In 2017, Well XWD1 drilled in the Wensu Salient, northwest Tarim Basin achieved the first hydrocarbon discovery in Proterozoic metamorphic rocks within the western basin of China. However, uncertainties regarding reservoir characteristics, hydrocarbon origins, and accumulation mechanisms have constrained further evaluation and exploration planning. Based on various hydrocarbon exploration data and experimental analyses from the region, this study conducts a comprehensive analysis of regional tectonic evolution, reservoir characterization, and hydrocarbon source correlation. Furthermore, it establishes a hydrocarbon accumulation model for metamorphic rock reservoirs and assesses their resource potential. It is found that: 1) the metamorphic strata have suffered extensive uplifts and denudations since the Paleozoic till the late Neogene, and extensively reformed by a northeast-trending boundary fault system, thus resulting fractured weathering crust reservoirs beneath the regional unconformity; 2) the metamorphic reservoirs exhibit ultra-low porosities typically around 4%, and low permeabilities ranging from 0.061 mD to 1.5 mD; 3) the discovered crude oil is characterized of typical terrestrial genesis associated with the northeastern Baicheng Sag, and was accumulated at approximately 17 Ma and 5 Ma; 4) the collected gas featured a mixed origin, which might derive from overmature marine source rocks in the Awati Sag, the marine oil cracking, and terrestrial source rocks in the northeastern Baicheng Sag, respectively; 5) the most promising metamorphic traps cover an area of 386.7 km², with a preliminary resource estimate of up to 57 million tons, implying significant exploration potential.

Following the maturation of shallow and medium-depth exploration, the petroleum industry is transitioning its focus to deep and ultra-deep formations. Field evidence shows that, even under extreme conditions of high temperature, high pore pressure, and high stress, some reservoirs retain anomalously high porosity and permeability, contradicting traditional compaction models. This paradox can be better explained through multi-field coupling, where temperature, pore pressure, and stress interact competitively and cooperatively to reshape compaction, fracture behavior, and fluid-rock interactions. Such interactions may induce brittle–ductile transitions that form semi-ductile permeability corridors, or cause localized enrichment when stress contrasts restrict fracture propagation and fluid accumulation promotes episodic reactivation. These insights shift the interpretation of deep reservoirs from single-factor models to a coupling-based framework, offering new directions for evaluation and exploration.