Fracture modelling is essential for understanding fluid flow in fractured hydrocarbon reservoirs, particularly in the phase of production; however, traditional discrete fracture network (DFN) modelling methods lack constraints that reflect characteristics of fracture development. Fractures or fracture networks exhibit a high degree of randomness; as such, it is difficult to model fracture characteristics. This paper proposes a new approach for DFN modelling constrained by seismic attributes. Firstly, the steerable pyramid method is adopted to improve seismic data resolution; secondly, multiple seismic attributes are extracted and combined into a composite attribute to characterize fracture spatial distribution; finally, a DFN modelling method is established by using the composite attribute as a location constraint. To verify the effectiveness of the approach, a case study is conducted in the Bonan Depression, in East China. The results show that, compared with the traditional DFN modelling methods, the DFN modelling with the location constraint create a more realistic fracture model which accurately reflects fracture distribution characteristics. The application demonstrates the potential of wide application prospects in fractured reservoirs.

With the tightening of global methane regulations (EU Methane Regulation 2024/1787, U.S. EPA GHG rules, OGMP 2.0) and China’s dual-carbon commitments, precise and traceable carbon accounting for natural gas gathering systems has become an urgent engineering imperative. To tackle manual workflows, data isolation, low precision, and poor traceability in carbon accounting for natural gas field surface systems, this study develops a four-tier digital delivery framework. The main goal is to establish an end-to-end engineering paradigm that transforms carbon management from passive post-hoc statistics into an active, traceable decision-support tool. By embedding carbon attributes into seed files and adopting a unified one-code-through equipment coding scheme, static design data, dynamic SCADA measurements, and emission factor databases are interoperably consolidated within a central data hub. The hub implements a three-stage progressive accounting workflow and closed-loop emission mitigation. Methodologically, a three-tier progressive accounting model (Tier 1: system-level, Tier 2: process-level, Tier 3: equipment-level) is constructed, with Tier 3 supported by OGMP 2.0 source-level emission factors locally calibrated against 386 field LDAR measurements. Deployed at Gas Field A, the framework realizes full diagram-model consistency and narrows systematic error from ±30% to ±3.5%. Tier-2 accounting quantifies gathering, compression, and dehydration emissions at 322,000, 504,300, and 162,500 tCO₂e, while Tier-3 analysis pinpoints reciprocating compressors and heaters as the primary contributors (51.70% of total emissions). Optimizations including compressor energy conservation, enhanced LDAR, and waste heat recovery provide an estimated annual mitigation potential of 97,400 tCO₂e (10.10%). In conclusion, this framework mitigates data fragmentation and accuracy defects, delivering a transferable technical route for oil and gas operators to advance methane abatement and dual-carbon targets.

Oil–water emulsions formed by heavy crude oil from Block A of the YT Oilfield during production and transportation are strongly influenced by the oil’s high viscosity and density and by its abundant resins and asphaltenes. Such emulsions can increase shear viscosity and flow resistance and may even undergo phase inversion. To clarify these behaviors, the rheology, viscosity–temperature characteristics, density, water cut, and SARA composition of the heavy oil were measured. The effects of emulsification temperature, stirring rate, salinity, and water cut on emulsion phase inversion and stability were then investigated. The oil exhibited weakly non-Newtonian behavior at 0–10 °C and Newtonian behavior at 20–60 °C. Its viscosity at 50 °C was 1323.4 mPa·s, and its density at 20 °C was approximately 0.96 g/cm³. The water cut was 0.05%, and the combined resin and asphaltene content was about 40%, with resins as the dominant fraction. With increasing water cut, the shear viscosity of the emulsion first rose and then declined, reaching a maximum at the phase inversion point. A higher emulsification temperature shifted the inversion point toward a higher water cut and increased the shear viscosity at inversion. Stirring rate and salinity did not change the position of the inversion point; however, a higher stirring rate increased the shear viscosity at inversion, whereas a higher salinity decreased it. Orthogonal range analysis showed that the factors affecting shear viscosity were ranked as follows: water cut > emulsification temperature > salinity > stirring rate. These findings provide an experimental basis for viscosity reduction, gathering and transportation optimization, and phase inversion control in the YT Oilfield.