Reservoir rocks of the Pearl River Mouth Basin’s Lufeng Sag have low porosity (average porosity 12.6%) and low permeability (average permeability 16.5 mD), requiring hydraulic fracturing to obtain economic production of oil and gas. To contribute to the understanding of these reservoirs, and to promote successful production in the region, we analyzed the mechanical properties of tight sandstone. Moreover, we introduced the shear/tensile strength factor, in combination with the fracture toughness and horizontal stress difference coefficient, as an innovative approach to characterize the ease of forming a complex fracture network after reservoir fracturing. Based on this, we established a fracability evaluation model suitable for offshore low-permeability sandstone reservoirs by an analytic hierarchy process from the perspective of whether the reservoir can form an effective transformation volume and complex fracture network after fracturing. The results indicate that the primary minerals of the target reservoir are quartz and clay minerals, and the natural fractures are not developed. The mechanical properties exhibit a high Young’s modulus (ranging from 30.4 to 34.4 GPa) and high compressive strength (with cohesion between 41 and 45 MPa and an angle of internal friction between 31.0 and 33.5°). The relatively low tensile strength and fracture toughness values are conducive to fracture initiation and extension during the fracturing process. Through the fracability evaluation model constructed in this paper, the depth interval at 4155.1–4172.1 m is identified as a high-quality fractured layer. The results of this study not only provide theoretical guidance for target well and formation selection in the Lufeng Sag, but also have important practical implications for increasing oil and gas production from tight sandstone reservoirs.

Erosion wear is a common failure form of slotted screen in service. In this paper, based on CFD software and sand production data of a gas field in the Tarim Basin, the particle velocity and shear force at the slot of the flow field in the sieve tube were studied to determine the maximum area of erosion; at the same time, the velocity, viscosity, particle size and concentration of sand-carrying fluid were analyzed by orthogonal test, and the regression model of multi-factor maximum erosion rate was established. ① Through the analysis of the four factors on the degree of dependent variables, the order of the primary and secondary factors are: sand-carrying liquid flow rate, particle concentration, fluid viscosity, particle diameter, the effect of fluid viscosity and particle diameter on erosion rate is relatively small; ② According to the analysis of variance and range, the combination scheme of minimum erosion generation is obtained, and the calculation model of the erosion rate of the slotted screen is established. In order to reduce the erosion and abrasion in the actual oil and gas production process, the reasonable flow control and precise sand control method design and precision selection can be adopted; it provides a design basis for sand control and long-term effects of production in high-yield gas field.

In the later stages of gas field development, corrosion and erosion wear often occur in elbow-shaped connections used for gas transportation. Combined with laboratory corrosion experiments, the paper is based on CFD to study the distribution characteristics of pressure and velocity in the flow field for the elbow with pre-set corrosion defects. Simultaneously, the specific procedure is designed to track the formation of Dean vortices, thereby revealing the impact patterns of different corrosion defect features on the erosion outcomes of the elbow. Accordingly, the effect of different arrangement, number and form of corrosion defects on erosion wear was systematically analyzed. The results show that: (1) A comparative analysis of the three different defect distribution forms indicates that erosion occurs mainly at the bend near the outlet Section (45° ~ 60°). Double corrosion defects in the radial distribution will significantly accelerate the rate of pipe erosion, changing the location of maximum erosion rate. (2) By controlling the number of corrosion defects to represent the size of the corroded area, the study reveals as the number of defects increases, the rate and area of erosion in surface of the target material increases significantly. Thus, the area of the corrosion will explicitly change the effect of erosion. (3) As the depth of the defects (corrosion rate) increase, the erosion rate around the radial and axial defects increases exponentially compared to the absence of corrosion, reaching a maximum of 7.8 × 10⁻⁶ kg/(m²·s). Corrosion and erosion are two complementary forms of damage to pipe in the production process. The presence of corrosion defects leads to faster erosion rates and changes in the overflow area, reducing service life. Hence, only a reasonable control of both types of wear can ensure the longevity of gas production and transportation.

The oil and gas resources in the deep Paleogene system of the South China Sea are abundant. However, due to its poor reservoir physical properties and strong heterogeneity, the deep Paleogene system needs to be commercially exploited by hydraulic fracturing technology. In view of the challenges of offshore low-permeability reservoirs, large-scale fracturing is not allowed because of the limited operation sites and complex string structure. Taking the H oilfield in the South China Sea as the target, based on the concept of the integration of geologic and engineering techniques, parameters such as the number of fracturing stages and the fracture length were optimized by a numerical simulation, and a study on the slurry rate and fracturing scale was carried out based on the type of fracturing and the pipe string structure. The results show that multistage fracturing technology is available in low-permeability offshore oil fields. It is suggested to adopt networking fracturing technology with a “slick water + high slurry rate” framework. A higher rate is recommended, and the fracturing scale of each stage should be 50 m³ of the sands and 700 m³ of the fluids. This research provides a new model for offshore low-permeability oilfield development.