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The exceptionally low geothermal gradient (~2 °C/100 m) in the Tarim Basin, notably in the Shuntuoguole (STGL) area with depths exceeding 7000 m, has catalyzed the discovery of ultra-deep liquid hydrocarbons. Yet, the genesis of these hydrocarbons remains elusive, presenting significant challenges to further exploration and development endeavors. To address this quandary, an extensive analysis involving biomarker assessments and compound-specific δ2H and δ13C isotopic evaluations of n-alkanes was conducted, unveiling the secondary alterations and origins of these crude oils. For the first time, an approximately horizontal distribution of compound-specific δ2H and δ13C in n-alkanes was observed. Through the integration of diagnostic biomarker compounds, it was elucidated that the STGL crude oils did not undergo significant biodegradation, thermal alteration, or thermal sulfate reduction. Biomarker- and compound-specific C/H isotopic correlations suggest that the STGL crude oil predominantly originates from the Lower Cambrian calcareous shale, positing it as a potential end-member oil for this lithofacial source rock. Furthermore, the STGL crude oil exhibits similar biomarker configurations (notably abundant C28 triaromatic sterones, C23 tricyclic terpenoids, and aryl isoprenoids, with minimal 4-methylstane and gammacerane presence) to those oils previously considered as mixed from the Tazhong and Tabei Uplifts within the Tarim Basin. This similarity suggests that these previously deemed mixed oils may also derive from the Lower Cambrian calcareous shale. Consequently, more focused investigations into the Lower Cambrian calcareous shale are imperative to bolster refined deep and ultra-deep petroleum exploration efforts within the Tarim Basin in forthcoming studies. [ABSTRACT FROM AUTHOR]

Accurately predicting permeability is important to elucidate the fluid mobility and development potential of tight reservoirs. However, for tight sandstones with the same porosity, permeability can change by nearly three orders of magnitude, which greatly increases the difficulty of permeability prediction. In this paper, we performed casting thin section, scanning electron microscopy and high-pressure mercury injection experiments to analyze the influence of pore structure parameters and fractal dimensions on the permeability of Chang 7 tight sandstones. Furthermore, the key parameters affecting the permeability were optimized, and a new permeability prediction model was established. The results show that the pore throat structure of Chang 7 tight sandstone exhibits three-stage fractal characteristics. Thus, the pore throat structure was divided into large pore throat, medium pore throat and small pore throat. The large pore throat reflects the microfracture system, whose fractal dimension was distributed above 2.99, indicating that the heterogeneity of the large pore throat was the strongest. The medium pore throat is dominated by the conventional pore throat system, and its fractal dimension ranged from 2.378 to 2.997. Small pore throats are mainly composed of the tree-shaped pore throat system, and its fractal dimension varied from 2.652 to 2.870. The medium pore throat volume and its fractal dimension were key factors affecting the permeability of Chang 7 tight sandstones. A new permeability prediction model was established based on the medium pore throat volume and its fractal dimension. Compared to other models, the prediction results of the new model are the best according to the analysis of root mean square value, average absolute percentage error and correlation coefficient. These results indicate that the permeability of tight sandstones can be accurately predicted using mesopore throat volume and fractal dimension. [ABSTRACT FROM AUTHOR]

Although tight oil reservoirs have abundant resources, their recovery efficiency is generally low. In recent years, CO2 injection huff-n-puff has become an effective method for improving oil recovery on the basis of depleted production of volume-fracturing horizontal wells in tight oil reservoirs. In order to study the effects of CO2 huff-n-puff (CO2-HnP) on production, a compositional numerical simulation study of CO2 huff-n-puff (CO2-HnP) was conducted in tight oil reservoirs with complex fractures. Embedded discrete fracture model technology was used in the simulations to characterize complex fractures. The process of CO2 huff-n-puff (CO2-HnP) was simulated, which consists of CO2 injection, CO2 soaking, and CO2 production. Taking into account the threshold pressure gradient and stress sensitivity in the model, we conducted a series of numerical simulations with different production condition parameters, such as bottom-hole pressure, CO2 injection rate, injection time, soaking time, and the number of cycles of CO2 huff-n-puff (CO2-HnP). Then, the effects of these sensitivity parameters on the cumulative oil production (COP) were studied. The results indicate that the threshold pressure gradient and rock stress sensitivity factors greatly affect the pressure field of tight reservoirs and the cumulative oil production (COP) of multistage-fracturing horizontal wells. The production parameters all have an impact on the COP. The injection rate and circulation number both have optimal values, and the injection time and soak time tend to have less significant effects on the growth of cumulative oil production over time. According to the numerical simulation, the optimal solution is 5 × 104 m3/day injection rate per cycle, 25 days of injection time, 35 days of soaking time, three cycles, and production for 5 years, which can obtain the optimal cumulative oil production. [ABSTRACT FROM AUTHOR]

Establishing a suitable classification and evaluation scheme is crucial for sweet spot prediction and efficient development of shale oil in the Chang 71-2 sub-member of the Longdong area. In this paper, a series of experiments, such as casting thin sections (CTS), scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), high-pressure mercury intrusion porosimetry (HMIP), and nuclear magnetic resonance (NMR), were integrated to classify the pore throats and shale oil reservoirs in the study area. Moreover, the pore structure characteristics of different types of reservoirs and their contributions to productivity were revealed. The results show that the pore-throat system can be divided into four parts: large pore throats (>0.2 μm), medium pore throats (0.08~0.2 μm), small pore throats (0.03~0.08 μm), and micropore throats (<0.03 μm). Based on the development degree of various pore throats, the reservoir is divided into four types: type I (Φ ≥ 10%, K > 0.1 mD), type II (Φ ≥ 8%, 0.05 mD < K < 0.1 mD), type III (Φ ≥ 5%, 0.02 mD < K < 0.05 mD) and type IV (Φ < 5% or K < 0.02 mD). From type I to IV reservoirs, the proportion of dissolved pores and intergranular pores gradually decreases, and the proportion of intercrystalline pores increases. The proportion of large pore throats gradually decreases, and the proportions of medium pore throats and small pore throats increase initially and then decrease, while the proportion of micropore throats increases successively. The NMR pore size distribution changes from the right peak to the left peak. The developed section of the type I reservoir corresponds to the oil layer, and the developed section of the type I and II reservoirs corresponds to the poor oil layer. In contrast, the developed section of the type III and IV reservoirs corresponds to the dry layer. The daily production from single wells is primarily attributable to type I and II reservoirs. [ABSTRACT FROM AUTHOR]

In the Benxi Formation of the Carboniferous system of the Upper Paleozoic in the Ordos Basin, there are many sets of coal measures dark organic-rich shale, being marine continental transitional facies, with significant unconventional natural gas potential. Previous studies are only limited to the evaluation of tight sandstone reservoir in this set of strata, with no sufficient study on gas bearing and geological characteristics of organic-rich shale, restricting the exploration and evaluation of shale gas resources. In this study, analysis has been conducted on the organic carbon content, the major elements, the trace elements, and the mineral composition of core samples from the Benxi Formation in key drilling sections. In addition, qualitative and quantitative pore observation and characterization of core samples have been conducted. The sedimentary environments and reservoir characteristics of the shale of the Benxi Formation have been analyzed. Combined with the gas content analyzing the results of the field coring samples, the shale gas resource potentials of the Benxi Formation have been studied, and the geological characteristics of the Benxi Formation shale gas in the eastern Ordos Basin have been made clear, to provide a theoretical basis for shale gas resource evaluation of the Benxi Formation in the Ordos Basin. The results show that (1) in the Hutian Member, Pangou Member, and Jinci Member of the Benxi Formation, organic-rich shale is well developed, with the characteristics of seawater input as a whole. There is a slight difference in sedimentary redox index, which shows that the reducibility increases gradually from bottom to top. (2) There is an evident difference in the mineral characteristics of shale in these three members. The Hutian Member is rich in clay minerals, while the Jinci Member is high in quartz minerals. (3) The pores are mainly inorganic mineral intergranular pores, clay interlayer fractures, and micro fractures, and organic matter pores are developed on the surface of local organic matter. (4) The mud shale in the Jinci Member has a large cumulative thickness, has relatively high gas-bearing property, and is rich in brittle minerals. The Jinci Member is a favorable section for shale gas exploration of the Benxi Formation. [ABSTRACT FROM AUTHOR]