Evaluation of infill well pattern based on the dynamic change of reservoirs during coalbed methane development

Abstract

With the deepening of coalbed methane (CBM) exploration and development, the problem of low gas production has gradually become one of the main factors restricting the development of the CBM industry in China. Reasonable well pattern deployment can improve the productivity of CBM wells and reduce the cost of production, while the reservoir changes of CBM wells play a important role for well pattern infilling. In this study, the dynamic characteristics of the average reservoir pressure (ARP), permeability, and drainage radius during the development process of CBM wells are systematically analyzed, and predicted the production changes of well groups before and after infilling wells in combination with the characteristics of reservoir changes. The results show that the high gas production wells have a larger pressure drop, long drainage radius, and a large increase in permeability. On the contrary, low gas production wells are characterized by small drainage radius, damaged permeability and difficult to recover. The productivity of infilled horizontal wells is predicted for two well groups with different productivity and reservoir dynamic characteristics. After infilling wells, the production of current wells has increased at different degrees. It is predicted that the average gas production of low gas production well group H1 and middle gas production well group H2 will increase 1.64 and 2.09 times respectively after 3000 days production simulation. In addition, the pressure interference between wells has increased significantly, and the overall gas production of the well group has greatly increased. Infill wells can achieve better development results in areas with superior CBM resources, recoverable reservoir permeability, and small drainage radius during the early production process. The research results provide a reference for the later infill adjustment of CBM well patterns in the study area.

Graphical abstract

Keywords

well pattern optimization / reservoir dynamic variation / infill well deployment / coalbed methane / Qinshui Basin

Qian ZHANG is a Ph.D. candidate at China University of Geoscience, Beijing. He is mainly engaged in the exploration and development of unconventional natural gas, and currently focuses on the development of coalbed methane. E-mail: [e-mail]

Shuheng TANG is a professor at China University of Geosciences, Beijing. His research interests include coal and coalbed methane geology, oil and gas field development geology, and unconventional oil and gas development theory and technology. He has published more than 200 peer-reviewed articles in professional journals and various academic conferences. As the first accomplisher or leading participant, he undertook more than 40 scientific research projects. Email: [e-mail]

Songhang ZHANG is a professor at China University of Geosciences, Beijing. His research interest is coalbed methane geology and development, coal and coalbed methane geology. He is a member of the sixth Youth Working Committee of China Coal Society. He has published more than 60 peer-reviewed articles

Xinlu YAN received the Ph.D. Degree from China University of Geosciences, Beijing in 2021. Dr. Yan is currently a research lecturer at Taiyuan University of Technology. He is mainly engaged in petroleum and natural gas engineering, and currently focuses on the development of coalbed methane. He has published 5 peer-reviewed papers in the development of coalbed methane. Email: [e-mail]

Kaifeng WANG is a Ph.D. candidate at China University of Geoscience, Beijing. He is mainly engaged in the exploration and development of unconventional natural gas, and currently focuses on the development of coalbed methane. E-mail: [e-mail]

Tengfei JIA is a Ph.D. candidate at China University of Geoscience, Beijing. He is mainly engaged in the exploration and development of unconventional natural gas, and currently focuses on the development of coalbed methane. E-mail: [e-mail]

Zhizhen WANG is a Ph.D. candidate at China University of Geoscience, Beijing. He is mainly engaged in the exploration and development of unconventional natural gas, and currently focuses on the development of coalbed methane. E-mail: [e-mail]

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Acknowledgments

This work was supported by the National Natural Science Foundation of China (Grant Nos. U1910205 and 41872178) and the National Science and Technology Major Project of China (No. 2017ZX05064003).

Geological and characteristic drainage parameters of typical wells

Types of CBM wells		Typical high gas production wells			Typical medium gas production wells			Typical low gas production wells
		G-88	G-32		Z-29	Z-03		D-01
Geological parameters	Initial reservoir pressure (MPa)	4.8	3.5		3.1	4.0		3.2
	Langmuir volume (m3/t)	35.7	32		36.8	36.1		32.9
	Langmuir pressure (MPa)	1.8	2.8		2.4	1.6		3.1
	porosity (%)	0.01	0.015		0.03	0.02		0.05
	Initial permeability (mD)	0.80	1.00		0.56	0.29		0.14
Drainage and production parameters	Average daily gas production (m3/d)	1398	1215		535	573		385
	Average daily water production (m3/d)	0.40	0.32		1.53	0.95		4.76
	Cumulative production time (d)	3636	3369		2309	2943		2341
	Start gas production time (d)	74	94		40	46		37
	Time to peak gas production (d)	336	914		1452	1361		/
	Maximum gas production (m3/d)	2356	2688		1210	1050		840
	Maximum water production (m3/d)	8.5	4.8		6.3	7.2		7.9

Calculation results of reservoir dynamic changes of typical wells

Types of CBM drainage wells	High gas production wells			Medium gas production wells			Low gas production wells
	G-88	G-32		Z-29	Z-03		D-01
Pressure drop amplitude (%)	89.58	62.85		64.00	43.25		33.75
Drainage radius (m)	181	125		111	105		97
Permeability change rate (k/ki)	3.00	3.40		0.92	0.96		0.90
Average pressure drop rate (KPa/100d)	118.2	75.4		125.0	73.7		46.2

Numerical simulation parameters of the well group

Parameter category	parameters	H1 well group fitting value	H2 well group fitting value
History fitting parameters	Buried depth (m)	775	658
	permeability (mD)	0.2	0.5
	Reservoir pressure (MPa)	4	4
	Langmuir volume (m3/t)	31	35
	Coal thickness (m)	6	6
	Fracture porosity (%)	6%	1.5%
	Langmuir pressure (MPa)	2.5	2.5
	Gas content (m3/t)	17	21
	skin factor (/)	−1	−1.5
	Reservoir temperature (°C)	26	24
Horizontal well parameters	Length of horizontal section (m)	800
	Number of fracturing fractures (/)	4
	Fracture conductivity (μm2·cm)	60
	Half length of fracturing fracture (m)	100
Numerical simulation settings	Abandonment pressure (MPa)	0.2
	Simulation time (d)	3000

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