Numerical investigation of the well shut-in and fracture uncertainty on fluid-loss and production performance in gas-shale reservoirs

Zhang, Tao; Li, Xiangfang; Li, Jing; Feng, Dong; Li, Peihuan; Zhang, ZH; Chen, Yu; Wang, Shan

doi:10.1016/j.jngse.2017.08.024

Cited by 70 publications

(36 citation statements)

References 29 publications

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“…In this section, type curves of SHS flow in IT and annuli are obtained and discussed in detail (Huang et al 2017(Huang et al , 2018a(Huang et al , 2018bFeng et al 2018;Sun et al 2017k, 2017l, 2018bZhang et al 2017aZhang et al , 2017bChen et al 2015Chen et al , 2016Chen et al , 2017. The injection pressure, temperature and mass flow rate at the heel point are 4.231 MPa, 566.6 K and 3 kg/s, respectively.…”

Section: Type Curve Analysismentioning

confidence: 99%

The heat and mass transfer characteristics of superheated steam in horizontal wells with toe-point injection technique

Sun

Yao

2018

J Petrol Explor Prod Technol

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Little efforts were done on the heat and mass transfer characteristics of superheated steam (SHS) flow in the horizontal wellbores. In this paper, a novel numerical model is presented to analyze the heat and mass transfer characteristics of SHS in horizontal wellbores with toe-point injection technique. Firstly, with consideration of heat exchange between inner tubing (IT) and annuli, a pipe flow model of SHS flow in IT and annuli is developed with energy and momentum balance equations. Secondly, coupled with the transient heat transfer model in oil layer, a comprehensive mathematical model for predicting distributions of pressure and temperature of SHS in IT and annuli is established. Then, type curves are obtained with numerical methods and iteration technique, and sensitivity analysis is conducted. The results show that (1). The decrease in SHS temperature in annuli caused by heat and mass transfer to oil layer is offset by heat absorbtion from SHS in IT. (2). SHS temperature in both IT and annuli increases with the increase in injection pressure. (3). IT heat loss rate decreases with the increases in injection pressure. (4). Increasing pressure can improve development effect. Keywords Superheated steam injection · Toe-point injection technique · Horizontal wellbores · Distributions of pressure and temperature · Heavy oil recovery List of symbols

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Section: Type Curve Analysismentioning

confidence: 99%

The heat and mass transfer characteristics of superheated steam in horizontal wells with toe-point injection technique

Sun

Yao

2018

J Petrol Explor Prod Technol

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“…All of the main hydraulic fractures (n F = 45) were assumed to be identical, as shown in Figure 3. The water-gas relative permeability and capillary pressure curves for F, f and m were assigned according to reference values [17,18]. The input reservoir and hydraulic fracture parameters of the simulation model are listed in Table 1.…”

Section: Description Of the Simulation Modelmentioning

confidence: 99%

Hydrodynamic Equilibrium Simulation and Shut-in Time Optimization for Hydraulically Fractured Shale Gas Wells

2020

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Post-fracturing well shut-in is traditionally due to the elastic closure of hydraulic fractures and proppant compaction. However, for shale gas wells, the extension of shut-in time may improve the post-fracturing gas production due to formation energy supplements by fracturing-fluid imbibition. This paper presents a methodology using numerical simulation to simulate the hydrodynamic equilibrium phenomenon of a hydraulically fractured shale gas reservoir, including matrix imbibition and fracture network crossflow, and further optimize the post-fracturing shut-in time. A mathematical model, which can describe the fracturing-fluid hydrodynamic transport during the shut-in process, and consider the distinguishing imbibition characteristics of a hydraulically fractured shale reservoir, i.e., hydraulic pressure, capillarity and chemical osmosis, is developed. The key concept, i.e., hydrodynamic equilibrium time, for optimizing the post-fracturing shut-in schedule, is proposed. The fracturing-fluid crossflow and imbibition profiles are simulated, which indicate the water discharging and sucking equilibrium process in the coupled fracture–matrix system. Based on the simulation, the hydrodynamic equilibrium time is calculated. The influences of hydraulic pressure difference, capillarity and chemical osmosis on imbibition volume, and hydrodynamic equilibrium time are also investigated. Finally, the optimal shut-in time is determined if the gas production rate is pursued and the fracturing-fluid loss is allowable. The proposed simulation method for determining the optimal shut-in time is meaningful to the post-fracturing shut-in schedule.

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“…For example, Yang et al () developed a pore network modelling to investigate fluid slippage and adsorption on shale oil permeability. In actual field cases, producers inject thousands of cubic meters of fracturing fluid (composed mostly of water) into subsurface reservoirs, significantly disturbing the equilibrium of the subsurface fluid system (Zhang, Li, Li, et al, ). During the production stage, the produced fluid usually begins as single‐phase water followed by two‐phase gas and water that eventually becomes a near‐single‐phase gas flow (Ghanbari & Dehghanpour, ).…”

Section: Introductionmentioning

confidence: 99%

Upscaling Water Flow in Composite Nanoporous Shale Matrix Using Lattice Boltzmann Method

Zhang

Javadpour

Yin

et al. 2020

Water Resources Research

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Water flow in nanoporous structures in shale strongly depends on water-pore wall interactions; specifically, water-pore wall interactions may influence flow more than water-water interactions. Because of strong water-pore wall interactions, the models that govern flow in nanoporous structures deviate from conventional continuum flow models such as the Darcy equation. We develop a novel lattice Boltzmann model to study water flow in nanoporous structures rendered from shale samples. First, we reconstruct three-dimensional (3-D) stochastic digital models based on composite shale samples that include hydrophobic organic matter (OM) and hydrophilic clay minerals. In the reconstructed digital models, we use pore size/shape distributions, porosity, and mineralogy from experiments. Then we use lattice Boltzmann models to model water flow through nanoporous structures (OM and clay) of the reconstructed shale sample, and we upscale the results to a microporous structure of composite shale containing OM, clay, and interpores associated to other minerals. The results show contraction/expansion effects of pore-throat-pore systems in nanoporous OM weaken the hydrophobicity-induced slippage effect on total water flow. In nanoporous clay, the swelling effect predominates and diminishes water slippage effects on water flow. The work also highlights the importance of (1) the accuracy of reconstructed 3-D pore networks in terms of pore connectivity, shape, and tortuosity in individual systems of OM and clay and (2) the role of OM nanopores in connecting isolated micropores to total water flow through the composite shale system.

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Numerical investigation of the well shut-in and fracture uncertainty on fluid-loss and production performance in gas-shale reservoirs

Cited by 70 publications

References 29 publications

The heat and mass transfer characteristics of superheated steam in horizontal wells with toe-point injection technique

The heat and mass transfer characteristics of superheated steam in horizontal wells with toe-point injection technique

Hydrodynamic Equilibrium Simulation and Shut-in Time Optimization for Hydraulically Fractured Shale Gas Wells

Upscaling Water Flow in Composite Nanoporous Shale Matrix Using Lattice Boltzmann Method

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