In low-permeability sandstone reservoirs (LPSR), impermeable interlayers significantly challenge carbon capture, utilization, and storage (CCUS) and enhance oil recovery (CO₂-EOR) processes by creating complex, discontinuous flow units. This study aims to address these challenges through a comprehensive multi-faceted approach integrating geological and microscopic analyses, including core analysis, reservoir petrography, field emission-scanning electron microscopy (FE-SEM), energy dispersive spectroscopy (EDS), and well-logging response analysis, and utilizing three-dimensional (3D) geological modeling. The current comprehensive investigation systematically characterizes interlayer types, petrophysical properties, thickness, connectivity, and their spatial distribution in the reservoir unit. Numerical simulations were conducted to assess the sealing efficiency and the impact of various interlayer materials on CO₂ flooding over a 10-year period. Results indicate the presence of petrophysical and argillaceous interlayers, with optimal sealing occurring in petrophysical barriers ≥ 4 m and argillaceous barriers ≥ 1.5 m thick. CO₂ leakage occurs through preferential pathways that emerge in a side-to-middle and bottom-to-top direction in interbeds, with multidirectional pathways showing greater leakage at the bottom compared to the upper side within barriers. Increased interlayer thickness constraints CO₂ breakthrough but reduces vertical flooding area and production ratio compared to homogeneous reservoirs. Augmented interbed thickness and area mitigate CO₂ breakthrough time while constraining gravity override and dispersion effects, enhancing horizontal oil displacement. These novel findings provide crucial insights for optimizing CCUS-EOR strategies in LPSR, offering a robust theoretical foundation for future applications and serving as a key reference for CO₂ utilization in challenging geological settings of LPSR worldwide.

Carbon asset management has become an important way to reduce carbon costs. There are three main carbon asset management modes, including carbon quota compliance, carbon asset autonomous management, and custody. A key challenge faced by capital-constrained enterprises is how to scientifically select a carbon asset management mode based on actual needs. This paper considers the impacts of setup costs of carbon asset management departments, carbon asset appreciation, custody costs, and revenue sharing, maximizes the enterprises’ profits, develops optimization models for three modes, and provides the optimal low-carbon production strategies. This paper provides evidence for enterprises to choose optimal modes under different capital levels and carbon emissions by comparing modes. The conclusions are as follows. When setup costs are low, the carbon asset autonomous management mode is suggested for the optimal profit. With higher setup costs, either carbon asset compliance or custody mode is recommended. Under abundant capital, the carbon asset custody mode is suggested. Given a certain amount of capital and low setup costs, high-emission enterprises are encouraged to adopt the carbon asset autonomous management mode for a win–win of profits and carbon emissions. The carbon asset custody and compliance modes are suggested for medium-emission and low-emission enterprises, respectively.

Rapid reservoir-energy depletion and a low primary recovery factor constrain shale oil development in the Qintong Depression. This study proposes a hybrid CO₂ injection method that combines continuous flooding with cyclic huff-n-puff. Coreflooding experiments with online nuclear magnetic resonance monitoring and compositional numerical simulations were used to identify the recovery mechanisms and optimize the operating parameters for the Luye-1 well block. The core experiment demonstrated the incremental recovery and compositional evolution occurring when cyclic huff-n-puff was applied after continuous CO₂ flooding. Separately, the numerical simulations indicated that the hybrid strategy provided a larger CO₂-contact area and a longer residence time than the individual injection strategies under the modeled conditions. The experiments also showed the sustained recovery of heavier hydrocarbons during successive cycles. A differentiated fracture-network design reduced inter-well gas channeling while maintaining reservoir contact. The selected engineering strategy comprised two asynchronous huff-n-puff cycles followed by hybrid injection, with a flooding-well injection rate of 80 t/d, a cyclic CO₂ injection volume of 7000 t per huff-n-puff well, and a soaking time of 60 days. Under the evaluated model scenario, the joint simulation of this complete parameter combination yielded a recovery-factor increase of 7.76 percentage points and a final recovery factor of 14.19%, with a gas-utilization efficiency of 0.160 t_oil/t_CO2. These scenario-based results suggest the potential of hybrid CO₂ injection for reservoir-energy replenishment and enhanced shale oil recovery.