Review on the Application of Low-Field Nuclear Magnetic Resonance Technology in Coalbed Methane Production Simulation

Zhang, Junjian; Chu, Xuanxuan; Wei, Chongtao; Zhang, Pengfei; Zou, Mingjun; Wang, Boyang; Quan, Fangkai; Ju, Wei

doi:10.1021/acsomega.2c02112

Cited by 24 publications

(16 citation statements)

References 37 publications

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“…Direct and indirect technologies have been developed to analyze shale pore structures . According to the direct method, qualitative information of pore structure, such as pore type and morphology in two/three-dimension, can be described well. − The indirect technologies are applied to obtain information about the quantitative parameters of shale pore structures, such as porosity, permeability, specific surface area (SSA), and PSD. − …”

Section: Introductionmentioning

confidence: 99%

Insights into Pore Structures and Multifractal Characteristics of Shale Oil Reservoirs: A Case Study from Dongying Sag, Bohai Bay Basin, China

Zhang

Yin

et al. 2022

Energy Fuels

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The pore structure and its complexity and heterogeneity control the occurrence states and fluidity of shale oil. The multifractal theory effectively characterizes the complexity and heterogeneity of the shale pore structure. In this study, serial technologies were applied to detect the pore systems of shale obtained from Dongying Sag, Bohai Bay Basin in China. The multifractal characteristics of the pore structure of the shale were analyzed based on its nuclear magnetic resonance (NMR) T 2 spectrum. The analysis results show that shale oil reservoirs can be classified into four types based on their T 2 spectra. Type I shales T 2 spectra show large p2 (1−20 ms), moderate p3 (>20 ms), but little p1 (<1 ms), characterized by large NMR and connected porosity, the lowest BET specific surface area (SSA), and the largest average pore throat diameter and S 1 contents. Large p2, moderate p1, and tiny p3 are the main distinctions of type II shales with the largest NMR porosity, large connected porosity, and BET SSA. The T 2 spectra of type III shales have large p1, moderate p2, and little p3, corresponding to large NMR porosity and BET SSA and the largest total organic content (TOC) and S 1 contents but lower connected porosity. Type IV shales have the most significant contents of micropores with the relatively largest p1 in the T 2 spectra characterized by the lowest NMR and connected porosity, the largest BET SSA, the lowest TOC, and S 1 contents but the largest clay mineral contents. Both types III and IV shales are unfavorable shale oil reservoirs. D q decreases monotonically as q increases, indicating the multifractal nature of shale pore structures. D 0 varies from 0.88 to 1.00 (mean: 0.95), and Δα ranges from 1.24 to 2.82 (mean: 1.79), suggesting complex and heterogeneous pore structures. Types I and II shales have lower D 0 values than types III and IV shales. Thus, type I organic-bearing massive felsic and type II organic-rich layered calcareous shales are favorable for shale oil reservoirs with large pores and large porosity. They have the least complex pore structures among the four shale types considered.

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Section: Introductionmentioning

confidence: 99%

Insights into Pore Structures and Multifractal Characteristics of Shale Oil Reservoirs: A Case Study from Dongying Sag, Bohai Bay Basin, China

Zhang

Yin

et al. 2022

Energy Fuels

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“…Coalbed methane (CBM), an important, nontraditional, clean energy resource, exists in coal seams in a free, adsorbed, solid-solution and dissolved state and mainly exists in an adsorbed state in coal matrices. − In CBM recovery or gas drainage prior to coal mining, gas desorbs from the wall of the pores in the coal matrix and diffuses through the pore system to the cleat due to the difference of gas concentration, then flows to the production well or drainage borehole through the cleat system due to a pressure difference. , Hence, the desorption characteristics of coal are key factors to CBM extraction. − …”

Section: Introductionmentioning

confidence: 99%

“… 1 − 3 In CBM recovery or gas drainage prior to coal mining, gas desorbs from the wall of the pores in the coal matrix and diffuses through the pore system to the cleat due to the difference of gas concentration, then flows to the production well or drainage borehole through the cleat system due to a pressure difference. 4 , 5 Hence, the desorption characteristics of coal are key factors to CBM extraction. 6 − 8 …”

Section: Introductionmentioning

confidence: 99%

CBM Desorption Model and Stages Based on a Natural Desorption Experiment

Zhang¹,

Wang

Cui

2022

ACS Omega

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Coalbed methane (CBM) desorption modeling is critical for understanding CBM desorption mechanisms and objectively analyzing the production characteristics of CBM wells. According to the CBM natural desorption experimental data of 64 coal samples taken from the Qinshui Basin, we established a CBM desorption model, quantitatively identified the CBM desorption stages, and discussed the relationship between CBM desorption characteristics and well productivity. The results indicated a very significant functional relationship between the CBM natural desorption time and cumulative desorption quantity, which could be accurately described by the model V = a L t/(t + b L ). On the basis of this model and the numerical description of the desorption data, the CBM natural desorption process was divided into four stages: the desorption startup stage, desorption sensitive stage, desorption steady stage, and desorption decay stage. As indicated by analogical reasoning of the CBM well production process, the desorption startup stage corresponded to the drainage-based pressure drop stage, the desorption sensitive and steady stages corresponded to the steady production stage, and the desorption decay stage corresponded to the production declining stage. The CBM adsorption time exponentially decreased with the increase in the average CBM desorption rate and with the increase in the CBM gas content and vitrinite/inertinite ratio. Furthermore, within a certain range of desorption pressure, a high ratio between the adsorption time and gas content corresponded to the extension of the steady production stage of CBM wells, whereas higher or lower ratios were adverse to steady production.

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“…LF-NMR inverts the fluid content, properties, and distribution and fluid pore size information by injecting a 1 H-containing fluid (water, methane) into porous media and testing its relaxation process under an external magnetic field. − Therefore, LF-NMR can well characterize the water micro-occurrence characteristics in coal under different S w . Additionally, LF-NMR can also simulate the in situ coal seam environment through the corresponding temperature and pressure application instruments and fluid injection system and reflect the changes in coal pore structure and fluid transport under complex formation conditions. − Lu et al indicated that during hydraulic fracturing, the formation of new pores was caused by broken pore walls that were supported by the injection liquid and pore water. Zhao et al .…”

Section: Introductionmentioning

confidence: 99%

Dynamic Variation on Water Micro-occurrence in Low-Rank Coals by a Low-Field Nuclear Magnetic Resonance Experiment: A Case Study of the No. 7 Coal Seam in Kongzhuang Coal Mine

Zhang

Huang

et al. 2022

Energy Fuels

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Determining the dynamic variation in water microoccurrence in the pore−fracture system of low-rank coal at different water saturations (S w ) is of great significance to reveal the water migration law of coal reservoirs during pressurized water injection. In this study, 10 low-rank coal samples were collected from the no. 7 coal seam of the Kongzhuang mine, Jiangsu Province, China, and the simulation experiments of water intrusive were used to study water micro-occurrence and dynamic variation in the coal pore−fracture system using low-field nuclear magnetic resonance technology. Additionally, water distribution heterogeneity in the pore−fracture system was clarified using the single fractal theory, and a mathematical model for the prediction of relative water saturation (S w ′) at different pressures was established. The results show that the T 2 spectra of most samples in the no. 7 coal seam show trimodal distribution and the fractures are relatively developed. When the saturation pressure continued to increase, the coal samples were further close to saturation. When the saturation pressure increases to 40 and 50 MPa, the pore−fracture begins to expand and connect due to the high-pressure saturated water. The water distribution heterogeneity in most coal samples remains stable at different saturation pressures. The water distribution heterogeneity is mainly affected by the content of adsorption pores. The water porosity (P w ) of the no. 7 coal seam is 2.9−8.1%. In addition, there is no certain correlation between the P w and the coal macerals and proximate analysis. There is a good power function relationship between the saturation pressure and S w ′ (y = a*x b , a is 0.227−0.578, b is 0.161−0.538). The values of a and b are affected by the pore structure. The results presented here provide a reference for the migration law of water in coal reservoirs during high-pressure water injection from the microscopic level in the production of coal-bed methane.

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Review on the Application of Low-Field Nuclear Magnetic Resonance Technology in Coalbed Methane Production Simulation

Cited by 24 publications

References 37 publications

Insights into Pore Structures and Multifractal Characteristics of Shale Oil Reservoirs: A Case Study from Dongying Sag, Bohai Bay Basin, China

Insights into Pore Structures and Multifractal Characteristics of Shale Oil Reservoirs: A Case Study from Dongying Sag, Bohai Bay Basin, China

CBM Desorption Model and Stages Based on a Natural Desorption Experiment

Dynamic Variation on Water Micro-occurrence in Low-Rank Coals by a Low-Field Nuclear Magnetic Resonance Experiment: A Case Study of the No. 7 Coal Seam in Kongzhuang Coal Mine

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