(48f) Grey and Blue Hydrogen Production Costs in Hydrogen Plants: A Comparative Analysis

Global hydrogen demand has tripled since the 1970s [1], reaching 94 million tonnes in 2021, surpassing its historical maximum of 91 million tonnes in 2019 [2]. Its emergence as the fuel of the future is credited to its clean burning, long-term storage capacity, and high energy density [3]. Several pathways exist for hydrogen production, including “black/grey hydrogen” from fossil fuels, where the generated CO₂ emissions are released to the environment, “blue hydrogen” where the produced CO₂ is captured and stored by an industrial carbon capture and storage (CCS) process, and “green hydrogen” by electrolysis using renewable energy [4]. To date, most of the hydrogen produced is by natural gas (NG) reforming, accounting for over 75% of the annual global hydrogen production [1]. There are three main routes for hydrogen production from NG: steam methane reforming (SMR), auto-thermal reforming (ATR), and partial oxidation (POX). These processes are associated with significant amounts of CO₂, ranging from 7.5 [5] to 13 tons of CO₂ [6] per ton of produced hydrogen. Producing low-carbon hydrogen is key to future energy systems as it can play a major role in the clean energy transition. Current methods being explored for low-carbon hydrogen generation include blue hydrogen from natural gas, and electrolysis [7], with blue-hydrogen being the most promising short-term solution for CO₂ mitigation from hydrogen processes [8].

Numerous studies in the literature have focused on the techno-economic analysis of blue-hydrogen production by SMR, with very limited analyses on ATR and POX. The literature is lacking a detailed integration, analysis and comparison of blue hydrogen production from NG for increasing emission levels following the three prominent routes. This study addresses the aforementioned gaps by presenting a comparative techno-economic assessment on hydrogen production by SMR, ATR and POX. The hydrogen plants are assumed to be standalone, and each process is energy-integrated with CO₂ capture and compression units to obtain a relationship between hydrogen production costs and CO₂ emissions’ mitigation for a wide range of CO₂ removal rates (0-90%). Different design regimes and energy system designs are developed for heat and power integration across the hydrogen plants and CO₂ capture and compression for grey to blue hydrogen production. Impact of natural gas price and plant capacities are also investigated on the hydrogen costs. The analysis is extended to assess the impact of life-cycle emissions outside the boundary of the hydrogen plants, and the results are compared with state-of-the-art electrolysis technology. Results show that hydrogen costs are lower than those reported in the literature, highlighting the importance of energy integration on overall production costs reduction.

Acknowledgments. This work was made possible by funding from Qatar National Research Fund (QNRF) project number NPRP12S-0304-190222 and co-funding by Qatar Shell Research and Technology Center (QSRTC). The statements made herein are solely the responsibility of the author(s).

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