Abstract: The paper intends to provide an overview of the characteristics of the Indian Distribution system and its problems with regard to a large scale rooftop PV rollout, as well as a template for distribution companies on how to deal with rising PV shares, which studies to conduct and which technology options to select.
Under the current national target based on National Solar Mission, 40 GW of rooftop PV shall be connected in India by 2022. As on 31st July 2018, only 2 GW of rooftop PV were Installed. In view of this, to achieve the target, a good understanding of the Indian power system, its regulatory frameworks, and the similarities and differences with other countries that have already deployed a large share of rooftop PV has to be developed by all stakeholders involved in the process.
2.0 Characteristics of India Distribution System
2.1 Indian Distribution Grids
2.1.1 Ownership and operation
The Indian power system has been unbundled since the Electricity Act of 2003 was signed into force. The Act was intended to grant separated ownership and operation of transmission, distribution and generation.
Distribution grids (66 kV and below) in India are operated by licensed Distribution companies (DISCOMs). These companies are in many cases owned by the State Electricity Board themselves, however, some are in private hand, or owned by public-private joint ventures
DISCOMs are in charge of the enforcement of compliance with legislation, technical and regulatory frameworks of generators feeding into the distribution grid.
Primary distribution is typically handled at 66 kV and/or 33 kV level or both. Secondary distribution takes place mainly at 11 kV. 11 kV feeders may only be 1 – 3 km long in the cities, but range up to more than 20 km in rural areas, often requiring reactive compensation in the latter case.
Residential customers are supplied either with 400 V three phase or 230 V single phase systems.
400 / 230 V feeders are usually a few hundred meters long at maximum to avoid overly high voltage drops and losses. Large customers (industrial, commercial or institutional) may have to be connected directly to 33 kv or 11 kV grid if their peak load exceeds a certain value.
Transmission and distribution losses in the Indian power system have been notoriously high, reaching a peak of 28 % of total generated energy in the early 2000s and being reduced to still high values of around 18 – 19 % by 2015.
Losses vary by state with some being below 10 %, while some more unstable areas have regularly exceeded 40% of losses in the last years. Technical losses are high due to aging equipment, long lines and bad design in places, but the majority of losses are non-technical. Non-technical losses are caused by various forms of electricity theft.
2.1.3 Tariff system
For the electricity distribution segment, the SERCs are currently entrusted with the responsibility of fixing the retail tariffs in accordance with the National Tariff Policy 2006 and as per the provisions of the Electricity Act 2003. The tariff is set based on the estimated Annual Revenue Requirement (ARR) of the DISCOMs in a financial year.
Electricity prices are comprised of a fixed charge (power price) that is determined by the monthly maximum demand, and an energy charge for each used kWh. The consumers are also loaded with electricity tax and adjustment tariff. Moreover, the varying fuel cost adjustment (FCA) charges is another burden for customers.
The tariffs charged from non-residential customers are substantially higher, , almost all states charge higher tariffs from large industrial or commercial consumers than from small consumers to allow access to cheap electricity for residents.
This structure may, in the long run, lead to economic issues with PV integration. The DISCOMs draw most of their revenue from large customers, and industry and commerce implicitly subsidize resident customers that pay lower prices. The high tariffs incentivize industrial and commercial customers to connect PV systems under net metering schemes, as power from such units will be cheaper than the power bought from the grid. Development is picking up quickly, as these types of customers typically have the cash available for the upfront investment needed to install a PV unit. This is favorable for India’s PV targets but may turn out to be very challenging for the DISCOMs, as demand from highly charged customers shrinks while demand from residents paying low tariffs is expected to grow. A restructuring and rationalization of tariffing regimes may be necessary to accommodate the changes in the system. Especially with DISCOMs often purchasing power via long term contracts with time frames up to 20 years, this may be a significant barrier to PV integration and the improvement of supply quality in general.
2.2 Regulatory Framework
2.2.1 Governance and regulation
The Ministry of New and Renewable Energy (MNRE) is the nodal ministry responsible for all matters relating to new and renewable energy. The ministry was established with the goal of developing and deploying new and renewable energy for supplementing the energy requirements of the country. MNRE has set the target of installing a PV capacity of 100 GW (40 GW of which will be distributed rooftop) by 2022.
The State Electricity Regulatory Commissions (SERC) have full autonomy in drafting their own regulations but mostly stick to adding local context to CERC regulations. SERCs are primarily responsible for regulating state generation, transmission and distribution tariffs, provide directions for system planning, enabling necessary conditions for the development of a market, adjunction of disputes and improving access of electricity at the state level.
In the case of rooftop solar systems, the SERCs in each state lays down the detailed guidelines and procedure for grid connectivity and metering with the provision of net metering arrangement and/or feed-in-tariff mechanism. This includes the detailed technical grid code requirements. These directions have to be followed by the respective DISCOM.
2.2.2 Policies and regulations specific to developing solar generation capacity in India
The Indian Government has announced a series of policy measures to promote solar energy and develop a self-sustaining market. There have been direct and indirect tax benefits, excise duty exemptions and custom duty exceptions provided to renewable energy including solar energy. This includes income tax deferments from all earnings in the first 10 years of operation of a PV unit and accelerated depreciation up to 80% of the project cost for solar energy in the first year itself.
2.2.3 Metering and incentives for rooftop solar PV
For rooftop solar two different types of metering arrangements are possible: gross and net metering. Whereas a net metering mechanism includes a compensation for the electricity generated by the PV system by definition, gross metering is just a way of measuring the generated energy which is usually used when PV electricity is compensated for on a feed-in tariff basis. The regulatory framework in India for the gross-metering based renewable projects (including solar) has been evolving over the years. Some very early rooftop PV units were connected under gross metering / feed-in tariff agreements, but today, the mechanism is used only for free field utility scale PV installations.
As per the present scenario, almost all Indian states and Union Territories have net metering policy and other support mechanism to promote grid connected distributed PV systems. Policy and support mechanism vary in detail from state to state.
Net-metering based arrangements in India are primarily aimed at encouraging self consumption by the consumer, albeit allowing the customer to store excess energy in the grid, or sell it to the DISCOM. The choice of incentive is thus dependent on the extent to which surplus energy is permitted to be exchanged with the grid and the price at which surplus over a settlement period is to be exchanged. Net-metering arrangement for a consumer primarily offsets power consumption from the grid and therefore compensates the owner of the rooftop system for solar energy consumption at the applicable retail tariff for the consumer category. The net meter arrangement may have a single, double or a three meter system. For multiple (2 or 3) meter systems, DISCOM has to recognize all the installed meters for commercial settlements.
When tariffs in a consumer category are lower than tariffs typically expected by rooftop solar system developers, some additional incentive has to be provided to promote rooftop PV. Such incentives for net metered based arrangements will need to vary across consumer categories and from state to state, as retail tariffs are different across categories and across states.
2.2.4 Regulation dealing with technical and safety aspects of distributed generation
Interconnection frameworks for net-metering based rooftop solar PV need to address minimum technical standards for interconnection and capacity of the system that can be connected to the grid. The cumulative capacity to be allowed by a distribution utility under the net metering arrangement also needs to be specified. There are three regulations by which CEA outlines the technical and safety requirements for distributed generation to be adhered to by DISCOMs and owners of the distributed generation system.
- The CEA’s Technical Standards for Connectivity of the Distributed Generation Resources are applicable to any generating station feeding electricity into the electricity system at a voltage level below 33 kV. The CEA regulations cover the roles and responsibilities of the developer/ system owner and of the Distribution Company, the equipment standards and codes of practice, and the system requirements for safe voltage, frequency, harmonics, etc.
- The CEA’s Installation and Operation of Meters regulation from 2006 (amendment in November 2014 includes distributed solar generation) regulate metering standards.
- The CEA’s Measures of Safety and Electricity Supply, 2010 govern safety for generators. The CEA regulation ‘Technical Standards for Connectivity of the Distributed Generation Resources’ Regulation 2013 mentions that safety standards should be in accordance to this code. However, these safety codes are aligned more towards large scale thermal power plants as opposed to small distributed solar PV installations. In addition, states in India have also prescribed some technical requirements for distributed solar PV through government policies, and regulations brought out by the SERCs.
CEA follows standard IEEE 519 which addresses the limitations for current and voltage harmonic contaminations through Individual Harmonic Limits and Total Harmonic Distortion (THD) limits. The voltage distortion limit established by the standard for general systems is 5 % THD.
As per the CEA (Technical Standards for Connectivity to the Grid) Amendment Regulations,2013 (Part II, Connectivity Standard applicable to the generating stations, clause B1, sub-clause 2), the following further requirements are applicable to distributed PV:
- The generating station shall not inject DC current greater than 0.5% of the full rated output at the interconnection point.
- The generating units shall be capable of operating in the frequency range of 47.5Hz to 52Hz and shall be able to deliver rated output in the frequency range of 49.5Hz to 50.5Hz.
- Provided that the above performance shall be achieved with a voltage variation of up to ±5%.
3.0 PV Development
3.1 Current Situation of Distributed PV in India
3.1.1 Solar resources
India receives good amount of solar radiation with an annual average of 4.5 to 6.5 kWh/m2/ day . Availability of roof or suitable ground space is another important factor to generate solar power in an effective and economical way. It is important to assess and utilize solar radiation data for specific areas for which systems are to be designed. There are different sources from where solar data are available. MNRE has released solar radiation data for 23 locations across India through a joint project with the Indian Meteorological Department. MNRE through the National Institute of Wind Energy (NIWE) and supported by GIZ has now set up more than 120 advance solar radiation monitoring stations across the country for collecting and monitoring solar data. NIWE has also published a national solar energy atlas in 2014.
Daily solar patterns are generally well predictable during summer where there is little overcast, but more varied during winter or monsoon season. Due to the size of the country, more exact data on seasonal variability has to be assessed on a more regional level.
3.1.2 Roof-mounted PV
By the end of 2016, a total of around 8700 MW of solar PV are connected to the Indian grid, of which 1020 MW are distributed roof-mounted installations. National incentives for PV, both roof mounted and centralized, exist, mainly in the form of capital cost subsidies and metering schemes. Centralized utility-scale PV has been subsidized under the Jawaharlal Nehru National Solar Mission since 2010 , or, for very large projects of more than 500 MW, under the Ultra Mega Solar Park program of the Ministry of New and Renewable Energy.
As of March 2017, all states have released a regulatory framework for the promotion of distributed PV through the net metering mechanism.
As rooftop PV for industrial and commercial customers has reached grid parity in several states, the Indian government has decided to subsidize such installations no longer, as the incentive set by grid parity and high prices for grid power is considered to be sufficient to sustain development.
Subsidies for PV for residential, institutional and social sector customers are raised back to 30 % of capital cost nationally to increase development in this sector. A maximum subsidy of 70 % is given to states that are given the Special Category status due to geographical and/or socioeconomic disadvantages (North Eastern States, Sikkim, Jammu and Kashmir, Himachal Pradesh and Uttarakhand, Lakshadweep, Andaman, and Nicobar Islands)
This may in the near future lead to a shift towards a higher capacity of PV installed on roofs of residential buildings, thus leading to a higher amount of PV being connected to the low voltage grids.
3.2 Expected development of Distributed PV in India
3.2.1 National and state targets
The national target of 40 GW of rooftop and 60 GW of utility-scale PV to be installed by 2022 is distributed to the states by the MNRE. This distribution is based on size, population, solar potential and economic power of the states (see Table 1) The states and their SERCs are responsible for the enforcement of these targets. The main enforcement mechanism is the renewable purchase obligation (RPO), with which states oblige their DISCOMs to purchase a certain percentage of their total electricity from renewable sources. Within the state RPOs, the that has to come from solar PV each year is specified, from which a trajectory towards the final goal of each state can be derived. RPOs have been in existence since 2010 (mostly for other renewable sources like small hydro and biomass), but have largely been notorious for a lack of enforcement.
Table 1: State wise Solar PV Target
|States||Rooftop PV Target by 2022 (MW)||Total Solar Target by 2022 (MW)|
|Jammu and Kashmir||450||1155|
|Dadra and Nagar Haveli||200||449|
|Daman and Diu||100||199|
|Andaman and Nicobar Islands||20||27|
4. Factors Potentially limiting Roof Top PV integration in India
4.1 Regulatory Issue
4.1.1 Lack of enforcement
While all Indian states have been assigned a solar target for 2022 to reach the national target of 40 GW of rooftop and 60 GW of utility-scale solar, an effective means of making sure the targets are reached is lacking. The main means of enforcement of solar targets are the renewable purchase obligations (RPO). States oblige their DISCOMs to purchase a certain amount of renewable energy by a certain date, often including a specific requirement for solar power. DISCOMs regularly fail to comply with the RPO, and most states neither monitor nor enforce RPO compliance. The CERC has stated that the SERCs are in charge of compliance and complained that the CERC itself has no power over enforcement of solar targets as far back as 2013. This lack of a central authority in charge of monitoring renewable energy targets seems to be very detrimental to their fulfillment. However, due to pressure from CERC, CEA and the federal government, the SERCs have recently become aware of this issue and are expected to control the states and DISCOMs more effectively in the future.
Similar problems can be expected to occur with grid code requirements for PV units. The lack of experience on the DISCOMs’ side, as well as their often dire financial situation, may lead to a lack of compliance control mechanisms. This should be addressed by the CERC and the SERCs quickly, as the installation of large shares of unchecked and possibly non-compliant PV may be a threat to operational security.
4.1.2 PV penetration limits set by DISCOMs
In 1999, the California Public Utilities Commission (CPUC) recommended limiting generation on distribution grid feeders to 15 % of the feeder’s peak load to avoid reverse power flows . The reasoning behind this was that minimum feeder load is usually around 30 % of peak load, and with a safety margin of 50 %, 15 % of peak
load could safely be integrated. This rule is still applied by some Indian states, sometimes with the full amount of 30 %, or in the form of PV penetration being limited to 15 % of distribution transformer capacity. The rule has since been revoked in California, but is still accepted as a standard in other parts of the world, leading, among others, to the following problems:
15 % of peak load is too high of a safety margin, as has been understood by CPUC in the meanwhile as well, significantly hindering large scale deployment of distributed PV.
It is sometimes suggested that 15 % is the amount that can be integrated without any further safety precautions or grid codes. This is true when considering only the distribution feeder in question, but a total of 15 % of uncontrollable PV in a power system may cause system-wide issues with frequency control and in cases of faults. In some states considerably higher installed capacities are allowed, with up to 65 % of the capacity of the distribution transformer. Some SERCs are revising their limits as well, however, it remains usual for a SERC to set a fixed limit.
Additionally, SERCs in many states set limits on how much PV can be connected by a single customer, sometimes in the form of an MW limit, some based on the registered load of the customer. Especially in the latter should be subject to the same revisions as the penetration level limits, while the fixed MW limits are usually quite high (500 kW and above, this includes installations connected directly to 11 kV) and in line with federal rooftop PV legislation.
4.2 Market and Financial Issue
4.2.1 Market development
The market structure through which the DISCOMs procure power from the transmission grid is quite inflexible. DISCOMs generally have to stick to a day-ahead schedule, or even to long term contracts, leading to problems in balancing load and the amount of procured power already. With fluctuating generation in the system, these problems will be aggravated, with DISCOMs possibly having to pay penalties for schedule deviations if no intra-day balancing mechanisms are introduced.
4.2.2 Financial performance of distribution companies
In present state of affairs each DISCOM needs to accept excess generation from solar rooftop projects and reimburse it at the rate announced by the regulator but as the penetration grows the increased distributed solar will decrease retail sales of the DISCOM, thus reducing their revenues and loading of this loss on to another consumer in the retail supply tariff. Additionally, since commercial and industrial consumers are also cross-subsidizing other consumers by paying a higher tariff, it is most likely that they become independent and start generating their own electricity thus leaving behind a reduced pool of cross-subsidizing consumers. These factors lead to a passive opposition from DISCOMs. However, it may be solved by introducing appropriate regulatory measures to rationalize the tariff system.
4.2.3 Financing issues
The rooftop solar sector is traditionally associated with having special financing needs. This is primarily due to the small project size, high upfront cost of project and credit risk associated with small scale lending. The above challenges are observed at different levels with residential and commercial or industrial consumers.
As per CPI research, the commercial and industrial (C&I) consumers are reluctant to invest the high upfront amount required to install rooftop solar capacity given energy generation is regarded as a non-core business activity. There are also concerns about the operation and maintenance costs of solar PV assets. The C&I customers tend to favor signing up long term Power Purchase Agreement (PPA) contracts with an annual cost escalation rate agreed with the developer, which allows them to manage their cash flow.
The PPA model also has a set of challenges, for example, poor legal enforcement of PPA contracts, leading to high lending risk for banks, poor bankability and creditworthiness of industrial and commercial users due to a variety of reasons.
In addition, banks are reluctant to lend to rooftop solar projects because of high perceived risks and limited information on the performance and track records of rooftop solar investments. The cost of solar PV panels and the balance of system continue to fall annually adding to the perceived risk factor for the banks. The resale value of primary assets will be lower than the sanctioned loan amount should a customer defaults on a loan.
4.3 Technical Issue
4.3.1 Distribution system
Technical issues possibly limiting PV integration in Indian distribution systems are less pronounced than regulatory and economic problems. A preliminary analysis of Indian distribution grid structures including review of previous studies suggests that the following issues should be investigated with a special focus.
The last instance of voltage control is usually the transformer that steps down from the transmission level to 66 kV or 33 kV. Beyond this point, there is no active voltage control in the distribution system. Power transformers and distribution transformers often cannot change their ratio according to load and PV penetration. Thus, voltage quality should be focused on in Indian distribution grid studies, including the consideration of reactive power control of PV inverters, on-load tap changing transformers at least for the step from 66 or 33 kV to 11 kV, switchable or power electronic based reactive compensation and wide area voltage control.
However, as many Indian customer suffers from regular brownouts and voltage drops on the feeders are high, the introduction of distributed PV may actually increase voltage quality at first, with control issues only arising at very high shares of PV.
Another set of issues to be analyzed includes protection settings and anti-islanding regimes. Protection, especially at voltage levels below 33 kV, may not be able to detect faults during times of high PV generation when power flow is reversed. Protection settings must thus be analyzed and, if necessary, revised.
4.3.2 Grid codes, power system impact and communication
PV in the distribution grid may cause stability problems in the transmission grid if grid code requirements are not set properly. For this, communication between the regional and national transmission grid operators and the DISCOMs is necessary. The behavior of distributed generation during faults in the transmission system may affect the power system in its entirety – if, for example, all PV disconnects automatically at a certain frequency threshold, stability may be endangered if PV share is high enough.
5.0 Technical Solutions
As the model grids were able to absorb quite high penetration levels of PV, in most cases, there is no need for advanced technical solutions to avoid loading or voltage problems. However, at very high penetration levels, it could be observed that the active power management strategies of either capping PV feed-in at 70 or 75 % of inverter capacity or the use of peak shaving batteries performed best in resolving both voltage and loading issues. This is true for both rural and urban grids, as the mechanisms are the same. Both overvoltage and overloading are caused by active power feed-in, and if that is limited or shifted, problems are alleviated. However, both solutions have costs attached to them, both of which may be either be borne by the DISCOM or by the client – either way, it will somewhat increase the cost of power from rooftop PV.
A. Peak shaving batteries
Battery storage needs to be procured and installed by the customer at their facility. Prices for lithium ion and lead acid batteries have reduced by more than 40 % since 2013, keeping the price for a kWh of storage capacity in the same range as the price for a kWp of rooftop solar PV. This means that the installation of 1 kWh of battery capacity for each kWp of installed solar capacity would roughly double the price of the installation. Currently, there is no grid parity for such a system, meaning that it would not work without an additional incentive scheme. However, as prices for PV and storage drop, this may be a feasible future scenario. Moreover, many Indian homes are already equipped with batteries that could be used for PV storage. The current backup battery boom in India also has the effect of reducing battery costs by economies of scale. In any way, an incentive has to be set for batteries to operate in peak shaving mode, instead of optimizing purely for own consumption, which may conflict with their use for backup during power outages.
B. Capping of inverters
The cheaper solution, having almost the same grid impact during extreme situations, is the capping of PV inverters. It is possible to cap PV feed-in at 70 – 75 % of the maximum value without losing more than 3 % of energy annually, while significantly increasing the hosting capacity of the grid. With an average increase of 3- 4 % in generation cost for retrofitted systems, and less than that for new systems due to cost savings in a smaller inverter, this is an effective, but much cheaper solution than the use of PV storage batteries.
The impact of demand-side management in grids with primarily residential customers is low due to the low potential for DSM in private households. However, the strategy should be given more attention when analyzing grids with a high share of industrial or commercial customers.
C. Voltage control measures
For cases in which only voltage problems (overvoltage) can be expected – long lines, low load and unfavorable PV distribution – some voltage control solutions are applicable and feasible. Voltage control by the power transformers can be enhanced by a wide area control system, measuring the voltage on each feeder and setting the transformer taps accordingly. This solution requires some additional investments in communication, but will have multiple positive effects on grid operation, extending beyond PV integration:
- Voltage rises induced by PV are detected and alleviated.
- Voltage drop issues caused by high loading during evening and night can be detected and alleviated as well.
- The general quality of supply will be improved by improving the voltage profile.
- As continuous measurements have to be made at multiple points in each grid, the operator is supplied with a constant stream of operational data, can manage quality of supply more efficiently, and detect possible operational problems early on.
On-load tap changing transformers with automatic voltage control at least at the connection between transmission or subtransmission level (220 or 132 kV) and the distribution grid should be considered in all cases – otherwise, voltage problems may occur already without any PV installed.
Besides facilitating PV integration, this will improve voltage quality significantly and alleviate current load-induced under voltage issues.
D. Voltage control from PV inverters
Voltage control from the PV units themselves, on the other hand, cuts both ways. Reactive power from PV inverters can effectively control voltage, and can be obtained via a simple grid code requirement that most inverters on the market can fulfill already, but at the cost of increasing grid loading through reactive currents. In already highly loaded grids caused either by high load or high PV feed-in, it may actually have a negative impact. In any way, requiring the capability for reactive power and voltage control from rooftop PV inverters is sensible, as it will give the operator an additional means of voltage control, that could also be used to alleviate pre-existing voltage issues (for example in cases where no automatic voltage control from power transformers is available.) The actual regime for activation of reactive power provision should be decided based on the characteristics of each individual grid.
E. Reversed power flows and protection
The only direct impact of a reversal of power flow with a moderate flow that can be observed concerns the protection settings. Especially with the over current protection typically used at medium and low voltage levels, the short circuit current contribution of the units feeding in between the protection relay and the location of the fault have to be considered. For PV, the short circuit current is no larger than the rated current of the inverter, leading to a moderate contribution that should nevertheless be considered in the calculation of protection settings.
The easy way around this problem would be to require the units on a feeder protected by an overcurrent relay to immediately disconnect at detection of a voltage drop (which indicates a short circuit nearby), or stay connected but not provide any short circuit current. If this requirement collides with low voltage ride through that may be required for other reasons, the short circuit current of all units on a feeder should be limited to
6.1 General technical requirements
Independent of expected or achievable PV penetration level, a number of technical requirements should always be fulfilled by PV units. Like all power electronics, PV inverters are potential sources of harmonics and DC currents that are generally undesirable to the power system. Grid codes applicable to PV should thus set limits on such emissions. Modern inverters emit very little distorting currents and are often compliant with international standards that limit emissions, such as IEEE 519 or IEC 61000-3-2. Typical voltage quality requirements include the following:
- Limits on voltage rise induced by connection of the unit (typically 2 – 3 %);
- Limit on voltage steps induced by switching operations (typically 2 – 3 %);
- Limits on flicker (example: Plt ≤ 0.5 with the definition according to standard IEC 61000- 3-3 and -3-11);
- Limits of harmonic current infeed (defined in IEC 61000-3-2, limits from 3 % for the third order harmonic, descending with ascending harmonic order);
- Limits on asymmetrical loading
Requirements to comply with international standards have been in place in all of them since the beginning of PV development in the 1990s.
PV units also have to be equipped with adequate generator protection to avoid damage to the unit in case of a nearby fault as well as to prevent unintentional islanding.
Moreover, the compatibility of the fault behavior of PV units with the local protection settings should be checked.
6.2 Technology options to enable high PV penetration levels
Specific technical solutions need to be assessed for each grid area separately, but some recommendations can be drawn from the model cases analyzed in this study. Concerning voltage control, these are the following:
- Automatic voltage control by tap changing transformers at 66/11 or 33/11 kV level is very beneficial to voltage quality regardless of PV penetration, but not strictly required if the voltage control above is adequate.
- Voltage problems in the distribution grid, caused by both load (undervoltage) and PV (overvoltage) can be efficiently eliminated by the use of a wide area voltage control, measuring the voltage at multiple points in the grid and operating the voltage control by transformers accordingly.
- The capability for voltage control by rooftop PV inverters by provision of reactive power can easily be required by the grid code, and such a requirement is highly recommended and international good practice. The actual set points of the voltage control or fixed power factor, or the decision whether it is engaged at all, must be determined by the operator based on grid loading. If loading is low, reactive power for voltage control is beneficial. If loading is high, reactive currents may cause overloads. Generally, Q-V characteristics perform better in highly loaded grids and offer more control, while fixed offset power factors alleviate voltage problems in lightly loaded grids more effectively.
- PV power plants connected to the 11 or 33 kV level should be equipped with active voltage control by Q-V characteristic. If the grid experiences severe overloading issues, the grid operator may choose to disable the controls and run the unit at a fixed power factor, unity or offset.
Active power management of PV units will also play a large role in the future, leading to the following recommendations:
- Some degree of active power management and controllability should be required from all PV units, regardless of size and connection level.
- Centralized PV power plants connected to 11 kV and above should be remotely controllable so the grid operator can curtail active power in case of grid congestion. The exact conditions under which the operator may curtail must be clearly defined and subject to energy legislation and regulation.
- Rooftop PV units connected to the low voltage grid should either be capped at 70 to 75 % of their maximum expected output, or be remotely controllable, or be equipped with a peak shaving storage. A cap is the cheapest and least complicated option.
- If PV batteries are introduced, there should be an incentive to use them in peak shaving mode to maximized positive grid impact.
6.3 Legal and regulatory framework
Technical development needs to be supported by an adequate legal and regulatory framework. Most Indian states have a net metering scheme in place and specific regulations for application, installation and metering. For a large scale roll-out of rooftop PV and with regard to the technical solutions developed within this report, the following points need to be addressed in legal and regulatory development:
- The distribution grid codes should be updated to require voltage control capability from PV inverters, with the grid operator being in charge of the actual reactive power regime. It is recommended to align the requirements with the German low voltage grid code, as many inverters available on the market are compliant with that already.
- The capping of PV at 70 or 75 %, if implemented, must be specified in grid code and net metering scheme, and must be checked for legal complications.
- For PV batteries, incentives have to be set by energy legislation, both for installation of batteries and for running them in peak shaving mode.
- If PV units can be remotely controlled by the grid operator, it needs to be specified in legislation and regulatory documents under which circumstances the operator is actually allowed to do so. For the case of active power curtailment, remuneration of lost energy must be agreed on.
- The high share of rooftop PV expected to be installed in India will also impact power system operation above the distribution level. Grid code requirements should be developed in coordination with the entities responsible for the operation and stability of the transmission system. As an example, frequency response of PV units will neither impact the distribution grid nor is it required for distribution grid operation, but will considerably impact transmission system operation.
Analysis of Indian Electricity Distribution Systems for the Integration of High Shares of Rooftop PV – GIZ