The formation of barium sulfate scale is a persistent and formidable challenge across various industrial processes. In order to effectively mitigate this problem, this study proposed the development of an innovative azacrown ether-based macrocycle descaling agent. Using density functional theory, an in-depth analysis of the surface energy of different barium sulfate crystal facets was carried out, together with a detailed investigation into the adsorption properties of the functional groups on the (001) surface. A further comprehensive investigation was carried out to determine how changes in the nitrogen and oxygen atoms in the crown ether framework influence its adsorption affinity to barium ions. In addition, a detailed analysis was carried out to elucidate the molecular interactions between crown ethers with pyridine carboxylic acid side chains and barium sulfate. The newly developed decalcifying macrocycle descaling agent exhibited superior adsorption performance, achieving an adsorption energy for barium ions approximately −4.1512 ev higher than that of conventional DTPA decalcifiers. This remarkable improvement is mainly attributed to the pivotal role of electrostatic forces in the coordination process between the macrocycle descaling agent and barium ions, with an electrostatic potential value reaching −143.37 kcal/mol. This discovery not only introduces a novel approach to the removal of barium sulfate scale but also highlights the significant potential of macrocycle chemistry in industrial applications.

The upper Shasi reservoir in the LN block is characterized by low abundance and greater depth, low porosity, low permeability, and low pressure. Due to high water injection pressure, the LN block has been developed in an elastic way. The natural productivity of oil wells in this block is low, but the productivity can be improved after fracturing. However, the field development effects show that the oil well has high initial production, but rapid decline and rapid pressure drop. At present, the recovery factor of this block is only 0.38%, and it is difficult to realize the economic and effective development of a difficult-to-develop block by conventional fracturing technology. Based on the geological characteristics of the LN block and the fracturing experience of adjacent wells, the fracturing process is optimized and the key fracturing parameters are determined in combination with the sand body distribution and logging curve of well LN-1. Due to the low-pressure coefficient and medium water sensitivity of well LN-1, a new high-efficiency stimulation fracturing fluid system was selected and the formula of the fracturing fluid system was formed. The cluster perforating process is optimized according to reservoir differences, and the perforating “sweet spot” is optimized. Based on the sand body spread point of well LN-1, the high diversion channel technology and the temporary plugging and turning fracturing technology are selected to form a new fracturing and stimulation technology suitable for this kind of oil reservoir. A fracturing test was performed in layers 17# (electrical sequencing number) and 22# of well LN-1. The initial oil production was 12.5 t/d, and the stimulation effect was significantly higher than the 8.3 t/d (general fracturing) of adjacent wells. At present, the well LN-1 has been producing steadily for more than six months, and the results of this work can provide technical guidance for the efficient development of low-abundance and greater-depth oil reservoirs that are difficult to develop.

The oil layers in the Dongying Formation offshore oilfield are severely contaminated. The near-wellbore reservoir pore throats are blocked, which seriously affects the development effect. It has become urgent to implement acidizing stimulation measures. However, the target reservoir is deeply buried, has high reservoir pressure, and is highly sensitive. These factors result in high pressure during acidizing operations, a long single-trip time for raising and lowering the tubing string, and high costs. Moreover, acid that is not promptly returned to the surface after acidizing can cause secondary pollution to the reservoir. This work proposes an integrated tubing string to perform reverse displacement and reverse squeeze. With this, acid can be injected into the formation through the annulus between the casing and tubing. The residual acid and its post-acidizing derivative residues are rapidly lifted to the surface by the reciprocating suction action of the return pump. Based on this, the structure and specifications of the acidizing-flowback tubing string are designed through the flow rate analysis method. The tubing string is mainly affected by mechanical effects, including buoyancy, piston effect, flow viscosity effect, helical bending effect, temperature difference effect, and expansion effect. The maximum deformations are 1.4 m, 1.9 m, 0.18 m, 2.7 m, 1.8 m, and 2.5 m, respectively. The total deformation is less than 3 m. Simulation results from three groups of oil wells at different depths indicate that the axial force of the tubing string ranges from 400 to 600 kN. The stress ranges from 260 to 350 MPa, deformation is 1.1–2.4 mm, and the safety factor exceeds 3.0. This can effectively ensure the safety of on-site operations. Based on the actual field conditions, the acidizing-flowback tubing string is evaluated. This verifies the effectiveness of the acidizing-flowback tubing string. This research provides an economical and efficient operation process for acidizing operations in the Dongying Formation offshore oilfield. It achieves the goal of removing reservoir contamination and provides guidance for the unblocking and stimulation of low-permeability and sensitive reservoirs in the middle and deep layers of offshore oilfields.

The in situ emulsification synergistic self-profile control system has wide application prospects for efficient development on offshore oil reservoirs. During water flooding in Bohai heavy oil reservoirs, random emulsification occurs with superimposed Jamin effects. Effectively utilizing this phenomenon can enhance the efficient development of offshore oilfields. This study addresses the challenges hindering water flooding development in offshore oilfields by investigating the emulsification mechanism and key influencing factors based on oil–water emulsion characteristics, thereby proposing a novel in situ emulsification flooding method. Based on a fundamental analysis of oil–water properties, key factors affecting emulsion stability were examined. Core flooding experiments clarified the impact of spontaneous oil–water emulsification on water flooding recovery. Two-dimensional T1–T2 NMR spectroscopy was employed to detect pure fluid components, innovating the method for distinguishing oil–water distribution during flooding and revealing the characteristics of in situ emulsification interactions. The results indicate that emulsions formed between crude oil and formation water under varying rheometer rotational speeds (500–2500 r/min), water cuts (30–80%), and emulsification temperatures (40–85 °C) are all water-in-oil (W/O) type. Emulsion viscosity exhibits a positive correlation with shear rate, with droplet sizes primarily ranging between 2 and 7 μm and a viscosity amplification factor up to 25.8. Emulsion stability deteriorates with increasing water cut and temperature. Prolonged shearing initially increases viscosity until stabilization. In low-permeability cores, spontaneous oil–water emulsification occurs, yielding a recovery factor of only 30%. For medium- and high-permeability cores (water cuts of 80% and 50%, respectively), recovery factors increased by 9.7% and 12%. The in situ generation of micron-scale emulsions in porous media achieved a recovery factor of approximately 50%, demonstrating significantly enhanced oil recovery (EOR) potential. During emulsification flooding, the system emulsifies oil at pore walls, intensifying water–wall interactions and stripping wall-adhered oil, leading to increased T2 signal intensity and reduced relaxation time. Oil–wall interactions and collision frequencies are lower than those of water, which appears in high-relaxation regions (T1/T2 > 5). The two-dimensional NMR spectrum clearly distinguishes oil and water distributions.