Xiao-xing Shi

Research Institute of Petroleum Exploration and Development

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Xingmin Li

Research Institute of Petroleum Exploration and Development

Ming Zhang

Wuhan University of Science and Technology

Ting Li

Chengdu University of Technology

Hangfei Gong

China University of Petroleum, East China

Yongbin Wu

Research Institute of Petroleum Exploration and Development

Guofeng Wang

Dalian Maritime University

Zhiquan Nie

State Development & Investment Corporation (China)

Wei Yao

Wuhan University of Science and Technology

Hao Chen

Chengdu University of Technology

Jiuning Zhou

Research Institute of Petroleum Exploration and Development

Cooperative Institutions

Research Institute of Petroleum Exploration and Development

China National Petroleum Corporation (China)

State Key Laboratory of Enhanced Oil Recovery

Chinese Academy of Sciences

Wuhan University of Science and Technology

State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation

Institute of Porous Flow and Fluid Mechanics

China University of Petroleum, Beijing

University of Chinese Academy of Sciences

China University of Petroleum, East China

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Analytical solution for steam-assisted gravity drainage with consideration of temperature variation along the edge of a steam chamber

Fuel (2018)

Xiao-xing Shi Ryosuke Okuno

Steam-assisted gravity drainage

Steam injection

10.1016/j.fuel.2017.12.110

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Citations (19)

Quantitative Characterization of Tidal Couplets in Oil Sands Reservoir, the Upper McMurray Formation, Northeastern Alberta, Canada

Lithosphere (2021)

Hao Chen Jixin Huang Zhaohui Xia Zhiquan Nie Xiao-xing Shi

Abstract The McMurray Formation, NE Alberta, Canada, is one of the most significant bitumen bearing deposits worldwide. This formation deposited and reworked in fluvial, tidal, or estuarine environments results in a huge number of tidal couplets (TCs) which is consisted of mm-cm scale sandy and muddy interlayers. These couplets not only increase the geologic heterogeneity of the oil sand reservoir but also make it hard to predict the performance of in situ thermal processes. In this paper, based on literatures, lab analysis, core photos, logging, and drilling data, a quantitative characterization procedure for mm-cm scale tidal couplets was proposed. This procedure, which includes identification, classification, quantitative description, and spatial distribution prediction, was presented. Five parameters, thickness, mud volume, laminae frequency, spatial scale, and effective petrophysical properties, were selected to describe the TCs quantitatively. To show the procedure practically, TCs in the oil sand reservoir of McMurray Formation, Mackay River Project, and CNPC, were selected to demonstrate this procedure. The results indicate that the TCs are in mm-cm thickness, densely clustered, and in a variety of geometries. Based on geologic origins, these couplets were divided into four types: tidal bar couplets (TBCs), sand bar couplets (SBCs), mix flat couplets (MFCs), and tidal channel couplets (TCCs). The thickness, mud volume, and frequency were calculated by mathematical morphological processed core photos. The spatial scale of TCs was estimated by high-density well correlations. The effective petrophysical properties were estimated by bedding scale modeling and property modeling via REV. Finally, the spatial distribution of TCs was predicted by object-based modeling.

Petrophysics

Tidal flat

10.2113/2021/2993537

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Study on the Quantitative Characterization and Heterogeneity of Pore Structure in Deep Ultra-High Pressure Tight Glutenite Reservoirs

Minerals (2023)

Meng Du Zhengming Yang Shuo Yang Chun Feng Guofeng Wang

The precise characterization of a tight glutenite reservoir’s microscopic pore structure is essential for its efficient development. However, it is difficult to accurately evaluate using a single method, and its microscopic heterogeneity is not fully understood. In this study, a combination of X-ray diffraction, casting thin section observations, scanning electron microscopy, high-pressure mercury injection, constant-speed mercury injection, X-ray computed tomography, and the advanced mathematical algorithms in the AVIZO 8.0 visualization software was used to construct the three-dimensional digital core of a glutenite reservoir at the study site, and the parameters of the pore network model were extracted. The overall microscopic pore structure characteristics were quantitatively investigated from multiple scales. Based on this, the mineral quantitative evaluation system (QEMSCAN) examined the microscopic heterogeneity of the glutenite reservoir and its impact on seepage. The results show that the glutenite reservoir in the study block can be classified into three categories based on lithology and capillary pressure curve characteristics. The type I reservoir samples have large and wide pore throats, low threshold pressure, and high reservoir quality; type II reservoir samples are characterized by medium-sized pore throat, medium threshold pressure, and moderate reservoir quality; and the small and narrow pore throat, high threshold pressure, and poor reservoir quality are characteristics of type III reservoir samples. The various pore throat types and mineral distributions are due to the differences in dissolution, compaction, and cementation. The continuous sheet pores have good connectivity, which is related to the interconnection of primary intergranular pores and strip fractures, while the connectivity of isolated pores is significantly poor, which is related to the development of intragranular dissolved pores and intercrystalline pores. This suggests the deterioration of physical properties and pore throat connectivity, reduced average pore radius, and decreased pore sorting as decreasing permeability. The tight glutenite pores range in size from 5 nm to 80 μm and primarily feature Gaussian and bimodal distribution patterns, and submicron–micron pores contribute more to seepage. The effective pores were found to be attributed to the slowing effect of abnormally high pressure on the vertical stress, and the protective effect was positively correlated with the high-pressure strength. Notably, there is strong microscopic heterogeneity in the distribution of the reservoir matrix minerals and the pore throat size. As a result, the injected fluid easily flows along the preferential seepage channel with pore development and connectivity. This study provides new insights into the exploration and development of similar tight reservoirs.

Capillary pressure

Characterization

10.3390/min13050601

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Comparison of Foamy Oil Behaviour between Shallow and Middepth Heavy Oil Reservoirs in the Orinoco Belt

Geofluids (2021)

Xingmin Li Changchun Chen Zhang-cong Liu Yongbin Wu Xiao-xing Shi

Nowadays, extra heavy oil reservoirs in the Orinoco Heavy-Oil-Belt in Venezuela are exploited via cold production process, which present different production performance in well productivity and primary recovery factor. The purpose of this study is to investigate the causes for such differences with the aspect of foamy oil mechanism. Two typical oil samples were adopted from a shallow reservoir in western Junìn region and a middepth reservoir in eastern Carabobo region in the Belt, respectively. A depletion test was conducted using 1D sand-pack with a visualized microscopic flow observation installation for each of the oil samples under simulated reservoir conditions. The production performance, the foamy oil behaviour, and the oil and gas morphology were recorded in real time during the tests. The results indicated that the shallow heavy oil reservoir in the Belt presents a weaker foamy oil phenomenon when compared with the middepth one; its foamy oil behaviour lasts a shorter duration with a smaller scope, with bigger bubble size and less bubble density. The difference in foamy oil behaviour for those two types of heavy oil reservoir is caused by the difference in reservoir pressure, solution GOR, asphaltene content, etc. Cold production presents obvious features of three stages under the action of strong foamy oil displacement mechanism for the middepth heavy oil reservoir, which could achieve a more favourable production performance. In the contrary, no such obvious production characteristics for the shallow heavy oil reservoir are observed due to weaker foamy oil behaviour, and its primary recovery factor is 9.38 percent point lower than which of the middle heavy oil reservoirs.

Oil Production

Residual oil

Gas oil ratio

10.1155/2021/3610207

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Effective Flotation Separation of Chalcopyrite and Graphite Using Eco-Friendly Xanthan Gum as Depressant

Mineral Processing and Extractive Metallurgy Review (2023)

Ming Zhang Congzhong Tian Jing Ding Xiao-xing Shi Lan Qiu

The concentrate grade in chalcopyrite flotation is often compromised by the associated inherently floatable gangue such as graphite. In this study, eco-friendly xanthan gum (XG) was introduced as a graphite depressant in the flotation of chalcopyrite. Single minerals flotation showed that XG strongly reduced the floatability of graphite at pH 7.5 with no significant effect on the flotation of chalcopyrite. Mixed minerals flotation showed that the addition of 20 mg/L XG increased copper grade and selectivity index by 16.83% and 14.23, respectively. This selective depressing behavior of XG was due to the strong affinity between XG and graphite as well as the weak interaction between XG and chalcopyrite, as suggested by electrokinetic and adsorption measurements. FTIR and XPS analyses indicated that the adsorption of XG on the graphite surface could be governed by physical adsorption mechanisms. Furthermore, since the contribution of hydrogen bonding interaction was insignificant, hydrophobic interaction was considered as the dominant driving force in the adsorption process. This investigation demonstrates the promising potential of XG for graphite depression and may contribute to the greening of chalcopyrite flotation process.

Depressant

Gangue

10.1080/08827508.2023.2196072

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Citations (6)

Experimental study on chemical-assisted methane flooding for foamy oil reservoirs after primary production

Journal of Petroleum Science and Engineering (2022)

Xingmin Li Xiaofei Sun Zhaopeng Yang Hangfei Gong Ting Li

Naphtha

10.1016/j.petrol.2022.110803

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Citations (5)