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The development of tight oil reservoirs in the Mahu conglomerate formation poses formidable challenges, marked by pronounced reservoir heterogeneity, significant horizontal bidirectional stress difference, the absence of natural fractures, and poor reservoir physical properties. In pursuit of a more economically efficient development strategy, a field trial involving tight well spacing and stereoscopic development was initiated for the first time in the Ma131 well area. Despite achieving a relatively high overall recovery rate in the trial area, the economic benefits fell short of expectations, prompting an urgent need for well spacing optimization.This study adopts an integrated approach that combines geological and engineering principles to establish a comprehensive method and process for optimizing the well spacing of stereoscopic well networks. Additionally, a method for rapidly fitting the hydraulic fracture network model under conditions involving multiple wells and fracturing stages is proposed, combining fracturing parameters and treatment pressure response characteristics. The key steps involve a systematic reservoir engineering analysis, utilizing unconventional fracture models based on detailed geological and geomechanical models to simulate complex fracture networks and match the history treatment pressure. The process further includes coupled reservoir numerical simulation for historical production matching. Well spacing optimization in the Ma131 stereoscopic development demonstration area was achieved through an integrated simulation of hydraulic fracturing and production, with validation conducted through a large scale well spacing field trial.The research results show that the analytical fracture length and the simulated fracture length can be mutually verified. The fractures in horizontal wells of the Bai3 section are relatively long, with an average propped half fracture length of 70.1 m and an average hydraulic fracture height of 24.6 m. In the Bai2 section, horizontal well fractures are relatively short and exhibit layer-penetrating effects, with an average propped half fracture length of 61.1 m and an average hydraulic fracture height of 28.3 m. Under conditions of certain permeability in the formation, the well spacing for both development layers can be appropriately expanded to a range of 200~300 m, ensuring an increase in individual well productivity and economic benefits while maintaining a high recovery rate.The proposed optimized well spacing range can be extended to similar development layers within the same well area, based on the well spacing field trial validation results. And the well spacing optimization method and process proposed in this study, utilizing a stereoscopic well network, can serve as a valuable reference for other unconventional oil and gas reservoir types.