Surfactant-enhanced carbonated water alternating with CO₂ (SCWAG) flooding, which integrates the advantages of surfactants, carbonated water (CW), and CO₂, has demonstrated significant potential for the development of low-permeability reservoirs. Nonetheless, the underlying mechanisms of SCWAG-enhanced oil recovery require further elucidation. Its CO₂ storage performance and pore-scale oil displacement characteristics have not been thoroughly investigated, and the influence of various factors on SCWAG performance remains poorly understood. This study, for the first time, investigates the pore-scale oil displacement characteristics and CO₂ storage performance of SCWAG by integrating core flooding experiments and nuclear magnetic resonance scanning. An innovative core-scale 3D heterogeneous numerical model was developed using computed tomography scanning and refined via history matching, thereby enabling reliable SCWAG simulation and facilitating reservoir-scale analysis of factors affecting SCWAG performance. The results demonstrate that SCWAG notably improves both sweep efficiency and oil displacement efficiency, achieving higher recovery and CO₂ storage efficiency than other methods. The total recovery reached 76.99%, with individual recoveries of 56.35%, 76.85%, and 87.96% for micropores, mesopores, and macropores, respectively, while the CO₂ storage efficiency is 57.22%. Permeability contrast exerts a significant effect on recovery, whereas CO₂ storage efficiency was primarily influenced by the injection rate and water-to-gas ratio. Moreover, the interaction between the water-to-gas ratio and permeability contrast exerts a substantial impact on both recovery and CO₂ storage efficiency. This study provides novel insights and an in-depth analysis of the SCWAG process, offering practical guidelines for its application in low-permeability reservoirs.

Non-chemical CO₂ microbubbles as a mobility control technology in enhanced oil recovery (EOR) and carbon sequestration are becoming attractive. In this study, the EOR mechanisms of non-chemical CO₂ microbubble (MB) in low permeability reservoirs are experimentally investigated by the nuclear magnetic resonance (NMR) technology. This study reveals, for the first time, the EOR mechanisms of MB in a heterogeneous reservoir and its effect on pore structure. First, mobility reduction factors of MB with various gas–liquid ratios were determined, with MB at a gas–liquid ratio of 1 exhibiting the best performance under experimental conditions. Second, the coreflood experiments with NMR scanning were performed to reveal the EOR mechanisms of MB. It was observed that MB achieved an incremental oil recovery of 13.49% and 22.80% in the core sample with a permeability of 9.51 × 10⁻³ and 2.23 × 10⁻³ μm², respectively. Benefiting from MB's conformance control, the total oil recovery was increased from 38.34% to 54.57% of original oil in place by MB in parallel core flood experiments. Third, the NMR tests demonstrated that MB significantly reduced residual oil in core samples, especially in small pore areas, which highlights the improvement of sweep efficiency by MB. Lastly, the effect of MB on pore structure was studied. The NMR tests indicated a significant increase in pore space after 1 pore volume of MB flooding. Minerals in the core sample were dissolved, leading to an increase in permeability and porosity of the core sample by 17.01% and 0.31%, respectively. Overall, the results of this study provide valuable insights into the EOR mechanisms of MB at the pore scale and offer implications for EOR and carbon sequestration in low-permeability reservoirs.

Naturally fractured gas reservoirs have contributed significantly to global gas reserves and production. The classical gas-well decline analysis relies largely on Arps’ empirical decline models, or modern production decline analysis associating with pseudo-variables. The explicit original gas in place determination methodology is extended from homogeneous reservoir to naturally fractured reservoir under constant or variable bottom-hole pressure conditions in gas-well rate decline analysis. Then, the relationship between gas flow rate and average reservoir pseudo-pressure in the boundary-dominated flow period is re-derived. This formula is in the same format with the equation for homogeneous reservoir by due to the introduction of a new productivity index parameter that captures the inter-porosity flow between fracture and matrix in the natural fractured reservoir. The proposed step-by-step procedures are applied here, which enable the estimation of decline exponent and the explicit and straightforward determination of the original gas in place without any iterative calculations. Four simulated cases prove that our methodology can be successfully used in heterogeneous naturally fractured reservoirs with irregular boundary under constant or variable bottom-hole pressure conditions.

Countercurrent imbibition is an important mechanism for tight oil recovery, that is, water imbibes spontaneously from the fracture into the porous matrix while oil flows reversely into the fracture. Its significance over cocurrent imbibition and forced imbibition is highlighted when permeability reduces. We used the computed tomography (CT) scanning to measure the one-dimensional evolution of water saturation profile and countercurrent imbibition distance (CID) at different fluid pressures, initial water saturations, and permeability. Surprisingly, experiments show that CID evolution for tight reservoir cores dramatically deviates from the classical diffusive rule (i.e., evolutes proportional to square root of time, t^0.5). At early stage, CID extends faster than t^0.5 (super-diffusive); while at late stage, CID extends much slower than t^0.5 (sub-diffusive). After tens of hours, the CID change becomes too slow to be practically efficient for tight oil recovery. This research demonstrates that this deviation from classic theory is a result of (1) a much longer characteristic capillary length than effective invasion depth, which eliminates full development of a classical displacement front; and (2) non-zero flow at low water saturation, which was always neglected for conventional reservoir and is amplified in sub-mili-Darcy rocks. To well depict the details of the imbibition front in this situation, we introduce non-zero wetting phase fluidity at low saturation into classical countercurrent imbibition model and conduct numerical simulations, which successfully rationalizes the non-diffusive behavior and fits experimental data. Our data and theory imply an optimum soaking time in tight oil recovery by countercurrent imbibition, beyond which increasing exposed fracture surface area becomes a more efficient enhanced oil recovery (EOR) strategy than soaking for longer time.

The oil production rate decreases rapidly after a short period of high yield from acidizing or fracturing in low-permeability reservoirs. In this paper, nanospheres are applied before the fracturing step, which possess the ability to absorb water and expand in the water layer, reducing the flow capacity of bottom water and finally enhancing the oil recovery. The plugging performance is investigated by nanosphere displacement experiments in cores and sand-packs, which explores the plugging effect in the oil layer, the oil-water transition zones, the water layer and the fracturing zones. In addition, a nuclear magnetic resonance experiment is conducted to study the flow mechanism of nanospheres and determine the plugging rates, which can characterize the plugging performance of nanospheres in porous media. The results show that the plugging rate is 85.84% and 78.65% on the water layer and oil-water transition zone, respectively, and 94.36% in the fracturing zone. Meanwhile, the nanospheres cannot plug the oil layer. The formation pressure has a less considerable effect on the plugging performance of nanospheres. The nanospheres have good injectivity, and the intensity variations in small, medium and large pores account for 34.46%, 13.22% and 52.32%, respectively. Overall, this paper explores the feasibility of applying nanospheres for water plugging and enhanced oil recovery.