隨著全球淨零排放目標與碳管理政策逐步推動，氫能被視為能源轉型與工業減碳之重要選項。然而，目前全球氫氣供應仍以化石燃料製成之灰氫為主，伴隨大量二氧化碳排放。相較於綠氫，藍氫可利用既有甲烷蒸氣重組製氫基礎，並結合碳捕集與封存技術降低碳排放，因此被視為短中期具可行性之低碳氫能路徑。臺灣受限於再生能源發展條件與能源進口依賴，短期內全面導入綠氫仍具挑戰，因此有必要針對藍氫生產成本與減碳效益進行在地化評估。本研究以臺灣藍氫生產為研究對象，建立甲烷蒸氣重組結合不同碳捕集路徑之技術經濟分析模型，並導入臺灣天然氣價格、電價、水費、運輸與封存成本及六輕臺塑石化二廠第三套氫氣單元(HYD#3)實際產能等參數。研究比較合成氣捕集、變壓吸附尾氣捕集與煙道氣捕集三種二氧化碳捕集路徑，並透過氫氣平準化成本、敏感度分析、極端情境分析、蒙地卡羅模擬及二氧化碳避免成本，評估不同捕集路徑之成本與減碳經濟效益。
研究結果顯示，在2025年基準情境下，合成氣捕集之氫氣平準化成本為68.21臺幣/kg-H₂，為三種路徑中最低；變壓吸附尾氣捕集為71.48臺幣/kg-H₂，略高於合成氣捕集；煙道氣捕集則為80.19臺幣/kg-H₂，為三者中最高。二氧化碳避免成本方面，合成氣捕集、變壓吸附尾氣捕集與煙道氣捕集分別為1,354、2,103與2,319臺幣/t-CO₂，顯示合成氣捕集在單位減碳成本上最具經濟效率。敏感度分析與極端情境分析結果顯示，天然氣價格為影響藍氫成本之最關鍵因素；蒙地卡羅模擬結果亦顯示，在納入天然氣價格、電價及運輸與封存成本等不確定參數後，三種捕集路徑之成本排序仍與基準情境一致。整體而言，合成氣捕集在成本與單位減碳效益上最具優勢，變壓吸附尾氣捕集具既有製程改造彈性，煙道氣捕集則較適合以高捕集率為優先目標之情境。若臺灣欲推動藍氫產業發展，應搭配碳價調整、資本補助、營運補貼、天然氣價格風險管理及CO₂運輸與封存基礎設施建置，以提升藍氫投資可行性，本研究結果可作為臺灣未來藍氫政策規劃與產業減碳策略之參考。

Hydrogen is an important option for the transition toward low-carbon energy systems and industrial decarbonization. However, the global hydrogen market remains dominated by gray hydrogen, which is produced from fossil fuels without carbon capture and therefore generates substantial carbon dioxide emissions. Green hydrogen, produced through electrolysis using renewable electricity is the ideal zero-carbon solution; however, Taiwan’s limited renewable energy capacity and heavy dependence on imported energy make large-scale deployment infeasible in the short term. Blue hydrogen, which combines fossil-based hydrogen production with carbon capture and storage, may serve as a transitional pathway by adapting Taiwan’s existing steam methane reforming infrastructure. This study assessed the production costs and carbon-reduction potential of blue hydrogen under conditions specific to Taiwan.
This study established a techno-economic analysis model for steam methane reforming in conjunction with various carbon capture pathways, including syngas capture, pressure swing adsorption (PSA) tail-gas capture, and flue gas capture. The main analysis parameters were the prices of natural gas, electricity, and water along with storage costs and the actual production capacity of a real-world hydrogen production facility (Hydrogen unit 3 (HYD#3), Formosa Petrochemical Corporation, Mailiao Refinery). The research methods included levelized cost of hydrogen, sensitivity analysis, extreme scenario analysis, Monte Carlo simulation, and carbon dioxide avoidance cost analysis.
Our findings revealed significant differences in cost performance among the three capture pathways. Under the 2025 baseline scenario, the levelized cost of hydrogen was as follows: syngas capture (68.21 TWD/kg-H₂), PSA tail-gas capture (71.48 TWD/kg-H₂) and flue gas capture (80.19 TWD/kg-H₂). The carbon dioxide avoidance costs were as follows: syngas capture (1,354 TWD/t-CO₂), PSA tail-gas capture (2,103 TWD/t-CO₂), and flue gas capture (2,319 TWD/t-CO₂).
Sensitivity and extreme scenario analyses revealed that the price of natural gas is the factor with the most pronounced effect on the cost of blue hydrogen. In Monte Carlo simulations, the inclusion of uncertainties in the costs of natural gas, electricity, and storage did not shift the ranking of the three capture pathways from the baseline scenario. Overall, syngas capture is the best option in terms of costs and unit carbon reduction efficiency, while PSA tail-gas capture provides flexibility for retrofitting existing processes and flue gas capture is suitable for scenarios prioritizing high capture rates. The development of a blue hydrogen industry in Taiwan will require economically viable projects. Policymakers should therefore consider carbon pricing adjustments, capital and operating subsidies, measures to manage natural gas price volatility, and investment in CO₂ transport and storage infrastructure. The findings of this study could inform the formulation of blue hydrogen policies and industrial decarbonization strategies for Taiwan.

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