Deploying green hydrogen to decarbonize China's coal chemical sector

Coal is a dominant fuel and feedstock in China, and the coal chemical sector is expanding as the share of coal used for power declines with renewable integration. Process CO₂ from coal gasification and water-gas shift reactions makes the sector hard to decarbonize through electrification alone. Few studies have examined decarbonization pathways for coal chemicals, and the greenhouse gas (GHG) mitigation potential and costs of deploying onsite green hydrogen (H₂) remain underexplored. This study assesses whether onsite renewables-based H₂ and O₂ production via electrolysis, colocated with coal chemical plants, can displace coal-based H₂ and air-separation O₂ to substantially reduce lifecycle GHG emissions at reasonable cost. The work is important because the sector accounted for ~9% of China’s national GHG emissions in 2020, is projected to grow, and is a large consumer of H₂, positioning it as a promising anchor demand for scaling green H₂.

Prior research on decarbonizing China’s coal chemical sector has focused on product structure adjustments, efficiency improvements, hybrid energy systems, and CCUS, with limited attention to the role of onsite green H₂. A proposed hybrid power system combining coal, natural gas, biomass, renewables, and nuclear has been suggested to produce electrolytic H₂ for coal chemical processes. However, comprehensive analyses quantifying lifecycle GHG mitigation potential and costs of onsite electrolytic H₂ and O₂ replacing water-gas shift H₂ and air-separation O₂ within coal chemical plants have been lacking. Policy context in China increasingly emphasizes green H₂ deployment and low-carbon development pathways for coal chemicals, and pilot utility-scale PV-to-H₂ projects for coal-to-olefin are underway (e.g., Ningxia).

The study integrates techno-economic analysis (TEA) with life-cycle assessment (LCA) under a broad system boundary (onsite chemical reactions and combustion; upstream coal mining and processing; grid electricity; outsourced heat; manufacturing of electrolyzers, batteries, solar panels/wind turbines; and H₂ leakage). Baseline GHG emissions are estimated for 2020 and projected for 2030. Four 2030 scenarios are evaluated: (1) Moderate-renewables Grid (MG) — electrolytic H₂/O₂ via a 2030 grid with moderate renewables penetration; (2) High-renewables Grid (HG) — electrolytic H₂/O₂ via a higher-renewables 2030 grid; (3) Onsite Solar Electricity (SE) — onsite solar electricity for electrolysis and to replace grid electricity for other operations; (4) Onsite Wind Electricity (WE) — analogous with wind. The 2030 baseline retains coal-based H₂ (gasification + water-gas shift) and coal-driven air separation for O₂, with a moderately decarbonized grid for other plant electricity. Provincial production of coal chemicals (coke, calcium carbide, ammonia, methanol, oil by direct/indirect liquefaction, synthetic natural gas, olefin, ethylene glycol) is compiled for 2020 and projected to 2030 (traditional products by downstream demand, modern projects by project pipeline expected online by 2030). LCA emission factors are compiled for onsite reactions/combustion and upstream processes; 2030 grid mixes are used to derive grid lifecycle intensities. Provincial solar/wind capacity factors determine lifetime generation, costs, and GHG intensities of onsite renewables. Battery storage (four-hour discharge) is included to firm intermittent renewables for continuous H₂/O₂ production; H₂ leakage (GWP100=11) is included. Emissions and costs for electrolyzer and battery manufacturing are accounted for; attribution of upstream impacts to provinces is based on production of coal, thermal power, solar panel manufacturing locations, and wind turbine deployment sites. Cost analysis (in 2020 CNY, using 2030 price assumptions) quantifies changes in coal feedstock and fuel costs, electricity costs (electrolysis and other operations), and capital/operating costs for electrolyzers, renewables, and batteries; uncertainty ranges reflect energy/equipment price ranges and discount rates. Optimization across provinces assigns each to solar or wind electrolysis to identify a maximum national mitigation solution and a minimum national cost solution.

• 2020 emissions: China’s coal chemical sector emitted 1.12 (1.07–1.17) GtCO₂eq (~9% of national total). Shares: onsite chemical reactions 43% (water-gas shift alone 33%), onsite fuel combustion 21%, upstream processes 36% (grid electricity, heat, coal mining/processing). Traditional products (coke, calcium carbide, ammonia, methanol) comprised 79% of emissions.
• 2030 baseline: 1.26 (1.19–1.33) GtCO₂eq (+12% vs 2020). Modern coal chemicals grow rapidly (+113% production; +93% related emissions), while traditional products slightly decline (−14% production; −9% emissions).
• Scenario results (relative to 2030 baseline): • MG (grid electrolysis, moderate-RE grid): +33% emissions (+416 MtCO₂eq). • HG (grid electrolysis, high-RE grid): +12% emissions (+151 MtCO₂eq). • SE (onsite solar): −53% emissions (−664 MtCO₂eq). • WE (onsite wind): −55% emissions (−694 MtCO₂eq). Conclusion: Grid-based electrolysis in 2030 is not low-carbon for this sector; onsite renewables-based electrolysis is highly effective.
• Decomposition of changes: All alternative scenarios avoid water-gas shift, reducing onsite reaction emissions by 482 MtCO₂eq; onsite fuel combustion falls by 69 MtCO₂eq (−39 from replacing air-separation O₂; −30 from reduced gasification for CO). Upstream coal mining/processing decreases by 78 MtCO₂eq in all alternatives. Upstream grid emissions change by −28 (HG), −116 (SE), and −119 (WE) MtCO₂eq due to cleaner electricity for non-electrolysis operations. Electrolysis increases upstream electricity emissions: approximately +1000 MtCO₂eq (MG) and +800 MtCO₂eq (HG); onsite renewable electrolysis adds +65 (SE) and +38 (WE) MtCO₂eq. Manufacturing adds limited emissions: electrolyzers ~2.7 MtCO₂eq (all alternatives), batteries ~6.4 MtCO₂eq (SE/WE). H₂ leakage contributes ~7.5 MtCO₂eq.
• Capacities and land: ~330 GW electrolyzers required (all alternatives) and ~320 GW four-hour battery storage (SE/WE). SE requires ~1.1 TW solar, ~2.0 PWh generation, ~26,000 km² land; WE requires ~0.96 TW wind, ~2.0 PWh generation, ~70,000 km² land. Land availability is concentrated in less-populated Northwestern provinces.
• Carbon intensity reductions (SE/WE): For most coal chemicals, −35% to −85% vs baseline (coke only −5%). Onsite fuel combustion intensities drop 14–44% due to avoided air separation and reduced gasification. Upstream intensities fall due to renewable electricity and reduced coal mining/processing. WE slightly outperforms SE (wind ~20 kgCO₂eq/MWh vs solar ~36 kgCO₂eq/MWh).
• Provincial mitigation: Largest absolute reductions in Inner Mongolia (−140 MtCO₂eq), Xinjiang (−75), and Shaanxi (~−70) under SE/WE. Some provinces see slight increases under SE due to PV panel manufacturing emissions (e.g., Jiangsu, Zhejiang, Jiangxi).
• Costs (relative to baseline, 2030 prices; annual): • Coal for feedstocks: −267 bn CNY; coal for fuels: −23 bn CNY. • Electrolyzers: +120 bn CNY; batteries: +87 bn CNY. • Electricity for electrolysis: +193 bn CNY (SE) / +282 bn CNY (WE). • Electricity for other operations: −103 bn CNY (SE) / −92 bn CNY (WE). • Net cost: +6.4 bn CNY (SE; 10 CNY/tCO₂eq; −120 to 127 CNY/t range) and +106 bn CNY (WE; 153 CNY/tCO₂eq; 30 to 265 CNY/t range). • Relative to total sector costs: SE ~0.6% increase; WE ~9% increase. SE generally yields more cost-competitive products than WE because onsite solar power (avg 109 CNY/MWh) is cheaper than wind (155 CNY/MWh) and far below grid (580 CNY/MWh).
• Optimization across provinces: • Maximum mitigation solution: ~57% reduction (~722 MtCO₂eq) at +26 bn CNY total (~36 CNY/tCO₂eq), with 17 provinces choosing solar and 12 wind. • Minimum cost solution: ~53% reduction (~665 MtCO₂eq) at +6.3 bn CNY total (~9.4 CNY/tCO₂eq), with 26 provinces choosing solar and 3 wind. • Inner Mongolia, Shaanxi, Ningxia, and Xinjiang deliver ~52% of total mitigation with net cost reductions.
• Additional opportunities: Selling excess green O₂ (∼185 Mt at ~360 CNY/t) could yield ~67 bn CNY revenue and ~50 MtCO₂eq additional mitigation, further improving economics (not included in main cost results).

The analysis shows that replacing coal-based H₂ (from gasification and water-gas shift) and air-separation O₂ with onsite renewables-based electrolysis substantially decarbonizes coal chemical production, whereas grid-powered electrolysis in 2030 increases emissions and costs. Onsite solar and wind provide continuous, low-carbon H₂ and O₂ (buffered by batteries), cutting process and combustion emissions and upstream coal-related emissions. Provincial optimization indicates that most regions minimize costs with solar, while select regions benefit more from wind; abundant resource provinces (Inner Mongolia, Shaanxi, Ningxia, Xinjiang) achieve large, low-cost mitigation and are prime candidates for pilots. The sector’s role as China’s largest H₂ producer/consumer creates a synergistic opportunity to scale green H₂, drive down costs, and meet climate goals. Policymakers can leverage carbon markets to offset modest cost increases (e.g., carbon price ~50 CNY/tCO₂ in 2021 exceeds the ~9.4 CNY/tCO₂eq cost of the minimum-cost pathway) and should consider enabling revenue from excess O₂. Co-benefits include reduced air pollutant emissions and associated health gains. Land availability near plants is sufficient, and early pilots in Ningxia and Inner Mongolia demonstrate feasibility. Overall, onsite renewable electrolysis is an effective, near-term decarbonization lever for a hard-to-abate sector.

Onsite deployment of green H₂ and O₂ in China’s coal chemical sector can reduce approximately half of 2030 baseline GHG emissions at low net cost, outperforming grid-based electrolysis. Choosing the lowest-cost renewable option (solar or wind) by province yields ~53% national mitigation at ~9.4 CNY/tCO₂eq (minimum-cost solution), with Inner Mongolia, Shaanxi, Ningxia, and Xinjiang contributing over half of mitigation while achieving net cost reductions. Selling excess green O₂ can further improve economics and mitigation. Inclusion of the coal chemical sector in China’s carbon market can offset remaining cost impacts. Future work will use plant-level operational data to quantify additional environmental co-benefits (air quality, freshwater conservation) and assess replacing captive coal power with onsite renewable electricity plus storage as high-temperature heat electrification scales.

The modeling uses annual average parameters at provincial resolution rather than plant-level or sub-annual operational profiles, potentially understating operational variability and integration challenges. Projections for 2030 production, costs, and grid mixes are uncertain and based on literature scenarios. The analysis retains onsite coal power for high-temperature heat and non-electrolysis operations through 2035, so full decarbonization is not addressed. Residual process emissions from coke and calcium carbide remain substantial and likely require CCUS. Manufacturing emissions and supply-chain attributions (e.g., PV panels, wind turbines, electrolyzers, batteries) rely on current data and assumptions about provincial allocation. Excess O₂ sale benefits are not included in main mitigation and cost results. H₂ storage and transport are minimized by design (onsite production), and battery storage is assumed to firm renewable electricity for continuous electrolysis (four-hour discharge), which may differ by site.