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Complete List of Power System Functions

The following is the complete list of power system functions identified during the IntelliGrid Project. They were briefly described and analyzed for their key communications requirements:

  • Communication configuration requirements, including number of end devices, location of equipment, media constraints, compute-constraints, wireless requirements, etc.
  • Quality of service requirements, including response speed, availability, data volumes, data accuracy, data exchange frequency, etc.
  • Security requirements, including authentication, access control, confidentiality, data integrity, non-repudiation, sensitivity to denial of service, etc.
  • Data management requirements, including managing large databases, many databases, timely access, frequent updates, data exchanges across organizational boundaries, etc.

The details of the brief analysis of these functions can be found in the Volume II, Appendix F: Task 1 Enterprise Activities. The list of these power system functions is provided below.

Market Operations Domain

1.     Long Term System Planning (1 month to 5 years for new construction)

a.     RTO/ISO update the system-wide power system model

b.     RTO/ISO certify generation units

c.     RTO/ISO analyze generation market for capacity and adequacy to meet long term load

d.     RTO/ISO coordinate long term transmission and generation maintenance

e.     RTO/ISO register and perform credit rating of Market Participants (MPs)

f.      RTO/ISO register meters

2.     Medium/Short Term Planning (Week ahead to months ahead for installing equipment)

a.     RTO/ISO/TransCos/DisCos forecast load

b.     RTO/ISO certify generation units

c.     RTO/ISO analyze generation market for capacity and adequacy to meet load

d.     RTO/ISO register and perform credit rating of Market Participants (MPs)

e.     RTO/ISO validate and register revenue meters

f.      TransCos/GenCos propose scheduled transmission and generation outages which are validated via congestion management analysis

g.      RTO/ISO auction, sell, and/or track transmission rights and other energy services to Market Participants

h.     Energy Traders, ESPs, and other authorized Market Participants establish bilateral energy contracts between Generation and Loads

3.     Short-term Planning (48 hours- one month)

a.     Corrections of medium-planning actions, available capacity, and possible ancillary services, based on updated data on transmission outages, generation maintenance, load forecasts, etc.

4.     Day Ahead Market (24 hours to 48 hours ahead)

a.     RTO/ISO auction/sell short term transmission rights and other energy services to Market Participants

b.     Market Participants submit Day-Ahead energy schedules

c.     Market Participants submit Day-Ahead bids for ancillary services: reserve, regulation, frequency response, etc.

d.     RTO/ISO perform bid/auction management

e.     RTO/ISO perform congestion management and security analysis on submitted energy schedules

f.      RTO/ISO calculate operational parameters for Day-Ahead planning: Available Transmission Capacity (ATC), Regulated Must Run (RMR), Locational Marginal Price (LMP)

g.     RTO/ISO provide information to Market Participants

·       Provide mandated and other energy information to Market Participants

·       Disclose environmental information

·       Publish notifications

5.     Real-Time (actual time to next hour)

a.     Calculate operational parameters in real-time

b.     Market Participants submit adjustments to real-time energy schedules

c.     Market Participants submit real-time bids for ancillary services

d.     RTO/ISO dispatch generation power system under normal conditions:

·       RTO/ISO SCADA system monitors power system

·       RTO/ISO EMS system performs Automatic Generation Control (AGC)

·       RTO/ISO Market Operations system analyzes transmission capacity and reliability

·       RTO/ISO Market Operations system balances energy/ancillary services

·       RTO/ISO EMS system monitors interchange schedules with internal and external Control Areas

e.     RTO/ISO exchange information with external entities:

·       RTO/ISO Market Operations system coordinates operational activities with distribution operations of interconnected UDCs

·       RTO/ISO Market Operations system coordinates operational activities with Reliability Councils and NERC

·       RTO/ISO Market Operations system coordinates operational activities with Market Participants

f.      RTO/ISO redispatch/emergency dispatch

·       RTO/ISO EMS system redispatches generation to handle emergency

·       RTO/ISO Market Operations system notifies Market Participants of redispatch

·       RTO/ISO Market Operations system manages market external price caps

6.     Post-Dispatch (last hour to prior months)

a.     Handle energy reporting

·       RTO/ISO Market Operations system calculates actual interchange information and energy schedules

·       RTO/ISO Market Operations system calculates actual Locational Marginal Pricing (LMP)

·       RTO/ISO Market Operations system calculates actual losses

·       Meter Data Management Agents (MDMAs) process meter revenue data

b.     Market Products Schedule Checkout

·       Settlement Agents validate implemented energy schedules against contracted energy schedules

·       Settlement Agents reconcile differences

c.     Financial Settlements

·       Settlement Agents reconcile RTO/ISO market

·       Settlement Agents reconcile transmission market

·       Settlement Agents reconcile Market Participants spot market

·       Settlement Agents resolve disputes

·       Market Participants reconcile bilateral schedules

d.     Accounting and Billing

·       Accounting Agents create budget and financial forecast

·       Accounting Agents manage accounts payable

·       Accounting Agents manage accounts receivable

e.     Market Monitoring and Auditing

·       Regulators and auditors develop monitoring criteria

·       Auditors perform market assessment

·       Auditors investigate market abuse

·       Regulators monitor environmental statistics

Transmission Operations Functions

1.     Long term transmission planning (1 year to 5 years ahead)

a.     Long term load forecast

b.     Forecast alternatives for generation sources (Probable market conditions)

c.     Plan transmission upgrades and additions (participation in ISO/RTO expansion plan)

d.     Plan automation of transmission system for SCADA, Equipment Monitoring, and EMS

e.     Prepare long-term contracts with Distribution Utilities:

·       Transmission voltage management

·       Distribution reactive power support (power factor) in the D-T interface

·       T&D information exchange

f.      Prepare emergency response planning, e.g. Ice Storm, Hurricane, Catastrophic outages

g.     Ensure hard copies of all schematics, diagrams, relay settings are available

h.     Prepare inventory and personnel plans based on neighboring load, tie point capacity, etc.

2.   Medium-term planning (1 month to 1 year)

a.     Forecast annual load

b.     Consider probable generation sources

c.     Equipment and Line Maintenance

d.     Calculate system utilization based on forecast load and nameplate ratings

e.     Schedule maintenance operations - time-based

f.      Schedule maintenance operations - predictive, based on data and models

g.     Schedule equipment replacement - based on age of equipment

h.     Schedule equipment replacement - predictive, based on data and models

i.       Schedule equipment replacement - based on contingency scenarios

j.      Schedule spare distribution, ensure sufficient at each site

k.     Revise contracts with Distribution Utilities

3.   Operational planning (1 day to 1 month)

a.     Short-term load forecast

b.     Short-term generation alternatives based on annual maintenance plan and market conditions

c.     Planned outage management

d.     Operators determine needed transmission outages

e.     Operators analyze contingencies

f.      Planners/operators perform load analysis of substation equipment based on data

g.     Operators submit transmission outages and constraints to RTO/ISO

h.     Dynamic equipment capacity

i.       Protection engineer, to alter relay settings

4.   Real-time normal operator actions (Using SCADA/EMS)

a.   SCADA system monitors transmission system

b.   Monitor plant state (open/close)

c.   Monitor system activity and load (current, voltage, frequency, energy)

d.   Monitor equipment condition (overheat, overload, battery level, capacity)

e.   Monitor environmental (fire, smoke, temperature, sump level) and Monitor security (door alarm, intrusion, cyber attack)

f.   Monitor security records (audio/video recording)

g.   Operators handle alarms

h.   Intelligent alarm processing should happen here as well as in (6).

i.    Distribution of alarms to non-operators:

·       overloads and replacement issues to maintenance engineer

·       automated work management system

·       fault records and SOEs to protection engineers

·       info to billing dept. re: possible refunds or reliability contract

·       external security or emergency response teams

j.   Operators perform supervisory control of switching operations

k.   Manual switching

l.   Transfer of Authority

m.   Automation system controls voltage, var and power flow based on algorithms, real-time data, and network linked capacitive and reactive components

n.   All items listed under 6h could also be performed under Normal operation as normal load management, I.e. "peak shaving" or temporary overloading of equipment due to other manual operations.

o.   Operators changes setup/options of EMS functions

·       Periodicity of real-time sequence/Cold Initiation

·       Event triggers

·       Manual initiations

·       Contingency list

·       Application tuning parameters

·       Other

p.   Operators prepare for storm conditions based on weather data and history and change recloser settings

q.  Operators prepare for storm conditions based on weather data and history and change alarm thresholds

r.   Prepare for transformer clipping (e.g. Solar wind/Solar Magnetic Disturbance raising ground DC offset)

5.   Network Analysis (real-time)

a.   EMS system performs model update, state estimation, bus load forecast

b.   EMS system performs contingency analysis, recommends preventive and corrective actions

c.   EMS system performs optimal power flow analysis, recommends optimization actions

d.   EMS system or planners perform stability study of network

6.   Real-time emergency operations (system protection level)

a.   Power System Protection

b.   Emergency Operations performs Under-frequency load/generation shedding

c.   Emergency Operations performs Under-voltage load shedding

d.   Emergency Operations performs Conditional localized load shedding

e.   Recovery from voltage or frequency-based load shedding

f.   LTC control/blocking

g.   Shunt control

h.   Series compensation control

i.    System separation detection

j.    Wide area real time instability recovery

k.   Operators manage emergency alarms

l.    SCADA/EMS aids operators in locating fault

m.  Operators dispatch field crews for restoration

n.   SCADA system performs intelligent alarm processing

o.   Local alarm reduction within substation

p.   Centralized alarm reduction based on events from multiple substations

q.   SCADA system performs disturbance monitoring analysis (including fault location)

r.   SCADA/EMS performs dynamic limit calculations for transformers and breakers based on real time data from equipment monitors

s.   SCADA/EMS performs pre-arming of fast acting emergency automation

t.    SCADA/EMS generates signals for emergency support by Distribution Utilities (according to the T&D contracts):

·       Emergency voltage and var control for providing dispatchable real and/or reactive loads

·       Emergency load re-balancing between T/D substations by feeder reconfiguration

·       Activation of interruptible/curtailable load

·       Activation of direct load control

·       Activation of distributed resources

·       Activation of other load management functions

u.   Operators performs system restorations based on system restoration plans prepared (authorized) by operation management

7.   Post operations

a.   All systems archive logs and reports

8.   Power system equipment maintenance (mobile enabled work force)

a.   Substation and Line Maintenance including operation blocking

b.   Periodic (time-based) maintenance

c.   Based on age of equipment

d.   Based on predictive models driven by real-time data

e.   Maintenance staff maintain transmission lines

f.   Request that operator block reclosing for maintenance purposes

g.   Maintenance staff provides information for updating relevant databases

h.   Maintenance staff refer to substation drawings (online?)

9.   SCADA/EMS Maintenance

a.   SCADA/EMS personnel updates SCADA/EMS databases

b.   SCADA/EMS personnel updates EMS applications

c.   SCADA/EMS personnel updates operator interfaces

d.   SCADA/EMS personnel updates interfaces with other systems

e.   SCADA/EMS personnel performs diagnostics of the SCADA/EMS systems

10. Operator and SCADA/EMS personnel training

a.   Operators and SCADA/EMS personnel perform periodic training by using the Operator Training Simulator

b.   Operators and SCADA/EMS personnel participate in advanced education programs

11. Engineering

a.   Protection engineers perform protection engineering

·    Duties: base case, fault studies, relay settings, protection coordination, fault analysis

·    Needs data: line/equipment capacity, relay specs, PT/CT ratios, fault records, SOE data, event info (relay 'targets' - which element picked up)

b.   Substation engineers perform substation engineering

c.   Transmission engineers perform transmission line engineering

d.   Engineering staff provides information for updating relevant databases - from site / online

12. Construction management

a.   Construction managers manage asset purchasing

b.   Construction managers plan construction projects

c.   Construction managers manage crew assignments

d.   Construction personnel provides information for updating relevant databases - from the site / online

e.   Construction personnel refer to substation drawings (online?)

13. Black Start

Distribution Operations Domain

1.     Long term distribution planning (1 year to 5 years)

a.     Distribution planners forecast loads for the long term by area

b.     Distribution planners plan distribution upgrades and additions in accordance with the long-term transmission plan (using planning simulation and optimization software)

·       New T/D substations

·       New distribution circuits/conductors

·       New distribution transformers

·       New distributed generation, including distributed resources impact studies

–       DisCo plans utility-owned DR to meet reliability and power quality targets

–       DisCo acquires DR base information (to provide ratings and device models)

–       DisCo analyzes DR interconnection to the power system

·       New circuit boundaries

·       New switch allocation

·       New capacitor allocation

c.     Distribution planners plan distribution automation

·        SCADA

·        DA functions

–        Fault Location

–        Fault isolation and service restoration

–        Outage statistics calculations

–        Volt/Var control

–        Planned outage management

–        Feeder reconfiguration

–        Cold load pickup

–        Dynamic limit calculations

–        Feeder paralleling

–        Integration with EMS/MOS

–        Equipment monitoring and diagnostics

–        Other

d.     Distribution planners prepare long-term contracts with transmission companies covering mutual obligations for the T&D interfaces, operation coordination, and information exchange.

e.     Distribution planners prepare long-term contracts with generators connected to distribution

f.      Distribution planners prepare long-term contract with customers regarding service reliability and power quality

g.     Distribution planners generate requirements for information support of distribution domain activities

h.     Distribution planners update the future layers of relevant databases

2.     Short-term distribution planning (1 week to 1 year)

a.     Short-term load forecast

·        Load forecast for existing nodal loads

·        Forecast of allocation and amount of new loads

·        Forecast/scheduling of distributed resources

b.     Update of circuit boundaries

c.     Update of switch placement

d.     Update of capacitor placement and sizing

e.     Update of no-load tap positions

f.      Update phase load allocation for better load and voltage balancing

g.     Update of contracts with transmission company

h.     Update of automation settings

i.       Short-term distributed resources impact studies

j.      Update of contracts with distribution generators

k.     Update of contracts with customers

l.       Contractor /Builder requests new service connection (see IEC WG14 Use Case #2 and 3)

m.   Update of relevant databases

n.     Prepare maintenance plan

·        Calculate system utilization based on forecast load and nameplate ratings

·        Schedule maintenance operations - time-based

·        Schedule maintenance operations - predictive, based on data and models

·        Schedule equipment replacement - based on age of equipment

·        Schedule equipment replacement - predictive, based on data and models

·        Schedule equipment replacement - based on contingency scenarios

·        Schedule spare distribution, ensure sufficient at each site

3.     Operational planning (1 day to 1 week ahead)

a.     Planned outage management by using DA applications in study/look-ahead mode and DA databases

·        Outage request analysis and scheduling, taking into account the capabilities of real-time DA functions.

·        Planners/operators perform load analysis of substation equipment based on data

·        Multi-level feeder reconfiguration

·        Contingency analysis/reliability (risk) assessment

·        Distributed resources re-scheduling

·        Protection coordination analysis

·        Switching order generation for facilitating the planned outages and for return to normal

b.     Work management (planning stage)

·        Schedulers interface with contractors

·        Schedulers schedule work crews for scheduled work

·        System operators review and approve scheduled work

·        Schedulers identify assets required for scheduled work

·        Work crews perform scheduled work, coordinating with operators for switching operations

c.     Operators prepare (plan) for storm conditions and other alerting situations based on weather data, other alarming systems, and history

·        Change recloser settings

·        Change alarm thresholds

·        Prepare for transformer clipping (e.g.  Solar wind raising ground DC offset)

4.     Real-time operations

a.     SCADA system monitors distribution system

·        Monitor plant state (open/close)

·        Monitor system activity and load (current, voltage, frequency, energy)

·        Monitor equipment condition (overheat, overload, battery level, capacity)

·        Monitor environmental (fire, smoke, temperature, sump level)

·        Monitor security (door alarm, intrusion, cyber attack, audio/video recording)

b.     Operators handle alarms

·        Intelligent alarm processing by SCADA system

·        Distribution of alarms to non-operators:

–       overloads and replacement issues to maintenance engineer

–       automated work management system

–       fault records and SOEs to protection engineers

–       info to billing dept. re: possible refunds or reliability contract

c.     Operators dispatch field crews for scheduled work:

·        Crew acquires drawings, previous records, customer profile

·        Operator establishes limits on what crew is permitted to do

·        Using mobile radio system

·        Using mobile computing

d.     Work crews provide information for updating relevant databases

·        Work crews log activities and results of tests

·        Work crews identifies assets installed and/or removed

e.     Operators perform supervisory and/or manual (using field crews) control of switching operations, load tap changers and voltage controllers, capacitor statuses

f.      Operator defines objectives and other parameters of DA functions, e.g.

·       Closed-loop control of service restoration function

·       Use emergency limits for service restoration

·       Provide volt/var support for transmission

·       Provide Peak Load reduction within voltage quality limits

·       Provide Peak Load reduction within voltage emergency limits

5.     Automation of distribution operations

a.     DA system updates power system model and analyzes distribution operations

·        Update topology model

·        Update facilities model

·        Update load model

·        Update relevant transmission model

·        Update and analyze real-time operating conditions using distribution power flow/state estimation

·        Update system capacity based on real-time equipment monitoring data

·        Issue alarming/warning messages to the operator

·        Generate distribution operation reports and logs

b.     DA system performs fault location, fault isolation, and service restoration

·        DA indicates the faults cleared by controllable protective devices

–       Distinguish faults cleared by fuses

–       Distinguish momentary outages

–       Distinguish inrush/cold load current

·        DA determines the faulted sections based on SCADA fault indications and protection lockout signals

·        DA estimates the probable fault locations based on SCADA fault current measurements and real-time fault analysis

·        DA determines the fault-clearing non-monitored protective device based on trouble call inputs and dynamic connectivity model

·        DA generates switching orders for fault isolation, service restoration, and return to normal (taking into account the availability of remotely controlled switching devices, feeder paralleling, and cold-load pickup)

–       Operators executes switching orders by using SCADA

–       Operator authorizes the DA application to execute the switching orders in closed-loop mode

·        DA system isolates the fault and restores service automatically by-passing the operator based on operator’s authorization in advance

·        DA considers creation of islands supported by distributed resources for service restoration

c.     DA system performs multi-level feeder reconfiguration for different objectives:

·        Service restoration

·        Overload elimination

·        Load balancing

·        Transmission facilities overload

·        Loss minimization

·        Voltage balancing

·        Reliability improvement

d.     DA performs relay protection re-coordination

·        After feeder reconfiguration

·        In case of changed conditions for fuse saving

e.     DA system optimally controls volt/var by changing the states of voltage controllers, shunts, and distributed resources in a coordinated manner for different objectives under normal and emergency conditions:

·        Power quality improvement

·        Overload elimination/reduction

·        Load management

·        Transmission operation support in accordance with T&D contracts

·        Loss minimization in distribution and transmission

6.     Real-time emergency operations

a.     Protection equipment performs system protection actions

·       Fault detection, clearing, and reclosing

·        Under-frequency load-shedding

·        Under-voltage load-shedding

b.     Operators manage multiple emergency alarms

·       Intelligent alarm processing by SCADA system

c.     SCADA system performs disturbance monitoring

·       Fault current recording

·       Fault location

·       Event recording

d.     Operators dispatch field crews to troubleshoot system and customer power problems

·        Mobile radio system

·        Mobile computing

e.     Operators perform emergency switching operations

f.      Operators performs intrusive load management activities

·        Operators or planners identify critical loads (hospitals, etc.) ahead of time

·        DA system locks out load shedding of critical loads

·       Operator activates direct load control

·       Operator activates load curtailment

·       Operator applies load interruption

·       Operators enables emergency load reduction via volt/var control

·       Operator applies manual rolling blackouts

g.     Operator enables emergency (major event) mode of operations of operation and maintenance personnel, and enables major event emergency mode of operation of DA applications

h.     Outage management systems collect trouble calls, generate outage information, arrange work for trouble shooting

i.       Interactive utility-customer systems inform the customers about the progress of events

j.      DA performs in major event emergency mode

7.     Post operations

a.     Basic logging and reporting

·       Systems create and archive logs and reports

·       System records voice logs of interaction between operators and field crews

·       All systems transmit reports to key parties

b.     Maintenance personnel of the automated systems (DAS, OMS, WMS) performs diagnostic analysis of system performance

c.     Diagnostic analysis based on real-time equipment monitoring data, e.g. using predictive models to determine when the equipment needs maintenance

8.     Power system equipment maintenance

a.     Maintenance staff maintain distribution equipment and lines

·        Maintenance staff analyzes equipment diagnostic results, compares it with the predictive models

·        Maintenance staff prepares outage requests based on time and condition criteria

·        Operations staff review and approve outage requests

·        Maintenance staff identifies assets and work crew requirements

·        Work crew carries out maintenance, coordinating with operators for switching

b.     Maintenance staff provides information for updating relevant databases

·        Work crew logs activities and results of tests

·        Work crew identifies assets removed and/or installed

·        Maintenance staff identifies errors in documentation and maps

·        Maintenance staff identifies marks up documentation ("red/green")

·        Maintenance staff indicates permanent versus temporary changes

9.     Engineering

a.     Engineering personnel perform distribution system engineering

b.     Engineering personnel specifies distribution power and control equipment

c.     Engineering personnel provides information for updating relevant databases

10.  Construction management

a.     Construction managers manage assets purchases

b.     Construction managers plan construction projects

c.     Construction managers manage crew assignments

d.     Construction personnel provides information for relevant databases

11.  Power Quality Management

a.     Utility measures power quality parameters, transmits them to central location, processes data, and stores data in PQ database in real time.

b.     Real time power quality state estimation system calculates power quality characteristics based on limited monitoring information from substations, distribution systems, and customer systems and models (pseudo-measurements) supplementing to the needed redundancy

c.     Utility exposes historical and real-time power quality data to customers

d.     Utility correlates data from utility operations database, lightning database, and other operations related database with PQ event database and generates reports and/or stores analysis results for future reporting.

e.     The utility PQ evaluation system analyzes PQ events, trends, and profiles of power quality levels of the supply system against planning limits and operation objectives.  The system is used to generate recommendations and priorities for system improvements.

f.      The power quality management system analyzes PQ events and profiles to identify causes of PQ problems and possible equipment problems that could be corrected.  Detailed recommendations are developed and automatic responses are implemented where possible.

g.     The power quality information is evaluated with respect to specific customer requirements on the specific system.  Coordination with equipment and power conditioning equipment within customer facilities is implemented to improve productivity and reliability of customer systems.  (See description in Customer Services Domain)

h.     Utility accesses PQ database and generates bill/refund/penalty statement for events that exceed contract limits.  (see description in the Customer Services Domain)

i.       Utility generates various reports from PQ database for operation, management, engineering, and customer consumption via e-mail and web interfaces.

12.  Dispatcher Training Simulator

HV Generation Domain

1.     Real Time Scheduling - Interface to RTO/ISO

2.     Real Time Commitment - Interface to RTO/ISO

a.     Unit scheduling

b.     Unit constraints

·       Ramp rates

·       Startup times

·       Minimum down times

·       Minimum generation levels

·       Upper operating limits

·       Minimum run times

c.     Price mitigation

·       Day-Ahead bidding

·       Spot-Price bidding

d.     Weather Analysis

e.     Ancillary services

·       Reserves commitment

·       Regulation commitment

3.     Real Time Dispatching - Interface to RTO/ISO

a.     Unit dispatching

b.     Unit constraints

·       Ramp rates

·       Startup times

·       Minimum down times

·       Minimum generation levels

·       Upper operating limits

·       Minimum run times

c.     Price mitigation

·       Day-Ahead bidding

·       Spot-Price bidding

d.     Weather Analysis

e.     Ancillary services

·       Reserves dispatch

·       Regulation dispatch

f.      Equipment status

g.     Equipment control

h.     Metering

·       Real Time Power Flow measurements

·       Real Time Var support measurements

4.     Real Time Contingency Operations

a.     Reserve pickup

b.     Regulation pickup

c.     Scheduled equipment outage contingencies

d.     Unscheduled equipment outage contingencies (self-healing)

e.     Electrical system fault/abnormal operation contingencies (self-healing)

f.      Contingency analysis with optimal power flow

g.     Black Start (healthy grid)

·       Maximum power output

·       Reactive power limits

·       Start-up times

·       Ramp rates

h.     Black Start (system restoration)

·       Physical constraints - startup times, real & reactive power, ramp times

·       Scheduling constraints - unit/personnel availability

·       Policy constraints - owner dictated

i.       Emergency Response - Disaster preparedness contingencies

j.      Performance standards data

·       Power flow

·       Var support

·       AGC

·       Excitation

·       PSS

·       Emissions

k.     Intentional Islanding

l.       Weather Analysis

5.     Real Time Plant Operations

a.     Generator power output and frequency control - governor and prime mover systems

b.     Generator voltage control - excitation systems

c.     Generator real time measurements

d.     Fuel management

·       Supply

·       Fuel system monitor

e.     Balance-of-Plant SCADA

·       Equipment status

·       Equipment control

·       Equipment monitoring

·       Real time measurements

f.      Black start procedures/process

g.     Diagnostic Maintenance Data

h.     Emissions monitoring and control

i.       Contingency Operations

·       Protection Functions

·       Scheduled equipment outage contingencies

·       Unscheduled equipment outage contingencies (self-healing)

·       Electrical system fault/abnormal operation contingencies (self-healing)

·       Mechanical systems operation contingencies (self-healing)

j.      Emergency Response - Disaster preparedness contingencies

k.     Compliance with performance standards

6.     Real Time Maintenance Control

a.     Outage Schedules

b.     Equipment Maintenance

c.     Equipment Inspection

d.     Equipment Replacement

e.     Equipment Contingencies

f.      Maintenance History

g.     Parts Inventory Management

7.     Long term planning (Years ahead)

a.     Generation planners perform long terms load forecasts

b.     Generation planners plan generation

c.     Market Participants negotiate long term market contracts

d.     Generation planners plan automated systems, communications, and interfaces in coordination with ISO/RTO and transmission owners

·       For measurement of ancillary services

·       For automated volt/var control to automatically execute optimal and/or security constrained power flow

8.     Short-term planning (1 month to 1 year)

a.     Plant equipment maintenance

b.     Update the automation settings

c.     Update the contracts with other market participants

9.     Operational planning (1 day to 1 month)

a.     Short-term equipment outage management

b.     Update short-term bids for energy and ancillary services

10.  Generator equipment maintenance planning

a.     Maintenance staff maintain generation equipment

b.     Automated system maintenance staff maintains the automated systems, interfaces, communications, and databases

11.  Construction management planning

a.     Construction managers manage asset purchases

b.     Construction managers plan construction projects

c.     Construction managers manage crew assignments

d.     Construction personnel provides information for relevant databases

12.  Commissioning planning

a.     example: nuclear

13.  De-commissioning planning

14.  Security (generation specific issues)

a.     Security of nuclear fuel/waste

b.     Security from cyber threats

c.     Inter-plan shared level of alert

Distributed Resources (LV Generation) Domain

1.     Local Functions (by DER Owners/Operators, which include Commercial Customers, Industrial Customers, Residential Customers, and Distribution Utilities). The DER can be located at a customer site or at a utility site, such as in a substation.  The DER owner/operator owns and operates the DER directly (no third party).

a.     DER owner/operator uses DER as automatic backup for key internal load if main power is lost or may be lost (e.g.  diesel generator).  The DER system undertakes automatic start of DER device, disconnects Area EPS, synchronizes and interconnects DER to local EPS, and performs generation control to meet changing load requirements. 

b.     DER owner/operator sets DER at a specific setpoint to provide a set level of generation (e.g.  to offset load, to provide local generation for reliability and/or demand-response, to shave peaks).

c.     DER owner/operator establishes a permanent building/campus microgrid (e.g.  utility power as backup)

d.     DER owner/operator uses DER for internal loads following with import/export interconnection to Area ESP, set for fixed import/export

e.     CHP or other factors drive the use of DER with net zero import/export, so Area EPS is used strictly as backup, so heat information is also required

f.      Heat is main purpose for heating hospitals – feed power back to the networked distribution grid in downtown New Orleans.  Monitored for power flow when it is on.

g.     Contractual establishment possibility of microgrids during power outage or peak shaving.  The DER owners are responsible for actually establishing the microgrid.  Although no data exchanges now, in the future they will want far more data and possible control over the process. 

h.     Greenpower demonstration house with net revenue and instantaneous metering on residential (up to 25 kW and small commercial up to 100 kW) – developing load curves from load monitoring, including after an outage. 

i.       DER owner plans the scheduling/bidding of DER generation in electricity marketplace, for energy, as ancillary services, as contracted, as per real-time pricing, etc.  The DER operator then executes the schedules as required.

j.      DER operator manages DER system maintenance, including DER generator, prime mover, local EPS switching and protection, communications system, and the monitoring and control system

k.     DER system collects information, logs, and statistics, including operational information, performance, efficiency, emissions, environmental parameters, green power %, etc.  This information may be available in real-time as well as historical.

2.     Third-Party Remote Operator or Aggregator Functions (by ESP or DisCo or Other e.g.  RTO/ISO). The DER can be located at a customer site or at a utility site, such as in a substation.  The DER is operated by a third party from a remote site.  The third party could be an Aggregator, and Energy Services Provider, a utility, or other entity.

a.     Remote operator monitors generator status only (on/off)

b.     Remote operator monitors instantaneous metering (status, alarms, kW output, voltage, amps, statistics, etc.)

c.     Remote operator monitors DER environment (prime mover, weather, emissions, protective relays, switches, etc.)

d.     Remote operator or Aggregator dispatches a local operator to manually control the DER device.

e.     Make-before-break DER system picks up local load, then disconnects from the Area EPS; diesel recips; startup, isolation, verification, real-time metering, revenue metering both at the PCC and at the DER, as well as submetering, stop

f.      Dispatch pricing signal – DisCo dispatches DER on (to run at full power) or off

g.     Remote operator or Aggregator sets DER at a specific setpoint to provide a fixed amount of generation (e.g.  to offset load, to provide local generation for reliability and/or demand-response, to shave peaks).

h.     AGC – Remote operator (e.g.  RTO/ISO or utility) or Aggregator controls DER operations through automatic control to meet specified operational needs and contracts (e.g.  power quality, emissions, economic dispatch, energy schedules, ancillary service contracts, real-time pricing, local backup, interconnection with distribution system)

i.       Remote operator dispatches field crew to perform manual switching operations on feeders with DER present

j.      Remote operator performs supervisory control of switching operations on feeders with DER present

k.     Remote operator performs supervisory control of load tap changers and/or voltage controllers with DER present

l.       Remote operator aggregates multiple DER device information for DisCo SCADA system

m.   Remote operator provides DER owners, DisCo, and/or market operators with the results and other information on DER operations

n.     Remote operator manages local microgrid operations with DER

o.     Net metering – ESP or DisCo manages and reads revenue meters for DER and loads

p.     ESP or DisCo handles settlements and billing for DER owner

q.     Regulators and auditors monitor compliance of DER operations with contractual and environmental commitments

3.     Automated Distribution Operations (ADO) Functions (by Distribution Utility) Supported by Advanced Distribution Automation (ADA). The DER can be located at a customer site or at a utility site, such as in a substation.  Multiple points of common coupling (PCCs) of multiple DRs along a feeder need to be taken into account.  The DER is operated by a distribution utility specifically to meet its normal operational needs, particularly if there is significant penetration of DER on some of its feeders or in its substations.  These operational needs can include power system reliability, power system efficiency, power quality assessment, outage management, market operations, and maintenance. 

a.     ADO collects and analyzes distribution operations with significant DER penetration (multiple PCCs), including basic SCADA, distribution state estimation and operational analysis, status estimation of controllable devices, load modeling and analysis, reliability assessment, dynamic limit calculations, power quality analysis, etc.

b.     ADO operates a DER system in a substation or other utility facility for additional local generation and ancillary services. 

c.     ADO, supported by ADA, provides quality power to customers under normal conditions and/or as a result of predicted adverse conditions, based on coordinated volt-var control, contingency analysis, multi-level feeder reconfiguration, relay protection re-coordination, feeder phase load and voltage balancing, etc. 

d.     ADO manages DER and distribution facilities planned outages, using Advanced Distribution Automation (ADA) applications in study/look-ahead mode, covering distribution operations analysis, DER availability analysis, multi-level feeder reconfiguration, coordinated volt-var control, reliability assessment, cold load pickup, work order creation. 

e.     ADO, supported by ADA, supports market operations for DisCo, through load forecasting with DER availability and dispatchable load analysis, look-ahead distribution system analysis, contract-oriented loss calculations, coordinated volt-var with real-time pricing, etc.

f.      ADO supports distribution and DER maintenance, by providing performance and historical statistics of DER and distribution equipment, as well as risk assessments based on these statistics

g.     ADO, supported by ADA, coordinates distribution and DER operations with bulk power system operations, including real and reactive load/DER management, load shedding, load/DER transfer to different feeders, etc.

h.     ADO, supported by ADA,  supports customer services, through power quality assessment and management, real-time pricing analysis, and performance analysis

i.       ADO, supported by ADA,  manages DER interconnected with the utility grid, through DER forecasting and scheduling, microgrid creation and management, injection and storage management, interconnection design, and performance monitoring

j.      ADO supports database management through asset management, database consistency management, and database validation management.

4.     Emergency Operations Functions. The DER can be located at a customer site or at a utility site, such as in a substation.  The DER is operated by a distribution utility specifically to meet its emergency operational needs, particularly if there is significant penetration of DER on some of its feeders or in its substations.  These emergency needs can include protection schemes and actions, load shedding, alarm management, disturbance monitoring, emergency switching, and establishment of microgrids. 

a.     Protection equipment performs system protection actions on DER interconnections – fault detection, clearing, and reclosing

b.     Distribution operator directly trips or verifies trip of interconnected DER on loss of feeder power

c.     Distribution operators manage emergency alarms from DER devices

d.     SCADA system performs disturbance monitoring analysis, including DER responses

e.     ADO, supported by ADA, manages forced outages of DER and distribution facilities, by supporting automated fault clearing (protective devices), fault indication, fault location, fault isolation, dynamic limit calculation, service restoration (manual or closed-loop switching), volt-var adjustment, DER control, microgrid creation, cold load pickup, paralleling check, relay re-coordination, etc. 

f.      Operators dispatch field crews to troubleshoot system and customer power problems

g.     Operators dispatch field crews to troubleshoot communication system and customer communication problems

h.     Operators perform switching operations involving DER interconnections

i.       Operators shed loads and/or DER devices intentionally

j.      Outage management systems collect trouble calls and generate outage information

k.     Microgrids of DER devices matched to loads are formed, operated, and eventually connected back into the distribution system

5.     Planning, Installation, Commissioning, and Maintenance Functions (by DER Owners, Energy Service Providers (ESP), and DisCos). Planning and implementation of DER involves longer term activities, with multiple parties involved to design, test, and audit DER systems.

a.     DER sizing, technology, configuration, and installation is planned and coordinated with DisCo, by providing ratings, configurations, planned usage, etc.

b.     Distribution planners study the impact of planned DER installations on the distribution system, and integrate these results with other distribution upgrades and additions, as well as ADA settings

c.     Installer installs and tests DER devices in the local EPS

d.     Distribution utility tests DER installation with interconnection to area EPS

e.     Distribution utility interacts with DER owner on DER installation physical and electrical configuration, contractual arrangements, planned operations, and/or other information

f.      DER operator tests DER communications system performance and management

g.     Vendors of different equipment (including DER systems, switches, protection, and communications system) gather real-time data and statistics, and perform troubleshooting of their own equipment.

h.     DER maintainer maintains DER system

i.       DER environmental monitoring

j.      Energy Service Provider meets contractual obligations for managing the DER system.

Customer Services Domain

1.   Automatic meter reading (AMR)

a.   Meter Data Management Agent (MDMA) reads meters with handheld/mobile technologies

b.   MDMA reads industrial and/or commercial meters with fixed AMR technology

c.   MDMA reads residential meters with fixed AMR technology

d.   MDMA provides individual and aggregated meter readings to market settlements, DisCos, and/or TransCos

e.   MDMA or DisCo provides individual energy usage and billing to customers

f.   Prepay metering

g.   Non-electric metering -- subcontracted submetering for non-electric utilities -- Note: focus on aspects of shared infrastructure and not the actual metering

h.   Sub-metering -- customer bill dis-aggregation and rental space allocations

i.    Non-intrusive load monitoring -- deducing load contributions by monitoring aggregate consumption changes

j.    Outage isolation

2.   Customer Management

a.   DisCo provides tamper detection, load profiles, etc.

b.   DisCo provides connect, disconnect, energy usage and billing information, etc. to customers

c.   DisCo provides information for updating relevant databases

3.     Customer trouble call management

a.   Customer reports trouble and trouble ticket is generated (see Customer Information under Corporate Services)

b.   Trouble ticket is used by outage management function (see Distribution Operations)

c.   Trouble ticket is used for statistical analysis (see Distribution Operations)

4.   Real-time Pricing (RTP)

a.   ESP updates RTP schedules for subscribing customers

·    ESP receives base RTP schedule from Market Operations

·    ESP calculates customer-specific RTP schedules

·    ESP multicasts RTP schedules to customers

b.   Customer EMS manages energy usage based on RTP

·    Customer EMS determines optimal mix of current load, deferred load, and DR generation, based on RTP schedule

·    Customer EMS implements load and DR management

5.   Load management

a.   ESP applies direct load control measures - residential

·    Applies/requests direct load control (cycle water heaters, air conditioners, and other loads)

·    Curtails customer loads

·    Interrupts customer loads

·    Sheds customer loads (under frequency / under voltage)

·    Requests load-reducing volt/var control

b.   Permissive power provision -- devices can request a limit of power. This would allow an emergency device to use power while other loads might not. Scheduled and load limited. Authenticated level control

c.   Aggregation of customers who are asked to reduce load amongst them when asked to curtailed. Pagers to signal

6.   Building/Home Energy Management Services

a.   ESP monitors building security systems (illegal entry, environmental alarms, health care signals, etc.) - no remote control

b.   Customer EMS manages building environment, based on preset parameters (security settings, temperature, appliances, lighting management, etc.)

c.   Customer status/control of building environment locally and/or remotely by modifying parameters

d.   Customer EMS bids into power market for dynamic load profile

·    Machine bidding for power consumption

·    Buildings of same owner collaborate on load profile

·    Negotiate for poor power quality events

e.   Customer EMS tracks billing

·    EMS receives bill to date

·    EMS receives pricing forecasts

·    EMS receives history data - minute by minute and events

f.   Offsite premise management

·    Provide analysis and control of homes / businesses /vacation property

g.   Occupancy based heating and lighting controls

h.   Building VAR Control

7.   Weather

a.   Lightening and severe weather alert notification

·    Notification of emergency transient conditions

b.   Weather to consumer

·    Provide day or multi-day ahead weather forecasts, alerts

·    Provide dynamic/periodic wind/solar/thermal/precipitation status for optimal control

c.   Weather from consumer

·    Retrieve microclimate data from consumer controls -- outside air, solar, precipitation

8.   Third party services

a.   Contractor use of utility gateway and communications

·    Remote servicing of HVAC control

b.   Home owner can access utility gateway and manage his house appliances

9.   Power Quality

a.   Notify customer of current PQ information

·    Current harmonic content

·    PQ events

b.   Implement power quality contracts

c.   Coordinate with power conditioning equipment and process equipment to improve performance

·    Power factor correction and harmonic filters

·    UPS and power conditioning equipment

·    Process equipment and machine controls

d.   Improve power quality through supervisory control

e.   Prioritize system improvements based on reliability and PQ levels being supplied to customers

10. Electric Vehicle / home co-generation

a.   Billing a "consumption event"

·    When consumer charges up at another customers "pump" (charging station) (not perceived as important)

b.   EV as generator 

·    Permit EV generator to emit power into power grid

11. Energy efficiency monitoring

a.   Appliance performance monitoring

·    Monitor and compute energy efficiency for appliances and subsystems

b.   Fault detection and diagnostics

·    Detect specific appliance signature and analyze for drift or fault

12. Indoor Air Quality

a.   Monitoring of sensors

·    Regulatory support / documentation of compliance

·    Remote monitoring and alarming of measurements

13. ISP services to customer

a.   Reselling of bandwidth to conventional communication service providers (including telephone, TV, and ISP)

14. Third party Service Support

a.   Homes security services - owner managed

b.   Home health (patient monitoring / health emergency alarm)

c.   Alarm qualification

d.   Remote video surveillance -- monitoring of home "web cams"

e.   Home alarms -e.g. -water in basement

15. Transmission and Distribution Operations Support

IT Services Domain

1.     Telecommunications Infrastructure

a.     Domains determine their telecommunication requirements

2.     Security Management (Federation)

a.     Security managers implement cyber security policies

b.     Security technologies manage security appropriately for each type of interaction

3.     Network and system management (Federation)

a.     Network and system managers (NSMs) assess NSM requirements

b.     NSM systems monitor and control communications networks and equipment

c.     NSM systems monitor and control systems and applications

d.     NSM systems analyze and report performance

e.     NSM staff perform preventative and emergency maintenance

4.     Data management (Federation)

a.     Data maintenance staff update data in databases

·       Automated mapping and facilities management databases

·       SCADA databases

·       Customer Information databases

b.     Systems synchronize data across all interfaced systems

c.     Data maintenance staff troubleshoot data problems

d.     All systems archive reports and logs of data maintenance activities


IntelliGrid Architecture
Copyright EPRI 2004