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Staging fracturing with balls for temporary plugging is a crucial technique used to stimulate deep reservoirs. However, the transport of matter confined in a trap is very complicated. To investigate the influence of various factors on the force exerted by the ball sealer during the construction of the temporary plug, we analyse the ball sealer migration in three stages: before, after, and after the pump is stopped. We examine the effect of density, viscosity, displacement, number of holes, and fracturing fluid viscosity on the confined force state of the spherical sealer. Based on a model of entrainment dynamics with three stress states, we analyse the motion and force properties of the sphere. With this analysis, we have identified the main factors that affect the force exerted by the ball sealer. Our findings suggest that reducing the number of holes, especially when using high displacement and high viscosity fracturing fluids, can optimize the force state of the plug sphere and increase the plug efficiency. This conclusion provides a theoretical foundation for the formulation and optimization of a staged FRAC construction scheme with plug balls.

Temporary plugging diversion fracturing (TPDF) technology has been widely used in various oil fields for repeated reconstruction of high-water-cut old oil wells and horizontal well reservoir reconstruction. Previous studies have carried out in-depth study on the pressure-bearing law and placement morphology of different types of temporary plugging agents (TPAs) in fractures, but there are relatively few studies on TPA accumulation body permeability. To solve this problem, an experimental device for evaluating the TPA performance with adjustable fracture pores is proposed in this paper. Based on the test of fracturing fluid breaking time and residue content, the low damage of fracturing fluid to the reservoir is determined. The TPA degradation performance test determines whether the TPA causes damage to the hydraulic fracture after the temporary plugging fracturing. Finally, by testing the TPA pressure-bearing capacity and the temporary plugging aggregation body permeability, the plugging performance and the aggregation body permeability are determined. The results show the following: (1) Guar gum fracturing fluid shows good gel-breaking performance under the action of breaking agent, and the recommended concentration of breaking agent is 300 ppm. At 90~120 °C, the degradation rate of the three types of TPAs can reach more than 65%, and it can be effectively carried into the wellbore during the fracturing fluid flowback stage to achieve the effect of removing the TPA in the fracture. (2) The results of the pressure-bearing performance of the TPA show that the two kinds of TPAs can quickly achieve the plugging effect after plugging start: the effect of ZD-2 (poly lactic-co-glycolic acid (PLGA)) particle-and-powder combined TPA on forming an effective temporary plugging accumulation body in fractures is better than that of ZD-1 (PLGA) pure powder. There are large pores between the particles, and the fracturing fluid can still flow through the pores, so the ZD-3 (a mixture of lactide and PLGA) granular temporary plugging agent cannot form an effective plugging. (3) The law of length of the temporary plugging accumulation body shows that the ZD-2 combined TPA has stronger plugging ability for medium-aperture simulated fracture pores, while the ZD-1 powder TPA has stronger plugging ability for small aperture simulated fracture pores, and the ZD-3 granular TPA should be avoided alone as far as possible. This study further enriches and improves the understanding of the mechanism of temporary plugging diverting fracturing fluid.

Purpose: The aim of the present study was to state a relationship between the meibomian gland loss area (MGLA), eyelid hyperemia and meibomian gland (MG) orifices plugging in a sample of university students. Material and methods: A total of 74 participants were recruited. Meibography images were obtained with the OCULUS® Keratograph 5M and MGLA was calculated using the ImageJ software; also, MGLA was categorized following the Meiboscale into 4 groups: group 1 (<25%), group 2 (25-50%), groups 3 (50-75%), and group 4 (>75%). An exhaustive slit lamp examination of both eyelids was performed. Eyelid margin hyperemia and MG orifices plugging of each eyelid were categorized following Arita et. al grading scales. Results: A significant statistical relationship was found between MG orifices plugging and MGLA for both eyelids (Fisher’s exact test; both p < 0.019). Also, correlations were obtained between lower MGLA and lower MG orifices plugging (Cramer-V = 0.583, p ≤ 0.001); and between upper MGLA and upper eyelid margin hyperemia (Cramer-V = 0.418, p = 0.023), and upper MG orifices plugging (Cramer-V = 0.413, Fisher’s exact test: p = 0.042). Conclusion: MGLA varies depending on MG orifices plugging in upper and lower eyelids; also, in upper eyelids MGLA was correlated with eyelid hyperemia.

Temporary plugging and diversion fracturing (TPDF) is widely used to promote the uniform and complex distribution of multi-clustered hydraulic fractures (HFs) in a horizontal well of the unconventional formations. However, the migration behavior of temporary plugging agent (TPA), as a function of the concentration and particle size of TPA and cluster-perforation numbers, etc., determining the effectiveness of this technique, remains unclear. Therefore, this study conducted innovatively a series of TPDF simulation experiments on transparent polymethyl methacrylate (PMMA) specimens (cubic block of 30 cm × 30 cm × 30 cm) to explore visually the migration behavior of TPA in multi-clustered HFs in a horizontal well. A laboratory hydraulic sandblasting perforation completion technique was implemented to simulate the multi-cluster perforations. All the distributions of wellbore, perforations, HFs, and TPA can be seen clearly inside the PMMA specimen post the experiment. The results show that there are four characteristic plugging positions for the TPA: mouth of HF, middle of HF, tip of HF, and the intersection of HFs. Small particle size TPA tends to migrate to the fracture tip for plugging, while large particle size TPA tends to plug at the fracture mouth. The migration of the TPA is influenced obviously by the morphology of the fracture wall. A smooth fracture wall is conducive to the migration of the TPA to the far end of HFs, but not conducive to generating the plugging zone and HF diversion. In contrast, a \"leaf vein\" fracture of rough wall is conducive to generating the plugging layer and the diversion of HFs, but not conducive to the migration of the TPA to the far end of HFs. The migration ability of TPA in a \"shell\" pattern is intermediate between the two above cases. Increasing TPA concentration can encourage TPA to migrate more quickly to the characteristic plugging position, and thereby to promote the creation of effective plugging and subsequently the multi-stage diversion of the HFs. Nevertheless, excessive concentration may cause the TPA to settle prematurely, affecting the propagation of the HFs to the far end. Increasing the number of clusters to a certain extent can encourage TPA to migrate into the HFs and form plugging, and promote the diversion. An evaluation system for the migration ability of granular TPA has been established, and it was calculated that when there is no plugging expectation target, the comprehensive migration ability of small particle size TPA is stronger than that of large particle size TPA. This research provides theoretical foundation for the optimization of temporary plugging parameters.

The reservoir in Area A are developed with synchronous injection and production. Waterflooding operations in specific reservoir units may induce elevated formation pressure concurrent with declining performance metrics in existing wells. This phenomenon arises from either micro-fracture network propagation or formation impairment, manifesting as depressed liquid levels, reduced flowing pressures, and diminished productivity indices for both fluids and hydrocarbons. Temporary fracture diversion technology proves effective for stimulating ultra-low permeability reservoirs. During implementation, engineered plugging particulates carried by fracturing fluids selectively invade original fracture-connected perforations and high-permeability zones. Through strategic accumulation within these zones, they establish impermeable filter cake barriers that redirect subsequent fluid stages toward underutilized reservoir regions. Under the condition of a certain horizontal bi-directional stress difference, secondary fractures will be generated, and then the fracture initiation orientation will be changed to create new fractures. To enhance production efficiency and maintain sustainable development in Area A’s oilfields, 44 well operations implemented temporary fracture diversion technology between 2022-2024. Field implementation outcomes confirm a 90.9% technical success rate with 7,723 tonnes of cumulative production gain, demonstrating significant production enhancement. This approach establishes critical technical support for exploiting ultra-low permeability reservoirs, particularly proving instrumental in sustaining long-term productivity of Area A’s Chang 6 formation.

Crevices and fissures are usually caused by collisions with rocks when a ship is grounded, therefore, it is often necessary to perform underwater plugging to restore the internal buoyancy of the ship through compressor drainage and other means during the salvage process. The recovery of buoyancy inside the ship will be directly affected by the effect of underwater plugging, which has a huge impact on the re-floating the ship. A new type of underwater plugging is designed basing on the salvage project of a grounding ship and through on-site testing in this article. Rubber plate combined with flat steel bars are used for underwater plugging, explored the feasibility of using rubber plate for underwater plugging, more importantly, the problem of underwater plugging at locations where the damaged ship is severely deformed during the compressor drainage operation. The flexible characteristics of rubber plate can effectively plug crevices or fissures, the use of flat steel bars on the rubber plate for reinforcement, effectively overcomes the problem of insufficient stiffness of the rubber plate and ensures the reliability of the plugging. The on-site results indicate that this underwater plugging has a good effect, the excellent performance and precautions of rubber plate during the experimental process have been summarized in this article, providing new ideas and methods for subsequent underwater plugging.

Temporary plugging fracturing technology is an effective method for extending the range of segmented fracturing in horizontal wells and improving the utilization between fractures in low-permeability reservoirs. In this study, a controllable degradable temporary plugging agent was synthesized by graft copolymerization of PGA and PLA with a material ratio of 3:1, under the catalysis of stannous octoate at 150°C. This approach allows for controlled degradation of the temporary plugging materials by protecting PLA, which has good affinity to water, and adjusting the molecular weight of the product. It reduces the initial degradation rate while increasing the later degradation rate. To consider the heterogeneity of natural fractures and reservoir physical permeability in shallow sea reservoirs, a numerical model for temporary plugging and fracturing of horizontal wells was developed. The model investigates the influence of parameters such as displacement and cluster spacing on crack propagation, resulting in the formation of a simulation method suitable for temporary plugging fracturing of horizontal wells in heterogeneous reservoirs. The research findings indicate that crack length and width gradually increase with the increase of displacement. The maximum crack spread area is achieved at a displacement of 5~8m 3 /min. Temporary plugging can be implemented when the cluster spacing is ≤12m, allowing for the full expansion of cracks that have not effectively expanded. The largest crack spread area is observed at a crack spacing of 5~8m.

In response to the issue of shallow casing leakage in oil and water wells, traditional treatment methods suffer from high costs, long cycles, and limited post-repair inner diameters. This study proposes a plugging process using a solid-free multifunctional chemical plugging agent. By analyzing the causes of leakage in the Sazhong Development Zone and combining the hardening mechanism and plugging performance of the new agent, the plugging process is optimized, and its application effectiveness is verified. Field tests show that the agent can quickly penetrate leakage points and form a high-strength three-dimensional network plastic-steel structure with surrounding media, achieving a 100% success rate in plugging. The cost per well is reduced by 48% compared to traditional casing replacement methods, demonstrating significant economic benefits.

At present, most oil wells in Changqing oilfield are producing crude oil by water injection. Because of the complexity of reservoir geological structure and heterogeneity of formation internal structure, it is easy to cause problems such as low water injection efficiency; rapid increase of water cut, and even water flooding. In recent years, the technique of multi-slug chemical water shutoff has attracted much attention due to its wide spread, long validity period and selective water shutoff. The difficulty of this technology is how to realize the different performance requirements of different slugs. In this paper, a self-designed multi-slug water shutoff technology system, according to the characteristics and requirements of different slugs developed a new plugging agent formula and performance testing. In this paper, a self-designed multi-slug water shutoff technology system, according to the characteristics and requirements of different slugs developed a new plugging agent formula and performance testing. The results show that the plugging agent has good stability, water absorption and expansion, and has a wide range. When the concentration of plugging agent in the main section exceeds 0.5%, the water shutoff rate can reach over 99%. The sealing section plugging agent is a micro-expansion cement system. The system has the characteristics of small size, good homogeneity and high plugging strength. It can be used to plug the reservoir with high squeezing pressure and weak formation absorption capacity. This paper can provide some data support for the design of multi-stage plugging technology and the study of plugging agent formulation.

In oil and gas production, reservoir heterogeneity causes plugging removal fluids to preferentially enter high-permeability zones, hindering effective production enhancement in low-permeability reservoirs. Traditional chemical diverting agents exhibit insufficient stability in high-temperature, high-salinity environments, risking secondary damage. To address these challenges, this study developed a water-sensitive self-thickening emulsion, targeting improved high-temperature stability, selective plugging, and easy flowback performance. Formulation optimization was achieved via orthogonal experiments and oil–water ratio adjustment, combined with particle size regulation and viscosity characterization. Core plugging experiments demonstrated the new emulsion system’s applicability and diverting effects. Results showed that under 150 °C and 15 × 104 mg/L NaCl, the emulsion maintained a stable viscosity of above 302.7 mPa·s, with particle size D50 increasing from 31.1 μm to 71.2 μm, exceeding API RP 13A’s 100 mPa·s threshold for acidizing diverters, providing an efficient plugging solution for high-temperature, high-salinity reservoirs. The injection pressure difference in high-permeability cores stabilized at 2.1 MPa, significantly enhancing waterflood sweep efficiency. The self-thickening mechanism, driven by salt-induced droplet coalescence, enables selective plugging in heterogeneous formations, as validated by core flooding tests showing a 40% higher pressure differential in high-permeability zones compared to conventional systems.