Contents
Introduction
Objectives
- Map a smart grid system on the three axes of the SGAM (domains, zones, interoperability layers) and identify the gaps.
- Distinguish SCADA, ADMS, DERMS and VPP by their scope, time horizon and network model.
- Simulate a self-healing (FLISR) sequence, calculate SAIDI, SAIFI, MAIFI and the energy not supplied, and justify an automation plan.
- Compare voltage control strategies: local control, centralised IVVC, IVVC/r with smart inverters, CVR.
- Aggregate DER into a virtual power plant, control EV charging (V1G, V2G) and simulate the islanding of a microgrid.
- Choose data models and protocols (CIM, IEC 61850, DLMS/COSEM, IEC 60870-5-104, Modbus, OCPP, OpenADR, IEEE 2030.5).
- Write an IEC 62559 use case and conduct the five phases of a project as owner's engineer.
Prerequisites: levels 2 and 5. Source: Smart grid specialisation guide and consulting framework (L. Thiaw, ESP-UCAD, October 2026). Calculations are made by the NRJXpert server. Duration: 30 h and a project.
6.1 SGAM architecture (IEC SRD 63200)
The Smart Grid Architecture Model was born from the European mandate M/490 (CEN-CENELEC-ETSI group, today SEG-CG: documents SG-CG/M490/C, 2012 and SG-CG/M490/K, 2014) and is formalised internationally by IEC SRD 63200 (UML modelling, OWL ontology). It gives a common language to generators, transmission (TSO) and distribution (DSO) system operators, DER actors and consumers. Three uses: map a system on its layers, position the standards, delimit the scope of committees.
| Axis | Components | Role |
|---|---|---|
| Domains | Bulk generation, Transmission, Distribution, DER, Customer premises | Energy value chain |
| Zones | Process, Field, Station, Operation, Enterprise, Market | Control hierarchy, from primary equipment to the market |
| Layers (GWAC) | Business, Function, Information, Communication, Component | Interoperability: business, functions, semantics, transport, hardware |
- Business: business processes, regulatory framework, business models;
- Function: use cases (IEC 62559) and requirements (IEC SRD 62913), technology-independent;
- Information: semantics and syntax of the data (CIM, IEC 61850);
- Communication: protocols, transport, addressing;
- Component: primary equipment, IEDs, computers, grid-edge gateways.
In a systems engineering approach, the SGAM is used as a gap analysis tool: at each intersection (domain, zone, layer), one checks that a standard exists, that it is used by all actors and that no interoperability break remains.
Lab 6.1 — Mapping the network drawn in NRJXpert
Open exemples/smartgrid_deux_departs.nxp (Help › Open a tutorial example). For each symbol of the « Smart grid » and « Distributed
resources » palettes, place in the tool above the equipment (Component layer), its protocol (Communication) and its data model (Information). Then
use Tools › Telecontrol points list: each line of the file produced corresponds to an arrow between two zones (Field → Station → Operation).
6.2 OT/IT operation: SCADA, ADMS, DERMS
The transition from passive distribution to active, DER-rich networks requires aligning operational technology (OT) and information technology (IT) (EPRI P174, IEEE 2030.11-2021 for DERMS):
| System | Scope | Horizon | Network model | Equivalent in NRJXpert |
|---|---|---|---|---|
| SCADA | Telecontrol, acquisition, elementary commands | Hard real time (ms to s) | Substations and IEDs | Points list (§ 6.8) |
| ADMS | Topological optimisation, load flow, outages (OMS), quality | Seconds to minutes | Complete model of the feeders | Distribution load flow, FLISR, IVVC |
| DERMS | Aggregation, forecasting, collective control of DER, BESS and loads | Minutes to day-ahead | Aggregated or automation islands | Time series, OPF, VPP (network check) |
The DMS guarantees physical security (thermal and voltage limits); the DERMS maximises the availability and yield of the DER. Two architectures: DMS-centric (single network model, but a strong real-time requirement for the ADMS) or by automation islands (the DERMS manages high-availability islands locally, the DMS keeps the consolidated view) — recommended when the existing ADMS is not real-time or the model is very large.
Example 6.2 — Why « negative load » is no longer enough
At low renewable penetration, the DMS load flow treats a DER as a negative load. With a strong injection, this model hides the local constraints.
Take timeSeries_ieee33.xml again (level 5): at cos φ = 1, 6 h of overvoltage; the same calculation with Q(V) leaves only 4 — the
active and reactive injection at the connection point must be modelled.
6.3 Self-healing (FLISR / FDIR) and reliability
Evolution of automation: passive network → self-healing (FLISR) → Volt/VAR control (IVVC) → inverter control (IVVC/r). FLISR (Fault Location, Isolation and Service Restoration) combines remote-controlled switches, fault passage indicators (FPI) and an algorithm based on the network model:
- Detection: the nearest upstream protection (feeder breaker, recloser) trips; the FPIs send their alarms (IEC 60870-5-104). A transient fault is cleared by reclosing: momentary interruption only.
- Location: the fault is downstream of the last « lit » FPI and upstream of the FPIs that stayed « off ».
- Isolation: opening of the remote-controlled switches surrounding the located zone; a manual switch cannot be used, hence an isolated zone that is sometimes larger.
- Restoration: reclosing of the breaker for the upstream part, closing of a normally open (NO) switch to transfer the downstream part to a neighbouring feeder, after a load-flow check of voltage and currents; otherwise partial transfer by blocks.
- Then the crew locates the exact section, operates the manual switches and repairs.
In NRJXpert
Smart grid palette: switching device (feeder breaker, recloser, switch, tie switch; normal state closed / open; remote-controlled; FPI). An open switch is an open circuit for all calculations: the network meshed by the NO switches stays radial. In the dialog box of a load: number of customers. Calculation Self-healing (FLISR), reliability; settings in Simulation › DER study settings › Self-healing (element in fault, intervention times, minimum voltage and maximum loading after transfer, annual study, costs).
Example 6.3 — Two 20 kV feeders that can be looped (file exemples/flisr_deux_departs.xml)
Feeder A: DJ-A, L1 (3 km), A1 (0.6 MW, 300 customers), IACM-A1 (remote-controlled, FPI), L2 (4 km), A2 (0.8 MW, 400), INT-A2 (manual switch without FPI), L3 (3 km), A3 (0.5 MW, 250), IACM-A3, L4 (5 km), A4 (0.7 MW, 350). Feeder B: DJ-B, L5, B1, IACM-B1, L6, B2. Remote-controlled NO1 switch between A4 and B2. Permanent fault on L3; λ = 0.1 /km/yr; repair 4 h.
Server results
| t | With FLISR | Without automation |
|---|---|---|
| 0.1 s | Tripping of DJ-A: 1 300 customers, 2 600 kW interrupted | |
| 20 s | FPIs lit: DJ-A, IACM-A1; fault located in {A2} + {A3} (INT-A2 has no FPI) | — |
| 35 – 50 s | Remote opening of IACM-A1 then IACM-A3 | — |
| 65 s | Closing of NO1: A4 (350 customers) transferred to feeder B, Vmin 0.982 pu | — |
| 80 s | Reclosing of DJ-A: A1 (300 customers) | — |
| 60 – 80 min | Crew: opening of INT-A2, closing of IACM-A1: A2 (400 customers) | — |
| 90 min – 2.2 h | — | Fault search, opening of IACM-A3 and INT-A2, reclosing of DJ-A, closing of NO1 |
| 4 h | Repair: A3 re-energised | |
Customers with a sustained interruption: 650 with FLISR (650 momentary) against 1 300; customer-minutes 92 000 against 189 500; ENS 3 093 kWh against 6 317 kWh. Annual study (2.4 failures/yr): SAIDI 197.9 → 105.8 min/yr, SAIFI 1.28 → 0.51 /yr (MAIFI 0.77), ENS 13 520 → 7 276 kWh/yr. With 6 remote-controlled switches (4 MF) and 5 FPIs (0.6 MF): 27 MF invested, 6.25 MF/yr of ENS avoided at 1 000 F/kWh, payback 4.3 years.
Lab 6.3 — Automation plan of a feeder
- Calculate example 6.3 (Simulation › Calculate a network file (XML)). Record the sequence, the customers interrupted and the ENS.
- Make INT-A2 remote-controlled with an FPI (
<remote>true</remote><fpi>true</fpi>): by how much does the annual SAIDI fall? Is the payback still acceptable? - Limit the current rating of L5 (
<Imax>= 60 A): the transfer through NO1 becomes partial or impossible; explain with the load flow of the transfer. - Transient fault: which interruptions remain? Which index measures them?
- Draw the same network in the client with the « Smart grid » palette and find the same results.
6.4 Integrated Volt/VAR control (IVVC, IVVC/r) and CVR
The voltage drop of a branch is ΔU/U ≈ (R·P + X·Q)/U². Control means: the on-load tap changer of the substation transformer (taps of ±0.625 %), capacitor steps, and — this is IVVC/r — the reactive power of the smart inverters (Volt/VAR and Volt/Watt functions, IEEE 1547-2018, EN 50549). Objectives: minimum losses, or CVR (Conservation Voltage Reduction): lowering the voltage within the contractual range reduces the consumption of voltage-sensitive loads (ZIP model).
In NRJXpert: stepped capacitor bank symbol (number of steps, power of one step, initial state); PV inverters and batteries; calculation Volt/VAR control (IVVC), which compares over the load profile: S0 no control, S1 local control (Q(V) of the inverters, voltage relays of the capacitors), S2 centralised IVVC (tap + capacitors), S3 IVVC/r (+ reactive power of the inverters). Settings: « Volt/VAR » tab (objective losses / CVR, tap changer range, ZIP model).
Example 6.4 — IEEE 33-bus with 2 × 0.8 MWp and two stepped capacitor banks (exemples/ivvc_ieee33.xml)
Results over 24 h (objective: losses)
| Strategy | Losses (kWh/d) | Vmin / Vmax (pu) | Hours out of range | Tap changer / capacitor operations |
|---|---|---|---|---|
| S0 no control | 1 664 | 0.913 / 1.013 | 6 | 0 / 0 |
| S1 local control | 1 097 (−34 %) | 0.943 / 1.022 | 4 | 0 / 7 |
| S2 centralised IVVC | 1 022 (−39 %) | 0.985 / 1.050 | 0 | 16 / 7 |
| S3 IVVC/r | 947 (−43 %) | 0.994 / 1.050 | 0 | 18 / 9 |
CVR objective (loads 40/30/30 %): the energy drawn at the substation falls by 1.72 % (S2) and 2.28 % (S3), the voltage being held as close as possible to 0.95 pu; losses increase a little compared with the « losses » objective — the two objectives conflict.
6.5 Virtual power plants (VPP) and aggregation
The IEEE P2030.14 project defines the VPP: aggregation software that schedules a heterogeneous portfolio (PV, wind, BESS, back-up gensets, thermal storage, curtailable loads) as a single predictable and controllable asset, able to provide fast reserve, frequency response and demand response. IEEE 2030.4-2023 frames the control automation (SGIRM model). Orchestration couples very short-term forecasts and the predictive load flow of the DMS; if local Volt/VAR control is not enough, the DMS prepares preventive switching plans sent to the crews (crew mobile).
In NRJXpert, calculation Virtual power plant (VPP): economic dispatch (MILP) of the DER of the diagram with an exchange programme requested at the connection point (deviation penalty), the sale of fast reserve, demand response, EV charging; then network check by a load flow at each step (role of the DERMS) and flexibility envelope upwards and downwards. OpenADR demand response events: level 7.
Example 6.5 — 20 kV feeder: 1 MWp PV, 0.5 MW / 1 MWh battery, 30 EVs in V2G (exemples/vpp_ve_batterie.xml)
Results
Programme: 0.8 MW at night, 0.3 MW from 07:00 to 18:00, 0.9 MW at peak; tariff 70 / 110 / 170 F/kWh; reserve at 8 F/kW/h. Programme met 20 h out of 24 (deviation 1 033 kWh); 11 310 kW·h of reserve sold; EV charging at 53.6 F/kWh on average, 166 kWh fed back (V2G); no voltage constraint or overload (Vmin 0.992 pu); mean available flexibility: +0.78 MW / −0.83 MW.
Economic dispatch alone (« Economic dispatch » calculation) depending on the charging mode: cost of the day 1.852 MF (uncontrolled, charging at 164.6 F/kWh); 1.741 MF (V1G, 70 F/kWh); 1.733 MF (V2G, 49.4 F/kWh).
6.6 Microgrids, storage and smart inverters
A microgrid is a set of loads and DER within defined electrical boundaries, controllable as a single entity, in connected or islanded mode. IEEE 2030.7-2017: microgrid controller, transition functions (seamless islanding, resynchronisation) and dispatch. IEEE 2030.8-2018: tests and qualification (HIL benches; NRJXpert test bench: level 7). Inverter interconnection: IEEE 1547-2018, EN 50549-1/-2, IEC 62898 (microgrids).
| Mode or function | Principle | In NRJXpert |
|---|---|---|
| Grid-following | PLL, injection of a synchronous current; requires a strong network | PV, wind: « grid-following inverter » model |
| Grid-forming | Voltage source, frequency and voltage reference, synthetic inertia | Battery: droop or VSM |
| Volt/VAR | Q function of the voltage | Q(V) control (IEEE 1547 cat. B curve) |
| Volt/Watt | Reduction of P in overvoltage | P(V) control |
| Frequency-Watt | P-f droop, primary control | Droop and dead band (dynamics) |
| Cross control Volt-Watt / Volt-VAR | Reactive power first, then reduction of P | Q(V) + P(V) control, Q priority |
Islanding and resynchronisation: in the dynamic simulation, events Islanding (opening of the coupling point) and Synchronised reconnection: the synchroniser adjusts the frequency and voltage of the grid-forming inverters of the island, and the breaker only closes if |Δf|, |ΔV| and |Δφ| meet the limits of IEEE 1547 (table 39): 0.3 Hz / 10 % / 20° up to 500 kVA, 0.2 Hz / 5 % / 15° up to 1.5 MVA, 0.1 Hz / 3 % / 10° above.
Example 6.6 — Islanding of a 0.9 MW site (exemples/microreseau_ilotage.xml)
Results
1 MVA grid-forming battery (VSM, H = 2 s, droop 2 %), 0.6 MVA grid-following PV (Frequency-Watt, dead band 0.036 Hz). Islanding at 1 s: the battery takes over the import (0.20 → 0.39 MW), nadir 49.39 Hz, RoCoF 4.2 Hz/s, steady-state frequency 49.82 Hz (droop). Reconnection requested at 4 s: closing at 7.70 s (Δf = 0.03 Hz, ΔV = 0.01 %, Δφ = −10°, 1.6 MVA island); back to 50 Hz and to the 0.2 MW set-point.
6.7 E-mobility: V1G, V2G and charging standards
Communication chain: vehicle —(ISO 15118-2/-20)→ charger (EVSE) —(OCPP 2.0.1)→ operator (CPO) / EMS —(OpenADR 2.0b, EEBUS)→ grid operator (DSO, ADMS, DERMS).
- IEC 61851: hardware requirements, safety, charging modes 1 to 4 (AC and DC);
- ISO 15118-20: bidirectional charging (V2G/V2X), wireless, Plug & Charge with PKI certificates;
- OCPP 2.0.1: charger ↔ CPO, TLS security, payment, smart charging profiles (V1G, V2G);
- OpenADR 2.0b: demand response, price and constraint signals between operators, aggregators and buildings or charging hubs.
In NRJXpert: charging station / fleet of electric vehicles symbol (number of vehicles, battery, charger power, arrival and departure times, states of charge, uncontrolled / V1G / V2G mode, coincidence factor). The load flow and the short circuit use the design power; time series use the uncontrolled charging profile; economic dispatch and the VPP optimise the charging.
Lab 6.7 — Night charging of a company fleet
In example 6.5, compare the three charging modes (tag <evMode>) in economic dispatch, then uncontrolled charging in time series:
at what time does the peak appear? How many vehicles does the feeder accept before a voltage below 0.95 pu?
6.8 Semantic data models and protocols
Two IEC pillars: the CIM on the IT side and IEC 61850 on the OT side, linked by a gateway (semantic mapping).
- CIM (UML): IEC 61970 (transmission, EMS/SCADA, topology, power flow, state estimation), IEC 61968 (distribution: DMS, OMS, GIS, asset management, metering; profile 61968-13 CDPSM), IEC 62325 (markets).
- IEC 61850: physical device → logical device (LD) → logical node (LN) → data object → attribute; e.g. XCBR (circuit breaker), XSWI (switch), MMXU (measurements); SCL language (IEC 61850-6, XML); MMS, GOOSE, SV services; extension to DER (IEC 61850-7-420) and to hydro plants (7-410).
- AMI: DLMS/COSEM (IEC 62056; OBIS codes), G3-PLC (IEC 61334; CENELEC A band 35–91 kHz, OFDM, IEEE 802.15.4 / IPv6 / 6LoWPAN), cellular NB-IoT, LTE-M, 4G, 5G (calculation in level 7).
- Telecontrol: IEC 60870-5-104 (TCP 2404, report by exception, time stamping, ASDU), DNP3 (IEEE 1815, classes 0 to 3), Modbus RTU/TCP (16-bit registers, no semantics).
Lab 6.8 — From the diagram to the information systems
- Tools › Export the network in CIM format: open the RDF/XML file produced; find the
ConnectivityNode, theTerminal, theACLineSegment, theBreaker/LoadBreakSwitch(normalOpen), theFaultIndicator, thePowerElectronicsConnectionwith theirPhotoVoltaicUnit/BatteryUnit. How does the ADMS rebuild the topology? - Tools › Telecontrol points list: open the CSV in a spreadsheet. For each switching device, check the ASDU type (M_DP_TB_1 for a double point, C_DC_NA_1 for a command), the IEC 61850 logical node and the Modbus register. Complete the addresses according to the operator's addressing plan. The proposed mappings are indicative: they are validated against the profiles of the selected equipment.
6.9 Project governance and owner's engineering
A smart grid project (ADMS, AMI, microgrid) is neither a simple electrical project nor a simple IT project: it is a transformation that requires structured owner's engineering (AMOA, assistance to the contracting authority) in five phases.
| Phase | Role of the consultant | Deliverables |
|---|---|---|
| 1. Scoping | OT/IT maturity, quality of GIS data, telecom coverage, regulatory barriers, renewable targets | Diagnosis, roadmap |
| 2. Requirements engineering | Cross-functional workshops (operations, telecom, IT, business); IEC 62559-2 use cases; SGAM mapping | Use case sheets |
| 3. Specification | Functional requirements, performance, architecture; CIM, IEC 61850, COSEM profiles; cybersecurity IEC 62443, SG-CG/SGIS (security by design) | Specification, technical clauses |
| 4. Bid analysis | Evaluation grids (open standards, sustainability, recurring costs); total cost of ownership (TCO), integration and change management included | Analysis report, choice of the contractor |
| 5. Steering and acceptance | Migration of GIS data to the ADMS model; factory acceptance (FAT, HIL benches), site acceptance (SAT), verification in regular service | Acceptance reports |
The sheet is kept in this browser; « Export » produces a Markdown file to attach to the specification.
Lab 6.9 — From the use case sheet to acceptance
For the FLISR use case: (1) complete the sheet (template above); (2) place its actors and exchanges in the SGAM tool; (3) deduce 10 requirements of the specification (sequence time, availability, CIM and IEC 61850 profiles, IEC 62351 security); (4) write 5 FAT tests that use the NRJXpert simulation as reference (sequence and customers restored of example 6.3); (5) compare two bids with the TCO calculator.
6.10 Skills matrix of the smart grid expert
Five domains: electrical engineering and operation; OT/IT architecture; standardisation and interoperability; telecommunications and cybersecurity; governance, economics and regulation. Assess yourself, then follow the proposed paths.
↑ Back to topSynthesis project — owner's engineering mission on an urban feeder
Subject
A utility wants to reduce by 40 % the SAIDI of a 20 kV feeder of 2 000 customers, and to host 3 MWp of PV and 200 charging points.
- Scoping: draw the feeder in NRJXpert (switching devices, loads with number of customers, PV, EV charger, capacitor banks); distribution load flow and hosting capacity.
- Requirements: three IEC 62559 sheets (FLISR, IVVC/r, smart charging); SGAM mapping.
- Studies: annual reliability study for 2, 4 then 6 remote-controlled switches; IVVC (S0 to S3); VPP with the aggregator's programme; islanding of a priority site.
- Specification: CIM export and points list; communication and security requirements.
- Bids and acceptance: evaluation grid and TCO of two solutions; FAT/SAT plan.
Deliverable: 20-page report and 20 min presentation (marking scheme in the teacher's guide).
Level 6 quiz
1. The three axes of the SGAM are:
- voltage, frequency, power
- domains, zones, interoperability layers
- generation, transmission, distribution
- hardware, software, telecom
2. A feeder protection IED is located, in the SGAM:
- Process zone
- Operation zone
- Field zone
- Enterprise zone
3. The DERMS differs from the ADMS by:
- aggregation and forecasting of DER, at intraday or day-ahead horizon
- millisecond telecontrol
- the absence of a network model
- wholesale market management
4. In a FLISR sequence, a manual switch without FPI located in the faulted zone:
- is opened by the ADMS
- prevents any restoration
- trips on the fault
- enlarges the isolated zone up to the neighbouring remote-controlled switches
5. An 80 s interruption restored by FLISR counts in:
- the SAIDI
- the MAIFI
- the SAIFI
- the ASAI only
6. IVVC/r adds to classical IVVC:
- the on-load tap changer
- capacitor steps
- control of the reactive power of smart inverters
- load shedding
7. With loads 40 % Z, 30 % I, 30 % P, the CVR factor is about:
- 1.1
- 0.3
- 2
- 0
8. To reconnect a 2 MVA island to the grid, IEEE 1547 requires:
- Δf ≤ 0.3 Hz, ΔV ≤ 10 %, Δφ ≤ 20°
- no condition
- Δf ≤ 1 Hz
- Δf ≤ 0.1 Hz, ΔV ≤ 3 %, Δφ ≤ 10°
9. Which protocol links a charging station to the operator's system (CPO)?
- ISO 15118
- OCPP
- DLMS/COSEM
- IEC 60870-5-104
10. In IEC 61850, the measurement of voltages, currents and powers is carried by the logical node:
- XCBR
- CSWI
- MMXU
- PTOC
11. Modbus differs from the CIM and IEC 61850 by:
- the absence of a semantic model (16-bit registers)
- mandatory use of TLS
- a UML model
- SCL files
12. The owner's engineering phase in which the IEC 62559 use case sheets are written is:
- scoping
- bid analysis
- acceptance
- requirements engineering
Author
November 2026