DG synchronisation with solar starts with a plain site. A factory has a 500 kVA diesel generator (DG), a new rooftop plant and a grid that fails often enough to matter. The owner expects the roof to help during an outage. The grid-tied inverters stop when the grid goes, and something has to decide how much of them may restart on the DG. If that decision is wrong, one of two things happens. Solar stays off all day, or it pushes the DG into reverse power and the whole site goes dark.
Most EPCs ask which controller to buy. The better first question is how much solar the DG can accept. The answer comes from the DG maker’s minimum load, not from the inverter rating.
Quick answer. A rooftop plant can run beside a factory DG only if the DG always stays above its maker’s minimum load. Cummins recommends at least 30 percent of nameplate rating. Size outage solar as load minus that floor plus a margin, and let a DG-PV controller curtail the inverters to hold it. Set the controller’s reverse power trip ahead of the DG’s own relay, and draw both on the SLD.
This guide is for an Indian or Gulf EPC adding rooftop solar to a factory that already owns a DG. If you are designing a new off-grid or weak-grid system with batteries, start with our hybrid solar, diesel and battery design guide. If the question is export to the DISCOM, read zero export solar design, which this article does not repeat.
What does DG synchronisation mean for a rooftop plant?
In this context it usually means the PV inverters locking on to the voltage and frequency that the DG produces. A grid-tied inverter follows a reference. On grid supply the DISCOM provides it. On DG supply the DG does, and it is a much softer reference.
The same words are also used for a different job. A DG synchroniser (ANSI device 25, sync check) closes a DG breaker onto a live bus. It is used when two DGs share load or when a DG parallels with the grid. Keep the two apart:
| Question | PV following the DG | DG paralleling with another source |
|---|---|---|
| What is synchronised | Inverter output to DG voltage and frequency | DG output to a live grid or another DG |
| Who does it | The inverter’s own grid-following control | A synchroniser in the DG controller |
| Approval route | Inverter settings and the SLD, agreed with the DISCOM where it applies | Connection agreement and DISCOM protection requirements if the DG parallels with the grid |
| What this article covers | Yes | Only where it touches the switching logic |
We cover the first case, where the DG supplies the site on changeover and never runs in parallel with the grid. If your DG will parallel with the grid, treat it as a second generator in the connection agreement and ask the DISCOM before you design anything. Cummins notes that sets running in parallel with the utility typically carry sync-check, voltage, reverse power, overcurrent, loss-of-grid and frequency protection. The settings are agreed with the utility (Cummins T-030 application manual, Issue 9, February 2015).
The Indian rules cited here are CEA rules. For a Gulf plant they do not apply, so read the utility’s connection requirements and the DG maker’s documents instead.
Why does a DG need a minimum load?
A diesel engine is built to run under load. Light load causes slow damage, and too much solar causes a fast fault. Both limits matter for sizing.
Wet stacking. Caterpillar states that running a diesel set below 30 percent of rated output for extended periods affects it negatively. The most common result is exhaust slobber, also called wet stacking. At light load the cylinders run cool, and unburned fuel and oil leak through the exhaust joints as a black, oily liquid. Longer light running can build deposits behind the piston rings and, in extreme cases, polish the cylinder liners. Sets with exhaust aftertreatment also suffer, because the filters and catalysts need a minimum exhaust temperature (Caterpillar, “The Impact of Generator Set Underloading”, October 2014).
Reverse power. If the inverters supply more than the load takes, the surplus flows back into the alternator. The alternator then drives the engine as a motor. Cummins describes this motoring condition in its manual and calls reverse power protection essential for paralleling systems. DEIF states the link to solar directly. A minimum genset load constraint keeps a certain load on the gensets, which removes the risk of reverse power and impure combustion (DEIF Hybrid Power Application Guide, 2022).
The manufacturers give different numbers, and they apply to different documents:
| Maker and document | What it says | Date |
|---|---|---|
| Cummins, T-030 Liquid-Cooled Generator Set Application Manual, section 2.4 | Recommends operating a set at a minimum of 30 percent of nameplate rating | Issue 9, 02-2015 |
| Cummins, T-030, section 7.1.2.2 | Does not recommend less than 30 percent of rated load; use load banks below that; a set should not run below 10 percent of rated load for any extended period | Issue 9, 02-2015 |
| Caterpillar, underloading white paper | Below 30 percent for extended periods harms a diesel set; standby and prime diesel sets are designed for 50 to 85 percent of nameplate; recovery run of at least 30 percent load for about 30 minutes per four hours of light load | October 2014 |
| SMA, Fuel Save Controller 2.0 manual | Default minimum genset loading parameter is 30 percent of nominal genset active power | Version 2.0 |
SMA’s default is a controller setting, not a DG warranty condition. It confirms that the controller industry works to the same 30 percent figure.
Two cautions. First, T-030 is a 2015 issue hosted on cummins.com, so check the current manual for the exact model. Second, other makers may state a different percentage. We could not open a Kirloskar or other Indian maker document with a minimum-load figure, so we do not quote one. Get the figure for your exact model in writing from the DG supplier before you set the controller.
The trade also circulates fixed PV-to-DG ratios. We found no maker document that states one, and the floor method below does not need one.
What does a DG-PV controller actually do?
It sits between the DG, the load and the inverters, and it limits inverter output so the DG stays inside its window. Four functions matter.
- Measure fast. The controller needs DG power and load power at short intervals. SMA’s genset documentation asks for values updated every 300 ms at the latest, within 1 percent of the measurement range, with power values exchanged every 150 ms.
- Hold the floor. It sets the inverter active power limit to load minus the DG minimum. SMA describes this as a minimum genset load feature that reduces inverter output, typically within five to seven seconds in its first-generation controller.
- Cut on reverse power. If a sudden load step makes the normal adjustment too slow, the first-generation SMA controller forces the inverters off. SMA states that complete inverter shutdown takes less than 2.5 seconds.
- Manage the DG count. With several DGs, the controller reads the DG controller’s reserve and start thresholds. SMA states that DG connection and disconnection stay with the genset controllers, and the solar controller only issues setpoints or recommendations.
Three controller families show how vendors describe it. We read manufacturer documents only and make no ranking.
| Controller | What the documents state | Notes |
|---|---|---|
| SMA Fuel Save Controller 2.0 | Minimum genset load, reverse power protection, spinning reserve, inverter ramp and fallback settings | Works with SMA inverters; needs a compatible genset controller interface or direct measurements and breaker feedback |
| DEIF AGC 150 Hybrid and ASC-4 Solar | Minimum genset load, spinning reserve, up to 16 inverters, up to 3 gensets (synchronising or not), SunSpec compatible, mains parallel or off-grid | AGC 150 Hybrid is positioned for small and medium rooftop plants |
| ComAp InteliGen 500 G2 with PV Control extended feature | Minimal genset load, import and export control, PV control over a Modbus client | ComAp says its controller handles DG-PV synchronisation, reverse power protection, genset minimum loading and solar curtailment. We found web pages only, no parameter manual |
The choice usually follows the DG controller already on site and the inverter brand the EPC has bought. SMA’s own note says that a solar controller and a genset controller that do not follow compatible power management principles can cause repeated genset connection and disconnection. Check compatibility before you order, not at commissioning.
How do you size solar against the DG minimum load?
Use one rule and two checks.
The rule. At any moment, the solar output allowed on the DG bus is the load minus the DG floor. The floor is the maker’s percentage times the DG kW rating, plus a margin.
Check 1, the step. If the solar plant trips, the DG takes its output in one step. That step must sit inside the DG maker’s step-load data.
Check 2, the reserve. With more than one DG, the running set must carry the load if solar drops. Staging DGs lifts the solar limit but cuts the reserve.
Worked example (illustrative)
Every number below is an assumption. Replace them with the client’s load data, the DG maker’s data sheet and the controller’s documented behaviour.
Assumptions (illustrative).
- One DG rated 500 kVA at 0.8 power factor, which is 400 kW.
- Maker floor 30 percent, which is 120 kW (Cummins and SMA default).
- Controller setpoint 35 percent, which is 140 kW. The 5 point margin is our choice.
- Rooftop plant of 300 kW AC at the inverters.
- Load measured on the DG bus during the outage. Sun is strong enough that the array can reach its limit.
The allowed solar output is the smaller of 300 kW and the load minus 140 kW, never below zero.
| Load on DG bus (kW) | Allowed solar (kW) | DG output (kW) | DG loading (percent of 400 kW) | Solar share of load (percent) |
|---|---|---|---|---|
| 100 | 0 | 100 | 25 | 0 |
| 180 | 40 | 140 | 35 | 22 |
| 260 | 120 | 140 | 35 | 46 |
| 330 | 190 | 140 | 35 | 58 |
| 400 | 260 | 140 | 35 | 65 |
Read the table three ways.
First, the array is 300 kW but only 120 kW of it runs at the 260 kW load. The inverter rating did not decide that. The gap between the load and the floor did. Adding more panels adds grid-tied hours and does nothing for outage output.
Second, the 100 kW row shows a different problem. Even with no solar the DG sits at 25 percent, below the floor. That is a DG sizing and operating issue, and curtailing solar cannot fix it. Cummins says to supplement the load with load banks when loading falls below the recommended value, and Caterpillar suggests designing load bank access into the system. Put a load bank connection on the SLD if the site will often run at light load.
Third, the step check. At the 260 kW row, if the solar plant trips, the DG goes from 140 kW to 260 kW. That is a 120 kW step, 30 percent of the DG rating. Ask the DG maker whether the set accepts that step and what frequency and voltage dip follows. The worst case is also the moment inverters restart, so see the switching logic below.
What does a second DG change?
Take a 180 kW load. With one 400 kW DG, the 30 percent floor is 120 kW and solar is limited to 60 kW. Replace it with two 200 kW DGs and run only one: the floor is 60 kW and solar can supply up to 120 kW. The solar share doubles.
The cost is reserve. The running 200 kW set would carry 180 kW alone if solar dropped, which is 90 percent loading with 20 kW of reserve. The DG controller must start the second set in time, and SMA notes that DG start and stop belong to the genset controller. Decide the staging thresholds with the DG controller programmer, not in the PV design alone.
Why not simply set the floor lower?
Caterpillar and Cummins both tie the harm to extended light running. Cummins’ exercise guidance even accepts a lower load if the exhaust gas temperature reaches the level in its engine table. A short dip is not the main danger. A fast load drop is, because it can push power backwards. That is why the margin sits in the controller setpoint and the reverse power trip is layered next.
How should reverse power be set on the DG?
Layer it so the controller acts first and the DG’s own relay is the last resort. SMA’s manual says the parameters must be configured so the reverse power protection triggers at the Fuel Save Controller first. If it triggers in the genset first, the genset stops unexpectedly, and SMA warns this can cause a power failure across the whole hybrid system.
CEA connectivity regulation 11(7)(b) gives the design reason for two layers: the failure of any single device must not compromise the safety and reliability of the system. Give the controller and the DG relay separate current transformers where the design allows it.
The table uses the 400 kW DG from the example. The DG maker’s controller manual and the DISCOM’s requirements govern the real values.
| Layer | Device | Pickup | Delay | Action | Basis |
|---|---|---|---|---|---|
| 1 | Controller floor setpoint | 140 kW minimum DG load (35 percent) | Ramp set in the controller | Trim inverter output | Cummins 30 percent plus our margin |
| 2 | Controller reverse power trip | Minus 5 percent of DG rating, which is minus 20 kW | 0.1 s | Shut down the inverters | SMA FSC 2.0 default error tolerance and timer |
| 3 | DG reverse power relay (ANSI 32) | 10 percent of rating, which is 40 kW | 5 s | Open the DG breaker | Practitioner illustration, not a published value |
A load trip shows why the order matters. Suppose the plant runs at 260 kW load with 120 kW of solar and a 200 kW motor trips. The load falls to 60 kW, solar still supplies 120 kW, and the DG sees minus 60 kW, which is 15 percent reverse. Layer 2 picks up, the controller shuts the inverters, and SMA’s published shutdown time is under 2.5 seconds. The relay at layer 3 waits 5 seconds, so it should not operate. If you set it at 3 seconds, the margin falls below a second.
That arithmetic uses one vendor’s first-generation figure, so use your controller’s measured shutdown time. Ask the DG maker how much reverse power and for how long the set tolerates it. That tolerance, not our illustration, sets layer 3.
Keep the DG’s own reverse power protection enabled at all times. SMA’s manual says it must stay active while the controller operates.
What is the switching logic between grid, DG and solar?
The sequence matters because inverters take time to restart and the DG carries the whole load until they do.
| Step | Source state | Inverters | Controller action | Source or basis |
|---|---|---|---|---|
| 1 | Grid healthy, DG stopped | Follow the grid, with export control if required | Monitoring only | See the zero export guide |
| 2 | Grid fails | Stop energising within 2 s | None | CEA connectivity regulation 11(6)(e), outer limit |
| 3 | DG starts and closes onto the bus | Still off | Ready | DG controller or AMF panel |
| 4 | DG voltage and frequency settle | Wait for the reconnection timer | Sets limit to zero until inverters respond | CEA regulation 11(6)(d) says 60 s of stable voltage and frequency for reconnection to the electricity system; the DG-bus timer is maker-specific |
| 5 | DG carries the whole load alone | Off | None | Size the DG without solar |
| 6 | Inverters restart | Ramp up | Limit equals load minus floor | Controller ramp settings |
| 7 | Running on DG | Output held by controller | Floor, reverse power, fallback | Controller manual |
| 8 | Grid returns | Stop when the DG supply is lost or transferred | Reduces solar to ease transfer if the controller offers that function | SMA “Micro-Grid Friendly” feature |
Three points sit behind the table.
The DG is alone first. In steps 3 to 5 the DG starts and carries the full factory load with no solar. That lasts at least as long as the inverter restart time. Do not credit solar when you size the DG for motor starting.
The grid-return transfer is a separate job. SMA states that the synchronisation of gensets and the grid is not controlled by its solar controller. The changeover panel or the DG controller does it. In a changeover design the transfer is break-before-make, so the DG never parallels with the grid. Interlock the grid and DG breakers so both cannot close together. CEA safety regulation 47(1)(iii) states the interlock requirement for supplies above 650 V that are not meant to run in parallel. We apply the same logic on low voltage as practice.
Inverter settings may need approval. SMA notes that the inverter grid monitoring has to be adjusted for genset-parallel operation. In some cases the required settings may not be accepted for grid-parallel operation, so the permission of the local network operator is required. Ask the inverter maker whether a DG-supplied bus is treated as a grid and what its DG mode changes. We did not verify a specific inverter maker’s DG mode.
What changes on the single line diagram?
The SLD is where this scheme becomes checkable. Our guide to reading a solar single line diagram covers the basic symbols, and the SLD glossary entry defines the term. For a DG-backed plant, add these items:
- The DG, its breaker (generator circuit breaker) and the changeover arrangement, with the interlock drawn as a labelled dashed link.
- A CT or meter on the DG output feeding the controller, with polarity marked.
- A load measurement point on the bus the inverters share with the factory loads, and a note stating which side of the changeover it sits on.
- The PV AC breaker with two trip sources: the DG-PV controller and the DG protection.
- The ANSI 32 relay on the DG, tagged and with its settings box.
- The communication path from the controller to the DG controller and the inverters, with the fail-safe action written next to it.
- A load bank connection point if light load is likely.
- A settings sheet on the same drawing set, listing floor setpoint, reverse power thresholds and delays.
CEA connectivity regulation 11(10) to 11(12) requires the applicant and the licensee to agree the protection features and control diagrams before first synchronisation. The drawings are amended when the plant changes. Treat a DG-PV controller as a change to those diagrams.
If you need the DG changeover, controller and relay drawn into a rooftop IFC package, our rooftop detailed engineering design service covers the drawing set. Scope and turnaround are agreed at scoping.
Which Indian rules touch this design?
Less than most EPCs expect. The numbers come from the DG maker, and the rules govern the interface.
CEA connectivity regulations. The CEA (Technical Standards for Connectivity of the Distributed Generation Resources) Regulations, 2013, as amended on 6 February 2019, cover plants connecting below 33 kV. We re-read the consolidated text. Regulation 11(6) sets the trip and reconnection behaviour. Regulation 11(7)(b) is the single-failure rule, 11(9) the isolating switch, and 11(10) to 11(12) the agreed diagrams. It states no minimum DG load and no ratio between PV and DG. Our CEA connectivity guide and the CEA connectivity glossary entry cover the wider framework.
CEA safety regulations. The CEA (Measures relating to Safety and Electric Supply) Regulations, 2023, notified on 8 June 2023, include interlocks in regulation 47(1) and protection in 47(2). The regulation is headed for voltages above 650 V. Regulation 47(2)(v) requires earth fault or leakage protection for all generators of 100 kVA and above. Ask the inspector how they apply that clause to a low voltage DG. The CEIG inspection route depends on state notifications, and our CEIG inspection checklist lists what we could confirm. The CEIG glossary entry defines the role.
CPCB. The Central Pollution Control Board rules cover the DG set itself. Emission standards for power generating set engines were revised by GSR 804(E) on 3 November 2022 and apply to new sets through type approval at manufacture. The noise limit for new diesel sets up to 1000 kVA is 75 dB(A) at 1 metre from the enclosure. CPCB’s noise guidance also tells users that installation must follow the DG manufacturer’s recommendations. We read nothing in those CPCB documents on minimum load or solar, and we cite them only for that pointer to the maker.
For relay grading across a larger plant, see our relay coordination study guide. It covers methodology. Do not take CEA setting values from it for this design. Use the CEA text itself and the DISCOM’s letter.
We cannot tell you that a DISCOM or an inspector will accept a given scheme. Acceptance is their decision on the specific site, so ask in writing.
Which commissioning faults come up most often?
The list below is practitioner judgement from design review and commissioning checks. It is not a published statistic, and the order is not a ranking.
- Reversed CT on the DG feeder. The controller reads reverse power when the DG is loaded, or reads normal power when it is motoring. Test with the DG on a known load and check the sign on the controller screen before solar is enabled.
- Wrong measurement point. The controller measures the DG output but not the load, or measures the load on the grid side of the changeover. Confirm which bus each CT sees.
- Inverter frequency window against the DG governor. Cummins states that mechanical governors have about 3 to 5 percent speed droop from no load to full load. Electronic governors can hold zero droop. At 50 Hz, 3 to 5 percent is 1.5 to 2.5 Hz. A set tuned for full load can therefore sit above the 50.5 Hz outer trip in CEA regulation 11(6)(b) at light load. Inverters set to a grid-code window may then trip on DG frequency. Check the DG governor type and the inverter’s DG mode.
- Fallback mismatch. SMA warns that if the inverter fallback settings differ from the controller’s, power fluctuations when communication returns can cause a power failure across the hybrid system. Match the two, and write the fallback on the SLD.
- Controller and DG controller disagree on DG start and stop. SMA states this can cause repeated DG connection and disconnection. Agree the thresholds once, in writing.
- Reverse power order wrong. The DG relay is set tighter than the controller trip, so the DG stops first. Re-read the layering table above and test it.
- Only tested at one load. Test solar step-off, load step-off, DG start with solar on standby, and grid return. Repeat at the minimum load.
- No light-load plan. The DG sits below 30 percent for weeks. Plan a load bank run or a loaded exercise, and record it.
FAQ
Can a rooftop plant run during a grid outage without a battery?
Yes, if a DG supplies the bus and gives the inverters a reference. Without a DG or battery the grid-tied inverters stay off, because CEA regulation 11(6)(e) requires them to stop energising within 2 seconds of an unintended island. How much solar can run depends on the DG minimum load, as shown above.
What minimum load percentage should I use?
Use the figure the DG maker states for your exact model. Cummins recommends 30 percent of nameplate in its application manual, and Caterpillar says extended running below 30 percent affects a diesel set negatively. Add a margin in the controller and do not rely on a trade rule of thumb.
Is a DG-PV controller mandatory in India?
We found no CEA regulation that names one. The need is physical. Solar can unload a DG below its minimum or drive it into reverse power, and a DG has no way to regulate the solar plant. Your DISCOM or inspector may ask for specific protection, so confirm in writing.
Does the controller also handle zero export?
Some do. ComAp lists import and export control in its PV Control feature, and SMA describes a feed-in protection feature. Export control to the DISCOM and DG-bus control are different jobs with different measuring points. Our zero export design guide covers the first.
Can I use a hybrid inverter and skip the controller?
A hybrid inverter with a battery changes the design, because the battery can absorb surplus and fill gaps. Our hybrid solar and diesel guide covers that case. The DG still has the same minimum load and reverse power limits, so the logic must exist somewhere. Ask the inverter maker to document how it handles them.
Does adding solar always cut diesel use?
It cuts diesel when solar displaces DG output above the floor. SMA notes that light-load operation is inefficient, so a DG held at the floor still burns fuel at a poor efficiency. Measure fuel per kWh during commissioning rather than assuming the saving.
Before you finalise the design
- Get the DG model, kW rating and written minimum load figure from the maker or supplier.
- Record outage load data on the DG bus, including the lowest hours.
- Apply the rule: allowed solar equals load minus floor, plus margin.
- Run the step check and, for several DGs, the reserve check.
- Choose a controller that is compatible with the DG controller and the inverters.
- Layer the trips: controller floor, controller reverse power, then DG relay.
- Draw the CT locations, interlock, load bank point and settings sheet on the SLD.
- Write the commissioning test list before the site visit.
To have the DG-PV scheme drawn into a rooftop IFC package, send us the site details and the DG data sheet and we will scope it with you. You can also message us on WhatsApp. To see how our drawing sets are laid out first, request the design samples. We reply within 1 business day.
Source and review note
Sources opened and read on 31 October 2026:
- Cummins T-030 Liquid-Cooled Generator Set Application Manual, Issue 9, February 2015 (sections 2.4, 4.3.1, 7.1.2.2, 7.5.3 and the reverse power and paralleling sections).
- Caterpillar, The Impact of Generator Set Underloading, Brian Jabeck, October 2014.
- SMA Fuel Save Controller 2.0 user manual, version 2.0, as hosted by BayWa r.e. (sections 8.1.1 and 8.1.2 and the inverter management settings).
- SMA technical information on gensets with the Fuel Save Controller 2.0, version 1.3.
- SMA Fuel Save Controller functional description, version 1.0. It describes the first-generation controller, so the 5 to 7 second and 2.5 second figures belong to that product.
- DEIF Hybrid Power Application Guide, 2022.
- ComAp hybrid power generation page and PV Control extended feature page. These are web pages with no parameter values.
- CEA (Technical Standards for Connectivity of the Distributed Generation Resources) Regulations, 2013, as amended on 6 February 2019: CBIP consolidated copy.
- CEA (Measures relating to Safety and Electric Supply) Regulations, 2023, notified 8 June 2023: Internet Archive capture of 26 December 2024. The cea.nic.in link returns 404.
- CPCB noise limit for diesel generator sets, including amendments to 2011, and the CPCB System and Procedure for the November 2022 emission standards, read as a working copy hosted by ECMA India.
Not verified: a minimum load figure from Kirloskar or another Indian DG maker, any inverter maker’s DG mode, and any Gulf utility’s DG rules. The worked example and the settings table are illustrative and use only the stated assumptions. Recheck the DG maker’s current manual and your controller’s firmware documentation before quoting this article to a client. Next review: 31 January 2027.