Power-to-Gas and CCUS Integration Boosts Renewable Utilization and Carbon Reduction in Integrated Energy Systems
In a groundbreaking study published in Modern Electronics Technique, researchers from Kunming University of Science and Technology have unveiled a novel approach to optimizing carbon capture, utilization, and storage (CCUS) capacity within integrated energy systems (IES) that incorporate power-to-gas (P2G) technology. The research, led by Shilong Chen and Chongxu Li, introduces a sophisticated planning model that not only enhances the economic viability of synthetic natural gas production but also significantly reduces carbon emissions by leveraging low-cost hydrogen from curtailed wind and solar power and high-purity CO₂ from thermal power plants.
The global push toward net-zero emissions has intensified the need for technologies that can effectively mitigate carbon output from fossil fuel-based energy systems. Among these, CCUS has emerged as a critical enabler, particularly in sectors where direct electrification remains challenging. However, the high costs associated with hydrogen production and CO₂ sourcing have historically limited the commercial scalability of P2G—a process that converts surplus renewable electricity into hydrogen via electrolysis, which is then combined with captured CO₂ to produce methane.
Chen and Li’s work directly addresses this bottleneck by proposing a holistic framework that integrates CCUS into a wind–thermal–hydrogen–gas coupled IES. Their model uniquely captures the temporal and spatial dynamics of renewable generation, electric vehicle (EV) charging patterns, and load profiles through advanced clustering techniques. By doing so, it preserves the intrinsic characteristics of cheap hydrogen and carbon sources even after reducing a full year of operational data into a manageable set of representative daily scenarios.
At the core of their methodology is a mixed-integer linear programming (MILP) formulation that minimizes the system’s total annualized cost—encompassing equipment investment, operational expenses, penalties for renewable curtailment, and a novel tiered carbon trading mechanism. This mechanism differentiates between “actual” CO₂ flows (physical carbon captured, stored, and utilized within the system) and “virtual” CO₂ (accounting for carbon allowances, grid electricity emissions, and market-based carbon transactions). Such a dual-layer carbon accounting system ensures that both economic incentives and genuine emission reductions are accurately reflected in the optimization process.
One of the study’s most significant insights is the critical role of CO₂ storage in decoupling hydrogen and carbon availability. The researchers found that in their modeled IES, periods of abundant wind and solar generation—ideal for low-cost hydrogen production—typically occur during off-peak hours when thermal plants are offline, resulting in minimal CO₂ emissions. Conversely, peak electricity demand coincides with high thermal generation and thus ample CO₂, but limited renewable surplus. Without intermediate CO₂ storage, the temporal mismatch would render P2G economically unfeasible. The inclusion of a CO₂ buffer tank allows captured carbon from daytime peaks to be stored and later combined with hydrogen produced overnight from curtailed wind, enabling continuous methane synthesis.
The numerical results are compelling. When the proposed CCUS configuration—comprising a 148 kg/h carbon capture unit, a 1,036 kg CO₂ storage capacity, and a 94.2 kg/h methanation reactor—was applied to a test system, it achieved a 23.5% reduction in total annual costs compared to the baseline scenario without CCUS. More impressively, actual system-wide carbon emissions dropped by 41.9%, from 5,511.5 tons to 3,201.2 tons per year. Simultaneously, wind and solar curtailment plummeted by 83.7%, demonstrating the dual benefit of emission abatement and renewable integration.
The economic gains stem from multiple synergies. First, by converting otherwise wasted renewable energy into storable methane, the system avoids curtailment penalties and creates a saleable commodity. Second, the captured CO₂—sourced internally from on-site thermal units—eliminates transportation costs and ensures high purity, reducing methanation catalyst degradation and operational complexity. Third, the tiered carbon trading scheme rewards aggressive decarbonization: as the system’s net emissions fall into lower (or even negative) tiers, it not only pays less for carbon allowances but can generate revenue by selling excess credits.
Interestingly, the study also highlights strategic energy storage choices. While lithium-ion batteries and hydrogen fuel cells are deployed for short-term, intra-day balancing—particularly during high-price evening peaks—P2G-derived methane serves as a long-duration, seasonal storage medium. Methane can be injected directly into existing natural gas infrastructure, leveraging its vast storage capacity and transport network without requiring new capital-intensive pipelines or cryogenic tanks. This hybrid storage architecture maximizes efficiency: electricity is converted to hydrogen only when surplus renewables are available, and hydrogen is converted to methane only when CO₂ is accessible, minimizing unnecessary energy conversions.
The researchers further emphasize the importance of system boundaries. Their IES model deliberately excludes district heating and complex multi-energy networks to maintain focus on the core hydrogen–carbon coupling. This simplification allows for precise characterization of gas flows—modeled in kilograms rather than volumetric units—to align with carbon trading metrics (yuan per ton). It also enables accurate tracking of oxygen flows, which play a supporting role in enhancing combustion efficiency through oxygen-enriched burning in thermal units, facilitated by an air separation unit (ASU).
From a policy perspective, the findings underscore the need for regulatory frameworks that recognize the distinction between virtual and actual emissions. The study warns that over-reliance on carbon credit mechanisms—without verifying physical carbon flows—could incentivize systems that appear low-carbon on paper but actually increase net emissions through inefficient energy conversions or imported grid electricity with high embedded carbon. Chen and Li advocate for “real carbon accounting” in future CCUS incentives to ensure environmental integrity.
Looking ahead, the authors identify several avenues for extension. Integrating thermal energy flows—especially in cold climates where P2G’s exothermic methanation reaction can supply district heating—could further improve system efficiency. Additionally, scaling the model to larger electric–gas–thermal distribution networks may unlock economies of scale in CCUS equipment procurement, though it would introduce new challenges in coordinating geographically dispersed carbon sources and hydrogen sinks.
The implications for the automotive and energy sectors are profound. As heavy-duty transport and industrial processes seek alternatives to diesel and coal, renewable methane produced via this optimized CCUS-P2G pathway offers a drop-in fuel compatible with existing engines and infrastructure. Moreover, the ability to store summer solar surpluses as winter gas reserves addresses a key limitation of battery-only systems in seasonal energy shifting.
In conclusion, Chen and Li’s work represents a significant leap toward practical, economically sustainable carbon-neutral energy systems. By marrying advanced data-driven scenario reduction with rigorous multi-energy flow modeling and realistic market mechanisms, they have charted a viable path for CCUS to move from a costly compliance measure to a profit-generating asset. Their model not only advances academic understanding but provides actionable insights for grid operators, policymakers, and clean energy investors navigating the complex transition to a net-zero future.
Authors: Shilong Chen and Chongxu Li, Kunming University of Science and Technology
Published in: Modern Electronics Technique, Vol. 47, No. 6, March 15, 2024
DOI: 10.16652/j.issn.1004-373x.2024.06.018