The research, led by Kui Chen with colleagues including Xiaoying Zheng, Huai Gao, and Guangning Wu, centers on a multi-physics coupled model that links three intertwined processes inside a single lithium-ion cell: the electrochemical reactions that store and release charge, the thermal behavior that governs how heat is generated and distributed, and the growth of the solid electrolyte interphase, or SEI, a thin film on the graphite anode that thickens over a battery’s life and consumes cyclable lithium. By coupling these domains, the model can simulate not just how a cell performs on a given cycle, but how each cycle quietly reshapes the cell’s internal chemistry and future performance.

The SEI film deserves particular attention because it sits at the heart of battery aging. Formed during the first charge cycles when the electrolyte decomposes at the anode surface, the SEI is nominally protective, passivating the anode against further reaction. But it is never perfectly stable. Each cycle, and especially each cycle run hot or at high current, adds new layers of decomposition products, and every increment of film growth permanently removes lithium ions from circulation. The result is a slow, irreversible loss of capacity that engineers call calendar and cycle aging. The Chinese team’s model treats this growth explicitly rather than as an afterthought, allowing them to track how aging and heating feed back into one another.

The team’s simulations compared cells cycled at different C-rates, a measure of how quickly a battery is charged or discharged relative to its capacity. A 1 C rate means a full discharge in one hour; 4 C means the same energy is extracted in fifteen minutes, a regime closer to what a locomotive experiences during hard acceleration or regenerative braking recovery. The results were unambiguous. Higher discharge rates accelerated the decline of cell voltage, shortened the usable discharge duration, and promoted capacity loss. After 1000 simulated cycles, the state of health, a standard metric expressing remaining capacity as a fraction of the original, stood at 0.902 for cells cycled at 1 C, 0.899 at 2 C, and 0.896 at 4 C.

Those capacity differences may look modest, but the thermal consequences of fast cycling are anything but. At a 4 C discharge, the model showed the temperature-rise rate was approximately 2.29 times that observed at 1 C. Heat generation in a lithium-ion cell scales steeply with current because both ohmic losses and polarization losses grow as charge is pushed through the cell faster. In a compact traction pack, that heat must be removed quickly or it accumulates, and accumulated heat does more than threaten safety: it accelerates the very aging processes that erode capacity, creating a feedback loop in which hard use makes the battery both hotter and weaker.

The SEI growth data made that feedback vivid. Under 4 C cycling, the increment in SEI film thickness was approximately 2.23 times that at 0.5 C and 1.78 times that at 1 C. In other words, pushing a cell four times harder did not merely quadruple the wear proportionally; it compounded the chemical damage, thickening the interphase far faster than gentle cycling. Every micron of extra SEI represents lithium locked away from useful work, and the model’s ability to resolve this growth cycle by cycle gives engineers a way to predict where on a duty profile a locomotive battery pays the highest aging price.

Ambient temperature emerged as an even more powerful lever on degradation. When the team cycled cells at 40 degrees Celsius, the state of health fell to 0.824 after the same 1000 cycles, and the SOH loss was approximately 2.8 times that observed under the low-temperature condition. The finding aligns with a well-established body of evidence that elevated temperatures accelerate electrolyte decomposition and SEI growth, following Arrhenius-type kinetics in which reaction rates climb exponentially with temperature. For locomotives operating through hot summers or in warm climates, the implication is that thermal management is not merely a comfort feature but a primary determinant of battery lifetime and replacement economics.

Perhaps the most novel contribution of the study is its treatment of spatial nonuniformity. A battery cell is not a point object; it is a three-dimensional structure in which the core, the surfaces, and the tabs can sit at markedly different temperatures during high-current operation. The researchers quantified this with an internal temperature nonuniformity coefficient, and under 4 C cycling the coefficient rose from 2.9 percent to approximately 5.2 percent. That means the hottest regions of the cell were aging measurably faster than the coolest, so the cell effectively contains a population of micro-environments with different degradation rates. Hot spots can seed local lithium depletion, accelerate local SEI growth, and in extreme scenarios contribute to the conditions that precede thermal runaway, the catastrophic self-heating failure mode that battery safety research works so hard to prevent.

Why does this matter for locomotives specifically? Rail traction is among the most punishing duty profiles any battery can face. A new-energy locomotive must deliver megawatt-scale bursts for acceleration, absorb regenerative braking energy, sustain long hauls, and do so across deserts, mountains, and humid subtropics, often with limited opportunity for active cooling. Unlike passenger electric vehicles, locomotives carry enormous battery packs whose replacement cost and downtime are substantial. A model that can predict how a given operating profile, climate, and cooling strategy translate into state of health over thousands of cycles is therefore a genuine engineering tool, not just an academic exercise. The authors position their work explicitly as a modeling basis for thermal management design and lifetime assessment of traction batteries.

The study also fits into a broader movement in battery science toward multi-physics and pseudo-two-dimensional electrochemical models, descendants of the classic Doyle-Fuller-Newman framework, increasingly coupled with aging submodels and, more recently, with machine learning for state estimation and remaining useful life prediction. What distinguishes the present work is its focus on the coupled thermal-aging response inside a single cell under conditions representative of rail service, and its explicit quantification of how C-rate, ambient temperature, and spatial nonuniformity interact. As electrified freight and passenger rail expand worldwide, findings like these, showing that a 4 C duty cycle heats a cell more than twice as fast as a 1 C cycle and that 40-degree operation can nearly triple capacity loss, will help engineers decide how hard a locomotive battery can safely be pushed, and how much cooling it needs to survive a working life measured in decades rather than years.

Subject of Research: Thermal response and SEI-driven aging of lithium-ion traction batteries under varying C-rates and ambient temperatures

Article Title: Thermal response and aging behavior of lithium-ion batteries for new-energy locomotives under complex operating conditions

Article References: Chen, K., Zheng, X., Gao, H., Tang, M., Wang, H., Long, Z., Wu, F., Gao, G., & Wu, G. (2026). Thermal response and aging behavior of lithium-ion batteries for new-energy locomotives under complex operating conditions. Ionics. https://doi.org/10.1007/s11581-026-07525-9

Image Credits: AI Generated

DOI: 10.1007/s11581-026-07525-9

Keywords: lithium-ion battery, battery aging, SEI film growth, thermal management, state of health, C-rate, new-energy locomotive, electrochemical-thermal model, temperature nonuniformity, capacity fade, traction battery, multi-physics modeling