Cogeneration for Industry – CHP Unit Sizing and Trigeneration

Cogeneration can be a very effective energy source for an industrial site, but only when electricity demand and demand for useful heat occur at the same time. This is why an analysis should not begin with the question, “Which CHP unit should we choose?” The first step is to examine the site’s operating profile, the parameters of its heat demand and the number of hours per year for which the installation will actually have suitable operating conditions.

Here we focus on the practical sizing of a cogeneration installation for a business: from measurement data, capacity and technology selection through to integration with heat, cooling, photovoltaics and the electricity grid.

In brief

CHP capacity should be based on the simultaneous electricity and heat demand profile, not on contracted capacity, annual consumption or a single peak value.
Monthly data are sufficient for an initial screening. Responsible sizing requires at least a representative hourly profile, while for electricity it is best to use available 15-minute data.
It is not only the quantity of heat in MWh that matters, but also its temperature, heat-transfer medium, point of use and seasonality. Heat that the site cannot use should not improve the cogeneration balance.
Trigeneration makes sense when there is measurable cooling demand that can be met by an absorption chiller. It should not be used solely as a way to “dispose of” surplus heat.
One larger unit is not always better than two smaller ones. At many sites, modularity makes it easier to match part-load conditions, maintenance requirements and seasonality.

Cogeneration for industry: simultaneous demand first, capacity second

Cogeneration, or CHP (Combined Heat and Power), produces electricity and heat in a single process. The key word, however, is useful. Poland’s Energy Law defines useful heat in cogeneration as heat used to meet actual demand for heat or cooling that, without cogeneration, would have to be supplied from other sources.

This leads to the most important sizing principle. A site may have high annual electricity consumption and equally high annual gas consumption, yet still be a poor candidate for a large CHP system. It is enough for peak heat demand to occur in winter while high electricity demand occurs at different hours or in different months.

From an auditor’s perspective, I would therefore first check how many hours per year the two demand profiles overlap. Only then would I compare specific CHP units, their modulation ranges and their part-load performance characteristics.

Annual MWh totals answer the question “how much energy was consumed?”. CHP sizing requires an answer to a different question: “How much electricity and heat did the site need simultaneously in each hour?”

What data should be collected before sizing a cogeneration installation?

The best input dataset covers a full, representative year of operation. If the site is highly seasonal or the latest year was unusual, it is worth comparing more than one period and separately accounting for planned production changes.

1. Electricity profile

The following data should be collected for the analysis:

electricity imported from the grid in 15-minute or hourly intervals;
peak demand and typical baseload on working days, weekends and during shutdowns;
production shift schedules;
existing on-site generation, especially photovoltaics;
planned new production lines, process electrification, heat pumps, vehicle charging or the removal of major loads;
planned maintenance and seasonal shutdowns.

Contracted capacity should not be treated as equivalent to the demand that CHP can cover. Contracted capacity is a billing and technical parameter. A CHP unit operates against the site’s actual load.

2. Useful heat profile

On the thermal side, we need data that are just as detailed as on the electrical side. Heat meters and process measurements are preferable. If these are unavailable, boiler fuel consumption can be used for an initial estimate, but assumptions are then required for efficiency and for allocating fuel consumption between heat users.

For each heat consumer, it is worth determining:

instantaneous thermal power and energy over time;
supply and return temperatures;
the heat-transfer medium: hot water, steam, thermal oil or process air;
for steam: pressure, temperature, flow rate and how it is used;
process operating hours;
seasonality;
the possibility of control and short-term thermal storage;
the source that cogeneration is intended to replace or relieve.

This distinction is critical. A 400 kW demand for water at parameters suitable for engine heat recovery is entirely different from a 400 kW demand that must be supplied as process steam.

3. Cooling profile — only if trigeneration is being considered

If the site has process refrigeration or a large, sustained demand for chilled water, collect:

cooling capacity over time;
supply and return temperatures of chilled water or another medium;
electricity consumption of existing chillers;
cooling operating hours;
minimum and maximum load;
seasonality and the required cooling temperature level.

Only these data make it possible to determine whether an absorption chiller will genuinely increase the utilisation of heat from CHP. The mere fact that surplus heat is available in summer is not sufficient justification for trigeneration.

4. Fuel and site technical conditions

Regardless of the load profile, the following must be checked:

the available fuel type and its parameters;
gas pressure and available connection capacity;
biogas quality and stability, if biogas is to be used as fuel;
conditions for connecting the generating unit to the electricity grid;
available space, ventilation, transport access and service access;
the possibility of discharging exhaust gases;
noise constraints;
existing boilers, heat exchangers, headers and control systems.

Only once this information has been combined is there a sound basis for comparing specific cogeneration systems.

Useful heat: MWh alone are not enough — temperature matters

A common mistake in CHP analysis is to add together the site’s entire heat demand. In reality, each portion of that heat has a specific quality and temperature level.

If a CHP engine provides heat in a water circuit and in its exhaust gases, this does not mean that all catalogue-rated heat can be assigned to any process. The heat use must be technically compatible with the required temperature, flow rate and process configuration.

For example:

hot water can supply space heating, domestic hot water preparation, washing, selected industrial processes or preheating;
exhaust gases can be used in a heat exchanger or waste-heat boiler where a higher temperature level or steam is required;
low-temperature heat cannot directly replace process steam merely because the annual MWh balance matches;
a heat consumer operating at the correct temperature for two hours per day is not equivalent to a continuous heat load.

For sizing purposes, it is therefore useful to create a map of heat consumers: how much capacity they require, during which hours, at what temperature and at which point in the installation they can be supplied.

From an auditor’s perspective, one of the most common mistakes is to treat all gas consumed by the boiler house as potential heat demand for cogeneration. The heat consumers must first be separated and their parameters checked. Only then does the genuine thermal baseload become visible.

How to size a cogeneration system step by step

Step 1. Determine the baseload, not the peak

For each hour, compare at least:

electricity demand;
useful heat demand at parameters that can be supplied by CHP;
any cooling demand;
generation from PV or other sources;
production status: normal operation, weekend, shutdown or maintenance.

We are looking for a load level that recurs over a large part of the year. In practice, a load duration curve and an analysis of coincident-demand hours are more useful than a single annual peak.

Step 2. Compare several capacity options

A single unit should not be selected first and its operation justified afterwards. A better approach is to compare several options, for example:

a smaller unit operating for longer hours and with higher heat utilisation;
a larger unit operating for fewer hours;
two modules started according to load;
a CHP system combined with a thermal buffer;
an option incorporating existing or planned photovoltaics.

For each option, use actual manufacturer data sheets: electrical and thermal output, efficiency and part-load limitations. It must not be assumed that nominal parameters remain unchanged at 50% or 70% load.

Step 3. Account for shutdowns and maintenance

CHP relies on mechanical equipment. The model must account for planned inspections and overhauls, service availability and the site’s process shutdowns.

If a process requires continuous heat, existing boilers will generally continue to serve as peak-load and backup sources. Conversely, if production stops for several weeks, the model should not assume full energy demand during that period.

Step 4. Define the control strategy

The system can be controlled, among other approaches, according to heat demand, electricity demand or a defined economic strategy. At a site with PV and a variable process, a simple “always run at 100%” rule can lead to unnecessary electricity exports or heat rejection.

The control strategy should define:

the unit’s minimum load;
start and stop conditions;
priority for heat use;
coordination with boilers;
coordination with PV;
charging and discharging of the thermal buffer;
behaviour during power limitation or a grid outage.

Oversizing: the unit may operate correctly while the installation is still poorly sized

An oversized CHP system does not always look like a fault. The engine may operate according to its instructions and the generator may achieve good electrical efficiency, yet the overall project can still lose its rationale because the site cannot use the heat being produced.

Assume that, according to the manufacturer’s data, the module under analysis produces 500 kW of electricity and 600 kW of heat at a given operating point. During a particular hour, the site draws 720 kW of electricity but has only 250 kW of useful heat demand at suitable parameters.

In that case:

all 500 kW of electricity can be consumed on site;
of the 600 kW of available heat, the site can use 250 kW;
the remaining 350 kW must be stored, reduced by changing the unit’s operating point, or rejected;
without an additional heat consumer, about 58% of the available thermal capacity in that hour has no useful application.

This is an example of a situation in which sizing solely against the electrical profile produces the wrong result. Technically, the unit may operate correctly, but primary energy is not being utilised as assumed in the analysis.

In systems equipped with emergency heat rejection, a dump radiator or other heat-rejection device can provide a protective function, but it should not become a permanent “consumer” used to justify CHP capacity.

Does a thermal buffer solve the problem?

A thermal buffer can shift heat use from one hour to the next and smooth short-term imbalances. It can also reduce the number of starts and stops.

It does not, however, solve a seasonal problem. If the site needs virtually no heat for three summer months, a tank cannot store energy from June until September. In that situation, the shorter operating period must be accepted, CHP capacity reduced, or a genuine process-justified heat use identified.

Cogeneration with photovoltaics, energy storage and existing boilers

Cogeneration and photovoltaics should not be analysed as two independent investments. PV reduces grid imports mainly during solar generation hours, while CHP may be constrained by both the electrical and thermal profiles.

If the PV installation already exists, the model should use its actual generation profile. If it is only planned, variants of both technologies should be compared on the same time axis.

Example: at midday, the site may have high heat demand but low grid electricity imports because of PV generation. The CHP unit can then:

continue operating and export part of its electricity, if the connection conditions and economic model justify this;
reduce output, if the unit’s operating characteristics permit it;
operate in conjunction with battery energy storage;
be stopped temporarily if there is no demand for its electricity and the technical conditions do not justify continued operation.

Existing boilers must be included in the same way. CHP generally does not replace the entire boiler house. It often covers the thermal baseload, while boilers provide peak output, start-up duty, backup and cover during maintenance periods.

Trigeneration only when the site genuinely needs cooling

Trigeneration, or CCHP (Combined Cooling, Heat and Power), extends cogeneration to include cooling production. It most commonly uses an absorption chiller driven by heat from the CHP system.

Technically, this can be a very effective solution at sites with sustained demand for process cooling, chilled water or air conditioning over a large number of operating hours. Absorption chillers can use hot water, steam or exhaust heat, but their sizing depends on the required cooling temperature and the parameters of the available heat source.

The most important point is to reverse the order of reasoning. The starting point should not be: “we have too much cogeneration heat in summer, so let’s add an absorption chiller.” First, existing cooling demand must be demonstrated and the amount of work performed by compressor chillers that can genuinely be displaced must be assessed.

A good candidate for trigeneration is, for example, a site where the following occur simultaneously for many hours:

stable electricity demand;
heat demand or heat available from CHP;
process cooling demand at parameters that can be achieved by an absorption chiller.

If cooling is needed only during a few of the hottest weeks and there is otherwise no heat demand, trigeneration may merely increase the system’s cost and complexity. In such a case, it is better first to analyse cogeneration itself and the site’s existing refrigeration system.

Which cogeneration technology should be selected for an industrial site?

There is no single type of CHP unit that is right for every business. The technology should be selected according to scale, fuel, required heat parameters and operating mode.

Technology	Where it is most often worth considering	What should be checked in particular
Gas / biogas reciprocating engine	Sites with relatively stable energy demand and useful heat available as hot water, with the possibility of exhaust heat recovery	Modulation range, circuit temperatures, exhaust heat recovery, fuel quality, servicing
Gas turbine	Larger, long-running loads, particularly where hot exhaust gases and steam generation are important	Baseload, ambient conditions, exhaust-gas parameters, minimum load
Back-pressure steam turbine	Sites with a stable steam system and a pressure differential that can be used to generate electricity	Steam balance, pressure levels, process seasonality, boiler operation
Fuel cell	Specific projects requiring different operating characteristics from conventional engines	Fuel, service cost and availability, required heat parameters
Biogas-based system	Wastewater treatment plants, waste facilities and sites with their own stable gas source	Biogas quantity and composition, H2S and moisture, gas treatment, fluctuations in fuel production

Reciprocating engines are common in industry, but their popularity is not an argument for selecting a particular capacity. The CHP unit must be matched to the site’s profile, not the site to the manufacturer’s catalogue.

Steam, ORC and polygeneration — special cases

The traditional “CHP unit plus hot water” concept does not exhaust the possibilities for energy recovery. At some sites, process steam or waste heat already available from the process is the more important energy stream.

Waste-heat boiler and process steam

If the site has stable steam demand, exhaust heat from a turbine or engine can supply a suitably selected heat exchanger or waste-heat boiler. This option must be analysed using the actual steam parameters, not just the annual MWh of heat.

In larger systems, electricity, hot water and steam production can be combined and, where there is demand, cooling can be added. Such a system is sometimes referred to as polygeneration. The number of energy streams produced should not, however, be an objective in itself. Each must have a genuine consumer and a justified operating profile.

ORC and electricity from waste heat

ORC (Organic Rankine Cycle) uses an organic working fluid to convert thermal energy into mechanical work and electricity. It can be applicable where the heat source has suitable quality and continuity, including selected waste-heat processes and biomass-based systems.

This is a different design problem from sizing a gas-engine CHP unit. The heat source must first be characterised in terms of temperature, capacity, variability, number of availability hours and the impact of heat extraction on the process. Only then can ORC technology be assessed.

At many sites it is therefore worth examining conventional waste-heat recovery in parallel. Direct use of heat in the process may sometimes be simpler than an additional conversion to electricity.

Technical requirements for a cogeneration installation at a business

Capacity selection is only one part of the project. A cogeneration installation must be properly integrated into the site’s energy system.

Electrical installation and grid connection

The following must be defined:

the generator connection point;
voltage level and short-circuit power;
generator and connection-bay protection;
requirements of the distribution system operator;
metering and settlement arrangements;
the method of limiting exports, where required;
impact on power quality;
controls for parallel operation with the grid.

Requirements for power-generating modules arising from the RfG network code and operator documents depend, among other things, on the module type and the date of the connection process. Conditions from another project should therefore not be copied without checking the current requirements.

Island operation and energy security

Simply having a CHP unit does not mean that the site will continue operating during a grid outage. A typical generator operating in parallel with the grid may be disconnected by its protection systems.

If the objective is to keep the site operating, the project must from the outset address, among other things, segregation of essential loads, the power balance, island-mode controls, synchronisation, appropriate protection and — where required — black-start capability. This is a separate design scope, not a function automatically added to every cogeneration system.

Thermal installation

On the heat side, the following must be designed:

heat exchangers;
pumps and hydraulic circuits;
required flow rates;
supply and return temperatures;
coordination with boilers;
a thermal buffer, if it improves system operation;
emergency removal of surplus heat;
controls governing heat-consumer priorities.

If the heat consumer is a production process, the consequences of a CHP shutdown must also be checked. The process cannot be left without heat while the engine is undergoing maintenance.

Fuel, exhaust gases, emissions and noise

The design should address fuel supply conditions, room ventilation, exhaust-gas discharge, noise, vibration, fire protection and environmental requirements.

For fuel combustion plants with a rated thermal input of 1 MW to less than 50 MW, the rules for medium combustion plants (MCP) may apply, including emission and monitoring requirements. The MCP threshold refers to the rated thermal input of the combustion plant, not the electrical output of the generator; the classification of a specific configuration must be checked taking the applicable aggregation rules into account.

Metering and monitoring after commissioning

A well-designed system should measure at least:

fuel consumption;
electricity generation;
electricity used on site and exported to the grid;
useful heat actually supplied to consumers;
temperatures and flow rates in key circuits;
operating hours and number of starts;
fault conditions and power limitations.

Without these data, it is difficult to verify after a year whether the unit is operating as assumed. Monitoring also makes it possible to detect changes in the site’s profile and adjust the control strategy.

Formal requirements and high-efficiency cogeneration

The formal aspects should be divided into three areas: connection of the generating unit, rules governing the business activity, and any applicable support scheme.

Poland’s Energy Law distinguishes between cogeneration and high-efficiency cogeneration. For units with an installed electrical capacity of at least 1 MW, high-efficiency cogeneration generally requires primary energy savings of at least 10% compared with separate production; for units below 1 MW, Polish regulations require savings compared with separate generation.

Poland’s support scheme for high-efficiency cogeneration is still in operation, and in 2026 the Polish Energy Regulatory Office (URE) is conducting CHP auctions as well as other premium-based support procedures. A premium should not, however, be included in the financial model “automatically”. The type and capacity of the unit, the investment status, fuel and applicable support route must be verified against current Polish regulations and URE documents.

Further amendments to Poland’s Energy Law and the Act on the Promotion of Electricity from High-Efficiency Cogeneration entered into force in 2026. Among other changes, the Act of 11 June 2026 introduced specific licensing exemptions for the generation and transmission of heat supplied for industrial technological processes, as well as changes relating to the support scheme. Licensing classification and the applicable premium route should therefore be checked against the law in force on the date of the investment decision.

The same applies to licensing and grid connection. The Polish Energy Regulatory Office (URE) publishes updated information for cogeneration electricity generators, while the relevant system operator specifies the connection conditions for the particular generating unit. Formal requirements should therefore be included in the analysis before the equipment is ordered, rather than only at the installation stage.

We address the detailed financial question — when does investment in cogeneration become profitable? — separately. This article deliberately does not reduce technical sizing to a single payback period.

How to prepare a request for quotation for a cogeneration installation

The better the input data supplied to a vendor, the lower the risk that the proposed system will be sized solely against maximum demand or annual consumption.

Before sending an enquiry, it is worth preparing:

12 months of 15-minute or hourly electricity data;
an hourly heat profile or the best available process measurements;
a list of heat consumers with temperatures and operating hours;
process-steam data, where applicable;
a cooling profile, if trigeneration is being considered;
information on PV and other energy sources;
gas-connection parameters or parameters of the site’s own fuel supply;
the site’s electrical and thermal diagrams;
operating, shutdown and production-development schedules;
requirements for backup, island operation and process continuity.

On this basis, vendors should present not only nominal capacity but also the expected operating hours, electricity generation, heat production and utilisation, part-load operation, assumed shutdowns and the method of coordination with existing energy sources.

If a proposal begins with “for a site of this size we recommend a 1 MW unit”, rather than with the consumption profile and heat-demand temperature requirements, the most important sizing step is missing.

When is an industrial site a good candidate for cogeneration?

Cogeneration is particularly worth analysing when the site:

operates for many hours per year and has a stable baseload;
consumes electricity and heat at the same time;
has year-round or long-season demand for process heat;
knows the temperatures and flow rates of its heat consumers;
can use the heat without artificially increasing demand;
has suitable fuel and connection conditions;
is prepared to retain peak-load or backup heat sources;
can measure the installation’s actual operating results.

A weaker candidate is a site with very short operating hours, almost exclusively seasonal space heating, frequent long shutdowns or no heat demand for a substantial part of the year. In such a case, a smaller module, a different technology or no CHP at all may be a better decision than maximising capacity.

Cogeneration at an industrial site — where to start

The first step is not to select a manufacturer. It is to build a reliable hourly energy balance showing when the site simultaneously needs electricity and heat at suitable parameters.

Only then can cogeneration systems be compared and the case for modularity, trigeneration, steam production, ORC, coordination with PV and the overall control strategy be assessed. This approach reduces the risk of buying equipment that looks attractive in a catalogue but has nowhere to deliver its heat for a substantial part of the year.

If a business is preparing for such an investment, the analysis should be integrated with the balance of the entire energy system: existing boilers, refrigeration, PV, planned energy sources and process changes. Energy Trend can help prepare the input data, compare technical options and verify whether the proposed capacity genuinely matches the site’s operating profile.

FAQ

Should cogeneration be sized according to contracted electrical capacity?

No. Contracted capacity can be one piece of information about the site, but it does not show actual load or simultaneous heat demand. Sizing should use time-series profiles of electricity demand and useful heat demand.

Are monthly utility bills sufficient to size a CHP unit?

They are generally sufficient only for an initial screening. Monthly consumption does not show whether electricity and heat are required during the same hours. Hourly data should be used to select capacity and assess operating hours, together with available 15-minute data on the electrical side.

What should be done if the site does not need heat in summer?

First, assess a smaller unit, a shorter operating season, several modules or another genuine heat consumer. An absorption chiller makes sense only when the site actually needs cooling. A lack of heat demand alone is not a reason to build a trigeneration system.

Will a CHP unit provide power during a grid outage?

Not automatically. If CHP is intended to supply selected loads during a grid outage, the installation must be designed for the appropriate island operating mode, with suitable controls, protection and a power balance.

Can photovoltaics and cogeneration operate at the same site?

Yes, but they should be analysed on the same time axis. PV generation changes the electricity-demand profile seen by the CHP system, so its effect must be included in capacity sizing and the control strategy.

Does high catalogue efficiency mean that the cogeneration system is correctly sized?

No. Equipment efficiency describes its performance under specified conditions. For the site, it is also critical to determine what proportion of the heat produced genuinely replaces another heat source and how many hours the unit operates within a favourable load range.

Cogeneration for Industry – Applications, System Sizing and Technical Requirements