# An overview of grid code possible requirements for an interoperability MVAC/MVDC systems -Focus on fault detection for a future PV power plant

Nicolas Lim, Van-Sang Nguyen, Seddik Bacha, Quoc-Tuan Tran

## ► To cite this version:

Nicolas Lim, Van-Sang Nguyen, Seddik Bacha, Quoc-Tuan Tran. An overview of grid code possible requirements for an interoperability MVAC/MVDC systems -Focus on fault detection for a future PV power plant. The 26th European Conference on Power Electronics and Applications, GDR SEEDS France & EPE Association, Mar 2025, Paris, France. 10.34746/epe2025-0188. hal-05105949

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Submitted on 10 Jun 2025

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# An overview of grid code possible requirements for an interoperability MVAC/MVDC systems – Focus on fault detection for a future PV power plant

Nicolas LIM¹,², Van-Sang NGUYEN¹, Seddik BACHA², Quoc-Tuan TRAN¹

¹Univ. Grenoble Alpes, CEA, LITEN, Campus INES, Le Bourget du Lac, France

²Univ. Grenoble Alpes, CNRS, Grenoble INP, G2Elab, 38000 Grenoble, France

E-Mail: nicolas.lim@cea.fr

Tel : +33 (0) 479792125 / URL: www.cea.fr

## Acknowledgements

This work has been realized with the participation from members of INES.2S. This work is supported by the French National Research Agency in the framework of the "France 2030" program with the reference 22-PETA-0003".

## Keywords

«AC-DC», «Interoperability», «Fault ride-through», «Standard», «Short-circuit».

## Abstract

An AC/DC interoperability is expected to be part of the future grid but is not currently developed at medium voltage level. Standardization efforts are necessary to develop medium voltage DC (MVDC) systems. This article discusses the existing grid code for medium voltage (MV) applications, providing an overview of the existing requirements and the future requirements expected for the development of MVDC applications. Behaviour of a hybrid AC/DC system during fault situations through PLECS based simulation has been provided.

## Introduction

With the integration of renewable energies, energy storage systems, and electric vehicles, an increasing number of sources in distribution networks are interfaced via power electronics converters. The DC systems become an alternative to AC in the coming years. These DC grids are already studied in high voltage (HV) for transmission, and low voltage (LV) for many applications such as microgrids. The MVDC grid is a promising solution for distribution systems [1], but is not currently developed at a large scale. The MVDC will have to accommodate to the existing medium voltage AC network (MVAC).

Unlocking the MVDC networks requires standardization efforts, requiring interoperability between these two medium voltage networks.

The MVDC systems could benefit from the recent developments of the HVDC [2] with a nevertheless important difference in the specifications, with the existing requirements of the HVDC systems focusing on safety while the MVDC distribution should be more based on economic factors. The existing standards related to the integration of DC [3] production means into the distribution network known as distributed energy resources (DER) can also be beneficial for the MVDC studies. The review presented here analyses existing requirements on grid, considering the requirements for an interoperability of the MVDC and the MVAC for a future PV power plant.

In this work, the first part defines the medium voltage (MV) system, and then the second part shows the requirements of the MV grid focusing on the protection and fault requirements. Finally, the simulations will be discussed for these case studies' validations.

## Review of grid code requirements

### Voltage level for distribution network

The existing standards [2] limit the AC voltage levels to a limited number of nominal values. For example, the electrical distribution grid in France is rated mostly at a nominal voltage of 20 kV.

For the DC applications, the voltage levels remain to be defined but are expected to have more voltage levels than AC applications. Until today, only a few recommendations exist for the MVDC voltage levels. The voltage level is an essential part of the definition of a grid and is necessary to define both the grid operation and the component specification.
Based on CIGRE recommendations [4] and Chinese standard GB/T 35727-2017, the voltage level of the MVDC can be defined by the following values (Table I).

<table><caption>**Table I: Recommended values for MVDC delimitation**</caption><thead><tr><td>Configuration</td><td>Minimal voltage</td><td>Maximal voltage</td></tr></thead><tbody><tr><td>Pole to pole</td><td>± 1.5 kV</td><td>± 50 kV</td></tr><tr><td>Pole to ground</td><td>3 kV</td><td>100 kV</td></tr></tbody></table>

The first guideline issued defined voltage level for shipboard applications, where the DC voltage where defined between 1.5 kV and 35 kV. The International Electrotechnical Commission (IEC) and the Chinese standard institution GB (GuoBiao) also established recommendations for high voltage application grids, where the high voltage was defined as above 1.5 kV. In these works, several DC voltages have been established, where the voltage is defined between two poles (Table II). The voltage levels considered are similar, with minor differences on the upper levels of the MVDC.

<table><caption>**Table II: Recommended nominal voltage level for MVDC**</caption><thead><tr><td>IEC-TS<br>63471:2023</td><td>CIGRE</td><td>GB/T<br>35727-2017</td><td>IEEE-<br>1709</td></tr></thead><tbody><tr><td>1.5 kV</td><td>1.5 kV</td><td>1.5 kV</td><td>1.5 kV</td></tr><tr><td>3 kV</td><td>3 kV</td><td>3 kV</td><td>3 kV</td></tr><tr><td>6 kV</td><td>6 kV</td><td>6 kV</td><td>6 kV</td></tr><tr><td>10 kV</td><td>12 kV</td><td>10 kV</td><td>12 kV</td></tr><tr><td>20 kV</td><td>20 kV</td><td>25 kV</td><td>18 kV</td></tr><tr><td>35 kV</td><td>30 kV</td><td>35 kV</td><td>24 kV</td></tr><tr><td>50 kV</td><td>50 kV</td><td>50 kV</td><td>30 kV</td></tr></tbody></table>

With the evolution of the actual grid and an emergence of high power electronics elements of the grid, inverter-based resources are replacing the traditional transformers used to connect the MVDC grids to the MVAC grids. The voltage level needs to be defined to directly connect an MVDC grid of minimal voltage value $U_{dc\_min}$ to the MVAC three-phase grid of voltage value $V_{ac\_RMS}$ [5] through a non-isolated inverter as (1):

$$U_{dc\_min} = V_{ac\_RMS} \cdot \frac{2 \cdot \sqrt{2}}{M} \quad (1)$$

Where M is the modulation factor of the inverter. As per the distribution grid, DC lines also replace old AC lines.

The conversion for an AC line system of voltage $V_{ac}$ to a DC line system of voltage $V_{DC}$ [6] is also defined as with the conversion factor $k_v$ as (2):

$$V_{DC} = k_v \cdot V_{ac} \quad (2)$$

$$k_v = 2 \cdot \sqrt{\frac{2}{\sqrt{3}}} \quad (3)$$

## Voltage operating range

The previous section takes into account the nominal voltage levels of the system. To define the operating voltage range, the grid operator may agree to a higher or a lower variation in voltage to the nominal voltage. Those values are used for the sizing of the grid-tied converters.

In this part, the voltage variations allow to define the withstand capability of the grid and the equipment during operation conditions (Fig. 1). A common approach is to allow variation between $\Delta V = 10\%$ of the nominal value for HVDC [7], though no standard exists for HVDC voltage variation. Variations have been defined for PV application at LVDC systems are often defined with a 3% voltage fluctuation.[8]. The MVDC system should follow the 10% recommendations, recommended by shipboard standard [9].

<figure><img src="image_2.png" /><figcaption>Fig. 1: Voltage operating range</figcaption></figure>

## Architecture requirement

As any other systems, the most important requirements of medium voltage systems focus
mainly on the power rating, the maximal distance of the interconnection, and the grounding method. In French underground distribution network, due to the section of the cable (240 mm²), 12 MW is the maximum connection power rating. The power of the MVDC system is expected to be between 0.4 MW and 4 MW according to CIGRE [4].

For the MVDC links, the break-even distance is an essential criteria to justify the use of the MVDC link over the MVAC link. The first estimation work considers the break-even distance of the MVDC solution to be around 10 km at 10 kV up to 30 km at 33 kV [10].

In [2], several different architectures are considered for the MVDC networks, depending on a specific application. As the actual distribution grid is operated at radial, a common assumption is to consider the first MVDC topologies connected to the distribution grid to be mostly radial.

## Existing requirements for grids

As the traditional grid system is centred on AC, most existing requirements are defining the expected behaviour at the AC point of connection (PoC). The distribution system operator (DSO) is responsible for the distribution grid, imposing constraints based on European standard [11] and national standard [12]. Each DSO has their own grid code compliance.

For the transmission grid, standardization efforts were made to define a common framework through European Network of Transmission System Operators for Electricity (ENTSO-E) for the transmission grid, defining common requirements for HVDC systems [13]. The grid code ensures the safety and quality of the grid through its requirements. The following requirements are reviewed:

* FRT (fault ride-through)

* Control strategy

* Reactive power capacity

## FRT requirement for MVAC application

The FRT requirement has been an essential part of the grid code requirements. The FRT is defined as the withstand capability to maintain operation during fault without disconnection. This requirement is mandatory for all voltage level applications connected to the grid and defined at the AC PoC (Fig. 2).

<figure><img src="image_3.png" /><figcaption>Fig. 2: Example of FRT requirement for MVAC application [11]</figcaption></figure>

## FRT requirement for MVDC application

To the best of the author's knowledge, there is no established FRT standardized requirement for DC applications. Several studies are ongoing to define a profile for FRT applications focusing on the HVDC applications. As FRT requirement is directly linked to the protection of the grid, the definition of a profile is very important. The critical clearing time defined in the profile is used to size the protection. Some profiles with arbitrary values (Fig. 3) have been proposed by CIGRE [4], which aimed to define the protection for HVDC system.

<figure><img src="image_4.png" /><figcaption>Fig. 3 FRT profile for HVDC systems [4]</figcaption></figure>

A fully established profile has yet to be defined. for MVDC distribution system, only profile for power systems on ships [9] exists, as Fig. 4.
<figure><img src="image_5.png" /><figcaption>Fig. 4: FRT profile for MVDC Power Systems on Ships application [9]</figcaption></figure>

Protection for MVDC application

The DC grids impose new challenges to handle
the fault protection of the system. In an AC
system, the protections are mainly reliant on the
circuit breakers. As per DC properties, the current
fault cannot be interrupted in the same way as AC
fault (Fig. 5), as there is no natural zero crossing,
and energy dissipation must be handled. The
protection is commonly considered as the main
topic for unlocking MVDC grids [14] at large
scale application.

<figure><img src="image_6.png" /><figcaption>**AC**: Natural zero
current crossing</figcaption></figure>

<figure><img src="image_7.png" /><figcaption>**DC**: need to interrupt fault
current</figcaption></figure>

Fig. 5: AC current versus DC current.

The development of DC breakers [16] is
considered to keep a similar protection structure.
Considering the use of DC breaker, the system
must be able to withstand the current rating of the
DC breaker at the given time.

Looking at the existing recommendations for
HVDC systems [7], the clearing time requirement
of fault in DC systems shall be much faster than
AC systems. (150 ms for HVAC, 1 to a few 10 ms
for HVDC). The clearing time in DC system is
dependent on protection and topology. Most
existing MVDC projects operate with a radial
point-to-point configuration. On this
configuration, protection scheme can avoid the
use of DC circuit breaker.

For different systems and operations, different
strategies must be considered as:

* Use of blocking converter, mostly MMC based converter [17]

* Use of breaker topology, already used in HVDC application

* Use of fuse and relay, a common strategy for the MVAC distribution grid [18] and could be adapted to MVDC grid for production connected to the distribution grid [19]

For the MVDC breakers, there is a lack of
existing standards for the design of protection.
Existing standards concern ships [9], railway
systems [20] and low voltage systems [21],
limiting the development of MVDC systems
connected to the distribution grid. For the DER
units connected to the MVAC grid, short circuit
contribution is expected and estimated to be
around 1.2 p.u. [22] defined by the thermal limits
of power electronics.

The commercially available [23] DC breaker
units for lower voltage applications can be used
to estimate the main characteristics of DC
breakers. The definition of current and time
interruption requirements is necessary to a proper
sizing of the protection.

Reactive power capacity

The development of grid codes has made it
necessary for each converter to help maintain the
voltage stability by exchanging power through
reactive power. During transient voltage
disturbance, the system connected to the grid
contributes to the support of voltage stability
through injection/absorption of reactive power.
That means the need to define the reactive
capacity of any system connected to the grid
depending of the voltage. Such requirement is
defined as a profile (Fig. 6) in DSO grid code.

<figure><img src="image_8.png" /><figcaption>Fig. 6: U<sub>AC</sub>/Q profile for French DSO [15]</figcaption></figure>

The reactive power capacity also depends on
active power flow limits implying specific P-Q
limits for grid code compliance testing (Fig.7)
<figure><img src="image_9.png" /><figcaption>Fig. 7: P<sub>AC</sub>/Q profile for French DSO [15]</figcaption></figure>

Regarding DC grids, the system will have to
comply with existing AC standards regarding
power capacity. The DC requirements will have
to adapt to provide support to the voltage through
active power exchanges, but they are yet to be
defined. Strategies involving exchanges of active
power are studied, but requirements to define the
capacity of a system to help maintain the voltage
stability are to be defined.

Control mode

The MVDC grids development can benefits from
the HVDC architecture and control development,
keeping most likely the MV architecture.

The grid-tied systems must allow flexible control
of active power to limit overloading and
curtailment. In existing grid codes, an active
power imbalance is linked to a system frequency
drop. The requirements on AC grid code specify
the active power controllability, the control range
and the ramping rate. The DC grid will have to
comply with the existing requirements for the AC
side[24] and define requirements for the DC side
control.

For parallel architecture, the droop control is used
in AC system to ensure the balancing of power
between connected units. The multiple droop
strategies exist for the HVDC system [25], but no
defined requirement exists for the DC systems
[26]. The definition of the DC droop control is
given for HVDC by IEC [18] as the change of
active power in response to a deviation of the DC
voltage from its reference.

Power losses and restoration

With the development of the DC grid, larger
power exchanges between the AC grid and the
DC grid are expected. The power losses occurring

during the blocking of a DC contingency have an
impact on the AC, which can be seen as an AC
voltage dip during the blocking state, following
by a voltage surge during the recovery. For the
grid to adapt to the new AC/DC grid,
requirements on the AC side must be compliant
with the contingencies from the DC side affecting
the AC side. The current grid codes focus on
permanent power losses, while restauration of
power can exist in AC/DC [27].

PLECS simulation: case study and
simulation results

Case study for fault detection

This case study is based on an AC/DC grid
implementation of an actual on-going project
[28]. The MVDC network at 3 kV<sub>DC</sub> is connected
to the distribution grid (20 kV). The MVDC
network (Fig. 8) consists of a future 3 kV<sub>DC</sub> PV
power plant and DC load connected to the bus.
The software PLECS [29] is used for the system
modelling and simulation.

<figure><img src="image_10.png" /><figcaption>Fig. 8: Simulation system for fault generation and study in PLECS software</figcaption></figure>

Chosen Models and control

The main parameters used for the simulation are
given in the table (Table III) below. For the
cables, standard cables for distribution grid were
used [30]. The converters used are modelled in
averaged models (AVMs). The PV systems feed
active power to grid, and the inverter is used to
control the MVDC Bus.
<table><caption>**Table III: Parameters used for converter in the simulation**</caption><tr><td>DC/DC PV</td><td>P<sub>MVDC</sub> = 100 kW</td><td>V<sub>PV</sub>=3 kV</td></tr><tr><td>DC/DC load</td><td>P<sub>MVDC</sub> = 100 kW</td><td>V<sub>Load</sub>=3 kV</td></tr><tr><td>AC/DC inverter</td><td>P<sub>MVDC</sub> = 300 kW</td><td>V<sub>MVAC</sub>=3 kV</td></tr></table>

## Fault detection

This simulation case study has been done considering a DC fault pole-to-ground (P2G) and a DC fault pole-to-pole (P2P) short-circuit on the MVDC bus. As Fig. 9, when a fault occurs, following sequential is considered:

* $t_0$ from $t_1$: detection time necessary

* $t_1$ from $t_2$: time necessary to clear the fault

* $t_2$ from $t_3$: restoration of the system

<figure><img src="image_11.png" /><figcaption>Fig. 9: Sequential fault</figcaption></figure>

The simulation results are shown in Fig. 10 during a pole-to-pole fault, the current is rising fast. During this transient time, a voltage (the voltage is here measured between the two poles) oscillation is observed and the current fault reaches its maximum value in less than 1 ms, and its permanent value reaches around 10 ms (duration for fault interruption) after fault inception.

<figure><img src="image_12.png" /><figcaption>Fig. 10: Voltage and current waveform during P2P fault generated at t = 500ms</figcaption></figure>

During a pole-to-ground fault (see Fig. 11), the voltage on the faulty pole rises up to twice its value, and the healthy pole voltage is reduced to near zero. The impact on each pole is different (in P2P fault, the voltage of each pole followed the same behavior). In order to detect this fault, the voltage must be measured pole-to-ground as for the pole-to-pole voltage, this fault is seen as only temporary.

<figure><img src="image_13.png" /><figcaption>Fig. 11: Voltage and current waveform during P2G fault generated at t = 500ms</figcaption></figure>

The durations and behavior observed during the faults are compliant with the existing recommendations for DC-FRT mentioned above.

## DC voltage dip impact on inverter control

In this system, only the inverter regulates the DC voltage. The other converters are operating in fixed power control. During a DC voltage dip, the inverter must be capable of maintaining the voltage DC to its value during different voltage dips.

<figure><img src="image_14.png" /><figcaption>Fig. 12: DC voltage bus during voltage dips of different scenarios</figcaption></figure>
It can be observed in Fig. 12, the inverter capacity to maintain the voltage DC bus is limited.

For small and fast voltage dips (case 1), the DC voltage is maintained at its nominal value after the voltage dip. When the fault is isolated (case 2), the voltage drops to 0.73 p.u. An assessment of the system is necessary to determine whether the system can operate at reduced voltage during the fault clearing, or whether the system must disconnect.

During large voltage dips (case 3), the DC voltage collapses, and solutions must be thought out. Contribution from DC DER could provide a solution.

## Conclusion

This paper has presented an overview of the existing requirements and possible requirements for distribution networks considering existing grid codes and standards. The requirements for the MVDC grid are in development, with the voltage levels being defined and recommended by different actors while other requirements such as FRT are still in very early process due to the lack of defined existing protection strategies, with some recommendations being defined on HVDC recommendations.

The requirements concerning control mode and power capacity are still not defined for DC applications and will need some development based using DER existing requirements on AC connection and experience given from HVDC.

By using the power electronics oriented simulation (PLECS), the validation of existing recommendations using a scenario has been presented with a focus on the behavior during the DC fault on a MVDC case study. This validates the expected behavior during a fault for a MVDC system and existing recommendations. A further study is necessary to assess the operation of the system during a fault situation.

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