Inside DEWA's Digitally Optimized Substation Design

Dubai Electricity & Water Authority operates a transmission network at 400 kV and 132 kV. As of its 2022 design paper it had over 350 transmission substations — a mix of 400/132 kV, 132/33 kV and 132/11 kV sites [1]. Its 132/11 kV design is called the Digitally Optimized Substation, DOSS, and the decision that shapes everything else in it sits at the process interface: conventional current and voltage transformers, hardwired in copper to the bay IEDs. No merging units. No sampled values on a network.

DEWA's August 2026 announcement of the standardised design says it "has supported the construction of 90 132kV substations, including 23 commissioned in the first half of 2026" [2]. The engineering behind it was published in 2022 by DEWA's own Transmission Protection Department [1], so it is possible to look at what was actually standardised rather than at the announcement figures alone.

Why conventional instrument transformers stayed

The paper's second section is titled "Digital Substations: Facts vs Myths", and its argument against non-conventional instrument transformers is worth reading in DEWA's own terms rather than in summary.

The first point is that a Rogowski coil or an optical sensor is itself an analogue device producing an analogue output; the analogue-to-digital conversion happens in the merging unit, in the same way it happens inside a conventional protection IED with a 1 A input. "Since the NCIT's are analogue devices that produce an analogue sinusoidal output, these systems are no more digital than conventional instrument transformers," the authors write, concluding that "the term full digital substation is somewhat misleading" [1].

The second is coverage. Non-conventional instrument transformers are not available for every measurement point a substation needs — the paper names bushing CTs, reactor internal CTs and transformer neutral CTs, "especially for applications which are immersed in oil". That alone, in DEWA's view, makes a substation built entirely on NCITs impossible [1].

The third is the one that carries the most weight for anyone who has costed a distribution-voltage retrofit. A typical DEWA 132/11 kV substation has 71 × 11 kV bays [1]. Putting a merging unit on each of them produces a large device count and a large volume of process-bus traffic, and the authors add that OEMs "are unable to provide a consistent solution" across that population. Their conclusion is procurement-shaped rather than protection-shaped: additional cost and complexity "considering that there is no benefit to the power system" [1].

On the accuracy argument usually made for NCITs, the paper's position is that modern protection IEDs "have very advanced filtering and algorithms capable of maintaining optimum performance even with significant nonlinearity or saturation during faults", so the linearity advantage "is negligible in almost all applications" [1]. The paper also compares reliability, life expectancy and consequence of failure between a conventional CT and a sensor-plus-merging-unit chain, but explicitly parks that discussion — "This is a separate subject and the details are not covered in this paper" [1].

The 132 kV bay

What DEWA did digitize is everything above the CT secondaries. Each 132 kV bay carries two Bay Control & Protection Units, BCPU1 and BCPU2, each from a different manufacturer, and each carrying protection, bay control, synchronism check, the voltage selection scheme and the disturbance recorder in one device [1]. The two units are fed from two independent auxiliary DC systems, explicitly to avoid common-mode failure [1].

That replaces a conventional bay's Main-1 protection relay, Main-2 protection relay, separate Bay Control Unit and separate DFR. In panel terms, a conventional feeder bay needed a protection panel and a local control cubicle (LCC); DOSS uses a single Control & Protection Panel (CPP) holding both BCPUs [1]. Across the station, integrating protection and control into single IEDs removed 15 IEDs and 18 control and protection panels [1].

flowchart BT
    subgraph FIELD["Primary plant — copper hardwiring"]
        CTVT["Conventional CT / VT"]
        GIS["132 kV GIS — status, alarms, equipment sensors"]
    end
    subgraph MV["11 kV switchgear"]
        BMP["BMP F01…F71 — feeder / incomer / capacitor bank"]
        CU["Busbar protection central units CU1 · CU2 · CU3"]
    end
    subgraph BAY["Bay level — Control & Protection Panel"]
        BCPU1["BCPU1 (vendor A)<br/>protection · bay control · synch check<br/>voltage selection · DFR"]
        BCPU2["BCPU2 (vendor B)<br/>protection · bay control · synch check<br/>voltage selection · DFR"]
    end
    subgraph STATION["Station level"]
        SWA["Station Switch-A (Level-2)"]
        SWB["Station Switch-B (Level-2)"]
        SRV1["Substation Server & Gateway 1<br/>SCMS · security · EWS · storage, in VMs"]
        SRV2["Substation Server & Gateway 2"]
        HMI["Substation HMI — thin client"]
        GPS["GPS clock"]
    end
    subgraph WIDE["Wide area"]
        OTDC["OT data centres DC-1 / DC-2<br/>cluster witness · COMTRADE archive"]
        CC["Master control station — TCC / DCC"]
    end
    CTVT --> BCPU1
    CTVT --> BCPU2
    GIS --> BCPU1
    GIS --> BCPU2
    BMP --> CU
    BCPU1 -->|"IEC 61850 — GOOSE interlocks & trips"| SWA
    BCPU2 -->|"IEC 61850 — GOOSE interlocks & trips"| SWB
    CU --> SWA
    CU --> SWB
    GPS --> SWA
    SWA --> SRV1
    SWB --> SRV2
    SRV1 --> HMI
    SRV1 --> OTDC
    SRV2 --> OTDC
    SRV1 --> CC
    SRV2 --> CC

Fig. 1 — DOSS station architecture as described in the DEWA paper. Everything below the BCPUs is copper; everything above them is IEC 61850, with the interlocking and trip GOOSE exchanged bay-to-bay across the same LAN. Reconstructed from Figures 2 and 5 of [1].

The abstract states the interoperability target directly: "All inter-bay connections are digitized through IEC61850 process bus, which are engineered to be interoperable and interchangeable between different manufacturers without the need for reconfiguration" [1]. The property is attached to the connections rather than to the devices, which is the right level for it — with two makes facing each other in every bay, it is the interface that has to hold. The paper is a design overview rather than an engineering manual, so the SCL workflow and template mechanism behind that are outside its scope; the standard signal list and per-make wiring templates described later in the paper are the visible part of how it is achieved.

Where 258 current transformers went

The CT reduction is the part of DOSS that is a protection-engineering decision rather than a panel-consolidation exercise, and the paper attributes it to three changes.

Busbar protection moved from high-impedance to low-impedance schemes. In the conventional design the 132 kV bay had a high-impedance Main-1 busbar zone protection and a low-impedance Main-2; in DOSS both are low-impedance [1]. As the paper's bay drawing puts it, "Digital Busbar Protection does not require a separate CT for the Check Zone" — so the dedicated check-zone core disappears. The same change on the 11 kV busbar, combined with integrating 11 kV feeder backup protection into the low-impedance busbar protection, removed 73 sets of CTs there [1].

Integrating bay control into the BCPUs eliminated the CT core that the separate Bay Control Unit had required [1].

On the 132 kV GIS, 13 sets — 39 CTs — went, with further reductions logged against the 11 kV bus sections and the LVAC board, where a high-impedance restricted earth fault scheme and its CTs were removed [1].

The station total is 258 CT units removed [1]. Reading the paper's tables, note that CTs appear in two units — "sets" in the per-category table, individual units in the summary — so the category lines are not meant to be added straight to 258.

Separately, and without touching the CTs, 24 metering units were removed on 11 kV while the metering CTs themselves were retained, with metering moved to the station metering system (EMVS) [1].

The rest of the count is auxiliary hardware, and most of it came out of the local control cubicles.

The 132 kV local control cubicles (LCC): 6,707 components. That one line is 82% of the station total, and it is left out of the chart below — plotted alongside the rest it flattens every other category to a stub. It is not 6,707 cubicles: it is the auxiliary relays, timers, terminals, MCBs and switches inside them, counted individually. They went because the hardwired interlock and control logic those components implemented moved into IED logic and GOOSE messages. Counting them, the station total is 8,198 items [1].

{
  "title": {
    "text": "Items removed in a typical DEWA 132/11 kV DOSS station",
    "subtext": "Excludes the 6,707 local-control-cubicle components — see above",
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  "xAxis": { "type": "value", "name": "Items removed", "splitNumber": 4, "axisLabel": { "hideOverlap": true } },
  "yAxis": {
    "type": "category",
    "data": ["132 kV bus coupler", "132 kV feeders", "132 kV IDTs", "11 kV busbar", "DFR panels", "AVR panel & equipment", "LVAC", "132 kV GIS (CTs)", "11 kV bus sections", "11 kV incomer", "11 kV capacitor bank", "SCMS", "11 kV feeder w/ metering", "11 kV feeder w/o metering"]
  },
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Fig. 2 — the remaining categories of Table 4 of the DEWA paper, 1,491 items. The counts are not like-for-like: some rows are protection panels, some are CT sets, some are individual components. Data from [1].

GOOSE in place of interlock wiring

Hardwired control interlocks were replaced with peer-to-peer IEC 61850 GOOSE signalling between the bay units, which the paper credits with eliminating over 100 km of copper cabling per station. It logs the electromechanical relays separately: all of them replaced with digital functions, over 8,000 devices removed [1].

A note on terminology, because it matters for readers comparing DOSS with process-bus projects. The paper says the design "utilizes the most practical and beneficial digital substation concepts of process & station bus", and describes the inter-bay connections as digitized "through IEC61850 process bus" [1]. Its own architecture drawing labels that link Station Bus, carrying GOOSE between BCPU1/BCPU2 of each bay and the substation HMI, with copper hardwiring below it to the conventional CT/VT and GIS status [1]. Nowhere does the paper describe sampled values being exchanged over a network. Every analogue measurement and all primary-plant I/O arrive on copper; what runs on the LAN is GOOSE and the station-level supervisory traffic.

The IEDs are IEC 61850-9-2 compliant and provide integrated disturbance recording, automatically transmitting fault records in COMTRADE format over the IEC 61850 network to both the station HMI and the central data centre — which is what allowed 3 standalone DFR panels to be removed [1].

The SCMS: two servers and a remote witness

The supervisory control and monitoring system was rebuilt around virtualization. Two substation servers each host the SCMS, the cyber security functions, the engineering workstation and local storage, with every application in its own virtual machine, and the pair is configured as a cluster with the remote OT data centre acting as witness server [1]. The station HMI is a thin client.

Engineers reach the IEDs through a secure virtual desktop application with role-based access; user and password management is centralised and run by a dedicated OT security team, with traffic recorded and scanned at DEWA's cyber security operations centre [1].

The network below the servers is duplicated: Station Switch-A and Station Switch-B at level 2, each feeding a LAN-A or LAN-B field switch serving the bay devices, with a GPS clock for time synchronisation and the 11 kV busbar protection central units CU1–CU3 collecting the BMP population across three 11 kV bus loops [1].

Consolidating that layer removed 4 SCMS panels, 5 computers, 2 monitors, 20 network switches, 196 fibre optic cables, 4 fibre patch panels and 1 GPS clock relative to the conventional design [1].

LVAC: a bay control unit instead of a PLC

The same team published a companion design a year later covering the 400 V station supply, and it follows the same instinct — replace a special-purpose box with a protection-family device and its logic engine [3].

A DEWA 132/11 kV LVAC switchboard has three buses fed from three earthing transformers with two normally-open bus sections, and the changeover between them was executed by a PLC. Two problems drove the redesign: a planned transformer outage required an operator to move the Auto/Manual switch by hand, losing supply and generating alarm floods; and in Auto mode the PLC changeover ran with a delay long enough to cause momentary interruptions to downstream LV circuits, again producing large numbers of unwanted SCMS alarms [3].

The replacement uses Bay Control Units from the approved OEM list instead of the PLC, chosen for logic-building flexibility, operating speed and IEC 61850 communication that makes remote switching possible from the control centre [3]. The changeover strategy is deliberately split. For planned switching, the scheme parallels momentarily with a maximum paralleling time of 500 ms, permitted only where the transformer primaries are already paralleled and the LVAC busbar fault levels allow it. For an IDT protection trip, paralleling is not attempted at all and a 10-second low-speed changeover is used instead [3].

The scheme is approved for all future DEWA 132/11 kV substations [3]. The switchboard's protection had already been touched by the earlier DOSS work, which logs 34 components removed on the LVAC line, including a high-impedance restricted earth fault scheme and its CTs [1]; the changeover redesign came a year later and is counted separately.

What was actually standardised

The 2026 announcement is about standardisation, and the paper lists what that means in document terms. DEWA issues a fixed design set as part of the tender documents, for strict contractor compliance [1]:

• control and protection specification; SCMS, DC and metering technical specifications
• conceptual protection single line diagrams, trip logics and control & interlock logics for all typical bays
• control and protection panel schematics and general arrangement drawings
• substation DC system single line diagrams, charger schematics and GA drawings
• test terminal block standard terminal arrangements
• master station SCMS signal list with standard IEC 61850 signal addresses
• standard CT and VT parameters for all bays and applications
• BCPU/BMP wiring templates specific to each IED make and application

Alongside these come approved-vendor lists for IEDs, protection and control components, energy meters, CT and VT manufacturers, panel manufacturers and DC systems [1]. The paper publishes the prequalified devices for some of the applications — not the whole list:

Table 1 — prequalified BCPU and BMP devices, from Table 3 of [1], which covers "some of the applications". The two units in a bay come from two different manufacturers. DEWA's approved OEM list is wider than the three makes shown here: the LVAC paper names SEL, Hitachi, GE and Siemens [3].

The per-make wiring templates and the standard signal list with fixed IEC 61850 addresses are the parts that do the real work here. They are what turns "two IEDs from different vendors per bay" from a per-project integration exercise into a repeatable one, and they are what the contractor is measured against.

The control and protection panels themselves are built in the UAE with local manufacturers [1].

The numbers, and which set is which

Two sets of figures are in circulation and they do not match, so it is worth keeping them apart. The 2022 paper reports savings for a specific typical 132/11 kV station; the 2026 announcement gives per-substation figures without stating its baseline or whether the design has been revised since.

The 2026 announcement adds the deployment scale — 90 substations whose construction the design supported, 23 of them commissioned in the first half of 2026 — and a six-star rating at the International Best Practice Competition [2]. Hussain Lootah, EVP Transmission Power, is quoted saying the standardised design "is based on a repeatable and continuously improvable engineering model that promotes consistency in technical standards and simplifies the management of design, reliability and implementation stages" [2].

A design offered for reuse

The paper closes by offering DOSS as a concept other utilities with the same business portfolio could implement [1], and it is specific enough to be taken up that way. The bay structure, the move from high-impedance to low-impedance busbar protection, the standard document set and the prequalified vendor lists are all published, which is more than most utilities put in the open about their in-house designs.

For an engineer reading it with their own network in mind, the transferable part is the method rather than the equipment list. DEWA started from its own bay counts — 71 bays at 11 kV in a typical station — and let those numbers decide where digitisation paid and where it did not, then wrote the answer down as a document set that every contractor builds to. That is why the design reproduces: the standard trip and interlock logics, the master signal list with fixed IEC 61850 addresses and the per-make wiring templates turn a two-vendor bay into a repeatable build rather than a per-project integration.

The same method points to what a further paper from the team would be valuable on. The engineering layer beneath the dual-vendor arrangement — how the SCL is managed across the approved IED families and how the master signal list is maintained as devices are revised — is the part every utility attempting the same thing has to solve, and DEWA has now solved it across 90 substations. The 2022 paper describes the 132/11 kV design; how the approach carries to the 400/132 kV and 132/33 kV sites, with their different bay counts, is a question the Transmission Protection Department is better placed to answer than anyone reading from outside.

Sources

1. O. R. Glynn, J. Balakrishnan, A. M. Khirwadkar, M. Kandakatla, M. S. Veerabahu (Transmission Protection Department, Dubai Electricity & Water Authority), "Introduction of 132/11 kV Digitally Optimized Substation for Protection, Control and SCADA System in DEWA Transmission Network", International Research Journal of Engineering and Technology (IRJET), Vol. 9 Issue 11, November 2022, pp. 656–662. https://www.irjet.net/archives/V9/i11/IRJET-V9I11140.pdf
2. DEWA standardises 132kV substation design to cut costs, time — trade-press report of DEWA's announcement, GCC Business News, 31 August 2026. https://www.gccbusinessnews.com/dewa-standardises-132kv-substation-design/
3. O. R. Glynn, J. Balakrishnan, A. M. Khirwadkar, M. Veerabahu, P. Chinnadurai, R. U. Heggodlu (Transmission Protection Department, Dubai Electricity & Water Authority), "Introduction of LVAC Auto Change Over Scheme in DEWA Transmission System", IRJET, Vol. 10 Issue 12, December 2023. https://www.irjet.net/archives/V10/i12/IRJET-V10I12135.pdf