CHP Feasibility and Night-Time Load Collapse at a Concrete Products Factory
A ready-mix concrete and block factory in 6th of October City buys electricity at EGP 2.35/kWh and burns diesel at EGP 14.5/litre in two boilers (85% efficiency, LHV 35.8 MJ/litre) that supply process hot water. The factory runs 6,000 h/yr with an average electrical load of 900 kW and a continuous hot-water demand of 700 kW at 90 °C. A supplier offers a 1,000 kWe natural-gas CHP unit: 40% electrical efficiency on LHV, 43% of fuel input recoverable as heat, gas at EGP 6.5/m³ (36 MJ/m³), installed cost EGP 22 million, maintenance EGP 0.18/kWh generated, and 8% of generation consumed by the package itself. Grid supply suffers about 40 h/yr of summer outages. The finance director will only look at a payback under three years; the operations manager worries about running the engine when the plant load collapses at night to 450 kW, below the engine's 50% minimum stable load.
1. Compute the annual saving and simple payback, and identify the assumptions most likely to break the case.
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Current heat cost. Diesel at 14.5 EGP/L with LHV 9.94 kWh/L and 85% boiler efficiency gives 14.5/(9.94 × 0.85) ≈ EGP 1.72/kWh thermal.
CHP fuel input. 1,000/0.40 = 2,500 kW thermal = 2,500 × 3,600/36,000 = 250 m³/h of gas → 1.5 million m³/yr → EGP 9.75 million.
Electricity benefit. 6.0 million kWh generated, 92% used on site = 5.52 million kWh × 2.35 = EGP 12.97 million.
Heat benefit. 0.43 × 2,500 = 1,075 kW recovered, 700 kW usable → 4.2 million kWh thermal × 1.72 = EGP 7.22 million.
Maintenance. 0.18 × 6.0 million = EGP 1.08 million.
Net annual benefit = 12.97 + 7.22 − 9.75 − 1.08 ≈ EGP 9.36 million, giving a simple payback of about 2.35 years - inside the three-year test, but with thin margin.
What would break it: electrical efficiency at 50% load falling to about 34%, which cuts the electricity benefit and raises the unit cost; utilisation below 6,000 h; the gas tariff being indexed upward while the electricity tariff is held; only half the 700 kW heat being usable in summer, which removes about EGP 3.6 million of the benefit; and any loss of the right to run in parallel with the grid. Present it as a sensitivity table, not a single number.
2. At night the plant load falls to 450 kW, below the engine's 50% minimum stable load. What operating and commercial arrangements do you recommend?
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First establish the real constraint. Below 50% load the engine risks flame-out, wet stacking, higher emissions and accelerated maintenance, so the options are: run at 500 kW and export or dump the 50 kW surplus (requires the utility's parallel-operating approval, export metering and reverse-power protection); run at 500 kW and dump the surplus as heat through a radiator, which wastes fuel but may still beat imported power; shut the engine down and import from the grid when there is no heat demand; or add thermal storage so the engine can run at 500 kW against stored hot water and stay off during the deepest trough.
Recommendation. Sequence the engine against the electrical load with an automatic start/stop that respects the minimum load, and do not run it below 50% for extended periods. Where the surplus power cannot be exported, install an air-cooled dump radiator sized for the minimum-load surplus and accept the heat rejection loss, provided the economics still hold at night.
Commercial structuring. Consider a BOOT/ESCO or PPA arrangement with the supplier carrying the load and performance risk, with availability and efficiency guarantees and a maintenance regime tied to running hours rather than kWh. Whichever route is chosen, the night-time economics must be modelled explicitly rather than averaged over the year, and the parallel-operation agreement with the distribution company must be in place before commissioning.
3. The HSE manager asks you to address gas safety, emissions and the 40 hours a year of grid outage. What do you require in the design and operating documentation?
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Gas safety. A gas train with double block and bleed, strainer, pressure regulation, slam-shut valve and a gas detection system interlocked to the isolation valve; detectors at high level for methane and at low level in pits and trenches; hazardous-area classification with ATEX-rated equipment and ventilation giving at least 12 air changes an hour in the package room; a fire and gas cause-and-effect matrix; and a permit-to-work regime for hot work near the gas train.
Exhaust and emissions. Flue termination above roof level, clear of windows and the packaging hall intake, with a dispersion check against NOx limits; silencer on the exhaust and acoustic treatment so the boundary noise limit is met; documented emission testing at commissioning and annually.
Outage plan. 40 hours a year of grid loss does not justify black-start capability alone, but it does justify defining the critical loads - control room, water treatment, lighting, curing - and covering them, either by islanding the CHP (with the utility's agreement and a proven island-mode sequence) or by a dedicated standby generator with automatic transfer. The CHP should be designed to trip safely and restart unattended without losing the hot-water supply to curing, and the plant should hold a documented emergency response plan, spill/leak drill and first-aid provision for gas exposure.