Oil saturation is an important parameter in shale-oil reservoir evaluation. However, due to complex wettability and pore construction, we find that conventional resistivity and nuclear magnetic resonance (NMR) methods do not perform well in calculating oil saturation in shale-oil reservoirs. Hence, we have developed a practical NMR-based method to calculate the oil saturation of the Lucaogou shale-oil Formation, Permian, in Jimusar Sag, Junggar Basin, China. First, we analyze the relationships among the wettability, oil saturation, and [Formula: see text] distribution based on the theoretical formula and core analysis data. Results indicate that the ratio of the surface area wetted by water and oil is approximately equal to the ratio of water saturation and oil saturation. So we conclude that oil is mainly stored in relatively bigger pores and the surface relaxivity of the oil-wet surface is lower than that of the water-wet surface, resulting in long relaxation signals, that is, the long relaxation signals of NMR [Formula: see text] spectra of shale-oil reservoirs are primarily attributed to oil signals. We have made a series of NMR measurements of as-received samples and confirm this point. Thus, we propose a [Formula: see text] cutoff for water and oil to calculate the oil saturation, and we determine 6 ms as the [Formula: see text] cutoff based on the oil saturation analysis of cores and NMR logs. Finally, we verify and make application of our method and acquire good results.

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Tight oil is more and more important in petroleum industry. However, there is few systematic studies up to now. Based on core data, petrophysical experimental data, well logs and test data, a systematic study on seven-property relation of tight oil reservoirs is conducted in Lucaogou Formation, Permian, Jimusaer Sag, Junggar Basin, China. To be specific, firstly, lithology is identified via cross plot of matrix density and constructed structure index from nuclear magnetic resonance (NMR) log. Secondly, using iteration method, lower limit T2 relaxation time value of effective pore and oil-filled porosity are calculated to be 1.7 ms and 7 ms respectively, which is a new way to predict porosity and oil saturation in tight oil reservoirs. Thirdly, high resolution resistivity (Rt) curve is acquired from micro-resistivity imager log by dimension reduction process and piecewise calibration. Total organic carbon (TOC) content is predicted by curve overlapping method of interval transit time (AC) and the obtained high-resolution resistivity. Fourthly, according to the transformation of dynamic and static rock mechanics parameters, an improved method is proposed for quantitatively predicting brittleness index (BI) of rocks via well logs. Ground stress value and direction are evaluated by various methods comprehensively. This study obtains a good application effect and provides important technical support for evaluating tight oil reservoirs via well logs, which plays an important role in tight oil exploration and development and new oil field discovery.

The evaluation of source rock properties has become a vital step in logging interpretation. Total organic carbon (TOC) content is the key to estimating the quality and hydrocarbon generation potential of source rocks. In the shale oilfield of the Junggar Basin, the conventional method of calculating the TOC of hydrocarbon source rocks cannot satisfy logging evaluation requirements. This paper predominantly deals with a method for the quantitative estimation of TOC in source rocks via nuclear physics and nuclear magnetic resonance (NMR) logs. According to this method, the total hydrogen index of the source rock is the sum of the response of kerogen, clay minerals and fluid, expressed by corrected neutron porosity. The hydrogen index of fluid and clay minerals is indicated by the effective porosity of NMR and the estimated clay content, respectively. To eliminate the hydrogen index of fluid, the effective NMR porosity is subtracted from the corrected neutron porosity. On this basis, a new and overlapping method suitable for clay-rich rocks and oil reservoirs is proposed. This method was developed by overlaying the scaled clay content curve on the hydrogen index curve. In non-source rocks, the two curves regularly overlap. However, in organic-rich rocks the two curves will separate. The separation distance between the two curves was used to estimate TOC continuously. Possessing sound application and benefiting from the measured results of sweet spots, this method provides new insights for TOC quantitative prediction in shale oil reservoirs.