Exhaust Heat Recovery from Upstream Power Generation: A Steam Cogeneration and Process-Heating Strategy with Economic Benchmarking

Abstract

Upstream oil and gas facilities often generate their own electricity with simple-cycle gas turbine generators (GTGs), even though the same facilities also need substantial high-temperature process heat. This creates a practical opportunity to use the exhaust more effectively, but only if the heat already recovered by the plant is accounted for correctly. In this study, we develop a first-principles engineering and techno-economic framework for sharing a finite exhaust-temperature profile among an existing thermal-oil waste-heat recovery unit (WHRU), a modular exhaust-gas boiler (EGB), a back-pressure steam turbine (BPST), and process-steam users. The reference facility has four Solar Titan 250 generator sets, of which three normally operate and one is held on standby. Each operating train delivers 245,660 kg/h of exhaust at a steady-state design temperature of 465°C. Field T7 readings of 547-587°C are treated as short-duration thermal-exposure conditions rather than annual design points. We also examine measured full-load data from a medium- speed diesel generator (4.17 MWe, 200.7 g/kWh BSFC, exhaust-manifold temperatures of 497°C and 469°C, and a stack temperature of 327.8°C) as a secondary transferability case. Because verified exhaust mass flow and dispatch data were unavailable, the diesel unit is not credited in the base steam or economic model. The analysis combines IAPWS-97 water and steam properties, section-by-section LMTD sizing, real isentropic turbine expansion, stack-temperature, pinch-point, GT-load and steam-pressure sensitivities, a concise exergy balance, preliminary mechanical sizing, and a Python discounted-cash-flow model. In the base case, each EGB transfers 10.25 MW and produces 14.86 t/h of steam. Across three trains, the system supplies 44.6 t/h of 20 barg steam, 2.08 MWe of net BPST power, and 26.3 MW of process heat at 4 barg, covering about 73% of the documented 36 MW thermal-oil duty. The exergy results show that useful heat remains the main recovered product, while exchanger irreversibility and unrecovered temperature potential are larger than the electrical output. Lower stack temperatures and smaller pinch points increase steam production, but they also drive up surface area and pressure-loss risk; HP steam pressure has much less influence on total useful output. Preliminary sizing indicates about 1,117 m2 of finned-tube surface and 8.27 m2 of free gas-flow area per train, together with a full-capacity fail-open bypass, independent supports, expansion joints, and clean/fouled pressure-drop guarantees. Although technically feasible, the 20-year base case is not economically attractive (NPV = USD -14.3 million). The result illustrates a central retrofit lesson: the configuration that recovers the most useful energy is not automatically the one that creates the most value.