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Frontiers of Earth Science

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Front. Earth Sci.    2021, Vol. 15 Issue (2) : 202-223    https://doi.org/10.1007/s11707-020-0833-1
REVIEW ARTICLE
Petrophysics characteristics of coalbed methane reservoir: a comprehensive review
Qifeng JIA1,2, Dameng LIU1,2(), Yidong CAI1,2, Xianglong FANG1,2, Lijing LI1,2
1. School of Energy Resources, China University of Geosciences, Beijing 100083, China
2. Coal Reservoir Laboratory of National Engineering Research Center of CBM Development & Utilization, China University of Geosciences, Beijing 100083, China
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Abstract

Petrophysics of coals directly affects the development of coalbed methane (CBM). Based on the analysis of the representative academic works at home and abroad, the recent progress on petrophysics characteristics was reviewed from the aspects of the scale-span pore-fracture structure, permeability, reservoir heterogeneity, and its controlling factors. The results showed that the characterization of pore-fracture has gone through three stages: qualitative and semiquantitative evaluation of pore-fracture by various techniques, quantitatively refined characterization of pore-fracture by integrating multiple methods including nuclear magnetic resonance analysis, liquid nitrogen, and mercury intrusion, and advanced quantitative characterization methods of pore-fracture by high-precision experimental instruments (focused-ion beam-scanning electron microscopy, small-angle neutron scattering and computed tomography scanner) and testing methods (m-CT scanning and X-ray diffraction). The effects of acoustic field can promote the diffusion of CBM and generally increase the permeability of coal reservoirs by more than 10%. For the controlling factors of reservoir petrophysics, tectonic stress is the most crucial factor in determining permeability, while the heterogeneity of CBM reservoirs increases with the enhancement of the tectonic deformation and stress field. The study on lithology heterogeneity of deep and high-dip coal measures, the spatial storage-seepage characteristics with deep CBM reservoirs, and the optimizing production between coal measures should be the leading research directions.
Keywords petrophysics      pore-fracture      permeability      heterogeneity      controlling factors     
Corresponding Author(s): Dameng LIU   
Online First Date: 15 October 2020    Issue Date: 26 October 2021
 Cite this article:   
Qifeng JIA,Dameng LIU,Yidong CAI, et al. Petrophysics characteristics of coalbed methane reservoir: a comprehensive review[J]. Front. Earth Sci., 2021, 15(2): 202-223.
 URL:  
https://academic.hep.com.cn/fesci/EN/10.1007/s11707-020-0833-1
https://academic.hep.com.cn/fesci/EN/Y2021/V15/I2/202
Fig.1  SEM images by sequential FIB showing the 2-D pore-fracture structure of BC sample. (a) image of 1st FIB slice; (b) the partial enlarged image of (a); (c) image of 201st FIB slice; (d) the partial enlarged image of (c); (e) image of 401st FIB slice; (f) image of 599th FIB slice (Li et al., 2017c).
Fig.2  SEM images by sequential FIB showing the 2-D pore-fracture structure of AC sample. (a) image of 101st FIB slice; (b) the partial enlarged image of (a); (c) image of 301st FIB slice; (d) the partial enlarged image of (c); (e) image of 501st FIB slice; (f) image of 701st FIB slice (Li et al., 2017c).
Fig.3  Comparison of fracture recognition between SEM and CT slice images. (a) Fractures in SEM images; (b) fractures in the CT section; (c) an enlarged view of local fractures in SEM; (d) an enlarged local view of a CT section (Song et al., 2018).
Fig.4  A schematic diagram of the characterization methods of pores and fractures in different scales (Yu et al., 2020).
Fig.5  Evolution curves of gaseous products of the coal sample with elevated temperatures by mass spectrometry (Li et al., 2015).
Fig.6  Evolution characteristics of pore structure at different temperatures (Li et al., 2017c).
Fig.7  The corresponding value of logging curve and GSI (Ni et al., 2019).
Fig.8  Curve of fitting relationship between GSI and permeability (Ni et al., 2019).
Fig.9  Relationship between flow velocity and core permeability (a high velocity sequence; b low velocity sequence) (Liu et al., 2018b).
Fig.10  Change of permeability damage rate at different flow velocities (a high velocity sequence; b low velocity sequence) (Liu et al., 2018b).
Fig.11  Diffusion coefficient and permeability for the low, medium, and high rank coals. (a) Diffusion coefficient for the low, medium, and high rank coals; (b) Permeability for the low, medium, and high rank coals (Fang et al., 2018).
Fig.12  Diffusivity vs. permeability for the different rank coals (Fang et al., 2018).
Fig.13  Experimental and unipore model fitting curves of adsorption kinetics of CH4 adsorption on various coals (Fang et al., 2018).
Blocks Working seam The era of coal seam Ro–Rmax
/%		 Burial depth
/m		 Permeability
/mD		 Average gas production per well /(m3·d–1) Remarks
Jincheng No. 3 and 15 C—P
(Shanxi Formation, Taiyuan Formation)		 2.5–3.5 400–1200 0.01–2 1420 (Well ZY-285);
310 (Well TS-306)		 The permeability of different partition blocks varies greatly, and some horizontal drainage wells exist
Tunlun No. 3 P1
(Shanxi Formation)		 2.0–3.0 400–900 0.02–0.10 >1100 (Tun well 2) The permeability is generally low
Enhon No. 9,
16, and 23		 P2
(Xuanwei Formation)		 1.2–1.5 500–1500 0.04–6.10 500 (Well EH-5) High porosity and permeability
Jixian–Hancheng No. 5 and 8 C—P
(Shanxi Formation, Taiyuan Formation)		 1.1–2.1 350–1500 0.01–43 852 (Jishi well 3);
>2500 (Jishi well 1)		 The permeability of the two layers of coal is very different, and some CBM wells allow the two layers of coal to be discharged together
Zaoyuan No. 3 P1
(Shanxi Formation)		 0.5–0.8 550–750 0.5–1.8 706 (Well FZ-007) The fracture has strong conductivity, and the permeability is very high
Baode No. 8 and 9 C—P
(Shanxi Formation, Taiyuan Formation)		 0.8–1.4 400–800 0.01–3.73 1482 (Well 3V) The coal reservoir has a high water content, and the permeability difference is enormous.
Binchang No. 4 J2
(Yanan Formation)		 0.5–0.7 400–650 3.06–5.73 12964 (Well DFSC-02) High permeability and porosity
Tiefa No. 4–2, 9, 12, and 15–2 J3—K1
(Fuxin Formation)		 0.5–0.6 300–950 0.10–1.60 5750 (Well DT3) High gas content and permeability
Tab.1  The reservoir permeability and average gas production per well in China’s CBM blocks
Fig.14  Working principle of mixed gas displacement testing machine (Ni et al., 2018).
Fig.15  Permeability change under different confining pressure and gas injection pressure.
Fig.16  3D spatial distribution of pore-fraction system in different ranges. a1–a3: FIB-SEM data of sample LHG; b1–b3: X-ray μ–CT data of sample LHG; c1-c3: FIB-SEM data of sample L-1; d1–d3: X-ray μ–CT data of sample L-1 (Li et al., 2020b).
Coalfield (Basin) Mercury injection test data Pore size distribution
Porosity /% Displacement pressure/MPa The average diameter of pore throat /mm Incoming mercury saturation/% The efficiency of mercury withdrawal
/%		 Macropores
/%		 Mesopores /% Small pores
/%		 Micropores
/%
Northern Qinshui 3.50 7.01 0.06 23.1 65.6 6.5 6 67.0 20.5
Central Qinshui 3.78 6.83 0.05 19.4 61.0 7.4 6.1 69.3 17.2
Southern Qinshui 4.23 7.67 0.12 24.6 65.6 8 7.9 26.4 57.7
Datong 4.24 11.37 0.04 22.0 82.7 4.3 2.6 32.4 60.7
Pingdingshan 6.75 7.93 0.08 43.4 73.0 9.1 10.3 54.7 25.9
Anhe 8.38 3.71 0.18 27.5 43.7 11.4 12.2 71.4 5
Jiaozuo 10.30 3.98 1.26 36.9 39.5 20.7 11 37.7 30.6
Yongxia 2.80 7.08 0.04 17.3 65.7 6 5.7 49.1 39.2
Xinggong 10.38 3.92 0.23 31.8 55.8 13.8 11.1 59.8 15.3
Huainan 4.61 0.07 12.27 37.1 33.1 18.8 6.5 57.9 16.8
Huaibei 3.94 0.15 11.14 55.2 37.8 27.6 15.4 37.7 19.3
Tab.2  Pore development and pore size distribution of coal reservoir in north China
Fig.17  Microseismic monitoring results of CBM well. (a) well SZ1; (b) well SZ2 (Jia et al., 2019).
Grinding rod time/min Macerals Density level/(g·cm−3)
<1.35 1.35–1.40 >1.40
5 Vitrinite 73.26% 34.57% 49.77%
Inertinite 26.74% 65.43% 50.23%
10 Vitrinite 75.83% 31.84% 44.62%
Inertinite 24.17% 68.16% 55.38%
15 Vitrinite 74.49% 32.80% 45.11%
Inertinite 29.51% 67.20% 54.89%
20 Vitrinite 70.78% 34.70% 45.99%
inertinite 34.22% 65.30% 54.01%
30 Vitrinite 66.53% 39.77% 46.45%
Inertinite 33.47% 60.23% 53.55%
Tab.3  The macerals of coal samples with different grinding rod time (Tao et al., 2020)
Fig.18  Relationships between the pore size and coal facies index. (a1) the relationship between pore size (<102 nm) and TPI; (a2) the relationship between pore size (102–103 nm) and TPI; (a3) the relationship between pore size (>103 nm) and TPI; (b1) the relationship between pore size (<102 nm) and gelification index (GI); (b2) the relationship between pore size (102–103 nm) and GI; (b3) the relationship between pore size (>103 nm) and GI; (c1) the relationship between pore size (<102 nm) and WI; (c2) the relationship between pore size (102–103 nm) and WI; (c3) the relationship between pore size (>103 nm) and WI; (d1) the relationship between pore size (<102 nm) and groundwater index (GWI); (d2) the relationship between pore size (102–103 nm) and GWI; (d3) the relationship between pore size (>103 nm) and GWI (Lu et al., 2020).
Fig.19  Relationships between the microfractures and GWI. (a) GWI against type A fractures; (b) GWI against type B fractures; (c) GWI against type C fractures; (d) GWI against type D fractures (Lu et al., 2020).
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