The study modeled an integrated Kuwaiti refinery-petrochemical complex using Honeywell UniSIM process simulation and previously developed membrane models. It examined two options: using recovered hydrogen and captured carbon dioxide to increase urea output, or using recovered hydrogen to replace part of the hydrogen generated by steam methane reforming while maintaining existing urea capacity.

For the first option, a polysulfone membrane purified tail gas from an atmosphere residue desulfurization unit. The simulated process recovered 665 kmol/h of hydrogen at 98 mol% purity and 99% recovery. After compression to 160 bar, the hydrogen could support production of an additional 212 metric tons of urea per day, equivalent to 30% of the plant’s original capacity.

The same option required a multistage membrane system to capture carbon dioxide from reformer flue gas. Three membrane stages were modeled to raise carbon dioxide purity from 8.4% to a target of 94 mol%. The process could recover enough carbon dioxide for the additional urea and was estimated to reduce direct carbon dioxide emissions by 34%.

However, the study estimated that electricity required by the membrane compressors would generate additional carbon dioxide at the nearby gas-fired power station. Accounting for those emissions lowered the net reduction to 10%. The combined hydrogen-recovery and carbon-capture configuration was estimated to require $30.8 million in capital expenditure and $4.6 million in annual operating expenditure, with an expected payback period of about three years, including a possible urea-plant upgrade.

The second option used the purified refinery hydrogen to replace some steam-methane-reforming hydrogen without capturing flue-gas carbon dioxide or increasing urea output. The simulation predicted that SMR hydrogen production would fall from about 1,722 to 1,057 kmol/h and reformer carbon dioxide production would decline from 430 to 265 kmol/h.

For this fixed-capacity configuration, direct carbon dioxide emissions were estimated to fall by 39%. Including carbon dioxide attributed to electricity use for the hydrogen compressor, the model estimated a net reduction of 35%. The membrane system was assigned capital expenditure of $4.5 million and annual operating expenditure of $754,000, with an estimated payback period of approximately six months and only minor process modification.

The hydrogen-recovery estimate was $0.092 per kilogram under a 20-year plant-life assumption with no interest rate. Applying a 7% interest rate increased the estimate to $0.111 per kilogram, while the authors reported that the solution’s savings changed by only 2%. The calculations also assumed an industrial electricity tariff of $0.032 per kilowatt-hour and excluded installation, insurance, site preparation and labor costs.

These findings are modeled technical and economic estimates rather than results from an operating demonstration. The analysis was based on one petrochemical plant and its simulation inputs, and the proposed membrane systems were not reported as having been tested at industrial scale.

Subject of Research: Simulation and economic assessment of refinery-hydrogen recycling for carbon dioxide reduction in a urea plant

Article Title: Innovative solutions for CO 2 utilization and reduction in urea plant

Article References: Alqaheem, Y., Alobaid, M., Alkandari, S., Alsuwaileh, F., Almutawa, A., & Nayefeh, L. (2026). Innovative solutions for CO2 utilization and reduction in urea plant. Results in Engineering, 32, Article 113634. https://doi.org/10.1016/j.rineng.2026.113634

Image Credits: AI Generated

DOI: 10.1016/j.rineng.2026.113634

Keywords: process simulation, carbon dioxide capture, hydrogen recovery, urea production, membrane separation, refinery integration, steam methane reforming, economic assessment, Kuwait, Innovative, solutions, utilization