Download P2030 Smart Grid Standard Text Submittal Form This text is

P2030 Smart Grid Standard Text Submittal Form
This text is intended as proposed text for consideration of the P2030 Writing Group to the
P2030 Draft Guide for Smart Grid Interoperability of Energy Technology and Information
Technology Operation with the Electric Power System (EPS), and End-Use Applications and
Loads.
SUBMITTAL INFORMATION
DATE SUBMITTED: 6/28/2017
SUBMITTED BY: P2030-TF1 Distribution working group
AFFILIATION:
EMAIL:
TEXT PLACEMENT INFORMATION
IN THE P2030 OUTLINE DRAFT (MENTOR DOC#180-2010):
CLAUSE #: 6
CLAUSE HEADING: DISTRIBUTION DOMAIN
PROPOSED TEXT
6.3.1.3 Distribution domain
The Distribution EPS (Figure 9) includes actors located throughout the electric power system.
The distribution substation actor represents many components located on a common site that
cannot be assigned to the distribution protection and control devices actor nor the distribution
sensors and measurement devices actor. In addition the distribution energy resource (DER)
actor represents generation and storage of all kinds that are connected directly to the
distribution EPS but not through a load customer interconnection, recognizing that there are
also DER in the customer domain.
1|Pa g e
CONTROL/OPERATIONS
D8
MARKETS
D2
D4
Distribution
Protection and
Control
Devices
D5
Distribution
Substation
D10
TRANSMISSION
D1
D11
D14
D3
D17
D7
D15
Sensors and
Measurement
Devices
Distributed
Energy Resource
(DER)
D16
D9
D6,D20
D12
D21
DISTRIBUTION
BULK
GENERATION
SERVICE PROVIDERS
CUSTOMER
Figure 9 – Distribution domain of the power interoperability perspective
The distribution domain has strong data paths to the distribution operation/control actor in the
operations/control domain. These data paths reflect the centralized control of the distribution
EPS from the distribution control center. The distribution domain may also have a data path to
the transmission substation actor in the transmission domain, representing only protection and
control systems.
6.4.1.1 Information transfer time
Information transfer time is the time from when the first byte of information from the
transmitting application layer to when the information is delivered to the receiving application
layer (i.e. first byte sent by source application to last byte received by destination application).
The transfer time includes the communications system latency (i.e. is technology and path
dependent), and any required connection time (e.g. dial-up). Without these inclusions, there
should not be a need to define information transfer time.
Various distribution domain functions will have not-to-exceed transfer time requirements
(sometimes referred to as “tolerable delay” or “latency”) which must be met by the
communications system:
∙ Tele-Protection (people or equipment safety) - Low latency of ~1ms is for networked
systems (e.g. transmission system or closed-loop distribution network) where there are
issues with transient stability; latency of up to ~2cycles for open-loop systems.
∙ Control/Monitor (operator/computer decision to improve reliability/efficiency) Medium to High latency of up to 3s depending on the functional requirements of the
computer system (e.g. DMS or EMS or Advanced Applications), and within 2s of the
formation of an unintentional DR island.
∙ Billing (financial support or historical information) - High latency of a few hours or longer
depending on the billing functional requirements (e.g. monthly, Time-of-Use, Critical Peak
Pricing, Demand Response, Remote disconnect-reconnect, etc.).
2
∙
File Transfer - Medium latency for transfer of event data, firmware, settings, etc.
6.4.1.2 Latency
Latency is channel access delay plus the propagation delay (first byte transmitted on the
medium to first byte received at the destination), including queuing and processing delays but
not any time required by the source or destination application to aggregate data, incorporate
data into protocols and perform data verification.
Queuing delay occurs when a gateway receives multiple packets from different sources heading
towards the same destination. Since typically only one packet can be transmitted at a time,
some of the packets must queue for transmission, incurring additional delay.
Processing delays are incurred while a gateway determines what to do with a newly received
packet. The combination of propagation, serialization, queuing, and processing delays often
produces a complex and variable network latency profile. The aggregate latency shall meet the
total of all latency expected between the sender and the receiver and may represent the
accumulated latency of multiple latency actions.
Define jitter?
6.4.1.3 Reliability
For the purposes of this guideline, reliability is a measure of the probability of the desired data
packet being accurately delivered in the required time, without exception. Reliability also has a
qualitative definition to describe functional requirement:
∙ Critical. The failure of information transfer may result in compromised safety or damage
to equipment.
∙ Essential. The failure of information transfer may result in inefficient or ineffective
operation
∙ Important. The failure of information transfer may result in loss of revenue, damage to
public image, or loss of technical information
∙
Non-essential. Not critical, essential, or important.
On the distribution domain, tele-protection data is critical, control/monitor data is essential and
billing & file transfer data is important. Single path reliability is typically acceptable and is an
economics issue (e.g. loss of Tele-Protection relies on backup protection; loss of Control relies
on on-site intervention; loss of Monitor relies on previous measurement; loss of Billing relies on
on-site intervention) except for extreme circumstances.
6.4.1.4 Data volume
A measure of the total amount of data to be carried in a given communications path. For
example, the amount of data from one piece of substation equipment, times the number of that
kind of equipment in the substation plus the protocol required for the data transmission.
6.4.1.5 Data occurrence interval
A data occurrence interval is a length of time between a communication start and a subsequent
communication start, which may be periodic (e.g. synchrophasor sample) or a periodic (e.g.
voltage reading). Update Frequency is often used to describe the functional requirement:
∙
Synchronous – Updates in much less than a cycle.
∙ Real-time - Updates once every few seconds or more frequently as required by
computer system (e.g. DMS or EMS), with provision for on-demand update.
3
∙ Near real-time - Updates once every five to fifteen minutes or more frequently as
required by operator or computer system (e.g. DMS or EMS), with provision for on-demand
update.
∙
Historical – Updates once per day or less frequently.
6.4.1.6 Security
A measure of the immunity from attack that a given communications function must have. This
includes cyber attacks and physical attacks, including electromagnetic attacks.
6.4.1.7 Priority
Priority refers to relative importance of communicating the data. Typically aligned with the
reliability functional requirements, though a particular critical message can have higher priority
than other critical messages.
6.4.1.8 Time Synchronization
The timing requirements placed on measurement and control systems are becoming
increasingly stringent. Traditionally these measurement and control systems have been
implemented in a centralized architecture in which the timing constraints are met by careful
attention to programming combined with communication technologies with deterministic
latency. Time Synchronization (per IEEE 1588) enables precise synchronization of clocks in
measurement and control systems implemented with technologies such as network
communication, local computing and distributed objects.
6.4.1.9 Level of assurance
Not sure why this is separate from Reliability.
6.4.10 Broadcast method
A mechanism to send a single message to a group or all of the devices connected at a particular
network layer.
6.5.2 Operations data
Bi-directional information and instruction flow requires frequent updating and provides a
snapshot of the grid. Examples include tele-protection data and control / monitor data such as
electrical quantities, operation modes, demand, energy consumption/production, etc.
6.5.3 Reporting and engineering data
Information uploaded on a demand or scheduled basis. Examples include availability, run-time
data, oscillography, event files, fault records, firmware updates, setting files, etc.
Appendix
Monitoring
Equipment
(Sensors)
Reporting
Equipment
CT, VT
Transducer
and/or IED
Distribution
Transformer
substation
CT, VT
Transducer
and/or IED
Distribution
Tap Changer
substation
IED
IED
CT, VT
Transducer
and/or IED
Actor
Equipment
Distribution
HV Bus
substation
Distribution
LV Bus
substation
Metric / Value
MVA, MW, MVAR (3ph)
Peak Demand w/ local reset
MWh throughput
Ia, Ib, Ic, In
Vab, Vbc, Vca
MVA, MW, MVAR (3ph)
Oil Temp, Oil Level, Gas in Oil
Winding Hotspot Temp
LTC Tap Position
LTC V Setpoint
Ia, Ib, Ic, In
Vab, Vbc, Vca
Va, Vb, Vc
4
Data Source
Transfer
Update
Time
Frequency (Tolerable
Delay)
Telemetered
or Derived
Real-time
Copper or aluminum conductor
Control /
found in substation and some
Monitor
substation equipment
Telemetered
Real-time
Substation incoming power
Control / transformer converting
Monitor transmission voltage to
distribution voltages.
Telemetered
Real-time
Telemetered
Real-time
Description of Item
Control / Built-in or separate tap changer
Monitor unit in station transformer
Copper or aluminum conductor
Control /
found in substation and some
Monitor
substation equipment
Actor
Equipment
Monitoring
Equipment
(Sensors)
Reporting
Equipment
Metric / Value
Data Source
Transfer
Update
Time
Frequency (Tolerable
Delay)
Telemetered
Near realtime
Description of Item
MVA, MW, MVAR (3ph)
Harmonic Mean & High Log,
Sag/Swell, ITI Disturbances,
Voltage Characteristics
Distribution
substation / SVC - Static Var
protection Compensator
Self
and control or STATCOM contained
devices / Static
CT, VT
sensors and Synchronous
measureme Compensator
nt devices
Distribution Shunt
substation Capacitors
CB
Self
contained
IED
RTU
Transducer,
Distribution
CT or Self
Protective
Circuit Breaker
substation
contained CT Relay, IED
and/or RTU
Distribution
Circuit
substation /
Recloser
sensors and
(Electronic
measureme
Controls)
nt devices
Self
contained
CT, VT
Self
contained
IED
Ia, Ib, Ic, In
Vab, Vbc, Vca
MVA, MW, MVAR (3ph)
Setpoints
Status: Open/Close
Status: Open/Close
Ia, Ib, Ic
Fault Current & Tags,
Alarms
Status: Open/Close
Ia, Ib, Ic, In
Fault Current & Tags
Vab, Vbc, Vca
MVA, MW, MVAR (3ph)
MWh throughput
Equipment used to provide Vars
Control / into the distribution system using
Monitor semi-conductor or synchronous
devices.
An assembly of dielectric and
electrodes in a container (case),
with terminals brought out, that is
intended to introduce capacitance
into an electric power circuit (See
IEEE Std. 18-2002 [B9]).
Circuit Breaker - A switching
device capable of making,
carrying, and breaking currents
under normal circuit conditions,
and also making, carrying for a
specified time, and breaking
currents under specified abnormal
conditions such as those of short
circuit (See IEEE Std. Dictionary
1984 [B1]).
Telemetered
Near realtime
Control /
Monitor
Telemetered
Near realtime
Control /
Monitor
and/or
TeleProtection
Telemetered
Near realtime
Device that interrupts the circuit
Control / on a fault than attempts to close
Monitor back in 1 or more times, typically
with some time delay.
Station Service
and Power
Supply
Distribution (Batteries,
substation Battery
Chargers,
Backup
Generator)
Self
Self
Alarms
Telemetered
Near realtime
Batteries - Source of control
voltage power for substation
equipment.
Battery Chargers - Equipment that
converts ac power to dc power
and is used to recharge and
maintain a station battery in a
fully charged condition and to
supply power to dc loads during
normal operation (See IEEE Std.
650-2006 [B16]).
Control /
Backup Generator - An
Monitor
independent source of standby
electrical power that consists of a
diesel-fueled internal combustion
engine (or engines) coupled
directly to an electrical generator
(or generators); the associated
mechanical and electrical auxiliary
systems; and the control,
protection, and surveillance
systems (See IEEE Std. 387-1995
[B11]).
Distribution Communicatio
substation / n (fibre,
sensors and microwave,
measureme copper, radio,
nt devices etc.)
Self
Self
Alarms
Telemetered
Near realtime
Control /
Monitor
Telemetered
Near realtime
Telemetered
Near realtime
Distribution Weather
substation Station
Self
Self
Lat/Long, Ambient Air
Temperature, Wind Speed,
Humidity, Cloud Opacity
Security
Distribution
Camera &
substation
Devices
Self
Self
Alarms, Audio/Video
5
Equipment and procedures to
monitor and report weather
Control /
conditions that may affect the
Monitor
operation of the power network
(See IEEE Std. 1646-2004 [B24]).
Remote visual monitoring,
perimeter monitoring, intrusion
detection, and door/access panel
Control / open/close monitoring to help
Monitor protect hardware and software
from accidental or malicious
access, use, modification,
destruction, or disclosure.
Actor
Equipment
Monitoring
Equipment
(Sensors)
Reporting
Equipment
Metric / Value
Data Source
Transfer
Update
Time
Frequency (Tolerable
Delay)
Description of Item
Security cameras can include
normal CCTV, low-light and
infrared systems. Intrusion
detection systems encompass a
wide range of technologies.
Typically system alarms and
indications are centrally
monitored or relayed to
appropriate manned workstations
to facilitate timely evaluation and
response. Security also pertains
to personnel, data,
communications, and the physical
protection of computer
installations (See IEEE Std. 1547.32007 [B23]).
Distribution
protection
Shunt
and control
Capacitors
devices /
(Electronic
sensors and
Controls)
measureme
nt devices
Distribution
protection
Voltage
and control
Regulators
devices /
(Electronic
sensors and
Controls)
measureme
nt devices
Distribution
protection
and control Circuit
devices / Interrupter/
sensors and sectionalizer
measureme
nt devices
Distribution
protection O/H Switch
and control (Supervisory)
devices
Distribution
protection
and control UG Switchgear
devices / (Electronic
sensors and Controls)
measureme
nt devices
Distribution
FCI - Faulted
sensors and
Circuit
measureme
Indicators
nt devices
Self
contained
IED
Ia, Ib, Ic, In
Vab, Vbc, Vca
MVA, MW, MVAR (3ph)
Setpoints
Telemetered
Near realtime
An assembly of dielectric and
electrodes in a container (case),
Control / with terminals brought out, that is
Monitor intended to introduce capacitance
into an electric power circuit (See
IEEE Std. 18-2002 [B9]).
Self
contained
CT, VT
Self
contained
IED
Ia, Ib, Ic, In
Vab, Vbc, Vca
MVA, MW, MVAR (3ph)
MWh throughput
Tap Position
V Setpoint
Telemetered
Near realtime
Device that attempts to keep the
Control /
voltage on a distribution line
Monitor
within an acceptable range.
Self
contained
CT, VT
Self
contained
IED
Status: Open/Close
Ia, Ib, Ic, In
Vab, Vbc, Vca
MVA, MW, MVAR (3ph)
Telemetered
Near realtime
Device typically used to switch
Control / equipment; designated fault
Monitor interrupters are able to interrupt
fault current.
Self
RTU
Status: Open/Close
Telemetered
Near realtime
Able to interrupt voltage;
Control /
designated load-break are able to
Monitor
interrupt load current.
Self
contained
CT, VT
Self
contained
IED
Status: Open/Close
Ia, Ib, Ic, In
Vab, Vbc, Vca
MVA, MW, MVAR (3ph)
MWh throughput
Telemetered
Control /
Monitor
Near realand/or
time
TeleProtection
Self
Contained
CT
RTU
Fault Indication,
I, pf, Fault Current
Telemetered
Near realtime
Distribution
sensors and
Amp Meter
measureme
nt devices
Self
Contained
CT
Transducer
and/or IED
I, pf, Ireal
Telemetered
Near realtime
Distribution
sensors and
Power Meter
measureme
nt devices
Self
contained
CT, VT
Transducer
and/or IED
MWh throughput, MVA, MW,
MVAR, V, PQ, Alarms,
Temperature
Telemetered
Near realtime
Distribution
sensors and Ductbanks /
measureme Manholes
nt devices
Transducer
Temperature, Status of
Transducer Auxiliary Equipment (e.g. sump Telemetered
pumps)
Near realtime
Control /
Monitor
Customer Billing meters
Self
Self
MWh throughput, MVA, MW,
MVAR, V, PQ, Alarms
Telemetered
Near realtime
Billing
and/or Meters used by end customers to
Control / monitor and record consumption.
Monitor
Demand
Customer Response
Controls
Self
Self
Undetermined
Telemetered
Near realtime
Control /
Monitor
Self
contained
CT, VT
6
Device that consists of electrical
disconnects, fuses, circuit
breakers/interrupters and/or
motor operators used to isolate
faults, energize or de-energize
equipment.
Control /
Monitor
Instrument transformer that
converts power level currents to
Control /
smaller levels that can be handled
Monitor
by monitoring and protection
devices.
Discrete instrument transformers,
installed on the circuit or on the
distribution transformer, that
Control /
converts power level voltages to
Monitor
smaller levels that can be handled
by monitoring and protection
devices.
Actor
Equipment
Distributed
Distributed
energy
Resource
resource
Customer /
Distributed
Microgrid
energy
resource
Monitoring
Equipment
(Sensors)
Self
Self
Reporting
Equipment
Metric / Value
Self
Ia, Ib, Ic, In
Vab, Vbc, Vca
MVA, MW, MVAR (3ph)
MWh throughput
Setpoints
Self
Ia, Ib, Ic, In
Vab, Vbc, Vca
MVA, MW, MVAR (3ph)
MWh throughput
Setpoints
Transfer
Update
Time
Description of Item
Frequency (Tolerable
Delay)
Control /
Near real- Monitor Generation located along the
Telemetered
time or
and/or distribution lines, and distribution
Real-time
Telesubstations.
Protection
A DR island system that can
separate and isolate itself from
Control / the Distribution EPS seamlessly
Near real- Monitor with little or no disruption or
Telemetered
time or
and/or power quality impact to the loads
Real-time
Teleand can automatically
Protection resynchronize and reconnect itself
to the Distribution EPS in a
seamless fashion.
Data Source
The following reporting equipment are used to provide the Parameters are listed in the
Metric/Value column above:
Transducer - Metering equipment that continuously monitors electric parameters.
PLC - Programmable Logic Controller - Digital control system with programming capability
that performs functions similar to a relay logic system (See IEEE Std. 1010-2006 [B18]).
Protective Relay - An assembly usually consisting of current and voltage circuits, measuring
units, logic, and power supplies to provide a specific relay scheme, such as line, transformer,
bus, or generator protection. A relay system may include connections to other systems, such
as data logging, alarm, communications, or other relay systems (See IEEE Std. C37.90.1-2002
[B5]).
DFR - Digital Fault Recorder - Monitoring device that captures transient and longer term
events such as fault signatures.
IED - Intelligent Electronic Device - Using some level of logic use data from their sensors and
data communicated to them to perform an action. Common IED's include protection
syste.ms and controllers for various equipment such as load tap changers, capacitors, etc.,
and can also include DFR functionality.
RTU - Remote Terminal Unit - Connects local equipment to SCADA to transmit telemetry
data and/or control/report status.
Usage:
HMI - Human Machine Interface - For local control/monitoring by the distribution substation
actor. Includes keyboards, displays, keypads, touch screens, and similar devices to allow
human interaction with a system (See IEEE Std. 610.12-1990 [B14]).
SCADA - Supervisory Control and Data Acquisition - System used by the distribution
operation and control actor for monitoring and control of the electric distribution system.
DMS - Distribution Management System – A distribution operation and control actor that
uses SCADA to provide for centralized visibility and control of the distribution assets with
enhanced decision-support capability that will assist in the day-to-day operations of the
distribution system.
Data Source:
Telemetered - Updated via SCADA system to the DMS; proprietary system to peer-to-peer
systems; or metering system to enterprise systems. SCADA typically use DNP3 protocol via
serial or IP but will require IEC61850 protocol over IP for low latency requirements over a
7
communications network. Metering systems typically use ANSI C12. Data concentrators
may be used to reduce the overhead for each message.
Derived - Updated by computer system with telemetered and/or other derived data.
8