High-Efficient Exploration and Development of Oil & Gas from Ocean—2nd Edition

Nowadays, given the lack of resources that is threatening the globe, the exploitation and exploration of oil/gas, especially unconventional reservoirs, has become a priority [1,2,3]. The ocean is important to human life and research focused on related scientific issues [4,5]. For example, it has abundant unconventional resources such as shale and tight oil/gas, where subsurface formations can be the crucial solution to resource supply challenges [6,7].

Under such circumstances, this Special Issue concentrates on the exploration and development of oil/gas with high efficiency in the ocean. Some critical problems regarding the marine geometry and oil/gas exploitation exist currently. First, the evaluation and characterization of the targeted layers has lacked sufficient and comprehensive research, particularly in quantifying rock–physical property variations and clarifying reservoir formation mechanisms. Second, critical parameters such as permeability and mineral composition and diagenetic alteration patterns have not been fully analyzed due to limited well-logging data and 3D seismic interpretation methods, as well as less relevant models matching with them. Third, hydraulic fracturing has achieved enhanced oil/gas recovery with the development of engineering, but the mechanism of fracture control is as yet unclear. Last but not least, the research on the heterogeneity of lithofacies, nano-scale pore structures, and pore connectivity has shown certain inadequacies. To solve these problems, multiple studies were conducted for this Special Issue. The main contributions of each article are included below.

Contribution 1 discovered that Early Jurassic gypsum in East African basins controlled gas reservoirs because of the delaying of Lower Jurassic source rock maturation by gypsum. Post-183 Ma graben-deposited thick gypsum enhanced sealing, enabling conventional gas accumulation and shale gas potential in non-faulted areas.

Contribution 2 applied the combined finite–discrete element method (FDEM) to simulate laboratory earthquakes, promoting earthquake precursor identification and connecting laboratory experiments to natural seismic prediction. Using Light Gradient Boosting Machine (LightGBM) models and SHapley Additive exPlanations (SHAP) analysis, friction coefficients were predicted (R² = 0.94) with optimized critical features.

Contribution 3 revealed that mass transport deposits (MTDs) in the Qiongdongnan Basin uplifted the gas hydrate stability zone (GHSZ), accelerating hydrate dissociation. The resulting gas seepage formed spiny (moderate-speed) and domed (low-speed) seamounts, establishing a model combining MTDs, hydrate dynamics, and seabed geomorphology.

Contribution 4 defined the lower limits of porosity and permeability for Qiongdongnan Basin gas reservoirs in deltas, submarine canyons, and fans. Sedimentary facies, grain size, and transport distance controlled these thresholds, with Red River-sourced sandstones achieving superior porosity and permeability through CO₂ and organic acid-induced feldspar dissolution.

Contribution 5 discovered that the Huaiyuan Movement formed a regional unconformity in Jiyang Depression’s lower Paleozoic, with karst breccias and vertical zonation (vadose/underflow zones). Reservoir development in the Fengshan–Yeli–Liangjiashan Formations was controlled by sedimentary microfacies, dolomitization, and karstification. High-energy beach granular dolomite exhibited optimal cavity-type reservoirs along the unconformity.

Contribution 6 investigated cement sheath integrity failure during multi-stage fracturing in offshore tight oil wells. Triaxial cyclic loading tests (TCLTs) revealed cumulative plastic deformation, which reduced compressive strength and elastic modulus, and increased permeability. Micro-annuli formed during cyclic loading and matched with 3D finite element simulations, explaining failure mechanisms, thus aiding cement sheath design for offshore tight oil reservoirs.

Contribution 7 simulated the shallow marine shelf sedimentation in West Siberia’s Jurassic strata, which was influenced by “two depressions, one uplift” tectonics and tides. Tidal amplitude positively affected sand body parameters, while higher initial water levels limited tidal bars.

Contribution 8 established a hybrid-driven method combining physics-based models and machine learning to predict fluid sampling time in offshore formation testing, where a digital twin generated 6000 simulated cases with physics-enhanced feature correlation. The machine learning achieved 92% accuracy, optimized to 95%, enabling efficient real-time prediction for oil/gas development.

Contribution 9 focused on Ek2 shales in Cangdong Sag (Bohai Bay Basin) and analyzed 50 samples to reveal adsorbed and free oil contents, which primarily resided in >20 nm pores, controlled by organic matter abundance and thermal maturity not pore volume. High-S1 organic-rich shales were optimal exploration targets, guiding Ek2 shale development prioritization.

Contribution 10 proposed the Salmon Salar Optimization algorithm, mimicking salmon social behavior for high-precision searches. It performed better than benchmarks and resolved deep-sea probe design constraints, proving effective for complex engineering systems, thus advancing resource development efficiency.

Contribution 11 improved fracture permeability assessment for South China Sea granite reservoirs by integrating Darcy–Poiseuille laws with fracture parameters (angle, aperture, tortuosity). Confirmed by core experiment data, the model effectively evaluated single fractures but required refinement for intersecting cases, advancing permeability prediction in complex unconventional reservoirs.

Contribution 12 evaluated Eocene–Oligocene source rock potential in China’s northern Yinggehai Basin, where tectonic activity drove east-to-south sedimentary trough migration, favoring lacustrine, shallow marine, and deltaic facies. The Early Oligocene’s warm–humid climate, reducing conditions, and high productivity optimized organic matter preservation. The established sedimentary models showed significant hydrocarbon exploration potential in this region.

Contribution 13 established a rapid spontaneous imbibition method using thin shale samples to assess pore connectivity and ultimate imbibed porosity. The results from the Qingshankou Formation (Fm), Shahejie Fm, and Liushagang Fm showed distinct averages of connectivity and porosity. By standardizing sample dimensions and reducing testing time, it enhanced accuracy in assessing pore connectivity and ultimate imbibed porosity, enabling efficient sweet-spot evaluation within a day.