The solid particles in the produced fluids from the oil wells treated by compound flooding can greatly stabilize the strength of the interfacial film and enhance the stability of the emulsion, increasing the difficulty of processing these produced fluids on the ground. In this paper, the oil phase and the water phase were separated from the SPAN series emulsions by electrical dehydration technology and adding demulsifier agents. The changing trends of the current at both ends of the electrodes were recorded during the process. The efficient demulsification of the emulsion containing solid particles was studied from the perspective of oil-water separation mechanisms. Combined with the method of molecular dynamics simulation, the effect of the addition of a demulsifier on the free movement characteristics of crude oil molecules at the position of the liquid film of the emulsion were further analyzed. The results indicated that the presence of solid particles greatly increased the emulsifying ability of the emulsion and reduced its size. Under the synergistic effect of demulsifier and electric dehydration, the demulsification effect of the emulsion increased significantly, and the demulsification rate could reach more than 82%. The addition of demulsifiers changed the stable surface state of the solid particles. The free movement ability of the surrounding crude oil molecules was enhanced, which led to a decrease in the strength of the emulsion film so that the water droplets in the emulsions were more likely to coalesce and break. These results are of great significance for the efficient treatment of wastewater from oilfields, promoting the sustainability of environment-friendly oilfield development.

After long-term polymer flooding, water channeling, and ineffective water circulation occur in oil wells, which seriously affect polymer flooding efficiency and oilfield recovery. The weak gel system has the property of delaying cross-linking. After the weak gel system enters the deep formation, the cross-linking reaction is carried out, which can achieve the purpose of deep regulation and flooding. In this paper, according to the formation characteristics of high temperature, high permeability, and large pores in Y1 block (a block in the Daqing Yushulin Oilfield), the formulation of weak gel system was developed. The optimal formulation was determined by parameters such as gel-forming properties, stability, viscoelasticity, and rheology. Finally, the best formulation for the Y1 block is that containing 0.22% of polyacrylamide (HPAM) and 0.15% of chromium (III) acetate system. The gel-forming time of the formulation is 8 h, and the viscosity can be maintained at 15,000–24,000 mPa·s. Next, this paper studied the factors that affect the gelation of formulations, mainly including dissolved oxygen content, bacterial content, insoluble suspended solids content, and metal ions in the formulation water. The results show that the critical point of the worst effect is the oxygen content close to 1.5 mg/L, and the optimal critical point of oxygen content of the gel system is 7 mg/L. The bacteria in the prepared water degrade the weak gel solution. The more bacteria, the more serious the degradation of the weak gel. A small amount of insoluble suspended solids will greatly increase the viscosity of the weak gel solution, but will accelerate the gel-breaking time. When the content of insoluble suspended solids is high, more than 1000 mg/L, a precipitate will be formed at the bottom of the solution, and the difference in the content of insoluble suspended solids in this interval has little effect on weak gels. The metal ion that mainly affects the gelation effect is Fe²⁺. With the increase of Fe²⁺ mass concentration, the viscosity of weak gel decreases sharply.

In the process of oilfield development, the use of CO₂ can improve the degree of reservoir production. Usually, CO₂ is injected alternately with water to expand the spread range of CO₂, and CO₂ presents a supercritical state in the formation conditions. In the process of alternating CO₂ and water injection, wellbore freezing and plugging frequently occur. In order to determine the cause of freezing and plugging of injection wells, the supercritical CO₂ flooding test area of YSL Oilfield in China is taken as an example to analyze the situation of freezing and plugging wells in the test area. The reasons for hydrate freezing and plugging are obtained, the distribution characteristics and sources of hydrate near the well are clarified, and a coupling model is established to calculate the limit injection velocity and limit shut-in time of CO₂ and water alternate injection wells. The results show that the main reasons for freezing and plugging of supercritical CO₂ water alternate injection wells are long time shut down after alternate injection, improper operation when stopping injection and starting and stopping pumps, and slow injection speed during alternate injection. In the process of supercritical CO₂ water alternative injection, in the case of post-injection, the CO₂ in the formation will reverse diffuse to the injection well end. With the continuous increase of daily water injection, the initial diffusion position and the time of CO₂ diffusion to the perforated hole after well shut-in gradually increase. The time of CO₂ reverse diffusion to the bottom of the well is 1.6–32.3 d, and the diffusion time in the perforated hole is 1.0–4.5 d. Therefore, the limit shut-in time following injection is 2.6–36.8 d. Following gas injection, the limit shut-in time of a waterproof compound can be divided into three stages according to the change of wellbore pressure: the pressure stabilization stage, pressure-drop stage and formation fluid-return stage. The limit shut-in time of a waterproof compound following gas injection is mainly affected by permeability, cumulative gas injection rate and formation depth. The limit shut-in time of a waterproof compound is 20.0~30.0 days. The research results provide technical support for the wide application of CO₂ flooding.

Radial drilling-fracturing is an innovative fracturing technology that achieves superior stimulation effects. In order to study the permeability-increasing effect and main influencing factors of radial water jet drilling in the low physical section, this paper uses a fracking electrical simulation experiment, based on the principle of hydropower similarity, to simulate the reservoir conditions and well pattern in the low physical section and, at the same time, establishes the radial fracturing model of the low physical section reservoir, simulates the saturation field, pressure field, and production-change law under different drilling parameters, and studies different influencing factors. The experimental results show that when the number of drilling holes exceeds two, the effect of increasing production gradually becomes less significant as the number of drilling holes increases; Within the range of the angle between the two boreholes, the forward distance of the oil–water displacement front is the farthest and the sweep is relatively uniform. On both sides of the included angle, the forward distance of the oil–water displacement front edge is smaller than the forward distance of the displacement within the included angle range and it is clearly inclined towards the radial drilling with uneven spread. Radial drilling has an impact on the seepage field, causing changes in its streamline. The pressure inside the borehole is lower than the surrounding formation pressure and most of the flow lines change direction near the borehole location, causing deflection. As the borehole length increases, the oil-well production also increases. The optimal effect is for the borehole length to be 100 m. This study provides a reference for the on-site application of radial fracturing in low physical properties sections.

The Lamadian oilfield has entered the stage of strong water cut after natural energy development and conventional water flooding development. The use of asphalt binder for profile control can not only adjust the contradiction between layers, expand the swept volume, but also improve the oil displacement efficiency. The field test has achieved certain results. The main oil layer in the Lamadian oilfield has a strong oil layer thickness and serious vertical and plane heterogeneity. After years of water injection development and polymer injection development, most oilfields have entered a period of strong water cut. In the test, it is found that the effect of different well layers is very different, the effect is unstable, and the reason is unclear. Therefore, it is necessary to carry out research on the adaptability and parameter optimization of profile control of asphalt binder through laboratory experiments. In this paper, the asphalt binder provided on site are modified and the dispersion effect of modified asphalt binder is studied, and the concentration of suspending agent is optimized. The artificial cemented core structure and injection method are improved to solve the problem of aggregated asphalt binder on the end face during injection. The displacement profile control experiment was carried out with artificial cores, and the matching relationship between the injected particle size of the asphalt binder and the permeability was determined, and the optimal injection amount was optimized for cores with different permeabilities. The research results show that adding a KCl (potassium chloride solution) solution with a concentration of 2% as a dispersant can exert a better dispersing effect on the asphalt binder. Through the plugging rate experiments of three types of asphalt binder, the profile control effect is determined as the best when the particle size of the asphalt binder is 0.06–0.1 mm. According to the experimental results, the experimental research on the injection concentration and profile control radius of the profile control agent system was carried out. Finally, it was determined that the injection concentration of 3500 mg/L and the profile control radius of 1/3–1/2 of the well spacing were the optimal injection parameters. The field application of a profile control agent provides experimental basis.

Sucker rods operate under long-term cyclic loading while exposed to corrosive produced fluids, making corrosion–fatigue damage a major integrity concern. This study examined produced-fluid samples from 16 wells with sucker-rod failures and 16 corresponding failed rods from a Daqing oil production plant using ionic-composition analysis, SEM/EDS, bulk chemical analysis, metallography, axial tensile tests, exploratory fatigue tests, and field load analysis. The fluids were HCO₃⁻-dominated, with average HCO₃⁻, Cl⁻, and SO₄²⁻ concentrations of 345.7, 0.129, and 2.55 mg/L, respectively. Representative fracture surfaces showed corrosion pits, corrosion products, secondary cracks, and lamellar or step-like morphologies, while corroded microregions were enriched in O and contained detectable Cl and S. Local discontinuities, including decarburization, inclusions, and scratches, were also observed. Residual tensile strength varied substantially with service history, and exploratory fatigue results showed considerable scatter. The actual field fracture location did not coincide with the maximum nominal axial stress. The combined evidence supports a representative sequence of localized corrosion and pit formation, crack-susceptible region development, microcrack initiation, cyclic crack propagation, crack coalescence, loss of effective load-bearing area, and final rapid fracture.