Numerical investigation of the effects of proppant embedment on fracture permeability and well production in Queensland coal seam gas reservoirs

Wang, Duo; You, Zhixiong; Johnson, Raymond L.; Wu, Lei; Bedrikovetsky, Pavel; Aminossadati, Saiied M.; Leonardi, Christopher

doi:10.1016/j.coal.2021.103689

Cited by 34 publications

(17 citation statements)

References 39 publications

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“…Staged fracturing is conducted using a large-displacement, high-pressure approach to create a primary fracture network under the influence of low-temperature LN2. By utilizing a proppant in a low-temperature fluid, an open fracture network is formed to facilitate CBM migration [116][117][118]. Microseismic and other monitoring technologies are em- Staged fracturing is conducted using a large-displacement, high-pressure approach to create a primary fracture network under the influence of low-temperature LN 2 .…”

Section: Lnf Low-permeability Reservoir Modelmentioning

confidence: 99%

Mechanism and Model Analysis of Ultralow-Temperature Fluid Fracturing in Low-Permeability Reservoir: Insights from Liquid Nitrogen Fracturing

Wang,

Li,

Song

et al. 2024

Processes

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Ultralow-temperature fluids (such as liquid nitrogen, liquid CO2) are novel waterless fracturing technologies designed for dry, water-sensitive reservoirs. Due to their ultralow temperatures, high compression ratios, strong frost heaving forces, and low viscosities, they offer a solution for enhancing the fracturing and permeability of low-permeability reservoirs. In this study, we focus on the combined effects of high-pressure fluid rock breaking, low-temperature freeze-thaw fracturing, and liquid-gas phase transformation expansion on coal-rock in low-permeability reservoirs during liquid nitrogen fracturing (LNF). We systematically analyze the factors that limit the LNF effectiveness, and we discuss the pore fracture process induced by low-temperature fracturing in coal-rock and its impact on the permeability. Based on this analysis, we propose a model and flow for fracturing low-permeability reservoirs with low-temperature fluids. The analysis suggests that the Leidenfrost effect and phase change after ultralow-temperature fluids enter the coal support the theoretical feasibility of high-pressure fluid rock breaking. The thermal impact and temperature exchange rate between the fluid and coal determine the temperature difference gradient, which directly affects the mismatch deformation and fracture development scale of different coal-rock structures. The low-temperature phase change coupling fracturing of ultralow-temperature fluids is the key to the formation of reservoir fracture networks. The coal-rock components, natural fissures, temperature difference gradients, and number of cycles are the key factors in low-temperature fracturing. In contrast to those in conventional hydraulic fracturing, the propagation and interaction of fractures under low-temperature conditions involve multifield coupling and synergistic temperature, fluid flow, fracture development, and stress distribution processes. The key factors determining the feasibility of the large-scale application of ultralow-temperature fluid fracturing in the future are the reconstruction of fracture networks and the enhancement of the permeability response in low-permeability reservoirs. Based on these considerations, we propose a model and process for LNF in low-permeability reservoirs. The research findings presented herein provide theoretical insights and practical guidance for understanding waterless fracturing mechanisms in deep reservoirs.

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Section: Lnf Low-permeability Reservoir Modelmentioning

confidence: 99%

Mechanism and Model Analysis of Ultralow-Temperature Fluid Fracturing in Low-Permeability Reservoir: Insights from Liquid Nitrogen Fracturing

Wang,

Li,

Song

et al. 2024

Processes

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“…Machine learning algorithms such as linear regression algorithm, lasso regression algorithm, polynomial regression algorithm, support vector machine algorithm, random forest algorithm, and gradient enhanced regression algorithm are widely used in exploration, drilling, and reservoir. The integrated intelligent decision-making system for deep CBM geological engineering encapsulates and embeds all commonly used machine learning algorithms. − …”

Section: System Key Technologiesmentioning

confidence: 99%

Intelligent Decision-Making System for Integrated Geological and Engineering of Deep Coalbed Methane Development

Wang,

Huang

et al. 2023

Energy Fuels

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Coalbed methane (CBM) exploration and development is becoming increasingly complex, and the deterioration of resource quality is intensifying. In this paper, first, based on the research results of data regional lake and fine description of gas reservoirs, artificial intelligence technology was applied to deep mining and analysis of comprehensive data of CBM reservoirs. Second, an innovative integrated CBM geology engineering intelligent decision-making system based on big data analysis algorithms was developed. Third, the fast single-well production prediction and master controlling factor analysis driven by big data is achieved. Fourth, comprehensive sweet spot analysis was conducted on CBM reservoirs by combining geological and engineering factors. The fracturing parameters based on the analysis of the main control factors of production after fracturing of CBM wells were optimized. The system is promoted and applied in Daning block on the east edge of the Ordos Basin. Results show that (a) the system has significantly improved the efficiency of gas reservoir research and the effectiveness of engineering decisions, and (b) it provides a powerful new method and system support for fully understanding the resource potential of gas reservoirs and comprehensively promoting the deep application of intelligence in scientific research and production.

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“…As a result, a large amount of coal fines become dislodged and accumulate, contaminating the proppant. The transportation and retention of coal fines in the proppant pack lead to the blockage of the fluid pathways within the coalbed, reducing the fracture conductivity and subsequently decreasing the production capacity of CBM [2][3][4][5][6]. Furthermore, the infiltration of coal fines into the pump barrel can cause pump sticking, blockage, equipment damage, and even production shut-in, posing severe hazards.…”

Section: Introductionmentioning

confidence: 99%

An Experimental Study on the Impact of the Particle Size and Proportion of Composite Proppant on the Conductivity of Propped Fractures in Coalbed Methane Reservoirs following Pulverized Coal Fines Infiltration

et al. 2023

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Coalbed methane reservoirs exhibit a low strength and high heterogeneity, rendering them susceptible to coal fines generation during hydraulic fracturing operations. The detrimental impact of coal fines on the conductivity of the propped fracture has been overlooked, leading to a substantial negative effect on the later-stage recovery of coalbed methane reservoirs. Moreover, the particle size distribution of the composite proppant also affects the conductivity of the propped fracture. To mitigate the damage caused by coal fines to the conductivity of the proppant pack in CBM reservoirs, this study conducted conductivity tests on actual coal rock fractures. The aim was to assess the effect of various particle size ratios in composite proppant blends on the conductivity of complex fractures in CBM reservoirs. The ultimate goal was to identify an optimized proppant blending approach that is suitable for hydraulic fracturing in coal seams. The results indicated that, in terms of the short-term conductivity of coalbed methane reservoirs, the conductivity of composite proppants is primarily influenced by the proportion of large or small particles. A higher proportion of large particles corresponds to a stronger conductivity (e.g., the conductivity is highest at a particle ratio of 5:1:1 for large, medium, and small particles). On the other hand, a higher proportion of small particles leads to a poorer conductivity (the conductivity is lowest when the particle ratio is 1:1:5). In the long-term conductivity of coalbed methane reservoirs, the fluid flushing of the fracture surfaces generates coal fines, and small particles can fill the gaps between larger particles, hindering the infiltration of coal fines. Therefore, it is important to control the particle size ratio of composite proppants, with a predominant proportion of larger particles. This approach can maintain long-term conductivity and prevent the excessive infiltration of coal fines, thereby avoiding fracture blockage (e.g., the conductivity is highest at a particle ratio of 5:1:5, followed by a ratio of 3:1:3). Furthermore, considering the influence of proppant placement methods and the support effect on near-wellbore opening fractures and far-end sliding fractures, segmented placement is utilized to fully fill the fractures for short-term conductivity, whereas mixed placement is employed for long-term conductivity to achieve a balance in particle gaps and hinder the infiltration of coal fines. The findings of this study contribute to the understanding of proppant selection and placement strategies for efficient hydraulic fracturing in coalbed methane reservoirs.

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Numerical investigation of the effects of proppant embedment on fracture permeability and well production in Queensland coal seam gas reservoirs

Cited by 34 publications

References 39 publications

Mechanism and Model Analysis of Ultralow-Temperature Fluid Fracturing in Low-Permeability Reservoir: Insights from Liquid Nitrogen Fracturing

Mechanism and Model Analysis of Ultralow-Temperature Fluid Fracturing in Low-Permeability Reservoir: Insights from Liquid Nitrogen Fracturing

Intelligent Decision-Making System for Integrated Geological and Engineering of Deep Coalbed Methane Development

An Experimental Study on the Impact of the Particle Size and Proportion of Composite Proppant on the Conductivity of Propped Fractures in Coalbed Methane Reservoirs following Pulverized Coal Fines Infiltration

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