, “Average” or “Ramp” would have no meaning if the Y-Value was a Curve Identifier.

Figure 29 – Example of Ramp types The point numbers listed are for Schedule 1; each schedule has its own set of data points. The outstation shall evaluate and start using each curve only at the moment when the master writes the identity of the schedule to the Schedule Enable point (Analog Output 636) or operates the Binary Output associated with that schedule.


Table 48 – Steps to create and enable one of the first 12 schedules using the DNP3 Advanced PV Profile


1.

Set the Time Offset (X-Value) for each schedule point. Time Offsets must increase with each point. Time Offsets represent relative seconds from each repetition of the schedule.


2. Set the Y-value for each schedule point Optional Direct Operate / Response AO e.g. 318, 320, 322

etc.

3.

Set the number of points used for the schedule. Set this value to zero to disable the schedule.


4. Set the ramp type for the whole schedule Optional Direct Operate / Response AO e.g. 638

5. Set the priority for the schedule Optional Direct Operate / Response AO e.g. 650

6.

(Set the meaning of the X-values (ranges) of the schedule. ) This value is now always <1> Relative Time, so this step is no longer necessary in this Advanced Profile.

Not Needed n/a AO e.g. 337

7. Set the meaning of the Y-values (targets) of the curve Optional Direct Operate / Response AO e.g. 338

8.

(Document the category and type of the schedule) This step is no longer necessary in this Advanced Profile.

Not Needed n/a AO e.g. 313., 314

9. Set the identity of the schedule to a unique number. Required Direct Operate / Response AO e.g.312

10. Set the time and repetition interval to execute the next schedule enabled.

Required Write / Response

Indexed Time and Date with Long Interval (g50v4)10

0

11.

EITHER Enable the Schedule by writing the corresponding unique identity value to this data point (Basic Profile)

Required Select / Response, Operate / Response AO 636

OR Enable the Schedule by changing its state to “ready” (Advanced Profile)

Required Select / Response, Operate / Response BO e.g.29

Using this Advanced Profile, it is possible to create and enable more than the12 schedules defined in the Basic Profile, by using the “Schedule ‘n’” points (AO662 – AO716). Only one of these additional schedules can be edited or viewed at a time, as described in section 2.3.2. The Schedule Edit Selector point (AO662) determines which schedule is “visible” for editing and viewing. One other difference in these additional schedules is that it is possible to define a different Ramp Type for each schedule point.

10 The structure and use of Object Group 50 Variation 4 is defined in IEEE Std. 1815-2012 2013-01-14 AN2013-001 DNP3 Profile for Advanced PV Generation and Storage

Table 49 – Steps to create and enable additional schedules beyond the first 12


1.

Select which schedule to edit by writing a number greater than 12 to this point. This is the “index” of the schedule, not its “identity”. The indexes shall be the monotonically increasing integers 12, 13, 14 .etc. while the curve identities may be any unique number.


2.

Set the Time Offset (X-Value) for each schedule point. Time Offsets must increase with each point. Time Offsets represent relative seconds from each repetition of the schedule.

Optional Direct Operate / Response AO 707, 708, 709

3. Set the Y-value for each schedule point Optional Direct Operate / Response AO 667, 668, 669

4. Set the Ramp Type for each schedule point Optional Direct Operate / Response AO 687, 688, 689

5.

Set the number of points used for the schedule. Set this value to zero to disable the schedule.


6. Set the priority for the schedule Optional Direct Operate / Response AO 664

7. Set the meaning of the Y-values of the schedule Optional Direct Operate / Response AO 666

8. Set the identity of the schedule to a unique number. Required Direct Operate / Response AO 663

9. Set the time and repetition interval to execute the next schedule enabled.

Required Write / Response

Indexed Time and Date with Long Interval (g50v4)11

0

10. Enable the Schedule by changing its state to “ready” Required Select / Response,


2.4 Interaction Between Settings Because there are so many different PV and storage functions that can be performed using this profile, it is important to define what happens when two or more of these functions are applied at the same time. This section provides that definition.

2.4.1 Remote/Local Mode

The purpose of “local” mode is to block commands from offsite sources to enable safe local maintenance and diagnostics and to provide a means for secure onsite management. When an outstation is placed in “local” mode, it is to only respond to commands originating from an onsite source. These local commands might be via a local communication port, direct controls at the outstation, or other local

11 The structure and use of Object Group 50 Variation 4 is defined in IEEE Std. 1815-2012 2013-01-14 AN2013-001 DNP3 Profile for Advanced PV Generation and Storage

interface mechanisms as selected by manufacturers. The means by which the outstation determines which communications are “onsite” and which are “offsite” are outside the scope of this specification. Notionally, the commands to place an outstation an “local” mode and to return it to “remote” mode are initiated onsite.

When the outstation is in “local” mode, the outstation shall not permit the master to perform any of the active functions described in this specification. This includes all the functions except the “DS” (data and status) functions. The local/remote state of the outstation is provided in BI6.

2.4.2 Automatic/Manual Mode If the master changes the state of BO6 from “Auto” to “Non-Auto”, also known as “manual” mode, the outstation is to no longer change its behavior automatically. This action may vary between devices, but the following is recommended:

• INV1: Connect/disconnect, leave in current position

• INV2: Limited Watts mode, leave at current setpoint

• INV3: Fixed power factor, leave at current setpoint

• INV4: Battery charging and discharging, leave at current setpoint

• INV5: Pricing signal, leave at current setpoint

• DS91: Changing settings permitted because these are considered “manual” changes. If it is desired to disable remote settings changes, “local” mode should be enabled.

• DS92: Logging, continue

• DS93: Monitoring, continue

• All other functions: Disable all curves. Maximum ramp rate continues to apply while disabling any active curve.

• Schedules: Do not take any scheduled actions in “non-Auto” mode

The intent of this recommended behavior is that the outstation should not make any autonomous decisions while in “Non-Auto” mode.

2.4.3 Priority of Last Command The outstation shall give priority to whichever function is applied most recently. Consider the following example:

1. At 8:00 am, the master programs a schedule, starting immediately, for the outstation to start delivering 50% maximum generation until 4:00 pm, at which time it is to start delivering 75% maximum generation until midnight. The outstation begins executing the program.

2. At 3:00 pm, a master sends commands to manually adjust the maximum generation to 25% (Function INV2). The outstation adjusts its output accordingly.

3. At 4:00, the previously scheduled event occurs and the outstation changes to 75% maximum generation as instructed.

4. When the schedule ends at 12:00 midnight, the outstation remains at 75% maximum generation because that is what it was last commanded to do. It does not, for instance, return to 25%.

Note that throughout this process, the outstation remains in Limited Watts Mode, as shown by the appropriate binary input point. The schedule also remains in place, as shown by the appropriate analog input point.

The two rules are therefore:


• The outstation behaves according to whichever message, mode, curve or schedule most recently commanded it.

• The outstation does not “remember” what it was doing before the previous command. In the absence of a new command, it continues what it was last commanded to do.

2.4.4 Guidelines for Precedence of Settings It is nevertheless possible for several different limits and intelligent control functions for distributed energy resources to be in effect simultaneously. In many cases multiple limits or control functions that affect the same parameter, such as Watts or VARs output, may be active at the same time. The purpose of this section is to specify the way these settings behave when simultaneously active and, where necessary, to establish an order of precedence.

Settings Affecting Watt Output The PV / Storage system’s active power (Watt) output may be affected by the settings identified in Table 50 , according to order of precedence.


Table 50 – Priority of Settings Affecting Watt Output Priority Settings/Functions Description

1st ( Highest )

Fundamental Physical Limits

Energy Source or Self-Imposed Limits

A system cannot produce power that it does not have available and may have other practical limits related to its present circumstances. Although these limitations do not show up as controls, they do establish the ultimate limits of the system. This would include any limits on Wattage that result from availability of solar resources or limits that an inverter imposes on itself, based on thermal conditions, errors, failures, etc. No other setting or condition may cause an inverter to violate these self-imposed limits.

2nd

Nameplate and Device

Limits

Maximum Active Power Capability Setting

(AO22)

Maximum Charge / Discharge Rate (AO55, AO56)

These configurable settings establish the DER’s maximum Wattage output at the Electrical Connection Point (ECP). This establishes the maximum allowed output from the DER at any time in terms of Watts. Higher or Lower priority settings may reduce the Wattage output below this value, but nothing may increase it above this value. Nameplate Watt rating (section 2.2.9) is for informational purposes and has no direct effect on Watt output.

3rd

Actively Affecting Operating

Boundaries

Adjust Maximum Generation Level

(AO15) Section 2.3.6

These intelligent functions, or the scheduled equivalent, serve to reduce maximum allowed Watt output to some percentage of its Maximum Capability less than 100%. The information that cause these reductions to occur varies (e.g. undesirable voltage, undesirable frequency, utility command ). These functions may be simultaneously active. Their relative priority is equal. The one requiring the greatest reduction in Watts (lowest percentoutput at any time) takes precedence. As functions intended to establish operating boundaries, these functions are higher priority than any of the dynamic (priority 4) or steady-state (priority 5) functions. Those functions may be active at the same time as these functions, but must operate (even dynamically) within the boundaries established by these functions.

Frequency-Watt Control

Section 2.3.16

Static Volt-Watt Control Section 2.3.20

4th Dynamic

Functions – Only

Transiently Active

Real Power Smoothing Section 2.3.22

These are dynamic functions, and produce “Additional” Watts that add-toor subtract-from whatever the present output power level may be based on unrestrained generation or one of the 5th priority functions listed below. These functions are equal priority, but are never in conflict because they produce additive Watts. These and other Watt-managing functions are complimentary and may simultaneously be active.

Dynamic Volt-Watt Section 2.3.23

5th

Steady-State Functions

Managing Watt Input/Output

Charge/Discharge Storage (AO16)

Section 2.3.8

These functions may be used to manage the flow of real power into or out of the DER. They are mutually exclusive and cannot be enabled simultaneously.

These functions have a lower order of precedence than those above and may not, at any time, prevent the operation of the 4th priority dynamic functions or result in a violation of the Watts limits set by any of the 3rd priority boundary settings listed above. For example, consider a device that is currently scheduled to discharge its battery at 80% of its max discharge rate, and this amounts to 3KW. If this same system has A Maximum Capability setting of 5KW, but is currently under a 50% reduction limit due to a Maximum Generation Level (AO15) function, then total power out from the storage and any local PV combined may not exceed 2.5KW.

If a device has an active charge/discharge command or schedule this takes precedence over a price or price or price schedule that might otherwise be used to manage battery charging and discharging.

Pricing Signal (AO19)

Section 2.3.9 or 2.3.21

Peak Power Limiting Section 2.3.24

Load/Generation Following

Section 2.3.25

Isochronus Mode Section 2.5.5


Settings Affecting VAR Output The PV / Storage system’s VAR output may be affected by the settings identified in Table 51, according to order of precedence.

Table 51 – Priority of Settings Affecting VAR Output Priority Settings/Functions Description

1st ( Highest )

Fundamental Physical Limits

Self-Imposed Limits

A system may have practical limits related to its present circumstances that limit its ability to produce VARs. Although these limitations do not show up as controls, they do establish the ultimate limits of the system at any time. This would include any limits on VARs that an inverter imposes on itself, based on thermal conditions, errors, failures, etc. No other setting or condition may cause an inverter to violate these self-imposed limits.

2nd

Nameplate and Device

Limit Settings

Nominal Maximum VARs Capability

Setting (AO24)

This is the configurable setting establishing the DER’s maximum VAR output at the Electrical Connection Point (ECP). This establishes the maximum reactive power output from the DER at any time in terms of VARs. Higher or Lower priority settings may reduce the VAR output below this value, but nothing may increase it above this value. Nameplate VAR rating (section 2.2.9) is for informational purposes and has no direct effect on VAR output.

3rd Settings Actively Affecting Operating

Boundaries

None Defined for VARs at this time N/A

4th Dynamic

Functions – Only

Transiently Active

Dynamic Reactive Current Support Section 2.3.17

This is a dynamic function, and produces “Additional” reactive current that adds-to or subtracts-from whatever the present reactive current level may be based on one of the 5th priority functions listed below.

5th Steady State

Functions Managing VAR Input / Output

Adjust Power Factor (AO17)

Section 2.3.7 These functions instruct the DER as to the desired level of VARs to produce at any time. For all these, the VAR level is directly or indirectly related to the Watt output. These functions have equal priority, but are never in conflict because they are mutually exclusive and only one may be effective at any time. In the event of confusion where commands regarding both functions are being received by the DER, the most recent function to be made active by either direct command or by schedule shall take effect, as discussed in section 2.4.1. For example, consider a DER that has a Volt-VAR schedule that specifies Volt-VAR Array Mode 1 from 4PM until 8PM, and Volt-VAR Array Mode 2 at all other times. If this system switched to Volt-VAR Array Mode 1 at 4PM, then at 5PM received a Power Factor setting, the Power Factor would take effect and remain in effect until 8PM when Volt-VAR Array Mode 2 would resume.

Watt-Power Factor Mode (AO819) Section 2.3.19

Volt-VAR Array Modes (AO14)

Section 2.3.14

Price or Temperature Curves affecting

VARs Section 2.3.21

Isochronus Mode Section 2.5.5


2.5 Grid Configurations and Islanding The term “grid configuration” is used in this profile to refer to the structure of the grid or power system into which the DER is connected. Specifically, it recognizes that the topology of this power system may change for a variety of reasons, including switch operations that might reconfigure the circuit (e.g. networked feeders), formation of large area or small area islands, alternate modes of grid operation, etc. These are all referred-to as “grid configurations” herein.

This profile defines parameters specifying how the DER will automatically switch to alternate settings when the local grid configuration changes, such as when islanding and circuit switching takes place.

2.5.1 Possible Grid Configurations This profile assumes there may be many different grid configurations. It defines standard numbers for the following minimum set:

<0> Not Used

<1> Unspecified / Autonomously Determined

<2> Factory Configuration

<3> Default Configuration / Communications Lost

<4> Normal Grid-Connected Configuration

<5> Islanded Condition 1 (small, local island)

<6> Islanded Condition 2 (larger, area island)

<7> Islanded Condition 3 (largest, regional island)

<8> 1st Alternate Grid-Connected Configuration

<9> 2nd Alternate Grid-Connected Configuration

<10> 3rd Alternate Grid-Connected Configuration

<11-255> Reserved for future assignment

2.5.2 Settings Groups

To adjust to changing grid configurations, the outstation shall contain within its memory multiple copies of all its settings, including setpoints, curves, modes and schedules, as illustrated in Figure 30. These “settings groups” shall include:

• All of the Analog Outputs in the profile except those controlling the settings groups themselves (AO912 and AO913)

• All of the Binary Outputs in the profile except the Disconnect Switch (BO0) and those controlling the settings groups (BO42 and BO43)

The settings groups shall not include any of the Binary Inputs, Double-Bit Binary Inputs, Counters, Analog Inputs, Device Attributes (including nameplate data), Logs or other data types defined in the profile.

The number of settings groups supported by any outstation is a local decision based on available resources. Just as manufacturers may choose which standard functions to support, it is suggested that they may also choose to limit which settings are actually different from one settings group to another.

NOTE: Although these settings groups share a name and perform a similar function to the mechanism in IEC 61850 known as “settings groups”, the mechanism and the manner of its use are completely different.


Figure 30 – Settings Groups

2.5.3 Settings Group Control Parameters

Figure 31 illustrates how settings groups can be edited, viewed and switched based on a few parameters.

The boxes in the center of the figure represent the various settings groups, with the green shapes inside each box representing the various settings, arrays, schedules, and other parameters that are included in each group.

The switch shown to the left provides a means by which a master can write-to a selected settings group. The group being written-to may or may not be presently active.

The switch shown to the right determines which settings group is presently active. As indicated by the “Decision Logic” block, the active settings group may be determined by whatever is presently requested via the communication channel, but may also be determined by a range of additional factors.

The following points implement the parameters shown in Figure 31:

• Requested Settings Group (AO912)

• Active Settings Group (AI67)

• Settings Group Being Edited (AO913)


Figure 31 – Parameters for Controlling Settings Groups

2.5.4 Sensing the Grid Configuration

As illustrated in Figure 32, a variety of factors in addition to the Requested Settings Group written by the master may affect the selection of the Active Settings Group by the outstation.

Figure 32 – Possible Inputs Determining Active Settings Group

One of the most important factors is that the outstation may be capable of automatically detecting its grid configuration (particularly, whether it is islanded or not). The master may enable or disable this capability by writing to the Enable Sensed Grid Config Detection binary output point (BO42). However, even if Sensed Grid Config Detection is disabled by the master, the Active Settings Group may still differ from the Requested Settings Group depending on the decision logic and other parameters.

2.5.5 Modes of Operation When Islanded

When islanding takes place, the outstation may behave in one of two modes, as illustrated in Figure 33:

• Isochronous mode, in which the DER attempts to control the voltage and frequency within the islanded section of the grid. Isochronous mode is intended to be something like a PID control


mode in which the isochronous DER attempts to control to an absolute value of frequency and voltage independent of Watt/VAR load up to the limits of the machine’s capabilities. In effect, the isochronous machine operating in an islanded scenario assumes the role played by the utility in a non-islanded scenario. It ignores the various curves and modes it would normally use in grid-connected configuration.

• Droop mode, in which the DER supports the efforts of a DER in isochronous mode using Volt/VAR curves, load/generation following and other functions, as it did when connected to the grid. DERs in droop mode are intended to follow the lead of an isochronous DER, utilizing the previously defined Volt/VAR curve function and Frequency/Watt curve functions, but using alternate settings as defined for the particular islanded condition, to achieve the desired droop characteristics. A DER acting in droop mode behaves similarly to when it was connected to the grid, but using a different set of curves and parameters.

The data point Islanded Mode (BO43) determines which of these two modes the outstation shall use in the Islanded grid configurations.

Figure 33 – Grid Configuration and Islanding Context


2.6 Implementation Table Table 52 shows the objects and function codes that shall be supported by the master and outstation implementing this profile. This represents a Level 4 implementation. (Refer to Annex A of IEEE 1815-2010) However, most functions can be accomplished using Level 1 or Level 2 features such as Class Data polling, as discussed in 2.3.12. Note that no counter objects are required for this profile.


Table 52 – DNP3 Implementation Table for the PV/Storage Profile

DNP OBJECT GROUP & VARIATION REQUEST Master may issue Outstation must parse

RESPONSE Master must parse Outstation may issue

Group Num

Var Num Description Function Codes

(dec) Qualifier Codes (hex)

Function Codes (dec)

Qualifier Codes (hex)

0

211-239 241-243 248-250 252

Device Attributes 1 (read) 00 (start-stop) 129 (response) 00 (start-stop) 17 (index)

0 240 245-247 Device Attributes

1 (read) 00 (start-stop) 129 (response) 00 (start-stop) 17 (index)

2 (write) 00 (start-stop)

0 254 Device Attributes – Non-specific all attributes request 1 (read) 00, 01 (start-stop)

06 (no range, or all)

0 255 Device Attributes – List of attribute variations 1 (read) 00, 01 (start-stop)

06 (no range, or all) 129 (response) 00 (start-stop) 5B (Free Format)

1 0 Binary Input – Any Variation 1 (read) 22 (assign class)

00, 01 (start-stop) 06 (no range, or all)

1 1 Binary Input – Packed format 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

1 2 Binary Input – With flags 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

2 0 Binary Input Event – Any Variation 1 (read) 06 (no range, or all) 07, 08 (limited qty)

2 1 Binary Input Event – Without time 1 (read) 06 (no range, or all) 07, 08 (limited qty)

129 (response) 130 (unsol. resp) 17, 28 (index)

2 2 Binary Input Event – With absolute time 1 (read) 06 (no range, or all)

07, 08 (limited qty) 129 (response) 130 (unsol. resp) 17, 28 (index)

2 3 Binary Input Event – With relative time 1 (read) 06 (no range, or all) 07, 08 (limited qty)


3 0 Double-bit Binary Input – Any Variation 1 (read) 22 (assign class)


3 1 Double-bit Binary Input – Packed format 1 (read) 00, 01 (start-stop)

06 (no range, or all) 129 (response) 00, 01 (start-stop)

3 2 Double-bit Binary Input – With flags 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

4 0 Double-bit Binary Input Event – Any Variation 1 (read) 06 (no range, or all)

07, 08 (limited qty)

4 1 Double-bit Binary Input Event – Without time 1 (read) 06 (no range, or all)


4 2 Double-bit Binary Input Event – With absolute time 1 (read) 06 (no range, or all)


4 3 Double-bit Binary Input Event – With relative time 1 (read) 06 (no range, or all)


10 0 Binary Output – Any Variation 1 (read) 00, 01 (start-stop) 06 (no range, or all)

10 2 Binary Output – Output status with flags 1 (read) 00, 01 (start-stop)


11 0 Binary Output Event – Any Variation 1 (read) 06 (no range, or all) 07, 08 (limited qty)

11 1 Binary Output Event – Status without time 1 (read) 06 (no range, or all)





Group Num





11 2 Binary Output Event – Status with time 1 (read) 06 (no range, or all) 07, 08 (limited qty)


12 1 Binary Command – Control relay output block (CROB)

3 (select) 4 (operate) 5 (direct op) 6 (dir. op, no ack)

17, 28 (index) 129 (response) echo of request

13 0 Binary Output Command Event – Any Variation 1 (read) 06 (no range, or all)


13 1 Binary Output Command Event – Command status without time 1 (read) 06 (no range, or all)


13 2 Binary Output Command Event – Command status with time 1 (read) 06 (no range, or all)


20 0 Counter – Any Variation

1 (read) 7 (freeze) 8 (freeze noack) 9 (freeze clear) 10 (frz. cl. noack)


20 1 Counter – 32-bit with flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

20 2 Counter – 16-bit with flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

20 5 Counter – 32-bit without flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

20 6 Counter – 16-bit without flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

21 0 Frozen Counter – Any Variation 1 (read) 22 (assign class)


21 1 Frozen Counter – 32-bit with flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

21 2 Frozen Counter – 16-bit with flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

21 5 Frozen Counter – 32-bit with flag and time 1 (read) 00, 01 (start-stop)


21 6 Frozen Counter – 16-bit with flag and time 1 (read) 00, 01 (start-stop)


21 9 Frozen Counter – 32-bit without flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

21 10 Frozen Counter – 16-bit without flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-stop)

22 0 Counter Event – Any Variation 1 (read) 06 (no range, or all) 07, 08 (limited qty)

22 1 Counter Event – 32-bit with flag 1 (read) 06 (no range, or all) 07, 08 (limited qty)


22 2 Counter Event – 16-bit with flag 1 (read) 06 (no range, or all) 07, 08 (limited qty)


23 0 Frozen Counter Event – Any Variation 1 (read) 06 (no range, or all) 07, 08 (limited qty)

23 1 Frozen Counter Event – 32-bit with flag 1 (read) 06 (no range, or all)





Group Num





23 2 Frozen Counter Event – 16-bit with flag 1 (read) 06 (no range, or all)


23 5 Frozen Counter Event – 32-bit with flag and time 1 (read) 06 (no range, or all)


23 6 Frozen Counter Event – 16-bit with flag and time 1 (read) 06 (no range, or all)


30 0 Analog Input – Any Variation 1 (read) 22 (assign class)


30 1 Analog Input – 32-bit with flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-

stop)

30 2 Analog Input – 16-bit with flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-

stop)

30 3 Analog Input – 32-bit without flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-

stop)

30 4 Analog Input – 16-bit without flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-

stop)

30 5 Analog Input – Single-prec flt-pt with flag 1 (read) 00, 01 (start-stop)


32 0 Analog Input Event – Any Variation 1 (read) 06 (no range, or all) 07, 08 (limited qty)

32 1 Analog Input Event – 32-bit without time 1 (read) 06 (no range, or all)


32 2 Analog Input Event – 16-bit without time 1 (read) 06 (no range, or all)


32 3 Analog Input Event – 32-bit with time 1 (read) 06 (no range, or all) 07, 08 (limited qty)


32 4 Analog Input Event – 16-bit with time 1 (read) 06 (no range, or all) 07, 08 (limited qty)


32 5 Analog Input Event – Single-prec flt-pt without time 1 (read) 06 (no range, or all)


32 7 Analog Input Event – Single-prec flt-pt with time 1 (read) 06 (no range, or all)


34 0 Analog Input Deadband – Any Variation 1 (read) 00, 01 (start-stop)

06 (no range, or all)

34 1 Analog Input Deadband – 16-bit 1 (read) 00, 01 (start-stop)


2 (write) 00, 01 (start-stop) 06 (no range, or all)

34 2 Analog Input Deadband – 32-bit 1 (read) 00, 01 (start-stop)



34 3 Analog Input Deadband – Single-prec flt-pt

1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-

stop)


40 0 Analog Output Status – Any Variation 1 (read) 00, 01 (start-stop) 06 (no range, or all)




Group Num





40 1 Analog Output Status – 32-bit with flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-

stop)

40 2 Analog Output Status – 16-bit with flag 1 (read) 00, 01 (start-stop) 06 (no range, or all) 129 (response) 00, 01 (start-

stop)

40 3 Analog Output Status – Single-prec flt-pt with flag 1 (read) 00, 01 (start-stop)


41 1 Analog Output – 32-bit



41 2 Analog Output – 16-bit



41 3 Analog Output – Single-prec flt-pt



42 0 Analog Output Event– Any Variation 1 (read) 06 (no range, or all) 07, 08 (limited qty)

42 1 Analog Output Event – 32-bit without time 1 (read) 06 (no range, or all)


42 2 Analog Output Event – 16-bit without time 1 (read) 06 (no range, or all)


42 3 Analog Output Event – 32-bit with time 1 (read) 06 (no range, or all) 07, 08 (limited qty)


42 4 Analog Output Event – 16-bit with time 1 (read) 06 (no range, or all) 07, 08 (limited qty)


42 5 Analog Output Event – Single-prec flt-pt without time 1 (read) 06 (no range, or all)


42 7 Analog Output Event – Single-prec flt-pt with time 1 (read) 06 (no range, or all)


43 0 Analog Output Command Event– Any Variation 1 (read) 06 (no range, or all)


43 1 Analog Output Command Event – 32-bit without time 1 (read) 06 (no range, or all)


43 2 Analog Output Command Event – 16-bit without time 1 (read) 06 (no range, or all)


43 3 Analog Output Command Event – 32-bit with time 1 (read) 06 (no range, or all)


43 4 Analog Output Command Event – 16-bit with time 1 (read) 06 (no range, or all)


43 5 Analog Output Command Event – Single-prec flt-pt without time 1 (read) 06 (no range, or all)


43 7 Analog Output Command Event – Single-prec flt-pt with time 1 (read) 06 (no range, or all)


50 1 Time and Date – Absolute time 1 (read) 07 (limited qty = 1) 129 (response) 07 (limited qty)

(qty = 1)

2 (write) 07 (limited qty = 1)




Group Num





50 3 Time and Date – Absolute time at last recorded time 2 (write) 07 (limited qty = 1)

50 4 Time and Date – Indexed absolute time and long interval

1 (read) 2 (write)

00, 01 (start-stop) 06 (no range, or all) 17, 28 (index)

129 (response) 00, 01 (start-stop) 17, 28 (index)

51 1 Time and Date CTO – Absolute time, synchronized 129 (response)

130 (unsol. resp) 07 (limited qty) (qty = 1)

51 2 Time and Date CTO – Absolute time, unsynchronized 129 (response)

130 (unsol. resp) 07 (limited qty) (qty = 1)

52 1 Time Delay – Coarse 129 (response) 07 (limited qty) (qty = 1)

52 2 Time Delay – Fine 129 (response) 07 (limited qty) (qty = 1)

60 1 Class Objects – Class 0 data 1 (read) 06 (no range,or all)

60 2 Class Objects – Class 1 data

1 (read) 06 (no range, or all) 07, 08 (limited qty)

20 (enbl. unsol.)

21 (dab. unsol.)

22 (assign class) 06 (no range,or all)



20 (enbl. unsol.)

21 (dab. unsol.)




20 (enbl. unsol.)

21 (dab. unsol.)


80 1 Internal Indications – Packed format 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-

stop)

2 (write) 00 (start-stop) index=7

85 1 Data Set Prototype 1 (read) 06 (no range or all) 129 (response) 5B (object size)

86 1 Data Set Descriptor – Data set contents 1 (read) 06 (no range or all) 129 (response) 5B (object

size)

86 2 Data Set Descriptor – Characteristics 1 (read) 06 (no range or all) 129 (response) 5B (object

size)

86 3 Data Set Descriptor – Point index attributes 1 (read) 06 (no range or all) 129 (response) 5B (object

size)

87 1 Data Set Event - Snapshot 1 (read) 06 (no range or all) 129 (response) 5B (object size)

No Object (function code only) 13 (cold restart)

No Object (function code only) 23 (delay meas.)


3 Conclusions This application note defines how the photovoltaic generation and storage functions defined by the EPRI report Common Functions for Smart Inverters and captured in IEC 61850-90-7 technical report shall be implemented using DNP3. The profile defined here is designed so the data reported by the outstation can be easily mapped onto a standard IEC 61850-7-420 distributed energy resource implementation.

4 Submitted By Electric Power Research Institute 3420 Hillview Avenue, Palo Alto, California 94304-1338 PO Box 10412, Palo Alto, California 94303-0813 USA 800.313.3774 ▪ 650.855.2121 ▪ [email protected] ▪ www.epri.com Prepared by: EnerNex 620 Mabry Hood Road Suite 300 Knoxville, TN 32769 USA 865.218.4600 ▪ www.enernex.com

5 Disclaimer Application Notes contain application information developed by users and are provided for the benefit of other users. This note illustrates how the features of DNP3 are used to meet specific user requirements. This Application Note has been reviewed by the DNP Technical Committee. It does not contain all of the details that are mandatory for a complete DNP3 implementation, and the Committee does not warrant that the approach taken is the only way to use DNP3 to meet the user requirements.

6 Technical Committee Commentary This section is reserved for Technical Committee comments regarding the application note.


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