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.

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.

During fracturing operations, special situations are often encountered. For example, the insufficient proppant-carrying capacity of fracturing fluid can cause quartz sand or ceramsite to settle near the wellbore and form a sand plug. Alternatively, excessive sand injection intensity can lead to severe accumulation of injected sand near the wellbore and also form a sand plug. These special situations are reflected in the fracturing operation curve as an abnormal increase in oil pressure over a short period of time. If not handled promptly, they can have unimaginable consequences. Sand plugs in fracturing operations, characterized by their speed and unpredictability, often form rapidly, within about 20 s. Conventional methods for on-site sand-plug warnings during fracturing include the oil pressure–time double logarithmic slope method and the net pressure–time double logarithmic slope method. Although these methods respond quickly, their warning results are unstable and vary significantly during actual operations. This is mainly because the fluctuations in the actual fracturing operation curve are often large, and there can be sudden pressure rises and drops even during stable periods, albeit less pronounced. To address the identification of anomalies in conventional fracturing operation monitoring and warning methods, a sand-plug warning index method has been proposed for sand-plug identification. This method combines the oil pressure–time double logarithmic slope with the oil pressure increment within 5 s, the rate of change in the oil pressure–time double logarithmic slope, and the fitted oil pressure intercept as indicators. The method has been validated using Well A in Fuling as an example. The validation results show that the dynamic analysis method can predict sand plugs while reducing warning fluctuations without affecting sensitivity. Compared to conventional methods, the warning time can be advanced by about 10 s.