Yurun Rui

Geothermal field characteristics fundamentally control hydrocarbon generation, phase evolution, and preservation, and are particularly critical in deep to ultra-deep hydrocarbon exploration. The Tazhong Uplift is a key area for deep to ultra-deep hydrocarbon exploration in the Tarim Basin; however, its deep thermal regime and controlling factors remain inadequately characterized. This study aims to accurately characterize the geothermal field and crustal thermal structure of the Tazhong Uplift to provide thermal constraints for ultra-deep exploration. We systematically compiled system steady-state temperature data from 24 wells, bottom-hole temperature (BHT) data from 51 wells, and rock thermal property measurements. Using the one-dimensional steady-state heat conduction equation, present-day geothermal gradients at 0–5000 m depths and terrestrial heat flow were calculated, and formation temperatures were predicted at deep horizons (6000–10,000 m). Results show geothermal gradients at 0–5000 m of 18.5–26.7 °C/km (average 23.06 °C/km) and heat flow of 39.3–59.8 mW/m² (average 48.1 mW/m²), both significantly higher than basin averages. The distribution of the geothermal field is jointly controlled by basement structure and rock thermophysical properties. Basement highs typically exhibit elevated geothermal gradients and high heat flow. The dual-layer structure of “upper clastic rocks (low thermal conductivity, high heat production) + lower carbonate rocks (high thermal conductivity, low heat production)” results in a vertical differentiation characterized by a “high-upper, low-lower” geothermal gradient. Notably, the thick Upper Ordovician mudstone acts as a regional “thermal blanket”, significantly reducing geothermal parameters in the northern slope area. Crustal thermal structure analysis indicates a “cold mantle” signature of cratonic basins, with a thermal lithosphere thickness of ~134–145 km and a Moho temperature of ~581 °C. These findings reveal that despite the ultra-deep burial (>8000 m), the “cold” thermal background and the thermal regulation of the overlying diverse lithologies maintain formation temperatures within a range favorable for liquid hydrocarbon preservation, significantly expanding the depth limit for oil exploration in the Tarim Basin.

A conventional linear pre-stack inversion method under the conventional stationary convolution model is limited by the assumptions of weak formation contrast change and small angle incidence and fails to take into account the amplitude attenuation of seismic wave propagation. Meanwhile, the resolution and precision of oil and gas evaluation and fracture characterization of shale reservoirs under complex geological conditions are low because the compaction and non-connectivity characteristics of deep shale reservoirs are not fully considered. Therefore, porous rock pores are divided into connected pores and disconnected pores. Combined with the effect of compaction on dry rock skeleton, a petrophysical model considering the compaction and pore dysconnectivity of deep shale reservoir is developed. The quantitative relationship between transverse isotropy with a vertical axis of symmetry (VTI) stiffness matrix, rock physical properties, and fracture parameters is established in this model. It provides a more accurate scheme for the original physical modeling of deep shale. This relationship is incorporated into the exact VTI reflection coefficient equation, and a nonstationary convolution operator is derived by using the attenuation theory of seismic wave propagation. A nonstationary pre-stack nonlinear direct inversion method of fracture parameters of shale reservoirs with horizontal fractures is proposed, which Improves the resolution and accuracy of shale reservoir gas bearing and fracture characteristics prediction. It provides a new way to accurately characterize the fracture development and oil-bearing property of shale reservoirs. A model test and field data test verify the effectiveness of this method.

The tight reservoirs in the Sichuan Basin generally contain water and have complex gas–water relationships. The dynamic changes and main controlling factors of natural gas injection are unclear, which has had a serious impact on the exploration and development of tight sandstone gas. This article selects samples from Yongqian and Qiulin gas fields to characterize the reservoir characteristics of the tight sandstone samples in the Xu-3 section. Nuclear magnetic resonance technology is applied to plan gas–water injection simulation experiments, and the dynamic changes in pore water and gas content during the natural gas injection of tight reservoir rock samples are characterized. The main controlling factors are analyzed based on the theory of nuclear magnetic resonance singlet and multifractal models. The results showed that material composition, pore type, structural characteristics, and physical properties cooperatively control the charging characteristics of natural gas. There was no significant difference in mineral content among the tight sandstone samples, and the pore morphology types were mainly parallel plate-like pores and fracture-type pores. There were significant differences in the pore structure characteristics of the samples with varying burial depths. The heterogeneity of gas-bearing pores is negatively related to the buried depth of tight sandstone, is a coupling relationship with quartz and feldspar content, and is negatively correlated with pore permeability. The stronger the sample heterogeneity, the more unfavorable it is for natural gas migration and accumulation.