Zhiming Hu

BYD (China)

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Xianggang Duan

Research Institute of Petroleum Exploration and Development

Jin Chang

Institute of High Energy Physics

Xiangui Liu

Research Institute of Petroleum Exploration and Development

Rui Shen

Research Institute of Petroleum Exploration and Development

Ying Mu

Chinese Academy of Sciences

Shusheng Gao

University of Chinese Academy of Sciences

Yalong Li

Shanghai Normal University

Guangzhao Zhou

Shanghai Fire Research Institute

Yanran Li

Central South University

Xueke Chen

China West Normal University

Cooperative Institutions

Research Institute of Petroleum Exploration and Development

Chinese Academy of Sciences

China National Petroleum Corporation (China)

University of Chinese Academy of Sciences

Institute of Porous Flow and Fluid Mechanics

State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation

Southwest Petroleum University

China University of Petroleum, Beijing

University of Science and Technology of China

Oil and Gas Center

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Influence of Particle Size on the Low-Temperature Nitrogen Adsorption of Deep Shale in Southern Sichuan, China

Minerals (2022)

Hongming Zhan Xizhe Li Zhiming Hu Xianggang Duan Wei Guo

Pore characteristics are one of the most important elements in the study of shale reservoir properties and are a key parameter for the evaluation of the potential of shale oil and gas resources. Low-temperature nitrogen adsorption is a common laboratory method that is used to characterize the pore structure of shale. However, the effect of shale’s particle size on the experimental results of the nitrogen adsorption of deep shale samples is still unclear. In this paper, using deep shale samples of different mesh sizes from the Luzhou Block as an example, we studied the effect of particle size on the pore structure of deep shale, as characterized by nitrogen adsorption experiments. The results showed that the pore volume of deep shale is mainly distributed in the mesoporous range, with a pore size ranging from 2 to 20 nm. The pore volume, as measured by nitrogen adsorption, increases slowly as the particle size decreases and then it increases rapidly. The particle size of shale has no obvious effect on the measurement of the specific surface area. The fractal dimension of deep shale gradually increases as the particle size of the shale samples increases and the smaller the particle size, the higher the correlation coefficient, R2, of the fractal dimension fitting. In this paper, different recommended sizes are given for selecting suitable particle sizes in nitrogen adsorption experiments on deep shale with different structural parameters, which will increase the accuracy of the study of the pore structure of deep shale.

Particle (ecology)

10.3390/min12030302

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Citations (11)

Dynamic details inside water-in-oil (W/O) emulsion droplet and its impact on droplet evaporation and micro-explosion

Fuel (2022)

Shuhang Shen Huan Liu Yi Liu Xi Liu Houzheng Hu

Emulsified fuel

Steam explosion

Coalescence (physics)

Liquid fuel

10.1016/j.fuel.2022.127254

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Citations (17)

Effects of hydrostatic pressure on hydraulic fracturing properties of shale using X-ray computed tomography and acoustic emission

Journal of Petroleum Science and Engineering (2022)

Hang Zhao Bing Liang Weiji Sun Zhiming Hu Yangqi Ma

Hydrostatic pressure

Bedding

Bed

10.1016/j.petrol.2022.110725

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Citations (16)

Study on the mathematical model for predicting settling of water-in-oil emulsion

Journal of Petroleum Science and Engineering (2021)

Yibo Li Tianshuang He Zhiming Hu Yaqian Zhang Qiang Luo

Settling

Coalescence (physics)

Creaming

Ostwald ripening

Oil droplet

10.1016/j.petrol.2021.109070

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Citations (16)

Adsorption and diffusion of sulfur dioxide and nitrogen in single-wall carbon nanotubes

Journal of Molecular Graphics and Modelling (2019)

Zhiming Hu Hui Xie Qian Wang Shiyong Chen

10.1016/j.jmgm.2019.01.003

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Citations (15)

Experimental Study on the Characteristics of Adsorbed Gas and Gas Production in Shale Formations

Geofluids (2021)

Zhiming Hu Xianggang Duan Nan Shao Yingying Xu Jin Chang

Adsorbed gas and free gas both exist in shale reservoirs simultaneously due to the unique nanoscale pore structure, resulting in the complex flow mechanism of gas in the reservoir during the development process. The dynamic performance analysis of shale reservoirs has mostly been conducted by the numerical simulation and theoretical model, while the physical simulation method for relevant research is seen rarely in the literature. Thus, in this paper, an experiment system was designed to simulate the degraded development experiments of shale, coal, and tight sandstone to reveal the output law of gas in different occurrence states of shale reservoirs and clarify the pressure propagation rules of different reservoirs, and then, adsorption gas and free gas production laws were studied by theoretical models. Research indicated the following: (1) The gas occurrence state is the main factor that causes the difference of the pressure drop rate and gas production law of shale, coal, and tight sandstone. During the early stage of the development of shale gas, the free gas is mainly produced; the final contribution of free gas production can reach more than 90%. (2) The static desorption and dynamic experiments confirm that the critical desorption pressure of adsorbed gas is generally between 12 and 15 MPa. When the gas reservoir pressure is lower than the critical desorption pressure in shale and coal formation, desorption occurs. Due to the slow propagation of shale matrix pressure, desorption of adsorbed gas occurs mainly in the low-pressure region close to the fracture surface. (3) The material balance theory of closed gas reservoirs and the one-dimensional flow model of shale gas have subsequently validated the production performance law of adsorbed gas and free gas by the physical simulation. Therefore, in the practical development of shale gas reservoirs, it is recommended to shorten the matrix supply distance, reduce the pressure in the fracture, increase the effective pressure gradient, and enhance the potential utilization of adsorbed gas as soon as possible to increase the ultimate recovery. The findings of this study can help for a better understanding of the shale reservoir utilization law so as to provide a reference for production optimization and development plan formulation of the shale gas reservoirs.

10.1155/2021/2448044

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Citations (1)

Well-logging evaluation of the shale gas potential in the lower Silurian Longmaxi Formation, Weiyuan, southern Sichuan Basin, China

Interpretation (2021)

Guangzhao Zhou Zhiming Hu Xiangui Liu Xianggang Duan Jin Chang

Recent observations of shale gas breakthroughs in the Weiyuan marine shale gas play in the Sichuan Basin have attracted great interest. To better understand these breakthroughs, we have used core description, cyro-focused ion beam scanning electron microscopy data, X-ray diffraction data, organic geochemistry, and well-logging data to better understand the reservoir characteristics carbonaceous shale, calcareous shale, and siliceous shale lithology, with a focus on organic-rich shale units. We find that conventional well-log methods are effective in mapping the spatial distribution of organic-rich shale in the Weiyuan area where the total organic carbon (TOC) content in the Longmaxi Formation ranges from 1.35% to 6.95%, averaging 4.42%. The kerogen is type I-II, and the vitrinite reflectance (R o ) is greater than 2.57%, which indicates that the formation is susceptible to shale gas accumulation. The clay mineral content ranges from 48 to 63 wt% (avg. 51 wt%) with illite and chlorite averaging 73.8% and 25.7%, respectively. The brittle mineral quartz and plagioclase content ranges from 32 to 61 wt% (avg. 47 wt%). Compared to the surrounding lithologic units, the marine shale exhibits relatively high gamma ray, neutron, sonic, resistivity, potassium, and uranium (U) values and relatively low density, photoelectric effect, and thorium/U values, allowing us to construct crossplots to define the units of interest. Using the same process, we quantify the TOC content providing a spatial distribution of organic-rich shale using conventional well logging.

Lithology

Illite

10.1190/int-2020-0069.1

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Estimation of Porosity in Gas Shale Using ¹H NMR Measurement: Implications for Enhanced Shale Gas Recovery

Energy & Fuels (2021)

Run Yang Zhiming Hu Zhaobin Gu Xiangui Liu Xianggang Duan

The identification of shale porosity is of fundamental significance for evaluating reservoir quality in gas-shale plays, where the various methods rarely discern the adsorbed porosity and free porosity. Comprehensive measuring campaigns, as well as reliable isothermal adsorption data sets, show that the adsorbed porosity and free porosity can be validly identified by using 1H NMR (nuclear magnetic resonance) and isothermal adsorption experiments. Here, we show that the T2 distribution of individual T2 peaks in "CH4-saturated shale", adsorbed film density, and Boyle's law can be applied to calculate the adsorbed porosity, free porosity, and total porosity. We estimated the adsorbed porosity and found that NMR measurements have remarkable capacity dynamics for characterizing CH4 saturation in shale samples. Furthermore, the adsorbed film density can be optimized by isothermal adsorption data. The novel method established in this paper directly computes the adsorption film density according to the physical characteristics of the measured isotherm adsorption. The purpose of this investigation is to unravel some of the mysteries surrounding the assessment of the adsorbed and free porosities of unconventional hydrocarbon development. The integrated analysis of these measurements helps us to better understand the adsorbed porosity, free porosity, and total porosity of samples from conventional and unconventional shale plays.

Shale Gas

10.1021/acs.energyfuels.1c00352

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Citations (4)

Influence of Pore Structure on Shale Gas Recovery with CO₂ Sequestration: Insight Into Molecular Mechanisms

Energy & Fuels (2019)

Jian Liu Hui Xie Qin Wang Shiyong Chen Zhiming Hu

Although the focus of shale gas recovery has shifted to CO2 sequestration with enhanced gas recovery (CS-EGR) for overcoming the low recovery efficiency, the adsorption and recovery mechanism of methane (CH4) and carbon dioxide (CO2) considering the effect of pore structures remains to be revealed. In this work, we focus on the influence of pore structures on adsorption behaviors of CH4 and CO2 at different geological depths and recovery process in different pore structures with various injection gas pressures. The results demonstrate that the excess adsorption capacity of CH4 and CO2 is in the order of cylinder-shaped > bottleneck > wedge-shaped > slit-shaped. The adsorption capacities of both CH4 and CO2 increase initially with geological depth until reaching maximum and then decrease with the depth going deeper. As for competitive adsorption of CH4 and CO2, the pore structures do not have much influence on the selectivity. However, the pore structures have significant impact on shale gas recovery, and the difficulty of CH4 molecules being displaced in various pore structures is ordered as cylinder-shaped > bottleneck > slit-shaped > wedge-shaped pores, which is consistent with the system resistance. The displacement efficiency of CH4 in cylinder-shaped pores is about 59%, much less than in other pore structures. The injection pressure has a negative effect on the speed of shale gas recovery and displacement efficiency of CH4 for the reason that more molecules aggregate into clusters near the pore throat and the flow blocking effect become more obvious when the injection pressure increases. Based on this actuality, we proposed a probable reliable method for CS-EGR: lower injection pressure is initially set to improve recovery efficiency, and higher pressure is finally used to increase CO2 sequestration amount.

10.1021/acs.energyfuels.9b02643

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Citations (25)

Palaeoenvironmental analysis of the Lower Silurian Longmaxi Formation in the Zhaotong area of the Sichuan Basin, South China: Implications for organic matter accumulation mechanisms

Geological Journal (2020)

Guangzhao Zhou Zhiming Hu Xiangui Liu Jianfa Wu Jin Chang

Geochemical data have been used as the most effective proxies for determining palaeoclimate and palaeoenvironmental conditions. In this article, we conduct a systematic review on a variety of geochemical data of sediments that are considered proxies for tracing palaeoclimate and palaeoenvironmental information. Comprehensive studies have been carried out on the palaeoproductivity, redox conditions, palaeoclimate, and the acquired data on the enrichment mechanism of organic matter have been summarized. The general mechanisms of the geochemical data regarded as the palaeoclimate and palaeoenvironmental archives include the characteristics of mineral composition, major and trace elements, and rare earth elements. The palaeoproductivity index, including the Ba and P, indicate that the organic‐rich shale was deposited in a high‐productivity water column. The trace elements revealed that the Longmaxi units recorded variable redox conditions from anoxic to aerobic. The elements V, U, Th, Ni, and Co together with the U/Th, V/Cr, Ni/Co, and V/(V + Ni) are essential indicators for defining the redox conditions. The NASC‐normalized REE + Y distribution indicates that the Longmaxi Formation was slightly altered by detrital materials in reduced and acidic environments. The Sr/Cu and MgO/CaO all reveal that the palaeoclimate was gradually transformed from humid to dry heat. The Sr/Ba ratio implies that the water depth fluctuates frequently at the early stage of sedimentation. All geochemical data integrated with the sedimentary characteristics show that anoxic conditions, high palaeoproductivity, and relatively humid palaeoclimates contributed to the accumulation of organic‐rich shale. We propose that jointly utilizing various geochemical and sedimentary indices can expand the outlook of the palaeoenvironment and provide a better understanding of the organic matter accumulation mechanisms.

Sedimentary organic matter

10.1002/gj.3934

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Citations (1)