The central government has envisaged 1.75 lakh MW of renewable energy generation by 2022. It comprises 1 lakh MW of solar power, 60,000 MW of wind generation and the balance 15,000 MW biomass and others. Of this 1.75 lakh MW, about 1.5 lakh MW will be distributed generation (DG), which will mostly be connected at a distribution system. Renewable energy generation would continue to grow beyond 2022, to decarbonise the electricity system by 2050. It can be contemplated that every house will be a producer as well as a consumer—called prosumer—to facilitate large-scale renewable DG. Today, the electricity supply system is largely centralised generation and there is unidirectional power flow. Further, the number of generators are in few thousands; with distributed energy resources (DER), it will be tens of millions.
This change has a huge implication on distribution utilities, as the fundamental design of traditional distribution grids has not changed over the past. Distribution utilities design their grids on a top-down basis, i.e. their primary role is to deliver energy flowing in one direction, from the transmission substation down to the end-consumer. This approach does not need extensive management or monitoring tools, as it is suitable for distribution networks with predictable flows. But this model is changing rapidly, with the increase in renewable DG connected mostly at low voltage levels.
Earlier, distribution utilities only addressed consumers, but now they also have to address prosumers, storage entities, bidirectional flow and various types of DER. This will get complicated with large-scale introduction of electric vehicles, which work both as storage as well as load. Higher shares of DER lead to unpredictable network flows, greater variation in voltage and different network reactive power characteristics. Local grid constraints will occur more frequently, which will adversely affect the quality and reliability of supplies.
It is generally felt that due to proximity to the load, DG would contribute to the security of supply, power quality, reduced need for long distance transmission, avoidance of network overcapacity, deferral of network investments and reduction in distribution grid losses.
In reality, integrating DG in distribution grids represents capacity challenges due to its production profiles, location and firmness. DG is not always located close to the load, and its production is generally not dispatchable, i.e. has no control on its own outputs. Therefore, production does not always coincide with demand and DG does not necessarily generate when the distribution network is constrained. This poses challenges for both distribution network development and operation.
The ability of DG to provide electricity close to the point of consumption alleviates the need to use network for transporting power over longer distances during certain hours. However, the need to design the distribution network for peak that often occurs for a few hours per year remains undiminished, and thus overall network cost may even increase. Distribution networks have always been designed in this way, but with DG the utilisation rate of network assets declines even more. This may lead to higher reinforcement costs, and a rise in capex for distribution utilities and/or high connection cost for DG developer. The lead time generally needed to realise DG is much lesser than that for grid reinforcement. Temporary lack of network capacity may result in queuing and waiting time, delaying grid connection of new generation.
DG (intermittent nature) poses a challenge not only for system balancing, but also for local network operation. The security and capacity of a distribution system is determined by voltage (minimum and maximum within safe limits) and the peak current-carrying capacity of a network. Voltage increase is the most common issue at the connection points for DG units and a relevant area. Reverse power flow occurs when DG production exceeds the local load, which would have a strong impact on voltage profiles. Distribution utilities may have difficulties in maintaining the voltage profile at customer connection points, in particular during low voltage levels, as active voltage control is not in place. The quality of power supply is highly impacted due to large variation in voltage levels. DERs are often connected through converters/inverters to the grid, which contribute towards harmonic injection into the system.
DG often does not participate in ancillary services such as voltage control and frequency control. Monitoring of grid parameter at distribution levels is missing today and most DG is not equipped to participate in system management, i.e. there is no active contribution to network operation. As a result, system security may be endangered.
With excessive generation from DG or excessive demand, congestion may occur in distribution network.
Maintenance would be a challenge as the prosumer may backfeed into the system, thus safety of maintenance crew is critical. So, maintenance of the grid would move towards more live line working, which would need specialised crew with higher cost. At times, there is a long restoration period after network failure, due to increased number and severity of such faults. The presently-deployed protection system that is based on over-current may not be sufficient for a distribution system with large-scale DG.
These issues are similar to those faced by transmission system operation earlier. It was a long journey and almost took 7-8 years to fix. We had to bring various changes in market design, load despatch functions for monitoring and control, policy and regulatory measures, suitable commercial mechanisms through tariff design, technology implementation, independent system operation, etc. It is still evolving. This has made transmission operation active on a real-time basis for system security and for establishing a vibrant electricity market.
Distribution system operation (DSO) is non-existent today. It needs to be brought in place at the earliest. This will be a challenge, as most distribution utilities are state-owned. The transition towards a more active distribution network requires technology; and both network operators and network users have to contribute to system security.
Appropriate commercial and regulatory frameworks also have to be in place.
* The regulatory framework should enable the creation of a distribution system operator for coordinating operations of interconnected DERs, micro-grids and consumers, and scheduling interchange with grid operators at the transmission-distribution interface to maintain safe, reliable and efficient distribution services. Such services should be well-defined in grid codes (voltage and reactive power contribution) and there should be introduction of ancillary services from DER within a transparent and non-discriminatory framework.
* Introduction of smart grid technology and taking into account innovations in distribution sector like smart meters and demand response.
* Development of a new market design with aggregators to act as facilitators for small DG and load customers offering the flexibility options they buy from their clients to transmission system operators, independent system operators and DSOs. This will enable demand, DER and storage resources to participate in the markets for energy and ancillary services.
* Establishment of system services at the distribution level with adequate tools that allow distribution utilities to operate in the network in an active way. Such tools include state-of-the-art distribution control centres with information communication technologies for real-time operation and control of distribution network.
* DER connectivity and access regimes need thorough review, including priority and guaranteed access for renewables. Such rules prevent grid and market operators from implementing cost-effective solutions to avoid grid congestion. Instead, they trigger inefficient investments in grid extensions. Variable network access or alternatives involving close to real-time operation might be a solution. This may allow for limiting generation from DER by the grid operator based on an agreement with the producer concerned who would be remunerated on the basis of market prices and/or local flexibility mechanisms.
* DSO regulation should be designed to encourage the transformation of distribution network into dynamically/actively managed systems with the most economical solution.
* Capacity/skill development for such services for a countrywide operation.
The author is former chairman & managing director, Power Grid Corporation of India Ltd