Speaker
Description
To clarify the flow capacity evolution mechanisms for hydraulic fracture networks for deep shale gas reservoirs, is a theoretical prerequisite for accurate production prediction and production strategies optimization. Given that the shale gas flow is characterized by multi-scale and multi-field coupling, the influence of water-rock interactions and in-situ stress change on seepage capacity during different flow zones remains insufficiently understood, and a unified mathematical characterization model has yet to be established. To address these challenges, the mechanisms and mathematical representation of seepage capacity for water-invaded fracture networks was investigated in this study by means of experimental method upgrades and theoretical model innovation. Firstly, a physical simulation method for high-pressure one-dimensional invasion of shale fracturing fluid was developed. It was firstly determined that under high injection pressure (45 MPa) condition, the thickness of the invaded zone of fracture networks with high-permeability (0.0068 mD) could generally reach from 4 to 7 cm. Furthermore, it was demonstrated that fracturing fluid was predominantly distributed within weakly supported fracture networks, with minimal invasion into matrix pores. Using micro-CT scanning and nano-indentation techniques, it was further revealed that fracturing fluid invasion can induce the formation of interconnected micro-fractures in the invaded zone and weaken the cementation between solid particles, resulting in a reduction of the elastic modulus by over 50% due to shale hydration and expansion. Finally, stress-sensitive flow experiments were designed for different flow regions within water-invaded fracture network, and thereby the permeability mathematical equations,with support performance, water invasion degree, and effective stress filed all considered, for water-invaded unsupported fracture zone were established. The results indicated that those shale cores with more developed fractures exhibited greater permeability loss by up to two orders of magnitude under high stress. In addition, the permeability stress sensitivity coefficient was determined to be not a constant. Instead, stress sensitivity was found to be positively correlated with water saturation and negatively correlated with effective stress. Under high-stress conditions (55MPa), the permeability of water-bearing unsupported fractures can decrease by 2–4 orders of magnitude. These findings confirmed that the flow capacity and stress sensitivity of water-invaded unsupported fracture zones are key factors governing the evolution of overall flow conductivity in fracture network regions during production. This study provides experimental insights and a theoretical foundation for multi-scale, multi-field seepage models establishment and optimizing flowback management plans optimization for for deep shale gas reservoirs.
| Country | China |
|---|---|
| Acceptance of the Terms & Conditions | Click here to agree |
