Hydrogen and Waste Heat Could Help Industrial Parks Cut Costs and Carbon Emissions

The research explores how coordinated scheduling of electricity, hydrogen and heat could reduce operating costs and carbon emissions in an energy-intensive industrial setting.

Wind turbines can generate more electricity than factories need at certain hours, leaving clean power unused in industrial parks that still face expensive energy bills and heavy heating demands. Hydrogen storage and heat recovery can connect those needs, giving surplus renewable electricity a useful role beyond the moment it is produced.

Fengkun Ji and colleagues examined this approach in "Optimizing Industrial Park Power–Hydrogen–Thermal Systems for Low-Carbon Economy: Accounting for Nonlinear Polarization and Waste-Heat Utilization," published in the journal Processes. The research explores how coordinated scheduling of electricity, hydrogen and heat could reduce operating costs and carbon emissions in an energy-intensive industrial setting.

The team simulated a representative summer day at a chemical industrial park in Xinjiang, China, comparing five operating arrangements. The findings describe what happened under the model's assumptions, with the strongest performance coming from a system that accounted for changing equipment efficiency and recovered heat from fuel cells.

Giving surplus electricity a second life

Surplus electricity powers proton exchange membrane electrolyzers, which split water to produce hydrogen for storage. Fuel cells convert stored hydrogen into electricity when needed, producing recoverable heat that contributes to the park's heating supply. Batteries support shorter shifts in electricity use, and a natural-gas boiler supplies the remaining heating demand.

The modeled park included 130 megawatts of wind power, 50 megawatts of solar capacity, an 80-megawatt electrolyzer and a 10-megawatt fuel cell. Its battery could store 100 megawatt-hours, and its hydrogen storage capacity was approximately 20,000 kilograms. During surplus nighttime wind generation, hydrogen production absorbed spare electricity; fuel-cell generation helped reduce purchases during expensive hours. Daytime shortages still required grid electricity and battery discharge, making coordinated timing essential to the system's operation.

Why equipment efficiency changes the calculation

Electrolyzers and fuel cells do not convert energy at a fixed efficiency across every operating level. Their electrical losses change with load, a behavior associated with electrochemical polarization. The researchers used simplified nonlinear models to represent these variations in hourly scheduling, allowing the optimizer to account for how much hydrogen or electricity equipment could actually produce under its assumed operating conditions.

The five comparisons covered a battery-based system without hydrogen, hydrogen storage with fixed efficiencies, fixed-efficiency hydrogen with heat recovery, hydrogen with changing efficiencies but no recovered heat, and the complete proposed arrangement. This separated the contributions of equipment modeling and heat utilization. Average operating efficiencies in the nonlinear cases were 50.37% for the electrolyzer and 49.51% for the fuel cell; the extra benefit from adding heat recovery came from using thermal energy.

An improved NSGA-II optimization algorithm searched for schedules balancing cost and emissions, with fuzzy-set scoring selecting a compromise from the available options.

Large savings, full renewable use and a heating limit

Daily operating costs fell from CNY 378,300 in the hydrogen-free baseline to approximately CNY 69,800 in the selected schedule, a reduction of 81.5%. Operational carbon emissions dropped from 651.81 to 160.77 tonnes of carbon dioxide, or 75.3%. These costs included electricity transactions, gas, equipment operation and maintenance, and penalties for unused renewable generation; they excluded upfront construction costs.

Conventional hydrogen storage reduced daily emissions to 240.08 tonnes, with heat recovery bringing them to 219.68 tonnes. Accounting for changing efficiencies without heat recovery produced 198.07 tonnes and CNY 83,600 in daily costs. The complete arrangement cut costs and emissions by a further 26.5% and 26.8%, respectively, compared with fixed-efficiency hydrogen plus heat recovery.

The selected schedule accommodated all available wind and solar electricity over the modeled 24 hours, achieving zero curtailment and a reported overall system energy efficiency of 78.79%. Recovered fuel-cell heat supplied 25.23% of daily heating demand. Its contribution reached 67.6% at 04:00, when heating needs were low, but daytime demand outpaced available recovered heat because fuel-cell operation followed electricity needs and its capacity was limited. The boiler supplied the shortfall, reaching approximately 23 megawatts of thermal output.

The cheapest schedule cost about CNY 64,900 daily but emitted 289.65 tonnes, reflecting greater use of carbon-intensive grid electricity. The lowest-emission option produced 116.11 tonnes at roughly CNY 75,400. Across ten independent optimization runs, selected emissions ranged from 136.12 to 230.85 tonnes, showing that the headline result represents one selected compromise. Grid electricity still accounted for about 56% of that schedule's operational emissions.

Stronger investment returns depend on practical details

A separate 20-year financial assessment raised the modeled renewable project's internal rate of return, a measure of investment performance, from 5.8% to 8.3% and shortened its simple payback period from 12.5 to nine years. Assumed investment increased from CNY 30 million to CNY 45 million for the retrofit. At an 8% discount rate, the discounted value of future cash flows exceeded investment by CNY 898,000, giving a positive net present value. These estimates used broad project assumptions rather than detailed equipment costs, replacement schedules or salvage values.

In a separate carbon-pricing test, increasing the carbon price from CNY 300 to CNY 1,882.5 per tonne reduced daily emissions from 271 to 160 tonnes, with daily costs reaching CNY 302,000. These results came from a different cost calculation that included carbon trading. A further illustration suggested cheaper hydrogen equipment could encourage greater use, but that relationship was an assumed sensitivity trend rather than a result generated by the daily scheduling model.

The operating study used predetermined hourly profiles for one summer day, rather than raw field measurements, and the equipment models were not independently checked against experimental or manufacturer curves. Emissions accounting used a fixed grid-emissions factor and covered purchased electricity and gas combustion, excluding equipment manufacturing and disposal. Thermal storage and external hydrogen sales were inactive in the tested scenarios, so neither contributed to the reported savings.

Recovered heat was matched to total heating energy, without verifying whether its temperature could satisfy individual industrial processes. The findings point to opportunities for coordinated hydrogen storage and heat recovery, with factory adoption requiring equipment calibration, process-temperature checks and analysis across a wider range of operating conditions.