Offshore low-permeability thin interbedded reservoirs contain significant oil reserves and are crucial for future development. However, due to the high cost and operational challenges associated with offshore fracturing, large-scale fracturing common in onshore fields is uneconomical. Furthermore, offshore low-permeability reservoirs often have sparse well placement and wide well spacing, in contrast to onshore low-permeability fields, which leads to low recovery. Additionally, there is a lack of comprehensive theory on optimizing the well patterns and fracture networks to maximize net income, highlighting the need for further research. This study tackles these issues in a low-permeability thin interbedded reservoir in the Bozhong Oilfield by using reservoir numerical simulation. First, fracture parameters, including fracture half-length and conductivity, are optimized for different well patterns. Subsequently, well pattern optimization is conducted under fractured conditions, targeting maximum net income under various conditions. The results indicate that when fractures are confined to a single reservoir layer and the main reservoir layer accounts for less than 36% of the development section, fractured directional well patterns yield a higher net income. Conversely, when fractures penetrate all reservoir layers, fractured horizontal wells with closer fracture spacing a higher number of fractures are the most profitable option, particularly in offshore fields with large well spacing. The findings provide critical insights into optimizing well patterns and fracture network designs for offshore low-permeability thin interbedded reservoirs.

China is actively advancing offshore oil and gas exploration and development, focusing on addressing the technical challenges associated with resource extraction in shallow waters. The shallow-water subsea tree development model has gradually been applied in such environments, alleviating some construction difficulties. However, it still poses well control risks that require systematic analysis and quantitative evaluation. Given that the blowout preventer (BOP) is located on the platform and the shallow-water subsea tree is only used during certain drilling stages, this study divided the drilling process into two phases: the first three sections and the fourth section. Based on the “man–machine–material–environment” analytical framework and an improved system-theoretic process analysis (STPA), a control model for the construction phases was developed. Fault tree analysis (FTA) was then employed to identify comprehensively the potential risks from the platform to the wellbore in both phases. Subsequently, the decision-making trial and evaluation laboratory (DEMATEL) method were used to assess quantitatively the well control risks. Using the average weight as the evaluation criterion, high-risk factors exceeding the average weight in each phase were identified. The results indicate that in the shallow-water subsea tree development model, well control risks in the first three drilling sections primarily stem from human errors and equipment failures, while risks in the fourth section are mainly caused by damage to the subsea tree itself. The identified risk factors provide a theoretical basis for enhancing well control safety management in the shallow-water subsea tree development model.

At present, many offshore oil fields are facing problems, such as pollution-induced near-well zone blockage, poor inter-well connectivity, and strong vertical heterogeneity, which lead to insufficient formation energy and low production in the middle and late stages of development. It is necessary to develop a new technology to overcome these issues. In this regard, water-injection-induced dilation technology, which was already proven to have positive effects on loose sandstone reservoirs, was controversially applied to an offshore low-permeability reservoir. To investigate whether the water-injection-induced dilation technology is suitable, experiments were conducted to analyze the dilation potential of offshore low-permeability sandstone reservoirs, namely, X-ray diffraction, laser particle size analysis, physical simulation, computed tomography scan, and electron microscope scanning experiments. The X-ray diffraction experiments showed that the samples had more than 80% non-clay mineral content and a high brittleness index, which meant more complex microfractures under water injection. Particle size analysis experiments revealed that the particle size was mainly between 10 μm and 100 μm, and thus belonged to coarse silty sand. According to the sorting grade, the sample particle size distribution was uniform and the reservoir was more prone to dilation. The true triaxial physical simulation showed that a volumetric dilation zone occurred around the wellbore, where complicated microfractures occurred. This paper provides adequate evidence and mechanisms of dilation potential for an offshore low-permeability sandstone reservoir.

To address the deformation and instability characteristics of a formation after an offshore shallow gas well blowout, a theoretical model of formation deformation caused by shallow gas blowouts was constructed, based on porous elastic medium theory and incorporating the sand-out erosion criterion. The spatiotemporal dynamics of formation subsidence were then investigated, and deformation patterns during a blowout were analyzed under various factors. The results indicate that, following a blowout, a shallow gas formation near a borehole experiences significant subsidence and uplift at the upper and lower ends, with the maximum subsidence values at 12 h, 24 h, 36 h, and 48 h post blowout being 0.072 m, 0.132 m, 0.164 m, and 0.193 m, respectively. The overlying rock layer forms a distinctive “funnel” shape, exhibiting maximum subsidence at the borehole, while more distant strata show uniform subsidence. The effective stress within the shallow gas stratum and surrounding rock layers increases gradually during the blowout, with lesser impact in distant areas. The ejection rate and sand blast volume demonstrate an exponential change pattern, with a rapid decline initially and later stabilization. Formation deformation correlates positively with factors like burial depth; shallow gas layer extent; pressure coefficient; sand blast volume; gas blowout rate; and bottomhole difference pressure. Formation pressure, ejection rate, and bottomhole difference pressure have the most significant impact, followed by sand blast volume and burial depth, while the extent of the shallow gas layer has a less pronounced effect. These simulation results offer valuable theoretical insights for assessing the destabilization of formations due to blowouts.

In the process of natural gas hydrate extraction, especially in offshore hydrate extraction, the multiphase flow inside the wellbore is complex and prone to flow difficulties caused by reservoir sand production, leading to pipeline blockage accidents, posing a threat to the safety of hydrate extraction. This paper presents experimental research on the migration characteristics of micrometer-sized sand particles entering the wellbore, detailing the influence of key parameters such as sand particle size, sand ratio, wellbore deviation angle, fluid velocity, and fluid viscosity on the sand bed height. It establishes a predictive model for the deposition height of micrometer-sized sand particles. The model’s predicted results align well with experimental findings, and under the experimental conditions of this study, the model’s average prediction error for the sand bed height is 12.47%, indicating that the proposed model demonstrates a high level of accuracy in predicting the bed height. The research results can serve as a practical basis and engineering guidance for reducing the risk of natural gas hydrate and sand blockages, determining reasonable extraction procedures, and ensuring the safety of wellbore flow.

As oil and gas exploration extends into ultra-deep land and sea environments, developing accurate and efficient hydraulic computation models is essential for improving safe and effective drilling techniques. This paper presents a non-isothermal transient hydraulic computational model developed in MATLAB, which integrates the wellbore temperature and flow fields to simulate temperature, pressure, and phase distributions during gas-liquid-solid three-phase flow in deep wells with large annular ratios. Through example calculations, we examine the effects of the annular ratio and convective heat transfer coefficient on wellbore flow. Results indicate that increasing the annular ratio decreases bottom-hole temperature and pressure; specifically, increasing the annular ratio from 1.5 to 3.5 results in approximately a 10% reduction in pressure and a temperature drop of over 50 K. Additionally, when considering convective heat transfer in the drilling fluid, wellbore temperature increases gradually with depth, peaking at about 1/8 of the total well depth. These findings provide theoretical guidance for designing drilling programs and selecting well control strategies for ultra-deep wells.