In order to improve the plugging performance of high-temperature and high-salt oil reservoir plugging agents, this paper utilizes a copolymer composed of acrylamide and 2-acrylamide-2-methylpropanesulfonic acid (AM/AMPS) as the polymer, polyethyleneimine as the cross-linking agent, and nylon fiber as the stabilizer to develop a high-temperature- and high-salt-resistant gel system. This study analyzed and evaluated the temperature resistance, salt resistance and blocking performance of the gel system. The evaluation results show that the gel-forming strength of this gel system can reach an H level, and it has good thermal stability at the high temperature of 130 °C. At the high salinity of 240,720 mg/L, the syneresis rate remains below 2.5%, and the gel-forming time is greater than 15 h; the higher the temperature, the shorter the gelling time. The results of our sand-filled pipe-plugging experiment show that the gel system can adapt to sand-filled pipes with different levels of permeability, and reaching a plugging rate of 94%.

In view of the high salinity characteristics of reinjection oilfield wastewater in the Gasi Block of Qinghai Oilfield, with the polymer produced by Shandong Baomo as the research target, we systematically investigated the variations in the impact of six ions, Na⁺, K⁺, Ca²⁺, Mg²⁺, Fe²⁺, and Fe³⁺, in the produced water from polymer flooding on the viscosity and stability of the polymer solution. Additionally, we provided the primary research methods for complexation in reinjected wastewater. Experimental results indicate that the main factors leading to a decrease in polymer viscosity are high-valence cations, with the descending order of their influence being Fe²⁺ > Fe³⁺ > Mg²⁺ > Ca²⁺ > Na⁺ > K⁺. High-valent cations also effect the viscosity stability of polymer solutions, and their order from greatest to least impact is: Fe²⁺ > Ca²⁺(Mg²⁺) > Fe³⁺ > Na⁺(K⁺). This article is focused on investigating the influencing factors and extent of the impact of oilfield wastewater on the viscosity of polymer solutions. It illustrates the response mechanism of cations to the viscosity of polymer solutions in reinjection wastewater polymerization. Through this research, the goal is to provide reference control indicators and limits for the water quality of injected polymers at oilfield sites. This ensures the stability and controllability of polymers in field applications and offers theoretical guidance for polymer flooding technology.

Water alternating gas (WAG) flooding is a widely employed enhanced oil recovery method in various reservoirs worldwide. In this research, we will employ SiO₂ nanofluid alternating with the CO₂ injection method as a replacement for the conventional WAG process in oil flooding experiments. The conventional WAG method suffers from limitations in certain industrial applications, such as extended cycle times, susceptibility to water condensation and agglomeration, and ineffectiveness in low-permeability oil reservoirs, thus impeding the oil recovery factor. In order to solve these problems, this study introduces SiO₂ nanofluid as a substitute medium and proposes a SiO₂ nanofluid alternate CO₂ flooding method to enhance oil recovery. Through the microcharacterization of SiO₂ nanofluids, comprehensive evaluations of particle size, dispersibility, and emulsification performance were conducted. The experimental results revealed that both SiO₂-I and SiO₂-II nanoparticles exhibited uniform spherical morphology, with particle sizes measuring 10–20 nm and 50–60 nm, respectively. The SiO₂ nanofluid formulations demonstrated excellent stability and emulsification properties, highlighting their potential utility in petroleum-related applications. Compared with other conventional oil flooding methods, the nanofluid alternating CO₂ flooding effect is better, and the oil flooding effect of smaller nanoparticles is the best. Nanofluids exhibit wetting modification effects on sandstone surfaces, transforming their surface wettability from oil-wet to water-wet. This alteration reduces adhesion forces and enhances oil mobility, thereby facilitating improved fluid flow in the rock matrix. In the oil flooding experiments with different slug sizes, smaller gas and water slug sizes can delay the breakthrough time of nanofluids and CO₂, thereby enhancing the effectiveness of nanofluid alternate CO₂ flooding for EOR. Among them, a slug size of 0.1 PV approaches optimal performance, and further reducing the slug size has limited impact on improving the development efficiency. In oil flooding experiments with different slug ratios, the optimal slug ratio is found to be 1:1. Additionally, in oil flooding experiments using rock cores with varying permeability, lower permeability rock cores demonstrate higher oil recovery rates.

T oilfield is the fractured-vuggy carbonate reservoir at a temperature of around 130 °C, with salinity of up to 22 × 10⁴ mg/L. In order to solve the problem of the high water cut in the late development stage of T oilfield, we selected XN-T from 27 kinds of swelling retarding particles by testing their swelling capacity, and coated a thin film to improve its retarding swelling capacity. The mechanisms of strong water absorption and water-holding abilities of particles were analyzed by infrared spectrometry and SEM. In the core flow experiment, the plugging rate was found to be 98.42%. Finally, the injection parameters of the coated particles were optimized to maximize the water plugging and profile control ability, resulting in an optimal particle size of 0.4–0.6 mm and a mass fraction of 10%.

The purpose of this study is to investigate the use of SiO₂ nanoparticles in assisting with surfactants and polymers for tertiary oil recovery, with the aim of enhancing oil recovery. The article characterizes the performance of SiO₂ nanoparticles, including particle size, dispersion stability, and zeta potential, evaluates the synergistic effects of nanoparticles with alpha-olefin sulfonate sodium (AOS) surfactants and hydrolyzed polyacrylamide (HPAM) on reducing interfacial tension and altering wettability, and conducts core flooding experiments in rock cores with varying permeabilities. The findings demonstrate that the particle size decreased from 191 nm to 125 nm upon the addition of SiO₂ nanoparticles to AOS surfactant, but increased to 389 nm upon the addition of SiO₂ nanoparticles to HPAM. The dispersibility experiment showed that the SiO₂ nanoparticle solution did not precipitate over 10 days. After adding 0.05% SiO₂ nanoparticles to AOS surfactant, the zeta potential was −40.2 mV, while adding 0.05% SiO₂ nanoparticles to 0.1% HPAM resulted in a decrease in the zeta potential to −25.03. The addition of SiO₂ nanoparticles to AOS surfactant further reduced the IFT value to 0.19 mN/m, altering the rock wettability from oil-wet to strongly water-wet, with the contact angle decreasing from 110° to 18°. In low-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for enhanced oil recovery increased the recovery rate by 24.5% over water flooding. The recovery rate increased by 21.6% over water flooding in low-permeability rock core experiments after SiO₂ nanoparticles were added and surfactants and polymers were utilized for oil displacement. This is because the nanoparticles blocked small pore throats, resulting in increased resistance and hindered free fluid flow. The main causes of this plugging are mutual interference and mechanical entrapment, which cause the pressure differential to rise quickly. In high-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for oil recovery increased the recovery rate by 34.6% over water flooding. Additionally, the recovery rate increased by 39.4% over water flooding with the addition of SiO₂ nanoparticles and the use of AOS surfactants and HPAM for oil displacement. Because SiO₂ nanoparticles create wedge-shaped structures inside highly permeable rock cores, they create structural separation pressure, which drives crude oil forward and aids in diffusion. This results in a comparatively small increase in pressure differential. Simultaneously, the nanoparticles change the rock surfaces’ wettability, which lowers the amount of crude oil that adsorbs and improves oil recovery.

Quasi-dry CO₂ fracturing technology is a new CO₂ fracturing technology that combines liquid CO₂ fracturing (dry CO₂ fracturing) and water-based fracturing. It uses a liquid CO₂ system containing a small amount of water-based fracturing fluid to carry sand, and it is characterized by sand blending at normal pressure, convenient preparation, the integrated application of resistance reduction and sand carrying, and no dedicated closed sand blender requirement. We developed a self-crosslinking emulsion-type water-based fracturing fluid (ZJL-1), which contained ionic bonds, hydrogen bonds, van der Waals forces, and hydrophobic associations, for quasi-dry CO₂ fracturing, and the comprehensive properties of the ZJL-1 fracturing fluid were evaluated. The results showed that the ZJL-1 fracturing fluid had obvious viscoelastic characteristics, a heat loss rate of less than 10% at 200 °C, a good thermal stability, sufficient rheology under high temperature and high shear conditions, and a good thermal stability. The resistance reduction rate reached 70%, which demonstrates a good resistance reduction performance. Compared with conventional guar fracturing fluid, ZJL-1 can carry more sand and has a lower core damage rate. The on-site use of quasi-dry fracturing showed that optimizing the mixing ratio of liquid CO₂ fracturing fluid and ZJL-1 fracturing fluid effectively enhanced oil and gas recovery. This can be used to optimize quasi-dry fracturing and can be used as a reference.