Zhongying Zhao

The viability of shale in-situ conversion is governed by the coupled evolution of pore structure and flow capacity during heating-driven solid–fluid reactions, yet dynamic effective porosity and permeability remain difficult to quantify under conversion conditions. Here we integrate thermo–physicochemical interpretation with an experimental–evaluation workflow that enables time-resolved estimation of produced fluids and reservoir properties during shale in-situ conversion. Effective porosity is evaluated from a produced-fluid mass–volume balance (oil, gas and water) and shows good agreement with independent plug-based porosity increments measured at multiple preset temperatures. To quantify permeability without imposing forced flow and thereby disturbing internal fluid equilibrium, we develop an in-situ gas pressure-transient apparatus and conduct continuous heating tests over ~89 days. Permeability exhibits an initial reduction followed by a rapid increase associated with the onset of large-scale expulsion at ~310 °C, with minimum permeabilities of ~3×10-4 mD (parallel to bedding) and ~3×10-5 mD (perpendicular). We further establish correction relationships to account for the effects of heating rate and stress/pressure conditions, enabling translation of laboratory estimates to representative subsurface scenarios. The resulting framework provides practical tools for dynamic reservoir-property assessment and production forecasting in shale in-situ conversion and is demonstrated through application to a field pilot in low-maturity Chang 7 shale, Ordos Basin, China.

Under in-situ conversion process of shale oil characterized by ultra-high temperature, high pressure, and multiple corrosive media, the corrosion behavior and mechanical degradation of S13Cr martensitic stainless steel were systematically investigated. The results show that the corrosion rate of S13Cr in this environment reached as high as 1.8146 mm/a. A typical bilayer corrosion film was formed on the steel surface. The outer layer, composed of loose and porous Fe3O4 together with island-like Fe5Ni4S8, exhibited weak adhesion to the substrate and was prone to large-area spallation. The inner layer consisted of FeCr2O4 doped with FeS, whose structural integrity and protective capability were significantly reduced, ultimately leading to the simultaneous degradation of corrosion resistance and mechanical properties. These findings are of great significance for evaluating the service life of S13Cr under realistic in-situ conversion process and provide a fundamental basis for the selection and development of corrosion-resistant materials for such harsh environments.

This study investigates the natural gas diffusion coefficients in tight sandstones, emphasizing the Sulige area′s geological conditions. Through experimental measurements and the simulation of natural gas diffusion processes, we explore the impact of various geological factors—including temperature, pressure, porosity, permeability, pore throat radius, and clay content—on gas diffusion coefficients. Our findings reveal that temperature and porosity positively influence diffusion, aligning with molecular collision theory, and displaying a linear relationship with the diffusion coefficient, respectively. Conversely, pressure and clay content negatively affect diffusion, with coefficients showing exponential decreases under higher pressures and increased clay content. Permeability and pore throat radius enhance diffusion in a logarithmic manner. Building on these individual relationships, we developed a multifactor model to accurately predict the gas diffusion coefficients in tight sandstones under diverse geological settings. Validation with the actual sample measurements confirms the precision of our model and its applicability across different geological periods and conditions. Our research offers valuable insights into understanding natural gas diffusion in tight sandstones, providing a solid foundation for further exploration and exploitation strategies in similar geological settings.

In-situ conversion technology is a sustainable and effective method of recovering medium-low maturity shale, which can be produced with oil resources expected to exceed global total proven oil reserves. Nevertheless, criteria and procedures for grading such shale oil resources are lacking. We present a combination of distinct faceis and theoretical economic index (I_e) to grade the in-situ conversion shale oil resources of Chang 7 Member in the Ordos Basin and Nenjiang Formation in the Songliao Basin. This shale oil resource was categorized into four classes: invalid, valid, sweet-spot and core resource. For the shale dominated by type II kerogen (Chang 7), total organic carbon (TOC) values at 6%, 9%, and 12%, hydrocarbon generation potential (S₁+S₂) values at 15 mg/g, 30 mg/g, and 50 mg/g, and I_e at 2, 3, and 4, respectively, represent the boundary of the four resource grades. For the shale dominated by type Ⅰ kerogen (Nenjiang), TOC values at 4%, 6%, and 8%, S₁+S₂ values at 19 mg/g, 32 mg/g, 48 mg/g, and I_e at 2, 3, and 4, respectively, represent the boundary of the four resource grades. Our research provides a feasible practical strategy for evaluating and predicting in-situ conversion shale oil resources in lacustrine basins.

The tectonic background and sedimentary environment during the transition period from the Ordovician to Silurian have been widely studied by many scholars. This study focuses on the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation in the Bajiaokou profile at the southern margin of the Qinling Orogenic Belt in southern China. In order to study the aggregation mechanism of organic matter, geochemical proxies were proposed, including redox proxies (V, V/Al, U, U/Al, Mo, and Mo/Al), paleoproductivity proxies (P, P/Ti, Ba, Ba/Al, and Si_XS), paleoclimate proxies (CIA), and terrigenous flux proxies (Al, Zr, and Zr/Al). In addition, Al-Co[EF] × Mn[EF] is used to provide information on paleoenvironmental parameters such as watermass restriction conditions. The redox proxies show that the Wufeng-Longmaxi shale is mainly accumulated under oxic-dysoxic conditions. During the shale deposition period of Wufeng-Longmaxi formations, the marine surface primary productivity in the southern Qinling area is generally low to moderate. The paleoclimate proxies show that from the Late Ordovician to the Early Silurian the southern Qinling area generally had a warm and humid climate. The upwelling current is widely developed in the northern margin of the Sichuan Basin and the southern margin of the Qinling area. Although the upwelling current was highly developed during the deposition of the Wufeng Formation in the Bajiaokou profile, the concentrated accumulation of a large amount of volcanic ash resulted in the low primary productivity of the ocean. During the sedimentary period of the Longmaxi Formation in the Bajiaokou profile, the development of seasonal upwelling currents and a small amount of volcanic ash supply increased the primary productivity to moderate, which provided a good material basis for the enrichment of organic matter, but the high detritus flux and the water body condition of oxic-dysoxic resulted in the slight enrichment of organic matter.

The Jimsar Sag is an important shale oil exploration target area in the Junggar Basin, northwestern China. The Permian Lucaogou Formation, with a thickness of 200–300 m, is the primary exploration target. High-frequency variation in lithology is a typical feature of the Lucaogou Formation, reflecting the fluctuation of the depositional environment and organic matter enrichment. The evolution of the depositional environment and accumulation mechanism of organic matter still need to be elucidated for the Lucaogou Formation. High-resolution sampling of the entire Lucaogou Formation was applied to a 248 m long core from Well JX in the Jimsar Sag to examine the depositional environment and organic matter enrichment. The findings unveiled that the Lucaogou Formation was deposited under a hot and arid climate, within the confines of a closed saline paleo-lake, where sediments endured an extended period of anoxic conditions, displayed periodic oscillations in paleo-temperature and paleo-salinity values over time, alongside a continuous rise in paleo-water depth. The predominant source lithology of the Lucaogou Formation is felsic igneous rock. Small-scale transgression and hydrothermal sedimentation occurred during the deposition of the Lucaogou Formation. The prevailing hot climate and enduring reducing environment fostered ideal circumstances for the enrichment of organic matter in the Lucaogou Formation. Due to different sedimentary environments and enrichment mechanisms, organic matter is enriched in two modes in the Lucaogou Formation.

It is well known that the existing horizontal-well-drilling and hydraulic fracturing technology used to achieve large-scale, cost-effective production from immature to low–moderate-maturity continental shale in China, where the organic matter mainly exists in solid form, is fairly ineffective. To overcome the obstacles, in situ conversion technology seems feasible, while implementing it in the target layer along with estimating the amount of expected recoverable hydrocarbon in such shale formations seems difficult. This is because there are no guidelines for choosing the most appropriate method and selecting relevant key parameters for this purpose. Hence, based on thermal simulation experiments during the in situ conversion of crude oil from the Triassic Chang 7₃ Formation in the Ordos Basin and the Cretaceous Nenjiang Formation in the Songliao Basin, this deficiency in knowledge was addressed. First, relationships between the in situ-converted total organic carbon (TOC) content and the vitrinite reflectance (Ro) of the shales and between the residual oil volume and the hydrocarbon yield were established. Second, the yields of residual oil and in situ-converted hydrocarbon were measured, revealing their sensitivity to fluid pressure and crude oil density. In addition, a model was proposed to estimate the amount of in situ-converted hydrocarbon based on TOC, hydrocarbon generation potential, Ro, residual oil volume, fluid pressure, and crude oil density. Finally, a method was established to determine key parameters of the final hydrocarbon yield from immature to low–moderate-maturity organic material during in situ conversion in shales. Following the procedure outlined in this paper, the estimated recoverable in situ-converted oil in the shales of the Nenjiang Formation in the Songliao Basin was estimated to be approximately 292 × 10⁸ tons, along with 18.5 × 10¹² cubic meters of natural gas, in an area of approximately 8 × 10⁴ square kilometers. Collectively, the method developed in this study is independent of the organic matter type and other geological and/or petrophysical properties of the formation and can be applied to other areas globally where there are no available in situ conversion thermal simulation experimental data.

It’s well known that existing horizontal well drilling and hydraulic fracturing technology that is used to achieve large-scale cost-effective production from immature to low-moderate maturity continental shale in China, where the organic matter mainly exists in the solid form is fairly ineffective. To overcome the obstacles, in-situ conversion technology seems feasible, while implementing it in the target layer along with estimating the amount of expected recoverable hydrocarbon in such shale formations seems difficult. This is because there is no guideline to choose the most appropriate method and select relevant key parameters for this purpose. Hence, based on thermal simulation experiments during the in-situ conversion of crude oil from the Triassic Chang 73 Formation in the Ordos Basin and the Cretaceous Nenjiang Formation in the Songliao Basin, this deficiency in knowledge was addressed. First, relationships between the in-situ converted total organic carbon (TOC) content and the vitrinite reflectance (Ro) of the shales and between the residual oil volume and the hydrocarbon yield was established. Second, the yields of residual oil and in-situ converted hydrocarbon were measured, revealing their sensitivity to fluid pressure and crude oil density. In addition, a model was proposed to estimate the amount of in-situ converted hydrocarbon based on the TOC, hydrocarbon generation potential, Ro, residual oil volume, fluid pressure, and crude oil density. Finally, a method was established to determine key parameters on the final hydrocarbon yield from immature to low-moderate maturity organic material during in-situ conversion in shales. Following the procedure outlined in this paper, estimated recoverable in-situ converted oil in the shales of the Nenjiang Formation in the Songliao Basin was estimated to be approximately 292×108 tons, along with 18.5×1012 cubic meters of natural gas, in an area of approximately 8×104 square kilometers. Collectively, the method developed in this study is independent from the organic matter type and other geological and/or petrophysical properties of the formation and can be applied to other areas globally where there isn’t any available in-situ conversion thermal simulation experimental data.

Previous studies have mainly focused on the source rocks of the 7th Member of Yanchang Formation (Chang 7 Member) in the Ordos Basin, with very few studies focusing on the extracts from the source rocks. These extracts have important guiding significance for studying the in situ conversion process of shale oil. Taking the shale source rock of the Chang 7 Member as an example, this paper selected the extract of shale source rock (i.e., retained oil), which has been less studied previously, as the sample to carry out the hydrocarbon-generating pyrolysis simulation experiment of a semi-open–semi-closed system. Seven groups of parallel simulation experiments were designed with a pressure of 20 MPa. The generated oil and gas were collected and quantified, and their geochemical characteristics were researched. In addition, the generated oil and gas were investigated from aspects of cumulative yield and net increased yield, and the chromatographic and mass spectral characteristics of the generated oil were also researched. Based on this, an inductive hydrocarbon generation model of retained oil in shale source rocks was established: slow hydrocarbon generation stage (300–320 °C), rapid hydrocarbon generation stage (320–360 °C), and residual oil pyrolysis stage (0.79%Ro–1.47%Ro). This study is of important significance to guide the research on the in situ conversion process of shale source rock.

The reservoir properties of low–medium-maturity shale undergo complex changes during the in situ conversion process (ICP). The experiments were performed at high temperature (up to 450 °C), high pressure (30 MPa), and a low heating rate (0.4 °C/h) on low–medium-maturity shale samples of the Chang 7 Member shale in the southern Ordos Basin. The changes in the shale composition, pore structure, and reservoir properties during the ICP were quantitatively characterized by X-ray diffraction (XRD), microscopic observation, vitrinite reflectance (Ro), scanning electron microscopy (SEM), and reservoir physical property measurements. The results showed that a sharp change occurred in mineral and maceral composition, pore structure, porosity, and permeability at a temperature threshold of 350 °C. In the case of a temperature > 350 °C, pyrite, K-feldspar, ankerite, and siderite were almost completely decomposed, and organic matter (OM) was cracked into large quantities of oil and gas. Furthermore, a three-scale millimeter–micrometer–nanometer pore–fracture network was formed along the shale bedding, between OM and mineral particles and within OM, respectively. During the ICP, porosity and permeability showed a substantial improvement, with porosity increasing by approximately 10-times and permeability by 2- to 4-orders of magnitude. Kerogen pyrolysis, clay–mineral transformation, unstable mineral dissolution, and thermal stress were the main mechanisms for the substantial improvement in the reservoir’s physical properties. This study is expected to provide a basis for formulating a heating procedure and constructing a numerical model of reservoir properties for the ICP field pilot in the Chang 7 shale of the Ordos Basin.