Evaluation of fluid mobility and factors influencing the deep tight sandstone of the third member of the Shahejie formation in the Jiyang depression, Bohai Bay Basin

The Paleogene lacustrine delta–turbidite facies sandstones of the Third Member of the Shahejie Formation (Es₃) in the Linnan Depression have abundant tight oil resources. Movable fluids can independently characterize reservoir fluid mobility and recovery efficiency, which are essential for accurate reservoir assessment and efficient development and evaluation of oil reservoirs. Systematic research on the distribution patterns and controlling factors of movable fluids in the tight sandstone reservoirs of the Linnan Depression is lacking. To address this gap, this study employs multi-gradient centrifugation combined with Nuclear Magnetic Resonance (NMR) to characterize fluid mobility and determine the lower limit of the movable fluid pore radius (LLMPR) in various lithofacies of lacustrine delta-turbidite facies sandstones. In conjunction with core descriptions, thin section observations, X-ray diffraction (XRD) analysis, gas permeability tests, and High-pressure mercury injection (HPMI) data, this research explicates the macroscopic impacts of depositional and diagenetic processes and the microscopic effects of pore structure on fluid movability. The study identifies four lithofacies (delta front facies massive siltstone (DFMS)、delta front facies laminated siltstone (DFLS)、slump turbidite facies siltstone (STS), and slump turbidite facies calcareous siltstone (STCS)) with corresponding pore structures and space types (I-micropores, II-micropores, mesopores, macropores). DFLS and DFMS feature well-developed primary intergranular and intragranular dissolution pores, high HPMI mercury intrusion saturation, and large average pore radius, primarily contributing to fluid mobility through mesopores and macropores with movable fluid saturation of 56.1% and 52.9%, respectively. In contrast, STS and STCS mainly comprise mesopores and micropores with lower movable fluid saturation of 33.5% and 27.5%, influenced by clay filling and carbonate cementation, resulting in poor connectivity. Macroscopically, better-sorted delta-front sand bodies develop connected pores within rigid quartz and feldspar particle frameworks, increasing the proportion of mesopores and macropores. Microscopically, reservoir properties, RQI, maximum invasion saturation, displacement pressure, and average pore radius significantly influence fluid movability. As centrifugal force increases, fluid output from pores slows, and the LLMPR decreases exponentially. At an optimal centrifugal force of 2.75 MPa, the LLMPR in the Linnan Depression is calculated to be 0.033 μm. Based on these insights, a fluid mobility model for lacustrine delta front-turbidite facies tight sandstones is established, identifying DFMS and DFLS as the optimal lithofacies for movable fluids. This study provides theoretical references for understanding and effectively developing deep tight sandstone reservoirs.