The retention and flowback of fracturing fluid of branch fractures in tight reservoirs

Zhang, Yanjun; Ge, Hongkui; Shen, Yinghao; McLennan, John; Liu, Dunqing; Li, Qiwei; Feng, Dong; Jia, Leilei

doi:10.1016/j.petrol.2020.108228

Cited by 17 publications

(7 citation statements)

References 14 publications

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Section: Basic Theory and Experimentsmentioning

confidence: 99%

“…This phenomenon is mainly a function of the capillary pressure that promotes the imbibition of fracturing fluid by matrix pores 37,38 and prevents the outflow of imbibed fracturing fluid from matrix pores. 39,40 The mechanism of spontaneous imbibition in reservoir shales is complex due to the characteristics of shale gas reservoirs, such as the quantity of micro-and nanoscale pores, large surface area-to-volume ratio, low original water saturation, and high content of clay minerals. 41,42 The pore distribution in shale is mainly composed of micro-and nanoscale pores, and a large amount of fracturing fluid may be imbibed under the high capillary pressure of these pores during fracturing.…”

Section: Basic Theory and Experimentsmentioning

confidence: 99%

“…During the flowback period, the fracturing fluid in the fractures and wellbore is easily extracted with a high yield during the next 100 days, while the imbibed fluid in pores is extracted with difficulty at a lower and more stable rate during the lifespan of the shale gas well. This phenomenon is mainly a function of the capillary pressure that promotes the imbibition of fracturing fluid by matrix pores , and prevents the outflow of imbibed fracturing fluid from matrix pores. , …”

Section: Basic Theory and Experimentsmentioning

confidence: 99%

See 2 more Smart Citations

Mechanism of the Production Impact in Shale Gas Wells Caused by Water Invasion during Interwell Interference

Wang

Jiang

et al. 2021

ACS Omega

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Interwell interference is a universal problem in shale gas development and can cause severe reductions in the productivity of producing wells. Studies have attempted to identify the root cause of interference in producing wells, but the mechanisms of production reduction and recovery in impacted wells are still not clear. Thus, an effective preventive strategy is needed for producing wells when fracturing is performed in adjacent wells. According to the mechanism of spontaneous imbibition and water drainage in shale mico- and nanoscale pores, this paper introduces the water–gas distribution during fracturing and production and reveals that water drainage in micro- and nanoscale pores is mainly controlled by the amount of stored gas and follows the order of pore size. Based on this analysis, the mechanism by which interwell interference impacts the production of producing wells is explained for the first time. It is concluded that the secondary water invasion caused by interwell interference completely blocks the pores associated with long-term gas production but has little influence on the pores that have not yet drained or have produced only a small amount of gas, and smaller pores face a greater risk of water blockage. The proportion of drained pores formed during long-term gas production determines the effect of interwell interference on production; when more pores are drained by long-term gas production, greater damage occurs to the productivity of the producing well. The suggestion for preventing interwell interference is to reduce the time interval between fracturing operations at two adjacent wells, thereby diminishing the reduction in production.

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Section: Basic Theory and Experimentsmentioning

confidence: 99%

Section: Basic Theory and Experimentsmentioning

confidence: 99%

Section: Basic Theory and Experimentsmentioning

confidence: 99%

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Mechanism of the Production Impact in Shale Gas Wells Caused by Water Invasion during Interwell Interference

Wang

Jiang

et al. 2021

ACS Omega

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“…Over the past decade, shale gas has led the development trend of hydrocarbon resources and has changed the global energy market due to the huge breakthrough of horizontal wells and multistage hydraulic fracturing stimulation. , In contrast to conventional reservoirs, shale rocks are usually characterized by low permeability (nano-Darcy), and their matrix porosity is mainly predominated by small pores with a size in the range of several to hundreds of nanometers. These small nanopores provide a large surface area and great surface energy for methane molecules, resulting in two typical gas occurrence modes, i.e., adsorbed gas and free gas. , In addition, some anomalous gas transport behaviors (surface diffusion, Knudsen diffusion, and slip flow) appear in nanopores and strongly depend on pore size, resulting in a failure of Darcy’s continuum flow and traditional production prediction. − Therefore, a thorough understanding of shale gas storage and transport behavior requires knowledge about a shale pore system ahead of time.…”

Section: Introductionmentioning

confidence: 99%

Determination of Apparent Pore Size Distributions of Organic Matter and Inorganic Matter in Shale Rocks Based on Water and N₂ Adsorption

et al. 2022

Self Cite

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Knowledge of a shale pore structure is essential and critical to estimating gas storage and predicting gas production. Shale is a heterogeneous rock in terms of its composition and consists of organic matter (OM) and inorganic matter (IOM). Due to their difference in surface wettability and affinity to methane, the quantitative determination of apparent pore size distributions (APSDs) of OM and IOM as well as their contributions to the Barrett–Joyner–Halenda (BJH) pore volume is a very important task, but it is still a puzzling issue, especially considering the occurrence of water under the in situ condition. In this work, combining the water adsorption and low-pressure N2 adsorption–desorption experiments, we obtained the APSDs of dry and moist shale and clay samples, where the latter is assumed to the representative of IOM. Then, given the water distribution related to the surface wettability, a novel approach is proposed to quantitatively determine the APSDs of OM and IOM as well as their contributions to the BJH pore volume of shale under dry and in situ conditions. Our experimental results demonstrated that small nanopores (<5 nm) presented under a dry condition may be absent on the clay APSD curves under a moist condition due to the capillary condensation effect but are still shown on the shale APSD curves due to the existence of hydrophobic OM nanopores. Under a dry condition, the APSDs of OM and IOM for our samples show that OM is rich in small nanopores (i.e., 3–50 nm) while IOM pores show a wider range of size (i.e., 3–200 nm), and the contribution of OM-hosted volume to BJH pore volume is 26.7% and 20%. While under a moist condition (RH = 98%), IOM pore volumes of 26% and 20% are occupied by water molecules, and the OM-hosted proportion increases to 36% and 26%, respectively. This study proposed a significant approach to deeply characterize shale pore structure, which provides a more solid and reliable foundation for the shale gas storage estimation and well performance prediction.

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“…An optimization model of the fracturing fluid flowback was constructed. A laser macroscope, low-field nuclear magnetic resonance (NMR) instrument, and a permeability device were used to scan fracture surface morphology (Zhang et al, 2021). Fracturing fluid retention and permeability regain experiments were conducted.…”

Section: Introductionmentioning

confidence: 99%

Experimental study on the flowback of a carboxymethyl hydroxypropyl guar gum fracturing fluid with good temperature resistance

Dai¹,

Li²,

Zhang³

et al. 2022

Journal of Theoretical and Applied Mechanics

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For unconventional oil and gas reservoirs such as shale oil and gas as well as tight oil and gas, hydraulic fracturing generally enhances oil recovery. However, the flowback rate of the residual fracturing fluid is low. The residual fracturing fluid in the fracture or the rock matrix can reduce relative permeability of oil and gas, and the production rate will decrease. Therefore, it is necessary to study the factors that affect the flowback rate of the fracturing fluid. Most previous studies used the slot model, and viscous and capillary forces explain stable discharge in porous media. The conclusions were only a primarily qualitative analysis. The factors from experimental studies were not comprehensive, and they did not consider the influence of gravity. There are few studies on unstable drainage in porous media under different displacement directions. This paper presents a carboxymethyl hydroxypropyl guar gum fracturing fluid with good temperature resistance, and a fracturing fluid flowback experiment is carried on. The effects of the displacement direction, injection pressure, interfacial tension, fracturing fluid viscosity, and proppant wettability on the flowback rate are analyzed. The research results can provide formulation of the on-site construction scheme.

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The retention and flowback of fracturing fluid of branch fractures in tight reservoirs

Cited by 17 publications

References 14 publications

Mechanism of the Production Impact in Shale Gas Wells Caused by Water Invasion during Interwell Interference

Mechanism of the Production Impact in Shale Gas Wells Caused by Water Invasion during Interwell Interference

Determination of Apparent Pore Size Distributions of Organic Matter and Inorganic Matter in Shale Rocks Based on Water and N₂ Adsorption

Experimental study on the flowback of a carboxymethyl hydroxypropyl guar gum fracturing fluid with good temperature resistance

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The retention and flowback of fracturing fluid of branch fractures in tight reservoirs

Cited by 17 publications

References 14 publications

Mechanism of the Production Impact in Shale Gas Wells Caused by Water Invasion during Interwell Interference

Mechanism of the Production Impact in Shale Gas Wells Caused by Water Invasion during Interwell Interference

Determination of Apparent Pore Size Distributions of Organic Matter and Inorganic Matter in Shale Rocks Based on Water and N2 Adsorption

Experimental study on the flowback of a carboxymethyl hydroxypropyl guar gum fracturing fluid with good temperature resistance

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Product

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Determination of Apparent Pore Size Distributions of Organic Matter and Inorganic Matter in Shale Rocks Based on Water and N₂ Adsorption