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This research proposes a new method to correct the nuclear magnetic resonance (NMR) T2spectrum at different centrifugal rotational speed states to more accurately evaluate the fluid mobility characteristics, pore connectivity characteristics, and unmoved water thickness of shale reservoir samples. The Longmaxi Shale in Southeast Chongqing was selected for this case study. Experiments, including mercury intrusion porosimetry (MIP) and NMR at dry, saturated water, and different centrifugal rotational speed states, were performed on these shale samples. The NMR T2spectrum at different centrifugal rotational speed states was corrected according to the calibration rules. Then, the characteristics of fluid mobility and pore volumes (PV) connected by different sizes of throats and unmoved fluid thickness were evaluated. The results of the connected PV from the corrected NMR were compared with those from MIP. After correcting, the signal amplitude of the NMR T2spectrum decreases with centrifugal rotational speed in order and becomes more regular without interleaving. The response signal of the NMR T2spectrum at the centrifugal state can more truly reflect the PV connected by different throat sizes. The method of correcting the NMR T2spectrum includes three advantages, namely, almost eliminating the influence of adsorbed and bound water, more accurately reflecting the response signal of movable fluid, and estimating the adsorbed water thickness. This method also has three disadvantages, namely, the NMR T2spectra must be measured at several states, corrected abnormal second minimum deviation, and contact angle accuracy error.

Shale oil has been found in the Paleogene lacustrine source rocks in the second (Eh32) and third beds (Eh33) of the third member of the Hetaoyuan Formation from the Biyang Depression of the Nanxiang Basin, eastern China, but the formation environments of the organic-rich shales are still unclear, which restricts the shale oil exploration. Here, this paper discusses the paleoenvironment and its control on the organic-rich shale formation. Our study suggests that shales from the Eh32and Eh33beds display some heterogeneities in total organic carbon (TOC) contents and oil potential as a result of their different paleoenvironments. During Eh33deposition, the paleoproductivity was moderate to high, which was diluted by moderate to high terrigenous detrital matter (TDM) input. During Eh32deposition, the TDM and terrigenous organic matter (TOM) inputs increased. The paleoproductivity was moderate, which was greatly diluted by the high TDM content. The redox conditions were anoxic during the two source rock intervals. Paleoproductivity is the main controlling factor of source rock formation during Eh32and Eh33depositions, which has a strong positive correlation with the burial of organic carbon. However, anoxia did not promote deposition of the richest source rocks. During Eh33deposition, shales with high contents of TOC values and better oil potential could be formed in this environment on account of the moderate to high paleoproductivity. In contrast, during Eh32deposition, high TOM input did not obviously improve the burial of organic carbon but high TDM input significantly diluted the paleoproductivity. The bottom water became semi-saline to hypersaline, but it did not enhance the anoxic environment. Shales with medium TOC values and oil potential could be formed in this environment as a result of moderate paleoproductivity.

To evaluate the amount of adsorbed methane in a shale reservoir under different conditions of temperature and pressure, the Longmaxi shale from the Py1 well of southeast Chongqing was selected as a case to establish the three compositions adsorbing methane (TCAM) method based on the results of total organic carbon, X-ray diffraction, and methane isothermal adsorption analyses. The amounts of methane adsorbed by organic matter (OM), clay, and other minerals were calculated under different conditions of temperature and pressure, followed by the evaluation of the occurrence characteristics of adsorbed gas in a shale reservoir. A comparison of data from experiments and the TCAM method with two shale samples revealed the uncertainty of TCAM. The results from the two samples range from 0.02 to 0.08 m3/t and from 0.01 to 0.09 m3/t, with average values of 0.05 and 0.04 m3/t, respectively. The methane adsorption capacities of OM, clay, and other minerals at temperatures ranging from 30 to 70 °C were 26.04–38.76, 1.83–2.76, and 0.43–0.53 m3/t, respectively, with average values of 32.86, 2.38, and 0.48 m3/t, respectively. These values are significantly reduced and are more likely to be affected by the temperature. The contributions of OM, clay, and other minerals to the total adsorbed gas are 34.83, 46.74, and 18.43%, respectively, on the basis of the limited data available. The efficient exploitation of adsorbed gas in a shale reservoir requires an increase in the reservoir temperature or a reduction in the reservoir pressure to lower than 10 MPa. The TCAM method requires the shale reservoir to be in a relatively stable sedimentary environment, to have the same diagenetic evolution, and to have the same type of OM. Once the TCAM model is established, it can be applied to the same marine shale reservoir with a similar diagenetic evolution in the same area.

With the worldwide increasing concern regarding environmental protection and controlling carbon emission, carbon dioxide (CO2) displacement in the subsurface becomes a vital process in environmental engineering and petroleum engineering. In this study, we propose a new “D3Q27” three fluid phase lattice Boltzmann method (TPLBM) based on a multiple relaxation time algorithm to study the flow behavior of three fluids, water, CO2, and oil in this study. A series of TPLBM simulation studies are carried out on a three-dimensional digital replica of a rock (sandstone) to investigate the microprocesses and mechanisms of CO2displacement from its oil–water–CO2systems. Data gathered from high-resolution X-ray computed tomography scanning of a sandstone sample from Daqing oilfield, Longhupao, Songliao Basin, China, is used to construct the rock replica. TPLBM numerical simulations are conducted to analyze the microdisplacement of CO2in sandstone under different injection conditions. The results show that the displacement efficiency is higher at higher injection rates and pressure differences, with a constant total volume of injected CO2. The optimal injection rate and pressure difference for CO2displacement in sandstone are identified. The average ultimate CO2displacement efficiency is 90.1% when the injection rate remains constant, whereas the average ultimate CO2displacement efficiency is 95.8% when the injection pressure difference remains constant. The proposed method offers a new method for analyzing the pore-scale three fluid phase flow in sandstone.

There are many hydrogen-bearing components in shale, including kerogen, free oil, adsorbed oil, free water, adsorbed water, and structural water. Measuring the content and distribution of each component is important to understand the occurrence mechanism of shale oil. The nuclear magnetic resonance (NMR) T1–T2map can be used as a non-destructive technique to distinguish hydrogen-bearing components in shale. In this paper, we examine the relaxation characteristics of kerogen, shale, and clay minerals in continental shale under different oil or water conditions using high-resolution low-field NMR instruments (frequency is 21.36 MHz, and echo time is 0.07 ms). The NMR T1–T2map division method was established for each hydrogen-bearing component. The relaxation characteristics of each component are as follows: (1) Kerogen has the highest T1/T2ratio; oil exhibits a higher T1/T2ratio than that of water; and the mobility of water is greater than that of oil under saturated conditions. (2) The transverse relaxation time of the free state is greater than the adsorbed state for oil and water. (3) Intergranular pores of clay-rich continental shale shrink after saturation with water and result in the main peak of the T2value of free water at less than 1 ms, which differs from marine shale. (4) Kerogen and structural water account for a large proportion of NMR signals in continental shale. (5) The signals of some components in T1–T2maps overlap because of the resolution limitation of the NMR instrument. Organic matter abundance and oil saturation of shale, estimated by the NMR T1–T2map method, were in good agreement with the pyrolysis and distillation experiments, which demonstrates the reliability of the NMR T1–T2map division method for each hydrogen-bearing component in continental shale.

Qualitative and quantitative evaluations of resource potential are of significant importance for both exploration and exploitation of shale oil. We investigate the shale oil resource potential in E2s4L(the lower submember of the fourth member of the Paleogene Shahejie Formation) of Damintun Sag by both qualitative and quantitative methods. From the viewpoint of qualitative evaluation, it is reasonable to hope that the target shale, with adequate oil-prone organic matter (OM) in the peak and late oil generation stage, forms a shale oil reservoir. The total oil content in shale is evaluated from free hydrocarbons in shale (S1) by correcting the heavy and light hydrocarbons and the resins and asphaltenes. The total oil content is found to be over 4.45 times greater than the original S1. The evaluation threshold of high-abundance oil is determined by both the total oil content (ST) and the ratio of STto the total organic carbon content with values that are greater than 8 mg/g and 1, respectively. Based on the total oil content in shale and the evaluation threshold of high-abundance oil, the resource potential of high-abundance shale oil is obtained to be around 2.2 × 108t. The average oil-bearing rate is about 0.033 m3/m3, which is equivalent to that of Upper and Lower Bakken shale and much higher than that of the Middle Bakken shale. From the viewpoint of the resource potential and the oil-bearing rate, the shale oil in E2s4Lof Damintun Sag is found to be promising. The evaluation results and the methods to correct the S1and to determine the high-abundance oil threshold are of practical importance for shale reservoir development.