Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process

Tongshan, China

Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process

Tongshan, China
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HUANG H.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | SANG S.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | FANG L.,Huainan Mining Group | LI G.,Tiefa Mining Group | And 2 more authors.
Mining Science and Technology | Year: 2010

Based on engineering tests in the Huainan coal mining area, we studied alternative well location to improve the performance of surface wells for remote pressure relief of coalbed methane in mining areas. The key factors, affecting location and well gas production were analyzed by simulation tests for similar material. The exploitation results indicate that wells located in various positions on panels could achieve relatively better gas production in regions with thin Cenozoic layers, low mining heights and slow rate of longwall advancement, but their periods of gas production lasted less than 230 days, as opposed to wells in regions with thick Cenozoic layers, greater mining heights and fast rates of longwall advancement. Wells near panel margins achieved relatively better gas production and lasted longer than centerline wells. The rules of development of mining fractures in strata over panels control gas production of surface wells. Mining fractures located in areas determined by lines of compaction and the effect of mining are well developed and can be maintained for long periods of time. Placing the well at the end of panels and on the updip return airway side of panels, determined by lines of compaction and the effect of mining, would result in surface wells for remote pressure relief CBM obtaining their longest gas production periods and highest cumulative gas production. © 2010 China University of Mining and Technology.


Yao H.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | Zhu Y.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process
International Journal of Earth Sciences and Engineering | Year: 2016

Coal seams,organic shale,and sandstones undergo vertical interbedded development in coal-bearing strata of Upper Paleozoic in Ordos Basin. Based on the sedimentary background analysis of research areas,and in combination with comparison of gas isotope,gas measurement and hydrology,the paper comprehensively analyzed the gas-bearing system classification for unconventional natural gas of Upper Paleozoic in Ordos Basin. Through an in-depth analysis of gas-bearing property and reservoir physical property of various gas-bearing systems,the paper also expounded gas reservoir formation characteristics for unconventional natural gas of Upper Paleozoic in the research areas. Results showed that the gas-bearing systems of Upper Paleozoic in Ordos Basin were divided into the shale gas-bearing system in Member 1 of Taiyuan Formation and the mixed-source gas-bearing system in Member 2 of Taiyuan Formation ~ Member 1 of Xiashihezi Formation. The shale was the type of gas source rock of the shale gas-bearing system in Member 1 of Taiyuan Formation,with an average organic matter content of 3.3% and an average gas amount of 5m3/t. There was a high content of brittle minerals in the reservoir and a relatively developed micro-fracture. It was characterized by “low porosity,low permeability,and low gas saturation” on the whole. Coal seams and shale were the main types of gas source rock of the gas-bearing system in Member 2 of Taiyuan Formation ~ Member 1 of Xiashihezi Formation,of which the coal seams had an organic matter content of 22.32%~81.51% and a gas amount of 17 m3/t,and the shale had an organic matter content of 0.04%~2.73% and an average gas amount of 3 m3/t. The main reservoir contained coal seams,dark shale,and tight sandstones,and was characterized by “low porosity and low permeability” on the whole. The shale in Member 2 of Xiashihezi Formation and in Shangshihezi Formation presented itself as regional cap rock that had a continuous planar distribution and a good sealing ability,and whose thickness was from 50m to 200m. The unconventional natural gas reservoirs in the research areas were mainly divided into the in-source combination gas reservoir in Member 1 of Taiyuan Formation and the mixed-source combination gas reservoir in Member 2 of Taiyuan Formation ~ Member 1 of Xiashihezi Formation. © 2016 CAFET-INNOVA TECHNICAL SOCIETY. All rights reserved.


Dou X.-Z.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | Dou X.-Z.,China University of Mining and Technology | Jiang B.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | Jiang B.,China University of Mining and Technology | And 7 more authors.
Meitan Xuebao/Journal of the China Coal Society | Year: 2012

Based on the test of coal vitrinite reflectivity, combined with abundant data of exploration, the pattern and mechanism of metamorphism of late permian coal seam in western Guizhou was summarized. Through the compositive analysis of the tectonic evolution background, the observation of field geology, the microstructures and the test of fluid inclusion, the metamorphism mechanism of coal in western Guizhou was deeply discussed. The research results indicate that the coal rank is complete in western Guizhou coalfield, the metamorphic grade is generally higher and characterized by north-south higher, middle lower and west higher, east lower, and increasing outward around the two lower grade areas, Panguan syncline and Shuicheng; the plutonic metamorphism is the main type to the late permian coal seam, and the rank raises by the regional magmatic thermal metamorphism in J 3-K 1, the structure formed in Yanshan movement decides the buried depth and further controlled the metamorphic grade of coal, and metamorphism pattern is established in western Guizhou. The discordogenic faults such as Shuicheng-Ziyun fault are ductile deformation of the upper crust and in compressional stress field, so they are not the channel of magma except sporadic areas.


Wang Y.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | Wang Y.,China University of Mining and Technology | Wang Y.,Pennsylvania State University | Zhu Y.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | And 3 more authors.
Fuel | Year: 2016

Shale matrix pore structure controls the gas storage mechanism and gas transport behaviors. We employed various techniques to characterize the complex pore structures of 12 shale samples collected from two marine shale formations in upper Yangtze area (UYA) in China. The characterization techniques include field emission scanning electron microscopy (FE-SEM), high-pressure mercury intrusion porosimetry (MIP), and low-pressure N2/CO2 adsorption. The excess methane adsorption capacity was measured for each sample and the results were modeled using Langmuir model. Based on the FE-SEM image analyses, micro- and meso-pores within organic matter and inter-particle pores between or within clay minerals are the most commonly developed in these shale samples. Both uni- and multi-modal pore size distributions (PSDs) were observed, and a significant portion of pores are in the pore size range between 3 and 100 nm. It was also found that the micropore (<2 nm) is the major contributor to the overall specific surface area (SSA), whereas most of the pore volume is occupied by mesopores (2–50 nm). Two different fractal dimensions, pore surface fractal dimension (D1) and spatial geometry fractal dimension (D2), were estimated from low pressure N2 isotherms, with D1 ranging between 2.469 and 2.682, and D2 ranging between 2.576 and 2.863, indicating that the surface and volume of pore structure are heterogeneous. Samples with higher D1 can provide more adsorption sites for methane and tends to have relatively high adsorption capacity, whereas shales with higher D2 do not influence the gas adsorption and storage capacities. Methane adsorption capacity increases with the increase of both micropore volume and micropore surface area, and this confirms that microporosity is the governing factor on methane adsorption capacity and storage. © 2016 Elsevier Ltd


Wang Y.,China University of Mining and Technology | Wang Y.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | Wang Y.,Pennsylvania State University | Zhu Y.,China University of Mining and Technology | And 3 more authors.
Fuel | Year: 2016

Understanding methane sorption behavior in the gas-shale system is of great importance for evaluating reservoir production potential and reducing exploration risk. In this study, methane sorption capacities of total 12 organic-rich marine shale samples from the southwest of China were measured by volumetric method. The absolute sorption results were modeled using Langmuir, Brunauer-Emmett-Teller (BET), Dubinin-Radushkevich (D-R) and Dubinin-Astakhov (D-A) models. The accuracy of each model for quantifying shale gas sorption capacity was analyzed and compared by using a residual error analysis technique. The impacts of organic and inorganic constituents on the methane sorption capacity were also analyzed. The experimental results indicate that the maximum absolute methane sorption capacity of the collected marine shale samples is between 0.50 cm3/g and 3.41 cm3/g, which positively correlates with the total organic carbon (TOC) content. The TOC-normalized methane sorption capacity shows a positive correlation with the total clay mineral content and exhibits a significant increase with increasing illite-montmorillonite mixed layers content when it is greater than 9%. For the results of gas sorption modeling, the D-A model is superior to the Langmuir, D-R and BET models, because of the additional parameter describing the micro-heterogeneity of shale rocks. The most commonly used Langmuir model gives a reasonable fit for most of the shale samples, which is comparable to D-A modeling results when TOC content is greater than 5%. The BET model performs poorly and thus it is not recommended for methane-shale sorption modeling exercise. Therefore, both D-A and Langmuir models are recommended for describing methane adsorption on organic-rich shale samples. © 2016 Elsevier B.V. All rights reserved.


Jiang B.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | Jiang B.,China University of Mining and Technology | Wang J.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | Wang J.,China University of Mining and Technology | And 10 more authors.
Earth Science Frontiers | Year: 2016

The Daning-Jixian Area is one of the key areas of coalbed methane exploitation in China. The modern stress principally controls the coal reservoir permeability. This paper explored a stress evaluation method and technique process fitted for coal reservoir, based on the analysis and calculation of well log for coalbed methane exploitation. The study has revealed that the maximum and minimum horizontal principal stress of the 5# coal seam has a general waving variation trend of low-high-low-high from the east to the west of the Daning-Jixian Area; The vertical principal stress has a general variation trend of low in East and high in West, but the increasing trend decreases in the middle area with complex geological structures. The 5# coal seam is generally under the stress transition depth, and is significantly affected by the vertical principal stress, which is in favour of the stretch of coal seam fracture and the increase of permeability, as in a tension stress environment. The orientation of the maximum horizontal principal stress is close to the development direction of the dominant fracture, which benefits the stretch of the fracture and results in the improvement of the coal seam permeability. There is a higher permeability in the areas of low minimum principal stress and of high principal stress difference. © 2016, Editorial Office of Earth Science Frontiers. All right reserved.


Wang Y.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | Wang Y.,China University of Mining and Technology | Zhu Y.,Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process | Zhu Y.,China University of Mining and Technology | And 3 more authors.
Journal of Energy Chemistry | Year: 2015

Pore structure plays an important role in the gas storage and flow capacity of shale gas reservoirs. Field-emission environmental scanning electron microscopy (FE-SEM) in combination with low-pressure carbon dioxide gas adsorption (CO2GA), nitrogen gas adsorption (N2GA), and high-pressure mercury intrusion (HPMI) were used to study the nanostructure pore morphology and pore-size distributions (PSDs) of lacustrine shale from the Upper Triassic Yanchang Formation, Ordos Basin. Results show that the pores in the shale reservoirs are generally nanoscale and can be classified into four types: organic, interparticle, intraparticle, and microfracture. The interparticle pores between clay particles and organic-matter pores develop most often, l with pore sizes that vary from several to more than 100 nm. Mercury porosimetry analysis shows total porosities ranging between 1.93 and 7.68%, with a mean value of 5.27%. The BET surface areas as determined by N2 adsorption in the nine samples range from 10 to 20 m2/g and the CO2 equivalent surface areas (<2 nm) vary from 18 to 71 m2/g. Together, the HPMI, N2GA, and CO2GA curves indicate that the pore volumes are mainly due to pores <100 nm in size. In contrast, however, most of the specific surface areas are provided by the micropores. The total organic carbon (TOC) and clay minerals are the primary controls of the structures of nanoscale pores (especially micropores and mesopores). Micropores are predominantly determined by the content of the TOC, and mesopores are possibly related to the content of clay minerals, particularly the illite-montmorillonite mixed-layer content. © 2015 Science Press and Dalian Institute of Chemical Physics. All rights reserved.

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