In situ crosslinked polymer gels (ISCPGs) are widely applied in petroleum reservoirs for conformance control and water shutoff to improve oil recovery. However, the differences in gelation behavior and conformance control performance among ISCPGs formulated with different types of crosslinkers, as well as the underlying microscopic mechanisms, remain insufficiently understood. In this study, the gelation properties of three commonly used crosslinkers—chromium (Cr), phenol-formaldehyde (PF) system, and polyethyleneimine (PEI)—with partially hydrolyzed polyacrylamide (HPAM) were evaluated using the Sydansk bottle-testing method. Core displacement experiments were conducted to compare the injectivity and plugging performance of these ISCPGs in both homogeneous and fractured cores. Results show that Cr-ISCPG had the shortest gelation time (0.3–4 h) and the highest gel strength, reaching grade G, but its long-term thermal stability was relatively poor under reservoir conditions (e.g., 73 ℃). PF-ISCPG exhibited superior thermal stability, maintained up to 90 d, but had weaker wall-building capacity compared with Cr-ISCPG. PEI, as a biologically and environmentally friendly crosslinker, yielded PEI-ISCPGs with the longest gelation times and thermal stability, also with the best wall-building performance among the three. In homogeneous cores with gas-measured permeability above 500 × 10⁻³ μm², Cr-ISCPG demonstrated strong plugging capability, largely due to its high wall-building strength on rock surfaces. Nuclear magnetic resonance (NMR) analysis provided microscopic insights into ISCPG injection and propagation mechanisms, showing that excessively prolonged gelation time can cause matrix damage. Owing to its stronger wall-building capacity, Cr-ISCPG performed better in plugging highly conductive channels such as fractures, thereby achieving more pronounced conformance control. This work clarified performance differences among ISCPGs crosslinked by different crosslinkers, providing valuable guidance for optimal crosslinker selection and conformance control design in field applications.

Polymer gels can cause damage to lowly to moderately permeable formations during both oilfield applications and laboratory evaluations of conformance treatment. To enhance reservoir sweep efficiency and oil recovery while using conventional bullhead injection, this study proposed a new injection method where a small amount of branched preformed particle gel (BPPG) was injected as a preflush slug before the injection of in situ cross-linked polymer gel (ISCPG). After that, a gel breaker was pumped to degrade particle gel. The breaking behavior of ISCPG and particle gels in gel breaker was first evaluated using static gel-breaking tests. Core plugging experiments combined with nuclear magnetic resonance (NMR) measurements were then employed to assess the sweep efficiency improvement and oil displacement effects of the ISCPG-BPPG composite gel system. Results showed that injecting the ISCPG-BPPG composite gel system into core samples, followed by a gel breaker, could effectively remove damage at the end faces of lowly to moderately permeable formations. Thus, it expanded the subsequent waterflood sweep volume and thus increased oil recovery by 28.43% original oil in place (OOIP). The gel breaker contained a 2:8 ratio of depolymerizing agent to ammonium persulfate at 2 wt% concentration. Moreover, BPPG in the composite gel system could act as a preflush slug to block subsequent ISCPG invasion into lowly to moderately permeable formations, reducing damage to oil-bearing formations. Compared to the single-gel injection method, the ISCPG-BPPG composite gel system demonstrated superior conformance improvement capability and oil recovery after gel-breaking treatment. The NMR technology was employed to analyze the novel conformance improvement method based on composite gel and gel-breaking mechanisms at the microscopic scale.

Black nanosheets (BN, with a specific chemical composition of molybdenum disulfide) have been widely studied for low-permeability reservoir development due to their unique nanoscale dimensions and lamellar structure. Our prior research demonstrated that cationically modified BN combined with low-salinity water (LSW) significantly enhances oil displacement. This study compared the imbibition adaptability of the composite system under both ambient-pressure and pressurized conditions, while combining nuclear magnetic resonance (NMR) techniques to analyze related imbibition mechanisms and reservoir permeability adaptability. Results showed that the modified BN-LSW composited system achieved an imbibition recovery efficiency of 43.92% under ambient pressure. The mechanism was capillary force-dominated, preferentially displacing oil from small pores by improving core wettability and emulsification. Under pressurized conditions, the driving force became dominant, further increasing recovery efficiency to 56.52%, with the system displacing oil from both large and small pores. Additionally, the system showed optimal adaptability in cores with 0.05 × 10⁻³ μm² permeability. Imbibition efficiency declined at higher/lower permeabilities due to weakened capillary forces or nanoparticle aggregation-induced clogging. This study confirmed that the modified BN-LSW composite system enhanced imbibition stability and recovery efficiency, and combined with nuclear magnetic resonance (NMR) technology, its mechanism was revealed at the microscale. This provided theoretical and technical support for the efficient development of low-permeability reservoirs, with significant engineering value.

Black nanosheets (BNs), as a highly promising fracturing-EOR integrated enhancement material, require further study of their huff-n-puff performance and mechanism. This work characterized nanoscale structure, stability, and interfacial properties of BNs, then evaluated their huff-and-puff performance through NMR-assisted core flooding experiments. The adaptability of BNs in low-permeability reservoirs with different permeabilities, as well as the effect of huff-n-puff cycles on their oil recovery performance, were analyzed. Results show that anionic modified BNs maintained nanoscale flake structure with enhanced electrostatic repulsion. The BNs with an extremely low concentration of 0.002 wt% exhibited excellent emulsification and stabilization effects on crude oil and wettability alteration of the rock surface. Compared with injection water, BNs had excellent huff-n-puff oil recovery effects, reaching 22.1% original oil in place (OOIP) after the first huff-n-puff cycle. BNs had good adaptability in low-permeability cores (i.e., 0.1 × 10⁻³ to 10 × 10⁻³ μm²). Increasing the huff-n-puff cycle significantly improved the oil recovery effect of BNs, and the optimal performance was at 4 cycles. As the huff-n-puff cycle increased from 3 to 4, the ability of BNs to “automatic oil-seeking” in micropores became more prominent. This paper also innovatively combined core nuclear magnetic resonance (NMR) T₂ analysis, nuclear magnetic imaging analysis, and longitudinal T₂ signal analysis along the core (i.e., along the core injection length). It can not only more accurately quantify the huff-n-puff recovery effect of low-permeability cores but also quantitatively analyze the penetration depth and microscopic huff-n-puff mechanism of BNs from a microscopic perspective. These findings are helpful for the selection of nanomaterials and mechanism analysis in the design of integrated fracturing-flooding schemes and processes.

Polymer gels are widely used in water control and enhanced oil recovery in oil fields. However, the damage mechanism of polymer gels to layers with remaining oil and not requiring plugging and corresponding protective measures are unclear. In this paper, we investigated polymer gels' damage and protection performance through static gel-breaking experiments and dynamic plugging and oil recovery evaluations on rock cores. Moreover, nuclear magnetic resonance (NMR) technology was combined to analyze the damage performance of polymer gels on cores from the pore scale. In addition, a protective technique based on gel breakers for layers with remaining oil and not requiring plugging was proposed. Results showed that when polymer gels were injected into heterogeneous cores, they plugged high-permeability layers while also penetrating low-permeability layers. When the damage to the low-permeability layers was not alleviated, the conformance and oil displacement efficiency were significantly reduced. When the concentration of ammonium persulfate was 2%–5%, the gel-breaking time was shortest and the residue was very minimal. Therefore, ammonium persulfate could be used as a gel breaker and reservoir protective material. Furthermore, after injecting ammonium persulfate into heterogeneous reservoir cores, the gel damage on the face of low-permeability layers was relieved. Consequently, the improvement in sweep efficiency was achieved, showing the re-activation of the remaining oil in medium-low permeability layers. Therefore, the low-permeability layer protection process and core experiment study based on gel-breaking agents proposed in this study were suggested to provide a new technique for the field application of conformance modification agents, aiming to achieve higher recovery degrees.

Fracturing operations can effectively improve the production of low-permeable reservoirs. The performance of fracturing fluids directly affects the fracturing efficiency and back flow capacity. As polymer-based fracturing fluids (such as guar gum (GG), polyacrylamide (HPAM), etc.) are high-viscosity fluids formed by viscosifiers and crosslinking agents, the degree of gel breakage after the fracturing operation directly influences the damage degree to the reservoir matrix and the mobility of oil angd gas produced from the reservoir into the wellbore. This study compared the viscosity, molecular weight, and particle size of the fracturing fluid after gel breakage prepared by GG and HPAM as viscosifiers, as well as evaluate their damage to the core. Results show that the viscosities of the gel-breaking fluid increased with the concentration of the viscosifier for both the HPAM-based and GG-based fracturing fluids. For the breaking fluid with the same viscosity, the molecular weight in the HPAM-based gel-breaking fluid was much larger than that in the GG-based system. Moreover, for the gel-breaking fluid with the same viscosity, the molecular particle size of the residual polymers in the HPAM-based system was smaller than that in the GG-based system. The damage to the core with the permeability of 1 × 10⁻³ μm² caused by both the HPAM-based and GG-based gel-breaking fluids decreased with the increase in the solution viscosity. For the gel-breaking fluid systems with the same viscosity (i.e., 2–4 mPa s), the damage of HPAM-based fracturing fluid to low-permeability cores was greater than the GG-based fracturing fluid (45.6%–80.2%) since it had a smaller molecular particle size, ranging from 66.2% to 77.0%. This paper proposed that the damage caused by hydraulic fracturing in rock cores was related to the partilce size of residual polymers in gel-breaking solution, rather than its molecular weight. It was helpful for screening and optimizing viscosifiers used in hydraulic fracturing process.

Nanoparticles have been widely used in polymer gel systems in recent years to improve gelation performance under high-temperature reservoir conditions. However, different types of nanoparticles have different effects on their gelation performance, which has been little researched. In this study, the high-temperature gelation performance, chemical structure, and microstructure of polymer gels prepared from two nanomaterials (i.e., nano-SiO₂ and nano-TiO₂) were measured. The conventional HPAM/PEI polymer gel system was employed as the control sample. Results showed that the addition of nano-TiO₂ could significantly enhance the gel strength of HPAM/PEI gel at 80 ℃. The gel strength of the enhanced HPAM/PEI gel with 0.1 wt% nano-TiO₂ could reach grade I. The system also had excellent high-temperature stability at 150 ℃. The enhanced HPAM/PEI gel with 0.02 wt% nano-TiO₂ reached the maximum gel strength at 150 ℃ with a storage modulus (G′) of 15 Pa, which can meet the need for efficient plugging. However, the nano-SiO₂ enhanced HPAM/PEI polymer gel system showed weaker gel strength than that with nano-TiO₂ at both 80 and 150 ℃ with G′ lower than 5 Pa. Microstructures showed that the nano-TiO₂ enhanced HPAM/PEI gel had denser three-dimensional (3D) mesh structures, which makes the nano-TiO₂ enhanced HPAM/PEI gel more firmly bound to water. The FT-IR results also confirmed that the chemical structure of the nano-TiO₂ enhanced HPAM/PEI gel was more thermally stable than nano-SiO₂ since there was a large amount of –OH groups on the structure surface. Therefore, nano-TiO₂ was more suitable as the reinforcing material for HPAM/PEI gels for high-temperature petroleum reservoir conformance improvement.

Nanomaterials and low-salinity water (LSW) are two popular enhanced oil recovery (EOR) methods that have been widely studied in recent years. The former is used for in-depth conformance improvement and the latter for microscopic oil displacement (by altering the potential and contact angle). However, there are few literature on combining them to achieve synergistic effects, especially for tight sandstone reservoirs. Based on the reservoir conditions of the Jimusar Oilfield, this study investigated the oil recovery mechanism of the combined imbibition system, which was composed of black nanosheet (BN) and LSW. Its performances including decreasing interfacial tension, emulsification, and wettability alterations were evaluated. The imbibition differences between the single system of BN and LSW and the combined BN-LSW imbibition system were then compared. Results showed that the combined imbibition system had a better emulsification effect on the crude oil and could also alter the wettability of the core surface. Moreover, the combined system could increase both the imbibition rate and the ultimate oil recovery. The nuclear magnetic T₂ spectrum also indicated that the addition of black nanosheets could divert more fluid into small pores and thus improve the microscopic sweep efficiency.